[Federal Register Volume 65, Number 4 (Thursday, January 6, 2000)]
[Rules and Regulations]
[Pages 810-959]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-2]
[[Page 809]]
Part II
Department of Energy
_______________________________________________________________________
18 CFR Part 35
Regional Transmission Organizations; Final Rule
Federal Register / Vol. 65, No. 4 / Thursday, January 6, 2000 / Rules
and Regulations
[[Page 810]]
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM99-2-000; Order No. 2000]
Regional Transmission Organizations
Issued December 20, 1999.
AGENCY: Federal Energy Regulatory Commission
ACTION: Final Rule.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
amending its regulations under the Federal Power Act (FPA) to advance
the formation of Regional Transmission Organizations (RTOs). The
regulations require that each public utility that owns, operates, or
controls facilities for the transmission of electric energy in
interstate commerce make certain filings with respect to forming and
participating in an RTO. The Commission also codifies minimum
characteristics and functions that a transmission entity must satisfy
in order to be considered an RTO. The Commission's goal is to promote
efficiency in wholesale electricity markets and to ensure that
electricity consumers pay the lowest price possible for reliable
service.
EFFECTIVE DATE: This Final Rule will become effective March 6, 2000.
FOR FURTHER INFORMATION CONTACT:
Alan Haymes (Technical Information), Federal Energy Regulatory
Commission, 888 First Street, NE, Washington, DC 20426, (202) 219-2919.
Brian R. Gish (Legal Information), Federal Energy Regulatory
Commission, 888 First Street, NE, Washington, DC 20426, (202) 208-0996.
James Apperson (Collaborative Process), Federal Energy Regulatory
Commission, 888 First Street, NE, Washington, DC 20426, (202) 219-2962.
SUPPLEMENTARY INFORMATION: In addition to publishing the full text of
this document in the Federal Register, the Commission provides all
interested persons an opportunity to view and/or print the contents of
this document via the Internet through FERC's Home Page (http://
www.ferc.fed.us) and in FERC's Public Reference Room during normal
business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First
Street, NE, Room 2A, Washington, DC 20426.
From FERC's Home Page on the Internet, this information is
available in both the Commission Issuance Posting System (CIPS) and the
Records and Information Management System (RIMS).
--CIPS provides access to the texts of formal documents issued by the
Commission since November 14, 1994.
--CIPS can be access using the CIPS link or the Energy Information
Online icon. The full text of this document will be available on CIPS
in ASCII and WordPerfect 8.0 format for viewing, printing, and/or
downloading.
--RIMS contains images of documents submitted to and issued by the
Commission after November 16, 1981. Documents from November 1995 to the
present can be viewed and printed from FERC's Home Page using the RIMS
link or the Energy Information Online icon. Descriptions of documents
back to November 16, 1981, are also available from RIMS-on-the-Web;
requests for copies of these and other older documents should be
submitted to the Public Reference Room.
User assistance is available for RIMS, CIPS, and the Website during
normal business hours from our Help line at (202) 208-2222 (E-Mail to
WebMaster@ferc.fed.us) or the Public Reference at (202) 208-1371 (E-
Mail to public.referenceroom@ferc.fed.us).
During normal business hours, documents can also be viewed and/or
printed in FERC's Public Reference Room, where RIMS, CIPS, and the FERC
Website are available. User assistance is also available.
Table of Contents
I. Introduction and Summary
II. Background
A. The Foundation for Competitive Markets: Order Nos. 888 and
889
B. Developments Since Order Nos. 888 and 889
1. Industry Restructuring and New Stresses on the Transmission
Grid
2. Successes, Failures and Haphazard Development of Regional
Transmission Entities
3. The Commission's ISO and RTO Inquires; Conferences with
Stakeholders and State Regulators
III. Discussion
A. Existence of Barriers and Impediments to Achieving Fully
Competitive Electricity Markets
B. Benefits That RTOs Can Offer to Address Remaining Barriers
and Impediments
C. Commission's Approach to RTO Formation
1. Voluntary Approach
2. Organizational Form of an RTO
3. Degree of Specificity in the Rule
4. Legal Authority
D. Minimum Characteristics of an RTO
1. Independence (Characteristic 1)
2. Scope and Regional Configuration (Characteristic 2)
3. Operational Authority (Characteristic 3)
4. Short-Term Reliability (Characteristic 4)
E. Minimum Functions of an RTO
1. Tariff Administration and Design (Function 1)
2. Congestion Management (Function 2)
3. Parallel Path Flow (Function 3)
4. Ancillary Services (Function 4)
5. OASIS and Total Transmission Capability (TTC) and Available
Transmission Capability (ATC) (Function 5)
6. Market Monitoring (Function 6)
7. Planning and Expansion (Function 7)
8. Interregional Coordination (Function 8)
F. Open Architecture
G. Transmission Ratemaking Policy for RTOs
1. Pancaked Rates
2. Reciprocal Waiving of Access Charges Between RTOs
3. Uniform Access Charges
4. Congestion Pricing
5. Service to Transmission-Owning Utilities That Do Not
Participate in an RTO
6. Performance-Based Rate Regulation
7. Other RTO Transmission Ratemaking Reforms
8. Additional Ratemaking Issues
9. Filing Procedures for Innovative Rate Proposals
H. Other Issues
1. Public Power and Cooperative Participation in RTOs
2. Participation by Canadian and Mexican Entities
3. Existing Transmission Contracts
4. Power Exchanges (PXs)
5. Effect on Retail Markets and Retail Access
6. Effect on States with Low Cost Generation
7. States' Roles with Regard to RTOs
8. Accounting Issues
9. Market Design Lessons
I. Collaborative Process
J. Implementation Issues
1. Filing Requirements
2. Deadline for RTO Operation
3. Commission Processing Procedures
4. Other Implementation Issues
IV. Environmental Statement
V. Regulatory Flexibility Act Certification
VI. Public Reporting Burden and Information Collection Statement
VII. Effective Date and Congressional Notification
VIII. Document Availability
Regulatory Text
Appendix
Before Commissioners: James J. Hoecker, Chairman; William L. Massey,
Linda Breathitt, and Curt Hebert, Jr.
I. Introduction and Summary
In 1996 the Commission put in place the foundation necessary for
competitive wholesale power markets in this country--open access
[[Page 811]]
transmission. 1 Since that time, the industry has undergone
sweeping restructuring activity, including a movement by many states to
develop retail competition, the growing divestiture of generation
plants by traditional electric utilities, a significant increase in the
number of mergers among traditional electric utilities and among
electric utilities and gas pipeline companies, large increases in the
number of power marketers and independent generation facility
developers entering the marketplace, and the establishment of
independent system operators (ISOs) as managers of large parts of the
transmission system. Trade in bulk power markets has continued to
increase significantly and the Nation's transmission grid is being used
more heavily and in new ways.
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\1\ See Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities and
Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities, Order No. 888, 61 FR 21,540 (May 10, 1996), FERC Stats. &
Regs. para. 31,036 (1996) (Order No. 888), order on reh'g, Order No.
888-A, 62 FR 12,274 (March 14, 1997), FERC Stats. & Regs. para.
31,048 (1997) (Order No. 888-A), order on reh'g, Order No. 888-B, 81
FERC para. 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC
para. 61,046 (1998), appeal docketed, Transmission Access Policy
Study Group, et al. v. FERC, Nos. 97-1715 et al. (D.C. Cir.).
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On May 13, 1999, the Commission proposed a rule on Regional
Transmission Organizations (RTOs) that identified and discussed our
concerns with the traditional means of grid management.2 In
that Notice of Proposed Rulemaking (NOPR), the Commission reviewed
evidence that traditional management of the transmission grid by
vertically integrated electric utilities was inadequate to support the
efficient and reliable operation that is needed for the continued
development of competitive electricity markets, and that continued
discrimination in the provision of transmission services by vertically
integrated utilities may also be impeding fully competitive electricity
markets. These problems may be depriving the Nation of the benefits of
lower prices and enhanced reliability. The comments on the NOPR
overwhelmingly support the conclusion that independent regionally
operated transmissions grids will enhance the benefits of competitive
electricity markets. Competition in wholesale electricity markets is
the best way to protect the public interest and ensure that electricity
consumers pay the lowest price possible for reliable service.
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\2\ Regional Transmission Organizations, Notice of Proposed
Rulemaking, 64 FR 31,390 (June 10, 1999), FERC Stats. & Regs. para.
32,541 at 33,683-781 (1999).
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Regional institutions can address the operational and reliability
issues now confronting the industry, and eliminate any residual
discrimination in transmission services that can occur when the
operation of the transmission system remains in the control of a
vertically integrated utility. Appropriate regional transmission
institutions could: (1) Improve efficiencies in transmission grid
management; 3 (2) improve grid reliability; (3) remove
remaining opportunities for discriminatory transmission practices; (4)
improve market performance; and (5) facilitate lighter handed
regulation.
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\3\ As discussed more fully later, appropriate regional
institutions could improve efficiencies in grid management through
improved pricing, congestion management, more accurate estimates of
Available Transmission Capability, improved parallel path flow
management, more efficient planning, and increased coordination
between regulatory agencies.
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Thus, we believe that appropriate RTOs could successfully address
the existing impediments to efficient grid operation and competition
and could consequently benefit consumers through lower electricity
rates resulting from a wider choice of services and service providers.
In addition, substantial cost savings are likely to result from the
formation of RTOs.
Based on careful consideration of the thoughtful comments submitted
in response to the NOPR,4 the Commission adopts a final rule
that generally follows the approach of the NOPR. Our objective is for
all transmission-owning entities in the Nation, including non-public
utility entities, to place their transmission facilities under the
control of appropriate RTOs in a timely manner. Therefore, we are
establishing in this rule minimum characteristics and functions for
appropriate RTOs; a collaborative process by which public utilities and
non-public utilities that own, operate or control interstate
transmission facilities, in consultation with state officials as
appropriate, will consider and develop RTOs; a proposal to consider
transmission ratemaking reforms on a case-specific basis; an
opportunity for non-monetary regulatory benefits, such as deference in
dispute resolution and streamlined filing and approval procedures; and
a time line for public utilities to make appropriate filings with the
Commission to initiate operation of RTOs. As a result of this voluntary
approach, we expect jurisdictional utilities to form RTOs. If the
industry fails to form RTOs under this approach, the Commission will
reconsider what further regulatory steps are in the public interest.
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\4\ The Commission received 334 initial and reply comments in
response to the NOPR. The commenters, and abbreviations for them as
used herein, are listed in an Appendix to this Final Rule.
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Pursuant to our authority under section 205 of the Federal Power
Act (FPA) to ensure that rates, terms and conditions of transmission
and sales for resale in interstate commerce by public utilities are
just, reasonable and not unduly discriminatory or preferential, and our
authority under section 202(a) of the FPA to promote and encourage
regional districts for the voluntary interconnection and coordination
of transmission facilities by public utilities and non-public utilities
for the purpose of assuring an abundant supply of electric energy
throughout the United States with the greatest possible economy, this
rule requires the following.
First, the Commission establishes minimum characteristics and
functions that an RTO must satisfy in the following areas:
Minimum Characteristics:
1. Independence
2. Scope and Regional Configuration
3. Operational Authority
4. Short-term Reliability
Minimum Functions:
1. Tariff Administration and Design
2. Congestion Management
3. Parallel Path Flow
4. Ancillary Services
5. OASIS and Total Transmission Capability (TTC) and Available
Transmission Capability (ATC)
6. Market Monitoring
7. Planning and Expansion
8. Interregional Coordination
Industry participants, however, retain flexibility in structuring RTOs
that satisfy the minimum characteristics and functions. For example, we
do not propose to require or prohibit any one form of organization for
RTOs or require or prohibit RTO ownership of transmission facilities.
The characteristics and functions could be satisfied by different
organizational forms, such as ISOs, transcos, combinations of the two,
or even new organizational forms not yet discussed in the industry or
proposed to the Commission. Likewise, the Commission is not proposing a
``cookie cutter'' organizational format for regional transmission
institutions or the establishment of fixed or specific regional
boundaries under section 202(a) of the FPA.
We also establish an ``open architecture'' policy regarding RTOs,
whereby all RTO proposals must allow the RTO and its members the
flexibility to improve their organizations in the
[[Page 812]]
future in terms of structure, operations, market support and geographic
scope to meet market needs. In turn, the Commission will provide the
regulatory flexibility to accommodate such improvement.
Second, to facilitate RTO formation in all regions of the Nation,
the Commission will sponsor and support a collaborative process to take
place in the Spring of 2000. Under this process, we expect that public
utilities and non-public utilities, in coordination with state
officials, Commission staff, and all affected interest groups, will
actively work toward the voluntary development of RTOs.
Third, we provide guidance on flexible transmission ratemaking that
may be proposed by RTOs, including ratemaking treatments that will
address congestion pricing and performance-based regulation. We also
propose to consider on a case-by-case basis incentive pricing that may
be appropriate for transmission facilities under RTO control.
Finally, all public utilities (with the exception of those
participating in an approved regional transmission entity that conforms
to the Commission's ISO principles) that own, operate or control
interstate transmission facilities must file with the Commission by
October 15, 2000, a proposal for an RTO with the minimum
characteristics and functions to be operational by December 15,
2001,5 or, alternatively, a description of efforts to
participate in an RTO, any existing obstacles to RTO participation, and
any plans to work toward RTO participation. We expect that such
proposals would include the transmission facilities of public utilities
as well as transmission facilities of public power and other non-public
utility entities to the extent possible. Through the required filings,
public utilities will make known to the public any plans for RTO
participation and any obstacles to RTO formation.
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\5\ An RTO proposal includes a basic agreement filed under
section 205 of the FPA setting out the rules, practices and
procedures under which the RTO will be governed and operated, and
requests by the public utility members of the RTO under section 203
of the FPA to transfer control of their jurisdictional transmission
facilities from individual public utilities to the RTO. Most RTO
proposals by public utilities are likely to involve one or more
filings under FPA sections 203 and 205, but the number and types of
filing may vary depending upon the type of RTO proposed and the
number of public utilities involved in the proposal. Under the Rule,
a utility may file a petition for a declaratory order asking, for
example, whether a proposed transmission entity would qualify as an
RTO or if a new or innovative method for pricing transmission
service would be acceptable, to be followed by appropriate filings
under sections 203 and 205.
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A public utility that is a member of an existing transmission
entity that has been approved by the Commission as in conformance with
the eleven ISO principles set forth in Order No. 888 must make a filing
no later than January 15, 2001. That filing must explain the extent to
which the transmission entity in which it participates meets the
minimum characteristics and functions for an RTO, and either propose to
modify the existing institution to the extent necessary to become an
RTO, or explain the efforts, obstacles and plans with respect to
conforming to these characteristics and functions.
The goal of this rulemaking is to form RTOs voluntarily and in a
timely manner. The alternative to a voluntary process is likely to be a
lengthy process that is more likely to result in greater
standardization of the Commission's RTO requirements among regions.
Although the Commission has specific authorities and responsibilities
under the FPA to protect against undue discrimination and remove
impediments to wholesale competition, we find it appropriate in this
instance to adopt an open collaborative process that relies on
voluntary regional participation to design RTOs that can be tailored to
specific needs of each region.
II. Background
In April 1996, in Order Nos. 888 6 and 889,7
the Commission established the foundation necessary to develop
competitive bulk power markets in the United States: non-discriminatory
open access transmission services by public utilities and stranded cost
recovery rules that would provide a fair transition to competitive
markets. Order Nos. 888 and 889 were very successful in accomplishing
much of what they set out to do. However, the orders were not intended
to address all problems that might arise in the development of
competitive power markets. Indeed, the nature of the emerging markets
and the remaining impediments to full competition that became apparent
in the nearly four years since the issuance of Order Nos. 888 and 889,
and the insightful comments and information presented to us by a wide
array of industry participants in this rulemaking proceeding have made
clear that the Commission must take further action if we are to achieve
the fully competitive power markets envisioned by those orders.
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\6\ See supra note 1.
\7\ Open Access Same-Time Information System (Formerly Real-Time
Information Networks) and Standards of Conduct, Order No. 889, 61 FR
21,737 (May 10, 1996), FERC Stats. & Regs. para. 31,035 (1996),
order on reh'g, Order No. 889-A, 62 FR 12,484 (March 14, 1997), FERC
Stats. & Regs. para. 31,049 (1997), order on reh'g, Order No. 889-B,
81 FERC para. 61,253 (1997).
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A. The Foundation for Competitive Markets: Order Nos. 888 and 889
In Order Nos. 888 and 889, the Commission found that unduly
discriminatory and anticompetitive practices existed in the electric
industry, and that transmission-owning utilities had discriminated
against others seeking transmission access.8 The Commission
stated that its goal was to ensure that customers have the benefits of
competitively priced generation, and determined that non-discriminatory
open access transmission services (including access to transmission
information) and stranded cost recovery were the most critical
components of a successful transition to competitive wholesale
electricity markets.9
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\8\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,682.
\9\ Id. at 31,652.
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Accordingly, Order No. 888 required all public utilities that own,
control or operate facilities used for transmitting electric energy in
interstate commerce to (1) file open access non-discriminatory
transmission tariffs containing, at a minimum, the non-price terms and
conditions set forth in the Order, and (2) functionally unbundle
wholesale power services. Under functional unbundling, the public
utility must: (1) take transmission services under the same tariff of
general applicability as do others; (2) state separate rates for
wholesale generation, transmission, and ancillary services; and (3)
rely on the same electronic information network that its transmission
customers rely on to obtain information about its transmission system
when buying or selling power.10 Order No. 889 required that
all public utilities establish or participate in an Open Access Same-
Time Information System (OASIS) that meets certain specifications, and
comply with standards of conduct designed to prevent employees of a
public utility (or any employees of its affiliates) engaged in
wholesale power marketing functions from obtaining preferential access
to pertinent transmission system information.
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\10\ Id. at 31,654-55.
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During the course of the Order No. 888 proceeding, the Commission
received comments urging it to require generation divestiture or
structural institutional arrangements such as regional independent
system operators (ISOs) to better assure non-discrimination. The
Commission responded that, while it believed that
[[Page 813]]
ISOs had the potential to provide significant benefits, efforts to
remedy undue discrimination should begin by requiring the less
intrusive functional unbundling approach. Subsequent to issuance of
Order No. 888, it has become apparent that several types of regional
transmission institutions, in addition to the kinds of ISOs approved to
date, may also be able to provide the benefits attributed to ISOs in
Order No. 888.
Order No. 888 set forth 11 principles for assessing ISO proposals
submitted to the Commission.11 Order No. 888 also stated:
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\11\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,730.
[W]e see many benefits in ISOs, and encourage utilities to
consider ISOs as a tool to meet the demands of the competitive
marketplace. As a further precaution against discriminatory
behavior, we will continue to monitor electricity markets to ensure
that functional unbundling adequately protects transmission
customers. At the same time, we will analyze all alternative
proposals, including formation of ISOs, and, if it becomes apparent
that functional unbundling is inadequate or unworkable in assuring
non-discriminatory open access transmission, we will reevaluate our
position and decide whether other mechanisms, such as ISOs, should
be required.12
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\12\ Id. at 31,655.
Below, we summarize our experiences with functional unbundling from the
date of issuance of Order Nos. 888 and 889.
B. Developments Since Order Nos. 888 and 889
In the nearly four years since Order Nos. 888 and 889 were issued,
numerous significant developments have occurred in the electric utility
industry. Some of these reflect changes in governmental policies;
others are strictly industry-driven. These activities have resulted in
a considerably different industry landscape from the one faced at the
time the Commission was developing Order No. 888, resulting in new
regulatory and industry challenges.
Order Nos. 888 and 889 required a significant change to the way
many public utilities have done business for most of this century, and
most public utilities accepted these changes and made substantial good
faith efforts to comply with the new requirements. Virtually all public
utilities have filed tariffs stating rates, terms and conditions for
comparable service to third-party users of their transmission systems.
In addition, improved information about the transmission system is
available to all participants in the market at the same time that it is
available to the public utility's merchant function and market
affiliate as a result of utility compliance with the OASIS regulations.
The availability of tariffs and information about the transmission
system has fostered a rapid growth in dependence on wholesale markets
for acquisition of generation resources. Areas that have experienced
generation shortages have seen rapid development of new generation
resources. For example, in the Northeast Power Coordinating Council
(NPCC) region (including New England, New York and parts of eastern
Canada), where there was deep concern about adequacy of generation
supply only three years ago, approximately 30,000 MW of generation is
proposed or actually under construction.13 That response
comes almost entirely from independent generating plants, which are
able to sell power into the bulk power market through open access to
the transmission system. Power resources are now acquired over
increasingly large regional areas, and interregional transfers of
electricity have increased. The very success of Order Nos. 888 and 889,
and the initiative of some utilities that have pursued voluntary
restructuring beyond the minimum open access requirements, have placed
new stresses on regional transmission systems--stresses that call for
regional solutions.
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\13\ Based on data supplied to the Commission by Resource Data
International.
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1. Industry Restructuring and New Stresses on the Transmission Grid
Open access transmission and the opening of wholesale competition
in the electric industry have brought an array of changes in the past
several years: Divestiture by many integrated utilities of some or all
of their generating assets; significantly increased merger activity
both between electric utilities and between electric and natural gas
utilities; increases in the number of new participants in the industry
in the form of both independent and affiliated power marketers and
generators as well as independent power exchanges; increases in the
volume of trade in the industry, particularly sales by marketers; state
efforts to introduce retail competition; and new and different uses of
the transmission grid.
With respect to divestiture, since August 1997, generating
facilities representing approximately 50,000 MW of generating capacity
have been sold (or are under contract to be sold) by utilities, and an
additional 30,000 MW is currently for sale. In total, this represents
more than ten percent of U.S. generating capacity. In all, 27 utilities
have sold all or some of their generating assets and seven others have
assets for sale. Buyers of this generating capacity have included
traditional utilities with specified service territories as well as
independent power producers with no required service territory.
Since Order No. 888 was issued, more than 40 applications have been
filed for Commission approval of proposed mergers involving public
utilities.14 Most of these merger proposals involve electric
utilities with contiguous service areas, although some of the proposed
mergers have been between utilities with non-contiguous service areas.
In addition, an increasing number of applications involve the
combination of electric and natural gas assets.
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\14\ See Commission's website, www.ferc.fed.us/electric/mergers.
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There has been significant growth in the volume of trading, and
particularly the number of marketers, in the wholesale electricity
market. For example, in the first quarter of 1995, according to power
marketer quarterly filings, marketer sales traded by only eight active
power marketers, totaled 1.8 million MWh. By the first quarter of 1999,
such sales escalated to over 400 million MWh, traded by over 100 power
marketers.15
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\15\ See Commission's website, www.ferc.fed.us/electric/PwrMkt.
The Commission recognizes that a significant portion of the sales
represent the retrading of power by a number of different market
participants, such that there may be multiple resales of the same
generation. Nonetheless, the volume of and intensity of trading
continues to increase in the wholesale electricity market.
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The Commission has granted market-based rate authority to more than
800 entities, of which nearly 500 are power marketers, (including over
100 marketers affiliated with investor-owned utilities). The remaining
entities include approximately equal numbers of affiliated power
producers, investor-owned utilities and other utilities.16
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\16\ See Commission's website, www.ferc.fed.us/electric.
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State commissions and legislatures have been active in the past few
years studying competitive options at the retail level, setting up
pilot retail access programs, and, in many states, implementing full
scale retail access programs. As of November 1, 1999, twenty-one states
had enacted electric restructuring legislation, three had issued
comprehensive regulatory orders, and twenty-six states plus the
District of Columbia had legislation or orders pending or
investigations underway.17 Fifteen states had implemented
full-
[[Page 814]]
scale or pilot retail competition programs that offer a choice of
suppliers to at least some retail customers. Eight states have
initiated programs to offer access to retail customers by a date
certain.
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\17\ See the Energy Information Administration website,
www.eia.doe.gov/cneaf/electricity/chg__str/regmap.html.
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Because of the changes in the structure of the electric industry,
the transmission grid is now being used more intensively and in
different ways than in the past. The Commission is concerned that the
traditional approaches to operating the grid are showing signs of
strain. According to the North American Electric Reliability Council
(NERC), ``the adequacy of the bulk transmission system has been
challenged to support the movement of power in unprecedented amounts
and in unexpected directions.'' 18 These changes in the use
of the transmission system ``will test the electric industry's ability
to maintain system security in operating the transmission system under
conditions for which it was not planned or designed.'' 19 It
should be noted that, despite the increased transmission system
loadings, NERC believes that the ``procedures and processes to mitigate
potential reliability impacts appear to be working reliably for now,''
and that even though the system was particularly stressed during the
summer of 1998, ``the system performed reliably and firm demand was not
interrupted due to transmission transfer limitations.'' 20
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\18\ Reliability Assessment 1998-2007, North American Electric
Reliability Council (September 1998), at 26 (Reliability
Assessment).
\19\ Id.
\20\ Id.
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An indication that the increased and different use of the
transmission system is stressing the grid is the increased use of
transmission line loading relief (TLR) procedures.21 And,
according to published reports, the incidence of TLRs is growing. While
in all of 1998 over 300 TLRs were called, in the first ten months of
1999, over 400 TLRs have been called, resulting in over 8,000 MW of
power curtailment in the three-month summer period beginning June
1999.22
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\21\ The TLR procedures are designed to remedy overloads that
result when a transmission line or other transmission equipment
carries or will carry more power than its rating, which could result
in either power outages or damage to property. The TLR procedures
are designed to bring overloaded transmission equipment to within
NERC's Operating Security Limits essentially by curtailing
transactions contributing to the overload. See North American
Electric Reliability Council, 85 FERC para. 61,353 (1998) (NERC).
\22\ Power Markets Week, November 8, 1999 at 1, citing NERC
data.
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It appears that the planning and construction of transmission and
transmission-related facilities may not be keeping up with increased
requirements. According to NERC, ``business is increasing on the
transmission system, but very little is being done to increase the load
serving and transfer capability of the bulk transmission system.''
23 The amount of new transmission capacity planned over the
next ten years is significantly lower than the additions that had been
planned five years ago, and most of the planned projects are for local
system support.24 NERC states that, ``The close coordination
of generation and transmission planning is diminishing as vertically
integrated utilities divest their generation assets and most new
generation is being proposed and developed by independent power
producers.'' 25
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\23\ Reliability Assessment at 26.
\24\ Id. at 7.
\25\ Id.
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The transition to new market structures has resulted in new
challenges and circumstances. For example, during the week of June 22-
26, 1998, the wholesale electric market in the Midwest experienced
numerous events that led to unprecedented high spot market prices. Spot
wholesale market prices for energy briefly rose as high as $7,500 per
MWh, compared with an average price for the summer of approximately $40
per MWh in the Midwest if the pricing abnormalities are
excluded.26 This experience led to calls for price caps,
allegations of market power, and a questioning of the effectiveness of
transmission open access and wholesale electric competition.
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\26\ See Staff Report to the Federal Energy Regulatory
Commission on the Causes of Wholesale Electric Pricing Abnormalities
in the Midwest During June 1998, (Sept. 22, 1998) (Staff Price Spike
Report) at 3-8 to 3-11. Unusually high spot market wholesale prices
also occurred during the summer of 1999. The Commission is not aware
that any formal evaluations of market data have been performed for
that occurrence of price abnormalities.
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The Commission staff undertook an investigation of the pricing
abnormalities. Staff's report concluded that the unusually high price
levels were caused by a combination of factors, particularly above-
average generation outages, unseasonably hot temperatures, storm-
related transmission outages, transmission constraints, poor
communication of price signals, lowered confidence in the market due to
a few contract defaults, and inexperience in dealing with competitive
markets.27
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\27\ 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.'' 28 Support for this view comes
from many sources. For example, the Public Utilities Commission of
Ohio, in its own report on the high spot market prices, recommended
that policy makers ``take unambiguous action to require coordination of
transmission system operations by regionwide Independent System
Operators.'' 29
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\28\ Id. at 5-8.
\29\ Ohio's Electric Market, June 22-26, 1998, What Happened and
Why, A Report to the Ohio General Assembly, at iii.
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On September 29, 1998, the Secretary of Energy Advisory Board Task
Force on Electric System Reliability published its final
report.30 The Task Force was convened in January 1997 to
provide advice to the Department of Energy on critical institutional,
technical, and policy issues that need to be addressed in order to
maintain bulk power electric system reliability in a more competitive
industry. The Task Force found that ``the traditional reliability
institutions and processes that have served the Nation well in the past
need to be modified to ensure that reliability is maintained in a
competitively neutral fashion;'' that ``grid reliability depends
heavily on system operators who monitor and control the grid in real
time;'' and that ``because bulk power systems are regional in nature,
they can and should be operated more reliably and efficiently when
coordinated over large geographic areas.'' 31
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\30\ Maintaining Reliability in a Competitive U.S. Electricity
Industry; Final Report of the Task Force on Electric System
Reliability (Sept. 29, 1998) (Task Force Report). The Task Force was
comprised of 24 members representing all major segments of the
electric industry, including private and public suppliers, power
marketers, regulators, environmentalists, and academics.
\31\ Task Force Report at x-xi.
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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
[[Page 815]]
portion of the network, consequently improving market efficiencies and
promoting greater competition; and (4) eliminate ``pancaking'' of
transmission rates, thus allowing a greater range of economic energy
trades across the network.32
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\32\ 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,33 PJM ISO,34 ISO New
England,35 the New York ISO,36 and the Midwest
ISO.37 In addition, the Texas Commission has ordered an ISO
for the Electric Reliability Council of Texas (ERCOT).38
Moreover, our international neighbors in Canada and Mexico are also
pursuing electric restructuring efforts that include various forms of
regional transmission entities.39
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\33\ Pacific Gas & Electric Company, et al., 77 FERC para.
61,204 (1996), order on reh'g, 81 FERC para. 61,122 (1997) (Pacific
Gas & Electric).
\34\ Pennsylvania-New Jersey-Maryland Interconnection, et al.,
81 FERC para. 61,257 (1997), order on reh'g, 82 FERC para. 61,047
(1998) (PJM).
\35\ New England Power Pool, 79 FERC para. 61,374 (1997), order
on reh'g, 85 FERC para. 61,242 (1998) (NEPOOL).
\36\ Central Hudson Gas & Electric Corporation, et al., 83 FERC
para. 61,352 (1998), order on reh'g, 87 FERC para. 61,135 (1999)
(Central Hudson).
\37\ Midwest Independent Transmission System Operator, et al.,
84 FERC para. 61,231, order on reconsideration, 85 FERC para.
61,250, order on reh'g, 85 FERC para. 61,372 (1998) (Midwest ISO).
\38\ See 16 Texas Administrative Code Sec. 23.67(p).
Furthermore, on June 18, 1999, S.B.7 was enacted to restructure the
Texas electric industry allowing retail competition. The bill
requires retail competition to begin by January 2002. Rates will be
frozen for three years, and then a six percent reduction will be
required for residential and small commercial consumers.
\39\ See Policy Proposal for Structural Reform of the Mexican
Electricity Industry, Secretary of Energy, Mexico (Feb. 1999); Third
Interim Report of the Ontario Market Design Committee (Oct. 1998);
TransAlta Enterprises Corporation, 75 FERC para. 61,268 at 61,875
(1996) (recognition of the restructuring in the Province of Alberta,
Canada to create a Grid Company of Alberta).
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The PJM, New England and New York ISOs were established on the
platform of existing tight power pools. It appears that the principal
motivation for creating ISOs in these situations was the Order No. 888
requirement that there be a single systemwide transmission tariff for
tight pools. In contrast, the establishment of the California ISO and
the ERCOT ISO was the direct result of mandates by state governments.
The Midwest ISO, which is not yet operational, is unique. It was
neither required by government nor based on an existing institution.
Two states in the region subsequently required utilities in their
states to participate in either a Commission-approved ISO (Illinois and
Wisconsin), or sell their transmission assets to an independent
transmission company that would operate under a regional ISO
(Wisconsin).
As part of general restructuring initiatives, several states now
require independent grid management organizations. For example, an
Illinois law required that its utilities become members of a FERC-
approved regional ISO by March 31, 1999, and Wisconsin law gives its
utilities the option of joining an ISO or selling their transmission
assets to an independent transmission company by June 30, 2000. In both
states, the backstop is a single-state organization if regional
organizations are not developed. Recently, Virginia,40
Arkansas 41 and Ohio42 have also enacted
legislation requiring their electric utilities to join or establish
regional transmission entities.
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\40\ See Virginia Electric Utility Restructuring Act, S1269
(Mar. 25, 1999). In Virginia, electric utilities are required by
January 2001, to join or establish regional transmission entities.
\41\ See The Arkansas Electric Consumer Choice Act of 1999, Act
1, 82nd General Assembly (Apr. 1999).
\42\ See Amended Substitute Senate Bill No. 3, 123rd General
Assembly (July 6, 1999).
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The approved ISOs have similarities as well as differences. All
five Commission-approved ISOs operate, or propose to operate, as non-
profit organizations. All five ISOs include both public and non-public
utility members. However, among the five, there is considerable
variation in governance, operational responsibilities, geographic scope
and market operations. Four of the ISOs rely on a two-tier form of
governance with a non-stakeholder governing board on top that is
advised, either formally or informally, by one or more stakeholder
groups. In general, the final decision making authority rests with the
independent non-stakeholder board. One ISO, the California ISO, uses a
board consisting of stakeholders and non-stakeholders.
Four of the five ISOs operate a single control area, but the large
Midwest ISO does not currently plan to operate a single control area.
Three are multi-state ISOs (New England, PJM and Midwest), while two
ISOs (California and New York) currently operate within a single state.
The current Midwest ISO members do not encompass one contiguous
geographic area. The ISO New England administers a separate NEPOOL
tariff, while the other four administer their own ISO transmission
tariffs.
Three ISOs operate or propose to operate centralized power markets
(New England, PJM and New York), and one ISO (California) relies on a
separate power exchange (PX) to operate such a market.43 The
Midwest ISO has not proposed an ISO-related centralized market for its
region.44 In addition, at least one separate PX has begun to
do business in California apart from the PX established through the
restructuring legislation.45
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\43\ The California PX offers day-ahead and hour-ahead markets
and the ISO operates a real-time energy market. Participation in the
PX market is voluntary except that the three traditional investor-
owned utilities in California must bid their generation sales and
purchases through the PX for the first five years. New York will
offer day-ahead and real-time energy markets that will be operated
by the ISO. PJM and New England offer only real-time energy markets,
although PJM has proposed to operate a day-ahead market. The ERCOT
ISO is the only other ISO that does not currently operate a PX.
\44\ There are indications, however, that the Midwest ISO is
considering the formation of a power exchange. See Joint Committee
for the Development of a Midwest Independent Power Exchange,
``Solicitation of Interest-Creation of an Independent Power Exchange
for the U.S. Midwest,'' February 5, 1999.
\45\ See Automated Power Exchange, Inc., 82 FERC para. 61,287,
reh'g denied, 84 FERC para. 61,020 (1998), appeals docketed, No. 98-
1415 (D.C. Cir. Sept. 14, 1998) and No. 98-1419 (D.C. Cir. Sept. 14,
1998).
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The existing ISOs are also evolving in terms of their governance
structure and as a result of operating experience with the transmission
systems and the various markets they operate. For example, the
Commission rejected the original governance proposals for two ISOs: the
New England ISO and New York ISO. In both cases, the Commission
concluded that the vertically integrated utility members of the ISO
would have too much voting power in the various advisory committees
that provide advice and recommendations to the non-stakeholder Boards.
The ISOs resubmitted governance proposals that gave balanced
representation to the various sectors of stakeholders, and the
Commission subsequently approved both revised governance structures.
In addition, the Commission has considered a number of significant
modifications of market rules proposed by the existing ISOs in the
seven months since issuance of the RTO
[[Page 816]]
NOPR. In particular, a number of rules for the California ISO and New
England ISO have been modified, affecting the products traded in, and
the timing of, the markets for energy, ancillary services, balancing
services and transmission.
An additional few transmission restructuring proposals that were
pending as of the date of issuance of the RTO NOPR have been approved
by the Commission, and others have been filed since that date. In July
1999, the Commission granted a petition for declaratory order filed by
Entergy Services Inc., in which the majority concluded that passive
ownership of a transmission entity by a generating company or other
market participant could meet the ISO principles contained in Order No.
888. The order stated, however, that the passive ownership must be
properly designed, such that the transmission entity is truly
independent of the market participants.46 Another filing
that was pending when the NOPR was issued was the request by
FirstEnergy to sell its transmission assets to a newly-formed
affiliate. The Commission approved the disposition of jurisdictional
facilities, noting that the proposed action would not adversely affect
competition, rates or regulation. In addition, the Commission noted
that the creation of the transmission-owning affiliate would facilitate
the subsequent transfer of FirstEnergy's transmission facilities to an
RTO, which FirstEnergy pledged to do within two years of Commission
approval of the disposition of facilities to its
affiliate.47
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\46\ See Entergy Services, Inc., 88 FERC para. 61,149 (1999)
(Commissioner Massey dissented from this order).
\47\ See FirstEnergy Operating Companies, et al., 89 FERC para.
61,090 (1999).
---------------------------------------------------------------------------
Since issuance of the RTO NOPR, the Alliance Companies filed a
proposal to create an RTO. Applicants suggest that the RTO could take
one of two forms, either an ISO or a transco, but note that they prefer
a transco configuration in which, at least initially, the five
transmission-owning participants could hold five percent ownership
stakes in the transco.48
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\48\ See Application of Alliance Companies in Docket No. ER99-
3144-000 (filed June 3, 1999). The Commission issued an order on
this application concurrently with the issuance of this Final Rule.
See Alliance Companies, 89 FERC para.____ (1999) (Alliance
Companies).
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Not all efforts to create ISOs have been successful. For example,
after more than two years of effort, the proponents of the IndeGO
(Independent Grid Operator) ISO in the Pacific Northwest and Rocky
Mountain regions ended their efforts to create an ISO.49
More recently, members of the Mid-American Power Pool (MAPP), an
existing power pool that covers six U.S. states and two Canadian
provinces, failed to achieve consensus for establishing a long-planned
ISO.50 In the Southwest, proponents of the Desert STAR ISO
have not been able to reach agreement to date on a formal proposal
after more than two years of discussion.51 In the interim
period, some of the participants in the Desert STAR ISO have filed at
the Commission a proposal to create the Mountain West Independent
Scheduling Administrator, which would oversee the scheduling of
transmission service within Nevada.52
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\49\ Recently, however, parties in the Pacific Northwest have
resumed RTO discussions.
\50\ However, trade press reports suggest that while MAPP
members continue to try to reach consensus, the Midwest ISO is in
discussion with MAPP members to join the Midwest ISO. See Inside
FERC, July 26, 1999; The Energy Report, Nov. 1, 1999 at 931.
\51\ Recent press reports, however, indicate that Desert STAR
has incorporated as a non-profit organization, a first step toward
the launch of an ISO. See Energy Daily, Nov. 5, 1999 at 2.
\52\ See Application of Mountain West Independent Transmission
Administrator in Docket No. ER99-3719-000 (filed July 23, 1999).
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Various reasons have been advanced to explain the difficulty in
forming a voluntary, multi-state ISO. Reasons include: ``cost
shifting,'' which involves increases in transmission rates for some
parties; disagreements about sharing of ISO transmission revenues among
transmission owners; difficulties in obtaining the participation of
publicly-owned transmission facilities; concerns about the loss of
transmission rights and prices embedded in existing transmission
agreements; and the preference of certain transmission owners to sell
or transfer their transmission assets to a for-profit transmission
company in lieu of handing over control to a non-profit ISO.
3. The Commission's ISO and RTO Inquiries; Conferences With
Stakeholders and State Regulators
In light of the various restructuring activities occurring
throughout the United States, the Commission has held 11 public
conferences in nine different cities across the country to hear the
views of industry, consumers, and state regulators with respect to the
need for RTOs and their appropriate roles and responsibilities.
The Commission initiated an inquiry in March 1998 pertaining to its
policies on ISOs. A notice establishing procedures for a conference
gave the following rationale:
In Order Nos. 888 and 889 and their progeny, the Commission
established the fundamental principles of non-discriminatory open
access transmission services. Nevertheless, many issues remain to be
addressed if the Nation is to fully realize the benefits of open
access and more competitive electric markets.
* * * * *
Given the dramatic changes taking place in both wholesale and
retail electric markets and the many proposals under consideration
with respect to the creation of ISOs or other transmission entities,
such as transmission-only utilities, it is time for the Commission
to take stock of its policies in order to determine whether they
appropriately support our dual goals of eliminating undue
discrimination and promoting competition in electric power
markets.53
\53\ Inquiry Concerning the Commission's Policy on Independent
System Operators, Notice of Conference, Docket No. PL98-5-000, at 1-
2 (March 13, 1998).
Accordingly, the Commission held a series of eight conferences in 1998
to gain insight into participants' views on the formation and role of
ISOs in the electric utility industry. The first conference was held in
April 1998 at the Commission's offices in Washington, D.C. Between May
28 and June 8, 1998, the Commission held seven regional conferences in
Phoenix, Kansas City, New Orleans, Indianapolis, Portland, Richmond and
Orlando. As a result of these conferences, the Commission heard
approximately 145 oral presentations and received a large number of
written comments on the appropriate size, scope, organization and
functions of regional transmission institutions. A number of different
of viewpoints were expressed.54
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\54\ A summary of those views was included as Appendix A to the
NOPR in this docket.
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On October 1, 1998, the Secretary of Energy delegated his authority
under section 202(a) of the FPA to the Commission. In doing so, the
Secretary stated that section 202(a) ``provides DOE with sufficient
authority to establish boundaries for Independent System Operators
(ISOs) or other appropriate transmission entities.'' 55 The
Secretary also stated: ``FERC is also increasingly faced with
reliability-related issues. Providing FERC with the authority to
establish boundaries for ISOs or other appropriate transmission
entities could aid in the orderly formation of properly-sized
transmission institutions and in addressing reliability-related issues,
thereby increasing the reliability of the transmission system.''
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\55\ 63 FR 53,889 (Oct. 7, 1998).
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On November 24, 1998, we gave notice in this docket of our intent
to initiate a consultation process with State commissions pursuant to
section
[[Page 817]]
202(a).56 The purpose of the consultations was to afford
State commissions a reasonable opportunity to present their views with
respect to appropriate boundaries for regional transmission
institutions and other issues relating to RTOs. Conferences with State
commissioners were held in St. Louis, Missouri, on February 11, 1999;
in Las Vegas, Nevada, on February 12, 1999; and in Washington, D.C., on
February 17, 1999. In all, we heard oral presentations by
representatives of 41 state commissions during these consultations,
with others monitoring or providing written comments.57
During these sessions, we received much valuable advice. Furthermore,
we have had additional consultations since issuance of the RTO NOPR in
May 1999.
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\56\ Regional Transmission Organizations, Notice of Intent to
Consult with State Commission, 63 FR 66,158 (Dec. 1, 1998), FERC
Stats & Regs. para. 35,534 (1998).
\57\ See Appendix for a list of commenters.
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III. Discussion
A. Existing Barriers and Impediments To Achieving Fully Competitive
Electricity Markets
In the NOPR, the Commission expressed its belief that there remain
important transmission-related impediments to a competitive wholesale
electric market. The Commission grouped these remaining impediments
into two broad categories: (1) The engineering and economic
inefficiencies inherent in the current operation and expansion of the
transmission grid, and (2) continuing opportunities for transmission
owners to unduly discriminate in the operation of their transmission
systems so as to favor their own or their affiliates' power marketing
activities.58
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\58\ FERC Stats. & Regs. para. 32,541 at 33,696.
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With respect to engineering and economic inefficiencies, the NOPR
noted that the transmission facilities of any one utility in a region
are part of a larger, integrated transmission system which, from an
electrical engineering perspective, operates as a single
machine.59 Engineering and economic inefficiencies occur
because each separate operator usually makes independent decisions
about the use, limitations and expansion of its piece of the
interconnected grid based on incomplete information, even though any
action taken by one transmission provider can have major and
instantaneous effects on the transmission facilities of all other
transmission providers. The Commission noted that, while this was not a
new phenomenon, the demands placed on the transmission grid had changed
in recent years due to (1) increases in bulk power trade, (2) large
shifts in power flows, and (3) an increasingly de-integrated and
decentralized competitive power industry.60 As a consequence
of these changes in trade patterns and industry structure, certain
operational problems had become more significant and difficult to
resolve.
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\59\ Id. at 33,697.
\60\ See id.
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Engineering and Economic Inefficiencies. The NOPR identified a
number of specific economic and engineering inefficiencies. First, the
NOPR noted that the reliability of the nation's bulk power system was
being stressed in ways that have never been experienced before, and
questioned the continued feasibility of one-on-one coordination of an
interconnected transmission grid encompassing more than 100
transmission owners and 140 separate control areas.61
Second, the NOPR observed that there were increasing difficulties in
accurately computing Total Transmission Capacity (TTC) and Available
Transmission Capacity (ATC), assessments that require reliable and
timely information about load, generation, facility outages and
transactions on neighboring systems, as well as consistency in
methodologies among systems.62 Third, the NOPR noted that
efficient congestion management required regional actions, and that the
current methods for managing congestion (e.g., Transmission Line
Loading Relief procedures in the Eastern Interconnection), which do not
attempt to optimize regional congestion relief, were cumbersome,
inefficient and disruptive to bulk power markets.63 Fourth,
the NOPR expressed concern that the uncertainty associated with
transmission planning and expansion had increased with the increasing
number and distance of unbundled transactions and the wider variation
in generation dispatch patterns. The NOPR pointed to a noticeable
decline in planned transmission investments and expressed concern that,
without a regional approach to planning and expansion, it would be
difficult to address complex and controversial issues that arise when
the benefits of an expansion do not necessarily accrue to the
transmission system that must undertake the expansion.64
Finally, the NOPR explained that pancaked transmission rates (where a
separate access charge is assessed every time the transaction contract
path crosses the boundary of another transmission owner) restrict the
size of regional power markets. The Commission added that the
balkanization of electricity markets hurts consumers who pay higher
transmission rates and have access to fewer generation
options.65
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\61\ See id. at 33,699.
\62\ Id. at 33,700.
\63\ Id. at 33,701-02.
\64\ See id. at 33,702-03.
\65\ Id. at 33,703.
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Continuing Opportunities for Undue Discrimination. With respect to
continuing opportunities for undue discrimination, the NOPR observed
that, when utilities control monopoly transmission facilities and also
have power marketing interests, they have poor incentives to provide
equal quality transmission service to their power marketing
competitors.66 The NOPR explained that the Commission had
made this point in Order No. 888:
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\66\ Id. at 33,704.
It is in the economic self-interest of transmission monopolists,
particularly those with high-cost generation assets, to deny
transmission or to offer transmission on a basis that is inferior to
that which they provide themselves. The inherent characteristics of
monopolists make it inevitable that they will act in their own self-
interest to the detriment of others by refusing transmission and/or
providing inferior transmission to competitors in the bulk power
markets to favor their own generation, and it is our duty to
eradicate unduly discriminatory practices.67
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\67\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,682.
In the NOPR, the Commission noted that functional unbundling does not
change the incentives of vertically integrated utilities to use their
transmission assets to favor their own generation, but instead attempt
to reduce the ability of utilities to act on those
incentives.68
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\68\ As noted in the NOPR, in Order No. 888, the Commission
received and considered numerous comments that functional unbundling
was unlikely to work, and that more drastic restructuring, such as
corporate unbundling, was needed. For example, the Federal Trade
Commission advised the Commission that a functional unbundling
approach ``* * * would leave in place the incentive and opportunity
for some utilities to exercise market power in the regulated system.
Preventing them from doing so by enforcing regulations to control
their behavior may prove difficult.'' However, the Commission
decided at the time to adopt the less intrusive and less costly
remedy of functional unbundling. FERC Stats. & Regs. para. 32,541 at
33,707.
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The NOPR expressed concern about continuing indications that
transmission service problems related to discriminatory conduct remain
and concluded that these problems are impeding competitive wholesale
power markets.69 The NOPR also noted that
[[Page 818]]
instances of actual discrimination may be undetectable in a non-
transparent market and, in any event, it is often hard to determine, on
an after-the-fact basis, whether an action was motivated by an intent
to favor affiliates or simply reflected the impartial application of
operating or technical requirement. The NOPR added that, while
continued discrimination may be deliberate, it could also result from
the failure to make sufficient efforts to change the way integrated
utilities have done business for many years. The Commission expressed
concern that the difficulty in determining whether there has been
compliance with our regulations raises the question as to whether
functional unbundling is an appropriate long-term regulatory solution.
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\69\ The NOPR described specific examples of undue
discrimination that had been brought to its attention through formal
complaints, informal complaints made to the Commission's enforcement
hotline, oral and written comments made in conjunction with public
conferences held by the Commission, and pleadings filed with the
Commission in various dockets. The complaints generally involved:
(1) Calculation and posting of ATC in a manner favorable to the
transmission provider; (2) standards of conduct violations, (3) line
loading relief and congestion management, and (4) OASIS sites that
are difficult to use. See id. at 33,707-13.
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The NOPR explained that the Commission considers allegations of
discrimination, even if not reduced to formal findings, to be a serious
concern for two reasons. First, this can be indicative of additional,
unreported, discriminatory actions, because there are significant
disincentives to filing and pursuing formal complaints that would
result in definitive findings.70 The NOPR expressed a
concern that actual problems with functional unbundling may be more
pervasive than formally adjudicated complaints would suggest. Second,
the NOPR explained that allegations of discrimination are serious
because, if nothing else, they represent a perception by market
participants that the market is not working fairly. If market
participants perceive that other participants have an unfair advantage
through their ownership or control of transmission facilities, it can
inhibit their willingness to participate in the market, thus thwarting
the development of robust competition. The NOPR added that such
mistrust can also harm reliability.71
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\70\ As noted in the NOPR, transmission customers are reluctant
to make even informal complaints because they fear retribution by
their transmission supplier; the complaint process is costly and
time-consuming; the Commission's remedies for violations do not
impose sufficient financial consequences on the transmission
provider to act as a significant deterrent; and, in the fast-paced
business of power marketing, there may be no adequate remedy for the
lost short-term sales opportunities in after-the-fact enforcement.
See FERC Stats. & Regs. para. 32,541 at 33,706.
\71\ Id.
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The NOPR explained the potential for undue discrimination increases
in a competitive environment unless the market can be made structurally
efficient and transparent with respect to information, and equitable in
its treatment of competing participants. Also, a system that attempts
to control behavior that is motivated by economic self-interest through
the use of standards of conduct will require constant and extensive
policing and requires the Commission to regulate detailed aspects of
internal company policy and communication. The NOPR added that
functional unbundling does not necessarily promote light-handed
regulation and undoubtedly imposes a cost on those entities that have
to comply with the standards of conduct and abide by rules that limit
the flexibility of their internal management activities. The NOPR
stated that the perception that many entities that operate the
transmission system cannot be trusted is not a good foundation on which
to build a competitive power market, and it created needless
uncertainty and risk for new investments in generation.72
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\72\ See id. at 33,714.
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Comments. Engineering and Economic Inefficiencies. Virtually all
commenters support the NOPR's premise that engineering and economic
inefficiencies exist in the operation, planning and expansion of the
regional transmission grid and that these inefficiencies hinder
electric system reliability and a fully competitive bulk power
market.73 Many commenters state further that, in the new
industry structure, coordinated regional transmission planning has
become a thing of the past and new transmission additions that will
benefit reliable grid operations are being delayed.74
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\73\ See, e.g., Duquesne, Entergy, Florida Power Corp., NU,
Kentucky Commission, NECPUC, Ohio Commission, Texas Commission, DOE,
American Forest, Arkansas Cities, East Texas Cooperatives, EPSA,
First Rochdale, FMPA, Oglethorpe, PNGC, Powerex, Public Citizen,
SoCal Cities, Sonat, Williams.
\74\ See, e.g., EPRI, Florida Power Corp, Duquesne, Entergy,
SoCal Cities, Merrill Energy, TAPS, IPCF, Powerex.
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FMPA states that grid fragmentation harms reliability.75
NU and EPRI note that recent demand growth has meant new stresses on
grid reliability and there is less coordination of generation and
transmission planning. TXU Electric states that, as the shift from
regulation to competition accelerates, and restructuring efforts
proliferate, the regional transmission grid is being exposed to
stresses that cannot be alleviated without regional solutions.
---------------------------------------------------------------------------
\75\ FMPA at 24.
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WPPI describes a situation in 1997 in which the 345-kV transmission
facility between MAPP and MAIN was overloaded as a result of
transactions scheduled within MAPP, and Wisconsin operators became
aware of the problem only when the constrained 345-kV facility
automatically separated in response to the overload. WPPI explains
that, with the 345-kV facility shut down, other transmission facilities
in the region overloaded, causing the transmission system over a large
region to come perilously close to a blackout. WPPI adds that, because
transmission providers do not have information about their neighbors'
on-system transactions to serve native load, they are unable to predict
the impact of potential TLR events. WPPI says that, in the face of this
uncertainty, transmission providers have to make overly conservative,
but inaccurate assumptions which unnecessarily reduce the amount of
transmission capacity available to the market.
TAPS states that, when the owners of a constrained interface
between MAPP and MAIN tried to remove the line for service for
maintenance, they found that 500 MW of flow remained on the line even
after all scheduled transactions were terminated. TAPS explains that
there were so many transactions in the region at the time that
transmission operators could not determine the source of this 500 MW
loop flow and were unable to ask other parties to cut their schedules
to permit the necessary maintenance.76 TAPS asserts that
transmission owners have engaged in ``creative'' concepts such as CBM
to reduce ATC and argues that price spikes are exacerbated, if not
caused by the failure to have regional transmission information and
control in one place.77
---------------------------------------------------------------------------
\76\ TAPS, Appendix A, at 8
\77\ TAPS, Appendix A at 2-5.
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TDU Systems complaint that the current system balkanizes regions
into a series of submarkets, each with its own dominant incumbent
transmission owner/generator that collects its own transmission toll.
EPRI contends that the current off-line ATC calculations result in
inconsistencies of ATC values. Entergy argues that the accuracy of ATC
will continue to be a problem as long as contract path pricing is
used.78
---------------------------------------------------------------------------
\78\ Entergy at 8.
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Minnesota Power notes that reliability across the broader region
suffers simply because of different standards for ATC calculations
within and across NERC
[[Page 819]]
regions and, indeed, different terminology and operating practices.
Minnesota Power states that: the market currently suffers as
participants attempt to deal with multiple OASIS sites; existing
tagging and reservation practices that limit transactions due to the
complexity of arrangements; its transactions are subject to curtailment
pursuant to two different procedures, NERC TLR and MAPP LLR; and
congestion management alternatives to line loading relief have not
succeeded because they lack regional coordination. Minnesota Power
argues that energy price volatility will continue to increase unless
there is a viable process, supported by transmission rights and
secondary transfer markets, where a participant can secure transmission
daily, or as needed, to bring the least cost supply to its customers.
EPSA asserts that one of the major impediments to robust
competitive bulk power markets is the current balkanization of the
system with dozens of individual utilities, NERC Regional Councils, and
security coordinators, and state laws and regulations imposing a
patchwork of often inconsistent and incompatible rules for the use of
the interstate transmission system. EPSA argues that the operational
and economic inefficiencies detailed in the NOPR are not unique to
certain region as and may be most pronounced in those regions where
competition has yet to take hold.79
---------------------------------------------------------------------------
\79\ EPSA specifically points to the SERC as a region where
``state commissions and utilities may be arguing that they don't
`need' RTOs to promote competitive markets,'' at a time when
Southeastern markets trail the rest of the nation in proposed
merchant plant development and power trading, ``both hallmarks of
robust wholesale competition and workable open access policies.''
EPSA notes that SERC is the largest NERC region, both in load and
peak demand, yet SERC and FRCC together constitute only 5.2 percent
of the wholesale power trades nationwide.
---------------------------------------------------------------------------
SoCal Edison states that existing transmission systems were
designed to serve native load customers in a defined area, in the most
efficient manner possible, in conjunction with the generation that it
owned and operated, and were not designed to function as common
carriers. SoCal Edison concludes that that radical changes in
downstream generation markets are having, and will continue to have,
significant and largely adverse effects of transmission systems.
Consumers Energy echoes this concern, noting that it should be obvious
that the current transmission system was designed to deliver locally
generated power to local markets with interfaces used primarily for
reliability purposes. Consumers Energy states that the system is simply
not engineered to move large quantities of power from many distant
generation sources to millions of end users.
Williams concludes that problems with congestion management,
pancaked transmission rates, parallel path or loop flows, inaccurate
ATC postings, and transmission facilities management and expansion
planning continue to impede the development of robust, competitive
wholesale electric markets in the United States.
PECO states that current TLR procedures allow one entity to cause
the curtailment of numerous third party transactions on a regular basis
to preserve power delivery in its single control area, regardless of
the impact on other control areas. PECO argues that, while physical
operation of the grid is maintained under these TLR procedures,
reliable, inter-control area power delivery is not assured and market
participants are denied fair access to the grid.
Tampa Electric states that, within peninsular Florida, transmission
users must often go to several individual transmission providers and
OASIS nodes, sign multiple agreements with various providers and
attempt to piece together and navigate through various partial paths to
connect a power sale to a buyer. Tampa Electric concludes that access
to transmission services within this region is not as open as it could
be to facilitate an efficient, robust wholesale market.
AEP states that coordination that previously existed in a fully
integrated electric system of the construction of new generation and
transmission facilities has eroded due to the separation of these
functions. AEP states that congestion constraints could potentially
inhibit the development of additional generation capacity or provide a
disincentive to add generating capacity where needed. AEP also notes
that the priorities of state regulatory agencies sometimes favor the
needs of native load customers that can create conflicts among
competing interest at the regional level. AEP also states that
developers of new merchant generation plants have become less willing
to share their long-term planning goals with transmission owners due to
the business strategies that accompany a more competitive power market.
However, AEP argues that removal of pancaking is not consistent with
economic efficiency and may distort future transmission expansion
because the cost of transmission should be based on distance and
location.\80\
---------------------------------------------------------------------------
\80\ AEP at 1, and Attachment to AEP's comments (Statement of
Paul Moul). As discussed in the Transmission Ratemaking section
(Section G), elimination of pancaked rates (multiple access charges
assessed only because the transaction crosses a corporate boundary)
does not constitute a prohibition on distance sensitive rates.
---------------------------------------------------------------------------
Several commenters state that needed transmission expansion is not
taking place because of a lack of pricing incentives to build new
transmission.\81\ EPRI states that failure to satisfy grid expansion
needs is resulting in increasing frequency and duration of power
disturbances and outages costing $50 billion per year.
---------------------------------------------------------------------------
\81\ See, e.g., Transmission ISO Participants, H.Q. Energy
Services, Powerex.
---------------------------------------------------------------------------
WPPI points out that transmission planning must be undertaken on a
regional, not a state basis, noting that import capability from MAPP
into Wisconsin is sometimes constrained by facilities located outside
of Wisconsin, e.g., transformers and lines located in Illinois and
Minnesota. On the other hand, Allegheny asserts that the industry has
not failed to plan and coordinate on a regional basis and cites
examples of study groups and planning committees, such as VEM
(Virginia-ECAR-MAAC) and GAPP (General Agreement on Parallel Paths).
Most commenters assert that pancaked transmission access charges
prevent efficient access to regional markets and distort the generation
market.\82\ A few commenters, however, question the benefits associated
with eliminating rate pancaking. Southern Company observes that the
severity of pancaking effects may vary from region to region.\83\
---------------------------------------------------------------------------
\82\ See, e.g., FMPA, IMEA, NECPUC, Ohio Commission, Texas
Commission, American Forest, Arkansas Cities, East Texas
Cooperatives, Oglethorpe, PNGC, Powerex, Williams, WPSC.
\83\ For illustration, Southern Company points out that a
customer in its service area can transmit power 500 miles away for
$3/MWh whereas a customer wanting to transmit power from Boston to
Washington, DC (also a distance of 500 miles) will have to go
through the three PJM, New England and NY ISOs and pay a total of
approximately $14/MWh.
---------------------------------------------------------------------------
Continuing Opportunities for Undue Discrimination. Comments dealing
with continuing opportunities for undue discrimination fall generally
into two camps. On the one side, transmission customers and some
transmission providers agree with the NOPR's premise that opportunities
for discrimination exist, that perceptions of discrimination are also a
serious impediment to competitive bulk power markets, and that
functional unbundling does not reflect the optimal long-term regulatory
solution.\84\ On the other side,
[[Page 820]]
a number of transmission providers disagree with these premises.\85\
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\84\ E.g., American Forest, Los Angeles, TAPS, UAMPS, Steel
Dynamics, Turlock, Cinergy, Statoil, WPPI, NJBUS, MidAmerican, LG&E,
Clarksdale, Michigan Commission, New Smyrna Beach, Industrial
Consumers, IMPA, First Rochdale, East Texas Cooperatives, FMPA, TDU
Systems, Canada DNR, Allegheny, IMEA, Sonat, Public Citizen, EPSA,
CCEM/ELCON, UtiliCorp and FTC. [85]:United Illuminating, Southern
Company, MidAmerican, Duke, PSE&G, FP&L, Entergy, FirstEnergy,
Alliance Companies, Lenard and Florida Power Corp.
\85\ United Illuminating, Southern Company, MidAmerican, Duke,
PSE7G, FP&L, Entergy, First Energy, Alliance Companies, Lenard and
Florida Power Corp.
---------------------------------------------------------------------------
Comments Asserting That Discrimination Still Exists. AMP-Ohio
points to an event last summer when it was unable to transmit power
from a generator on AEP's system to a load on the FirstEnergy system
and was forced to purchase power from FirstEnergy at $4000/MWh. AMP-
Ohio contends that AEP and FirstEnergy were simultaneously reporting
zero ATC during the hour, i.e., an event that cannot be rationalized by
AMP-Ohio (i.e., an interface that is fully loaded in both directions at
the same time would, in AMP-Ohio's view, cancel out).
UAMPS argues that three transmission owners that jointly own
segments of a single transmission line have avoided releasing the
capacity of this line under their open access tariffs through a series
of contractual arrangements that distributes transmission rights
directly to each of their merchant functions. As a result, only the
transmission owners' merchant functions have the ability the schedule
transmission service over the line. UAMPS contends that this example,
and others, confirm the Commission's perception that the remedies
mandated in Order No. 888 have not eliminated discrimination. UAMPS
states that it is intuitively obvious that when the transmission
function and merchant function ultimately serve the same master,
neither can be truly independent.
Hogan contends that, without an efficient regional spot market and
its ease of access, the problems of discrimination will persist. FTC
concludes that several years of industry experience confirm the concern
that discrimination remains in the provision of transmission services
by utilities that continue to own both generation and transmission. FTC
concludes that reliance on behavioral rules have proved to be less than
ideal.
Cinergy contends that reliance on CBM by some transmission
providers this summer provided their native load an unfair operational
edge over network service in the import of power through interconnects
that were the subject of TLR orders. Cinergy argues that the more
severe impact on market efficiency is caused by the lack of information
underlying the transmission provider's implementation of TLRs, and
raises significant opportunities for transmission providers to use
alleged reliability reasons to hide conduct actually motivated to
protect their own or their affiliate's own power market. Cinergy
concludes that market participants will never know the real answer
because it may be impossible to prove abuse of the TLR procedures with
access to information on the nature and cause of constraints and the
lack of consistency in implementing TLRs across the regions. Cinergy
adds that, even where there may be sufficient evidence to prove
discrimination, potential complainants may fear retribution by the
transmission provider, and may also be hesitant to file complaints
because of the litigation costs of the complaint process and the lack
of remedy for lost short-term market opportunities.
Enron/APX/Coral Power state that the following types of relatively
overt, although difficult to detect, discrimination occur: (1) Offers
of attractive transmission service to a transmission owner's affiliate
or merchant function that are not similarly offered to others; (2)
advance notification to the affiliate or merchant function of the
availability of transmission service or the availability of a new
service; and (3) changes in procedures, such as scheduling deadlines,
for obtaining transmission service in ways that benefit the affiliate
or merchant function. Enron/APX/Coral Power (as well as CCEM/ELCON,
UtiliCorp and EPSA) also argue that a ``principal form of
discrimination grows out of the exemption from the pro forma OATT and
OASIS that is enjoyed by transmission bundled with service to captive
`native-load' customers.'' Enron/APX/Coral Power believes that, if the
Commission were to conduct an investigation of compliance with the
Commission's open access requirements and the uses of their own
transmission system during periods of extreme peak loads and volatile
prices during the past summer, the Commission would uncover evidence of
widespread abuses. According to Enron/APX/Coral Power, these abuses
would include instances where the transmission provider imported power
on a network basis, as if it were intended to service captive, native
load customers, only to turn around and sell that power competitively,
off-system; where scheduling requirements or deadlines were changed
without adequate notice to third parties; and where ATC amounts that
either were not posted or were posted in an untimely manner.
NASUCA concludes that, despite Order No. 888, there is still reason
for concern that continued discrimination in the provision of
transmission services by vertically integrated utilities may be
impeding competitive electric markets.
EPSA states that the prospect of real competition continues to be
threatened by (1) arbitrary and discriminatory curtailment and line
loading relief policies, and (2) needlessly complex and overly
restrictive transmission planning, expansion and interconnection
practices.
TAPS argues that the anticompetitive effects of allowing a subset
of competitors to control essential facilities have been long
recognized.\86\ TAPS provides specific examples that it claims show
that discrimination exists: (1) The price spikes in June 1998 and
Summer of 1999 where the asserted ATC was inadequate to allow external
generation resources to meet the needs of the market; (2) failure of a
transmission owner to provide necessary upgrades; and (3) a
transmission owner taking negotiating positions contrary to a clear
provision of the Open Access Transmission Tariff (OATT). In its reply
comments, TAPS describes a recent situation where AEP, acting in its
role as the NERC Security Coordinator, informed IMPA that it had
implemented a TLR seven minutes earlier, too late for IMPA to replace
the curtailed schedule with another transaction at market prices, which
were $35/MWh. TAPS contends that IMPA had no effective choice but to
make up the shortfall by purchasing emergency energy from AEP at $100/
MWh. In following hours that day, IMPA elected to purchase power from
AEP at $35/MWh rather than continue its other purchase options (at $17/
MWh) and risk further curtailments. TAPS observes that AEP
substantially profited from delayed communication of the TLR, by
selling power to IMPA at nearly three times the then-market price. TAPS
states that, even assuming AEP was acting properly on this occasion,
this example illustrates the inherent conflict of interest in combining
security coordinator functions with that of market participant. TAPS
argues that this diminishes the faith in the market place and breeds
mistrust. Based on the examples it provides and on the evidence
reviewed in the NOPR, TAPS
[[Page 821]]
recommends that the Final Rule make formal findings that undue
discrimination remains widespread throughout the industry.
---------------------------------------------------------------------------
\86\ TAPS cites to a 1912 Supreme Court case involving the
control of a railway terminal by several railroads which their
competitors were required to use. See United States v. Terminal RR
Ass'n, 224 U.S. 383, 397 (1912).
---------------------------------------------------------------------------
Steel Dynamics states that the Commission needs to build confidence
that transmission customers will not be victimized when markets get
tight and claims the Commission's record to date has been uneven. Steel
Dynamics cites a case in which the Commission determined that Niagara
Mohawk Power Corporation had committed several violations of the OASIS
posting requirements and standards of conduct in order to favor its
marketing affiliate over a third-party user.
Clarksdale states that it has experienced problems with the posting
of ATC by Entergy on the OASIS. Clarksdale states that on July 21,
1999, it attempted to purchase from Cajun Electric Cooperative 20 MW of
power for whatever length of time that Cajun would have had it
available up to one week. Entergy denied the transaction on the basis
that the ATC between Entergy and Cajun was zero. Clarksdale complained
and the next day the ATC for this interface was shown to be 1,700
megawatts; however, by that time Cajun had sold the power to another
entity and it was no longer available for Clarksdale. Clarksdale
submits that the incident, along with others Clarksdale reported,
compels the conclusion that the function of security coordination
should be entirely separate from the transmission owner and from the
generation owner and that participation in an absolutely independent
RTO should be mandated by the Commission in the final rule.
FMPA states that, whether because of discriminatory motivations or
simply because of balkanized perspectives (or both), there have been
numerous instances of Florida's dominant transmission owners falling
short on the transmission planning performance. According to FMPA,
Florida's dominant transmission owners have failed to promptly address
regionally significant constraints (until addressing them became
advantageous for their own merchant function), and have continued to
impose discriminatory transmission-related construction requirements.
FMPA claims that relying on functional separation rules to curb the
self interest of market-interested transmitters when huge sums of money
are at stake is like ``relying on words to hold back the tide.'' \87\
---------------------------------------------------------------------------
\87\ FMPA at 23-24.
---------------------------------------------------------------------------
WPPI states that it routinely experiences and observes subtle and
difficult to detect problems in the marketplace. WPPI states that,
because they are subtle and difficult to detect, they are not
susceptible to any prompt and effective regulatory remedy. WPPI adds
that prosecution of complaints is expensive and time consuming and
customers do not have the ability to prosecute each such incident.
WPPI contends that transmission owners are able to dispatch their
resources in order to manipulate their exposure to TLRs, while
customers cannot. WPPI characterizes this tactic as a ``shell game''
because it is purportedly accomplished by designating fictional sources
and sinks and treating one transaction as two separate transactions.
WPPI contends that these actions leave other transmission users to bear
the costs of curtailments and denials of service. WPPI argues that
these manipulations of TLRs are ``rampant.''
WPPI states that during summer peak periods, when it claims power
prices exceeded $5,000/MWh in the Eastern Interconnection, at least one
Midwestern transmission-owning utility appears to have been able to
abuse its control-area operator authority to gain a market advantage.
According to WPPI, as a control-area operator, the transmission owner
at issue declared that power shortages had created an emergency
situation which allowed it to relax the transmission limitations that
it had imposed on other market participants, enabling the transmission
owner to acquire less expensive power from the MAPP region. WPPI claims
that the transmission owner thereby gained a market advantage, at a
time when market advantages were worth huge sums. WPPI claims that most
if not all other control-area operators in the region played by the
rules and did not abuse the system to access less expensive power for
which ATC ostensibly was not available. WPPI asserts that utilities
that are not control-area operators had no choice other than to buy
high cost, locally generated power, and that they ``lack not only the
right, but also the might'' \88\ to declare an emergency or to
recalculate ATC to help themselves. WPPI and Cinergy maintain that this
recent event provides a clear example of the continuing potential,
under present industry structure, for vertically integrated utilities
to abuse their transmission control to gain market advantages and for
that reason, among others, the Commission should mandate that entities
under its jurisdiction participate in RTOs.
---------------------------------------------------------------------------
\88\ WPPI at 31.
---------------------------------------------------------------------------
TDU Systems provide a number of examples which raise their concerns
about undue discrimination, including: (1) Failure of an incumbent IOU
to reduce its own out-of-region power sales during a period when the
system was experiencing overloads and the transactions of other
transmission users were jeopardized; (2) overly aggressive and
selective enforcement of tariff requirements on transmission customers
than are imposed on the transmission providers' own merchant function;
(3) selectively targeting generating units that are jointly owned by
competitors when redispatch of the transmission system is required to
relieve line loading; (4) self-serving ATC calculations in
circumstances when transmission customers have no way of knowing
whether access is being denied legitimately or through manipulation for
competitive gain; and (5) onerous and lengthy negotiations to obtain
system studies. TDU Systems contend that there is a fire under the
smoke of allegations of discrimination, and those complaining of the
anecdotal nature of its information haven't provided any evidence to
show that discrimination is not occurring.
TXU Electric states that, if a truly successful, restructured
competitive electric industry is to achieve its full potential, it is
incumbent of all concerned, transmission providers, users and
regulators alike, to move beyond the impediments of the past, including
hidden motivations on the part of some, unfounded fears of hidden
motivations on the part of others, and a general environment of
distrust. TXU Electric adds that, transmission users and regulators
must have confidence that the transmission grid is truly an open, non-
discriminatory and robust commercial highway and transmission providers
must inspire that confidence. TXU Electric concludes that the
Commission's voluntary collaborative approach is an important step in
the right direction.
LG&E states that, under the current system, transmission owners'
operational decisions, even if well intentioned, are surrounded by a
cloud of suspicion that, acting in the name of reliability, the
transmission owner has enhanced its position in the generation market.
LG&E agrees that this perception that the transmission system is not
being operated in an even handed manner undermines confidence in the
non-discriminatory open access implemented under Order No. 888.
Virginia Commission agrees that allegations of discrimination
represent only known problems, and there may be many unknown ones
remaining given that it is difficult for transmission users
[[Page 822]]
to identify and demonstrate instances of discrimination.
Canada DNR states that discriminatory behavior by transmission
operators, identified in the NOPR as the second significant driver for
establishment of RTOs, is not perceived as a key impediment to the
evolution of efficient bulk power markets in Canada.
Dynegy argues that transmission provides have the incentive and
ability to discriminate in today's markets due to the combination of
control over transmission with participation in power markets and the
existing regulatory structure that exempts transmission providers from
the open access rules of Order Nos. 888 and 889 for its bundled, native
load customers. Dynegy argues that the ``native load'' exemption can be
and is often manipulated to favor the transmission providers' own or
affiliated merchant functions.
PECO notes that, in their capacity as vertically integrated
utilities, transmission providers have access to critical market
sensitive information with respect to each transaction (e.g., source,
sink), at a time when they are in direct competition in the same
markets and with the same transmission customers whose market
information they have. PECO argues that, in spite of the existence of
functional unbundling and codes of conduct, the serious potential for
conflicts of interest and abuse inherent in the current structure
cannot be ignored.
Comments Asserting That Discrimination Is Not a Problem. A number
of commenters, mostly transmission owners, do not believe that
significant discrimination problems remain with respect to wholesale
transmission access pursuant to Order No. 888. As a general matter,
those transmission owners whose actions are cited in other pleadings as
examples of undue discrimination disagree with those characterizations
of the cited events and declare that they provide non-discriminatory
transmission service under their OATT. These transmission owners
contend that the disputes cited in the pleadings are not the result of
discriminatory practices; rather, they are the result of the priority
accorded native load customers under the OATT, and good faith errors on
the part of the transmission provider trying to administer complex
rules and tariff changes that have necessitated fundamental changes to
the structure of companies and the way they do business.
EEI contends that many of the difficulties transmission customers
encounter in obtaining price, availability and transmission service
result in a technology gap that can be, and often is, interpreted as
discriminatory behavior. EEI also contends that many allegations of
discrimination are ``rooted at their heart'' on the scarcity of
transmission resources and not overt attempts to discriminate against
specific customers.
PSE&G argues that supposition and anecdotal evidence of alleged
abuses by transmission owners does not justify a radical change in the
existing regulatory scheme. PSE&G contends that, while the incentive to
maximize shareholder value is certainly a powerful force in the
marketplace, the requirements of law, such as Order Nos. 888 and 889,
will prevail.
Duke argues that mere anecdotes of discrimination, involving
unnamed parties and without reference to specific facts, are not
evidence of anything, let alone discrimination, and cannot form the
basis of a reasoned decision. Duke also lists a number of formal
complaint proceedings where the Commission found the transmission
provider to have acted properly. Entergy argues that those alleging
discrimination, as competitors of transmission providers, have an
economic incentive to make their own allegations. Entergy adds that, if
perceptions of discrimination were impeding competitive markets, there
would not be 20,000 MW of generation investment proposed in its region.
United Illuminating complains that many of the allegations of undue
discrimination presuppose that all utilities are the same, i.e.,
vertically integrated transmission, distribution and generation
companies, and do not recognize that a number of utilities are
divesting their generation business.
Southern Company states that the goal of non-discriminatory
transmission service is already being satisfied in the Southeast.
Southern Company asserts that it has separated its transmission and
reliability functions from its wholesale merchant function up to the
level of ``very senior management.'' Southern Company submits that it
is unaware of any pending allegations of discrimination against it.
Southern Company adds that the Southeast is characterized by large
transmission systems such as Southern Company, Tennessee Valley
Authority, and Entergy and that these transmission systems are already
planned and operated on a regional basis. Southern Company also points
out that it alone covers a region as large as (if not larger than) many
ISOs currently in existence. Under these circumstances, Southern
Company believes that the Commission's open access initiatives have
worked in the Southeast and that additional steps are not required to
ensure non-discriminatory transmission service.
MidAmerican asserts that complaints received by the Commission
about alleged discrimination should not be the primary basis for
determining if the market is successful. According to MidAmerican, if
it is assumed that an adequate number of parties are competing
successfully, it could be concluded that the complaints may be
indications of ill-defined problems not yet resolved, isolated market
flaws, or indications of a successful market with somewhat inadequate
tools.
Duke believes that its transmission organization is meeting the
needs of its customers as evidenced by the very few and relatively
insignificant complaints Duke has received regarding the administration
of its OATT. Duke believes that Order No. 888 has been quite successful
and, although it agrees with the Commission that elimination of
balkanized transmission operations through the formation of larger,
regional operations is ultimately preferred, Duke does not believe
Order No. 888 should be abandoned hastily.
Duke argues that disputes are primarily the result of the
complexity of the priority scheme in the Commission's pro forma tariff,
the rules for which are still being developed; the inherent tension
between the Commission's comparability requirement and the requirements
of state-regulated native load customers; and the obligation to ensure
reliability of the transmission grid on a real time basis. Duke asserts
that the vast majority of transactions occurring as a result of Order
No. 888 do not produce transmission disputes and, to the extent that
isolated instances of discrimination have occurred, the Commission has
adequate authority to address the problem.
Duke also maintains that a major source of confusion involves the
rights of native load customers versus wholesale transmission users
under the pro forma tariff and that this issue remains subject to
disagreement and needs further clarification. Duke says its conclusion
is reinforced by its experience as a market participant in areas where
there are ISOs. Duke asserts that the establishment of ISOs in
California, NEPOOL and PJM has not resulted in the elimination of
disputes over tariff ambiguities. Duke questions the assertion that
disagreements between customers and individual transmission owners are
indicative of significant ongoing discrimination.
Florida Power Corp. and FP&L's comments are similar to Duke's.
Florida
[[Page 823]]
Power Corp. and FP&L state that they have not received any formal
complaints alleging undue discrimination with regard to their OATT.
Florida Power Corp. and FP&L agree that the increasing number of
transactions has led to a concomitant increase in transmission
disputes; however, they characterize the disputes as legitimate
disagreements over policy or meaning of the pro forma tariff as opposed
to true allegations of discriminatory conduct. Like Duke, Florida Power
Corp. and FP&L believe that many of the allegations of potentially
discriminatory conduct are attributable to two primary areas: (1)
Rights of native load customers versus wholesale wheeling customers;
and (2) disputes arising from the complex priority scheme in the pro
forma tariff. According to FP&L, disputes will still occur until the
issues relating to priority rights are resolved. FP&L argues that the
Commission cannot expect that any remedy will eliminate discrimination
claims in light of the Eighth Circuit Court's decision in Northern
States Power Co. v. FERC.\89\
---------------------------------------------------------------------------
\89\ See Northern States Power Co. (Minnesota) and Northern
States Power Co. (Wisconsin), 83 FERC para. 61,098, clarified, 83
FERC para. 61,338, reh'g, clarification and stay denied, 84 FERC
para. 61,128 (1998), remanded, Northern States Power Co., et al. v.
FERC, 176 F.3d 1090 (8th Cir. 1999), reh'g denied (unpublished order
dated Sept. 1, 1999), order on remand, 89 FERC para. 61,178 (1999)
(request to withdraw curtailment procedures pending) (Northern
States).
---------------------------------------------------------------------------
FPL and Florida Power Corp. argue that unsubstantiated allegations
do not constitute evidence of discrimination and should be
characterized as legitimate disputes over tariff interpretation, while
EEI describes some of the allegations as ``one-sided characterizations
of cases now being litigated.'' FPL also contends that some intervenors
adopt the stance that, whenever the transmission provider and customer
are in disagreement, it evidences discrimination. Florida Power Corp.
states that, if undue discrimination exists outside of Florida, it is a
function of the newness of the Commission's open access rules, and it
is far too soon to declare functional unbundling ineffective. Florida
Power Corp. agrees with the Commission's statement that it may be
impossible to distinguish an inaccurate ATC presented in good faith
from an inaccurate ATC posted for the purpose of favoring the
transmission provider's marketing interests, but concludes that, once
technical issues have been resolved about ATC calculations, the volume
of disputes will be greatly diminished. Florida Power Corp. adds that
there is no evidence of a pattern of industry-wide undue
discrimination, and concludes that mere perceptions cannot provide a
justification for generic remedial action.
Entergy, FirstEnergy, Alliance Companies and Lenard argue that
there is no credible or substantial evidence in the record that
transmission owners have been engaging in discriminatory practices in
providing transmission services under Order Nos. 888 and 889 and,
therefore, the Commission should not, and lawfully cannot, rely on mere
allegations of discriminatory conduct. FirstEnergy states that it has
doubled its control area reservation and back office staff to handle
the five percent of its transmission business that is wholesale related
and still is having difficulty keeping pace with OASIS and tagging
administrative processes. FirstEnergy asserts that due to relatively
new processes associated with open access transmission, there are often
good faith disputes over the proper interpretation of the Commission's
requirements and these disputes should not be mischaracterized as
continued discrimination.
Commission Conclusion. Engineering and Economic Inefficiencies. In
this Final Rule, we affirm our preliminary determination that the
engineering and economic inefficiencies identified in the NOPR
90 are present in the operation, planning and expansion of
regional transmission grids, and that they may affect electric system
reliability and impede the growth of fully competitive bulk power
markets. The sources of these inefficiencies involve: difficulty
determining ATC; parallel path flows; the limited scope of available
information and the use of non-market approaches to managing
transmission congestion; planning and investing in new transmission
facilities; pancaking of transmission access charges; the absence of
clear transmission rights; the absence of secondary markets in
transmission service; and the possible disincentives created by the
level and structure of transmission rates. Virtually all commenters
agree that at least some of these inefficiencies exist. There is
substantial agreement among commenters that most of the engineering and
economic obstacles identified by the NOPR arise from the current
industry structure and can be rectified through development of regional
transmission entities.
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\90\ FERC Stats. & Regs. para. 32,541 at 33,697.
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As noted by Allegheny, the industry historically has done an
excellent job of regional coordination in implementing voluntary
standards to maintain the security of the transmission system through
various study groups and planning committees. However, virtually all
commenters agree that new competitive pressures are interfering with
the use of traditional methods of coordinated regional transmission
planning. As a result, new transmission additions that will benefit
reliable grid operations are being delayed. Some commenters state that
the increasing frequency and duration of power outages have cost the
economy billions of dollars, and they predict that unless this problem
is addressed now the reliability of power supply will worsen. The
traditional use of regional coordination through study groups and
planning committees is no longer effective because these entities are
usually not vested with the broad decisionmaking authority needed to
address larger issues that affect an entire region, including managing
congestion, planning and investing in new transmission facilities,
pancaking of transmission access charges, the absence of secondary
markets in transmission service, and the possible disincentives created
by the level and structure of transmission rates.
We recognize, as some commenters point out, that the degree to
which these inefficiencies act as obstacles to electric competition and
reliability varies from system to system. However, we believe it is
clear that such inefficiencies exist and are sufficiently widespread
that they must be addressed to prevent them from interfering with
reliability and competitive electricity markets.
Continuing Opportunities for Undue Discrimination. As noted, many
transmission customers and some transmission providers argue that there
are continuing opportunities for undue discrimination under the
existing functional unbundling approach. A number of the commenters
provide examples of events that, in their view, indicate that
transmission owners are engaging in undue discrimination. These
commenters also generally believe that even the perception of undue
discrimination is a significant impediment to the evolution of
competitive electricity markets. A number of transmission providers
challenge the relevancy of these examples, characterizing them as
unsubstantiated or anecdotal allegations that do not rise to the level
of evidence of undue discrimination necessary to support generic
action. These transmission providers further contend that many disputes
simply reflect good faith efforts of transmission providers to
interpret the Commission's pro forma tariff and standards of conduct.
These
[[Page 824]]
commenters also generally share the view that the Commission should not
base its decisions in this rule on mere perceptions that may be
prevalent in the industry.
For the most part, the challenges mounted by these commenters are
focused against a determination by the Commission that it should
mandate participation in RTOs in this Rule. As noted in Section C.1 of
this Rule, we have also determined that a measured and appropriate
response to the evidence presented and concerns raised is to adopt a
voluntary approach to the formation of RTOs. However, as discussed
below, we do conclude that opportunities for undue discrimination
continue to exist that may not be remedied adequately by functional
unbundling. We further conclude that perceptions of undue
discrimination can also impede the development of efficient and
competitive electric markets. These concerns, in addition to the
economic and engineering impediments affecting reliability, operational
efficiency and competition, provide the basis for issuing this Final
Rule.
At the outset, it is important to note that the conclusion that
there are continuing opportunities for undue discrimination should not
be construed as a finding that particular utilities, or individuals
within those utilities, are acting in bad faith or deliberately
violating our open access requirements or standards of conduct.
However, we cannot ignore the fact that the vertically integrated
structure reflected in the industry today was created to support the
business objectives of a franchised monopoly service provider that
owned and operated generation, transmission and distribution facilities
primarily to serve requirements customers at wholesale and retail in a
non-competitive environment. Clearly, there are aspects of this
vertically integrated structure that are difficult to transition into a
competitive market. As we noted in the NOPR and Order No. 888,
vertically integrated utilities have the incentive and the opportunity
to favor their generation interests over those of their competitors. If
a transmission provider's marketing interests have favorable access to
transmission system information or receive more favorable treatment of
their transmission requests, this obviously creates a disadvantage for
market competitors.
While we have attempted to rely on functional unbundling to address
our concerns about undue discrimination, there are indications that
this is difficult for transmission providers to implement and difficult
for the market and the Commission to monitor and police. In cases in
which the Commission has issued formal orders, we have found serious
concerns with functional separation and improper information sharing
with respect to at least four public utilities.91 In
addition, our enforcement staff is receiving an increasing number of
telephone calls about standards of conduct issues, ranging from simple
questions about what is permissible conduct to more serious complaints
alleging actual violations of the standards of conduct. In a number of
cases, our staff has verified non-compliance with the standards of
conduct.92 The petitioners for rulemaking in Docket No.
RM98-5-000 allege that there are common instances of ``unauthorized
exchanges of competitively valuable information on reservations and
schedules between transmission system operators and their own or
affiliated merchant operation employees.'' 93 They also cite
OASIS data showing an instance where a transmission provider quickly
confirmed requests for firm transmission service by an affiliate, while
service requests from independent marketers took much longer to
approve. We believe that some of the identified standards of conduct
violations are transitional issues resulting from a new way of doing
business, and we acknowledge that many utilities are making good-faith
efforts to properly implement standards of conduct. However, we also
believe that there is great potential for standards of conduct
violations that will never even be reported or detected. Moreover, as
we stated in the NOPR,94 we are increasingly concerned about
the extensive regulatory oversight and administrative burdens that have
resulted from policing compliance with standards of conduct. The use of
standards of conduct is not the best way to correct vertical
integration problems. Their use may be unnecessary in a better
structured market where operational control and responsibility for the
transmission system is structurally separated from the merchant
generation function of owners of transmission.
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\91\ See Wisconsin Public Power Inc. SYSTEM v. Wisconsin Public
Service Corporation, 83 FERC para. 61,198 at 61,855, 61,860, order
on reh'g, 84 FERC para. 61,120 (1998) (WPSC's actions raised
``serious concerns'' as to functional separation; WP&L's actions
demonstrated that it provided unduly preferential treatment to its
merchant function); Washington Water Power Co., 83 FERC para. 61,097
at 61,463, further order, 83 FERC para. 61,282 (1998) (utility found
to have violated standards in connection with its marketing
affiliate); Utah Associated Municipal Power Systems v. PacifiCorp,
87 FERC para. 61,044 (1999) (finding that PacifiCorp had failed to
maintain functional separation between merchant and transmission
functions).
\92\ See, e.g., Communications of Market Information Between
Affiliates, Docket No. IN99-2-000, 87 FERC para. 61,012 (1999)
(Commission issued declaratory order based on hotline complaint
clarifying that it is an undue preference in violation of section
205 of the FPA for a public utility to tell an affiliate to look for
a marketing offer prior to posting the offer publicly).
\93\ Petition at 15.
\94\ FERC Stats. & Regs. para. 32,541 at 33,711-12.
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We also cannot dismiss the significance of reports of undue
discrimination simply because they are not reduced to formal
complaints. As many intervenors have asserted, the cost and time
required to pursue legal channels to prove discrimination will often
provide an inadequate remedy because, among other things, the
competition may have already been lost.95 The fact that
evidence of discrimination in the fast-paced marketplace is not
systematic or complete is not unexpected. The fact remains that claims
of undue discrimination have not diminished, and there is no evidence
that discrimination is becoming a non-issue.
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\95\ For example, EPSA has told us: ``Furthermore, even if the
exercise of such discrimination could be adequately documented and
packaged in the form of a complaint under section 206 of the Federal
Power Act under a more streamlined complaint process contemplated by
the Commission, it would still be extremely costly and inefficient
to deal with such complaints on a case-by-case basis. More than
likely, the potential power transactions for which transmission
principally was sought would disappear by the time a Commission
ruling was obtained. Motion to Intervene and Comments of Electric
Power Supply Association in Support of Petition for Rulemaking,
Docket No. RM98-5-000 (filed Sept. 21, 1998), at 3.''
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Finally, we continue to believe that perceptions of discrimination
are significant impediments to competitive markets. Efficient and
competitive markets will develop only if market participants have
confidence that the system is administered fairly.96 Lack of
market confidence resulting from the perception of discrimination is
not mere rhetoric. It has real-world consequences for market
participants and consumers. As stated by NERC, there is a reluctance on
the part of market participants to share operational real-time and
planning data with transmission providers because of the suspicion that
they could be providing an advantage to their affiliated marketing
groups,97 and this can, in turn, impair the reliability
[[Page 825]]
of the nation's electric systems. Lack of market confidence may deter
generation expansion, leading to higher consumer prices. Fears of
discriminatory curtailment may deter access to existing generation or
deter entry by new sources of generation that would otherwise mitigate
price spikes of the type that have been experienced during peak periods
in the last two summer peak periods. Mistrust of ATC calculations will
cause transactions involving regional markets to be viewed as more
risky and will unnecessarily constrain the market area, thereby
reducing competition and raising prices for consumers. The perception
that a transmission provider's power sales are more reliable may
provide subtle competitive advantages in wholesale markets, e.g.,
purchasers may favor sales by the transmission provider or its
affiliate, expecting greater transmission service reliability. We
believe that the potential for such problems increases in a competitive
environment unless the market can be made structurally efficient and
transparent with respect to information, and equitable in its treatment
of competing participants.
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\96\ For example, a representative of Blue Ridge told us:
``There simply is no shaking the notion that integrated generation
and transmission-owning utilities have strategic and competitive
interests to consider when addressing transmission constraints.
Functional unbundling and enforcement of [standard of] conduct
standards require herculean policing efforts, and they are not
practical.'' Regional ISO Conference (Richmond), Transcript at 20.
\97\ NERC Reliability Assessment 1998-2007, at 39.
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In summary, we affirm our conclusion in the NOPR that economic and
engineering inefficiencies and the continuing opportunity for undue
discrimination are impeding competitive markets. As noted below, we
conclude that RTOs will remedy these impediments and that it is
essential for the Commission to issue this Final Rule.
B. Benefits That RTOs Can Offer to Address Remaining Barriers and
Impediments
In the NOPR the Commission explained how the use of independent
RTOs could help eliminate the opportunity for unduly discriminatory
practices by transmission providers, restore the trust among
competitors that all are playing by the same rules, and reduce the need
for overly intrusive regulatory oversight.98 The Commission
further identified a number of significant benefits of establishing
RTOs: (1) RTOs would improve efficiencies in the management of the
transmission grid; 99 (2) RTOs would improve grid
reliability; (3) RTOs would remove opportunities for discriminatory
transmission practices; (4) RTOs would result in improved market
performance; and (5) RTOs would facilitate lighter-handed governmental
regulation.100 The Commission requested comments on the
benefits of RTOs and the magnitude of these benefits.
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\98\ FERC Stats. & Regs. para. 32,541 at 33,714.
\99\ These efficiencies include, among other things, regional
transmission pricing, improved congestion management of the grid,
more accurate ATC calculations, more effective management of
parallel path flows, reduced transaction costs, and facilitation of
state retail access programs.
\100\ FERC Stats. & Regs. para. 32,541 at 33,716-20.
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Comments. Description of Benefits. Many commenters support the
establishment of RTOs throughout the United States to effectively
remove the remaining impediments to competition in the power
markets.101 Illinois Commission states that the pursuit of
competition as the driving force for markets in the electric industry
requires developing new institutions and accepting new practices, and
RTOs are the logical next organizational step in the electric industry
restructuring process. Entergy agrees that significant benefits can be
achieved by the creation of properly-structured, large RTOs and that
the Commission has accurately described many of those benefits in the
NOPR. Ohio Commission believes that a properly structured RTO will
facilitate efficient regional generation markets, while preventing
incumbent holding companies from improperly exercising their market
power.
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\101\ See, e.g., PJM, DOE, Illinois Commission.
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PG&E acknowledges that the benefits of Order No. 888 have been
largely reaped, and still significant impediments to an efficient
competitive marketplace remain in place where RTOs are not yet
operational. Moreover, industry restructuring has led to new and
complex operational issues that were unanticipated at the time Order
No. 888 was issued. RTOs represent the most promising and efficient
regulatory method for the Commission to address these issues. Without
RTOs, it would be incumbent on the Commission to take very detailed and
intrusive actions because the transmission grid cannot operate reliably
and efficiently unless the competitive and operational issues are
resolved.
Ontario Power agrees that the electric power industry should now
move beyond the functional unbundling approach prescribed in Order Nos.
888 and 889. TDU Systems asserts that wholesale electric markets will
benefit immensely if RTOs can simply provide transmission service on an
unbiased basis, treating all customers fairly, and take the lead role
in regional transmission planning.
On the other hand, a number of vertically integrated utilities do
not support government action to form RTOs. For example, Duke
recognizes that there may be transmission functions performed today
within individual company control centers, within existing control
areas, or within existing reliability councils that may be better and/
or more efficiently performed by a regional transmission organization.
However, Duke also believes that the industry is voluntarily working to
identify such functions or processes and is effecting meaningful
changes and improvements in a timely manner. Accordingly, Duke believes
that this progress should not be pre-empted by regulatory mandates, and
that there are insufficient data, at this time, to draw meaningful
conclusions regarding the magnitude of benefits that will result from
RTO formation.
Similarly, MidAmerican argues that benefits of RTOs can be realized
without RTOs. MidAmerican claims that existing regional organizations,
such as MAPP, are capable of meeting the Commission's concerns about
eliminating existing impediments to an efficient competitive
marketplace. FP&L states that the NOPR does not attempt to quantify any
of the claimed benefits of RTOs. FP&L is unaware of any data that
specifically and objectively show that ISOs have saved ratepayers money
in those areas where ISOs have been established. Nor is it aware of any
specific quantification of any other actual or projected benefits of
ISOs.
Some commenters contend that the costs of establishing RTOs must
not exceed the benefits. Cal DWR argues that significant start-up costs
and costs associated with duplicative efforts have been higher than the
NOPR appears to recognize. These costs entail not only costs of the new
organization itself, but also market participants' costs in travel,
staffing, and other expenses and investments necessary to participate
or operate in new structures. Other commenters suggest that each
proposal contained in the NOPR should be carefully evaluated for its
cost consequences.\102\
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\102\ See, e.g., Cal DWR, California Board, Southern Company,
Aluminum Companies.
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Seattle notes that its region has the lowest cost electricity in
the Nation and an already thriving wholesale market with little price
volatility. Assuming that an RTO is projected to result in additional
transmission costs, Northwest consumers will be less willing to incur
these costs than consumers in regions where power costs are high and
wholesale prices are extremely volatile. Snohomish and Aluminum
Companies assert that one of fatal flaws of the IndeGO proposal \103\
was that its demonstrable benefits did
[[Page 826]]
not clearly outweigh the costs of its start-up and operation. Snohomish
requests that the Commission not impose an RTO with similar flaws upon
the Northwest. A number of commenters also urge the Commission to
reject any RTO filing for the Northwest or other regions that fails to
provide a strong demonstration that its benefits will substantially
outweigh its projected costs.\104\
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\103\ IndeGO is an independent grid operator proposal that has
been discussed for the Pacific Northwest and Rocky Mountain area.
\104\ See, e.g., Big Rivers, Chelan, California Board,
Industrial Customers, Arizona Commission, EEI, Idaho Commission,
Washington Commission.
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To ensure that RTOs are formed in a cost effective and efficient
manner, SRP proposes a phased approach to RTO development that would
allow RTOs to gradually take on new functions and responsibilities in
response to the needs to the market. In addition, the Commission should
require RTOs to establish criteria against which they will measure cost
effectiveness and efficient performance and to make adjustments where
criteria are not being met.
Canada DNR states that structural differences between the Canadian
and American electric power industries mean that there may be fewer
potential benefits from the formation of RTOs in Canada than those
identified by the Commission for the United States. Consequently, it
believes that Canadian jurisdiction should be able to assess the costs
and benefits of RTO proposals. In addition, it notes that some may find
that, although the benefits do warrant the associated costs, they may
address impediments to efficient electricity markets through other
means.
Comments on RTOs Improving Efficiencies in the Management of the
Transmission Grid.\105\ PJM agrees with the Commission that placing as
many grid management functions as possible under an RTO is the best
means of bringing the benefits of RTOs to the marketplace. A number of
commenters address specific RTO actions as examples of grid management
efficiencies, including use of regional transmission pricing, accurate
estimation of ATC, efficient planning for grid expansion, and
facilitating state retail access programs.
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\105\ As noted earlier, many of the principal benefits of RTOs
(e.g., congestion management, improved reliability, parallel path
flow resolution) are discussed in greater detail later as RTO
minimum characteristics and functions; however, some of the
commenters cited here mention these benefits as part of their
overall discussion of RTOs improving efficiencies in the management
of the transmission grid.
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FMPA claims that a just and reasonable RTO transmission rate, with
a unified regional loss factor or factors, would provide a regionally
rational approach, which is not provided by the existing fragmented
regime. Pancaking has long prevented FMPA and its members located on
the Florida Power Corp. transmission system from economically
delivering the output from their portions of the St. Lucie nuclear
plant to their loads. Similarly, WPSC notes that without an RTO that
encompasses the Midwest region, unjustified pancaked transmission rates
may inhibit the efficient flow of power across the region.
PacifiCorp supports the Commission goal of eliminating transmission
pancaking, to the extent practical. PacifiCorp maintains that such a
goal could be furthered by the creation of the most geographically
expansive RTOs that are technically workable. The goal also could be
met, however, if multiple RTOs within the western United States agree
to reciprocally eliminate charges in connection with the ``export'' or
``import'' of power from one RTO to another. In the western United
States, such ``reciprocity'' agreements may be preferable to the
creation of a single RTO that otherwise is too large to be efficient,
safe and reliable, or of a single RTO for which operating principles
must be unreasonably compromised to attract all necessary transmission
owners.
Allegheny asserts that even with an RTO, grid inefficiencies such
as rate pancaking and congestion will continue unless an appropriate
pricing mechanism is adopted. The various RTO structures, regardless of
size and number, would still need to work cooperatively to ensure that
the various interfaces are sufficient to maintain the reliable
operation of the system. The formation of an RTO, by itself, does not
bring a particular benefit.
Rochdale asserts that a properly structured independent RTO, with a
broad geographic scope, could eliminate incorrect calculations of ATC
and TTC. Furthermore, the motive for discrimination and possible
manipulation that exists where transmission owners with affiliated
power marketers are responsible for reporting ATC and TTC would become
moot. FMPA contends that, without an RTO, most market participants
would remain unable to replicate or trust the transmission owners' ATC
calculations. FMPA indicates that customers and regulators cannot
properly review transmission providers' ATC accounting without access
to their TTC starting points; however, existing Florida OASIS sites do
not provide TTC information. In addition, ATC calculations require
extensive application of engineering judgment. FMPA questions whether
market-interested transmission providers can be trusted to exercise
such judgment disinterestedly. Consequently, FMPA believes that an RTO
could provide unbiased ATC information.
Many commenters believe that RTOs would provide more efficient
planning for transmission and generation investments.\106\ For example,
Entergy agrees that the creation of RTOs can lead to more efficient and
effective planning and expansion of the transmission system. However,
to ensure efficient investment in the transmission system, Entergy
proposes that the Commission encourage innovative pricing policies to
replace traditional cost-of-service ratemaking in certain respects.
Minnesota Power also agrees that an RTO would help identify the best
place on the grid to locate new generation. It believes that the
centralization of regional reliability planning is a big step forward
for enabling independent power producers to build projects and also is
a significant benefit to each transmission owner who deals with
requests from generation groups.
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\106\ Comments are addressed in greater detail in the discussion
of planning and expansion as an RTO minimum function.
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Illinois Commission and Texas Commission state that electricity
consumers in states adopting retail direct access can directly and
fully benefit from the operation of properly constituted RTOs and their
concomitant improvements in system efficiency, reliability and market
competition.
Comments on RTOs Improving Grid Reliability. Many commenters agree
that an RTO could provide improved reliability.\107\ Minnesota Power
supports the formation of a single regional body that operates the
regional grid and enforces reliability rules for the entire region. It
suggests that a non-profit RTO can be expected to enforce reliability
rules fairly and aggressively and, thus, require minimal Commission
oversight. On the other hand, a for-profit RTO may be perceived as
biased towards making a profit at the expense of reliability and may
require additional scrutiny by the Commission.
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\107\ Comments are addressed in greater detail in the discussion
of short-term reliability as an RTO minimum characteristic.
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Michigan Commission strongly supports creating an RTO for the
Midwest that is large enough to ensure reliability. It is very
concerned that splitting the Midwest region into improperly sized
competing ISOs, RTOs, and/or Transcos will affect regional reliability
and delay the benefits of competition. Also, splitting a region into
multiple RTOs reduces
[[Page 827]]
access to economic generation due to increased transmission charges.
Michigan Commission believes competition and reliability within the
region will be served best if the Transmission Alliance and Midwest ISO
are joined.
Comments on RTOs Removing Opportunities for Discriminatory
Transmission Practices. Many commenters, mostly transmission customers,
agree that RTOs will remedy continuing opportunities for undue
discrimination.\108\
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\108\ See, e.g., American Forest, TDU Systems, WPPI, Sonat,
Illinois Commission, Arizona Commission, FMPA, Tampa Electric,
Advisory Committee ISO-NE. Comments are addressed in more detail
later in the discussion of existing discriminatory conduct.
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As both a buyer and seller of wholesale electricity, Oglethorpe
supports the evolution of competitive markets for generation service.
To ensure that competitive markets evolve and perform in a workable
manner, market participants should be assured access to the
transmission system on a fair and comparable basis, without regard to
transmission ownership. It believes that true competition can occur
only with widespread, open and nondiscriminatory access to the
transmission system. UtiliCorp claims that removing control over access
to transmission from the remaining large transmission-owning utilities
and placing such control in properly structured RTOs will go a long way
toward eliminating the remaining obstructions to effective competition
in wholesale markets for electric power.
Virginia Commission agrees that discrimination exists and that RTOs
can help facilitate competition and police non-competitive activities.
However, Virginia Commission believes that it is premature to conclude
that there is no role for rigorous governmental regulation. Virginia
Commission urges that the Commission not rely exclusively on RTOs to
detect, prevent and penalize violations of the FPA and should itself
provide for expedited handling of allegations regarding discrimination
and market power abuses.
On the other hand, a number of commenters, mostly transmission
owners, do not believe that RTOs are needed to address undue
discrimination because they do not believe that significant
discrimination problems remain with respect to wholesale transmission
access pursuant to Order No. 888.\109\ PSE&G argues that, if a
misperception exists in the marketplace as to the trustworthiness or
incentives of transmission owners as a whole, it may signal a need for
an industry-wide educational campaign that discusses transmission
operation and system reliability. However, such a misperception does
not, in and of itself, warrant altering the structure of the industry.
---------------------------------------------------------------------------
\109\ See, e.g., United Illuminating, Southern Company,
MidAmerican, Duke, PSE&G, FP&L, Entergy, FirstEnergy, Alliance
Companies, Lenard, Florida Power Corp.
---------------------------------------------------------------------------
Comments on RTOs Resulting in Improved Market Performance. DOE
asserts that open and comparable transmission access can reduce both
concentration in generation markets (by expanding the boundaries of the
relevant market) and the potential to discriminate through vertical
control but cannot, in its view, eliminate all market power. The
establishment of an independent RTO can and should substantially
mitigate the potential exercise of market power through vertical
control, because dispatch and related transmission services will be
provided by an independent entity with no financial interest in
wholesale market participants. Furthermore, the expected contribution
of an RTO in reducing the risk of horizontal market power will be
realized only if RTOs have sufficient ``critical mass.'' Appropriately
sized RTOs are necessary to assure a transparent and fair marketplace
for all generation.
EPA notes that RTOs can play an important role in the development
of environmentally preferred or ``green'' electricity products for use
by states that are implementing retail electricity competition. As the
operator of the transmission system, an RTO will have access to
detailed information on the operations of individual generators as well
as fuel type and air emissions, even where such information is
considered confidential. RTOs are uniquely situated to assemble the
information necessary to determine environmental attributes of specific
retail electricity products for purposes of consumer information
disclosure. EPA notes that this is already occurring in New England,
where ISO-NE has agreed to provide the states with information on
environmental attributes and resource mix for individual generators. In
addition to facilitating consumer information disclosure, EPA notes
that this information will support other state policies, such as
renewable portfolio standards and generation performance standards.
Comments on RTOs Facilitating Lighter-Handed Governmental
Regulation. Although most commenters agree that properly-designed RTOs
can be self-governing to a certain extent, the vast majority of
commenters believe that the Commission has either overstated the
reliance it should place on self-governance or has reached this
conclusion prematurely. Most of these commenters suggest that there is
insufficient evidence at this time to reach the conclusion that RTO
formation would necessarily result in lighter-handed regulation. A
number of commenters also caution that the Commission should not
significantly reduce its oversight of RTOs until they are proven to be
effective. British Columbia Ministry states that the structure of
future RTOs should minimize additional layers of administration and
oversight. However, at least one commenter, Cal DWR, noting that RTOs
are themselves transmission monopolies subject to the FPA, argues that
the Commission should continue its course of regulating RTOs to ensure
compliance with legal and policy requirements.
PJM generally supports the Commission's conclusion regarding light-
handed regulation. It notes that, where ISOs' decisions are independent
and conducted through an extensive stakeholder processes to produce
collaborative solutions to market issues, the Commission can defer
confidently to those decisions. Under such circumstances, the
Commission can be assured that ISO proposals to changes market rules
and procedures would promote competitive markets and are not designed
to favor any one group of market participants.
PJM argues further that the Commission accord greater flexibility
to properly structured RTOs to change market rules and procedures
without Commission filings. An RTO with an established stakeholder
process could publish some changes in market rules on its internet
site, without requiring prior Commission approval. In the event that a
market participant objected, it could file a complaint with the
Commission. PJM says the benefit is that the market would not be
hindered by delay in implementing new rules. Other rules could be
permitted to go into effect upon filing, rather than at the end of the
Commission review process.
Some commenters suggest that the Commission be particularly
deferential to decisions that result from ADR processes. For example,
PNGC supports strong and broad dispute resolution power in an RTO. It
argues that many small transmission users currently have no effective
way to be heard regarding service complaints, outage restoration, and
adequacy of equipment or maintenance because of the high cost of
bringing such a dispute to the Commission. In addition, Desert STAR
[[Page 828]]
asserts that where the Commission has approved the charter governance
and ADR processes of an RTO as being sufficiently broad-based and
independent, the Commission should give some deference to decisions
reached through the RTO's ADR processes. However, deference in dispute
resolution to an RTO should not impair a transmission user's
fundamental rights under section 211 of the FPA. Because the RTO will
be a jurisdictional entity, the Commission is an appropriate appeals
forum. Similarly, Seattle supports the Commission proposal to defer to
RTOs on matters involving commercial, operating and planning practices,
as well as to resolve disputes, but argues that it is too early to tell
whether ISOs transcos or other forms of RTOs can be deferred to in lieu
of regulatory filings.
MidAmerican welcomes the Commission's proposed lighter-handed
approach to regulation, but questions whether lighter-handed
regulation, in fact, will be derived from the proposed rule.
MidAmerican proposes that the Commission issue a policy statement to
provide general guidance on how it intends to give deference to RTOs.
For example, the policy should outline that, if a transmission owner
follows RTO directives, it will be presumed that the transmission owner
does not have transmission market power and that it is not capable of
transmission market discrimination. The Commission should give
deference to RTOs to design tariffs that include rate incentives and
should permit returns on equity that compensate transmission owners for
additional risks and for competitive market development.
A number of commenters argue that there is as yet no evidence to
support the conclusion that RTO formation should lead to lighter-handed
regulation. Duke and Entergy argue that each of the existing ISOs has
been mired in significant litigation with market participants, and the
Commission's dockets are loaded with cases arising out of decisions
made by ISOs. They and NECPUC suggest that this raises the possibility
that RTOs represent a new layer of regulatory oversight of market
activities, supplementing rather than replacing federal and state
regulation. FP&L states that the independence and objectivity of the
Florida Public Service Commission make it unnecessary to create a
formal (and costly) separate entity to operate and oversee the Florida
grid as an RTO.
Other commenters suggest that the probability that RTOs can be
self-regulating may be overstated. APPA argues that existing ISOs still
represent the interests of the transmission owners that formed these
ISOs. In addition, it argues that each ISO is a market participant
because its revenue recovery is affected by the performance of
transmission, ancillary services, and energy imbalance spot markets. It
suggests that the right to self-regulation must be earned in the
marketplace, not bestowed by regulators in advance.
NECPUC argues that not only must an RTO be properly structured to
be self-regulating, so must the utilities involved, or the RTO will
constantly be involved in the business of dispute resolution. It
suggests that during a transition phase, a certain level of active
regulation may be inescapable. For example, it notes that the
Commission stepped in quite definitively in developing the governance
of the New England Power Pool. NECPUC believes that strong intervention
by the Commission was effective at achieving progress when the parties
in New England stalemated.
PG&E claims that an RTO is uniquely situated to handle a number of
responsibilities, including reliability enforcement and sanctions,
market monitoring, and reporting non-reliability market-related
violations. However, a single entity, no matter how well-structured and
independent, cannot successfully fulfill several competing roles
simultaneously, i.e., serve as judge, jury and advocate. While the RTO
can do much to create region-specific processes that meet the needs of
market participants, the Commission must retain ultimate oversight. The
RTO is not a substitute for this function. With the tremendous volume
of transactions flowing through an RTO, even small errors in energy or
financial accounting can lead to huge cost shifts. Market participants
need to have a remedy at the Commission if issues are not resolved
adequately by the RTO.
Other commenters believe that the Commission may have to play a
strong role in ADR. Arizona Commission urges the Commission to give
respect rather than deference to decisions reached through an RTO's ADR
processes. TDU Systems state that the ability of an RTO transmission
customer to obtain ultimate Commission review of a dispute with the RTO
(or another RTO customer) should not be cut off. RTO tariffs should
contain ADR provisions that allow for mediation or other low-cost forms
of ADR so disputes can, if possible, be resolved without resort to the
Commission. If this is not possible, the Commission should consider any
dispute that comes to it after the conclusion of ADR at an RTO on a de
novo basis.
In dealing with disputes between RTOs and their customers, TDU
Systems suggests that the Commission be sensitive to the issue of
``minority rights.'' The Commission should ensure that transmission
customers with complaints against their RTOs get due process and a full
and fair opportunity to air their concerns. Just because a customer may
take a position in a dispute not shared by many others does not mean
that it is automatically wrong.
Moreover, TDU Systems believe that the Commission, in considering
the ADR issue, should make a distinction between ISOs or other RTOs
that are not-for-profit or quasi-governmental in nature and for-profit
RTOs. For-profit RTOs may not necessarily be well suited to be the
arbiters of disputes, especially where they are an involved party. It
would be inappropriate for the Commission simply to ``off load''
dispute resolution duties to a private for-profit entity, especially if
the entity is an interested party in the dispute. ISOs, on the other
hand, are more quasi-governmental in nature, and if fully independent,
may be in a better position to attempt to resolve a dispute, subject to
Commission review.
Duke asserts that streamlined filings and approval procedures could
reduce costs that would otherwise be borne by market participants.
Reducing regulatory burdens could constitute one form of incentive to
encourage RTO participation. The policy could be applied equally for
non-profit and for-profit RTOs. On the other hand, TDU Systems argues
that opportunities for streamlined RTO filings could set a very
dangerous precedent, especially if applied to incentive rate filings of
for-profit RTOs. RTOs will still be monopolies (although hopefully
large horizontal ones, rather than smaller, vertically integrated
ones). The norm for RTO filings should still be full Commission
scrutiny. Entergy argues that the Commission should encourage proposals
submitted by RTOs designed to increase regulatory efficiencies and
reduce regulatory burdens imposed on RTOs. The Commission should
specifically declare its willingness to entertain proposals to
streamline filing requirements. The Commission could encourage
innovative ways to reduce regulatory costs by authorizing performance-
based rates that reward RTOs for reducing regulatory costs.
Commission Conclusion. We conclude that properly structured RTOs
throughout the United States can provide significant benefits in the
operation of the transmission grid. The comments received reinforce our
preliminary determination in the NOPR
[[Page 829]]
that RTOs can effectively remove existing impediments to competition in
the power markets.
Description of Benefits. We conclude that RTOs will provide the
benefits that we described in detail in the NOPR, and others that
commenters mention.110 While we acknowledge that the level
of RTO benefits may vary from region to region depending on the current
transparency and efficiency of markets, the Commission believes that
benefits from RTO's would be universal. These benefits will include:
increased efficiency through regional transmission pricing and the
elimination of rate pancaking; improved congestion management; more
accurate estimates of ATC; more effective management of parallel path
flows; more efficient planning for transmission and generation
investments; increased coordination among state regulatory agencies;
reduced transaction costs; facilitation of the success of state retail
access programs; facilitation of the development of environmentally
preferred generation in states with retail access programs; improved
grid reliability; and fewer opportunities for discriminatory
transmission practices.111 All of these improvements to the
efficiencies in the transmission grid will help improve power market
performance, which will ultimately result in lower prices to the
Nation's electricity consumers.
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\110\ The benefits described in this section are not intended to
include all benefits that RTOs could provide. Some of the principal
benefits of RTOs (e.g., more effective management of parallel path
flows, improved congestion management) are addressed in later
discussions of RTO minimum characteristics and functions.
\111\ FERC Stats. & Regs. para. 32,541 at 33,716-20.
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As stated in the NOPR, we expect that RTOs can reduce opportunities
for unduly discriminatory conduct by cleanly separating the control of
transmission from power market participants. An RTO would have no
financial interests in any power market participant, and no power
market participant would be able to control an RTO. This separation
will eliminate the economic incentive and ability for the transmission
provider to act in a way that favors or disfavors any market
participant in the provision of transmission services.
Most commenters support the premise that RTOs can be beneficial in
addressing the remaining transmission-related impediments to full
competition in the electricity markets. Although we recognize certain
differences in perspective about the existence of, or potential for,
widespread discrimination by current transmission owners, no one
seriously disputes the benefits of a marketplace where service quality
and availability are uniform, where users of the network are treated
equally, and where commercially important data are readily available to
all. Although some commenters support the NOPR proposal only if the
costs of establishing RTOs do not exceed the benefits, a subject
discussed further below, most believe that the benefits listed in the
NOPR are accurate and can be achieved through an RTO.
We recognize that some commenters believe that either RTOs alone
will not solve all of the identified problems, or individual benefits
can be achieved in ways other than creating RTOs. Both of these
observations may have some merit. However, we believe that the creation
of RTOs is one action that can address all of the identified
impediments to competition and provide all or most of the identified
benefits.
We also recognize that there are those who worry that the costs of
establishing an RTO will outweigh the benefits. We believe this concern
fails to account for the flexibility we have built into this rule.
While many look at the high costs involved with respect to establishing
some existing ISOs and PXs, this rule does not require an RTO to follow
any specific approach. For example, this rule does not require the
consolidation of control areas nor does it require the establishment of
a PX. We are allowing significant flexibility with respect to how and,
in some cases, when the minimum characteristics and functions are
satisfied. Accordingly, we do not believe it will be necessary to
expend the same level of resources that were expended, e.g., in
California, to create an RTO satisfying our minimum characteristics and
functions. We therefore conclude that the flexibility built into the
Final Rule will allow RTOs to create streamlined organizational
structures that are not overly costly. Moreover, with five ISOs now
operating in the United States, there is considerable experience
available regarding what works and what does not with respect to
regional transmission entities. This experience should make it somewhat
easier, and more cost efficient, to create new RTOs.
As we stated in the NOPR, by improving efficiencies in the
management of the grid, improving grid reliability, and removing any
remaining opportunities for discriminatory transmission practices, the
widespread development of RTOs will improve the performance of
electricity markets in several ways and consequently lower prices to
the Nation's electricity consumers. To the extent that RTOs foster
fully competitive wholesale markets, the incentives to operate
generating plants efficiently are bolstered. The evidence is clear that
market incentives can lead to highly efficient plant operations. The
incentives for more efficient plant operation can also affect existing
generation facilities. Especially noteworthy is the recent experience
that indicates improvements in the generation sector in regions with
ISOs. Regions that have ISOs in place are undergoing dramatic shifts in
the ownership of generating facilities. Large-scale divestiture and
high levels of new entry in California and the Northeast are changing
the ownership structure of these regions' generators. Access to
customers and the presence of competing suppliers are creating the
incentives for better-performing plants.
By improving competition, RTOs also will reduce the potential for
market power abuse. As discussed earlier, eliminating pancaked
transmission prices will expand the scope of markets and bring more
players into the markets. By eliminating the mistrust in the current
grid management, entry by new generation into the market will become
more likely as new entrants will perceive the market as more fair and
attractive for investment. And with more players, the market becomes
deeper and more fluid, allowing for more sophisticated forms of
transacting and better matching of buyers and sellers.
Estimation of Benefits. The full value of the benefits of RTOs to
improve market performance cannot be known with precision before their
development, and we do not yet have a sufficiently long track record
with existing institutions with which to measure. The Commission staff
has estimated a subset of the potential cost savings from RTOs as part
of its National Environmental Policy Act analysis. In the Environmental
Assessment (EA) for this rulemaking, three scenarios were developed to
estimate potential economic and environmental effects of the
rulemaking.112 The scenario analysis was conducted using a
computer simulation model of the continental U.S. electric power system
over the
[[Page 830]]
period 1997 to 2015.113 The Commission adopts staff's
analysis.
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\112\ One of these scenarios assessed transmission effects only,
the second assessed generation efficiencies in addition to
transmission effects, and the third posited increased entry of new
supply and demand choices.
\113\ The Integrated Planning Model (IPM) was developed for the
U.S. Environmental Protection Agency by ICF Inc. See 3.3.1 of the
Commission Staff's Environmental Assessment in this proceeding.
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The results of the EA modeling present a range of potential cost
savings resulting from the changes in modeling assumptions in each
scenario. Although this Final Rule does not mandate RTO formation, full
development of RTOs as envisioned by the Commission in this rule could
offer substantial economic benefits. The EA scenarios modeled resulted
in average annual savings of up to $5.1 billion per year over the 2000-
2015 period. Based upon review of the EA scenarios and comparison with
other existing analyses of competitive electric power markets, the best
estimate from the EA analysis of annual benefits that could result from
RTO formation is $2.4 billion per year. This estimate results from a
scenario in which the modeling assumptions for transmission and
generation efficiency are selected for consistency with other economic
analyses of competitive power markets, including the Order No. 888
Environmental Impact Statement analysis conducted by Commission staff
in 1996.114
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\114\ Order No. 888, Final Environmental Impact Statement, FERC/
EIS-0096, FERC Stats. & Regs. para. 31,036 at 31,860-96.
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These estimates do not represent a complete economic analysis of
the rulemaking because the EA analysis addressed only factors that may
change the dispatch of power plants or future generating capacity
decisions. The model accounts for production costs (capital additions,
operations and maintenance expenses, and fuel) equal to roughly one-
third of the annual sales revenue now passing through the industry, and
does not include such cost categories as existing (sunk) capital, the
distribution system, and end user charges such as taxes. If other cost
savings were realized, for example, from merger-like consolidation
savings in the transmission grid, these savings would be additional to
those estimated in the EA. Benefits from elimination of market power
and improved intra-regional congestion management are also not included
in the calculation and could represent significant additional savings.
The costs of RTO formation are not explicitly captured in the EA
analysis, nor are any potential costs associated with the provision of
incentives for RTO formation or operation. Costs of RTO formation
cannot be well estimated because of the wide range of design choices
that the rule allows for a new RTO. For instance, the choice of
building a dedicated telecommunications and data infrastructure, as
opposed to relying on existing infrastructures, can have a large effect
on the initial cost of an RTO.115
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\115\ See, e.g., California ISO, Cost Performance Benchmarking
Study of Independent System Operators, revised version of Feb. 17,
1999.
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Based on review of cost studies for existing ISOs, it appears
unlikely that the costs of RTO formation will exceed RTO cost savings
on an annualized basis over time. This is because most of the costs are
capital investments that occur at the beginning of the RTO's operation.
But whether the costs in the initial period are under $10 million or up
to several hundred million dollars (and more likely between these two
figures) for an RTO, they are small in comparison with the ongoing
annual savings that RTOs may provide.
As discussed above, our best estimate of cost savings from RTO
formation is $2.4 billion annually, with potential cost savings
estimated to be as high as $5.1 billion annually. This represents about
1.1 to 2.4 percent of the current total costs of the U.S. electric
power industry.116 Such savings can be considered in the
context of recent analysis of the economic benefits of further industry
restructuring.117 The wholesale cost savings the Commission
is anticipating from the formation of RTOs are properly viewed as
distinct from the larger savings that may result from competitive
retail power markets. However, RTOs can also help achieve retail access
and its associated benefits by creating a robust wholesale power
market. In this sense the cost savings from retail access depend on the
Commission fulfilling its RTO objectives.118
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\116\ Defined as revenue from sales to ultimate users, which
were reported as $215 billion in 1997. See Energy Information
Administration, Annual Energy Review 1997, DOE/EIA-0384(97) (July
1998).
\117\See, e.g., Department of Energy, Supporting Analysis for
the Comprehensive Electricity Competition Act, DOE-PO-0059 (May
1999).
\118\ DOE's Economic Analysis of the Comprehensive Electricity
Competition Act shows an estimated cost savings from a national
policy of retail access to be $20 to $32 billion per year. See id.
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Light-Handed Regulation. One of the benefits of RTOs that we
identified in the NOPR was that the existence of a properly structured
RTO would reduce the need for Commission oversight and scrutiny, which
would benefit both the Commission and the industry. We stated that to
the extent an RTO is independent of power marketing interests, there
would be no need for the Commission to monitor and attempt to enforce
compliance with the standards of conduct designed to unbundle a
utility's transmission and generation functions. We also stated that an
independent RTO with an impartial dispute resolution mechanism could
resolve disputes without resort to the Commission complaint process,
and that it is generally more efficient for these organizations to
resolve many disputes internally rather than bringing every dispute to
the Commission. Further, we noted that the Commission has in the past
indicated its willingness to grant more latitude to transmission
pricing proposals from appropriately constituted regional groups
119 and, to the extent that RTOs increase market size and
decrease market concentration, the competitive consequences of proposed
mergers would become less problematic and thereby help further
streamline the Commission's merger decision-making process.
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\119\ Inquiry Concerning the Commission's Pricing Policy for
Transmission Services Provided by Public Utilities Under the Federal
Power Act, 59 FR 55031 (Nov. 3, 1994), FERC Stats. & Regs. para.
31,005, at 31,140, 31,145, 31,148 (1994) (Transmission Pricing
Policy Statement).
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We continue to believe that the types of reduced regulatory
scrutiny mentioned in the NOPR, and summarized above, are possible and
appropriate for RTOs. A number of commenters, however, have expressed
concern that it is premature to reduce regulation of RTOs, and that
RTOs will be monopolies that will require continued regulation. We
believe that this concern stems from a misunderstanding of our concept
of light-handed regulation. Admittedly, this concept is subject to
varying interpretations.
We clarify that we will continue to apply the level of regulation
and scrutiny that is necessary to ensure that public utilities comply
with the FPA and our regulations. Only when we determine that a
different form of regulation will adequately protect the public
interest, we will allow a reduced oversight role for the Commission.
Furthermore, our encouragement of the use of ADR by participants in
RTOs to resolve disputes without resort to formal complaint proceedings
is not new. In our RTG Policy Statement, we encouraged RTGs to develop
alternative dispute resolution procedures for resolving transmission
issues, particularly technical and reliability issues. We also stated
that we would be willing to entertain proposals for some degree of
deference to decisions rendered pursuant to an ADR process, pursuant to
procedures that are specified in an agreement and assure
[[Page 831]]
due process for all participants. 120 We stated there, and
we reaffirm here, that while the Commission cannot delegate its
authority, it can give deference to resolutions that meet the standards
of the FPA.
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\120\ Policy Statement Regarding Regional Transmission Groups,
58 FR 41626 (Aug. 5, 1993), FERC Stats. & Regs. para. 30,976 (1993)
(RTG Policy Statement).
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We reiterated this concept in the eleven ISO principles we set
forth in Order No. 888. We stated there that an ISO should provide for
a voluntary dispute resolution process that allows parties to resolve
technical, financial, and other issues without resort to filing
complaints at the Commission.121 We have also expressed our
willingness to grant some deference to changes to an open access tariff
by an ISO concerning a regional solution to an identified regional
problem based on what we understand is a broad consensus.122
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\121\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,732.
\122\ See PJM Interconnection, L.L.C., 84 FERC para. 61,212
(1998).
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Accordingly, we believe that some degree of deference can be
granted on certain issues to independent RTOs that have appropriate
procedural mechanisms in place to ensure fair representation of
viewpoints. We cannot delineate here precisely the degree of deference
that is appropriate, or on what issues. To the extent some issues can
be fairly resolved within a region without formal Commission
procedures, a benefit accrues to both the parties and the Commission.
In addition, we note that some of the innovative ratemaking
policies discussed later in this Final Rule are consistent with light-
handed regulation, since we expect that these policies may result in
reduced levels of regulatory scrutiny. We emphasize, however, that we
will not delegate or fail to exercise our regulatory responsibilities.
We also recognize that the degree of deference and reduced regulatory
scrutiny accorded to an RTO may necessarily depend on the ability of
the RTO to reach consensus solutions to regional issues.
C. Commission's Approach to RTO Formation
The NOPR proposed an approach to RTO formation that embraces
several general principles: first, as a matter of policy, we should
strongly encourage transmission owners to participate voluntarily in
RTOs; second, we should be neutral as to organizational form (e.g., ISO
or transco) of an RTO as long as it satisfies our minimum
characteristics and functions; and third, we should provide maximum
flexibility as to the specifics of how an RTO can satisfy the minimum
characteristics and functions. We sought comment on these principles
and specifically asked whether we should generically mandate RTO
participation 123 or whether market-based rates or merger
approvals should be conditioned on RTO participation.124
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\123\ FERC Stats. & Regs. para. 32,541 at 33,762.
\124\ Id.
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Based on the wide array of comments received, which we discuss
next, and the voluminous record compiled in this rulemaking proceeding,
we conclude that a voluntary approach to RTO formation represents a
measured and appropriate response to the technical impediments to
competition that have been identified as well as the lingering
discrimination concerns that have been raised. We believe that
voluntary formation of RTOs will address the fundamental economic and
engineering issues which confront the industry and the Commission, and
will help eliminate any actual or perceived discriminatory conduct by
entities that continue to control both generation and transmission
facilities.125 Further, we believe that the voluntary
process adopted in this rule, in conjunction with the innovative
transmission pricing reforms that we will permit RTOs to seek, will be
successful in achieving widespread formation of RTOs in a timely
manner. Our adoption of a voluntary approach to RTO formation in this
Final Rule does not in any way preclude the exercise of any of our
authorities under the FPA to order remedies to address undue
discrimination or the exercise of market power, including the remedy of
requiring participation in an RTO, where supported by the record.
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\125\ These engineering, economic and discrimination issues are
discussed in Section III.A above.
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1. Voluntary Approach
Comments. Comments as to whether the Commission should require
formation of and/or participation in RTOs break down into five main
categories: (1) The Commission should require formation of and
participation in RTOs; (2) formation of and participation in RTOs
should be voluntary; (3) the Commission should encourage voluntary
RTOs, but with strong enforcement mechanisms; (4) RTOs should be
voluntary, but if they do not form or if utilities do not participate,
the Commission should mandate them; and (5) RTOs should be voluntary,
but the requirements of the NOPR effectively create a mandate.
Most investor-owned utilities argue that RTOs should be voluntary.
Most municipal utilities, customer groups, consumer advocates, and
marketers argue that the Commission should require RTOs. State
commissions and cooperatives are more evenly split. These
characterizations, however, are broad generalizations, and there are
strong exceptions to each statement.
Comments That the Commission Should Require Formation of and
Participation in RTOs. The most extensive argument for mandating RTOs
comes from TAPS and is representative of the positions of a number of
public power utilities and other transmission customers. 126
TAPS argues that the non-mandatory approach leaves the keys to reform
in the hands of the wrong people--the monopolists who have market
power--and that the voluntary creation of RTOs will give opportunities
for monopolists to maintain their market power. TAPS presents extensive
arguments as to the Commission's authority to mandate and its
obligation under the FPA to do so. They state:
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\126\ E.g., APPA, Empire District, FMPA, Great River, Lincoln,
UAMPS, UMPA.
Only by mandating that jurisdictional utilities participate in *
* * RTOs will the Commission protect against * * * utilities'
inclinations to form alternative RTOs that are structured to
perpetuate or enhance their competitive position. Compelling such
participation is also the only way for the Commission to satisfy its
statutory obligations to eradicate undue discrimination and protect
against unjust and unreasonable pricing of both transmission service
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and wholesale generation sales.
TAPS further argues that past attempts to allow voluntary formation of
RTOs have not been successful. Only where states have required ISOs or
where the Commission has required them as part of a merger proceeding
have effective ISOs been formed.
TDU Systems also presents extensive arguments for a mandate. It
argues that the need for a national system of RTOs is urgent; that the
Commission cannot rely purely on voluntary actions of transmission
owners; that only a mandate will create RTOs in a timely fashion; and
that inducements are counterproductive. WPPI states that the financial
incentive to protect a transmission owner's generation investment is
much stronger than any transmission incentive FERC can give to induce
RTO participation. First Rochdale argues that voluntary RTOs will
create too great an emphasis on forcing parties to litigation and other
[[Page 832]]
costly, time consuming dispute resolution.
Some investor-owned utilities support a mandate.127 For
example, Cinergy presents arguments similar to those of TAPS, and
believes that ``all jurisdictional utilities must be required to
transfer control of their transmission facilities to a qualified ISO,
which shall integrate those facilities into an RTO approved by the
Commission.''
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\127\ E.g., Minnesota Power, WEPCO, PG&E, PECO.
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A number of marketers believe that RTOs must be mandated. Sonat is
not convinced that incentives alone are sufficient to persuade
transmission providers to follow through with RTO formation. NEMA
believes that participation by all transmission owners should be
mandatory, but that the form of the RTO should be allowed to evolve.
Many industrial customers agree that RTOs must be required. PJM/
NEPOOL Customers argue that the goals of the Commission cannot be
achieved without mandatory participation by all transmission owners in
RTOs. They go further to state that experience from both the Midwest
ISO/Alliance debate over formation of ISOs and from the natural gas
industry demonstrates monopolists will not act effectively to eliminate
discrimination without strong mandates attached to strong penalties.
Residential consumer advocates and environmental organizations
concur. Public Citizen says that the Commission should order the
creation of three non-profit public transmission companies (one each
for the Eastern, Western, and ERCOT interconnections) and order each
public transco to purchase all of the transmission facilities needed to
provide customers with transmission service.
Project Groups recommends that the final rule be strengthened to
require that if owners do not voluntarily transfer control of
facilities to an approved RTO by a date certain, the Commission will
either order the transfer (in the case of jurisdictional utilities) or
take other actions designed to minimize the opportunities for resisting
owners to use their facilities in anti-competitive ways.
A number of state commissions support a mandatory RTO regime
imposed by the Commission. Illinois Commission does not believe that
the voluntary approach set out in the NOPR is likely to obtain its
objectives and especially not in a timely manner, noting that voluntary
efforts ``for more than six years'' have failed and that the
encouragements and incentives contained in the NOPR are unlikely to
change the situation. Indiana Commission points to its experience with
the Midwest ISO/Alliance debates as indicating that the Commission must
take a more assertive role. Montana Commission agrees, pointing to
unwillingness of transmission owners to give up control and to concerns
about cost-shifting. It recommends that the Commission strengthen the
NOPR to ensure the prompt formation of RTOs using all the tools at its
disposal. Pennsylvania Commission argues that in order to be stable,
both as to their authority and with respect to membership
participation, RTOs must be mandatory. Virginia Commission argues that
the goal of independence is in conflict with a voluntary approach.
Wisconsin Commission argues that the Commission should move forward
quickly and require all transmission facilities to be placed under the
control of an RTO. In the absence of any action from FERC to require
utility membership, it states, it is unclear how any effort to resolve
the ``Swiss cheese'' problems already experienced in the Midwest can
succeed. Ohio Commission argues that it continues to believe that the
mandatory participation and boundary drawing approach is more
appropriate.
Comments That Formation of and Participation in RTOs Should Be
Voluntary. The most extensive presentation of the argument that RTOs
should and must be voluntary comes from Indianapolis P&L and FP&L,
which make mostly legal arguments that are addressed below. Southern
Company argues that a voluntary, flexible RTO policy is consistent with
desires of the states as reflected in statements given at the
consultations with the states held by the Commission. It also avers
that an RTO is not required to achieve the goals of the NOPR. Alliance
Companies and Trans-Elect argue that voluntary formation is the key to
RTO success, noting that the Commission's voluntary approach of
encouraging regionalization of the transmission grid has been
successful and there is no reason to doubt its continued success.
EEI suggests that the voluntary approach is working well,
indicating that five ISOs have been approved serving 46 percent of U.S.
customers and 38 percent of total MWh sales. They state that four other
regions have proposed or are about to propose RTOs which will result,
within three years since the issuance of Order No. 888, in nearly 63
percent of the nation's electricity customers being served by regional
transmission entities. They go on to argue that a mandate could
stimulate litigation that would slow this voluntary
development.128
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\128\ Other transmission-owning utilities supporting voluntary
development and opposing mandates are Detroit Edison, Duke, Entergy,
Florida Power Corp., SCE&G, Metropolitan, MidAmerican, NEPCO et al.,
NU, NSP, Montana-Dakota, Tampa Electric, TXU Electric, United
Illuminating, CP&L, Central Maine and Virginia Power.
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A number of public power entities, including municipal utilities,
cooperative utilities, Federal Power Marketing Administrations, and
others, also support a voluntary approach. TVA argues that FERC's
proposal to make RTO participation voluntary is a wise one, that as
RTOs demonstrate their effectiveness and the benefits of RTOs become
more evident, transmission owners likely will be persuaded to
participate and the holes in the RTOs should disappear. CMUA argues
that mandatory RTOs are not likely to be formed through collaborative
processes and therefore are not likely to take into account broad
stakeholder input. Tacoma Power supports voluntary formation because
some utilities may not find that the cost savings are sufficient to
warrant the expenditure necessary. Also, it states that public power
utilities may face legal obligations or restrictions that inhibit their
participation and that such utilities should not face penalties or
sanctions for not participating.129
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\129\ Other public power and cooperative entities supporting
voluntary formation of RTOs include Big Rivers, East Kentucky,
Georgia Transmission, South Carolina Authority, SMUD, Seattle, JEA,
LPPC, NRECA, Los Angeles, MEAG, Oglethorpe, Platte River, NPRB,
NPPD, RUS and Tri-State.
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A number of state commissions support voluntary formation of RTOs.
Alabama Commission argues that the Commission does not have authority
to mandate RTOs. Florida Commission agrees and states that any action
by the Commission must be on a case-by-case basis, and the Commission
should defer to states in developing regional approaches. Michigan
Commission believes that there is a solution short of mandating RTO
formation, but that uses FERC's unique national perspective and
authority to facilitate larger RTO formation. Wyoming Commission urges
the Commission not to codify or mandate anything other than the general
framework for RTOs and thereby allow the voluntary process an
opportunity to work.130
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\130\ Other state commissions supporting voluntary formation
include South Carolina, Iowa, New York, and Washington. Other
entities supporting voluntary formation of RTOs include NYPP, SRP
and Cal ISO.
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Comments That the Commission Should Encourage Voluntary RTOs But
With Strong Enforcement Mechanisms. The Justice Department argues that
the
[[Page 833]]
NOPR makes a strong case for mandating RTOs. It recommends that a
regime of ``carrots and sticks'' be carefully designed to reasonably
guarantee complete voluntary compliance, rather than merely promote
greater voluntary compliance.
Enron/APX/Coral Power argue that the Commission should take steps
to induce transmission owners to participate in RTOs.131
They doubt, however, that performance-based ratemaking alone will be a
sufficient inducement and recommend Commission procedures to prevent
transmission owners that fail to participate in RTOs from misusing
their transmission systems to favor their own or affiliated uses of
their systems. These could include regional proceedings to impose added
safeguards against violations, presumptions of ineligibility for
market-based rates, and presumptions that mergers are inconsistent with
public interest absent membership in an RTO.
---------------------------------------------------------------------------
\131\ Concurring are H.Q. Energy Services, Midwest Energy and
Oregon Office.
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Comments That RTOs Should Be Voluntary, But if They Do Not Form,
the Commission Should Mandate Them. PNGC argues that if a voluntary RTO
encompassing the Pacific Northwest does not come about in a reasonably
short time, the Commission should explore its authority or seek new
authority to mandate participation in RTOs. Fertilizer Institute
believes that the Commission has sufficient authority to mandate RTOs
but would likely be bogged down in endless litigation should it do so,
and so recommends that the Commission pursue a voluntary approach, but,
should that not work, proceed with a requirement. WPSC argues that
encouraging voluntary participation in RTOs is the appropriate starting
place. However, the Commission must be prepared to take more direct
action, including increased legislative authority, to ensure the
participation of utilities that do not voluntarily choose to join an
RTO.
Comments That RTOs Should Be Voluntary, But the Requirements of the
NOPR Effectively Create a Mandate. Puget states that if the Final Rule
continues to reflect a position that nonparticipation in the RTO will
result in negative regulatory consequences for the nonparticipant, then
the RTO proposal cannot really be said to be voluntary. CP&L argues
that mandatory filings, coupled with threats of withholding benefits
and/or leveling penalties for those that do not choose to
``voluntarily'' join and RTO, do not present a picture of a truly
voluntary process.
Comments on Sanctions for Non-Participation. Most vertically
integrated public utilities oppose conditioning market-based rates and
merger approval on RTO participation, while most transmission customers
favor the Commission using conditioning authority. A number of
utilities express concern that the Commission may be exceeding its
legal authority, and that conditioning would undermine the voluntary
nature of the RTO initiative. Florida Power Corp. argues that the
Commission cannot impose penalties for failure to participate
voluntarily in an RTO in contravention of the FPA. Puget contends that
the possibility of penalties for non-participation means that no
provision is made for participation to be truly voluntary. Duke
expresses concern that potential revocation of market-based rate
authorization and refusal to find a merger in the public interest are
actions that make it legally or economically impossible for any public
utility not to participate in an RTO. EEI observes that such linkage
would change settled law requiring reasoned analysis or factual
findings. Similarly, Consumers Energy submits that summary withdrawal
of existing market-based rate authorization must be justified by
substantial evidence of changed circumstances. CP&L claims that the
Commission cannot impose RTO participation conditions on a proposed
merger that go beyond the consistency with the public interest standard
under the FPA.
Two commenters suggest that the Commission must proceed on a case-
by-case basis. MidAmerican contends that there is no clear indication
that the number of parties competing in generation markets is so small
to cause inadequate levels of competition. Since changes to restructure
the industry into RTOs will be costly and difficult for all parties,
mandates or sanctions should be based only on willful violations of
Commission policy. LG&E concurs that only where the record supports a
case-specific finding that a transmission owner's failure to
participate in an RTO will result in undue discrimination or the
ability to exercise market power should the Commission take remedial
steps to address the situation so that the Commission is on firm legal
grounds.
On the other hand, a number of commenters believe the Commission
must require RTO participation as a condition of future market-based
rate transactions and authorizations. TAPS notes that this is necessary
for the Commission to meet its obligation to protect consumers from
unjust and unreasonable rates if it intends to pursue a lighter-handed
regulatory approach, adding that only RTOs of appropriate size and
structure will be able to meet fully the Commission's statutory
obligation to protect consumers. Oneok and New Smyrna Beach argue that
manipulation and undetectable anticompetitive conduct for which there
is no practical after-the-fact remedy are concerns that could be
alleviated by an RTO and that, accordingly, denial of merger approval
or market-based rate authorization is well within the Commission's
authority when anticompetitive factors have not been mitigated.
PJM/NEPOOL Customers, Great River, East Texas Cooperatives and PNGC
support revoking market-based rate authorization to remedy inherent
discrimination resulting from non-participation and also using non-
participation as a factor in merger analysis. APPA favors imposing the
merger condition in the form of an immediate requirement to participate
given the Commission's prior experience with conditioning mergers with
commitments to join an ISO. merican Forest supports conditioning all
future market-based rate transactions on participation. H.Q. Energy
Services encourages the Commission to explore the full extent of its
authority under the FPA to compel participation in RTOs.
Enron/APX/Coral Power recommend that the Commission create a
rebuttable presumption that RTO participation is required for approval
of market-based pricing or a transfer of facilities under section 203
of the FPA. For market-based rate authorizations, the Commission should
establish a presumption that a decision by a transmission owner not to
participate in an RTO is evidence that it is misusing its transmission
facilities to advantage its merchant function. This presumption could
be rebutted through a demonstration that stand-alone operation of the
non-participant's grid serves the public interest as well as or better
than participating in an RTO. They suggest that utilities currently
with market-based rate authorizations should be ordered to show cause
by the December 15, 2001, implementation deadline why their market rate
authorizations should not be revoked. Enron/APX/Coral Power also
recommend that all sales, leases, mergers and consolidations of
transmission systems be conditioned on RTO participation based on a
presumption that it is inconsistent with the public interest to dispose
of transmission facilities without eliminating the incentive to
[[Page 834]]
discriminate by committing the operation of those facilities to an RTO.
Industrial Consumers believes that the engineering and economic
efficiencies of RTO participation loom so large that the Commission is
justified in adopting a presumption that a decision by a transmission
owner not to participate in an RTO is evidence that it is misusing its
transmission facilities. Industrial Consumers recommends that the
Commission assert jurisdiction over the transmission component of
bundled sales, and order that the rates, terms and conditions offered
under the OATT apply to all eligible customers. This would deprive
vertically-integrated utilities of the incentive to resist RTO
participation.
State commission commenters tend to favor the Commission using
conditioning authority, but some are not sure this will necessarily
encourage participation in RTOs. Oregon Commission comments that unless
a utility can demonstrate that it cannot manipulate the transmission
system to its advantage or that an RTO is impossible, the Commission
should revoke its ability to sell at market-based rates. Complaints of
unfair practices without credible reasons should be prima facie
evidence of market power. Pennsylvania Commission recommends that the
Commission revisit previously granted market-based rate authorizations.
Indiana Commission cautions, however, that a recalcitrant utility that
does not join an RTO may not perceive loss of market-based pricing
authorization as detrimental. Illinois Commission does not oppose
conditioning merger and market-based rate approvals on RTO
participation, but it also believes that the threat of these penalties
may be inadequate to induce RTO participation.
Comments on Consequences for Failure to File, or Filing Alternative
Explanation. The majority of comments on this issue support the
Commission taking additional action if adequate RTOs do not form. PJM/
NEPOOL Customers suggests that strict penalties must be assessed
against actions inconsistent with RTO formation. Oneok suggests that
certain benefits that are within the Commission's authority and
discretion to grant or deny should be withheld from utilities unwilling
to participate. Project Groups recommend that the Final Rule provide
that the Commission itself create RTOs if the stakeholders are unable
or unwilling voluntarily to do so by a reasonable date certain. PNGC
suggests that if RTOs do not form within a reasonable time, the
Commission should explore its authority or seek new authority to
mandate participation by all utilities.
On the other hand, Duke is concerned that the Commission may not
accept valid reasons for nonparticipation and use the October 15, 2000,
alternative filings as vehicles to mandate RTO membership. Duke offers
that the Commission cannot consider imposing penalties for non-
participation while simultaneously claiming that its policy on
participation is voluntary. Seattle cautions that the Commission should
exercise care not to unfairly sanction transmission-owning utilities
that cannot participate in an RTO (e.g., where good cause is shown that
participation would violate state and local legal obligation, or the
costs of RTO participation outweighs the benefits).
Commission Conclusion. Based on the record before us with respect
to undue discrimination and market power, as well as with respect to
economic and engineering issues affecting reliability, operational
efficiency, and competition in the electric industry, it is clear that
RTOs are needed to resolve impediments to fully competitive markets.
However, we continue to believe, as we proposed in the NOPR, that at
this time we should pursue a voluntary approach to participation in
RTOs.
We acknowledge that there are many commenters who are skeptical
that a voluntary approach will be able to accomplish our stated
objective, which, as we stated in the NOPR,132 is for all
transmission-owning entities to place their transmission facilities
under the control of RTOs in a timely manner. In general, they argue
that those with a market advantage will not easily give it up, and that
voluntary efforts to date have not been very successful in creating
effective regional entities.
---------------------------------------------------------------------------
\132\ FERC Stats. and Regs. para. 32,541 at 33,685.
---------------------------------------------------------------------------
However, we believe that a voluntary approach as we have structured
it, with guidance and encouragement from the Commission, is most
appropriate at this time. Given the rapidly evolving state of the
electric industry, we want to allow involved participants the
flexibility to develop mutually agreeable regional arrangements with
respect to RTO formation and coordination. Further, we want the
industry to focus its efforts on the potential benefits of RTO
formation and how best to achieve them, rather than on a non-productive
challenge to our legal authority to mandate RTO participation.
We believe the voluntary approach to RTO formation can be more
successful now than in the past for several reasons. The pace of
industry restructuring is accelerating. Many formerly vertically
integrated utilities have recently recognized the strategic benefits to
them of concentrating solely in one of the traditional utility areas
(generation, transmission, or distribution). Moreover, the NOPR has
focused industry attention on RTOs and their benefits. Further, this
Final Rule is providing clear rules and guidance on what is necessary
to form an RTO. Through this Final Rule, we are also committing the
Commission to act as a catalyst in RTO discussions by initiating and
encouraging a collaborative process. Finally, we have provided in this
Final Rule for certain favorable ratemaking treatments for those who
assume the risks of the transition to a new structure, which should, at
a minimum, eliminate any rate disincentives to RTO formation.
We are not adopting as a generic policy in this Final Rule either
that RTO participation is required in order to retain or obtain market-
based rate authorization for wholesale power sales, or that RTO
participation is required for a disposition of jurisdictional
facilities to be in the public interest. However, in response to those
who argue that the Commission has a statutory responsibility to remedy
undue discrimination and anticompetitive effects when evaluating
market-based rate and merger requests, we recognize that we may have to
consider, in individual cases, issues that arise as to whether market
power has been mitigated in the absence of RTO participation or as to
whether a merger would be in the public interest without RTO
participation.
While we have concluded on this record that it is in the public
interest to provide for a voluntary approach to RTO formation that
relies upon encouragement, guidance, and support from the Commission,
this does not mean that all aspects of this Rule are voluntary. The
filing requirements set forth in section 35.34(c) of the new
regulations are mandatory. In other words, public utilities must file
either an RTO proposal or a report on the impediments to RTO
participation. In addition, to qualify as an RTO, an applicant must
comply with the minimum characteristics and functions and other
specific RTO requirements set forth in the new regulations. We will
also expect that all transmission owners will participate in good faith
in the collaborative process that we are establishing herein.
2. Organizational Form of an RTO
Comments. A number of commenters address the proposal to allow
flexibility
[[Page 835]]
in the type of structure allowed for RTOs. Several of those commenting
recommend maintaining the NOPR's flexibility and that the Commission
not prescribe either a transco, ISO or some other
structure.133 FirstEnergy advocates flexibility and says
that no one knows today what the best structure will be for the future
so, therefore, the Commission should allow customization reflecting
regional needs. Several commenters, such as APPA, argue that the
Commission's flexibility on type of organization should go beyond the
standard ISO and transco structures and include gridcos, wirecos, not-
for-profit and for-profit forms of each organization, and hybrid
organizations.
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\133\ See, e.g., EEI, Lincoln, LG&E, SERC and Washington
Commission.
---------------------------------------------------------------------------
Numerous commenters state a preference in favor of for-profit
transcos although many of these commenters still recommend that other
structures be allowed at each region's option.134 In
favoring transcos, commenters cite the greater efficiency due to a
transco's profit motive.135 Commenters further argue that
for-profit transcos can better serve the goal of independence because
the transco would make all business decisions,136 can more
cleanly divide Commission-regulated transmission from state-regulated
distribution,137 and can operate more efficiently by
integrating investment decisions, facility design, construction and O&M
into a unified strategy.138 A few additional supporters of
transcos prefer that they be not-for-profit.139 Gainesville
recommends further that transcos in Florida become an instrumentality
of the state.
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\134\ See, e.g., Allegheny, Entergy, INGAA and Trans-Elect.
\135\ See, e.g., Sierra Pacific, H.Q. Energy Services and
Detroit Edison.
\136\ MidAmerican.
\137\ CTA.
\138\ Duke.
\139\ LPPC, Los Angeles, Gainesville and Public Citizen.
---------------------------------------------------------------------------
In contrast to the above, ISOs are preferred by a number of
commenters.140 PJM argues that ISOs are necessary to ensure
independence, provide more independent market monitoring and have a
fiduciary duty to the public interest. PJM also notes that ISOs can
meet the Commission's objectives more quickly than transcos. NASUCA
reports that some of its members oppose for-profit transcos because of
their ``natural incentive to extract monopoly rents from consumers.''
141 Some of those who prefer ISOs contend that transcos
would favor transmission solutions over generation solutions to
congestion.142 This argument is contested in the reply
comments of Trans-Elect and others. NEPCO et al. maintains that the
alleged bias in favor of transmission solutions can be overcome by
using performance-based rates to replace standard rate base regulation.
---------------------------------------------------------------------------
\140\ See, e.g., NASUCA, PJM and ICUA.
\141\ NASUCA at 20.
\142\ See, e.g., PJM and ISO-NE.
---------------------------------------------------------------------------
Some commenters favor a hybrid involving an ISO with a gridco or
with another type of organization.143 As noted above, many
commenters recommend flexibility and believe that either an ISO or
transco would satisfy the needs of an RTO if designed properly.
---------------------------------------------------------------------------
\143\ See, e.g., ISO-NE.
---------------------------------------------------------------------------
Several commenters cited problems that need to be worked out for
both transcos and ISOs. Professor Joskow notes that ISOs would suffer
efficiency losses from the separation between ownership and operation
of transmission assets. This separation makes it harder to apply
incentive regulation because it divides decisions that affect the costs
of transmission between two organizations. On the other hand, Professor
Joskow says that an ISO may be superior to a transco where transmission
ownership is presently so balkanized that loop flow and congestion
cannot be managed, but he asserts that this advantage may decline over
time as the industry changes. Southern Company says that while some see
ISOs as ineffective bureaucracies which add to transmission risk, the
creation of transcos presents substantial tax and financial problems.
A few commenters contend that the NOPR's provisions produce a bias
in favor of ISOs even though this intent is not noted.144
For example, Duke argues that the NOPR provisions for stakeholder
participation in formation, governance and market monitoring functions
seem more geared toward the ISO form of organization. These commenters
recommend that the Final Rule not include such a bias.
---------------------------------------------------------------------------
\144\ See, e.g., Sierra Pacific, Duke and Enron/APX/Coral Power.
---------------------------------------------------------------------------
A number of commenters suggest multi-layered structural
alternatives. For example, ISO-NE proposes an ISO and gridco operating
in tandem. A non-profit ISO would direct the operation of the
transmission system and run day-ahead and real-time power markets
coupled with a grid entity that owns and maintains the transmission in
the area operated by the ISO. This, they claim, would require a final
rule that defines an RTO as an entity, or a combination of entities
working in collaboration, that satisfies the minimum characteristics
set forth in the NOPR. Under the model discussed by ISO-NE, the ISO
would have responsibility for assuring open transmission access,
operating the regional transmission assets (including provision of
switching orders to the gridco), monitoring power markets, serving as a
clearing agent and possibly serving as a clearinghouse, and maintaining
short-term reliability. The gridco would own and maintain transmission
assets, operate transmission assets in response to ISO directions
consistent with safety requirements, and build new transmission
facilities (including licensing, permitting and siting
responsibilities). Joint responsibilities would include planning
upgrades to transmission system.
ISO-NE argues that ISOs alone would have disadvantages in the realm
of transmission expansion due to fragmentation of transmission
ownership. A gridco, however, could raise investment capital, bring
parallel and complementary strengths to an ISO, and should bring crisp
and decisive implementation of transmission planning and expansion
decisions. Pairing an ISO with a gridco, ISO-NE argues, would eliminate
the problems inherent in a transco by separating transmission ownership
from market administration and market monitoring.
Midwest ISO suggests a structure that it believes could meld the
best of both ISOs and transcos, i.e., an ISO that would allow an
independent transmission company to operate under the Midwest ISO. This
model would not require that all transmission be owned by a single
gridco--transmission owners could decide whether to operate directly
through the ISO, or spin assets off to a gridco that would operate
under the ISO. Midwest ISO argues that this proposal overcomes the
problems encountered in expecting all transmission owners to divest
their transmission assets to separate companies.
PGE points out that, ``for an RTO to achieve * * * critical mass in
the near term, it must be capable of managing a regional transmission
market in which a variety of subsidiary transmission structures will be
in place. Such subsidiary structures may include single-company and
sub-regional ITCs, integrated utilities located in states that already
have restructured their retail electric markets, integrated utilities
located in states that have not yet restructured, and publicly-owned
and federal utilities.'' PJM argues that ISOs
[[Page 836]]
should be present even in regions that form separate transmission-
owning companies to avoid continued conflict regarding the neutrality
and commercial consequences of grid management decisions.
Professor Hogan states that it is very unlikely that a pure transco
model is viable at all. He further indicates that, ``the advantages of
an independent transmission company can be pursued through the gridco
model with an accompanying ISO.'' He suggests that this approach is
already well advanced in the United States and elsewhere, and that by
separating ownership of the wires from control of system operations, it
would be easy to accommodate a complex pattern of ownership.
ComEd says that characteristics and functions should be performed
by two linked organizations that make up a binary RTO: a for-profit ITC
under the oversight of an independent not-for-profit regional
transmission board.
Michigan Commission believes that wirecos, transcos and ISOs are
all interim transitional organizations along the path toward very large
RTO-like organizations. Even if vestiges of the smaller interim
organizations continue to exist, they should operate under some kind of
RTO umbrella to assure appropriate regional control. Missouri
Commission proposes a zonal model in which the zones are areas where
generation is integrated through the transmission grid in such a way as
to minimize restrictions on sources of generation used in the area. In
the future, independent transmission companies may form with the
possibility that adjacent control areas will join to form larger zones.
In such a case, an RTO is a collection of zones for purposes of
administering the regional gatekeeper function and providing markets
for transmission congestion. Each zone would be responsible for
maintaining its transmission facilities and coordinating both the use
and expansion of those facilities with the RTO.
WEPCO proposes that each RTO should be composed of two parallel
organizations to serve the same region under a common, independent
board: a Regional Reliability Council to develop regional reliability
rules and a not-for-profit ISO that operates under those regional
rules.
Cal DWR suggests a three-tiered structure that builds on existing
organizations. Existing NERC regional councils should set broad
governing criteria for ISO reliability issues, parallel path flow
issues, and for regional planning. More than one ISO may be located in
each NERC region. These should control area reliability, administer
transmission terms and conditions, and create market mechanisms to
manage congestion, among other functions. Transmission owners should
support, but not duplicate the roles of NERC regional councils.
Commission Conclusion. We will not limit the flexibility of
proposed structures or forms of organization for RTOs. We are prepared
to accept a transco, ISO, hybrid form, or other form as long as the RTO
meets our minimum characteristics and functions and other requirements.
Some of the commenters argue that the NOPR's requirements either
favor one form of organization over others or make one or the other
forms very difficult to construct. It is not our intention to favor or
disfavor transcos, ISOs, or other organizational form. We acknowledge
that some of our minimum requirements might affect transcos and ISOs
differently, but there also may be different acceptable ways for an ISO
or transco to satisfy the minimum requirements. However, we designed
this Final Rule to be neutral as to organizational form, and we do not
believe that the requirements for forming an RTO in this Final Rule
favor any particular RTO structure.
Arguments are made that an ISO is the better form of RTO because an
ISO has no incentive either to favor transmission solutions to solve
congestion constraints or to perpetuate congestion. ISOs are easier to
form, in most cases, because there are fewer tax and mortgage
consequences as there is no actual transfer of ownership.
On the other hand, some argue that transcos are preferable because
they introduce a profit motive for efficient operation and expansion.
Performance-based rates are normally considered more effective with
transcos than with ISOs. Advantages are cited for having the same
entity both propose and carry out transmission expansion and
maintenance.
The transco and ISO forms of organization each has its advantages
and disadvantages as do combination forms and other forms that have
been suggested. In many cases, the situation facing transmission owners
in a particular region may influence the appropriate form of
organization to propose. In other cases it may be a matter of
preference for how the participants wish to do business. Some may
propose to start operation in one form and transform to another form at
a future date. Tax consequences, public ownership, bond indentures and
current organization will each have an impact on the decision of what
form of organization a particular RTO will propose.
This Rule does not necessarily require that a single organization
perform all of the functions itself. To mention but a few examples, we
specifically clarify in other parts of this Final Rule that the
security coordinator function and the OASIS function could be shared
with another RTO or contracted out, and that appropriate scope may be
achieved in creative ways. We will entertain appropriate tiered or
other structures. We require only that the RTO be responsible for
ensuring that the requirements are met in a way that satisfies our
Rule.
Because of the differing conditions facing various regions, we
offer flexibility in form of organization. We welcome innovative
structures and forms that meet the needs of the market participants
while satisfying the minimum requirements of this Rule.
3. Degree of Specificity in the Rule
Comments. Many commenters believe that our proposed flexible
approach is either still too rigid, or that it should provide clearer
guidance. INGAA argues for less specificity in the Final Rule. INGAA
points to the success of Order No. 636, wherein the Commission required
open access, functional unbundling, and a new rate design, and it
established specific requirements for operational control and pipeline
capacity trading, all without having to specify the structure of the
conforming gas transmission entity. NU similarly points to the
precedent of the restructured gas industry. It states that the
Commission should avoid the perils of imposing a rigid system pursuant
to the mistaken belief that it can be easily and swiftly changed later
to respond to future needs of the marketplace. CP&L also cautions that
the principle of flexibility could prove illusory in practice and that
there is a danger that, if guidance from the Commission takes the form
of overly restrictive rules, it will stifle the development of
innovative proposals. PG&E submits that the Commission should simply
define a broad standard that provides for independence and evaluate
particular RTO proposals on a case-by-case basis. South Carolina
Commission also counsels that the Commission should not attempt to
mandate a particular form of RTO, or establish its size or region,
because this will not ensure that an efficient market will develop. It
posits that any RTO policy should be flexible enough and dynamic enough
to allow for both regional and
[[Page 837]]
organizational differences and for growth and changes in the future.
SCE&G claims that the NOPR is overly prescriptive with respect to
both scope and timing. TXU Electric submits that the NOPR's approach to
reliance on minimum characteristics and functions seems to reflect a
significant number of fundamental policy decisions that have already
been made without the benefit of any of the very experimentation the
NOPR extols. Southern Company argues that the Commission should recast
the characteristics and functions as voluntary guidelines at this early
stage in the development of RTOs, since it is unclear what the best
form of RTO will be.
ISO supporters, such as NYPP and Central Maine, recommend that the
Commission reject proposals to impose rigid and inflexible rules on
RTOs and remain flexible especially with regard to existing ISOs and
RTO pricing. ISO-NE counsels that tolerance for a diversity of
approaches is essential, as well as politically pragmatic, due to the
fact that different regions will have different histories, industry
elements, and local regulatory policies that need to be accommodated.
FirstEnergy supports the NOPR's flexibility because there is no
best model to deal with regional variations. Alliance Companies and
Washington Commission also recommend that the Commission adhere to a
flexible RTO policy, open to voluntary regional experimentation in the
design of RTO structures. In addition, both Southern Company and Trans-
Elect recommend that the Commission maintain flexibility toward
transcos. And while a transco supporter, Entergy, sees the NOPR as
properly flexible in regard to for-profit and not-for-profit RTOs.
Finally, Duke agrees that RTOs should satisfy key principles, as long
as they are not so prescriptive as to promote only one type of RTO.
On the other hand, Illinois Commission submits that the NOPR's
minimalist approach will lead to creation of lowest common denominator
RTOs that minimally comply with the characteristics and functions and
general guidance as to geographic scope and membership. Project Groups
suggests that the Commission expand and strengthen the minimum
characteristics. TDU Systems recommends that the Commission resist
calls to water down its Final Rule and urges more substance. TAPS
claims that calls for more flexibility are really a cover for diluted,
ineffective RTOs that will lack the scope, independence and authority
to get the job done.
Commission Conclusion. While many commenters think that our
proposal to rely on guidance and flexibility to promote establishment
of appropriate RTOs is either too rigid or too non-specific, we
conclude that we struck an appropriate balance in the NOPR.
Although we and the electric industry see many problems associated
with the operation of the Nation's transmission systems and we see a
general need for regional transmission solutions, we cannot at this
time foresee the best organizational means to resolve every problem.
Given this situation, we believe that the right balance is a minimally
intrusive, solution-oriented approach that provides guidance and
specifies only the fundamental RTO characteristics and functions.
We do not agree with those commenters who contend that the NOPR
approach adopted herein is either overly or insufficiently
prescriptive. Certainly the minimum characteristics and functions do
reflect a number of threshold requirements, but collectively, these
requirements serve to define the minimum necessary to improve the
operation of the Nation's transmission systems. While we agree that
there is no best answer and we encourage regional innovation, we cannot
simply define a standard of independence and nothing else. This would
leave the industry without direction and provides no guidance on how we
would evaluate the various RTO proposals.
Finally, we do not agree with those who suggest that our electric
regulation must follow our natural gas pipeline industry Order No. 636
model, where the Commission did not attempt structural unbundling of
the pipeline industry but simply relied on more limited, functional
unbundling. The situations in the two industries are different
regarding the need for regional entities. Most importantly, there was
not in the gas industry the degree of vertical integration of
production, transmission, and distribution that historically existed in
the electric industry. In addition, the gas industry has no analog to
loop flow, transmission loading relief, the need for large regional
calculations of ATC, or the use of generation energy and reactive power
output to manipulate transmission flow, among other reasons.
4. Legal Authority
In the NOPR, we noted that sections 205 and 206 of the FPA, 16
U.S.C. 824d and 824e, give the Commission both the authority and
responsibility to ensure that the rates, charges, classifications, and
services of public utilities (and any rule, regulation, practice, or
contract affecting any of these) are just and reasonable and not unduly
discriminatory, and to remedy undue discrimination in the provision of
such services. We stated that in fulfilling its responsibilities under
FPA sections 205 and 206, the Commission is required to address, and
has the authority to remedy, undue discrimination and anticompetitive
effects.145 We also noted that the Commission has the
authority and responsibility under section 203 of the FPA to review
mergers and other transactions involving public utilities, including
dispositions of jurisdictional facilities by public utilities, and that
the Commission may grant an application under section 203 upon such
terms and conditions as it finds necessary to secure the maintenance of
adequate service and the coordination in the public interest of
jurisdictional facilities.
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\145\ FERC Stats. & Regs. para. 32,541 at 33,695.
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Further, we noted that section 202(a) of the FPA authorizes and
directs the Commission ``to divide the country into regional districts
for the voluntary interconnection and coordination of facilities for
the generation, transmission, and sale of electric energy.'' The
purpose of this division into regional districts is for ``assuring an
abundant supply of electric energy throughout the United States with
the greatest possible economy and with regard to the proper utilization
and conservation of natural resources.'' Section 202(a) states that it
is ``the duty of the Commission to promote and encourage such
interconnection and coordination within each such district and between
such districts.''
We solicited comments on whether the Commission should generically
mandate RTO participation by all public utilities to remedy undue
discrimination under sections 205 and 206 of the FPA, whether market-
based rates for generation services could continue to be justified for
a public utility that does not participate in an RTO, whether a merger
involving a public utility that is not a member of an RTO would be
consistent with the public interest, whether non-participants that own
transmission facilities should be allowed to use the non-pancaked
transmission rates of the RTO participants in that region, whether
transmission services provided by a transmitting utility need to be
under RTO control to satisfy the discrimination standards of sections
211 and 212 of the FPA, and whether a public utility's lack of
participation
[[Page 838]]
would otherwise be in violation of the FPA.146
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\146\ Id. at 33,762.
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Comments. The comments on the Commission's legal authority to
mandate participation in RTOs span the spectrum from those asserting
that we clearly have that authority to those asserting that we clearly
do not, with others taking a less definitive position in between.
Supporting Commission's Authority to Mandate RTO Participation.
Representative of those asserting that the Commission has the authority
to mandate RTO participation are the joint comments filed by APPA,
ELCON, TAPS, and TDU Systems (``APPA et al. (WP)''). These parties
argue that the FPA as presently constituted gives the Commission
``ample'' legal authority to require participation by public utilities
in properly structured and configured RTOs. APPA et al. assert that
section 202(a) permits the Commission to determine rational and
efficient regional boundaries; section 203 provides authority to
require RTO participation as a standardized condition to mitigate the
increased generation and transmission concentration brought about by
mergers; ``it would be fully consistent with, and indeed required by''
FPA section 205 to insist on RTO participation as a condition necessary
to yield competition robust enough to produce just and reasonable
market-based rates; requiring RTO participation falls within the
Commission's broad discretion to fashion a remedy for undue
discrimination under FPA sections 205 and 206; and the Commission could
reasonably conclude that it is no longer just and reasonable for
transmission service to be planned, implemented, or priced on a less-
than-regional basis. Other commenters echo some or all of these points
in asserting that the Commission currently has sufficient legal
authority to mandate RTO participation.147
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\147\ E.g., UAMPS, PJM/NEPOOL Customers, Illinois Commission,
Michigan Commission, Cinergy, Industrial Consumers, First Rochdale,
East Texas Cooperatives, FMPA.
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Some other commenters emphasize the authority contained in
particular statutory sections. One commenter states that FPA section
202(a) is an express delegation of authority to the Commission to make
policy, and the stated goal of that section of assuring an abundant
supply of electric energy with the greatest possible economy provides
ample authority to support the conclusion that transmission facilities
should be operated by an RTO. This commenter states that it is well
established administrative law that there is great deference given to
an agency charged with policymaking responsibility.148
Another commenter, FMPA, argues that the Commission's interconnection
authority under FPA sections 202(b) and 210 provides ample basis for
mandating RTO participation. According to FMPA, the Commission could
find that RTO participation is necessary to ``make effective'' an
interconnection, pursuant to FPA section 210, that has been rendered
ineffective by fragmented and anticompetitive practices of transmission
owners. FMPA also asserts that the Commission could use this authority
through a rulemaking without following the individual procedural
requirements of section 212.149
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\148\ Professor Koch, citing Chevron U.S.A., Inc. v. Natural
Resources Defense Council Inc., 467 U.S. 837 (1984).
\149\ Citing American Paper Institute, Inc. v. American Elec.
Power Serv. Corp., 461 U.S. 402, 419-20 (1983).
---------------------------------------------------------------------------
In addition to those commenters finding clear authority in the FPA
for an RTO mandate, a number of commenters support the suggestion, as
one commenter put it, that certain benefits and rights that are within
the Commission's authority and discretion to grant or deny should be
withheld from utilities unwilling to participate in an
RTO.150 PNGC states that the Commission should use ``big
sticks'' to obtain RTO participation, and Michigan Commission says the
Commission ``should use every stick, carrot, orange-colored stick and
tool it can.'' Some commenters assert specifically that the Commission
has the authority, and should use its authority, to condition mergers
under section 203 and condition market-based rate authority under
section 205 of the FPA on RTO participation.151 Some
commenters also favor limiting access to non-pancaked transmission
rates of RTOs to those who participate in RTOs.152
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\150\ Oneok.
\151\ E.g., Oneok, TAPS, APPA, PJM/NEPOOL Customers, Illinois
Commission, Industrial Consumers, East Texas Cooperatives, FMPA, TDU
Systems and PNGC.
\152\ E.g., TDU Systems, PNGC and PJM/NEPOOL Customers.
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Even some commenters that generally oppose the idea of an RTO
mandate acknowledge that market-based rate authority or mergers could,
on a case-by-case basis, be conditioned on RTO participation. For
example, Florida Power Corp. states that the Commission could find,
``given certain factual circumstances,'' that the granting of market-
based rate authority would not be appropriate ``unless the entity
agreed to commit its transmission facilities to an RTO.'' United
Illuminating states that whatever conditioning authority the Commission
may have for market-based rates or mergers could not be used as a basis
for a generic rulemaking.
NECPUC cites to other sections of the FPA that the Commission might
rely upon to promote RTO establishment. It supports the use of the
complaint process under section 206 of the FPA in specific cases. It
also suggests the use of FPA section 207 proceedings, which can be
initiated by state commissions, as a vehicle for requiring RTOs where
the Commission finds interstate service inadequate or insufficient.
NECPUC also urges the use of joint boards and cooperative procedures
between the Commission and the states under FPA section 209 as a means
of resolving RTO issues.
Opposing Commission's Authority to Mandate RTO Participation. At
the other end of the debate on the Commission's legal authority with
respect to RTOs are those that assert that the Commission's authority
to mandate RTOs is non-existent or very limited.153 A number
of commenters emphasize that FPA section 202(a) is explicitly voluntary
and therefore provides no support for the Commission's authority to
mandate RTOs.154 FP&L states that it is questionable whether
the Commission could use FPA section 202(a) as a tool to promote
competition, given that section 202(a) is for the ``coordination and
interconnection of facilities,'' and coordination is arguably
inconsistent with competition.
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\153\ E.g., Southern Company, Puget, Avista, CP&L, Duke, STDUG,
FirstEnergy, NYPP, Indianapolis P&L, FP&L, Detroit Edison, Florida
Power Corp., Florida Commission, Alabama Commission.
\154\ E.g., EEI, United Illuminating, Southern Company, Central
Maine, CP&L, Duke, NYPP, Florida Power Corp., Florida Commission.
---------------------------------------------------------------------------
Some argue that the exercise of FPA section 206 authority to remedy
discrimination on a generic basis by requiring RTOs would have to be
supported by more explicit findings of discrimination than are
contained in the NOPR.155 For example, Florida Power Corp.
and United Illuminating contend that the Commission cannot use an
industry-wide solution to remedy a problem that does not exist
industry-wide,156 and the record does not demonstrate an
industry-wide problem. EEI and others argue that the Commission may
only impose a remedy that is reasonable and appropriate in light of the
specific discriminatory
[[Page 839]]
findings made and the actual practices to be corrected, and the NOPR
fails to demonstrate such a nexus. Southern Company notes that the
Commission has not made any finding of discrimination and that the
``perception'' of discrimination is an insufficient basis on which to
invoke FPA sections 205 and 206. CP&L asserts that section 206 may give
the Commission some authority with respect to requiring RTOs, but only
in individual cases after hearings and substantial evidence of
discriminatory practices. Southern Company contends that the
Commission's remedial authority under section 206 must be construed in
light of the voluntary nature of section 202(a) and the Commission
cannot do anything indirectly under section 206 that it cannot do
directly under section 202(a). Central Maine asserts that
discrimination findings would not apply against a ``wires only''
company such as itself, and similarly, Indianapolis P&L argues that it
has no ability to discriminate in favor of its own wholesale generation
and therefore could not be forced to join an RTO as a remedy for
discrimination.
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\155\ E.g., EEI, Central Maine, Southern Company, Duke, NYPP,
Dalton Utilities, Indianapolis P&L, Florida Power Corp., Entergy.
\156\ Citing Associated Gas Distributors v. FERC, 824 F.2d 981
(D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988).
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Some commenters question the Commission's authority to condition
market-based rates or mergers on RTO participation. Central Maine
argues that the Commission could not conclude on a generic basis that
an RTO is needed in every market-based rate case, and that the
Commission could not change its existing policy on market-based rates
without substantial evidence and reasoned decisionmaking. CP&L states
that the Commission cannot use FPA section 205 authority to grant
market-based rates merely to advance preferred policies, and cannot use
FPA section 203 to condition mergers absent specific findings in a
particular case. Duke contends that the Commission has no authority to
issue a rule that imposes sanctions for non-participation that would
make non-participation practically or economically unfeasible.
Similarly, NYPP states that mergers, market-based rates, and access to
non-pancaked transmission rates are economic necessities, and using
them as conditions would effectively require RTO participation.
Indianapolis P&L asserts that it would be inequitable and unjustifiable
to withhold market-based rate authority from a utility that has a good
reason not to participate in an RTO, and further, that the Commission
may not pressure a utility to engage in an activity that it may not
require through direct regulation.157 Similarly, Puget
states that if the Commission is not mandating RTOs, which is beyond
its authority, then the rule must contain no penalties for non-
participation.
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\157\ Citing Altamont Gas Transmission Co., v. FERC, 92 F.3d
1239, 1246 (D.C. Cir. 1996).
---------------------------------------------------------------------------
Several commenters point to the recent court decision in Northern
States 158 as limiting the Commission's authority with
respect to RTOs.159 These parties assert that Northern
States stands for the proposition that the Commission may not directly
or indirectly interfere with state regulation of retail service, and
that the NOPR would result in traditional utility retail
responsibilities being shifted to RTOs. Specifically, for example,
Puget alleges that redispatch and planned maintenance are reliability
functions that affect the utility's ability to serve native load and
are subject to state law. Indianapolis P&L asserts that Northern States
makes clear that the Commission may act only under authority given by
Congress.
---------------------------------------------------------------------------
\158\ See Northern States, supra note 89.
\159\ E.g., Southern Company, Puget, Indianapolis P&L, FP&L,
Florida Commission.
---------------------------------------------------------------------------
A variety of other legal arguments are made in opposition to any
Commission efforts to mandate RTO participation. Southern Company
contends that since there has been no finding that Order Nos. 888 and
889 have failed, there has been no reasonable explanation as to why the
Commission should change that policy. CP&L argues that the Commission's
authority to enforce FPA section 205 is in the enforcement provisions
of FPA sections 314, 316, and 317. CP&L also states that it would be
discriminatory to have higher pancaked rates for non-participants in
RTOs while participants get the advantage of non-pancaked rates. Duke
and Florida Power Corp. assert that requiring involuntary wheeling and
imposing common carrier status is outside the Commission's
authority,160 and likewise, so is mandating RTOs. Florida
Power Corp. contends that requiring RTO participation would force a
utility to join an ISO or divest its transmission or generation assets,
and the Commission cannot compel divestiture. Florida Power Corp. and
Southern Company make the point that the Public Utility Holding Company
Act granted the SEC, not the FERC, the authority to restructure the
electric utility industry. Florida Power Corp. further argues that
requiring RTO participation would be a ``taking'' of utility property
for which just compensation would be owed, and that the ``taking''
problem is exacerbated by utilities being liable for facilities no
longer under their control. Florida Commission states that the Energy
Policy Act of 1992 indicated that the Commission should proceed with
transmission access issues case-by-case, not generically.
---------------------------------------------------------------------------
\160\ Citing Richmond Power & Light Co. v. FERC, 574 F.2d 610
(D.C. Cir. 1978) and Otter Tail Power Co. v. U.S., 410 U.S. 366
(1973).
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Other Comments On Legal Authority. DOE submitted comments strongly
supporting the Commission's efforts to establish RTOs. DOE states that
while the Commission has substantial authority to accomplish much of
what needs to be done, Federal legislation clarifying Commission
authority, especially with respect to non-jurisdictional utilities,
would greatly facilitate RTO formation.
One commenter raised the issue of what authority the Commission
would rely upon to require the filings in proposed section 35.34(c).
This commenter wants the Commission to clarify that the filings would
be required pursuant to the information gathering authority under FPA
sections 304, 307, and 311, and not under authority of section 205,
which the commenter asserts provides no such authority.161
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\161\ Consumers Energy.
---------------------------------------------------------------------------
There were only a few comments in response to the Commission's
inquiry about sections 211 and 212 or other FPA standards. Florida
Power Corp. submits that the Commission cannot rely on FPA sections 211
and 212 to mandate RTOs. Florida Power Corp. notes that in Order Nos.
888 and 888-A, the Commission recognized that it does not have the
authority to order wheeling pursuant to FPA sections 211 and 212 except
on a case-by-case basis after an evidentiary hearing resulting in
specific findings. Florida Power Corp. argues that because the
Commission is fashioning an industry-wide generic solution and not
acting on a case-by-case basis, the Commission cannot rely on sections
211 and 212 in this proceeding.
NARUC also notes that Congress revised FPA sections 211 and 212 to
provide FERC with authority to address requests for non-discriminatory
transmission service on a case-by-case basis. NARUC argues that the
goal of promoting regional flexibility is more readily served by case-
by-case consideration. In this way, NARUC believes that the Commission
can use FPA sections 211 and 212 to take a more tailored approach
rather than ``one-size-fits-all'' regulations that ignore market
development and local conditions.
Commission Conclusion. Much of the discussion in the comments on
the Commission's legal authority with
[[Page 840]]
respect to RTOs focuses on whether the Commission has the statutory
authority to mandate that transmission owners participate in an RTO. As
discussed elsewhere in this Final Rule, we have decided not to mandate
generically that all public utility transmission owners must join an
RTO. We conclude that the Commission possesses both general and
specific authorities to advance voluntary RTO formation. We also
conclude that the Commission possesses the authority to order RTO
participation on a case-by-case basis, if necessary, to remedy undue
discrimination or anticompetitive effects where supported by the
record.162 Of course, RTO participation is not the only
remedy that the Commission might employ to address these problems.
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\162\ We need not decide in this case the extent of the
Commission's authority to mandate generically RTO participation.
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FPA sections 205 and 206. As we stated in the NOPR, the Commission
is granted the authority and responsibility by FPA sections 205 and
206, 16 U.S.C. 824d and 824e, to ensure that the rates, charges,
classifications, and service of public utilities (and any rule,
regulation, practice, or contract affecting any of these) are just and
reasonable and not unduly discriminatory, and to remedy undue
discrimination in the provision of such services. In fulfilling its
responsibilities under FPA sections 205 and 206, the Commission is
required to address, and has the authority to remedy, undue
discrimination and anticompetitive effects. The Commission has a
statutory mandate under these sections to ensure that transmission in
interstate commerce and rates, contracts, and practices affecting
transmission services, do not reflect an undue preference or advantage
(or undue prejudice or disadvantage) and are just, reasonable, and not
unduly discriminatory or preferential.163 Additionally, as
discussed in Order No. 888,164 there is a substantial body
of case law that holds that the Commission's regulatory authority under
the FPA ``clearly carries with it the responsibility to consider, in
appropriate circumstances, the anticompetitive effects of regulated
aspects of interstate utility operations pursuant to [FPA] sections 202
and 203, and under like directives contained in sections 205, 206, and
207.'' 165
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\163\ Once such a finding is made, the Commission is required to
remedy it. See, e.g., Southern California Edison Company, 40 FERC
para. 61,371 at 62,151-52 (1987), order on reh'g, 50 FERC para.
61,275 at 61,873 (1990), modified sub nom., Cities of Anaheim v.
FERC, 941 F.2d 1234 (D.C. Cir. 1991); Delmarva Power and Light
Company, 24 FERC para. 61,199 at 61,466, order on reh'g, 24 FERC
para. 61,380 (1983).
\164\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,669.
\165\ Gulf States Utilities Co. v. FPC, 411 U.S. 747, 758-59,
reh'g denied, 412 U.S. 944 (1973). See City of Huntingburg v. FPC,
498 F.2d 778, 783-84 (D.C. Cir. 1974) (Commission has a duty to
consider the potential anticompetitive effects of a proposed
Interconnection Agreement.)
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There are two principal contexts in which the authority of FPA
sections 205 and 206 has been raised. One is the use of requiring
participation in RTOs as a remedy for undue discrimination by public
utilities. As discussed above, many commenters believe that the
evidence of undue discrimination is sufficient to justify generically
mandating RTO participation as a remedy, and many others argue that the
record on undue discrimination is insufficient to impose a generic,
industry-wide solution. We have concluded in our discussion elsewhere
in this Rule that continuing opportunities for undue discrimination
exist in the electric transmission industry. However, we have also
concluded that a voluntary approach to eliminating such opportunities
through RTO formation (including the filing requirements and Commission
supported collaboration efforts identified herein) represents a
measured and appropriate response to the significant undue
discrimination and other competitive impediments identified in this
record.
The other context in which our authority under FPA sections 205 and
206 is raised is whether permitting a public utility to charge market-
based rates for wholesale electricity sales can continue to be
justified if the seller or its affiliate owns or operates transmission
assets that have not been placed under the control of an RTO. The
Commission has a responsibility under FPA sections 205 and 206 to
ensure that rates for wholesale power sales are just and reasonable,
and has found that market-based rates can be just and reasonable where
the seller has no market power. The Commission has determined that to
show a lack of market power, the seller and its affiliates must not
have, or must have adequately mitigated, market power in the generation
and transmission of electric energy, and cannot erect other barriers to
entry by potential competitors.166 In the past, the
Commission has found that an open access transmission tariff mitigated
transmission market power.167
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\166\ See, e.g., Heartland Energy Services, Inc., 68 FERC para.
61,233 at 62,060 (1994); Louisville Gas & Electric Company, 62 FERC
para. 61,016 at 61,143-44 (1993) (Heartland). See also Louisiana
Energy and Power Authority v. FERC, 141 F.3d 364 (D.C. Cir. 1998)
(court upholds Commission's use of market-based rate authority).
\167\ See, e.g., Heartland, 68 FERC at 62,061, 62,063-64.
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As discussed above, some commenters believe that the Commission
should insist upon RTO participation as a condition necessary to yield
competition robust enough to support market-based rates, while others
argue that we cannot use market-based rate authority to advance
preferred policies or as a penalty. We are not adopting in this Final
Rule a generic policy that participation in an RTO is a necessary
condition to a public utility receiving, or retaining, market-based
rate authority, nor do we propose to use the denial of market-based
rate authority as a penalty for not voluntarily complying with this
Rule. However, we do have an obligation to ensure that rates for
wholesale power sales are just and reasonable, and we adhere to our
precedent that market-based rates can be just and reasonable only where
transmission market power has been mitigated and there are no other
barriers to entry.
FPA section 202(a) and PURPA section 205. Section 202(a) of the
FPA, the authority for which has been delegated to the Commission by
the Secretary of Energy,168 authorizes and directs the
Commission ``to divide the country into regional districts for the
voluntary interconnection and coordination of facilities for the
generation, transmission, and sale of electric energy.'' The purpose of
this division into regional districts is for ``assuring an abundant
supply of electric energy throughout the United States with the
greatest possible economy and with regard to the proper utilization and
conservation of natural resources.'' Section 202(a) of the FPA states
that it is ``the duty of the Commission to promote and encourage such
interconnection and coordination within each such district and between
such districts.''
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\168\ 63 FR 53889 (Oct. 7, 1998).
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Some commenters assert that FPA section 202(a) gives us broad
authority and discretion to promote RTOs to support an abundant supply
of electric energy with the greatest possible economy, while others
contend that the authority is limited by the ``voluntary'' nature of
the provision. We need not decide the precise confines of section
202(a) authority here. Clearly, this section gives the Commission the
authority, after consultation with state commissions, to establish
boundaries for regional districts for the voluntary interconnection and
coordination of
[[Page 841]]
facilities in order to assure an abundant supply of electric energy
with the greatest possible economy. We have decided in this Rule that
we will exercise this authority, at least in the first instance, by
allowing transmission owners, in consultation with other interested
parties and state commissions, to propose to us what they believe to be
appropriate regional districts. In this regard, we conclude that the
Commission, pursuant to FPA section 202(a), clearly has the authority
to direct public utilities as well as non-public utilities
169 to consider the regional coordination that would result
from joining an RTO and to participate in Commission-sanctioned RTO
discussions.
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\169\ The legislative history, as well as the Commission's past
use of section 202(a), indicates that the provision applies to both
public utilities and non-public utilities. See S. Rep. No. 621, at
49 (1935) (``public as well as private plants are included'');
Reliability and Adequacy of Electric Service, Order No. 383, 41 FPC
846,47 (1969) (information on coordination requested pursuant to
section 202(a) from public and non-public utilities).
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As we are not in this Final Rule mandating any particular
interconnection or coordination of facilities, we need not address
whether the language in FPA section 202(a) referring to ``voluntary''
interconnection and coordination limits our authority. It is clearly
the intent and requirement of this section that the Commission
encourage and promote a regional approach, which is what we are doing
in this Final Rule.
Section 205 of PURPA 170 also supports the Commission's
authority to encourage and promote regional coordination. This section,
which addresses power pooling, gives the Commission the authority to
exempt electric utilities from state laws or regulations which prohibit
or prevent voluntary coordination, and to recommend to electric
utilities to enter voluntarily into negotiations for pooling
arrangements where opportunities for conservation, efficiency, and
increased reliability exist. The Commission has previously interpreted
section 205 of PURPA as essentially complementing the functions under
section 202(a).171
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\170\ 16 U.S.C. 824a-1.
\171\ In Public Service Company of New Mexico, 25 FERC para.
61,469 at 62,038 (1983), the Commission stated that, ``Our mandate
under PURPA to promote voluntary coordination is similar to that
exercised by our predecessor, the Federal Power Commission, for more
than 40 years under Section 202(a) of the Federal Power Act.''
Accord Pacific Gas and Electric Company, 38 FERC para. 61,242 at
61,791 (1987) (PURPA ``reaffirms the Commission's authority to
promote voluntary coordination of electric utilities'').
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FPA Section 203. The Commission has the authority and
responsibility under section 203 of the FPA to review mergers and other
transactions involving public utilities, including dispositions of
jurisdictional facilities by public utilities. There are two aspects of
this authority that relate to RTO formation. First, public utilities'
transfers of control of jurisdictional transmission facilities to
entities such as RTOs would require section 203 approval. Under section
203 of the FPA, the Commission must approve a proposed disposition of
jurisdictional facilities if it is consistent with the public interest.
Second, the Commission may grant an application under section 203
upon such terms and conditions as it finds necessary to secure the
maintenance of adequate service and the coordination in the public
interest of jurisdictional facilities. FPA section 203(b) explicitly
gives the Commission authority to condition a public utility's proposed
disposition of jurisdictional assets ``upon such terms and conditions
as it finds necessary or appropriate to secure the maintenance of
adequate service and the coordination in the public interest of
facilities subject to the jurisdiction of the Commission.'' Thus, for
instance, the Commission has used section 203 conditioning authority to
require that all mergers be conditioned on the offer of comparable open
access transmission.172 In the Commission's Merger Policy
Statement, it was recognized that the development of fully competitive
generation markets is in the public interest and that turning over
control of transmission assets to an ISO might be an appropriate remedy
for anticompetitive effects of a merger.173
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\172\ El Paso Electric Company and South West Services, 68 FERC
para. 61,181 at 61,914-15 (1994), dismissed, 72 FERC para. 61,292
(1995).
\173\ Inquiry Concerning the Commission's Merger Policy Under
The Federal Power Act, 61 FR 68595 (Dec. 30, 1996), FERC Stats. &
Regs. para. 31,044 at 30,115, 30,121, 30,137 (1996).
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Some commenters urge the Commission to make RTO participation a
standardized condition to all mergers in order to mitigate increased
generation and transmission concentration, while others claim that RTO
imposition as a section 203 condition would require specific findings
in a particular case. We do not find as a generic matter in this
proceeding that no merger could be consistent with the public interest
in the absence of RTO participation. However, as noted in the Merger
Policy Statement with respect to ISOs, turning control of transmission
assets over to an RTO might be an appropriate remedy for the
anticompetitive effects of a merger. In general, our processing of
merger applications can be facilitated to the extent the merging
parties have resolved potential anticompetitive issues through means
such as RTO participation.
Other Legal Issues. Commenters have suggested other statutory
authorities that may be relevant to our efforts to encourage RTOs.
These include FPA section 207, which upon state commission complaint
authorizes the Commission to remedy inadequate or insufficient
interstate service; FPA sections 202(b) and 210, which address the
Commission's authority to order interconnections and make effective an
interconnection; FPA section 209, which authorizes the Commission to
refer matters to joint boards composed of Commission and state
representatives; and FPA sections 211 and 212, which address the
Commission's authority to require transmission services. We agree that,
under appropriate circumstances, these authorities may indeed be
relevant to RTO formation. However, we do not, and need not, rely upon
them for what we are requiring in this Final Rule, so we will not
address here what authority they might confer.
In response to those commenters who assert that the Northern States
\174\ court decision somehow limits our authority with respect to RTOs,
we disagree. As reflected in our recently issued order on remand \175\
of the Northern States court decision, that decision addresses narrow
circumstances involving transmission curtailment where the third-party
transmission customer has redispatch options. We do not interpret the
decision as limiting our authority to encourage or require RTO
participation. Moreover, we note that formation of RTOs is likely to
eliminate or significantly reduce the potential for the type of
conflict encountered in Northern States.
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\174\ See Northern States, supra note 89.
\175\ Northern States Power Co. (Minnesota) and Northern States
Power Co. (Wisconsin), 89 FERC para. 61,178 (1999).
---------------------------------------------------------------------------
With respect to the commenter seeking clarification of the
authorities we are relying upon to require the filings we are mandating
in this Rule, we clarify that we are relying upon the authorities
contained in FPA sections 202(a), 304, 307, and 309 for the filings we
are requiring under new sections 35.34(c) and (g). To the extent a
public utility proposes to participate in an RTO, we will process that
application pursuant to FPA sections 203, 205 or other sections as
appropriate.
D. Minimum Characteristics of an RTO
In the NOPR, we proposed minimum characteristics and functions for
a transmission entity to qualify as an
[[Page 842]]
RTO. These characteristics and functions are designed to ensure that
any RTO will be independent and able to provide reliable, non-
discriminatory and efficiently priced transmission service to support
competitive regional bulk power markets. In the section that follows,
we discuss the four minimum characteristics for an RTO, which are:
(1) Independence from market participants;
(2) Appropriate scope and regional configuration;
(3) Possession of operational authority for all transmission
facilities under the RTO's control; and
(4) Exclusive authority to maintain short-term reliability.
In our discussion below, we clarify and revise to some extent our
discussion in the NOPR, but we affirm these as the minimum
characteristics of an RTO.
1. Independence (Characteristic 1)
As a first required characteristic, the Commission stated that all
RTOs must be independent of market participants. To achieve
independence, we proposed that RTOs must satisfy three conditions.
First, the RTO, its employees, and any non-stakeholder directors must
not have any financial interests in any market participants.\176\
Second, the RTO must have a decision-making process that is independent
of control by any market participant or class of participants.\177\ The
NOPR defined market participant as any entity or its affiliate that
buys or sells electric energy in the RTO's region or in any neighboring
region that might be affected by the RTO's actions. We said that this
second condition would be judged on a case-by-case basis. However, the
Commission also proposed, by way of example, that an RTO could satisfy
this second condition with (a) a non-stakeholder governing board and
(b) a prohibition on market participants having more than a de minimis
(one percent) ownership interest in the RTO. Third, the RTO must have
exclusive and independent authority to file changes to its transmission
tariff with the Commission under section 205 of the FPA.\178\
---------------------------------------------------------------------------
\176\ FERC Stats. & Regs. para. 32,541 at 33,726.
\177\ Id. at 33,727.
\178\Id. at 33,729.
---------------------------------------------------------------------------
Comments. A large number of commenters address different facets of
the independence characteristic. To make the summary of comments more
manageable, we grouped the comments by key sub-issues: the basic
principle; who is a market participant; RTO economic interests in
market participants and energy markets; voting interests of one market
participant and affiliates; voting interests of classes of market
participants; passive ownership interests; RTO governing boards; role
of state agencies; and section 205 filing rights.
The Basic Independence Principle. In the NOPR, the Commission
reiterated its earlier statement that ``the principle of independence
is the bedrock upon which the ISO must be built'' and that this
standard should apply to all RTOs, whether they are ISOs, transcos or
variants of the two.\179\ Virtually all commenters agree with this
principle. For example, EEI states that ``[a] decisionmaking process
independent of the control of any market participant or class of market
participants should be an important aspect of the independence
principle.'' \180\ The TDU Systems say that ``[f]ull independence is
vitally important to the success of RTOs * * * and cannot be safely
compromised.'' \181\ The Nine Commissions urge that RTOs must be
``truly independent of market participants in word, deed and
appearance.'' \182\ Despite the almost unanimous acceptance of the
principle, there are fundamental disagreements (discussed in later
sections) among commenters as to how the principle should be
implemented, especially for RTOs that would operate as stand alone,
for-profit transcos.
---------------------------------------------------------------------------
\179\ Id. at 33,726.
\180\ EEI at 25.
\181\ TDU Systems at 41.
\182\ Nine Commissions at 8.
---------------------------------------------------------------------------
Some commenters question whether complete independence comes at too
high a cost. For example, FP&L recommends that the Commission ``not
consider independence in a vacuum.'' It contends that ``it would make
little sense to trade off the greatest degree of independence for the
highest cost structure.'' \183\ Salomon Smith Barney makes a similar
point. It contends that strict application of the independence standard
could thwart the development of for-profit RTOs. Therefore, it urges
the Commission ``not to promulgate rules that maintain absolute purity
but also throttle the * * * voluntary formation of RTOs.'' \184\
Konoglie/Ford/Fleishman, three individuals from the financial
community, express concern that independence will usually be
interpreted to mean a separation between ownership and control as
currently practiced in ISOs. They argue that, if the ISO model becomes
the norm, it could lead to higher capital costs because those who own
the transmission assets would not be able to make basic investment and
operating decisions. They point out that ownership usually imparts
control in most U.S. industries and that transmission operating and
investment efficiencies are unlikely to be achieved unless this becomes
the norm in a restructured U.S. electricity industry.
---------------------------------------------------------------------------
\183\ FP&L at 32.
\184\ Salomon Smith Barney at 5.
---------------------------------------------------------------------------
PJM and WEPCO contend that a for-profit transmission company can
never be independent because it will always be biased in its operating
and investment decisions. Specifically, they assert that a for-profit
transco will always be biased toward transmission solutions over other
solutions (such as generation redispatch) and its own transmission
assets over transmission assets owned by others. WEPCO, therefore,
concludes that independence can be achieved only if there is an ISO
operating over a for-profit transmission company.\185\
---------------------------------------------------------------------------
\185\ WEPCO at 9.
---------------------------------------------------------------------------
Other commenters argue that it would be naive to believe that
independence, by itself, will lead to an effective RTO. They argue that
an RTO may be completely independent but it must also have sufficient
operational and decisionmaking authority if it is to be effective. For
example, the TDU Systems assert that independence will not be
sufficient if transmission owners attempt to reserve certain decisions
for themselves. It points to the transco proposals of the Entergy and
the Alliance Companies as examples of a proposed RTO having
insufficient decisionmaking authority. NECPUC, representing six New
England commissions, argues that an RTO must have independent funding
and urges the Commission to include this as an explicit requirement in
the final rule. NCPA states that an RTO will not be truly independent
unless it is able to make and implement independent procurement
decisions.
Who Is a Market Participant? There is substantial disagreement
among commenters about the proposed definition of market participant.
Some commenters argue that it should be expanded; others contend that
it should be narrowed. In the first group, Illinois Commission urges us
to expand the definition of a stakeholder because ``[a] market interest
can arise through functions and activities other than just buying or
selling electricity.'' \186\ Enron/APX/Coral Power echo this point and
contend that an RTO should ``not be subject to control by, and has no
interest in the success of any vendor or buyer in the competitive
functions of the
[[Page 843]]
industry.'' \187\ Duke recommends expanding the definition to include
``any distribution company or neighboring transmission company and/or
any buyer or seller of ancillary services.'' \188\ PJM urges that the
definition of a market participant include any entity that owns
transmission facilities or provides or buys transmission service.\189\
---------------------------------------------------------------------------
\186\ Illinois Commission at 29.
\187\ Enron/APX/Coral Power at 8.
\188\ See Duke Power at 27. See also Midwest Municipals, Avista
and American Forest.
\189\ United Illuminating disagrees. It asserts that
``transmission owners without power marketing interests'' should not
be considered as market participants. United Illuminating at 37.
---------------------------------------------------------------------------
TAPS, representing an informal group of transmission dependent
utilities in 24 states, also urges us to adopt a broad definition of
market participant to ensure RTO neutrality. It argues that millions of
dollars of investments and operating costs will be affected by RTO
decisions. It gives several examples of how RTO decisions can have
major economic impacts. As a transmission planner, an RTO will have
substantial responsibility for routing new transmission lines.
Depending on its decisions, it can help or hurt one gas pipeline or
another or one generator or another. As a transmission tariff
administrator, it will have significant discretion in choosing how to
price congestion. Any decision that it makes (e.g., zonal versus nodal
pricing) could have significant impacts on the profitability of
particular generators. As the supplier of last resort for ancillary
services, it will have considerable discretion in defining the types
and quantities of ancillary services that are needed. Depending on its
decisions, some generators ``will win, and others will lose.'' \190\
Finally, as the ``transmission-request gatekeeper,'' it will have
substantial influence on who gets service and on what terms. To ensure
both the appearance and reality of neutrality in these various
decisions, TAPS urges us to adopt a broad definition of market
participant.
---------------------------------------------------------------------------
\190\ TAPS at 63.
---------------------------------------------------------------------------
In contrast, others contend that the proposed definition is too
broad. CP&L states that a literal application of the proposed
definition ``would make every single residential, commercial,
industrial and wholesale electric customer (and all of their
affiliates) market participants.'' \191\ It recommends that the
definition be narrowed by changing it to ``those entities that are
active in wholesale and non-regulated retail power markets using
transmission of the RTO.'' \192\ LPPC asks that the Commission define
the term ``affiliate'' because it is not defined anywhere in the NOPR.
It also suggests that the definition of affiliate be limited to
``common control'' rather than using the five-percent ownership
interest standard of PUHCA.\193\
---------------------------------------------------------------------------
\191\ CP&L at 23-24. American Forest believes that ``the
Commission did not intend such a broad exclusion, and seeks
clarification on this point.'' American Forest at 4.
\192\ CP&L at 23-24.
\193\ LPPC points out that the term ``affiliate'' is used in
defining market participant but is not defined anywhere in the
proposed rule.
---------------------------------------------------------------------------
A number of commenters focus specifically on the question of
whether a ``distribution only'' entity (i.e., an entity that performs
the sole function of transporting electricity at distribution voltages)
should be considered a market participant. Montana Power urges us
against expanding the definition to include an entity that operates
``distribution-only facilities.'' It argues that an RTO and a
distribution entity are both ``delivery entities'' and efficiencies can
be gained by having one entity provide ``total delivery service'' from
high to low voltages. These efficiencies of vertical integration could
include the savings that would result from having maintenance performed
on both transmission and distribution facilities by the same crews, the
sharing of shop and warehouse space and the sharing of various
administrative support functions. Sierra Pacific generally supports
this view and asserts that it does not believe that a ``transmission
owner could so operate its facilities to materially assist affiliated
transmission and distribution interests to the disadvantage of
unaffiliated entities.'' 194
---------------------------------------------------------------------------
\194\ Sierra Pacific at 17.
---------------------------------------------------------------------------
Salomon Smith Barney takes a more cautious view. It states that an
RTO owned by distribution entities ``could manipulate the grid to favor
their customers over the customers of other distributors.''
195 Trans-Elect argues that the Commission's recent attempt
to impose non-discriminatory curtailment procedures on all users of the
grid in the NSP service territory demonstrates that this problem
already exists.196 Arguing that it would be undesirable to
lose distribution entities as potential investors in RTOs, Salomon
Smith Barney recommends that the Commission require RTOs to follow
market-based priority rules in curtailment situations to reduce the
likelihood that an RTO would favor affiliated distribution entities.
---------------------------------------------------------------------------
\195\ Salomon Smith Barney at 5.
\196\ Trans-Elect at 5 citing Northern States Power Co. v. FERC,
176 F.3d 1090 (8th Cir. 1999).
---------------------------------------------------------------------------
Both Sierra Pacific and NEPCO et al. raise concerns about the
interaction of the market participant definition and ``state-mandated
backstop power supply obligations.'' NEPCO et al. asserts that all 23
states that have opted for retail competition to date have usually
imposed a default supplier obligation (which also is referred to as a
``standard offer supplier'' or a `` provider of last resort''
obligation) on one party which is usually the incumbent provider.
Sierra Pacific notes that the nature and duration of this mandated
obligation varies from state-to-state ``but at least some of the
programs are structured so that the POLR [provider of last resort] does
not compete for new customers and has no incentive to retain existing
POLR customers.'' 197 Both commenters argue that providers
of last resort should not automatically be considered as market
participants, even though they buy and sell electricity, because this
would reduce the pool of potential transco investors. Sierra Pacific
states that the Commission should ``leave the door open to consider the
POLR issue on a case-by-case basis'' and that the final regulations
should explicitly say that a provider of last resort would not be
deemed a market participant if its state mandated obligation gives it
no incentive to make such sales.198
---------------------------------------------------------------------------
\197\ Sierra Pacific at 16.
\198\ Id.
---------------------------------------------------------------------------
Finally, NEPCO et al. raises the issue of incumbent utilities that
have tried to divest themselves of their generating assets but have not
yet succeeded. It points to its difficulties in divesting its minority
ownership interests in nuclear plants. It requests that an entity not
be automatically deemed a market participant because of these minority
ownership interests especially if it has taken actions to eliminate its
control over the retained ownership interest (e.g., through a long-term
contract that would give marketing rights to a non-affiliated entity).
RTO Economic Interests in Market Participants and Energy Markets.
Many commenters, representing a wide range of industry constituencies,
agree with the NOPR's proposal that the RTO, its employees and any non-
stakeholder directors must not have any financial interests in
electricity market participants.199 Duke recommends that,
where divestment is required, the Commission should continue its past
practice of allowing employees to divest personal investments in a
manner that
[[Page 844]]
does not cause them significant financial harm.
---------------------------------------------------------------------------
\199\ One exception is Salomon Smith Barney. It argues that this
requirement is ``altogether unreasonable, in that it could require
the most qualified directors and employees to dispose of mutual
funds, pension plans and old investments whose tax base makes
disposition unreasonable.'' Salomon Smith Barney at 3.
---------------------------------------------------------------------------
Most commenters agree that the focus should be on current financial
interests.200 Several commenters point out that it would be
virtually impossible for an RTO to hire knowledgeable and experienced
employees if the Commission were to require no past financial
connections to market participants. They assert that some of the most
knowledgeable candidates for RTO positions, at least in an RTO's early
years of operation, are likely to be individuals who have retired from
companies that are market participants and it is likely that these
individuals will be receiving pensions from their former employers. In
situations like this, NASUCA urges the Commission to ``exclude from
this prohibition * * * employee pension plans and other post-employment
benefits received while a former employee of a market participant.''
201 Others urge that the Commission follow the precedent
that was established in the Midwest ISO decision.202
Individuals would not be automatically excluded from RTO employment or
directorships if their pension does not directly depend on the economic
performance of their former employers (e.g., a defined benefit pension
plan). TDU Systems suggests that reasonable exceptions should be made
``in the case of defined benefit pension plans, general mutual funds
(as opposed to utility/energy sector funds) that hold stock or bonds of
market participants, or other similar financial holdings where the
holder cannot direct specific investments or benefit directly from
stock performance.'' 203
---------------------------------------------------------------------------
\200\ With respect to future financial interests, Salomon Smith
Barney states that ``[p]rivate enterprises do not normally, control
the lives of their ex-employees.'' Salomon Smith Barney at 3.
\201\ NASUCA at 17.
\202\ See Midwest Independent System Operator, 85 FERC para.
61,250 (1998). See also Southern Company, Duke, TDU Systems and
Avista.
\203\ TDU Systems at 39.
---------------------------------------------------------------------------
In the NOPR, we asked whether there was a need to ``define the
financial independence requirement in more specific terms.''
204 The answer from almost all respondents was ``no.'' For
example, TDU Systems recommend that we issue a general rule with a set
of guidelines and then allow for its application on a case-by-case
basis. Avista agrees and states that any financial independence
standard ``require[s] case-by-case consideration as well as the common
sense application of the rule of reason.'' 205 PJM/NEPOOL
Customers states that RTOs will have the benefit of the conflict of
interest standards that have been drafted for each of the functioning
ISOs. They also recommend that the Commission commence a separate
rulemaking on this issue.
---------------------------------------------------------------------------
\204\ FERC Stats. & Regs. para. 32,541 at 33,727.
\205\ Avista at 11.
---------------------------------------------------------------------------
Some commenters contend that the NOPR's treatment of financial
independence is too narrowly drawn. For example, Dynegy argues that
while ISOs ``may ostensibly be independent of market participants--they
are not independent of the market itself.'' 206 As evidence
of this phenomenon, it points to instances when the California ISO has
tried to impose price caps on energy prices. EPSA expresses a similar
view and points to the price caps proposed by ISO New England and
approved by this Commission during the June 1999 heat wave, when energy
prices reached $1,600 a megawatt-hour, as another example of
undesirable and inappropriate intervention by a transmission provider
in energy markets. In crafting a definition of independence, EPSA urges
the Commission to require that RTOs ``should be indifferent to the
price at which the commodity they transport clears the market.''
207
---------------------------------------------------------------------------
\206\ Dynegy at 35.
\207\ EPSA Reply Comments at 12.
---------------------------------------------------------------------------
Others argue that this conflict is unavoidable as long as the
Commission imposes a requirement that RTOs be the supplier of last
resort for certain ancillary services.208 According to these
commenters, this obligation will often require that the RTO be a buyer
in certain ancillary service markets. If the supplier of last resort
obligation is also combined with a requirement that the RTO buy
efficiently, then it is inevitable that the RTO will be interested in
whether the prices are high or low (i.e., it is no longer simply a
disinterested market operator).
---------------------------------------------------------------------------
\208\ See NEMA at 19. See also EPSA Reply Comments.
---------------------------------------------------------------------------
Active (Voting) Ownership Interests in the RTO. a. By Individual
Market Participants and Their Affiliates. A number of commenters oppose
a one-percent cap on allowed voting interests of market participants in
RTOs as a necessary requirement for achieving
independence.209 EEI states that such a cap is not
``necessary, rational or supportable'' for achieving the goal of
independence.210 It recommends that the Commission allow
market participants or their affiliates to own up to ten-percent voting
interests in RTOs. EEI also asks for a clarification of whether an
ownership restriction would ``apply only to ownership in the RTO itself
or does it also apply to ownership interests in the transmission
facilities under the operational control of the RTO.'' 211
PJM, which is organized as a non-profit limited liability corporation
(LLC), asks the Commission to clarify whether its ``members'' would be
considered owners.
---------------------------------------------------------------------------
\209\ See, e.g., EEI, Duke, CP&L and PacifiCorp.
\210\ EEI notes that the NOPR mentions the one percent cap on
voting interests by market participants in the National Grid Company
in England and Wales but observes that there was no obvious
justification given at the time the decision was made.
\211\ EEI at 26.
---------------------------------------------------------------------------
CTA also argues for a higher cap. It states that the NOPR's
emphasis on ownership is misplaced. Instead, the Commission should be
concerned with the ``actual control over the day-to-day affairs of the
system, not some arbitrary percent ownership test.'' 212 The
Alliance Companies express the concern that, even though the one
percent cap appears to have been proposed as a ``safe harbor,'' it
could quickly become ``the only port of entry to Commission approval.''
213
---------------------------------------------------------------------------
\212\ CTA at 4.
\213\ Alliance Companies at 18.
---------------------------------------------------------------------------
EEI observes that other government agencies allow five or ten
percent ownership in voting shares before assuming that these ownership
interests conveyed control.214 For example, it notes that
the SEC definition of an ``affiliate'' under PUHCA is limited to
entities that own or control more than five percent of the voting stock
of a public utility. It also observes that this Commission, in
determining whether a company is an affiliate of a natural gas pipeline
or an electric utility, applies a rebuttable presumption of control
only when a utility owns ten percent or more of a company's voting
stock. Entergy states that ``there do not appear to be instances under
U.S. law where one-percent ownership is considered to give rise to a
risk of control.'' 215
---------------------------------------------------------------------------
\214\ Most investor-owned utilities agree with EEI. An exception
is Cinergy which urges the Commission to incorporate the one-percent
ownership standard in the final regulations ``exactly as proposed''
because such a prohibition ``is vital to preserving a RTO's
financial independence characteristic.'' Cinergy at 17.
\215\ Entergy at 28.
---------------------------------------------------------------------------
Several commenters question why there should be any limits on the
amount of voting shares that can be held by a market participant. For
example, Allegheny asserts that ``[t]he desire to maintain or obtain
ownership of transmission assets by market participants should not be
regarded as an evil to be avoided at all costs.'' 216 FP&L
states that there is no need to
[[Page 845]]
prohibit affiliated transcos.217 It argues that the
Commission should allow 100-percent ownership of voting equity and
ensure non-discriminatory transmission access through codes of conduct
and state commission oversight, in the case of a single state RTO. It
observes that ``in the natural gas industry there are numerous transcos
(pipelines) that are affiliated with gas producers, marketers and/or
distribution companies and there is no basis to conclude that this
structure would be less likely to succeed in the electric power
industry.'' 218
---------------------------------------------------------------------------
\216\ Allegheny Reply Comments at 10.
\217\ In contrast, APPA states that affiliated transcos should
be allowed ``only where such private companies operate under the
direct, ongoing supervision of a strong, fully functional regional
Independent System Operator.'' APPA at 28.
\218\ FP&L at 26.
---------------------------------------------------------------------------
Other commenters disagree and urge the Commission to adopt even
stricter standards on ownership than those presented in the
NOPR.219 For example, APPA recommends that the final rule
prohibit any ownership interests in RTOs by market
participants.220 APPA states that even a one-percent
ownership would represent an unjustifiable and unnecessary exception to
the independence standard. South Carolina Authority agrees with APPA
and argues that the NOPR failed to present a ``public policy benefit''
for allowing even a de minimis ownership interest.221 NASUCA
also shares this view. In addition, it asserts that as soon as the
Commission allows any ownership by market participants it will be
forced to continually track the share of each market participant,
including affiliates. NASUCA argues that this would be ``time-
consuming, difficult and expensive'' and would represent the very
antithesis of the independent, lightly regulated structure that the
Commission wished to foster.
---------------------------------------------------------------------------
\219\ See, e.g., Midwest Municipals, APPA, TDU Systems and
Industrial Consumers.
\220\ APPA clarifies that it does not oppose market participants
owning ``for-profit'' transcos if the transcos come under the
supervision of strong fully functional ISOs. Industrial Consumers
recommend that a one-percent cap should be adopted in the final rule
as a general requirement rather than as a possible safe harbor. In
addition, it recommends that the cap be calculated on a corporate-
wide basis to avoid the situation of multiple affiliates each with a
one-percent interest. See Industrial Consumers at 30.
\221\ See South Carolina Authority at 18.
---------------------------------------------------------------------------
TDU Systems concurs and observes that any ownership by market
participants will trigger the ``chasing after conduct'' regulation that
the Commission said it hoped to avoid.222
---------------------------------------------------------------------------
\222\ TDU Systems at 41 citing FERC Stats. and Regs. para.
32,541 at 31,145.
---------------------------------------------------------------------------
In addition, TDU Systems criticizes EEI's ten percent proposal. TDU
Systems asserts that EEI fails to understand the rationale for the
``safe harbor'' proposal in the NOPR. TDU Systems argues that the
regulatory purpose of a ``safe harbor'' is to ensure that ``no case-by-
case review of the regulatory agency is required.'' 223
Therefore, TDU Systems contends that it would be inappropriate to adopt
EEI's proposed ten percent because this percentage is not in the ``safe
harbor'' but, as recognized by other regulatory agencies, raises a
clear risk of control. Consumer Groups supports this view and points to
one case in which a court decided that a three-percent ownership
interest of a company's common stock was found to be ``sufficient to
assert control over the corporation because the ownership of the other
common shares was widely dispersed.'' 224
---------------------------------------------------------------------------
\223\ TDU Systems Reply Comments at 14 (italicized in the
original).
\224\ Consumer Groups Reply Comments at 8.
---------------------------------------------------------------------------
The Alliance Companies, who support a ceiling of five percent
ownership in voting interests by market participants, state that they
``are aware of no practical means of tracking who has an ownership
interest at a threshold of less than five percent `` because SEC
regulations require reporting of ownership in publicly traded companies
only at five-percent ownership and above. In contrast, Cinergy asserts
that enforcing a lower ownership limit should not be a problem. It
states that the Commission could keep track of ownership interests
``through transmission owners'' representations and subsequent audits
if the need arises.'' 225
---------------------------------------------------------------------------
\225\ Cinergy at 18.
---------------------------------------------------------------------------
APPA, which argues for absolute and total prohibition on voting
ownership by market participants, asserts that even with access to SEC
data it will be difficult for the Commission to keep track of who
really owns voting shares since they are often registered in ``street''
names. Therefore, it urges the Commission to impose a total prohibition
on ownership by market participants. South Carolina Authority agrees
and further argues that anything less would fail to achieve the
Commission's characterization of an RTO as entity in which ``the
control of transmission operation is cleanly separated from power
market participants.'' 226 It concludes that ``[t]here is
nothing `clean' about permitting incumbent transmission owners to
indefinitely maintain an ownership interest, voting or otherwise, in
the newly created RTO.'' 227
---------------------------------------------------------------------------
\226\ South Carolina Authority at 8 (quoting from FERC Stats. &
Regs. para. 32,541 at 33,718 (emphasis added by the quoter)).
\227\ South Carolina Authority at 14.
---------------------------------------------------------------------------
EPSA suggests a compromise that would allow greater flexibility
with respect to initial ownership interests. It proposes that the
Commission establish time limits on voting ownership. TDU Systems makes
a similar recommendation with respect to passive ownership. While TDU
Systems states that it would prefer an absolute prohibition on market
participants owning voting shares, it suggests that the Commission
might consider allowing transmission owners to ``hold passive, non-
voting ownership interests in excess of one percent as an extraordinary
transition measure.'' 228 However, TDU Systems recommends
that such interests be reduced to one percent or below in a
``relatively short period of time.''
---------------------------------------------------------------------------
\228\ TDU Systems at 42.
---------------------------------------------------------------------------
b. By Classes of Market Participants. SRP asserts that the NOPR is
flawed because it is not sufficient to place a limitation on the
ownership interests that can be held by a single participant and its
affiliates while ignoring the possibility that other owners may have
similar interests. SRP urges the Commission to recognize that ``[a]n
interest that may be considered de minimis, when viewed in isolation,
could still result in effective control when aggregated for a group
with common interests.'' \229\ Therefore, it recommends that limits be
placed not only on the ownership interests of an individual market
participant but also on the ownership interests by other market
participants with similar economic interests. SRP does not recommend a
specific percentage for a group cap, but Industrial Consumers urge the
Commission to cap the voting interests of any group at five percent.
---------------------------------------------------------------------------
\229\ Salt River at 11. United Illuminating agrees and states
that if the Commission ``were to adopt a higher de minimis standard,
such as five or ten percent ownership interest, it would be
relatively easy for five or six market participants owning such
percentages to control the operations of an RTO.'' United
Illuminating at 39-40.
---------------------------------------------------------------------------
FP&L contends that there is no need for ownership caps for a group
of market participants because they will often have conflicting
economic interests. It gives the example of a group of transmission
owners with ownership interests in an RTO who also own affiliated power
marketers. FP&L argues these marketing affiliates will compete against
each other and this rivalry will mitigate the potential for collusion
among the parent companies that jointly own the RTO. Alliance Companies
agree with this view. They assert that ``[i]n today's competitive power
markets, all market participants, including those traditionally
classified within the same
[[Page 846]]
stakeholder group are likely to be competitors'' and, therefore, that
it is unlikely that there will be a ``nexus of interest.'' \230\
---------------------------------------------------------------------------
\230\ Alliance Companies at 21-22.
---------------------------------------------------------------------------
EEI argues that ownership caps on groups of market participants
would be ``impractical and extremely burdensome on Commission
resources'' because the Commission would have to keep track of
ownership levels by every market participant and also align market
participants into specific groups with ``alleged common interests.''
\231\ In addition, it contends that this task would be difficult to do
because markets are evolving and the business objectives of individual
firms will change as they buy or sell assets. Moreover, while accepting
that ``some market participants may have common interests at certain
times'' EEI believes that such ``coalitions'' would be ``fragile,
short-lived and unlikely to result in a serious threat to the
independence of the RTO.'' \232\
---------------------------------------------------------------------------
\231\ EEI Reply Comments at 21.
\232\ Id.
---------------------------------------------------------------------------
A number of commenters assert that a cap on voting interests will
thwart capital formation in new and existing transmission facilities.
For example, UtiliCorp contends that such a cap ``may potentially choke
off significant sources of capital'' for the formation of for-profit
transcos.\233\ Various commenters from the financial community argue
that such a cap would make it difficult to create RTOs that function as
for-profit transcos. Salomon Smith Barney states that current owners of
transmission assets need to retain a larger ownership interest, at
least for a transition period, in order to avoid heavy capital gains
taxes. It estimates that many current transmission owners would have to
pay capital gains taxes on about 35 to 50 percent of the current book
value of their transmission assets if they were to sell these assets.
---------------------------------------------------------------------------
\233\ UtiliCorp at 7.
---------------------------------------------------------------------------
Alliance Companies asserts that restrictions on ownership would
reduce the potential pool of investors (i.e., buyers of transmission
assets) and therefore reduce the price that current owners could
receive for their assets. They contend that this would be especially
damaging because it would place limits on ownership by ``those entities
that are most likely to understand the potential value of the business
model.'' \234\ Alliance Companies states that the Commission should
allow five-percent individual ownership interests by industry
participants because this will provide confidence to other, non-energy
industry investors that the transco will be a financial success.\235\
In general, the Alliance Companies and other commenters that share this
view take the position that a one-percent cap for market participants
will be a major impediment to the creation of for-profit transcos and
that the de facto effect of such a cap will be to limit the industry to
the ISO model.
---------------------------------------------------------------------------
\234\ Alliance Companies at 19.
\235\ In contrast, APPA asserts that ``if the underlying
business model is sound, investors will come.'' APPA at 36.
---------------------------------------------------------------------------
Passive (Non-Voting) Ownership Interests in the RTO. A number of
privately-owned utilities stress that the final rule must distinguish
between passive and voting interests in RTOs.\236\ For example, while
EEI is willing to accept a ten-percent cap on ownership of voting
interests by individual market participants, it states that ``[t]here
should be no limit on the amount of passive ownership interest''
because ``[p]assive owners who lack voting rights have no ability to
control the firm.'' \237\ Enron/APX/Coral Power also support this
position. They urge the Commission to ``explicitly and unambiguously
allow incumbent utilities and other power industry participants to
possess passive but not controlling ownership interests in an RTO.''
\238\ Southern Company states that ``[p]assive ownership of
transmission facilities--even up to 100 percent--should not be a
concern.'' \239\ United Illuminating, while recommending that the
Commission allow passive ownership, recommends that we should not issue
generic rules because passive ownership is a ``complex matter that must
be reviewed on a case-by-case basis.'' \240\
---------------------------------------------------------------------------
\236\ See, e.g., EEI, Enron/APX/Coral Power and UtiliCorp.
\237\ EEI at 26. EEI relies on a legal memorandum that concludes
that passive ownership interests are ``necessarily permissible, no
matter how large and no matter what other interests they are
combined with.'' EEI Appendix H at 17.
\238\ Enron/APX/Coral Power at 14.
\239\ Southern Company at 42.
\240\ United Illuminating at 7.
---------------------------------------------------------------------------
EEI contends that some of the opposition to passive ownership by
market participants may simply reflect a misunderstanding of the
fiduciary responsibilities that the board of a for-profit transco has
to its passive owners. EEI asserts that, under Delaware law and various
model statutes, the fiduciary responsibilities of a for-profit transco
board, its managers and owners that hold voting rights to a passive
owner are limited to maximizing the value of the transmission assets
and ``not the value of any other assets that may be held by the passive
owner.'' \241\ According to EEI, a transco board has no fiduciary
obligation to take actions to produce economic benefits for other
assets such as generating units that happen to be owned by its passive
owners. Entergy states that if there are any lingering doubts about the
fiduciary obligation of the board and its voting members, a provision
could be inserted in the ``transco's limited liability agreement that
specifically directed that managers would have no fiduciary duty to
consider the private interests of members'' and that such a provision
would be enforceable under Delaware law.\242\
---------------------------------------------------------------------------
\241\ EEI at 26.
\242\ Entergy at 29.
---------------------------------------------------------------------------
Consumer Groups, however, questions the legal feasibility of this
approach. It cites to several law review articles which it argues raise
doubts as to whether fiduciary duties assigned by a state law to the
directors of a subsidiary corporation can be removed by private
agreement. It also cautions the Commission not to get lost in ``a
lawyer's duel over conflicting citations about the treatment of passive
and affiliated ownership interests'' when the fundamental issue is the
need to safeguard independence and ``avoid any appearance of
partiality.'' \243\
---------------------------------------------------------------------------
\243\ Consumer Groups Reply Comments at 9.
---------------------------------------------------------------------------
EEI points to our recent decision in Entergy Services, Inc., as
demonstrating that the Commission recognizes that passive ownership is
not inconsistent with the independence principle under the ISO
principles of Order No. 888.\244\ It asks that the Commission reach the
same policy conclusion for any similar independence requirement in the
final RTO rule. In contrast, the South Carolina Authority observes that
while the Entergy decision could be read to imply that the Commission
has ``prejudged this issue,'' the Commission should now use the
opportunity of this NOPR to take another look at the issue.\245\
---------------------------------------------------------------------------
\244\ EEI at 26 citing Entergy Services, Inc., 88 FERC para.
61,149 (1999).
\245\ South Carolina Authority at 22.
---------------------------------------------------------------------------
EEI also points to actions or policies taken by other federal
regulatory agencies that it argues support its contention that passive
ownership does not necessarily convey control. It observes that the
definitions of ``holding company,'' ``affiliate'' and ``subsidiary
company'' in PUHCA are all tied to ownership of voting rather than non-
voting shares. Similarly, EEI states that the FCC ``attribution rules''
used to determine when broadcasters and cable companies own or control
another
[[Page 847]]
broadcaster or cable company are keyed to voting rather than passive
ownership interests. According to EEI, these policies demonstrate that
other federal regulatory agencies do not believe that passive ownership
conveys control and that the Commission should adopt a similar policy.
EEI also contends that the Commission has already allowed a
``passive economic interest'' in all of the ISOs that have been
approved to date. Sierra Pacific makes a similar argument. Sierra
Pacific contends that ``profits'' made by an ISO go back to the
transmission owners even though they may have relinquished operational
and decisionmaking control. It argues that ``this arrangement [in ISOs]
is the essence of a passive ownership interest.'' \246\ The principal
difference is that ``the passive ownership interest in a Transco
involves ownership in the transco itself rather than the assets
operated by the Transco.'' \247\ However, it argues that in substance
both types of interests are the same since they allow the owner to
share in the profits derived from operating their transmission
facilities without having any influence over that operation. Sierra
Pacific concludes by urging the Commission to allow passive ownership
in both types of institutions to avoid creating ``an artificial
incentive in favor of ISOs instead of Transcos.'' \248\
---------------------------------------------------------------------------
\246\ Sierra Pacific at 11.
\247\ Id.
\248\ Sierra Pacific at 12.
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Enron/APX/Coral Power point to the example of National Grid Company
(NGC) in England and Wales as a real world example of passive ownership
of a for-profit transco by market participants. For several years after
privatization in 1990, the regional electricity companies (RECs) were
allowed to own NGC but were ``expressly barred from participating in
day-to-day management or interfering with the ability of NGC to fulfill
the purpose of privatization.'' \249\ However, in reply comments TDU
Systems contends that Enron/APX/Coral Power fails to mention that this
passive ownership arrangement was terminated after several years.
Citing to a recent interview with Callum McCarthy, Great Britain's
Director of Gas and Electricity Supply, TDU Systems points out that the
RECs were ``told to divest these interests, and did so.'' \250\
---------------------------------------------------------------------------
\249\ Enron/APX/Coral Power at 14.
\250\ TDU Systems Reply Comments at 22.
---------------------------------------------------------------------------
In contrast, TDU Systems and others ask the Commission not to allow
passive ownership in the final rule.\251\ TDU Systems say that ``the
line between passive and active ownership is often not a bright line.''
\252\ As an example, it states that in the recent Alliance transco
filing, the divesting transmission owners ``hold supposedly passive
ownership interests in the Transco, but retain the right to pass on a
number of different business transactions.'' \253\ TDU Systems assert
that if the Commission opens the door to ownership of RTOs by market
participants, it will be forced to engage in substantial ``conduct
policing.'' Salomon Smith Barney concurs and states that passive
ownership ``will prove troublesome for both the utilities and FERC''
because it creates a ``need to constantly police supposedly passive
ownership positions to make sure that they remain passive in all
respects.'' \254\
---------------------------------------------------------------------------
\251\ See, e.g., APPA, Industrial Consumers and South Carolina
Authority.
\252\ TDU Systems at 41.
\253\ Entergy at 42.
\254\ Salomon Smith Barney Reply Comments at 15.
---------------------------------------------------------------------------
South Carolina Authority echoes this point. It argues that by
allowing passive ownership the Commission would be put in the difficult
job of determining ``how `passive' a particular `passive interest'
really is.'' \255\ It urges the Commission not to compromise its
``bedrock position on independence'' because it will lead to ``an
endless series of extensive battles over ownership structure, corporate
bylaws and rules, layered on top of continuing allegations of
discrimination in the marketplace.'' \256\ It asks ``why * * * risk
compromising the independence principle?'' \257\
---------------------------------------------------------------------------
\255\ South Carolina Authority at 21.
\256\ Id. at 24.
\257\ Id.
---------------------------------------------------------------------------
Just as several commenters raise capital formation arguments in
support of the need to allow some voting interests by market
participants, many of these commenters also raise similar arguments in
support of allowing passive ownership.\258\ In general, they contend
that current owners are not likely to sell transmission assets
voluntarily to others if selling leads to a large capital gains tax
payment. They contend that passive ownership provides a creative way to
allow transfer of grid operations to an independent party while
reducing the tax burden on current transmission owners.
---------------------------------------------------------------------------
\258\ See, e.g., Entergy and Southern Company.
---------------------------------------------------------------------------
In contrast, Consumer Groups asserts that there are mechanisms
other than passive ownership that would ``permit `divestiture' without
tax consequences'' and that an important advantage of these other
mechanisms is that they would ``better assure independence.'' \259\ As
one example, Consumer Groups asserts that a vertically integrated
utility could spin off its transmission assets to its shareholders.
While recognizing that the IRS Code seems to eliminate the favorable
tax treatment if the spun-off corporation is sold within two years of
the original distribution, Consumer Groups states that this is a
rebuttable, not an absolute, prohibition and that a recent IRS proposed
rule seems to suggest that favorable tax treatment could be retained if
the spin-off of transmission assets is done in response to regulatory
mandates. South Carolina Authority raises a different argument against
regulatory policies to accommodate passive ownership. It asks why the
Commission should feel obligated to minimize the federal corporate
income tax responsibilities of privately owned utilities.
---------------------------------------------------------------------------
\259\ Consumer Groups Reply Comments at 11.
---------------------------------------------------------------------------
Several commenters recommend that we accept passive ownership at
least as a necessary transition device. For example, Enron/APX/Coral
Power state that ``there will likely need to be some years of passive
ownership by industry participants before the RTOs will have
demonstrated their viability as stand-alone transmission businesses
that can successfully be taken public.'' \260\ ISO-NE, which favors a
single grid company for all of New England, observes that because of
``tax and other considerations, current owners of transmission assets
may wish to avoid immediate divestiture, and may wish to retain
indirect ownership.'' \261\ Salomon Smith Barney predicts that most
utilities will want to dispose of passive and minority interests over
time. NECPUC, representing the six New England commissions, echoes this
point. It states that the Commission may have to accept
``[t]ransitional periods in which the ownership interests of market
participants are phased out over time.'' If such transitions are
allowed, NECPUC urges us to ensure that they are ``carefully
monitored.'' \262\ TDU Systems, as noted earlier, recommends that
passive ownership should be used only as an ``extraordinary transition
measure'' and should be allowed only for a short period of time.
---------------------------------------------------------------------------
\260\ Enron/APX/Coral Power at 14.
\261\ ISO-NE at 20.
\262\ NECPUC at 11.
---------------------------------------------------------------------------
RTO Governing Boards. Many commenters recommend that membership on
RTO governing (i.e., decisional) boards be limited to non-
stakeholders.\263\ For example, the Justice
[[Page 848]]
Department urges the Commission to consider barring all market
participants from any decision-making role. It says that this approach
assures ``a clean structural break.'' \264\ If stakeholders are allowed
on the governing board, the Justice Department recommends that
independents (i.e., non-stakeholders) should constitute a majority of
the board's voting members and that the board's voting rules not allow
vetoes by any one class of stakeholders. Most commenters who support an
independent board recommend that the maximum size of the board not be
specified in the final rule but instead be left to the discretion of
the participants. Two exceptions are the South Carolina Authority,
which recommends that board size be limited to seven to nine directors,
and the Midwest Municipals, which suggests that the Commission question
any non-stakeholder board that has more than 10 to 15 members.
---------------------------------------------------------------------------
\263\ See, e.g., Advisory Committee ISO-NE, APX, Avista, Desert
STAR, Industrial Consumers, PJM, Reliant, South Carolina Authority
and UtiliCorp. In general, these commenters adopt the convention
used in the NOPR that a non-stakeholder is synonymous with a non-
market participant. See note 187 in FERC Stats. and Regs. para.
32,541 at 33,726.
\264\ Justice Department at 4. The Southern Company states that
if the Commission requires non-stakeholders boards RTOs that are
ISOs, then it must allow transmission owners the right to establish
``performance standards'' for the RTO and the right to withdraw if
the RTO fails to meet these standards. Southern Company at 40-41.
---------------------------------------------------------------------------
Other commenters state that a danger of non-stakeholder boards,
such as those already approved by the Commission for several ISOs, is
that they become isolated and sometimes unresponsive to stakeholder
concerns. UtiliCorp, for example, asserts that ``one of the most
frequently heard criticisms of the ISOs currently in existence is their
unresponsiveness and lack of accountability.'' 265 Several
other commenters echo this concern and recommend that an independent
board be required to consult formally and informally with advisory
committees of stakeholders (i.e., a two-tier form of governance). For
example, the Midwest Municipals recommend that RTOs with non-
stakeholder boards ``be required to have a senior management or
advisory committee made up of market participants from each relevant
market sector and subordinate, issue oriented committees'' similar to
those that exist in the PJM, New York and New England
ISOs.266 STDUG recommends that if a non-stakeholder board is
formed ``it must be accompanied by some action forming mechanism that
forces the board to listen and consider the concerns of all members or
stakeholders in the RTO.'' 267
---------------------------------------------------------------------------
\265\ UtiliCorp at 11.
\266\ Midwest Municipals at 19.
\267\ STDUG at 7-8.
---------------------------------------------------------------------------
EPSA urges the Commission to pay close attention to the composition
and functions of any committee structure that operates underneath a
governing board because independent governance ``does not stop at the
ISO board.'' 268 It contends that this is necessary for
independence because advisory committees of stakeholders will often
have de facto decisionmaking power. Dynegy makes specific
recommendations for any stakeholder committees that operate below and
report to an RTO board. It recommends that such committees be governed
by ``segment voting''--each industry segment would have a proportional
vote; each market participant would have to choose to participate in
one market segment; and the votes within a segment would be split among
however many entities choose to participate in that segment. It
observes that this approach has been adopted or proposed in the PJM,
NEPOOL and New York ISOs.
---------------------------------------------------------------------------
\268\ EPSA at 15.
---------------------------------------------------------------------------
Other commenters urge us not to prohibit stakeholder or hybrid
boards consisting of stakeholders and non-stakeholders such as the one
that exists in California. Cal ISO, noting that it is the only FERC-
jurisdictional ISO with a stakeholder board, states that ``[t]he Cal-
ISO stakeholder board has worked'' and urges us to confirm the
acceptability of a stakeholder board in the final rule if the board is
structured to ensure that no market participant or class of market
participants can control the decisions of the RTO.269
Dairyland points out that the Commission has encouraged and approved
stakeholder boards under the independence principle for ISOs in Order
No. 888.270 Dynegy recommends a hybrid governing board with
``disinterested'' (i.e., non-stakeholder) members comprising one-third
of the board and stakeholder members comprising the remaining two-
thirds.271 However, it observes that mandated stakeholder
representation would be ``inappropriate'' for an RTO that is a for-
profit transco. California Board urges us to allow a variety of
governance forms including stakeholder boards ``until and unless
experience shows that one form'' is clearly superior to other forms of
governance.272 TXU Electric states that ``stakeholder
representation is a legitimate form of governance for a regional
transmission organization'' and, in fact, is the required form of
governance under the recently enacted Texas electric restructuring
statute.273
---------------------------------------------------------------------------
\269\ Cal ISO at 15. Cal ISO points out that this has been
achieved through a board of governors in which (1) no one voting
class is able to block or veto an action, and (2) no two classes
together are able to form a sufficient majority to make decisions,
and (3) no entity (including its affiliates and subsidiaries) is
able to participate in more than one voting class. See Attachment A-
1 of Cal ISO.
\270\ ``A governance structure that includes fair representation
of all types of users would help to ensure that the ISO formulates
policies, operates the system, and resolves disputes in a fair and
non-discriminatory manner.'' Order 888, FERC Stats. and Regs. para.
31,036 at 31,730-731
\271 \ Dynegy recommends that five ``segments'' for the
stakeholder representatives: transmission owners, transmission-
dependent utilities, marketers, end-users and independent power
producers. Dynegy at 42.
\272 \ California Board at 6.
\273 \ TXU Electric at 9.
---------------------------------------------------------------------------
Role of State Agencies. Commenters express a wide range of opinions
on the appropriate role of state agencies. The comments fall generally
into two categories: the role of state agencies during the
developmental stage and the role of state agencies after an RTO begins
operating.
Many commenters believe that state commissions and other state
agencies should have a major role in RTO development. NARUC argues that
state commissions ``should fully participate in RTO formation and
development.'' 274 State commissions generally take the
position that their involvement is important because the size, scope
and functions of an RTO will be critical for the success of their
state-by-state retail choice programs.275 NECPUC notes that
it had an important role in shaping the design of the ISO-NE before any
formal filing was made at the Commission. Nine Commissions,
representing state commissions from the East-Central, Midwest and
Southwest regions, gives a specific example of how the Commission
should defer to state commissions. They state that if a critical mass
of state commissions in their region reach agreement on the appropriate
boundaries for an RTO, then FERC ``should provide deference to that
collective state determination.'' 276
---------------------------------------------------------------------------
\274\ NARUC at 11.
\275\ See, e.g., Illinois Commission.
\276\ Nine Commissions at 6.
---------------------------------------------------------------------------
Other commenters outside of the state regulatory community also
address the issue of the appropriate role for state commissions. For
example, Enron/APX/Coral Power say that state regulators and
politicians should play a role in encouraging local transmission owners
to join RTOs but ``[t]he role of states * * * should extend no
further.'' 277
---------------------------------------------------------------------------
\277 Enron/APX/Coral Power at A-3.\
---------------------------------------------------------------------------
Once an RTO becomes operational, Enron/APX/Coral Power argue that
state commissions should have no special
[[Page 849]]
role and, in fact, the RTO ``should be protected from local
interference.'' Their argument for minimizing the role of state
agencies is that ``no other commercial activity (with the possible
exception of telecommunications) is more intrinsically in interstate
commerce.'' Conlon, the former President of the California Public
Utilities Commission, expresses a similar view (``local control,
although desirable from a states' rights standpoint, should be
sacrificed to get interstate control of the entire interconnection.'')
278
---------------------------------------------------------------------------
\278\ Conlon states that these are his views and are not
necessarily the views of any present or former Commissioners or
staff of the California PUC.
---------------------------------------------------------------------------
On the issue of voting rights for state commissions, Enron/APX/
Coral Power argues that it would be inappropriate for any state
commission to be a voting member of an RTO. Their rationale is that the
state commission would lose its ability to monitor the relationship
between the RTO and any entity that may be serving the state's domestic
load if it is also a voting member of the RTO board. NECPUC expresses a
similar view. While recommending that state commissions have extensive
communication with the RTO and its participants, it concludes that
state commissions ``should not have a vote in the governance of the ISO
New England.'' 279 Arizona Commission says that states
should have the right of ex officio membership but that ``FERC should
not force the states to be voting members.'' 280 ISO-NE also
shares this view. It contends that it would be ``awkward'' for a state
official to serve as a voting director of an RTO for several reasons.
First, it could create a conflict between the state official's duties
as an RTO board member and his or her regulatory or administrative
duties at the state level. ISO-NE argues that many state conflict of
interest laws may expressly prohibit such service because of the
conflicts it would create.281 Second, in the case of a
multistate RTO, it may difficult for an official from one state to vote
for decisions that are good for the residents of all the states served
by the RTO. Third, the solution of having a board member from each
state ``could create gridlock or unwieldy boards.'' 282
---------------------------------------------------------------------------
\279\ NECPUC at 9.
\280\ Arizona Commission at 5.
\281\ In contrast, Reliant recommends that ``state officials
should serve as board members in order to avoid conflicts in future
decisions.'' It appears that Reliant is referring to future
decisions of the state agencies. Reliant at 5.
\282\ ISO-NE at 3.
---------------------------------------------------------------------------
Florida Commission makes a distinction between for-profit and non-
profit RTOs. It says that it would be inappropriate for members of a
state regulatory body or other state officials to serve on the board of
a for-profit transco. However, Florida Commission believes that it may
be appropriate for a state commissioner to serve on the board of a non-
profit RTO if disputes involving the RTO and other parties do not come
before the state commission.
Washington Commission expresses a different view. In its opinion,
the role of state commissions should vary depending on the type of
board. It recommends that state involvement could be limited to the
selection of the non-affiliated board members for a non-stakeholder or
hybrid board. In contrast, if there is a stakeholder board, Washington
Commission urges that states be granted ``voting member status.'' In
the case of a for-profit transco, it urges the Commission to require a
formal advisory role for the states.
Section 205 Filing Rights. Many IOUs and public systems oppose the
NOPR's proposal to require that RTOs have ``exclusive and independent
authority to file changes to its transmission tariff with the
Commission under section 205 of the Federal Power Act.'' 283
In contrast, those who support the proposal assert that it is a
necessary and logical implication of the Commission's previously stated
policy that the ``[a]uthority to act unilaterally * * * is a crucial
element of a truly independent ISO.'' 284 SRP recommends
that ``the need for an RTO to independently administer its own tariff
must be balanced against the need for individual transmission owners to
maintain control over their ability to recover their revenue
requirements and meet their debt service obligations.'' 285
---------------------------------------------------------------------------
\283\ See, e.g., AEP, Alliance Companies, CMUA, Duke, Florida
Power Corp., LPPC, Metropolitan, Midwest Municipals, Montana-Dakota
and Southern Company.
\284\ Citing NEPOOL, 79 FERC para. 61,974 at 62,585 (1997). See,
e.g., PJM, Cal ISO, Industrial Consumers, Montana Commission, NECPUC
and NASUCA.
\285\ SRP Reply Comments at 12.
---------------------------------------------------------------------------
Those who oppose the proposal focus on the case of an RTO that is
an ISO. Transmission ISO Participants argues that the proposal is bad
law and bad policy. Citing the Supreme Court decision in United Gas
Pipe Line Co. v. Mobile Gas Service Corp.,286 it asserts
that the Commission does not have the legal authority to grant section
205 filing rights to an ISO. It contends that the FPA grants this
fundamental right to transmission owners that are public utilities.
While a transmission owner may ``voluntarily cede'' this right to an
ISO, the Commission cannot compel a transmission owner, either directly
or indirectly, to give up this legal right. Puget Sound argues that the
proposal would have the effect of reducing the transmission-owning
utility to little more than a ``bystander'' and could constitute an
illegal ``taking'' under the Fifth Amendment of the U.S. Constitution.
---------------------------------------------------------------------------
\286\ 350 U.S. 332 (1956).
---------------------------------------------------------------------------
Transmission ISO Participants also claims that the Commission's
previous decisions in this area have not been consistent. It asserts
that the Commission ``required transmission owners to cede their
section 205 rights to the ISO in our order approving the PJM ISO.''
287 But it points to the fact in a 1997 California ISO order
that the Commission seemed to establish a much smaller role for the ISO
(``the ISO is responsible for only collecting the revenue
requirement.'') 288 Furthermore, it notes that in this same
order the Commission decided to set all rate design and rate
methodology issues in the dockets established for the filings made by
the transmission owners, and not in a docket for the transmission
tariff filing made by the ISO.289
---------------------------------------------------------------------------
\287\ Transmission ISO Participants at 20.
\288\ Quoting 81 FERC para. 61,122 at 61,506 (1997).
\289\ However, the California ISO asserts that it has
``exclusive and independent'' authority ``to modify the design of
rates for transmission and ancillary services.'' See Cal ISO at 18.
---------------------------------------------------------------------------
Many commenters also address whether it would be practical to give
RTOs FPA section 205 filing rights for transmission rate design and
terms and conditions that directly affect access while transmission
owners would retain section 205 rights for overall revenue
requirements. A number of commenters say that this distinction is
unworkable because the two are inextricably connected (i.e., changes in
rate design can have major impacts on revenue
collections).290
---------------------------------------------------------------------------
\290\ See, e.g., EEI, Transmission ISO Participants and Southern
Company.
---------------------------------------------------------------------------
However, other commenters argue that the Commission cannot
realistically expect an RTO to be a neutral and unbiased transmission
provider unless the RTO has full legal authority to propose changes in
its own transmission tariff.291 PJM states that ``its
ability to function would be severely hindered'' unless it has the
ability to unilaterally make tariff filings. It points to several
recent instances of emergency filings with us as examples of why it
must have its own independent filing authority without getting the
prior approval of
[[Page 850]]
transmission owners or any other group. It argues that it will not be
able to satisfy its responsibility to ``provide for safe and reliable
operation of the transmission grid and operation of a robust,
competitive, and non-discriminatory electricity market'' without such
authority.292 However, PJM does state that transmission
owners, rather than the RTO, should have the unilateral right to seek
changes in the RTO's tariff to address changes in the transmission
owners revenue requirements with respect to transmission
facilities.293
---------------------------------------------------------------------------
\291\ See, e.g., Cal ISO, PJM ISO, Industrial Customers, Montana
Commission, NECPUC and NASUCA.
\292\ PJM at 53.
\293\ PJM at 54. The California, New York and New England ISOs
agree with PJM on this point.
---------------------------------------------------------------------------
Oneok, a power marketer, states that an RTO needs its own section
205 filing authority because it would not be able to reach a consensus
and act quickly if it must get the prior approval of all stakeholders.
However, Oneok suggests an alternative to what was proposed in the
NOPR. It recommends a two-tier approach to transmission tariff filings.
Under this proposal, ``transmission-owning utilities would be free to
file changes to their rates (or rate structures) at any time'' to their
single customer, the RTO.294 The RTO would then be free to
``repackage'' the transmission capacity and services that it purchased
under these separate transmission owner tariffs in its own RTO
transmission tariff filed under section 205. Oneok states that there
are precedents for this approach in prior Commission practices.
---------------------------------------------------------------------------
\294\ Oneok at 8.
---------------------------------------------------------------------------
Commission Conclusion. The Basic Independence Principle. In the
NOPR, we repeated our earlier statement that ``the principle of
independence is the bedrock upon which the ISO must be built ``and
emphasized that this principle must apply to all RTOs, whether they are
ISOs, transcos or variants of the two. We also stated that ``[a]n RTO
needs to be independent in both reality and perception.'' We reaffirm
both principles in the Final Rule.
In applying these principles in the context of ISOs, we have
stressed the importance of a decisionmaking process that is independent
of control by any market participant or class of participants. This, in
turn, required that we pay considerable attention to governance (e.g.,
voting shares and voting rules). Because ISOs are typically non-profit
and non-share corporations, we generally did not have to consider the
effect of ownership interests on the independence of the ISO. This will
change with the emergence of for-profit RTOs, such as transcos, that
have ownership interests. For these types of RTOs, we will have to
examine how ownership of the RTO by market participants could affect
the independence of its decisionmaking process.
Who Is a Market Participant? The overall purpose of the
independence standard in the Final Rule is to ensure that an RTO will
provide transmission service and operate the grid in a non-
discriminatory manner. Equal access requires RTOs to be independent.
Implementation of this standard then requires answering the question:
independence from whom? Our logic in the NOPR, which we have adopted in
the Final Rule, is to define a group of entities, referred to as market
participants, whose economic or commercial interests are likely to be
affected by an RTO's decisions and actions.
Commenters provided many helpful comments on the definition of
market participant that was proposed in the NOPR. As noted in the
summary, the commenters generally fall into two broad categories: those
who argue that the NOPR definition is too broad and those that argue
that it is too narrow. We find that these views were not always
inconsistent since the commenters were often discussing different
aspects of the definition. After a careful review of the comments, we
conclude that it is necessary to change the definition of a market
participant that was proposed in the NOPR. The revised definition at
section 35.34(b) is:
(2) Market participant means:
(i) Any entity that, either directly or through an affiliate,
sells or brokers electric energy, or provides transmission or
ancillary services to the Regional Transmission Organization, unless
the Commission finds that the entity does not have economic or
commercial interests that would be significantly affected by the
Regional Transmission Organization's actions or decisions; and
(ii) Any other entity that the Commission finds has economic or
commercial interests that would be significantly affected by the
Regional Transmission Organization's actions or decisions.
(3) Affiliate means the definition given in section 2(a)(11) of
the Public Utility Holding Company Act (15 U.S.C. 79b(a)(11)).
Before discussing how this definition is different from the NOPR
definition, it is useful to consider why a definition of market
participant is needed in the first place. It is the Commission's view
that an RTO must be independent of any entity whose economic or
commercial interests could be significantly affected by the RTO's
actions or decisions. Without such independence, it will be difficult
for an RTO to act in a non-discriminatory manner. Therefore, the
definition focuses on those entities whose economic and commercial
interests can be significantly affected by the RTO's behavior. However,
it should be emphasized that the definition of a market participant is
simply a starting point for implementing the independence standard. The
definition is used as a reference point for establishing limits on
ownership (i.e., an RTO's ownership of market participants and market
participants' ownership of an RTO) and standards for independent
decisionmaking or governance. As discussed below, the fact that a
particular participant is defined as a market participant does not
preclude it from having any active or passive ownership interest in an
RTO.
We agree with many commenters that the NOPR definition was too
broad in defining a market participant to be ``any entity that buys or
sells electric energy in the RTO's region or in any neighboring region
that might also be affected by the RTO's actions.'' As several
commenters pointed out, a literal reading of this definition would make
market participants of every residential, commercial, industrial and
wholesale electric customer in the RTO region and some neighboring
regions. This is clearly too encompassing and was not our intent. We
therefore are narrowing the definition of a market participant in the
Final Rule to include those who sell or broker electric energy but not
those who buy electric energy.
We recognize, however, that there may be circumstances where buyers
of electric energy could buy a controlling interest in a for-profit RTO
and manipulate its access and curtailment decisions to their advantage.
Such an outcome would clearly be inconsistent with the independence
standard. Therefore, as a backstop, we are adding paragraph (b) to the
definition (``any other entity that the Commission finds has economic
or commercial interests that would be significantly affected by the
RTO's actions or decisions''). The addition of this paragraph allows
us, on a case-by-case basis, to consider whether particular buyers of
electric energy (or any other entity) could manipulate an RTO's
decisions to the disadvantage of other RTO customers.
We are also dropping the phrase ``in the RTO's region or in any
neighboring region that might also be affected by the RTO's actions.''
Given the high degree of integration within the Eastern and Western
Interconnections, the growth of transactions involving buyers and
sellers separated by hundreds of miles and the participation of energy
concerns
[[Page 851]]
in multiple markets, we conclude that it would be virtually impossible
to apply a geographically delineated standard. However, we will
consider requests for waivers from entities in other Interconnections
who can demonstrate that their economic or commercial interests would
not be significantly affected by the RTO's actions or decisions.
We are also making one other change to the NOPR definition to
expand its scope. Paragraph (a) expands the NOPR definition by
including entities that provide transmission or ancillary services to
an RTO. We believe that it would compromise an RTO's independence if
one or more transmission owners could influence the RTO's decisions to
the detriment of other market participants. Therefore, it is
appropriate to include providers of transmission service as market
participants.295 With regard to the creation of RTOs that
are transcos, we have developed policies on the level of ownership that
market participants may possess, as discussed below, in order to ensure
that the operating decisions of the RTO are truly independent and non-
discriminatory.
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\295\ It is conceivable that RTO A might provide transmission
service to a neighboring RTO B. In such a situation, RTO A would be
considered a market participant. RTO A might also acquire ownership
interests in RTO B as a first step towards consolidation of the two
RTOs. We would anticipate granting a waiver to RTO A from a market
participant definition and any associated ownership restrictions if
we had reason to believe that the waiver could lead to a larger and
more effective RTO.
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We believe that it is necessary to include ancillary service
providers as market participants since the RTO is the supplier of last
resort for ancillary services. As a consequence, the RTO is likely to
have considerable discretion in defining the types and quantities of
ancillary services needed and how they will be procured (e.g., market
design). An RTO's decisions in any of these dimensions can have major
economic effect on one or more providers of such services. Therefore,
we define these entities as market participants to ensure that they are
not in a position to influence the RTO's decisions to their own
advantage.
Several other commenters urged us to include distribution entities
as market participants. At present, most distribution entities provide
a bundled service. The bundled service includes the sale of electric
energy as well as the delivery of this electric energy over local
distribution facilities. Since these traditional distribution entities
are selling electric energy, they would be considered market
participants under the definition.
However, several commenters pointed out that a new type of
distribution entity is likely to emerge with the spread of retail
competition. This type of distribution entity would simply transmit
electric energy over distribution facilities for others and would not
sell electricity.
The issue is whether this type of pure distribution entity should
be considered a market participant. Several commenters pointed to the
danger of allowing one or two distribution entities to control an RTO.
Their concern is that these distribution entities could use their
control over the RTO to favor their distribution facilities over the
facilities of non-affiliated distribution entities when the RTO has to
choose among competing requests for transmission service or alternative
curtailment actions. Other commenters minimize this risk and argue that
distribution entities should be allowed to own RTOs because there are
economies in having a single entity provide total delivery service
(i.e., transmit electric energy at high and low voltages). The
Commission does not wish to create impediments to the efficient
integration of transmission and distribution facilities. Therefore, we
will not include pure distribution entities in paragraph (a) of the
market participant definition. However, if we are presented with
evidence that a distribution entity is able to influence an RTO's
actions or decisions to the disadvantage of other users, we may find
such a distribution entity to be a market participant under paragraph
(b) of the definition. Paragraph (a) of the revised definition defines
all sellers of electric energy, whether retail or wholesale, as market
participants. Several commenters urge us to exclude retail providers of
last resort from the definition. These are entities that are required
by state commissions or state law to be backup suppliers to retail
customers who choose not to switch suppliers in a state-mandated retail
competition program. We have decided to include such entities in the
market participant definition because they are sellers of electric
energy. However, the obligations and responsibilities of such entities
are still being developed on a state-by-state basis. As a consequence,
even though such entities may be generically referred to as ``suppliers
of last resort,'' their responsibilities and incentives may vary
widely. The Commission believes that certain factors, (e.g., an
entity's sole electric sales are made to satisfy a state requirement
and it does not compete for retail load) would support a finding that
the entity is not a market participant.
NEPCO et al. point to the problem of incumbent utilities that have
tried to divest themselves of generating assets but have not yet
succeeded. They say that this is likely to be a particular problem for
utilities that own minority interests in nuclear plants since it is
currently difficult to sell such interests. NEPCO et al. request that
they not be automatically deemed a market participant because of these
ownership interests. Once again, we will entertain requests for
exemption. For example, we would be willing to give an exemption if the
current owner could clearly demonstrate that it has transferred to non-
affiliated entities both the marketing rights and any profits resulting
from the sale of electric energy associated with its ownership
interest. Any compensation that the market participant receives from
the non-affiliated entity should not be tied to profits on specific
sales made by this entity.
RTO Economic Interests in Market Participants and Energy Markets.
We reaffirm the NOPR proposal that the RTO, its employees and any non-
stakeholder directors must not have any financial interests in market
participants. As noted in the NOPR, our focus will be on current
financial interests. Since this principle raises a number of specific
issues, especially with respect to pension rights and benefits, we will
continue our current policy of implementing this principle on a case-
by-case basis.
Several commenters argued that the NOPR's treatment of financial
independence was too narrowly drawn. For example, Dynegy, pointing to
the example of ISOs, argues that while ISOs ``may ostensibly be
independent of market participants--they are not independent of the
market itself.'' 296 The participation of RTOs in the market
stems from certain obligations that we require of any RTO: it is the
supplier of last resort for required ancillary services and it must
attempt to procure such services efficiently in competitive markets.
These two requirements mean that most RTOs will be operators of
bilateral and spot markets in ancillary services as well as buyers in
these same markets. In addition, they will be resellers of any
ancillary services that they purchase.
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\296\ Dynegy at 35.
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It is our intention that RTOs perform functions that make the
transmission infrastructure operate efficiently, not that they take
actions in ways that skew competitive outcomes in the market.
[[Page 852]]
Nevertheless we acknowledge that RTO operations may have that effect.
Moreover, the two requirements may lead to an outcome that an RTO is
not indifferent to whether the prices are high or low. Given this
possible conflict, we will require that all RTOs must propose an
objective monitoring plan to assess whether the RTOs involvement in
these markets favors its own economic interests over those of its
customers or members.297
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297 This is discussed more fully under Market Monitoring.
See infra section III.E.6.
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Passive Ownership Interests in the RTO. As we have emphasized, the
Commission wishes to give industry participants every reasonable
opportunity to create RTOs through their own voluntary actions.
However, we also recognize that mere exhortations that the industry
participants should volunteer to create independent transmission
entities will not ensure a truly open and reliable grid in the
reasonably foreseeable future. The Commission must take actions to
ensure that the stand-alone transmission business is financially
attractive and viable. We must also provide a high degree of regulatory
certainty and not foreclose viable options for creating and developing
RTOs. To provide more certainty, the Final Rule provides guidance on
our future policies for establishing revenues, incentives and
performance-based regulation for proposed RTOs.298
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\298\ See infra section 111.G.
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We also recognize that the voluntary creation of RTOs requires that
current owners of transmission assets must be willing to transfer
operational control of these assets to RTOs or to divest their
interests in their entirety. Therefore, it is important that we provide
current transmission owners with flexibility in deciding how they will
relinquish ownership or control of their transmission facilities to an
RTO. Numerous commenters, ranging from IOUs to state commissions to
marketers, urge the Commission not to make RTO policy in a vacuum. In
particular, they stress that the Commission needs to understand that
there are many existing legal and tax disincentives to the outright
sale of such assets to an RTO.299
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\299\ See EEI, Southern Company, United Illuminating, Enron/APX/
Coral Power, ISO-NE, NECPUC, Salomon Smith Barney and Konoglie/Ford/
Fleishman.
---------------------------------------------------------------------------
Among these potential impediments, commenters identify the federal
capital gains tax most frequently. There was agreement among many
commenters that it would be unrealistic for the Commission to expect
current transmission owners to sell their transmission facilities to an
RTO if the sale becomes a taxable event that triggers a large capital
gains tax. Therefore, they urge the Commission to accommodate financing
and ownership arrangements that facilitate the creation of for-profit
RTOs while minimizing the tax burden on current transmission owners who
are willing to take actions that would promote the Commission's RTO
policies. Many commenters argue that the Commission could significantly
accelerate RTO development if we were to allow current transmission
owners to retain a passive ownership interest in new RTOs. Several
commenters contend that if the Commission fails to accommodate such
arrangements, this initiative will be unproductive because our policies
would be effectively biased against the creation of for-profit
transmission companies that seek RTO status. They assert that such an
outcome would be inconsistent with the statement in the NOPR that the
Commission wishes to encourage all types of RTOs, whether they are
transcos, ISOs or combinations of the two.300
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\300\ FERC Stats. and Regs. para. 32,541 at 33,726.
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In response to these comments, we reaffirm that it is the
Commission's policy to encourage all types of RTOs. In light of our
evolving experience with the workability of certain RTO models, it
would be inappropriate for us to mandate a single RTO model of
ownership and operation. While the dominant approach to date has been
ISOs, we are receptive to alternative approaches that can provide
evidence of the legitimacy of various models of ownership and
operation. Because the institutions which we propose to sanction
pursuant to this Final Rule will be so influential in operating the
Nation's nfrastructure over a period of time, the Commission resolves
to implement its independence criteria with an open mind and, to the
extent practicable, with flexibility. At this juncture, we therefore
propose to remove unnecessary impediments to the creation of
transmission companies by allowing market participants to maintain
passive ownership interests in RTOs.
We reaffirm our belief that ``[a]n RTO must be independent in both
reality and perception.'' 301 This same conclusion was also
reached by the DOE Reliability Task Force and the NERC Reliability
Panel, two widely respected industry groups comprised of
representatives from all sectors of the industry. The DOE Reliability
Task Force concluded that regional reliability entities must be ``truly
independent of commercial interests so that their reliability actions
are--and are seen to be--unbiased and untainted.'' The Electric
Reliability Panel concluded that ``[t]o dispel suspicions that the
system operator favors one participant over another * * * the operator
must be independent of market participants.'' 302
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\301\ As discussed below, this overriding consideration is also
relevant to active voting interests.
\302\ See U.S. Department of Energy, Maintaining Reliability in
a Competitive U.S. Electricity Industry: Final Report of the Task
Force on Electric System Reliability, at xv (September 29, 1998);
North American Reliability Council, Electric Reliability Panel,
Reliable Power: Renewing the North American Electric Reliability
Oversight System at 17 (Dec. 22, 1997)
---------------------------------------------------------------------------
The Commission concludes that an RTO will not be successful unless
all market participants believe that the RTO will operate the grid and
provide transmission service to all grid users on a non-discriminatory
basis. It is clear that the perception of a broad cross-section of
commenters is that passive ownership may interfere with the independent
operation of RTOs.303 In the view of many commenters,
passive ownership is only a subtle mechanism to allow existing
transmission owners to continue to control use of transmission assets
and ultimately deny equal access to competitors. Therefore, we must
provide assurances to all market participants that any passive
ownership interest is truly passive and will in no way interfere with
the independent operation and decisionmaking of the RTO. It is
important to require a system of independent compliance auditing to
ensure that passive ownership arrangements remain passive over time and
to provide assurances to other market participants that the RTO is
truly independent.304
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\303\ See, e.g., Consumer Groups, South Carolina Authority, TDU
Systems, Industrial Customers, APPA, Los Angeles, NASUCA, Arkansas
Cities and Wolverine Cooperative.
\304\ The auditing requirements of this Rule represent one
approach to addressing our concern that it may otherwise be
difficult to assess the ongoing independence of passive ownership
arrangements. We expect that parties will include in any rehearing
requests their views on this approach, in general, and the
particular auditing requirements that we have adopted.
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Those who support the policy of allowing market participants to
have passive ownership in RTOs point to the fact that the Commission
has accepted many instances of passive ownership in the past.
Typically, these arrangements have involved the sale and leaseback of
generating units in which a jurisdictional public utility will sell a
generating unit to a bank, insurance company or other financial
institution. The financial institution will then lease
[[Page 853]]
back the generating unit to the jurisdictional utility. Even though the
financial institution is the owner of record, we have generally
concluded that it is a passive owner without any real operational
control and, therefore, is not a jurisdictional public utility under
the FPA.305
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\305\ See Pacific Power and Light Co., 3 FERC para. 61,119
(1978); Baltimore Refuse Energy Systems Co., Wheelabrator Millbury,
Inc., 40 FERC para. 61,366 (1987).
---------------------------------------------------------------------------
There are, however, several considerations that distinguish these
earlier passive arrangements from the ones that are being contemplated
for RTOs. First, the passive ownership arrangements for RTOs (e.g.,
two-tier LLCs, synthetic leases and leveraged partnerships) may be
complicated and multi-layered. Even those commenters who urge that we
accept passive ownership as a necessary transition mechanism admit that
such arrangements ``will prove troublesome for both utilities and
FERC'' because they create the ``need to constantly police supposedly
passive ownership positions to make sure that they remain passive in
all respects.'' 306
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\306\ Salomon Smith Barney Reply Comments at 15.
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Second, unlike financial institutions, the passive owners will
typically own other assets (e.g., generating assets) that could reap
major economic benefits if an RTO's decisions can be influenced to
their advantage. Therefore, unlike financial institutions, the passive
owners in RTOs may have a direct economic incentive to influence the
RTO's operating and investment decisions to favor other economic
interests.
In response to a request for a declaratory order from Entergy
Services, Inc., the Commission found that passive ownership of a
transmission entity by a generating entity or other market participant
could meet the Commission's ISO standards relating to governance and
independence if it were properly designed. Because Entergy's proposal
was incomplete, the Commission provided some limited guidance related
to: board selection and removal, potential issues about the board's
fiduciary duties, attraction of capital and issues about the
transmission entity contracting with member companies. In this rule we
provide further guidance which we believe will help RTO applicants who
may be considering some form of passive ownership structure.
Based on these considerations, the Commission's policy on proposals
for passive ownership of RTOs by market participants will have three
key elements:
(1) Passive ownership proposals will be reviewed on a case-by-case
basis. The Commission will approve a proposal only if we are satisfied
that the passive owners have relinquished control over operational,
investment and other decisions to ensure that the RTO will treat all
users of the grid--passive owners and others--on an equal basis in all
matters. The burden of proof is on the RTO to demonstrate that control
of the RTO is ``truly independent'' and that the RTO has a
decisionmaking process that is independent of control by the passive
owners.
(2) The Commission requires any RTO with passive ownership
interests approved by the Commission to undertake an obligation and
propose processes for an independent compliance audit to ensure the
independence of its decisionmaking process from the passive owners. The
first independence audit will be required two years after initial
approval of the RTO and every three years thereafter. The independence
compliance audit must be submitted to the Commission in a public
document without any requirement for approval by the RTO
board.307
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\307\ See supra note 304.
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(3) The Commission will take appropriate action if it finds
evidence of abuses.
We will now discuss implementation of these elements. The first
element of our policy is that any RTO that wishes approval for passive
ownership above the limits set for active ownership must demonstrate in
its application that the passive owners will relinquish effective
control over operational and investment decisions. Specifically, the
RTO must demonstrate that the proposed arrangement has been designed to
ensure that it can treat all users of the grid--passive owners and
others--on an equal basis in the provision of non-discriminatory
transmission service.
It will be difficult for the Commission to make an assessment of
whether a particular passive arrangement achieves true independence in
decisionmaking for the RTO board and its management unless an RTO
provides complete information about the rights that passive owners have
reserved for themselves both as owners of the RTO and as providers of
facilities and services to the RTO. In judging any proposal, our
overriding concern is that the arrangements provide a high degree of
assurance that those who are not passive owners will have equal access
to the services provided by the RTO.
To assure ourselves that this standard is satisfied, the Commission
will need information on the following issues: fiduciary
responsibilities of the RTO board and management to passive owners;
ability of the RTO to raise capital independently of its passive
owners; ability of the RTO to make investment and financing decisions
independently of its passive owners; the extent of control by passive
owners over board selection and removal; the extent of control by
passive owners over transmission rates, terms and conditions; control
of passive owners over issuance of new membership interests and/or
equity; services that will be provided by the passive owners or their
employees to the RTO; and the extent of access of passive owners to
information not available to other market participants.308
An RTO application seeking approval for passive ownership should
provide any other relevant information that will allow the Commission
to assess whether passive owners have reserved rights for themselves
that are superior to those of other market participants and if such
rights constitute control over the RTO.309
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308 For example, this could include information on the market
behavior of one or more non-affiliate market participants acquired
through a market monitoring program and information on the RTO's
proposed investment and operational plans, except where the
Commission has approved it as necessary to protect the passive
owner's capital investment.
\309\ We note that many of these same concerns also apply to
RTOs that allow market participants to have ownership interests in
voting securities.
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The second element requires a mechanism for assuring ourselves and
market participants that any passive ownership arrangement remains
passive over time. The Commission will require the RTO to notify us
immediately of any changes in the underlying agreements or facts that
occur after the initial filing. The Commission has relied on a similar
system of self-monitoring in cases in which we have approved market-
based rates. Specifically, we have required that any public utility
that receives market-based pricing must notify us of any factual
changes that call into question whether it should be allowed to
continue to charge market-based rates.310
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\310\ When there is a change in the factual circumstances that
were the basis for the Commission's approval of market-based
pricing, we require that a public utility notify us immediately of
this change or at the next update of their market power analysis.
This update occurs once every three years. With respect to passive
ownership, we will require that the passive owner must notify us
immediately of any change in governance in ownership or governance
that takes place after our initial approval.
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We will also require a system of independent compliance auditing.
The auditing must be performed by individuals or organizations that are
not
[[Page 854]]
affiliated with the RTO or its owners. The purpose of the auditing
would be to ensure that what is passive on paper is passive in reality
throughout the transition period. In particular, auditors would assess
whether the passive owners have retained rights or privileges in their
role as owners or providers of services that would put non-owner
participants at a competitive disadvantage. The audits would cover the
RTO's actions and decisions with respect to operations and investments.
In order for this to be a credible auditing system, the auditors should
have clear authority to obtain any information or data necessary to
perform their audits and they should have the right to report any
findings and recommendations to the Commission without prior approval
of the RTO or any of its owners/members. An initial audit must be
performed two years after our approval of the passive ownership
arrangements and every three years thereafter.311 If there
is evidence of abuse or we are unable to determine if the ownership
interests continue to be passive, the Commission will not hesitate to
order appropriate remedial action, including possible termination of
passive ownership interests.
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\311\ See supra note 304.
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We understand that passive ownership arrangements are likely to
take many forms and that the Commission has not had much experience in
examining these types of arrangements in the context of RTOs. We
encourage market participants to investigate the options available for
passive ownership to identify those types of arrangements that will
provide the greatest assurance of independence. For example, we note
that the SEC's Rule 250.7(d) establishes criteria under which entities
may have ownership interests that do not trigger SEC jurisdiction under
PUHCA. The criteria under Rule 250.7(d) are that: (1) The entity owns
the facility as a company, a trustee or holder of a beneficial interest
under a trust; (2) the facility is leased under a net lease directly to
a public utility company and such facility is to be employed by the
lessee in its operations; (3) the company is otherwise primarily
engaged in business other than that of a public utility; (4) the terms
of the lease have been approved by the regulatory authority having
jurisdiction over the lessee; (5) the lease extends for an initial term
of not less than 15 years; and (6) the rent reserved under the lease
shall not include any amount based, directly or indirectly, on revenues
or income of the lessee public utility. While it is unclear whether
these exact criteria can be applied to the passive ownership
arrangements that may be involved in the formation of an RTO or whether
they would address the particular independence issues raised in this
Rule, we believe that it would be acceptable for market participants to
develop passive ownership arrangements that are purely financial. A
passive ownership arrangement that is demonstrated to be purely
financial could be relieved of the auditing requirement in this Rule.
Active Ownership Interests in the RTO. We now turn to a discussion
of active as opposed to passive ownership. Most commenters used the
term ``active'' ownership interests to refer to ownership of voting
securities that give the owner the ability to influence or control an
RTO's operating and investment decisions. We adopt this definition for
purposes of our discussion and will use the terms ``active'' and
``voting'' interchangeably.
Several commenters who were strong proponents of allowing high or
unlimited voting interests by market participants argue that in the
NOPR the Commission was wrong to focus on any particular ownership
percentage. Instead, they contend that what really matters is ``actual
control over the day to day affairs of the system, not some arbitrary
ownership percent ownership test.'' 312 We agree that the
independence of an RTO ultimately depends on who makes the
decisions.313 But control of decisionmaking ultimately
depends on who votes and how many votes each party has.
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\312\ CTA at 4.
\313\ However, independence does not automatically guarantee
that an RTO will be effective in providing non-discriminatory access
to the grid. Independence must also be combined with adequate
operational and legal authority in order for the RTO to provide non-
discriminatory access.
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Consequently, we do not think that the Commission can ignore market
participants' ownership of voting interests in the RTO.314
To do so would require us to presume that even though a market
participant has the legal right to vote for its own commercial
interests, it will choose to vote for the public interest (or the
general interests of all market participants). Therefore, we conclude
that ownership of voting interests does matter and we cannot remain
agnostic about the ownership of voting interests in an RTO by
individual market participants, their affiliates or classes of market
participants.315
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\314\ In response to EEI's request for a clarification, we
clarify that we are referring only to corporate or shareholder
ownership in the RTO itself and not to ownership of transmission
facilities under the RTO's operational control. The fact that such
facilities are owned by market participants would not be a concern
unless the owners retain legal rights and operational
responsibilities that make it difficult for an RTO to provide non-
discriminatory transmission service to other market participants.
\315\ This is not the first time that we have emphasized the
importance of voting rights. In various cases dealing with voting
shares and voting rules for ISOs, we required that proposed
arrangements be reformed to assure that no individual market
participant or class of market participants could dominate the
decisions of stakeholder committees that advised the ISO's board.
See New England Power Pool, 88 FERC para. 61,079 (1999); Central
Hudson Gas and Electric Corp., et al., 88 FERC para. 61,229 (1999).
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a. Active Ownership by Individual Market Participants and
Affiliates. A number of transmission customers argue that the cleanest
solution would be an ``absolute prohibition'' on ownership of voting
interests by any market participant 316 We agree that this
would produce a high level of certainty that an RTO is truly
independent and anything less than an absolute prohibition introduces
some risk. However, if our goal is to encourage the voluntary creation
of RTOs, we have to accept that current owners may not relinquish
ownership or control of their transmission assets unless it is in their
economic interests to do so. In order to create a viable, for-profit,
regional transco, at least some current transmission owners must be
willing to sell their transmission assets to a new transmission
company. Many commenters point out that this voluntary action is not
likely to happen if the current owners anticipate large capital gains
taxes as a consequence of the sale. The solution, according to many
commenters, is to allow current owners to retain some voting interests,
some non-voting (i.e., passive) interests or both.
---------------------------------------------------------------------------
\316\ See, e.g., APPA, Consumer Groups and South Carolina
Authority.
---------------------------------------------------------------------------
As with passive ownership, the Commission must balance two
conflicting goals: the need to assure that any RTO will be truly
independent; and of not creating disincentives for transmission owners
to voluntarily relinquish ownership or control of their transmission
assets. Against the backdrop of these two goals, the specific question
that confronts us is how much ownership of active voting interests in
RTOs should be allowed for market participants.
Several investor-owned utilities urged us to allow current
transmission owners to retain as much as 100 percent voting interest in
new for-profit transcos. They argue that we allow 100 percent ownership
combined with codes of conduct in the natural gas industry and there is
no reason why this model should not also apply to a restructured
electricity industry. We disagree with
[[Page 855]]
this recommendation. The two industries, while similar in some
respects, also differ significantly in the degree of vertical
integration. The electricity industry is starting with a much higher
level of vertical integration. As we noted in our NOPR discussion of
the complaints filed since the issuance of Order No. 888, it is
difficult to monitor compliance with codes of conduct when there is
substantial vertical integration (i.e., those who own generation and
also own transmission). 317
---------------------------------------------------------------------------
\317\ FERC Stats. and Regs. para. 32,541 at 33,704-14.
---------------------------------------------------------------------------
Moreover, it is a very intrusive form of regulation and ultimately
requires us to be ``chasing after conduct.'' If such regulation is to
be effective, we have to be concerned with internal corporate
organization and ``who spoke to whom in the company cafeteria.''
318 This is not light-handed regulation. Therefore, we see
little value in replicating this model in the new world of RTOs.
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\318\ Id. at 33,714.
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It would be equally unworkable to adopt the recommendations of some
transmission customers that we should allow no ownership of RTOs by
market participants from the outset. While this is a clean solution and
greatly reduces the need to monitor for discriminatory behavior, it
also reduces the likelihood that many current transmission owners will
voluntarily relinquish ownership or control of their transmission
facilities. As a consequence, it is likely to produce significant
delays in the creation of RTOs that can support more competitive
markets that would benefit consumers. Therefore, the Commission has
concluded that it is in the public interest to permit some ownership of
RTOs by market participants for a transition period. Within five years
of RTO approval, however, active ownership by market participants must
end unless the RTO seeks, and the Commission approves, an extension.
Any request for extension, including a request occasioned by changed
circumstances, must demonstrate that the extension is consistent with
the independence standard of this rule and is otherwise in the public
interest.
For the transition period, the Commission will establish a safe
harbor of five percent for active ownership interests by market
participants. We will allow any market participant to own up to five
percent of an RTO's outstanding voting securities without the need for
case-by-case review by the Commission. An active ownership interest at
five percent or lower will be construed as not providing the owner with
control.
The Commission will carefully evaluate, on a case-by-case basis,
proposals that involve an ownership percentage higher than five
percent. In deciding whether to allow active ownership interests that
exceed five percent, we will look at various factors including the
voting interests held by other class members (i.e., other market
participants with similar economic interests), the amount of passive
ownership held by market participants, the degree of dispersion of
voting interests among other market participants and the general
public, and the rights retained by the owners as suppliers of
facilities and services to the RTO. While there is no prohibition on
RTO proposals that involve higher ownership percentages, it would
heighten the concerns identified above and would require justification
by the applicants to overcome these concerns.
We note that other Federal regulatory agencies have chosen to use a
five percent value in similar situations. The SEC employs a five
percent value in deciding when one entity is an affiliate of another
under PUHCA.319 The SEC also requires that any person who
becomes a direct or indirect owner of more than five percent of any
class of stock of a company must file a public statement with the SEC.
In commenting on this latter requirement, the FCC observed that its
purpose is ``to ensure that investors are alerted to potential changes
in control * * * which confer on their holders the potential for
influence or control.'' 320 Less than two months ago, the
FCC established a five-percent ``voting share benchmark'' for assessing
ownership interests in companies that are cable TV operators. In
justifying its decision to stay with a five-percent value, the FCC
noted that ``[t]here is a body of more recent academic evidence that
tends to confirm our earlier conclusions, demonstrating that interest
holders of [five percent] can likely exert considerable influence on a
company's management and operational decisions.'' 321 The
FCC concluded that ``ownership percentages starting at [five] percent
can influence management polices.'' 322
---------------------------------------------------------------------------
\319\ See 15 U.S.C. 79b(a)(11).
\320\ Federal Communications Commission, In the Matter of
Implementation of the Cable Television Consumer Protection and
Competition Act 1999; Implementation of Cable Act Reform Provisions
of the Telecommunications Act of 1996; Review of the Commission's
Cable Attribution Rules, FCC LEXIS 5243, *53 (October 20, 1999)
citing Securities and Exchange Commission v. Savoy Industries, Inc.,
587 F.2d 1149 (D.C. Cir. 1978), cert. denied, 440 U.S. 913 (1979).
\321\ Id.
\322\ Id.
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We recognize that this Commission has used higher percentages in
other contexts. For example, in determining whether a company is an
affiliate of a natural gas pipeline or an electric utility, we have
applied a rebuttable presumption of control only when a utility or
pipeline owns ten percent or more of the company's voting stock. As a
general matter, since the success of RTOs will depend on both the
perception and reality of independence, the Commission believes that
caution requires us to allow only very limited voting interests by
market participants. The Commission believes that a lower percentage is
necessary in this instance because we allow other market participants
with similar economic interests (i.e., members of the same class) to
have voting interests. Therefore, we believe that it is appropriate to
impose a lower cap to reduce the risk that owners with similar outside
economic interests may create a voting bloc. If, after our initial
approval, we find evidence that control over the RTO is being exercised
by an individual market participant or a class of market participants,
we will not hesitate to take appropriate action, including ordering one
or more entities to divest their ownership interests in the RTO.
The Commission recognizes that there are risks associated with
allowing market participants to have any active ownership interests in
an RTO. Even with a five percent active ownership interest, there is a
risk that one or more market participants will be able to influence the
RTO's decisionmaking process to the disadvantage of other market
participants. Consequently, the RTO may fail to be an entity in which
``the control of transmission operation is cleanly separated from power
market participants.'' 323 Accordingly, we will require that
all market participants divest themselves of any active ownership
interests no later than five years after our approval of the RTO. We
will consider requests for extensions to this ``sunsetting''
requirement on a case-by-case basis. Any request for extension,
including a request occasioned by changed circumstances, will be
granted if the requester demonstrates that the extension is consistent
with the independence standard of this Rule and is otherwise in the
public interest. We will also require that any RTO that proposes active
ownership by a market participant must adopt a system of independent
compliance auditing to ensure that the active voting interests held by
an individual market participant or classes of market
[[Page 856]]
participants do not convey decisionmaking control.
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\323\ FERC Stats. & Regs. para. 32,541 at 33,718.
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b. Active Ownership by Classes of Market Participants. In the NOPR,
we stated that ``[a]n RTO must have a decisionmaking process that is
independent of control of any market participant or class of
participants.'' 324 While we suggested a safe harbor of one
percent ownership in voting securities by an individual market
participant and its affiliates, we did not propose any specific cap on
ownership of voting securities by a class of participants. Based on a
review of the comments received, we have concluded that a policy on
ownership by classes of market participants is necessary to ensure the
independence of the RTO. Thus, we will review RTO proposals with
respect to class ownership, considering potentially relevant factors
such as voting interests held by other market participants or classes
of market participants, the degree of passive ownership by market
participants, the degree of dispersion of voting interests, and the
rights retained by the owners as suppliers of facilities and services
to the RTO. We recognize that this is a fact-specific determination
that will require the Commission to evaluate, on a case-by-case basis,
proposals that involve ownership by more than one market participant.
We will adopt a benchmark of 15 percent class ownership. Our
willingness to allow ownership by a class of participants that exceeds
fifteen percent will depend on the particular circumstances of the
filing (e.g., the presence of offsetting voting interests by another
class of market participants with competing economic or commercial
interests or proposals to sunset active ownership).325
Moreover, intervenors may also advance arguments that a 15 percent
class ownership is inappropriate under certain factual circumstances.
---------------------------------------------------------------------------
\324\ Id. at 33,727.
\325\ See Alliance Companies, supra note 48.
---------------------------------------------------------------------------
Comments on this issue reflect widely divergent views. SRP
criticizes the NOPR for failing to recognize that ``[a]n interest may
be considered de minimis when viewed in isolation, could still result
in effective control when aggregated for a group with common
interests.'' SRP contends that while the Commission explicitly
recognized the importance of classes in the NOPR, we failed to do
anything about it. In contrast, FP&L and others argue that there is no
need for any ownership caps for a group of market participants since
they will often have conflicting interests. EEI echoes this point by
observing that any ``coalitions'' are likely to be ``fragile, short-
lived and unlikely to result in a serious threat to the independence of
the RTO.'' 326 It also contends that it will be difficult to
keep track of ownership interests and to categorize market participants
into specific groups with ``alleged common interests.'' Therefore,
while EEI proposes a ten-percent cap on ownership interests in voting
securities by individual market participants, it recommends that there
be no cap on the ownership interests of any group of participants.
---------------------------------------------------------------------------
\326\ EEI Reply Comments at 21.
---------------------------------------------------------------------------
In several ISO orders, we rejected proposed governance arrangements
because we concluded that the voting weights and rules given to classes
or sectors of participants would allow transmission owners to dominate
the decisionmaking process.327 We believe that the concerns
that motivated these orders also hold true with respect to ownership of
RTOs. It would make little sense to establish a policy on ownership by
individual market participants and their affiliates while allowing five
or six generators or marketers to group together to force an RTO to
adopt a policy that favors their interests.
---------------------------------------------------------------------------
\327\ See New England Power Pool, 88 FERC para. 61,079 (1999);
Central Hudson Gas and Electric Corp., et al., 88 FERC para. 61,229
(1999).
---------------------------------------------------------------------------
The Commission is unpersuaded by the assertions that similarly
situated market participants will not have a ``nexus of interests.''
While we recognize, for example, that individual generators may
actively compete against each other for specific sales, this does not
imply that there is a total absence of common economic interests among
generators relative to marketers or distributors. If we were to accept
this argument, it would require us to ignore the fact that the
Commission routinely receives joint pleadings from non-affiliated
parties with similar economic interests. Similarly, over the last two
years, we have frequently observed various non-affiliated entities
within ISOs voting as a bloc on issues where they have similar economic
interests (e.g., existing generators voting against new generators who
seek lower interconnection charges when they connect to the grid).
There is a second reason why we believe it is necessary to review
class or sector ownership of voting securities in RTOs. With ISOs, we
have allowed sector or class representation on the advisory and
technical committees that are charged with giving advice or making
recommendations to non-stakeholder governing boards. We have accepted
these arrangements even though the votes of some classes exceed 20
percent because all other classes are represented and have roughly
equal voting power. Thus, independence is achieved through a diffusion
of voting power among all the affected classes. While this arrangement
may work for ISOs that are typically non-profit and non-share
corporations, we do not think it is viable option for RTOs that have
ownership shares that must be purchased. In particular, we cannot
assume that all affected classes of market participants will have the
financial resources to purchase ownership interests that would
guarantee them a vote at the table. Therefore, we cannot presume that
there will be a balance of voting power as was the case for the ISOs.
In the absence of such countervailing voting blocs, we believe that it
is necessary to establish lower limits on the amount of voting shares
that can be owned by members of any one class of market participants.
Based on our experience to date, we do not think it is impractical
to define classes of market participants with similar economic
interests. This has been routinely done as part of the governance
design in every one of the ISOs that we have approved. The Commission
will not establish categories of classes in this Final Rule. Instead,
we will allow each RTO to propose the classes that it believes are
relevant to its region. However, we are inclined to define such classes
broadly to avoid bypassing the class cap through narrowly defined
classes.
In addition, we will require independent compliance auditing to
ensure that market participants that have ownership interests will not
use these ownership interests to put other non-owner market
participants at a competitive disadvantage.328
---------------------------------------------------------------------------
\328\ See supra note 304.
---------------------------------------------------------------------------
The auditing should be performed by individuals or organizations
that are not affiliated with the owners or RTO. The auditors would have
clear authority to obtain any information or data necessary to perform
their audits, and they would have the right to report any findings and
recommendations to the Commission without prior approval of the RTO or
any of its owners/members. An initial audit should be performed two
years after our approval of the RTO. This will be the only audit
required for active ownership unless the RTO or the active owners
request and receive approval for an extension of active ownership
interests beyond five years. If such an extension is granted, then
follow-up compliance audits must be performed at three year intervals,
[[Page 857]]
beginning with a three-year audit filed along with any request for
extension.
As we discussed above with respect to passive ownership, applicants
will have a continuing obligation to inform the Commission of any
changed circumstances regarding active ownership. Moreover, the
Commission would expect auditing for compliance with the individual and
class caps established at the time of RTO approval. Where feasible, the
auditors would rely on publicly available information on ownership
interests (e.g., SEC data sources). Where such information is not
publicly available (e.g., individual ownership interests of less than
five percent), the auditors should have the authority to obtain this
information from market participants and their affiliates. Any market
participant that wishes to have an ownership interest in an RTO must
agree to provide this information to the auditor or the Commission upon
request. We would expect that market participants will comply with both
the individual and class caps at all times. If the auditor finds that
either cap has been violated, it must notify the Commission and the
affected owners immediately and also recommend a remedy.
Since the caps do not guarantee a lack of control, the Commission
expects that the auditors will also look for evidence of control over
RTO decisionmaking at lower levels of ownership. These audit reports
would be closely reviewed by the Commission and if there is evidence of
abuse or unwillingness to cooperate with the auditors, the Commission
will not hesitate to order owners to divest themselves of their active
ownership interests.
RTO Governing Boards. Many commenters urge us to impose specific,
detailed requirements on RTO governance. Commenters make
recommendations on many different aspects of governance: the
desirability of stakeholder, non-stakeholder or hybrid boards, the size
of boards, the relationship between non-stakeholder boards and
stakeholder advisory groups, the number of classes for stakeholder
boards, the appropriate voting entitlements for individual classes on a
stakeholder board; and optimal voting rules. Most of the
recommendations seemed to be targeted for RTOs that are ISOs. In the
Final Rule, we have decided not to impose any specific requirements on
RTO governing boards other than the general requirement that they must
satisfy the overall principle that their decisionmaking process should
be independent of any market participant or class of participants. We
have opted not to impose more detailed governance requirements for
three reasons.
First, we anticipate that RTOs will take many different forms that
reflect the needs and different starting points of each region. We
expect to see proposals from ISOs, transcos and hybrids. It is unlikely
that a single approach to governance will work for the different types
of RTOs that are likely to emerge. At this early stage, it would be
counterproductive to impose a ``one size fits all'' approach to
governance when RTOs may differ significantly in structure and patterns
of ownership.
Second, our experience to date has been largely limited to
reviewing governance proposals of ISOs that operate but do not own
transmission facilities. A governance model that works for an ISO may
not be appropriate for transcos or other types of for-profit
transmission enterprises.
Third, even among the ISOs, there are different models of
governance. As we noted in the NOPR, the dominant governance model
(PJM, New England, New York and the Midwest) for ISOs is a two-tier
form of governance. The top tier consists of a non-stakeholder board,
while the lower tier consists of advisory committees of stakeholders
that may recommend options to the non-stakeholder board. Generally, the
top tier has the final decisionmaking authority.329 In
contrast, California, employs a decisionmaking board for its ISO that
consists of both stakeholders and non-stakeholders representatives. And
we note that the recently passed Texas restructuring law would require
a pure stakeholder governing board for the ERCOT ISO. Given the variety
of governance forms that exist or are proposed for ISOs and the limited
experience with these different approaches, the Commission believes
that it is premature to conclude that one form of governance is clearly
superior to all other forms in every situation.
---------------------------------------------------------------------------
\329\ One exception is the New York ISO where decisionmaking is
explicitly shared by a non-stakeholder Board of Directors and
stakeholder Management Committee. Modification of the ISO tariffs
under the FPA requires approval of the ISO Board and the Management
Committee. If they fail to agree on a modification, either the Board
or the Management Committee may make a filing under FPA section 206.
See Central Hudson Gas & Electric Corp., et al., 88 FERC para.
61,138 (1999).
---------------------------------------------------------------------------
Therefore, we will not mandate detailed governance requirements for
RTO boards. Instead, the approach that we adopt in the Final Rule is
that any RTO governance proposals, whether from an ISO, transco or a
hybrid arrangement, will be judged on a case-by-case basis against the
overarching standard that its decisionmaking process must be
independent of individual market participants and classes of market
participants.330
---------------------------------------------------------------------------
\330\ We will require every ISO to submit an audit of the
independence of its governance process two years after its approval
as an RTO.
---------------------------------------------------------------------------
While we are not imposing any other specific requirements, the
Commission believes that it is appropriate to give some general
guidance based on the governance arrangements that we have reviewed to
date. Where there is a governing board with classes of market
participants, we would expect that no one class would be allowed to
veto a decision reached by the rest of the board and that no two
classes could force through a decision that is opposed by the rest of
the board. Where there is a non-stakeholder board, we believe that it
is important that this board not become isolated. Both formal and
informal mechanisms must exist to ensure that stakeholders can convey
their concerns to the non-stakeholder board. Where there are
stakeholder committees that advise or share authority with a non-
stakeholder board, it is important that there be balanced
representation on the stakeholder committees so no one class dominates
its recommendations or its decisions.
We note that this general guidance is based on our experience with
governance proposals of ISOs. The Commission recognizes that these
observations may not be completely relevant for an RTO that intends to
operate as a for-profit transmission company. Nevertheless, we
emphasize that the common element for all types of RTOs must be that
they satisfy the threshold principle that their decisionmaking should
be independent of market participants.
Role of State Agencies. We do not impose any specific requirements
on the role of state agencies in RTOs. Such specificity would be
counterproductive in light of the variation in the legal
responsibilities of state commissions and RTO design across regions.
However, we agree with NARUC that state commissions ``should fully
participate in RTO formation and development.'' When we undertake our
collaborative efforts with the industry after issuance of the Final
Rule, we encourage state commissions and other state agencies to play a
key role in this effort. State involvement is important for several
reasons, especially where RTOs are a critical element of the retail
choice programs of many states. State commissions are in a unique
position to assess whether a particular RTO design will help or hinder
their efforts to promote retail competition.
[[Page 858]]
Once an RTO becomes operational, it appears that most states
believe that it would be inappropriate for a state official, whether a
state commission representative or some other state employee, to serve
as a voting member of an RTO board. We note that NECPUC, representing
the six New England state commissions, was joined by most other state
commissions and commenters from other sectors of the industry in
recommending that state officials should not be voting members of any
RTO governing body. ISO-NE presents three reasons why it would be
problematic for a state official to serve as a voting member of an RTO
governing board. First, it would create a conflict between the state
official's duties as an RTO board member and his or her regulatory or
legal responsibilities at the state level. Second, in the case of a
multi-state RTO, it would be difficult for an official of one state to
represent the interests of others states if the state interests are in
conflict. Third, the solution of allowing each state to have its own
voting member on the RTO board could lead to large and unwieldy boards
for multi-state RTOs.
While most commenters agreed that state officials should not serve
as voting members of RTO boards, most of these same commenters were
comfortable with allowing state officials to serve as ex officio
members. It was thought that state officials would be better informed
in making their own decisions if they could closely observe the
considerations and constraints that were weighed by the RTO in making
its decisions. It was thought that the ability of state officials to
observe the RTO's decisionmaking process would be especially useful if
the RTO had to recommend one or more expansions to the existing grid.
While we see considerable merit in the arguments that state
officials should not be voting members of an RTO governing board (and
note that most state commissions share this view), the Commission is
not imposing such a prohibition. Since RTOs do not yet exist, it would
be premature to conclude that state officials should not participate as
voting members of RTO boards. There may be special circumstances in
some regions that would make it in the public interest to give voting
rights to one or more state government representatives. Therefore, we
will be willing to entertain such proposals and perhaps revisit the
issue after we gain more experience.
Section 205 Filing Rights. In the NOPR, we proposed that the RTO
must have exclusive and independent authority to file changes in its
transmission tariff under section 205 of the Federal Power Act. This
proposal triggered hundreds of pages of comments. Upon consideration of
the comments received, as discussed below, we will modify our proposal,
in part, to make clear that transmission owners who do not also operate
their transmission facilities retain certain section 205 rights.
Most commenters on this issue fall into two categories. Those who
oppose the proposal in the NOPR argue that it is bad law and bad
policy. They contend that the Commission does not have the legal
authority to grant section 205 rights over their transmission
facilities to some other entity. While a transmission owner may
voluntarily cede this right to an RTO, they argue that the Commission
cannot compel a transmission owner, either directly or indirectly, to
give up this legal right. Many transmission owners, representing IOUs,
public and cooperative systems, argue that the transfer of this right
to an RTO would increase their risk of recovering revenues to which
they are lawfully entitled. On the other hand, those who support the
proposal argue that it is a necessary and logical implication of our
previously stated policy that the ``[a]uthority to act unilaterally * *
* is a crucial element of a truly independent transmission provider.''
331 They contend that an RTO will not be able to function as
an independent and neutral transmission provider if it has to seek the
approval of transmission owners or other market participants every time
it wishes to modify its tariff. They point to numerous tariff changes
that the various ISOs have had to make as real world evidence of their
need to move quickly and make filings at the Commission when they
encounter a tariff problem that needs to be corrected.
---------------------------------------------------------------------------
\331\ New England Power Pool, 70 FERC para. 61,374 at 62,585
(1997).
---------------------------------------------------------------------------
Based on the comments received, we reaffirm our determination that
RTOs, in order to ensure their independence from market participants,
must have the independent and exclusive right to make section 205
filings that apply to the rates, terms and conditions of transmission
services over the facilities operated by the RTO. This determination,
however, is subject to several important clarifications discussed
below.
We recognize that for some RTOs (in particular, ISOs), both the
transmission owners and the RTO will be public utilities with respect
to the same transmission facilities,332 i.e., one or more
entities will own the facilities and a different entity will operate
the facilities and actually sell the transmission provided by the
facilities, and that this presents a somewhat unusual situation insofar
as sections 205 and 206 of the FPA are concerned. The FPA does not
explicitly address who has filing authority or responsibility in this
circumstance. We conclude that while the RTO must have independent and
exclusive authority to propose changes in the rates, terms and
conditions of transmission service provided over the facilities it
operates, it also is reasonable for the transmission owners to retain
certain independent section 205 filing rights with respect to the level
of the revenue requirement that the transmission owners receive from
the RTO and that the RTO, in turn, will collect from the transmission
customers through its rates. We therefore clarify that a transmission
owner must have independent authority to set the level of its portion
of the revenue requirement to be collected by the RTO.333
---------------------------------------------------------------------------
\332\ Under FPA section 201(e), a public utility is any person
who owns or operates jurisdictional facilities.
\333\ Of course, a transmission owner may voluntarily agree to
relinquish this right during the RTO negotiation process or
subsequently.
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Importantly, we further clarify that we expect the authorities of
the transmission owners and the RTO to be exercised as follows. The
transmission owners may make section 205 filings to establish the
payments that the RTO will make to the transmission owners for the use
of the transmission facilities that are under the control of the RTO;
the RTO, in turn, will make section 205 filings to recover from
transmission customers the cost of the payments it makes to
transmission owners as well as its own costs, and propose any other
changes in the rates, terms and conditions of service to transmission
customers. Thus, the transmission owners may have on file a tariff that
assures their recovery of transmission revenues from the RTO and, while
they may be affecting the level of the RTO's revenue requirement, they
will not be permitted to make section 205 filings for RTO services to
transmission customers and will not interfere with the independence of
the RTO to file proposed changes to the open access
tariff.334
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\334\ We note that some existing ISOs have adopted an approach
where the transmission owners' revenue requirement is filed with the
Commission in a separate transmission rate filing (e.g., California
ISO), while others incorporate the revenue requirement of the
transmission owners, as changed from time to time, in the ISO's
tariff. In either case, only the ISO is authorized to make filings
that change the tariff sheets in the ISO's tariff.
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[[Page 859]]
We believe this division of filing rights reflects a reasonable
interpretation of the FPA as applied to these circumstances, and that
it appropriately balances the need to ensure the independence of the
RTO with the need to provide transmission owners the opportunity to
recover revenues. To avoid unnecessary disputes and coordinate the
interaction of these independent section 205 filings, we will require
the RTO and the transmission owners to give prior notice to each other
of any planned section 205 filings. Further, we strongly encourage
transmission owners and RTOs to resolve rate issues prior to the filing
of proposed rate changes.
We recognize that the division of filing rights described above may
not be the only way to accommodate the concerns raised. Accordingly,
the Commission will entertain other approaches as long as they ensure
the independent authority of the RTO to seek changes in rates, terms or
conditions of transmission service and the ability of transmission
owners to protect the level of the revenue needed to recover the costs
of their transmission facilities. The Commission will require RTOs to
provide a detailed description of the process to allow us to assess its
fairness and workability.
2. Scope and Regional Configuration (Characteristic 2)
The NOPR proposed as the second minimum characteristic of an RTO
that the RTO must serve an appropriate region--a region of sufficient
scope and configuration to permit the RTO to effectively perform its
required functions and to support efficient and nondiscriminatory power
markets.353 The NOPR noted that there is likely no one
``right'' configuration of regions and proposed to establish a set of
factors that encourage appropriate regional configuration without
prescribing boundaries. The NOPR suggested that a region that is large
in scope would facilitate the effective performance of many of the
RTO's functions, but also recognized that there may be factors that
might limit how large an RTO should be.336 The NOPR also
proposed a set of factors that may affect the location of regional
boundaries. These factors indicate that boundaries should facilitate
essential RTO functions and goals, recognize trading patterns, mitigate
the exercise of market power, do not unnecessarily split existing
control areas or existing regional transmission entities, encompass
contiguous geographic areas and highly interconnected portions of the
grid, and take into account useful existing regional boundaries (such
as NERC regions) and international boundaries. The NOPR put forth for
discussion the appropriateness of existing configurations, such as the
three electric interconnections within the continental United States,
the ten NERC reliability councils, and the 23 NERC security coordinator
areas.
---------------------------------------------------------------------------
\335\ FERC Stats. and Regs. at 33,729.
\336\ Id. at 33,730.
---------------------------------------------------------------------------
The NOPR also requested comments on what portion of the
transmission facilities within an appropriate region the RTO must
control in order to be approved as an RTO. The Commission recognized
that it might be difficult to obtain 100 percent participation of all
transmission owners within a region, but that, on the other hand, it
would not be appropriate to approve an RTO proposal that included only
a small portion of the facilities of the region. The Commission also
requested comments on how much deference the Commission should give to
regions proposed to us, and to what extent state commission approval or
disapproval should be taken into account.
a. How Should Initial Boundaries be Established? Comments. Most
commenters agree with the Commission's proposal not to initially
prescribe the boundaries for appropriate regions.337 Among
the rationales asserted by these commenters is that this is a matter
best left in the first instance to the stakeholders in the various
regions,338 there should be deference to proposals by
transmission owners and market participants,339 FERC should
give deference to state commissions on scope and
configuration,340 boundaries should be determined naturally
in a way that facilitates market transactions,341 and size
and configuration must be determined on a case-by-case
basis.342
---------------------------------------------------------------------------
\337\ See, e.g., South Carolina Authority, Cleco, SRP, LG&E,
Detroit Edison, Wyoming Commission, Entergy, UtiliCorp, NECPUC,
MidAmerican, Enron/APX/Coral Power, Duke, NASUCA, Industrial
Consumers, Connectiv, Massachusetts Division, Iowa Board.
\338\See, e.g., South Carolina Authority, NASUCA, Florida Power
Corp.
\339\ See, e.g., Entergy, MidAmerican.
\340\ See, e.g., Southern Company, NECPUC, Nine Commissions,
Florida Commission.
\341\ See, e.g., Duke, FirstEnergy, Allegheny, Iowa Board.
\342\ See, e.g., NYPP.
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However, some commenters argue that the Commission should prescribe
regional boundaries. APPA, East Texas Cooperatives, TDU Systems and the
Michigan Commission urge that the Commission use section 202(a)
authority to establish initial boundaries. APPA asserts that the
Commission should establish a rebuttable presumption in favor of
specific regional district boundaries based on the topology of the
transmission network to enhance system security. East Texas
Cooperatives argues that after the Commission established regional
districts, the burden would be on those proposing different regions to
show that they provide at least the benefits of the prescribed
districts. Michigan Commission states that the electricity market is
currently too immature to determine by itself the size of the markets,
and that firm guidance is needed rather than allowing the RTO
boundaries to be set by participants.
Several other commenters do not go as far in asserting that the
Commission should initially set boundaries, but argue that the
Commission should take a strong role in assuring proper boundaries. For
example, Cinergy urges that the Commission be aggressive in
establishing boundaries consistent with the proposed criteria, noting
that the willingness of the Commission to exercise its authority over
boundaries will determine the success of the Commission's restructuring
efforts. Coalition of Alliance Users maintains that the Commission
should take a direct and active role in formulating RTO boundaries.
WEPCO believes that the role of the Commission should be to set
criteria that encourage the establishment of sensible RTO boundaries.
Project Groups assert that if the stakeholders in a region do not
determine boundaries by the end of 2000, the Commission should make the
determinations. LG&E states that while the Commission should show
deference to voluntary RTOs, it should not hesitate to disapprove
proposals with geographic shortcomings.
Commenters express a variety of views regarding whether particular
regional configurations would be appropriate. Some commenters support
interconnection-wide RTOs as a desirable goal,343 while
others regard either an Eastern or Western interconnection RTO as
unworkably large. 344
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\343\ See, e.g., South Carolina Authority, Conlon, Industrial
Consumers, First Rochdale, Los Angeles, PG&E, Sonat.
\344\ See, e.g., South Carolina Authority, Desert STAR,
MidAmerican, TDU Systems, CREDA, SNWA, CRC, Platte River, PSNM, SRP,
Metropolitan.
---------------------------------------------------------------------------
Commenters offer specific ideas about the number and placement of
RTOs. PG&E states that the long-term goal should be four or five RTOs
nationwide.
[[Page 860]]
Williams argues for 3 to 10 RTO nationwide, while Project Groups
advocates 3 to 12 RTO nationwide. WEPCO proposes the formation of five
RTOs: (1) three in the Eastern interconnection (one covering MAPP,
MAIN, ECAR and portions of SPP; one covering SERC, Florida and the rest
of SPP; and one covering NPCC and MAAC); (2) one for WSCC; and (3) one
for ERCOT. APPA, supported by East Texas Cooperatives, suggests: (1) no
more than three RTOs in the West; (2) the combination of PJM, NY ISO
and ISO-NE into one RTO with the possible participation of Ontario; (3)
the combination of the Alliance RTO, Midwest ISO, and MAPP into one
RTO; (4) Kansas to the Carolinas under one RTO; and (5) separate RTOs
for Florida, ERCOT and Hydro-Quebec.
With respect to specific regions, ISO-NE contends that it already
operates a region of appropriate size and configuration. Mass Companies
agrees that ISO-NE is an appropriate region. NYC argues that the
formation of a northeastern RTO with a broader geographic scope than
the NY ISO would help remove existing institutional impediments to the
construction of new transmission lines. American Forest argues that PJM
is too small, while NASUCA and Mid-Atlantic Commissions believe that
PJM satisfies the size criteria. Some commenters object to a split
between the area represented by the proposed Alliance RTO and the
Midwest ISO.\345\ Most of the Florida commenters assert that peninsular
Florida represents an appropriate region.\346\ For example, Florida
Commission claims that peninsular Florida is a large and efficient
marketplace that does not share parallel flows with other electrical
regions; however, it states that the Florida panhandle could be in a
region with all of SERC or a subregion of SERC.
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\345\ See, e.g., Michigan Commission, South Carolina Authority,
Midwest ISO, Midwest ISO Participants, NASUCA.
\346\ See, e.g., Florida Commission, JEA, FP&L, Florida Power
Corp., Tallahassee, Gainesville.
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Although some commenters encourage a Western interconnection-wide
RTO, the majority of commenters support three or four RTOs for the
Western interconnection, noting that the interests in the WSCC are too
diverse and the area too large for control by a single entity.\347\ Cal
ISO contends that California satisfies the minimum size criteria, but
does not represent the maximum feasible area. Commenters from the
Pacific Northwest generally agree that a region including Washington,
Oregon, and all or portions of Idaho and Montana is distinct enough to
warrant an RTO limited to that area.\348\ CREDA and Platte River
envision one RTO for the Pacific Northwest, one for California and one
for the Rocky Mountain/Desert Southwest area; CRC suggests a similar
alignment, with the exception of the Rocky Mountain and Southwest areas
as separate RTOs.
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\347\ See, e.g., SRP, Metropolitan.
\348\ See, e.g., Seattle, PGE, Industrial Customers, BC Hydro,
Powerex, Tacoma Power, PNGC.
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A number of commenters make the point that, regardless of where RTO
boundaries are drawn, it is important that there be integration and
coordination among RTOs.\349\ NERC believes that there are two seams
issues: reliability practices across seams and market practices across
seams. TDU Systems suggests that there be a set of regions for
reliability/operations purposes within a larger region for rates and
scheduling. Industrial Consumers state that, if multiple RTOs are
formed within an interconnection, RTOs should be required to coordinate
their operations to collectively ``simulate'' an interconnection-wide
RTO. Cinergy suggests that, if there were more than one RTO in a large
interconnection, a ``super'' RTO could be established to operate and
coordinate inter-RTO activities. Montana Commission states that RTO
boundaries are less important than ensuring that seams do not interfere
with the market, and proposes, as do others such as Ontario Power and
CMUA, that the Commission require adjacent RTOs to embody consistent
methods of access, pricing, and congestion management to encourage
seamless trading. PacifiCorp asserts that reciprocity agreements among
RTOs may be easier to achieve than having all parties in a large region
agree to one RTO. Allegheny suggests that appropriate transmission
pricing could provide some of the same benefits as a large RTO.
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\349\ See, e.g., South Carolina Authority, SPP.
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Several commenters express concern that multiple RTO proposals for
the same region will be submitted. Indiana Commission contends that the
NOPR leaves the door open for more than one RTO proposal for
approximately the same wholesale power market region and this could
limit the operational efficiency and increase the cost of transmission
in the region. It suggests that the Commission consider requiring
formal mediation or play an assertive role in such circumstances.
Snohomish suggests favoring the RTO proposal that is negotiated
pursuant to the most open process that included consumers, transmission
dependent utilities and others with a vital interest in the effective
and efficient operation of the transmission grid. Midwest ISO
Participants submit that the proponents of multiple RTOs meet a heavy
burden and demonstrate the need for more than one RTO. In particular,
it would require demonstration that the proposals: do not balkanize the
market; allow for effective congestion relief; maintain reliability;
facilitate construction of new transmission facilities; and allow for
effective tariff administration and unbiased ATC determination
throughout the region.
Commission Conclusion. We adopt the NOPR proposal on this
characteristic. All RTO proposals filed with us must identify a region
of appropriate scope and configuration. The scope and configuration of
the regions in which RTOs are to operate will significantly affect how
well they will be able to achieve the necessary regulatory,
reliability, operational, and competitive benefits.
As proposed in the NOPR, we will not at this time prescribe initial
boundaries for RTOs. Section 202(a) of the FPA does give us the
authority, after consultation with state commissions, to fix and modify
boundaries for regional districts for the voluntary interconnection and
coordination of facilities. We acknowledge those commenters who believe
that it may be more efficient for the Commission to establish at least
a rebuttable presumption that particular boundaries are appropriate
starting points. However, we conclude, as a matter of policy, that we
should not attempt to draw boundaries at this time. We are convinced
that the transmission owners, market participants, and regulators in a
particular region have a better understanding of the dynamics of the
transmission system in that region, and that they should, at least in
the first instance, propose the appropriate scope and regional
configuration of an RTO. There are many technical considerations
involved in discerning the appropriate scope and regional configuration
of an RTO, and we believe that those most familiar with such
considerations in a region are in a better position to propose a
workable solution.
As noted above, some commenters advocate that the NERC regions be
starting points; others advocate that the Interconnections be the goal;
and still others propose specific configurations that would divide the
Nation as many as three to 12 RTOs. Consistent with our decision to let
the parties take the initiative to propose what is appropriate for
their region, we will not specifically
[[Page 861]]
endorse any particular scheme for RTO configuration.
This is not to say, however, that we will deem appropriate any
regional configuration proposed. As stated in the regulatory text for
this characteristic, an appropriate region is one of sufficient scope
and configuration to permit the RTO to effectively perform its required
functions and to support efficient and nondiscriminatory power markets.
A proposed RTO could simply be too limited to satisfy several of the
necessary functions. Further, we are aware that transmission owners
could seek to gain strategic advantage by the way an RTO is formed. For
example, an RTO could be placed to act as a toll collector on a
critical corridor.\350\ An RTO could propose a configuration that
interferes with the formation of a larger, more appropriately
configured RTO.
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\350\ See Statement of Ohio Commission Chairman Craig Glazer,
RTO Conference (St. Louis), transcript at 85-87.
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As we review a proposal by a regional transmission entity for its
scope and regional configuration, if we determine that the scope is
inappropriate, that entity will not be deemed to be an RTO, and its
participants will not be deemed to be RTO participants.\351\ In
response to the commenters questioning what the Commission would do if
it received multiple RTO proposals for a region, we note that we hope
the collaborative process we are encouraging in this Final Rule would
foreclose that circumstance. However, if we are faced with multiple
proposals, we would have to determine which RTO proposal best meets the
objectives of this Rule.
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\351\ The proposal could be accepted, however, as something less
than an RTO that represents an improvement over the status quo.
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As we stated in the NOPR, we are aware that there is likely no one
``right'' configuration of regions. One particular boundary may satisfy
one desirable RTO objective and conflict with another. We recognize
here, and elsewhere in this Final Rule,\352\ that the industry will
continue to evolve, and the appropriate regional configurations will
likely change over time with technological and market developments. The
Commission is also mindful of the interests of individual states
regarding RTO boundaries. Given all these considerations, the
Commission believes that the public interest will best be served if we
provide guidance in this Final Rule, in the form of factors that affect
appropriate regional configuration, without actually prescribing
boundaries.
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\352\ See section F on Open Architecture.
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b. Scope and Configuration Factors. Comments. A large number of
commenters agree that the factors listed in the NOPR for determining a
proper scope and configuration for an RTO are generally
appropriate.\353\ Industrial Consumers propose that the factors be
codified as part of our regulations. Florida Commission, on the other
hand, argues that the factors should not be mandated as part of the
Commission's regulations.
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\353\ See, e.g., UtiliCorp, Desert STAR, Midwest ISO
Participants, Metropolitan, NECPUC, LG&E, PJM/NEPOOL Customers,
Midwest Municipals, Industrial Consumers, Dairyland, TDU Systems,
ISO-NE, Midwest Energy, APX, APPA, Cal ISO.
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Many commenters argue that the RTO region should be as large as
possible, i.e., bigger is better.\354\ Several commenters suggest the
minimum size should be the NERC regions.\355\ Conlon suggests a minimum
area should be one containing a load of 50,000 MW. PJM states that its
organization demonstrates that a very large RTOs is feasible, in that
it manages a grid serving more than 57,000 MW of generation and
containing more than 8,000 miles of high voltage transmission lines.
PJM states that even larger control areas are possible as technology
advances. PJM/NEPOOL Customers, claiming that all potential factors
that might limit size can be overcome, argue that the Commission should
not conclude that there are factors that limit size. As discussed below
with respect to the congestion management function, some commenters
make a particular point of emphasizing the importance of large scope to
effective congestion management.\356\
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\354\ See, e.g., Cinergy, American Forest, EPSA, UtiliCorp,
PG&E, NSP, Pennsylvania Commission, NJBUS, LG&E, Enron/APX/Coral
Power, NASUCA, PJM/NEPOOL Customers, Cal ISO, Texas Commission,
Conlon, Dynegy, Nine Commissions, Michigan Commission, Lincoln,
WPSC, First Rochdale, East Texas Cooperatives, Los Angeles, Ohio
Commission, EME, Ontario Power, H.Q. Energy Services, Ogelthorpe,
UMPA, PG&E, Indiana Commission.
\355\ See, e.g., Cinergy, WPSC, Lincoln, Ohio Commission, PG&E.
\356\ See, e.g., LG&E, ComEd, Midwest ISO Participants, Midwest
ISO.
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Other commenters argue that bigger is not necessarily better and
that there are factors that limit size.\357\ CMUA argues that the role
of security coordinator and operational characteristics of a region may
limit geographic scope. STDUG claims that size breeds inefficiency.
Several commenters claim that requiring maximum scope upon creation may
discourage RTO formation or make it more costly and take longer to
achieve.\358\ NYPP expresses concern that, if an RTO is too large, it
may not be able to handle local reliability issues. Other commenters
believe that the ability to plan new transmission facilities may limit
scope.\359\ AEPCO expresses concern that the voice of smaller
participants could be lost in a larger RTO. Florida Power Corp. claims
that there may be a security risk associated with concentrating control
of too large an area into a single facility, and that large areas of
non-pancaked rates may eliminate incentives for proper generator siting
decisions. A number of commenters believe that either the Eastern
interconnection or the Western interconnection is too large an area to
be controlled by one RTO.\360\ New York Commission argues that the
Commission should recognize that experience must be gained in stages
before an RTO encompassing an entire interconnection can be
implemented. Several commenters in the Pacific Northwest cite the
failed attempt to create IndeGo as evidence that trying to create too
large an RTO is unworkable, and at some point ``bigger'' creates more
problems than it solves.\361\
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\357\ See, e.g., AEPCO, Tallahassee.
\358\ See, e.g., Enron/APX/Coral Power, FirstEnergy, Tri-State.
\359\ See, e.g., Dairyland, Minnesota Power.
\360\ See, e.g., South Carolina Authority, Desert STAR,
MidAmerican, TDU Systems, CREDA, SNWA, CRC, Platte River, PSNM, SRP,
Metropolitan.
\361\ See, e.g., Industrial Customers, Powerex, Tacoma Power.
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Some commenters offer subjective parameters for the scope of an
RTO. For example, SNWA proposes that the RTO be large enough to
accommodate as many market participants as possible, but not so large
as to be overly burdensome to manage. SRP argues that a balance must be
struck between an RTO that is too small to cover a meaningful wholesale
power market and one that is too large to form and operate effectively.
TDU Systems argue that RTOs should comprise the largest regions that
could operate in a coordinated fashion within a short period of time
with reasonable investments of funds.
A number of commenters emphasize particular factors that they
consider important in determining scope and configuration. Some
commenters assert that reliability and system security should be the
primary determinant of scope and configuration.\362\ Others place prime
importance on trading patterns and facilitating market
transactions.\363\ EEI states that the most efficient size and
configuration of an RTO should be left to the market to determine.
Other commenters propose electrical
[[Page 862]]
configuration and physical power flows as important factors.\364\ CREDA
and Desert STAR argue that the preservation of a Federal Power
Marketing Administration project marketing area is an important
consideration. Chelan argues that cost shifts need to be considered in
determining scope. Platte River contends that established security
coordinators should be a factor. Southern Company argues that joint
ownership agreements should be a factor. Tacoma Power claims that
traditional business relationships and social and political commonality
are factors that affect scope.
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\362\ See, e.g., CMUA, APPA, Florida Commission, Minnesota
Commission.
\363\ See, e.g., UtiliCorp, Reliant, Duke, South Carolina
Commission, NU, Florida Power Corp., Detroit Edison.
\364\ See, e.g., South Carolina Authority, Williams, NSP,
Dynegy.
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Commenters are divided on whether points where transmission
facilities are constrained should be used as an RTO boundary or
internalized within an RTO. Some commenters claim that constraints
should be internalized to the extent possible and not constitute
boundaries between regions.365 NERC states that boundaries
should not be placed at weak interconnections because a single entity
is better able to strengthen them. On the other hand, other commenters
believe that constrained facilities should constitute the boundaries,
either because they may form a natural boundary between robust systems
or because it makes more sense to internalize markets than to
internalize constraints.366 APPA states that, because it is
not possible to internalize all constraints, the goal should be to
alleviate or mitigate the effects of interregional constraints through
additional construction and RTO operating rules and pricing policies.
NECPUC argues that it does not matter where constraints are if
compatible methods of locational pricing are adopted by contiguous
RTOs. MidAmerican and Duke assert that constraints are not natural
boundaries between regions because the location of points of constraint
change over time as market conditions change. Several commenters, such
as Dairyland and Desert STAR, take the position that the issue whether
to design RTO boundaries at constrained interfaces cannot be stated
generically, and must be decided on a case-by-case basis.
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\365\ See, e.g., Industrial Consumers, First Rochdale, Minnesota
Power, STDUG, NARUC.
\366\ See, e.g., Ohio Commission, EAL, Florida Power Corp.
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Commission Conclusion. The factors we believe should be used to
develop appropriate regions are set out here and called regional
configuration factors. These cover such considerations as how large a
region should be and how boundaries should be evaluated. We do not see
a benefit to placing them in regulatory text, as suggested by one
commenter, and we will not do so. The factors are intended as guidance
and, as such, must necessarily be applied flexibly.
Regional Configuration Factors. As stated above, the principal
consideration in evaluating the appropriate scope of an RTO is that
such scope must permit the RTO to perform its functions effectively. As
we stated in the NOPR, many of the characteristics and functions for an
RTO proposed in this section suggest that the regional configuration of
a proposed RTO should be large in scope.367 For example:
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\367\ This reiterates the conclusion we reached in the eleven
ISO principles in Order No. 888, where we stated that ``[t]he
portion of the transmission grid operated by a single ISO should be
as large as possible.'' Order No. 888, FERC Stats. & Regs. para.
31,036 at 31,731.
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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.
Improving Operations: A single OASIS operator over an area
of sufficient regional scope will better allocate scarcity as regional
transmission demand is assessed; promote simplicity and ``one-stop
shopping'' by reserving and scheduling transmission use over a larger
area; and lower costs by reducing the number of OASIS sites.
Planning and coordinating transmission expansion:
Necessary transmission expansion would be more efficient if planned and
coordinated over a larger region.
We note that the comments on this issue express a range of views.
Many commenters assert that the bigger the RTO is the better, and that
there really are no serious limitations to RTOs representing loads as
large as several hundred thousand megawatts. Other commenters suggest a
number of considerations that may militate against RTOs that are too
large, including the role of security coordinator, operational
characteristics, costs of formation, local reliability issues, and the
effect on smaller participants. In the NOPR, we recognized that there
may be a limitation on how many facilities or transactions can be
overseen reliably by a single operator, imposed either by hardware
design or costs, or imposed by human limitations to process the
required amount of information. We further recognized that the
difficulty and cost of transferring operational control over many
transmission systems to one RTO may affect regional configuration. We
also noted that, as regions get larger and involve more existing owners
of transmission, reaching consensus on an appropriate transmission rate
design for the region may prove challenging.
We note that a number of commenters make the point that, at least
for some purposes and functions, the scope of an individual RTO is less
important if it is part of a group of RTOs that have adequately
eliminated the negative effects of ``seams'' between itself and the
other RTOs. NERC identifies two seams issues: reliability practices
across seams and market practices across seams. We further note that
other commenters suggest that large RTOs could be ``simulated'' through
coordinated operations and consistent methods of access, pricing, and
congestion management, and that there may be different acceptable
scopes for reliability and operations purposes on one hand, and rates
and scheduling on the other.368 We also detect a common
theme that runs through a number of comments: large geographic size is
most important for trading areas. Thus, the concept of large ``seamless
trading areas'' for power emerges as a ``scope'' issue that is distinct
from the scope of the region for organizing the transmission functions
of an RTO.
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\368\ In a recent conference to address interregional ISO
coordination in the northeast, the three northeast ISOs (ISO New
England, New York ISO, and PJM ISO) and other market participants
discussed current and future coordination efforts among the ISOs
intended to simplify market transactions and enhance reliability in
the northeast. See http//www.dps.state.ny.us/isoconf.htm.
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We conclude that a large scope is important for an RTO to
effectively perform its required functions and to support efficient and
nondiscriminatory power markets. Adequate scope is not necessarily
determined by geographic distance alone; other factors include the
numbers of buyers and sellers covered by the RTO, the amount of load
served, and the number of miles of transmission lines under operational
control. The scope must be large enough to achieve
[[Page 863]]
the regulatory, reliability, operational and competitive objectives of
this Rule.
We are receptive to flexible and innovative ways for an RTO to
achieve sufficient scope. Where a proposed regional transmission entity
may be of sufficient scope for some RTO purposes, but not others, an
RTO may be able to achieve sufficient ``effective scope'' by
coordination and agreements with neighboring entities, or by
participating in a group of RTOs with either hierarchical control or a
system of very close coordination. We do not foreclose the possibility
that an RTO may satisfy some of the minimum characteristics and
functions by itself, while satisfying others through a strong
cooperative agreement with neighboring RTOs to create a ``seamless
trading area.'' The functions of a large RTO may be met by eliminating
the effect of seams separating smaller RTOs through a contract or other
coordination arrangement. One of our concerns about an RTO's scope is
that the existing impediments to trade, reliability, and operational
efficiency be eliminated to the greatest extent possible. However, an
RTO application that proposes to rely on ``effective scope'' to satisfy
Characteristic 2 must demonstrate that the arrangement it proposes to
eliminate the effect of seams is the practical equivalent of
eliminating the seams by forming a larger RTO.
Factors for Evaluating Boundaries. In addition to the factors
affecting the size of a region, other factors may affect the
delineation of regional boundaries. As stated in the NOPR, the
Commission proposed that RTO boundaries be drawn so as to facilitate
and optimize the competitive, reliability, efficiency and other
benefits that RTOs are intended to achieve, as well as to avoid
unnecessary disruption to existing institutions. The Commission
proposed in the NOPR a list of factors it would consider in evaluating
the configuration for a proposed RTO. Nearly all of the comments agree
that these factors are generally appropriate.
We recognize that different factors may suggest different
configurations and that assessing the appropriateness of a region's
configuration will require balancing factors and a flexible approach.
Given this qualification, the Commission, in evaluating an RTO's
boundaries, will consider the extent to which the proposed boundaries:
Facilitate performing essential RTO functions and achieving RTO
goals: The regions should be configured so that an RTO operating
therein can ensure non-discrimination and enhance efficiency in the
provision of transmission and ancillary services, maintain and enhance
reliability, encourage competitive energy markets, promote overall
operating efficiency, and facilitate efficient expansion of the
transmission grid. For example, we understand that there have been
instances where transmission system reliability was jeopardized due to
the lack of adequate real-time communication between separate
transmission operators in times of system emergencies. To the extent
possible, RTO boundaries should encompass areas for which real-time
communication is critical, and unified operation is preferred.
Encompass one contiguous geographic area: The competitive,
efficiency, reliability, and other benefits of RTOs can be best
achieved if there is one transmission operator in a region. To be most
effective, that operator should have control over all transmission
facilities within a large geographic area, including the transmission
facilities of non-public utility entities. This consideration could
preclude a noncontiguous region, or a region with ``holes.'' However,
as we discuss below, we will not automatically deny RTO status where
the RTO is not able to obtain full participation in its region.
Encompass a highly interconnected portion of the grid: To promote
reliability and efficiency, portions of the transmission grid that are
highly integrated and interdependent should not be divided into
separate RTOs. One RTO operating the integrated facilities can better
manage the grid. This is not to say, however, that every weak
interconnection belongs on a regional boundary. Where a weak interface
is frequently constrained and acts as a barrier to trade, it may be
appropriate to place that interface within an RTO region. It may be
more difficult to expand a weak interface on the boundary between two
regions; this may act as a barrier to trade between the two
regions.369
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\369\ Commenters are also divided on whether weak interfaces
should be encompassed within an RTO or act as a natural boundary.
After consideration, we conclude that there is not a universal
answer applicable to all situations. Consequently, we will address
this issue as it arises in RTO proposals on a case-by-case basis.
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Deter the exercise of market power: While the industry should work
toward a goal of virtually seamless trade between RTOs, it may be that
initially a significant amount of trade may be contained within an RTO,
especially if the RTO or the market establishes a power exchange that
covers the same area as the RTO. Thus, to have a competitive market, it
is important to create an RTO region that is not dominated by a few
buyers or sellers of energy. Also, the RTO configuration should not be
one where the RTO participants can exercise transmission market power
by collecting congestion fees on a critical corridor.
Recognize trading patterns: Given that a goal of this initiative is
to promote competition in electricity markets, regions should be
configured so as to recognize trading patterns, and be capable of
supporting trade over a large area, and not perpetuate unnecessary
barriers between energy buyers and sellers. There may exist today some
infrastructure or institutional barriers unnecessarily inhibiting trade
between regions that could be economically reduced. RTO boundaries
should not perpetuate these unnecessary and uneconomic barriers.
Take into account existing regional boundaries (e.g., NERC regions)
to the extent consistent with the Commission's goals for RTOs: An RTO's
configuration should, to the extent possible, not disrupt existing
useful institutions. The Commission recognizes that utilities have been
working together regionally in different contexts for some time, and
that there is value in preserving historical institutions and
relationships; but we also recognize that in the evolving market,
efficiencies may call for new configurations.
Encompass existing regional transmission entities: Because existing
ISOs, and any other regional transmission entities we may hereafter
approve, already integrate transmission systems, it may not be
efficient to divide them into different regions. This is not to say,
however, that RTO boundaries must coincide with existing regional
transmission entities. An appropriate region may well be larger, and
there may be circumstances that support combining or reconfiguring
existing entities.
Encompass existing control areas: Many existing control areas are
relatively small. It may be advisable not to divide them further.
However, parties would not be precluded from proposing to divide a
control area if they show this to be beneficial.
Take into account international boundaries: The Commission
recognizes that natural transmission boundaries do not necessarily
coincide with international boundaries. Indeed, a large part of
Canada's transmission system, and a small part of Mexico's transmission
grid, is interconnected on a synchronous basis with that of the U.S.
Accordingly, an appropriate region need not stop at the international
boundary. However, this Commission
[[Page 864]]
does not have, and is not intending by this rule to seek, jurisdiction
over the facilities in a foreign country. We will ask our international
neighbors to participate in discussion of these issues. Perhaps what
may be thought of as a ``dotted line'' boundary at the international
border could be used to indicate that a natural transmission region
does not necessarily stop at the border, while this Commission's
jurisdiction does.
Although most commenters generally support these factors, other
considerations are proposed as factors. For example, some commenters
claim that we should make reliability and system security the dominant
factor, while other commenters propose that we make trading patterns
and market transactions the dominant factor. After consideration, we do
not think it appropriate to identify one factor as the most important.
Although it is essential that reliability not be jeopardized by RTO
formation, and it is important to promote competition, we do not
believe that one goal needs to be sacrificed to achieve the other.
Other commenters suggest additional factors that they deemed
important to RTO boundaries, including, for example, established
security coordinators, joint ownership arrangements, and Federal power
marketing administration project marketing areas. We do not intend the
factors we have listed to be exclusive: other factors may have merit
for a particular region. We encourage parties to identify additional
factors they believe relevant as we consider specific RTO proposals.
c. Control of Facilities Within a Region. We proposed in the NOPR
to accept as RTOs only those proposals for which a region of
appropriate scope and configuration is identified and the proponents
represent a large majority of the transmission facilities within the
identified region. We solicited comments on how best to balance our
goal of having RTOs in place that operate all transmission facilities
within an appropriately sized and configured region against the reality
that there may be difficulties in obtaining 100-percent participation
in all regions in the near term. We asked if we should deny RTO status
for any proposal that does not include all transmission facilities
within an appropriate region, or if we should require that the RTO at
least negotiate certain agreements with any non-participants within its
region to ensure maximum coordination.
Comments. Almost all commenters argue that RTO status should not be
withheld if the RTO participants are unable to obtain participation by
all transmission owners in the region.370 Several
commenters, such as Desert STAR and Minnesota Power, note that, if the
Commission does not mandate 100 percent participation, it does not make
sense to make it a condition of RTO approval. Other commenters propose
standards to consider in determining when a proposed RTO represents
sufficient facilities in the region. For example, Desert STAR suggests
that the RTO have more than a majority of transmission owners and has
not restricted membership. Southern Company proposes a standard that
sufficient facilities include most of the major transmission facilities
and the RTO can show benefits. MidAmerican proposes that the RTO be
able to demonstrate that it would improve the wholesale market of any
subregion of the country without hindering the wholesale market of any
other region of the country. Enron/APX/Coral Power argues that an RTO
should be approved if it provides an improvement even with ``gaps.''
Midwest Municipals believe that an RTO should be accepted if the
Commission can make the judgment that the proposal with ``gaps'' is
likely to encourage others to join through the strength of its
operations and the facilities support the development of a competitive
generation market. CRC suggests a standard that the proponents make a
showing that they have diligently tried to accommodate the concerns and
needs of the nonparticipating transmission owners.
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\370\ See, e.g., Desert STAR, Southern Company, Metropolitan,
MidAmerican, Nevada Commission, Avista, Enron/APX/Coral Power, Duke,
PJM/NEPOOL Customers, Cal ISO, Midwest Municipals, CRC, NPRB,
Minnesota Power, Tri-State, TVA.
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Some commenters, such as NJBUS and Cal ISO, believe that an RTO
should include the participation of all jurisdictional transmission
owners in the region. Duke, however, opposes any attempt by the
Commission to determine the appropriate level of participation, stating
that the market should determine the participation level. Some
commenters, such as Metropolitan, support having the RTO develop
coordinated operations agreements with non-participants, while other
commenters, such as Avista and Duke, caution that requiring such
agreements would be contrary to market principles and would give the
non-participating party too much bargaining power.
Seattle contends that the Commission should guard against utilities
that would add to the RTO some facilities that are not necessary for
RTO operations merely to obtain incentives. It argues that small
municipal control areas should have some latitude to determine which of
their facilities are regional for RTO purposes. Seattle also questions
what ``participation'' entails for a utility that has limited
transmission facilities.
Commission Conclusion. To satisfy the scope and configuration
characteristic of this Final Rule, all or most of the transmission
facilities in a region must be included in the RTO. Any RTO proposal
filed with us should intend to operate all transmission facilities
within its proposed region.
We recognize, however, that the proponents of an RTO may not be
able to obtain agreement by all transmission owners in a region of
appropriate scope and configuration to transfer operating control of
their facilities to the RTO. This may occur, for example, because
certain facilities may be owned by governmental entities that have
restrictions on transfer of control that may require time to resolve.
We do not believe that it would be desirable to deny RTO status or
delay RTO start-up where the transmission owners representing a large
majority of the facilities within a region are ready to move forward,
while a few others are not. On the other hand, we do not believe it
would be desirable to approve an RTO proposal for a region if the
proponents represent only a small portion of the facilities in an
otherwise satisfactory region.
Not knowing the full extent of difficulties that may be involved to
achieve participation by all transmission facilities, we will not
decide generically to automatically deny RTO status for lack of full
participation. If an RTO proposal does not cover all the transmission
facilities within its proposed region, it should identify the reasons
for this, any continuing efforts to include all facilities, and any
interim arrangements with the non-represented facility owners to
coordinate transmission functions within the region. The Commission may
at a future time determine whether the use of its authorities under FPA
sections 202(a) and 206 is appropriate to rationalize proposed regions
in order to accomplish the objectives of those sections, as discussed
elsewhere in this Final Rule.
3. Operational Authority (Characteristic 3)
In the NOPR, the Commission proposed that the RTO have operational
authority for all transmission facilities under its
control.371 We stated that this
[[Page 865]]
requirement raised two questions: Which functions must an RTO perform?
How should an RTO perform the functions that it has reserved for
itself? With respect to the question of which functions an RTO should
perform, the Commission proposed that, at a minimum, the RTO must have
operational authority over all transmission facilities transferred to
the RTO and must be the security coordinator for its
region.372 As security coordinator, the RTO would be
responsible for real-time monitoring of system conditions (including
voltage, frequency, transmission and generation availability, and power
flows) in order to anticipate potential reliability problems, and for
directing and coordinating relief procedures to respond to transmission
loading problems (such as assisting the control area in alleviating the
loading, halting additional interchange transactions, reallocating the
use of the transmission system, selecting the transmission loading
relief procedure, and implementing emergency procedures, including
directing that the control area immediately redispatch generation,
reconfigure transmission or reduce load). Those proposing an RTO may
also decide to have their RTO perform other traditional control area
functions (such as maintaining the energy balance, interchange
schedules and system frequency). The Commission proposed, however, that
an RTO would not be required to be a single control area because of
concerns over potentially high costs and technical limitations. Instead
those proposing an RTO would be given flexibility in determining the
best division of functions between the RTO and any providers of other
control area functions if there are no other grid operators in its
region. However, the Commission insisted that an RTO must be ultimately
responsible for providing reliable and non-discriminatory transmission
service.373
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\371\ FERC Stats. & Regs. para. 32,541 at 33,734 and proposed
Sec. 35.34(i)(3). In the NOPR, we used the terms ``operational
authority'' and ``operational responsibility'' interchangeably. For
purposes of clarity and consistency, we will use only the term
``operational authority'' to describe this function and have revised
the proposed regulatory text accordingly.
\372\ FERC Stats. & Regs. para. 32,541 at 33,734 and proposed
Sec. 35.34(i)(3)(ii).
\373\ Id.
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With respect to the second question of how an RTO will perform its
functions, the Commission proposed that an RTO be given considerable
flexibility in determining whether it will control facilities directly,
delegate functions, or use a combination of these
methods.374 For example, we stated that an RTO proposal
could have the RTO operate a single control area, or establish a
master-satellite hierarchical control structure with one central and
multiple distributed control centers (in either case it could propose
to lease equipment and convert employees from existing control
centers).375 The Commission also proposed that the RTO must
submit a public report assessing its operational arrangements no later
than two years after it begins operations.376
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\374\ Id. and proposed Sec. 35.34(i)(3)(i).
\375\ Id.
\376\ Id. at 33,735.
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Comments. Comments on the Functions an RTO Must Perform. Most
commenters agree that the RTO must have operational authority
377 for the transmission facilities under its
control.378 Some commenters claim that this authority is
necessary to prevent anticompetitive behavior by transmission
owners.379 Some commenters further contend that this
authority must extend to all facilities involved in wholesale
transactions so that the transmission owner does not retain control of
``access ramps'' that happen to be at low (34kV or 69kV) voltage
levels.380 In contrast, some utilities express concern that
RTO authority over low voltage facilities will unnecessarily complicate
operations.381
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\377\ Operational authority refers to the authority to control
transmission facilities, either directly or through contractual
agreements with the entities that do have direct control. In
contrast, security coordination refers to real-time monitoring of
system conditions in order to anticipate potential reliability
problems, and directing and coordinating relief procedures to
respond to transmission loading problems.
\378\ See, e.g., APPA, Cal ISO, Duke, East Texas Cooperatives,
Entergy, EPSA, First Rochdale, Georgia Transmission, Illinois
Commission, IMEA, ISO-NE, Michigan Commission, Minnesota Power,
Montana-Dakota, NASUCA, NECPUC, Nevada Commission, Mid-Atlantic
Commissions, PacifiCorp, PJM, PJM/NEPOOL Customers, SNWA, Southern
Company, SRP, SPRA, Tri-State, UtiliCorp, WPSC.
\379\ See, e.g., Illinois Commission, IMEA, NASUCA, PJM/NEPOOL
Customers.
\380\ See, e.g., First Rochdale, IMEA, UMPA.
\381\ See, e.g., Montana-Dakota, Tacoma Power.
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Several commenters oppose operational authority over the
transmission system by the RTO. Some commenters claim that the
Commission does not have the legal authority to require transmission
owners to transfer control to any other entity.382 Midwest
Energy and SPP believe a transfer of authority would be too costly to
implement. Other commenters maintain that the owner and operator of the
transmission system must be the same entity in order to avoid liability
disputes.383 Mass Companies suggests that transmission
owners retain authority to ensure the safe and prudent management of
their facilities. ComEd suggests that transmission owners retain
operational authority with the RTO having oversight responsibility.
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\382\ See, e.g., Florida Commission, Puget. It appears that the
Florida Commission interprets a transfer of operational control as a
transfer of retail dispatch authority. Although other commenters
such as WPSC support the RTO having operational authority, they
believe that the Commission may need legislative action to obtain
the authority to require such a transfer.
\383\ See, e.g., Florida Power Corp., Georgia Transmission, JEA,
MidAmerican, Southern Company, Enron/APX/Coral Power.
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Commenters are divided whether the RTO should be required to be a
control area operator. The existing ISOs in California, New England and
PJM, which are all control area operators, report that this structure
is working in their regions. Some commenters express concern over
potential harm to competitive markets if control area authority is not
transferred to an independent entity.384 ICUA recommends
that the RTO be the sole control area operator. Many other commenters
support a single control area as the ultimate goal, but suggest that
the RTO be allowed to evolve to this structure and not be required to
consolidate control areas immediately.385 Other commenters
express concern about potential costs associated with control area
consolidation, but agree that such action would be acceptable if and
when the RTO decides it is necessary for reliability or other
reasons.386
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\384\ See, e.g., APPA, APS, Arkansas Consumers, NASUCA, NJBUS,
TDU Systems.
\385\ See, e.g., Conlon, Illinois Commission, Los Angeles, First
Energy, Minnesota Power, SRP, TDU Systems.
\386\ See, e.g., CP&L, ECAR, EEI, Entergy, EPSA, Southern
Company.
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Commenters that oppose requiring control area consolidation provide
a variety of reasons.387 Enron/APX/Coral Power state that
only an RTO that is a transco should perform control area functions.
The Florida Commission is concerned that control area consolidation may
result in a security risk. Tri-State and WEPCO believe that there are
higher priorities in RTO development (such as eliminating pancaking,
and promoting regional system planning) and that emphasizing control
area consolidation may inhibit RTO formation.
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\387\ It appears that the Florida Commission and JEA believe
that such a transfer would involve RTO control of retail dispatch.
It also appears that Dynegy believes that the basic control area
function of frequency control is identical to dynamic scheduling,
which they believe should not be centralized or consolidated.
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With respect to specific control area functions, numerous
commenters discuss the need for an RTO to have some control of
generation in order to ensure system reliability, especially
[[Page 866]]
during emergency situations.388 Minnesota Power suggests
that the Commission include ``control generation as required to ensure
reliability'' as an additional minimum function in the final rule. It
also recommends that responsibility for area control error (ACE) and
automatic generation control (AGC) be transferred to the RTO as control
area functions because separating these functions from transmission
operations can lead to reliability problems. Other commenters request
that the balancing function be transferred to the RTO to prevent
discriminatory behavior by transmission owners.389
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\388\ See, e.g., NASUCA, First Energy, Otter Tail, PJM, PJM/
NEPOOL Customers, Professor Hogan, Project Groups, SPRA, UtiliCorp,
Williams, WPPI. We also discuss below in more detail the issue of
congestion management as an RTO minimum function.
\389\ See, e.g., East Texas Cooperatives, WPPI, Project Groups.
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There is widespread agreement among commenters that the RTO must be
the security coordinator. Marketers, utilities, existing ISOs and
customers all agree that coordination and reliability will be enhanced
if a regional organization is responsible for maintaining grid
security.390 Some commenters state that the authority of a
security coordinator to receive commercially sensitive information to
order the curtailment of transactions and the shedding of firm load
also grants it the ability to favor its own merchant functions.
Confidence in comparable and non-discriminatory transmission service,
therefore, will be improved if these functions are performed by an
entity that is independent of all market participants.391
Though essentially in support of our proposal, NERC and MidAmerican
assert that is not necessary to link each RTO to a single security
center, but rather it is possible to allow a single security
coordinator to assume responsibility for more than one RTO. NERC points
out that if an RTO performs all the characteristics and functions
specified in the NOPR, it will necessarily be a security coordinator.
---------------------------------------------------------------------------
\390\ See, e.g., Allegheny, APPA, APX, Cal ISO, ComEd, Dynegy,
East Texas Cooperatives, Enron/APX/Coral Power, Entergy, EPSA, LG&E,
Mass Companies, MidAmerican, Midwest Energy, Montana-Dakota, NASUCA,
NECPUC, NERC, NJBUS, PJM/NEPOOL Customers, PPC, Professor Hogan,
Seattle, South Carolina Authority, SPP, SRP, Tri-State, UtiliCorp,
Williams.
\391\ See, e.g., LG&E, PJM/NEPOOL Customers, SPP, UtiliCorp. See
also supra section III.D.1 for a more detailed discussion of
independence as an RTO minimum characteristic.
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A number of parties state that the RTO must have access to real-
time system information in order to perform its functions as security
coordinator.392 Montana-Dakota explains further that
security centers, by definition, will be equipped with the hardware and
software required to assume basic operational control of the system,
which are beyond that required strictly for security functions.
---------------------------------------------------------------------------
\392\ See, e.g., Montana-Dakota, PJM/NEPOOL Customers, South
Carolina Authority, Williams.
---------------------------------------------------------------------------
Only two commenters express concern over the need for the RTO to be
the security coordinator. ComEd, though supporting some security
functions for the RTO, asserts that the RTO's role can be limited
simply to one of oversight. ComEd does not believe that the RTO needs
access to real-time data, and instead would allow the individual
control areas to perform the bulk of the security functions. The only
commenter that argues against making the RTO a security coordinator is
Avista, which states that the security coordinator in the Pacific
Northwest is already an independent body and has the authority
necessary for ensuring reliability; therefore, no changes are required.
Comments on How an RTO Should Perform Its Functions. Overall,
commenters strongly agree with the Commission's proposal to permit
those proposing an RTO the authority to decide the type of control they
require: direct, functional or a combination. Some commenters believe
direct control is the best approach to prevent abuse of sensitive
information and better ensure reliability.393 However,
Manitoba Board and Canada DNR express concern that continued
coordination between U.S. and Canadian utilities might be undermined if
highly centralized systems are developed and controlled by U.S.
entities. A few commenters contend that it is best for the RTO to
delegate control authority.394 The majority of commenters
support some form of hierarchical control structure, where the RTO
would establish a master control center and direct the operations in
the existing geographically distributed control centers, which would
become satellite centers.395 PJM and ISO-NE indicate that
they both currently operate with a hierarchical control structure,
where the ISO control center is the master control room that directs
the actions of the satellite control centers.
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\393\ See, e.g., East Texas Cooperatives, First Rochdale,
Illinois Commission, PJM/NEPOOL Customers.
\394\ See, e.g., MidAmerican, Seattle, South Carolina Authority.
\395\ See, e.g., ECAR, Enron/APX/Coral Power, EPSA, East Texas
Cooperatives, First Rochdale, Industrial Consumers, ISO-NE, LG&E,
Los Angeles, Lincoln, MidAmerican, Montana-Dakota, NECPUC, NASUCA,
Otter Tail, PJM, PJM/NEPOOL Customers, Project Groups, Seattle,
South Carolina Authority, Tri-State. Many of these commenters
support eventual consolidation when any cost and technical barriers
are overcome and if the RTO decides it is necessary.
---------------------------------------------------------------------------
A number of supporters of the hierarchical structure specifically
request that the Commission ensure that the RTO has the authority to
direct all actions at the satellite control centers and that the
satellite centers will be independent in order to prevent
discriminatory transmission service and the transfer of commercially
valuable information to market participants.396 Montana-
Dakota and Otter Tail believe a major benefit of the hierarchical
structure is improved emergency response and system security in a large
region if the RTO is coordinating and directing the actions of all
operators in the region. Finally, Enron/APX/Coral Power believe the
standardization of balancing practices for a large region is an
important benefit of a hierarchical system.
---------------------------------------------------------------------------
\396\ See, e.g., EAL, East Texas Cooperatives, ISO-NE,
Industrial Consumers, LG&E, NASUCA, PJM, PJM/NEPOOL Customers,
Powerex, Project Groups, Tri-State.
---------------------------------------------------------------------------
Commission Conclusion. Which Functions Must an RTO Perform? We
reaffirm the determination proposed in the NOPR that an RTO must have
operational authority for all transmission facilities under its control
and also must be the security coordinator for its region. We recognize
that it is difficult to draw a precise line between transmission
control and generation control,397 and we also recognize
that given the changing nature of the industry, terminology such as
``control area operator'' is undergoing definitional
changes.398 Accordingly, it is difficult to state precisely
what functions an RTO must have in order to have full operational
authority for transmission facilities. Moreover, our desire to allow
RTOs flexibility dissuades us from trying to be too precise. However,
certain concepts are basic and generally understood in the industry.
---------------------------------------------------------------------------
\397\ See NERC Operating Manual Policy 2 which can be found at
www.nerc.com. As we have stated before, the dividing line ``between
transmission control and generation control is not always clear
because both sets of functions are ultimately required for reliable
operation of the overall system.'' Midwest ISO, 84 FERC at 62,151.
The idea that the entity that controls the transmission system must
have some degree of control over some generation seems to be
generally recognized. See Docket No. ER98-1438-000 Applicants'
Response at 3.
\398\ We note that the definition of a control area, and
consequently the functions that must be performed by a control area,
is currently being reexamined by the NERC Control Area Criteria Task
Force in an open forum. See NERC web page at www.nerc.com.
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[[Page 867]]
One necessary aspect of operational authority as used here refers
to the authority to control transmission facilities. This includes, but
is not limited to, switching transmission elements into and out of
operation in the transmission system (e.g., transmission lines and
transformers), monitoring and controlling real and reactive power
flows, monitoring and controlling voltage levels, and scheduling and
operating reactive resources. Functions such as these must be included
within the operational authority of an RTO.
We conclude, as proposed in the NOPR, that the RTO is also required
to be the NERC security coordinator for its region. The role of a
security coordinator is to ensure reliability in real-time operations
of the power system. As security coordinator, the RTO will assume
responsibility for: (1) performing load-flow and stability studies to
anticipate, identify and address security problems; (2) exchanging
security information with local and regional entities; (3) monitoring
real-time operating characteristics such as the availability of
reserves, actual power flows, interchange schedules, system frequency
and generation adequacy; and (4) directing actions to maintain
reliability, including firm load shedding.
We believe that the RTO must be security coordinator for several
reasons. The functions of the security coordinator are enhanced when
they are performed over large regions. In addition, the independence of
the security coordinator is important for ensuring non-discriminatory
transmission service, and the RTO will have that independence. As we
stated in Midwest ISO:
This role [the role of a security coordinator] is central to
maintaining grid reliability and non-discriminatory access. Under
proposed NERC policies, security coordinators would be required to
anticipate problems that could jeopardize the reliability of the
interconnected grid. In the course of performing these reliability
functions, the Security Coordinator would receive considerable
information which is commercially sensitive. Therefore, it is
important that the proposed Midwest ISO Security Coordinator be
performed by an entity that is independent of market
participants.\399\
\399\ 84 FERC at 62,158.
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However, we will allow flexibility in how the RTO performs its
security coordinator functions. For example, an RTO may contract these
responsibilities out to an independent security coordinator if this is
justified. Also, this requirement does not prevent more than one RTO
from sharing a single security coordinator as suggested by NERC.
As proposed in the NOPR, we will not at this time require the RTO
to operate what traditionally has been thought of as a single control
area for its region. However, the RTO must perform the control
functions required to satisfy the minimum characteristics and functions
in this Final Rule, including the transmission control and security
coordinator functions discussed above,\400\ in a non-discriminatory
manner for all market participants.\401\ We will permit those
developing an RTO proposal flexibility in deciding on the particular
division of operational responsibilities with existing control areas.
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\400\ For example, several commenters state that an RTO must
have some authority over generation to ensure system reliability.
The RTO is required to have some authority as a minimum
characteristic, as discussed with respect to short-term reliability.
\401\ In our order approving the Midwest ISO, we stated that our
approval of the ISO was based on the applicants' commitment that the
ISO would be able to ``take all actions necessary to provide
nondiscriminatory transmission service, promote and maintain
reliability.'' Midwest ISO, 84 FERC at 62,159.
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We recognize that the feasibility of consolidating existing control
areas into a single such area may be limited by cost and technical
considerations. However, we note that physical consolidation may be
unnecessary when a hierarchical control structure is used to define a
single control area by making existing control areas subject to RTO
direction (and so avoiding the high costs and technical uncertainty
associated with centralization of physical control for a very large RTO
region). Hierarchical control is a form of power system control that
relies on a master-satellite control structure, which establishes a
single controlling authority without requiring the construction of a
single, consolidated control room. Existing control centers are not
replaced, but continue to operate, independent from market
participants, as satellite control centers reporting to the RTO master
control center. The RTO security center assumes the dual role of the
master control center and security center, with clear authority to
direct all actions at the satellite centers.\402\
---------------------------------------------------------------------------
\402\ See, e.g., Marija Ilic and Shell Liu, Hierarchical Power
System Control: Its Value in a Changing Industry, Springer-Verlag,
1996.
---------------------------------------------------------------------------
We conclude that each region should be free to decide if and when
the region will transition to a hierarchical control structure,
consolidate the control areas in its region, or adopt a different
control structure that best meets the region's needs.
How Should the RTO Perform Its Functions? We conclude that those
designing the RTO should have flexibility to decide how it would
exercise its operational control authority. The RTO operate the
transmission system through direct physical operation by RTO employees,
contractual agreements with other entities (e.g., transmission owners
and control area operators) or implement a hierarchical control
structure involving a combination of direct and functional control.
Under these arrangements, the personnel of existing control centers
might become employees of the RTO or remain as employees of the control
center owner, while being supervised by RTO personnel. We will leave it
to the discretion of the region to decide on the combination of direct
and functional control that works best for its circumstances.\403\
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\403\ This issue is also addressed in greater detail in our
discussion of the RTO's role as a provider of ancillary services as
an RTO minimum function.
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However, regardless of the method of control chosen, the RTO must
have clear authority to direct all actions that affect the facilities
under its control, including the decisions and actions taken at any
satellite control centers. The system of operational control chosen
must ensure reliable operation of the grid and non-discriminatory
access to the grid by all market participants. In addition, to ensure
that the RTO does not become locked into an operational system that is
unsatisfactory, the Commission will require the RTO to prepare a public
report that assesses the efficacy of its operational arrangements no
later than two years after it begins operations.
4. Short-Term Reliability (Characteristic 4)
The fourth proposed characteristic of an RTO is that it must have
exclusive authority for maintaining the short-term reliability of the
transmission grid under its control. In the NOPR we identified four
basic short-term reliability responsibilities of an RTO: (1) the RTO
must have exclusive authority for receiving, confirming and
implementing all interchange schedules; (2) the RTO must have the right
to order redispatch of any generator connected to transmission
facilities it operates if necessary for the reliable operation of these
facilities; (3) when the RTO operates transmission facilities owned by
other entities, the RTO must have authority to approve and disapprove
all requests for scheduled outages of transmission facilities to ensure
that the outages can be accommodated within established reliability
standards; and (4)
[[Page 868]]
if the RTO operates under reliability standards established by another
entity (e.g., a regional reliability council), the RTO must report to
the Commission if these standards hinder its ability to provide
reliable, non-discriminatory and efficiently priced transmission
service.\404\
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\404\ FERC Stats. and Regs. para. 32,541 at 33,735.
---------------------------------------------------------------------------
Comments. General Comments. Commenters address both general
concerns about reliability as well as the four basic proposed short-
term reliability responsibilities of an RTO. Most commenters generally
agree that the RTO should have the responsibility for short term-
reliability.\405\ Several commenters raise questions regarding
definition and scope of ``short-term'' reliability. TEP requests that
the Commission further define the time period involved. It suggests
that designating a specific time period (whether one month, six months
or a year) would be beneficial to evaluating this characteristic.
Enron/APX/Coral Power requests that the Commission make clear that
``short-term'' is intended to mean ``real-time.''
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\405\ See, e.g., American Forest, Cal ISO, California Board,
Cinergy, CMUA, CSU, EAL, Enron/APX/Coral Power, Entergy, EPSA,
Industrial Customers, NASUCA, NECPUC, PJM, PNGC, SMUD, UtiliCorp,
H.Q. Energy Services, Mass Companies, Mid-Atlantic Commissions,
MidWest Energy, Minnesota Commission, NY ISO, PacifiCorp, PG&E,
Williams, WPSC.
---------------------------------------------------------------------------
While agreeing that the RTO should be given ultimate control over
facilities necessary to preserve reliability, SMUD expresses concern
that the RTO should not be encumbered with responsibility for
facilities that do not serve a regional transmission function. TANC
requests that the RTO's responsibility over reliability not infringe on
the management responsibilities of local regulatory authorities or
interfere with the management and operation of the local system
facilities of a utility distribution company.
PG&E requests that the Commission require that the RTO rely
primarily on market mechanisms to maintain reliability. However, PJM/
NEPOOL Customers urge the Commission to ensure that the RTO's actions
in maintaining the short-term reliability of the grid do not
unreasonably impinge on the freedom of business decisions inherent in a
competitive supply market. Several commenters, such as San Francisco
and Minnesota Commission, state that because the primary function of a
RTO is ensuring short-term reliability, it should be more clearly
defined and should not be compromised by any other RTO market
functions.
PJM suggests that the Commission grant additional authorities to
the RTO to ensure reliability, including the authority to (1) collect
information, (2) direct operations in the control area, (3) assure that
those it directs will respond in a predictable manner (which the RTO
can achieve through training and drills) and (4) declare an emergency,
direct emergency operations, and determine when emergency conditions
have ended.
Southern Company notes that the industry has little, if any,
experience in granting a new entity control over the operations of a
transmission system that encompasses a broad, multi-state region.\406\
It claims that transmission owners and State commissions must be
assured that the RTO is capable of operating a regional transmission
system reliably before an RTO is formed. New York Commission indicates
that the authority of States to require the maintenance of electric
system reliability should be recognized in establishing
responsibilities. Iowa Board believes that there is a need for greater
regional development of reliability standards to reflect regional needs
and conditions. It requests that State commissions be involved in the
decisionmaking process of an RTO to ensure that electric facilities are
properly sized and located and that additions are not detrimental to
the reliability of the grid.
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\406\ Southern Company notes that the California and ERCOT ISOs
operate within the boundaries of a single state. In PJM, New York
and New England, the control of the grid remains remarkably
unchanged because the ISOs in those regions were already operating
the system on behalf of the transmission owners and adopted the
institutions and infrastructures of an ISO.
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Comments on Interchange Scheduling. The Commission proposed that,
in the context of the RTO's role as the recipient and evaluator of all
requests for transmission service under its own FERC-approved tariff,
an RTO that is a control area operator must also receive, confirm, and
implement all interchange schedules between adjacent control
areas.\407\ The Commission expressed concern that non-RTO control area
operators would receive commercially sensitive information involving
its competitors in implementing interchange schedules and questioned
whether there is any Commission action, other than its current code of
conduct standards, and short of requiring consolidation of all control
areas within a region, which could address this concern.
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\407\ FERC Stats. & Regs. para. 32,541 at 33,735-36.
---------------------------------------------------------------------------
Several commenters agree that the RTO should have authority over
receiving, confirming and implementing all interchange schedules.\408\
PJM believes that an independent ISO is in the best position to
exercise the scheduling authority of an RTO. It suggests that an RTO
that is independent of commercial interests in the market does not face
the commercial information problem because it does not compete with
market participants and consequently would make scheduling decisions in
an unbiased and fair manner.
---------------------------------------------------------------------------
\408\ See, e.g., Cal ISO, CMUA, Entergy, Mass Companies, NECPUC,
Nevada Commission, PJM/NEPOOL Customers, PJM, SMUD, Southern
Company, WPSC, PG&E.
---------------------------------------------------------------------------
PJM/NEPOOL Customers claims that interchange scheduling oversight
must be performed by an independent entity because it would be neither
possible nor desirable for a non-RTO control area operator to perform
this function without access to commercially sensitive information. It
suggests that the RTO maintain direct control over interchange
scheduling either by using RTO employees or a master satellite
arrangement where ultimate responsibility remains in the RTO master
control area operating room. APX suggests that requiring a contractor
(acceptable to the RTO and the control area operator) to operate the
control area operator facility could help address this concern.
Enron/APX/Coral Power believes that the risk is eliminated if
transmission operations, including control-area operations, are
operationally separated from the load and generation of vertically-
integrated utilities. Barring such complete separation, this risk could
nevertheless be substantially obviated if the RTO provided control area
operators with information only about scheduled net interchanges
between control areas without disclosing the individual transactions
making up the new schedules.\409\
---------------------------------------------------------------------------
\409\ See also Southern Company.
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However, other commenters contend that control area operators will
continue to need information on individual transactions in order to
implement interchange schedules and to ensure real-time
reliability.\410\ Desert STAR believes that work should be done in this
area to determine what information is required by control area
operators and when they must receive it in order to carry out their
reliability responsibilities.
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\410\ See, e.g., Duke, Florida Power Corp.
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Florida Commission states that this issue has already been resolved
within the Florida Reliability Coordinating Council (FRCC) by requiring
all entities who operate control areas within the
[[Page 869]]
region that require access to commercially sensitive information to
sign agreements that separate reliability personnel and the relevant
information from their wholesale merchant personnel.
Several commenters, such as Duke and Florida Power Corp., state
that no additional Commission action is necessary. These commenters
believe that the existing code of conduct standards are working and the
reciprocity provisions of Order No. 888 provide for compliance with the
code of conduct standards by all non-public utility control area
operators. Florida Power Corp. also notes that within the FRCC, all
entities operating control areas are required to sign agreements
verifying functional separation.
Comments on Generation Redispatch. In the NOPR, the Commission
proposed that the RTO's reliability authority include the ability to
order redispatch of any generator connected to the transmission grid
when necessary for the reliability of the grid. However, the RTO would
have no authority over initial unit commitment and normal dispatch
decisions.\411\
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\411\ FERC Stats. and Regs. para. 32,541 at 33,736.
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Several commenters agree that the RTO have some authority to order
redispatch when necessary to maintain the reliability of the grid.\412\
Sithe, however, believes that, in the evolving competitive marketplace,
redispatch authority alone is insufficient. It argues that the RTO
should also provide appropriate incentives to the owners of assets that
are needed for reliability to maintain those assets and make them
available for operation in constrained areas. Sithe urges the
Commission to consider adopting a final rule that provides RTOs with
sufficient commercial authority, ``including the necessary financial
resources'' to enter into market-rate business arrangements, that
assure availability of assets needed for reliability. Sithe states that
without this authority, the RTO may not have sufficient tools to fully
ensure reliability, because must-run generators would have little
incentive to continue to operate in constrained areas.
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\412\ See, e.g., Cal ISO, Cinergy, CMUA, NECPUC, PJM, UtiliCorp,
Entergy, Allegheny, LG&E, Lincoln, Metropolitan, Minnesota Power,
Nevada Commission, Otter Tail, Southern Company, TDU Systems,
NASUCA, Reliant, Mass Companies, TAPS.
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CMUA maintains that it is insufficient to vest authority in the RTO
to maintain short-term reliability without also vesting enforcement
powers to ensure compliance with RTO dispatch instructions. Allegheny
and other commenters agree that RTOs should be able to direct
redispatch, particularly if the redispatch is accomplished under a
market-based compensation scheme as a part of transmission service
pricing methodology that uses the redispatch costs to set marginal
system use costs. However, they argue that in no case should the RTO be
able to direct generation redispatch unless the generator is
compensated at market value (unless market power issues are
involved).413
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\413\ See, e.g., Cinergy, Chelan, Southern Company, LG&E,
Reliant.
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Avista expresses serious concern with the breadth of a redispatch
requirement. It believes that the right to order redispatch of
generation should be negotiated among the parties in the region without
a presumption that the RTO must have broad redispatch authority, except
in emergency circumstances. Avista and others note that a negotiated
approach is particularly important to operators of hydroelectric
resources which are subject to numerous environmental and operating
restrictions that limit their ability to redispatch.414
Avista and SMUD request that the Commission clarify that the RTO's
authority to redispatch is limited to emergency circumstances affecting
reliability.
---------------------------------------------------------------------------
\414\ See, e.g., CMUA.
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Chelan believes that RTOs should be required to enter into arm's-
length agreements with those generators that are willing to service
redispatch requests, and compensate those generators for supplying this
service. RTOs should not be allowed to unilaterally redispatch a
generating unit without the generator's consent, and without
compensation.
Commenters, such as Cal ISO and Nevada Commission, suggest that the
Commission require reliability-related services (i.e. redispatch) be
provided to RTOs under a set of uniform rates, terms and conditions.
Such a requirement would reduce the Commission's administrative burden
of contracts governed by different sets of terms and conditions.
EME believes that the RTO's control over dispatch of generation
should be carefully circumscribed. It recommends that reliability
functions be internalized into explicit procedures for congestion
pricing. It states that in most cases proper pricing signals can
provide sufficient incentives for generators to schedule operation of
their facilities to ensure system reliability.
Industrial Consumers states that the RTO's redispatch decisions
regarding ``any generator'' must be qualified to excuse on-site
generators that serve an industrial load, especially those that serve a
critical steam host. For environmental, safety and economic reasons,
these units should not be forced to redispatch except as a last resort
option.
Metropolitan supports an RTO having authority to order redispatch
of any generating unit when necessary for the reliability of the grid.
However, ``reliability'' must be carefully defined to avoid RTO
interference with normal market operations by redispatching generation
for its own convenience, or to alleviate adverse market
conditions.415
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\415\ Metropolitan believes the Cal ISO's definition of system
emergency appropriately describes the circumstances in which
redispatch may be appropriate. A ``system emergency'' is described
as ``any abnormal system condition which requires immediate manual
or automatic action to prevent loss of load, equipment damage or
tripping of system elements which might result in cascading outages
or to restore system operation to meet the minimum operating
reliability criteria.''
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Several commenters oppose the proposal to allow the RTO to
redispatch generation.416 PG&E believes that the proposal
would give too much latitude to RTOs and create an incentive to impose
centrally determined fixes on market operations, rather than allowing
market mechanisms to self-correct. Therefore, PG&E argues that RTOs
should be allowed to redispatch generation facilities only when there
is a true reliability emergency as specified in the RTO tariff.
Moreover, RTOs should be able to redispatch only those units that have
actually participated in the market.
---------------------------------------------------------------------------
\416\ See, e.g., PG&E, Southern Company, Reliant, SMUD.
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PJM/NEPOOL Customers believes that the authority as proposed in the
NOPR is too broad and must be further defined. It requests that the
Commission ensure that this authority is exercised only during only the
most serious circumstances when grid reliability is truly in danger. It
suggests that the Commission promulgate or pre-approve reliability
standards for determining when the RTO can order redispatch of
generators, the amount of generation assets that the RTO will have
authority over and standards for the redispatch order. Southern Company
recommends that the Commission provide only general guidance concerning
redispatch and allow the regions to develop more specific procedures.
When considering allowing an RTO to redispatch a Federal
hydroelectric generator, SPRA emphasizes that the Commission must
recognize that individual Federal hydroelectric generators are under
the control of either the Corps, the Bureau of
[[Page 870]]
Reclamation or the International Boundary Waters Commission, not the
PMA. While a PMA may belong to an RTO, it is unlikely that other
Federal agencies will. The Commission must give careful consideration
to determine that RTO redispatch authority does not prohibit or limit a
PMA's ability to fulfill its statutory obligations.
Comments on Transmission Maintenance Scheduling. In the NOPR, the
Commission proposed that an RTO which operates transmission facilities
owned by other entities be authorized to approve or disapprove all
requests for scheduled outages of transmission facilities in order to
ensure that maintenance outage schedules meet applicable reliability
standards.417
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\417\ FERC Stats. and Regs. para. 32,541 at 33,736-37.
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The Commission requested comments on a number of issues related to
this proposed requirement: Does it cede too much or too little
authority to the RTO? If the RTO requires a transmission owner to
reschedule its planned maintenance, should the transmission owner be
compensated for any costs created by the required rescheduling? Would
it be feasible to create a market mechanism to induce transmission
owners to plan their maintenance so as to minimize reliability effects?
Should an RTO that is an ISO have any authority to require rescheduling
of maintenance if it anticipates that the planned maintenance schedule
will adversely affect power markets? If the RTO is a transco, can it
manipulate its transmission maintenance schedules in a manner that
harms competition?
The Commission stated that the RTO's regional perspective will
allow it to coordinate individual maintenance schedules with each other
as well as with expected seasonal system demand variations. Because the
RTO will have access to extensive information, it will see the ``big
picture'' and be able to make more accurate assessments of the
reliability effect of proposed maintenance schedules than individual,
sub-regional transmission owners.
Commenters address essentially three issues related to transmission
maintenance scheduling: the RTO's authority; appropriate compensation;
and use of market mechanisms.
RTO Authority to Schedule Transmission Maintenance. Many commenters
support giving an RTO authority over transmission maintenance
scheduling.418 Duke, however, believes that an enforcement
mechanism may also be needed. First Rochdale recommends that
transmission owners be given the right to protest an RTO's actions to
the Commission. Reliant, however, opposes RTO authority over
maintenance scheduling, arguing that transmission maintenance decisions
must reside with transmission facility owners.
---------------------------------------------------------------------------
\418\ See, e.g., Cal ISO, NECPUC, PJM, Desert STAR, Entergy,
PGE, Allegheny, Avista, LG&E, Lincoln, Tri-State, WPSC, CRC, Duke,
EAL, First Rochdale, Industrial Consumers, ISO-NE, Metropolitan,
Montana-Dakota, NASUCA, New Smyrna Beach, NYPP, Oneok, PG&E,
Southern Company, SRP, Turlock, WPPI, Florida Power Corp., Nevada
Commission.
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Seattle and NYPP suggest that the Commission define an RTO role
only for scheduling facility outages that are clearly associated with
the regional transmission network because internal subtransmission and
radial transmission facilities do not have regional significance.
Turlock supports restricting the RTO's authority to the grid it manages
to prevent its outage scheduling authority extending beyond the grid
for which it is responsible. On the other hand, TDU Systems claims that
an RTO should also coordinate maintenance of interconnected
distribution facilities that are not under its control, if maintenance
on those facilities would adversely affect RTO operations.
Duke suggests that with the creation of an RTO that is not a
transco, a set of governing principles for outage coordination should
be established. The parties should agree on the timing of requests for
planned maintenance and the timing of responses to those requests. If
for any reason, other than the gross negligence of the transmission
owner, a scheduled maintenance outage was determined to be a problem
after an agreement is reached, rescheduling the outage would require
the mutual consent of the transmission owner and the RTO.
EAL recommends that appropriate contracts with existing
transmission facility owners that ensure the continued reliable
operation of the grid are required. Principal elements of such
contracts would include standards of service, provisions for
information sharing and reporting, maintenance scheduling, transmission
facility ratings, testing and performance expectations. Maintenance
scheduling should include provisions for maintenance deferral under
instructions from the RTO if required for system security reasons only.
NYPP states that arrangements for outages should be made well in
advance of the outage start date because RTO approval of proposed
schedules could become the critical path. If approval is delayed, or
subsequently revoked, the transmission owner will incur significant
expenses that should be reimbursed.
Montana-Dakota suggests that the effects of rescheduling can be
decreased by having the RTO review and approve all transmission
maintenance schedules on a weekly, monthly and quarterly basis. After
reviewing the transfer capability and market effects of the proposed
outage, the RTO should communicate the need to reschedule to the
transmission owner far enough in advance of the planned outage to allow
the owner to reschedule, possibly to avoid any cost impact. Montana-
Dakota notes, however, that the closer the date of the outage, the
higher the probability of an economic impact.
Southern Company requests that the Commission clarify that once an
RTO approves a scheduled outage, it should be allowed to change that
schedule only if implementing the plan would compromise system
integrity or reliability.
Seattle believes that the NOPR fails to provide adequate assurances
to transmission owners that a timely maintenance schedule will be
adopted by the RTO. The RTO must establish timely dates certain for
maintenance outage requests from operating entities. To do this the RTO
must adequately balance safety considerations, and the cost of
deferring maintenance with commercial impact. For these reasons, an RTO
should not be permitted to arbitrarily postpone required maintenance.
Compensation. Nearly all of the commenters believe that
transmission owners should be compensated in some form if they are
required by an RTO to reschedule maintenance.419 Avista
argues that the transmission owners' shareholders should not bear the
burden of decisions made by an independent body that result in reduced
revenues or increased costs for the transmission owner.
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\419\ See, e.g., PJM, TANC, WPSC, Avista, Lincoln, CRC, Duke,
Metropolitan, Minnesota Power, Montana-Dakota, NASUCA, NPRB, NYPP,
PJM/NEPOOL Customers, Reliant, TDU Systems, Turlock, Florida Power
Corp., Reliant, Desert STAR, Southern Company.
---------------------------------------------------------------------------
Metropolitan states that if an RTO requests a transmission owner to
reschedule planned maintenance for reliability concerns, a transmission
owner should be compensated only for its direct costs necessarily and
reasonably incurred in complying with the RTO's request. Direct costs
may include, for example, increased labor or equipment expenses arising
from the rescheduled maintenance. However, Metropolitan does not
believe a transmission owner should recover lost
[[Page 871]]
opportunity costs arising from the rescheduled maintenance because
opportunity costs are uncertain and speculative.
Southern Company argues that, if an RTO requires a transmission
owner to reschedule a previously approved outage, the RTO should
compensate the transmission owner for any additional costs caused by
the rescheduling.
NASUCA believes that the RTO should compensate transmission or
generation owners only to the extent that incremental costs are
incurred due to the rescheduling of outages. NASUCA argues that it is
unlikely that owners would incur significant incremental costs,
especially for transmission outages.
Some commenters such as PGE and Minnesota Power state that if an
RTO requires a transmission owner to reschedule its planned maintenance
for reliability reasons in an emergency situation, the RTO should not
be required to compensate the transmission owner. However, if an RTO
requires a transmission owner to reschedule its planned maintenance for
economic reasons, the RTO should be required to compensate the
transmission owner for liquidated damages.
Other commenters such as Tri-State and Cal ISO oppose transmission
owners being compensated for the rescheduling of maintenance work. Cal
ISO states that, where an RTO properly exercises such authority by
requiring a transmission owner to reschedule a maintenance outage, that
transmission owner is not entitled to compensation for the costs
associated with rescheduling. Tri-State recommends factoring any
additional expense into the revenue requirement that the transmission
owner receives from the RTO.
Market Mechanisms. PJM/NEPOOL Customers suggests that the RTO enact
a compensation mechanism in transmission outage rescheduling situations
or propose to use a market mechanism to encourage transmission owners
to plan maintenance so as to minimize reliability effects. Minnesota
Power, however, argues that maintenance rescheduling to benefit power
markets is analogous to generation redispatch and should be paid for by
the benefitting market participants.
Montana-Dakota believes that an RTO should have the authority to
reschedule maintenance for market effects if there is an incremental
cost reimbursement mechanism in place that would provide an incentive
to the transmission owner to change maintenance schedules to benefit
the market.
Metropolitan argues that an RTO with authority to unilaterally
reschedule transmission maintenance for market considerations could
have a destabilizing effect on the power market. Emerging markets
require predictability to thrive, and therefore RTOs should interfere
in market operations only when necessary to address reliability
concerns.
Florida Power Corp. suggests that, while it may be feasible to
develop a market mechanism to induce transmission owners to plan their
maintenance to minimize reliability effects, it would be far simpler to
retain the existing structure in which a single entity both owns and
operates the transmission system. When ownership and operation are
combined, a single entity is responsible for both reliability and
maintenance, and thus has a natural incentive to seek an optimal
balance between these activities. Thus, Florida Power Corp. opposes
RTOs having authority to reschedule maintenance to manage the
performance of the market.
Turlock also does not believe an RTO should have authority to make
transmission outage decisions based on market considerations. Turlock,
as well as Desert STAR and CRC, believe instead that consideration
should be given to motivating transmission owners to appropriately
schedule their maintenance outages, to minimize impacts on competitive
markets.
Comments Generation Maintenance Scheduling. The short-term
reliability characteristic, as proposed in the NOPR, would not give an
RTO authority over proposed generation maintenance outage schedules.
However, the Commission noted that some generation control is necessary
for reliable operation of a transmission system. The Commission asked
whether an RTO should have some authority over generation maintenance
schedules and, if so, how much.420
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\420\ FERC Stats. and Regs. para. 32,541 at 33,737.
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The majority of commenters support an RTO having at least some
authority over generation maintenance schedules.\421\ However, most
commenters suggest limiting the RTO's authority. Some commenters
suggest that an RTO have authority only for generating units that are
``must-run'' or that the RTO has under contract due to the requirement
to maintain system reliability.\422\ Desert STAR believes that an RTO
should not attempt to manipulate the commercial power market when
reliability is not affected.
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\421\ See, e.g., Cinergy, NECPUC, PJM, Desert STAR, WPSC, Cal
ISO, EAL, Industrial Consumers, ISO-NE, Turlock, Florida Power
Corp., Metropolitan, Minnesota Power, Montana-Dakota, NASUCA, Nevada
Commission, NYPP, PSNM, TDU Systems.
\422\ See, e.g., Desert STAR, Metropolitan, Turlock, Florida
Power Corp., PSNM, NYPP.
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Cinergy supports an RTO having the ability to request changes to a
schedule to serve reliability needs, coordinate transmission outages,
and maximize grid efficiency to increase ATC for transmission
customers' use, so long as generators receive compensation at market-
based prices for missed market opportunities. Other commenters agree
that an RTO should compensate the generation owner if a schedule change
is necessary.\423\
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\423\ See, e.g., WPSC, LG&E, Montana-Dakota.
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A few commenters claim that the RTO should not have any authority
over generation maintenance schedules.\424\ SPRA states that requiring
such authority would discourage or prevent participation by PMAs
because other Federal agencies own the hydroelectric plants that
generate the power marketed by the PMAs.
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\424\ See, e.g., Duke, PJM/NEPOOL Customers, SPRA, Tri-State,
Empire District.
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Tri-State does not believe that an RTO should have approval
authority over generation maintenance outages because these outages are
driven by the cost considerations associated with generation plant
equipment replacement or rehabilitation. However, Tri-State agrees that
an RTO must have advance knowledge of the scheduled generation outages
in order to assure transmission system reliability and adequacy of
reserves. Other commenters concur with a notification requirement.\425\
Cinergy notes, however, that while it believes a generator may be
required to submit its maintenance schedule to an RTO, the RTO should
be prohibited from sharing that information with any other market
participants, or affiliates of market participants.
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\425\ See, e.g., Enron/APX/Coral Power, FirstEnergy, Mass
Companies, Metropolitan.
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Comments on Performance Standards. In the NOPR, the Commission
discussed the establishment of performance standards by an RTO for
transmission facilities under its direct or contractual control.\426\
For example, an RTO could establish a standard that identifies specific
performance targets for planned and unplanned outages of facilities.
The Commission requested comments on whether a non-profit ISO could
establish incentive schemes for the transmission owners whose
facilities it operates.
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\426\ FERC Stats. and Regs. para. 32,541 at 33,737.
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PJM believes that an RTO will be capable of developing performance
[[Page 872]]
standards and incentives to encourage transmission owners and
generators to operate and maintain reliable facilities. It states that
market participants cooperatively can create market-oriented incentives
to maintain their transmission and generation facilities
effectively.\427\
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\427\ See also LG&E.
---------------------------------------------------------------------------
Duke also believes that incentive schemes can be developed. It
suggests that the revenues collected from users by the RTO could be
returned to transmission owners according to a prearranged formula that
incorporates quality standards for reliability. Thus, the revenue
allocation would reflect transmission owner performance in providing a
reliable system.
PSE&G believes that RTOs will, and should, be able to offer
incentives to participants to ensure that reliability standards are not
only met but exceeded. It states that a mechanism of linking payment
with performance, measured against accepted benchmarks, has worked well
for many years in PJM.
EAL states that appropriate contracts with existing transmission
facility owners that ensure the continued reliable operation of the
grid are required. It suggests that these contracts include standards
of service, provisions for information sharing and reporting,
maintenance scheduling, transmission facility ratings, testing and
performance expectations.
Industrial Consumers believes that an RTO could establish
performance standards for transmission facilities that takes into
account the ``reliability'' of each facility. It argues that a facility
that has frequent unplanned outages should not receive the same
compensation as a facility whose availability is more reliable. It
suggests that a transmission owner be precluded from recovering fixed
costs during periods of unplanned outages that exceed some minimum
threshold based on superior performance.
Cal ISO indicates that its tariff provides for the implementation
of maintenance standards, and penalties under those standards, to
ensure both adequate maintenance and system reliability. These
provisions act in concert with the California ISO's authority to
coordinate and approve maintenance outages.
Southern Company believes that the establishment of performance
standards for transmission facilities controlled by an RTO is
misplaced. Transmission owners plan and operate their transmission
systems according to NERC and regional reliability standards, as well
as State legal and regulatory requirements. Thus, while Southern
Company doesn't claim that performance-based incentives are
inappropriate, it points out that there already are existing standards
to ensure reliable system operations.
Comments on Facility Ratings and Operating Ranges. Reliable
operation of the transmission system in the short-term requires both
continuous monitoring of equipment availability and loading, and
actions to maintain loading levels within the established operating
ranges and equipment ratings. The NOPR suggested that RTOs are best
situated to establish ratings and operating ranges for two reasons.
First, they will have the most complete information about expected and
real-time operating conditions. Second, RTOs will be trusted because
they will not have any economic interests in electricity market
outcomes and they will not be owned or controlled by any market
participants. The Commission proposed to let RTO established equipment
ratings prevail in a dispute with a transmission owner pending the
outcome of a dispute resolution process.\428\
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\428\ FERC Stats. and Regs. para. 32,541 at 33,737-38.
---------------------------------------------------------------------------
Nearly all commenters that address this issue oppose the NOPR
proposal. South Carolina Authority urges the Commission to proceed with
caution to prevent avoidable damage to persons or property. SRP argues
that ratings and operating ranges influence the useful life and
maintenance cost of equipment, as well as the level of service to the
end-use customer, and notes that each transmission owner has a
legitimate interest in the ratings. SRP believes that the ideal
situation would be to establish ratings by mutual consent of the
transmission owner and RTO. If they cannot agree, the issue should go
to dispute resolution.
NYPP and Mass Companies oppose this proposal because transmission
owners have the fiduciary responsibility to protect their assets.
Furthermore, they state that the rating of equipment necessarily
requires a particularized knowledge of the equipment and related
facilities that is unlikely to be possessed by the RTO.
Metropolitan believes that a well-established reliability
organization is best suited for establishing maximum transmission line
ratings that can be sustained over most of the hours in a year because
it will include the cooperation of technical groups representing all
systems, not just those under RTO control. It sees no benefit from
moving this responsibility to RTOs when the reliability councils have
historically performed this function with a minimum of controversy. EAL
suggests that since the owner of the transmission facility assumes the
equipment, personnel and public risks for the operation of its
equipment, the RTO could fulfill an audit role to ensure that facility
ratings by the owners follow industry norms.
Seattle suggests that the Commission instruct RTOs to work
cooperatively with facility owners, since ratings on most power
transmission equipment are a function of age and past usage, and a new
entity will not have such historical information.
Southern Company states that transmission owners have
responsibilities to their shareholders and State commissions to operate
their equipment safely and reliably. SPRA believes that this proposal
has the potential to create significant liability risks for the United
States.
Entergy believes that a transco has an advantage at performing this
function because it will have the natural incentive to maintain the
highest and safest ratings for the transmission facilities since it
will be solely and directly responsible for the risks and rewards of
equipment ratings.
Comments on Liability for Actions. Given that an RTO has
responsibility for system reliability, the NOPR requested comments on
the appropriate extent of an RTO's liability for its actions, and
whether RTO facility ownership changes this determination.\429\
---------------------------------------------------------------------------
\429\ FERC Stats. and Regs. para. 32,541 at 33,738.
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Most commenters believe that liability must be linked to the entity
operating and controlling the transmission assets. Several commenters
recommend that all RTO governing documents and operating agreements
clearly establish the RTO's liability for any facilities that it
operates but does not own.\430\ SRP recommends that the Commission not
set a hard and fast rule, but rather give deference to assignments of
liability worked out between the RTO and the transmission owner in the
course of negotiating an operating agreement.
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\430\ See, e.g., Seattle, PGE, Desert STAR, PSNM, South Carolina
Authority.
---------------------------------------------------------------------------
Salomon Smith Barney believes that an RTO should be paid to run the
network, and should suffer the consequences if it is not run well.
Given this reasoning, it believes that an RTO requires sufficient
capital to bear the risk, and that it operates under a regulatory
scheme that acknowledges that higher risk taking requires a higher
return.
Other commenters focus on how to apportion liability. Several
commenters
[[Page 873]]
suggest that the governing standard for liability for a particular
activity should be the same standard that the Commission has approved
for comparable ISO conduct. Thus, for example, the RTO would be subject
to liability only on account of its reliability activities when damage
caused by its actions is found to be the result of gross negligence or
intentional misconduct.\431\
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\431\ See, e.g., NY ISO, Cal ISO, Nevada Commission, New York
Commission.
---------------------------------------------------------------------------
Other commenters believe that, if the RTO assumes authority to
ensure proper maintenance and reliability of the system, it should
assume that role fully (i.e., assume liability for its decisions) and
it should hold transmission owners harmless for any increased cost
responsibility.\432\
---------------------------------------------------------------------------
\432\ See, e.g., Avista, Minnesota Power, SPRA, MidAmerican,
Florida Power Corp.
---------------------------------------------------------------------------
Tri-State believes that an RTO should not be held liable for the
inevitable errors and omissions that will occur during transmission
system operations except in the instance of gross negligence. It
believes that without some form of indemnification, the RTO could be
the target of numerous lawsuits alleging financial harm as a result of
RTO actions.
TANC believes that the RTO should be held liable for the
consequential damages resulting from the RTO's instructions, if damage
is caused to the transmission owners facilities as a result of the RTO
requiring a transmission owner to operate its facilities in a manner
that is inconsistent with prudent utility practice.
Comments on Reliability Standards. In the NOPR, the Commission
expressed a potential concern regarding an RTO's implementation of
reliability standards that are established by another entity. The
Commission identified two specific concerns: (1) regional or sub-
regional reliability groups may not be as independent from market
participants as RTOs; and (2) almost every reliability standard will
have a commercial consequence. The NOPR proposed to require an RTO to
notify the Commission immediately if implementation of externally
established reliability standards will prevent it from meeting its
obligation to provide reliable, non-discriminatory transmission
service.\433\
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\433\ FERC Stats. and Regs. para. 32,541 at 33,738-39.
---------------------------------------------------------------------------
Most commenters generally support the proposal in the NOPR,
although a few commenters believe that the NOPR proposal does not go
far enough. On the other hand, some commenters seek clarification or
oppose the NOPR proposal; most commenters that oppose the NOPR proposal
believe that RTOs must be subordinate to national or regional
reliability groups.
PJM/NEPOOL Customers and other commenters agree that the RTO is an
appropriate institution to evaluate whether other rules and
requirements are impacting its ability to perform its function and to
inform the Commission of this fact.\434\
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\434\ See, e.g., Entergy, NECPUC, NASUCA.
---------------------------------------------------------------------------
PSE&G requests that the Commission clarify in its Final Rule that
RTOs, not reliability trade associations, will have primary
responsibility for resolving reliability issues in the future. It
suggests that reliability trade associations can continue to play a
role in developing reliability standards to be incorporated into RTO
tariffs; these standards would then be implemented by the RTOs and
ultimately enforced by the FERC. The standards, however, must be
developed through a fair and open consensus process, such as the
American National Standards Institute (ANSI) process.
EPSA believes that reliability standards should be uniform
throughout the United States. Reliability standards should be
established at the national level through an industrywide
representative organization, subject to review and approval by the
Commission. Reliability rules should deviate regionally only if
necessary to reflect specific operating conditions that are unique to a
particular region. EPSA requests that existing reliability rules be
considered carefully by the RTO, and reviewed by the Commission, as to
their function and importance. EPSA and other commenters suggest that
RTOs replace existing regional reliability councils as the entity
responsible for maintaining compliance with nationally established
reliability standards.\435\
---------------------------------------------------------------------------
\435\ See, e.g., Cal ISO, Duquesne, Nevada Commission, Statoil.
---------------------------------------------------------------------------
Conlon claims that the RTO must have the ability to establish
various reliability standards that every participant. He suggests that
the RTO, or the Commission with delegated authority to the RTO, set
mandatory standards and impose sanctions or fines for violations.
Cal ISO believes that RTOs are the appropriate entities to
establish reliability standards. Regional organizations (not a single
national standard-setter) should have the flexibility to develop
standards that reflect regional priorities as well as individual issues
related to particular areas or configurations in the transmission grid.
It recommends that RTOs have the authority and responsibility to
develop regional reliability standards, subject to general oversight by
an appropriate independent national reliability organization such as
NAERO.
Similarly, Entergy believes that the RTO should have the primary
role, authority and responsibility to adopt, implement and enforce
regional reliability standards. Entergy further argues that this
authority must be subject to regional oversight, especially as to
reliability issues between and among interconnected RTOs.
Some commenters argue that the Commission should provide additional
authority to RTOs. For example, PJM believes that an RTO should have
exclusive authority for administering the regional reliability of the
bulk power system. It argues that no entity external to an RTO's region
should have authority to dictate reliability rules that adversely
affect the reliability in a region served by an RTO. Thus, PJM believes
the Commission should extend this proposal beyond the proposed
reporting requirement. In its opinion, RTOs that are responsible for a
particular area of the bulk power market system best can develop tools
that are designed to meet the needs of their individual areas. PJM
requests that the Commission insist in its rule that RTOs play a
significant role in setting any national reliability standards. Sithe
suggests that RTOs should also have independent authority to modify
existing rules, and/or to place new rules before the Commission for its
review and approval in order to promote rules that intrude less into
the markets and that promote efficiency goals, as well as system
reliability.
Illinois Commission argues that the proposal is not adequate and
that the Commission must more directly address the concern over lack of
independence between reliability standards development, enforcement
organizations and commercial market interests. Illinois Commission
suggests some possibilities: (1) require NERC/regional reliability
council reform so that the process of establishing and enforcing
reliability guidelines, standards, and policies is independent of
discriminatory generation/transmission owner influence; (2) require
that all NERC/regional reliability council guidelines, standards, and
policies be approved by FERC prior to their adoption; or (3) reform
NERC so that it is independent of generation/transmission owners, then
eliminate MAIN and ECAR and require the Midwest ISO to act as the
regional standards setting entity and as the
[[Page 874]]
reliability enforcement entity for the Midwest Region.
A few commenters seek clarification.\436\ British Columbia Ministry
requests that the Commission clarify how the RTO roles and
responsibilities overlap with duties outlined for the Self Regulating
Reliability Organization in the North American Electric Reliability
Council's draft legislation. New York Commission and Iowa Board request
that the Commission recognize the authority of the states to require
the maintenance of electric system reliability.
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\436\ See, e.g., Canada DNR, Manitoba Board, Cal DWR, Entergy,
Minnesota Commission, PSE&G.
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NERC and several other commenters generally oppose the proposal.
NERC urges the Commission to include an obligation that the RTO adhere
to the reliability rules adopted by NERC and the relevant regional
reliability council as a condition of becoming an RTO. NERC states that
RTOs must be designed, implemented and operated consistent with NERC
operating and planning policies. NERC notes it will revise its
operating and planning policies to recognize and accommodate these
emerging institutions, as necessary.
Several commenters such as Duke and SERC supports the work of NERC
to establish consistently applied reliability standards and supports
NERC's authority to enforce these standards. Duke also supports NERC
and the regional reliability councils continuing to play a vital role
in setting reliability standards. NERC oversight of reliability should
prevent different RTOs from applying different standards and will
ensure that inter-RTO reliability matters will be dealt with
effectively. CEA suggests that the reliability responsibilities
authorized for RTO's be respectful of the carefully balanced design of
the evolving NERC/NAERO.
SRP requests that each RTO be required to join NERC, or NAERO when
formed. In addition, other commenters such as SRP and Los Angeles
propose that RTOs be required to use planning and design criteria that
comply with the criteria established by the appropriate NERC (or NAERO
when established) regional reliability council.
NYPP believes that properly constituted local and regional
reliability councils authorized by FERC should have the authority to
establish criteria necessary to maintain the reliability of the
transmission system including the reliability of discrete locations
(e.g., the supply of reactive power to support voltage in load
pockets).\437\
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\437\ The Commission has authorized the establishment of the New
York State Reliability Council and has accepted the relationship
between it and the NY ISO.
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FirstEnergy requests that the role of the regional reliability
councils be clarified with respect to regional RTOs. Also it would have
us identify the need boundaries so that each RTO reports only to one
regional reliability council. In addition, the regional reliability
councils may need to undergo a transformation similar to NERC/NAERO to
expand the role of the various industry segments.
Commission Conclusion. The Commission adopts the proposal in the
NOPR that the RTO must have exclusive authority for maintaining the
short-term reliability of the grid that it operates. Although many
commenters support this requirement, some pose additional questions
regarding how this function will be performed by the RTO. Some
commenters request that the Commission define better the time period
associated with ``short-term'' reliability. We clarify that the term
``short-term'' is intended to cover transmission reliability
responsibilities short of grid capacity enhancement. It includes all
time periods, including but not limited to ``real-time,'' necessary for
the RTO to satisfy its reliability responsibilities, up to the planning
horizon. There is no time gap between what is included within short-
term reliability and the RTO's planning responsibilities.
Commenters also request more specificity in describing the RTO's
functions. The facilities that will be under RTO control, the specific
functions that the RTO must perform, and how the RTO will execute its
responsibilities and direct operations, are all defined above in the
section on operational authority. PJM's additional request that the RTO
have authority to collect information is discussed in both the
operational authority and the market monitoring sections.
PG&E requests that the RTO rely on market mechanisms to maintain
short-term reliability. PJM/NEPOOL Customers requests that reliability
and commercial activities be kept separate. We will not require the RTO
to rely on market mechanisms in every instance to maintain short-term
reliability. The Commission believes that some reliability functions
may not be conducive to supply through competitive market mechanisms
since a reliable power system provided to one customer cannot be
withheld from other customers, viz., many reliability functions are, in
economic terms, ``public goods.'' In Order No. 888, we identified some
functions necessary to maintain grid reliability as ancillary services
and required them to be provided as separate products. These services
and their potential inclusion in emerging markets is discussed in the
section on ancillary services below. We cannot conclude at this time
that it is appropriate to rely solely on market mechanisms to supply
the reliability functions that the transmission system operator must
perform, but we expect that over time most of the generation services
that perform these functions will be competitively procured.
Interchange Scheduling. We conclude that the RTO must have
exclusive authority for receiving, confirming and implementing all
interchange schedules, which are often coincident with schedules for
unbundled transmission service. This function will automatically be
assumed by RTOs that operate a single control area. If the RTO
structure includes control area operators who are market participants
or affiliated with market participants, the RTO will have the authority
to direct the implementation of all interchange schedules. As stated in
the NOPR, a remaining concern is that non-RTO control area operators,
who are also competitors in energy markets, have unequal access to
commercially sensitive information and could use this knowledge of
their competitors' schedules and transactions to gain an unfair
competitive advantage in the energy markets. In the event that the RTO
filing includes a structure in which non-RTO control area operators
receive sensitive information, we will require the RTO to monitor for
any unfair competitive advantage, and report to the Commission
immediately if problems are detected. In addition, to address concerns
about protecting commercially sensitive information, we will require
the RTO or any entities who operate control areas within the RTO's
region that require access to commercially sensitive information to
sign agreements that separate reliability personnel and the relevant
information they receive from their wholesale merchant personnel.
Redispatch Authority. We conclude that the RTO must have the right
to order the redispatch of any generator connected to the transmission
facilities it operates, if necessary for the reliable operation of the
transmission system.\438\
[[Page 875]]
We also require each RTO to develop procedures for generators to offer
their services and to compensate generators that are redispatched for
reliability. In order to maintain the reliability of the transmission
system, the entity that controls transmission must also have some
control over some generation. In general, we believe this control
should be through a market where the generators offer their services
and the RTO chooses the least cost options. This authority does not
extend to initial unit commitment and dispatch decisions for
generators. However, for reliability purposes, the RTO should have full
authority to order the redispatch of any generator, subject to existing
environmental and operating restrictions that may limit a generator's
ability to change its dispatch.
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\438\ Redispatch for congestion management is addressed under
different rules, as discussed in the section on congestion
management.
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Some commenters request that we define what is meant by redispatch
for reliability. We clarify that we intend the authority for generator
redispatch to be used by the RTO to prevent or manage emergency
situations, such as abnormal system conditions that require automatic
or immediate manual action to prevent or limit equipment damage or the
loss of facilities or supply that could adversely affect the
reliability of the electric system, or to restore the system to a
normal operating state.\439\
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\439\ In general, a power system can be in one of three states:
normal, emergency and restorative. When all constraints and loads
are satisfied, the system is in its normal state; when one or more
physical limits are violated, the system is in an emergency state;
and when part of the system is operating in a normal state yet one
or more of the loads is not met (partial or total blackout), the
system is in a restorative state.
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Transmission Maintenance Approval. We conclude that, when the RTO
operates transmission facilities owned by other entities, the RTO must
have authority to approve and disapprove all requests for scheduled
outages of transmission facilities to ensure that the outages can be
accommodated within established reliability standards. Control over
transmission maintenance is a necessary RTO function because outages of
transmission facilities affect the overall transfer capability of the
grid. If a facility is removed from service for any reason, the power
flows on all regional facilities are affected. These shifting power
flows may cause other facilities to become overloaded and,
consequently, adversely affect system reliability.
The RTO is expected to base its approval on a determination of
whether the proposed maintenance of transmission facilities can be
accommodated within established state, regional and national
reliability standards. The RTO's regional perspective will allow it to
coordinate individual maintenance schedules with other RTOs as well as
with expected seasonal system demand variations. Since the RTO will
have access to extensive information, it will be able to make more
accurate assessments of the reliability effect of proposed maintenance
schedules than individual, sub-regional transmission owners.
If the RTO is a transmission company that owns and operates
transmission facilities, these assessments will be an internal company
matter. However, if there are several transmission owners in the RTO
region, the RTO will need to review transmission requests made by the
various transmission owners.\440\ In this latter case, we expect the
RTO to: receive requests for authorization of preferred maintenance
outage schedules; review and test these schedules against reliability
criteria; approve specific requests for scheduled outages; require
changes to maintenance schedules when they fail to meet reliability
standards; and update and publish maintenance schedules as needed.
---------------------------------------------------------------------------
\440\ Since some of these transmission owners may also own
generation, they may have an incentive to schedule transmission
maintenance at times that would increase the prices received from
their power sales. A transmission company, not affiliated with any
generators, would not have these same incentives.
---------------------------------------------------------------------------
We conclude that, if the RTO requires a transmission owner to
reschedule planned maintenance, the transmission owners should be
compensated for any costs created by the required rescheduling only if
the previously scheduled outage had already been approved by the RTO.
We encourage the RTO to establish performance standards for
transmission facilities under its direct or contractual control. Such
standards could take the form of targets for planned and unplanned
outages. The rationale for this requirement is that two transmission
owners should not receive equal compensation if one owner operates a
reliable transmission facility while the other operates an unreliable
facility. For RTOs that are transcos, we will require that such quality
standards be made explicit in any rate proposal.
Generation Maintenance Approval. We conclude that the RTO is not
required to have authority over proposed generation maintenance
schedules. However, we acknowledge that there are reliability
advantages to the RTO having this authority, and we would accept RTO
proposals where the participants choose to grant the RTO such
authority. In our order approving the Midwest ISO, we observed that
``the dividing line between transmission control and generation control
is not always clear because both sets of functions are ultimately
required for reliable operation of the overall system.'' 441
Because of this close connection between generation and maintenance of
system reliability, it is essential for generator owners and operators
to provide the RTO with advance knowledge of planned generation outage
schedules so that the RTO can incorporate this information into its
reliability studies and operations plan. However, although a generator
may be required to submit its maintenance schedule to an RTO, the RTO
should be prohibited from sharing that information with any other
market participants, or affiliates of market participants.
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\44\ Midwest ISO, 84 FERC at 62,180.
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Facility Ratings. After consideration of the comments, we conclude
that it is inappropriate here to require RTOs to establish transmission
facility ratings. We encourage, however, such ratings to be determined,
to the extent practical, by mutual consent of the transmission owner
and the RTO, taking into account local codes, age and past usage of the
facilities.
The Commission acknowledges the concern that changes in existing
equipment ratings may lead to problems of equipment safety and possible
damage. We further recognize that the RTO may initially need to rely
upon existing values for equipment ratings and operating ranges so as
not to disrupt reliable system operation. However, as an RTO gains
experience operating or directing the operation of the transmission
facilities in its region, we expect this responsibility to migrate to
the RTO, as facility ratings have at least an indirect effect on the
ability of the RTO to perform other RTO minimum functions (e.g.,
planning and expansion, ATC and TTC). If there is a dispute over
equipment ratings, the parties should pursue resolution through an ADR
process approved by the Commission.
Liability. After consideration, we will determine the extent of RTO
liability relating to its reliability activities on a case-by-case
basis.
Reliability Standards. We conclude that the RTO must perform its
functions consistent with established NERC (or its successor)
reliability standards, and notify the Commission immediately if
implementation of these or any other externally established reliability
standards will prevent it from meeting its obligation to provide
reliable, non-discriminatory transmission service.
[[Page 876]]
E. Minimum Functions of an RTO
In the NOPR, we proposed seven minimum functions that an RTO must
perform. In general, we proposed that an RTO must:
(1) administer its own tariff and employ a transmission pricing
system that will promote efficient use and expansion of transmission
and generation facilities;
(2) create market mechanisms to manage transmission congestion;
(3) develop and implement procedures to address parallel path flow
issues;
(4) serve as a supplier of last resort for all ancillary services
required in Order No. 888 and subsequent orders;
(5) operate a single OASIS site for all transmission facilities
under its control with responsibility for independently calculating TTC
and ATC;
(6) monitor markets to identify design flaws and market power; and
(7) plan and coordinate necessary transmission additions and
upgrades.
We basically affirm these seven functions with the clarifications
and revisions as noted below. In addition, we have added interregional
coordination as an eighth minimum function, as discussed below.
1. Tariff Administration and Design (Function 1) Sole Administrator of
Tariff
In order to ensure non-discriminatory service within the region,
the NOPR proposed that the RTO be the sole administrator of its own
transmission tariff.442 The RTO would thus be the sole
authority making decisions on the provision of transmission service
including decisions relating to new interconnections. The NOPR
requested comments on several aspects of this standard, including how
the authority over interconnections would work for ISOs that do not own
transmission and would not be performing the construction. The NOPR
also sought comment on whether authority over interconnection should
apply to all new interconnections, including those for reliability and
connections to other regions.
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\442\ FERC Stats. and Regs. para. 32,541 at 33,739-740. The
authority to file changes in the RTO tariff is discussed above under
the Independence Characteristic.
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Comments. The vast majority of commenters addressing these issues
agree with the proposal that the RTO be the sole administrator of its
own tariff.443 Commenters noted many of the benefits of an
RTO being the sole tariff administrator: it will eliminate confusion;
reduce transactions costs; assure that access decisions are
independent; 444 reduce reliability concerns; 445
and ensure consistent ratemaking across the RTO.446 Some
commenters suggest that their respective organizations already meet
this requirement, including ISO-NE and NY ISO, which ask whether
sharing authority with transmission owners for non-discriminatory
access meets the standard.
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\443\ See, e.g., Allegheny, APX, SMUD, NASUCA, NY ISO, East
Kentucky, Utilicorp, JEA, LG&E, Enron/APX/Coral Power, EPSA, South
Carolina Authority, First Energy, Cal DWR, California Board,
PacifiCorp and NSP.
\444\ PJM.
\445\ PJM/NEPOOL Customers.
\446\ UAMPS.
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But some of the commenters that support the proposal had specific
concerns and suggestions: the Commission should adopt specific pricing
regulations and expressly permit expedited declaratory orders on
pricing; 447 the Commission should take a more active
approach in developing innovative rates; 448 there may be a
problem for an RTO located in both the United States and Canada if
there is disagreement over the tariff by the respective authorities;
449 and quicker decisions are likely if a stakeholder board
is not involved.450
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\447\ Entergy.
\448\ Illinois Commission.
\449\ Canada DNR.
\450\ New Smyrna Beach.
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A number of commenters also supported the proposal with respect to
the RTO's authority over interconnections.451 Some of these
commenters expressed concerns and recommendations about the
Commission's proposal, e.g., transmission owners should be a part of
the decision process; 452 transcos will be better able to
integrate interconnection decisions into a unified strategy covering
investment, operations, maintenance and facility design; 453
RTOs should not have the authority to deny a generator that is not
optimally located on the grid; 454 interconnection policy
should rely more heavily on market mechanisms; 455 the
transmission owner should develop the actual interconnection agreement
to insure adequate protections for its equipment; 456
national fees and technical standards should be established for
interconnections; 457 authority over interconnections should
involve coordinated planning and construction, not ``autonomous,
unilateral authority''; 458 RTOs need to develop procedures
and guidelines so that there are no adverse impacts of interconnection
on existing facilities; 459 RTOs should have authority to
assess the impact of a new interconnection on regional facilities but
should only have authority over interconnections involving RTO
facilities, not all regional facilities; 460 and an RTO must
be required to show harm to deny an interconnection
request.461
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\451\ See, e.g., Entergy, PJM, South Carolina Authority,
Southern Company, Tri-State, Desert STAR, East Texas Cooperatives,
Enron/APX/Coral Power, Sithe and PG&E.
\452\ Cal ISO.
\453\ Duke.
\454\ Minnesota Power.
\455\ PG&E.
\456\ Southern Company.
\457\ Distributed Power and EAL.
\458\ SPRA.
\459\ TANC.
\460\ Metropolitan.
\461\ Williams.
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A few commenters opposed the Commission's proposal or suggested
making significant modifications. With respect to tariff
administration, Seattle opposes the Commission giving RTOs with small
control areas blanket authority to approve new interconnections and
also argues that the RTO should not be given authority over the
interconnection of customer based backup and load shaving generators,
QFs, or subtransmission and radial transmission facilities (used to
reinforce municipal grids). TXU Electric argues that the Commission
should be more flexible and allow RTOs to choose whether to administer
the tariff of other entities. TXU Electric notes that in ERCOT, each
owner has its own tariff with its own revenue requirement but with
uniform terms and conditions of access and that this approach can
protect the owner better than an RTO tariff. Florida Commission
recommends that the question of tariff administration be determined on
a regional basis with endorsement by state regulators.
With respect to RTO authority over interconnections, Mass Companies
argues that the RTO should not have the authority over interconnections
because such authority is unlawful, impairs reliability, and because
the transmission owner is in a better position to perform this
function. SRP suggests that an RTO's exclusive right to administer its
own tariff and the right to control interconnections may establish a
property right that would jeopardize a public power's tax free status
by being declared a private business use. This would be a potential
problem if the RTO were not a governmental entity or a 501(c)(3) non-
profit organization. To prevent this, SRP says that the RTO would have
to be structured carefully with these concerns in mind. DOE indicates
that the authority over interconnection is a concern for PMAs
[[Page 877]]
because of the NEPA requirements which must be accommodated. Industrial
Consumers would amend the proposed Regulatory Text on tariff
administration to add ``throughout the interconnection within which the
Regional Transmission Organization resides'' to the requirement to
promote efficient use and expansion. Industrial Consumers also propose
that the Regulatory Text on interconnection be amended to add the
responsibility to coordinate transmission needs across the
interconnection. Finally, Industrial Consumers would amend the
provision that RTOs review and approve requests for new
interconnections to add ``by new loads that take service at
transmission voltages and by any new generation resource regardless of
the nominal voltage at the generator's point of interconnection. Any
proposal to increase the nameplate-rated capacity at an existing
generating site shall be treated as a new request for interconnection''
to clarify that the RTO is to authorize such interconnections and
minimize entry barriers to new sources of generation.
Commission Conclusion. We note the strong support for this standard
in the comments and we adopt the NOPR's requirement that the RTO be the
sole provider of transmission service and sole administrator of its own
open access tariff. Included in this is the requirement that the RTO
have the sole authority for the evaluation and approval of all requests
for transmission service including requests for new
interconnections.462
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\462\ Of course, eligible applicants always have the right to
seek interconnections from the Commission pursuant to sections
202(b) and 210 of the FPA.
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With the RTO the sole provider of transmission service,
transmission customers have a nondiscriminatory and uniform access to
regional transmission facilities. This type of access cannot be assured
if customers are required to deal with several transmission owners with
differing tariff terms and conditions. As noted in the NOPR, the RTO
must be the provider of transmission service in the strong sense of the
term. Mere monitoring and dispute resolution are insufficient to meet
the requirements of this standard.
The requirement that the RTO administer its own tariff and not the
tariff or tariffs of other entities received little objection in the
comments, even from ISOs where this requirement is not currently being
met.463 One commenter, SCE&G proposes that the RTO's tariff
only cover its own costs and wheeling. The transmission owners would
maintain standard open access tariffs which would be administered by
the RTO. We reject this proposal. To provide truly independent and
nondiscriminatory transmission service, the RTO must administer its own
tariff and have the independent authority to file tariff changes.
---------------------------------------------------------------------------
\463\ See, e.g., ISO-NE at 9.
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Mass Companies argues that the RTO is not in as good a position as
transmission owners to judge requests for new interconnections. SPRA
and Metropolitan suggest that an RTO's authority over new
interconnections should be limited. Because the ability for customers
to obtain nondiscriminatory access to the regional transmission system,
whether over existing facilities or over new facilities, is integral to
a competitive market for generation, we reject these proposals to
modify our original position on new interconnections.
Other commenters, as noted above, support this standard but have
specific concerns they would like to see the Commission address. The
concerns listed do not cause us to change our original proposal. These
concerns, to the extent they apply, should be voiced at the time RTO
proposals are filed and they will be considered on a case-by-case
basis.
Multiple Access Charges. The NOPR proposed that the RTO's tariff
must not result in transmission customers paying multiple access
charges. We affirm that proposal in this Final Rule. Because the issue
of multiple access charges is a rate issue, we discuss in detail the
comments we received on this issue, the reasons for our conclusion, and
the concepts of pancaked rates, license plate rates, and uniform access
charges in Section III.G of this Final Rule addressing transmission
ratemaking policy for RTOs.
2. Congestion Management (Function 2)
In the NOPR, we proposed to include congestion management as a
minimum function that an RTO must perform.464 Specifically,
we proposed to require the RTO to ensure the development and operation
of market mechanisms to manage transmission congestion. We proposed
that the RTO must either operate such markets itself or ensure that the
task is performed by another entity that is not affiliated with any
market participant. In carrying out this function, we stated that the
RTO must satisfy certain standards or demonstrate that an alternative
proposal is consistent with or superior to satisfying the standard. We
further proposed that the market mechanisms must accommodate broad
participation by all market participants, and must provide all
transmission customers with efficient price signals regarding the
consequences of their transmission usage decisions. We proposed to
allow RTOs considerable flexibility in experimenting with different
market approaches to managing congestion through pricing. However, we
stated that proposals should ensure that (1) the generators that are
dispatched in the presence of transmission constraints are those that
can serve system loads at least cost, and (2) limited transmission
capacity is used by market participants that value that use most
highly. We asked for comments as to what specific requirements, if any,
may best suit these goals.465
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\464\ FERC Stats. & Regs. para. 32,541 at 33,741-43.
\465\ Id. at 33,754-55.
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We stated in the NOPR that traditional approaches to congestion
management such as those that rely exclusively on the use of
administrative curtailment procedures may no longer be acceptable in a
competitive, vertically de-integrated industry. We thus concluded that
efficient congestion management requires a greater reliance on market
mechanisms, and stated our belief that a large regional organization
like an RTO will be able to create a workable and effective congestion
management market. We stated that while it is our intent to give RTOs
considerable flexibility in experimenting with different market
approaches to managing congestion, we believe that a workable market
approach should establish clear and tradeable rights for transmission
usage, promote efficient regional dispatch, support the emergence of
secondary markets for transmission rights, and provide market
participants with the opportunity to hedge locational differences in
energy prices.
The Commission invited comments on the requirement that RTOs must
be responsible for managing congestion with a market mechanism, and
posed the following questions. Can decentralized markets for congestion
management be made to work effectively and quickly? Can the RTO's role
be limited to that of a facilitator that simply brings together market
participants for the purpose of engaging in bilateral transactions to
relieve congestion? If not, will these markets require centralized
operation by the RTO or some other independent entity? How can an RTO
ensure that enough generators will participate in the congestion
management market to make possible a least-cost dispatch? Are there any
special considerations in evaluating
[[Page 878]]
market power in a congestion market operated or facilitated by an RTO?
In addition, we proposed to allow up to one year after start-up for
this function to be implemented. We noted that market approaches to
congestion management may take additional time to work out, and asked
for comments on whether this additional implementation time period is
warranted, and whether one year is an appropriate additional time
period.
Comments. Using Market Mechanisms to Manage Congestion. Although
opinions vary as to the proper role of the RTO in managing congestion,
many commenters believe that efficient congestion management requires
greater reliance on market mechanisms.466 CSU believes that
congestion management is uniquely amenable to a market solution. CSU
states that there will be a continuing need for some type of market
mechanism to address constraints and this mechanism is best established
at the regional level and best placed with an entity independent of
wholesale power market participants.
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\466\ See, e.g., United Illuminating, CSU, Duke, NASUCA, Los
Angeles, NYPP, DOE, SMUD, Otter Tail, PG&E, FirstEnergy, Mass
Companies, Enron/APX/Coral Power, Nevada Commission.
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Some commenters emphasize that it is better to use market
mechanisms to manage congestion than to rely on the physical
interruption of power flows.467 NERC contends that if the
industry had in place more market-oriented mechanisms that dealt
effectively with constraints, then the frequency of transmission
loading relief (TLR) procedures would decrease. Professor Hogan claims
that with efficient pricing, users have the incentive to respond to the
requirements of reliable operation. He asserts that, absent such price
incentives, market choices would need to be curtailed in order to give
the system operator enough control to counteract the perverse
incentives that would be created by prices that did not reflect the
marginal costs of dispatch. PJM/NEPOOL Customers argues that, when
faced with a transmission congestion circumstance, the RTO should
redispatch generators to the extent possible.
---------------------------------------------------------------------------
\467\ See, e.g., NERC, Sithe, NASUCA, Cinergy, Professor Hogan,
PJM, Dr. Ilic.
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Also, Statoil claims that the use of TLR procedures is inherently
discriminatory. Statoil claims that most transmission owners serving
retail load do not engage in interchange transactions or use the pro
forma tariff at the same level as new competitive market entrants
attempting to enter historically captive markets. Statoil thus argues
that, even if TLR is applied in a comparable manner, it will still
disproportionately and adversely affect new competitive market
entrants.
Role of the RTO in Congestion Management. Commenters offer a
variety of views concerning the proper role of the RTO in congestion
management. Some advocate an active role for the RTO in operating an
energy market that is highly centralized.468 Others envision
the RTO's role as being much smaller, perhaps limited to that of a
facilitator that brings together market participants for the purpose of
engaging in voluntary transactions to relieve congestion.469
Still others, such as Southern Company and EEI, believe that RTOs are
not necessary to make congestion management work. EEI argues that while
congestion management does require a coordinated regional or
interconnection-wide solution, it does not require the extensive
infrastructure and responsibilities associated with what the Commission
has proposed to define as RTOs. EEI notes that NERC's Congestion
Management Working Group is exploring available options for congestion
management, independently of whether RTOs exist.
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\468\ See, e.g., PJM, Professor Hogan, CSU, Sithe, NERA, Duke,
PJM/NEPOOL Customers, H.Q. Energy Services, Minnesota Power, FTC.
\469\ See, e.g., APX, SPP, South Carolina Authority, Alliant
Energy, WPSC, NSP, TANC, Williams.
---------------------------------------------------------------------------
PJM/NEPOOL Customers believes that an independent entity must
operate any congestion management market. It believes also that that
entity must have sufficient power and centralization to address
congestion problems effectively and quickly. Consequently, it urges the
Commission not to consider proposals that include a decentralized
market for congestion management or that limit the RTO role to that of
a facilitator of bilateral transactions to relieve congestion. In
addition, it contends that the RTO must retain sufficient authority
over generators that choose to make themselves available to ensure that
those generators will participate in the congestion management market.
Duke states that, eventually, decentralized markets may organize in a
manner to accomplish effective congestion management, but at this time,
the congestion management function should be centrally managed.
PJM claims that RTOs can facilitate efficient, broad-scale
congestion management. PJM states that by combining multiple
transmission systems over a large geographic region, an RTO can have an
effective pricing system to price efficiently actual transmission flows
in a region. PJM argues that not only should the Commission require
that RTOs be responsible for managing congestion with market
mechanisms, the Commission also should prohibit any other entity from
acting in a manner that detracts from the RTO's ability to employ its
market mechanisms.
Cleveland believes that an effective way to manage congestion may
be to combine a market-based mechanism with a power exchange. It states
that the RTO's redispatch function and the bidding process available
through a power exchange should jointly operate to minimize the
congestion.
H.Q. Energy Services contends that control over the management of
congestion goes hand-in-hand with control over reliability. It believes
that, ideally, an RTO should establish a congestion pricing system that
manages congestion with minimal operator intervention. However, H.Q.
Energy Services argues that, without control over reliability, an RTO
will not be in the position to accurately and fairly allocate available
transmission capacity because it cannot send the correct congestion
pricing signals.
Sithe contends that the Commission should not allow overly
decentralized systems whereby individual utilities in a region continue
to manage congestion relief, especially if those utilities continue to
own generation. Arkansas Consumers believe that the RTO's congestion
management function helps provide a remedy for any anti-competitive
activity on the part of generators or transmission owners. First
Rochdale contends that only fully independent operation of an RTO is
likely to lead to open markets in which all entities can compete
freely. Duke asserts that there are no special considerations in
evaluating market power in a congestion market operated or facilitated
by an RTO.
Other commenters stress that the RTO's role in managing congestion
using market mechanisms should be strictly limited. Indeed, the South
Carolina Authority opposes a centralized arrangement for managing
congestion as being unduly restrictive and perhaps anti-competitive.
WPSC argues that the role of the RTO should be limited to acting as a
clearinghouse so that market participants are aware of the range of
alternatives available for dealing with congestion. WPSC contends that
the market will then dictate which mechanisms are used in any
particular instance. SPP suggests that the RTO can be a facilitator of
congestion relief and that there is no need for the Commission to
require that the RTO adopt a centralized approach,
[[Page 879]]
such as locational marginal pricing, for managing congestion. SPP
states that it is a facilitator of congestion relief and intends to
continue in that role under its new proposal. SPP states that it will
identify which generators can relieve a constraint and the relative
impact of redispatching those generators. It will then be the
customer's responsibility to contract with the owner of these
generators for redispatch services. SPP notes that this method relies
on the market and bilateral contracts for the redispatch solutions. SPP
claims that the market can also provide for price assurance and for
long-term redispatch obligations. PG&E claims that with the proper
information, bilateral market-based redispatch could be used within an
hour of the occurrence of congestion on any part of the controlled
system.
APX argues that the RTO should not conduct the trading process
because it will impede the adaptation of trading to market conditions,
which is essential for market development. APX claims that all
competitive industries use decentralized trading through forward
contracts, and no competitive industry uses a central bidding agent to
create its market. Consequently, APX believes that the Commission
should limit the RTO's role in congestion management to that of a
provider of last resort. PG&E argues that although the RTO may
administer certain market mechanisms such as congestion management, it
is important that the RTO not view itself as responsible for energy
pricing and other aspects of supply and demand interactions, all of
which, PG&E contends, can be most effectively managed by the market
unless material and lasting market flaws are present.
Similarly, Cinergy argues that the mechanism for price transparency
in the commodity market should be developed and implemented by the
market, not the RTO. Cinergy recognizes, however, that an economic
congestion management system depends on a power market mechanism that
provides price transparency for determining economic dispatch of
generation. Consequently, Cinergy notes, RTOs will be confronted with
issues of applying an economic dispatch valuation mechanism. Cinergy
argues that such mechanism should evolve from the marketplace, not
directly from the RTO. Cinergy proposes that the RTO would administer
the congestion management system, but would not be involved in the
commodity market infrastructure unless its involvement was mutually
agreeable among all stakeholders.
Williams claims that decentralized markets for congestion
management, operating under the auspices of RTOs, can work effectively
and quickly in an environment in which market participants have the
correct incentives. Williams states that depending upon the geographic
size of RTOs and the extent of congestion within each, zones for
congestion management may have to be developed. Williams provides a
detailed description of how a zonal approach to congestion management
can be implemented.
Both CP&L and Enron/APX/Coral Power believe that the role of the
RTO in congestion management should depend on the time frame in which
the decisions are being made. These commenters prescribe different
roles for the RTO in each of three different time frames.
The Direct Dispatch Authority of the RTO. While supporting the use
of pricing and other market mechanisms to manage congestion, a number
of commenters state that an RTO must have authority to direct
redispatch if necessary to ensure grid reliability.\470\ For example,
Otter Tail contends that the RTO should have direct authority to order
redispatch of generation for purposes of relieving congestion and
during system emergencies. Otter Tail states that this dispatch should
be directed for the generating units that can most economically reduce
the congestion. Otter Tail states that because there is a need for
immediate, real-time response to system contingencies and to relieve
transmission congestion, the RTO should have control of generating
units. East Kentucky contends that to effectively manage congestion,
the RTO must have absolute authority to order redispatch of all
generators on the RTO transmission system. However, for this to work,
East Kentucky states that the RTO will have to compensate the generator
with firm transmission service for the additional out-of-pocket costs
incurred due to the redispatch, plus an amount for lost margins on lost
revenue. It suggests that generators with non-firm transmission service
would have to redispatch as directed by the RTO but would have to bear
their own costs.
---------------------------------------------------------------------------
\470\ See, e.g., Otter Tail, NERC, Allegheny, EME, NASUCA, East
Kentucky, Williams, Minnesota Power, CSU. See also supra section
III.D.3, which addresses the appropriate scope of the RTO's
operational authority.
---------------------------------------------------------------------------
NERC notes that market mechanisms may offer better ways of dealing
with congestion management than does physical interruption of power
flows, but asserts that it will always be necessary to have a non-
market mechanism such as transmission loading relief in place to ensure
that the stability of the grid is always maintained. However, EME
believes that the extent of RTO control over dispatch of generation
should be carefully circumscribed to ensure maximum development of
competitive markets in wholesale power and ancillary services. Seattle
contends that where transparent power supply markets exist, price
differences are widely known to the market and congestion can be
resolved bilaterally with no intervention by an RTO. PJM notes that
since implementing LMP, it rarely has needed to take emergency actions
to alleviate transmission congestion.
Minnesota Power believes that RTOs must have the authority to
require that all generators, existing and new, agree to redispatch as a
condition of grid connection. Minnesota Power also believes that the
RTO must have the authority to penalize generators who subsequently
refuse a redispatch order, or claim a false unplanned outage. CSU
asserts that generation redispatch is essential in Front Range
Colorado, which can be expected to have an increasing population of
gas-fired generation within the boundaries of the constraints. It
contends that the inability to redispatch these units for any reason
other than reliability would severely hinder the ability of an RTO to
address capacity constraints.
MidAmerican states that, although congestion must be managed using
pricing signals from the market, circumstances may occur where
immediate actions are required and time does not permit normal bidding
to allow the marketplace to respond. It contends that during such
events, the RTO must be required to follow previously established
procedures.
However, Seattle argues that the RTO should not have authority to
redispatch generation to accomplish congestion management without
unanimous consent of the stakeholders. Seattle notes that many
Northwest generating plant operators are subject to fishery-related
hydroelectric dispatch constraints. Seattle states that because these
constraints are particular to the owners of the generating facilities,
these resources are not well suited to third party dispatch.
Managing Congestion by Eliminating It. Some commenters contend that
the ultimate goal of RTOs should be the elimination of congestion
within their respective areas of control.\471\ Powerex believes that it
is better to eliminate congestion at its source through facilities
upgrades, if economically and environmentally feasible, rather than
[[Page 880]]
attempting to manage congestion on a long-term basis through congestion
pricing schemes. Salomon Smith Barney believes that the Commission has
overemphasized congestion pricing as a vehicle to price the existing
network rather than as a vehicle to induce investment when such
investment is an economical alternative.
---------------------------------------------------------------------------
\471\ See, e.g., Williams, Powerex, Manitoba Board, Salomon
Smith Barney.
---------------------------------------------------------------------------
TDU Systems state that they do not want management of significant
transmission congestion to become a long-term function of RTOs. They
claim that minor congestion (i.e., congestion that is economically
dealt with through redispatch of generators) will always be a feature
of wholesale transmission markets, and an RTO should properly manage
it. However, they argue that an RTO should deal with significant
persistent transmission congestion by constructing (or having
constructed) the appropriate transmission or generation facilities.
Desirable Attributes of Market Mechanisms. Many commenters offer
their views on the desirable attributes of any market mechanisms that
are used to manage congestion.\472\ For example, PJM/NEPOOL Customers
urges the Commission to employ three general criteria to evaluate any
proposal: simplicity, visibility and predictability. They state that
the proposed approach to relieve the congestion should be simple to
administer, both for customers and for the RTO. They believe that
market participants should be able to examine the operation of the
congestion management mechanism on a real-time basis and verify that
transmission access is being appropriately accorded to entities that
most desire transmission service. They state that such visibility will
engender confidence by market participants in the congestion management
mechanism. In addition, they believe that the congestion management
mechanism must be predictable to all transmission users to determine
the anticipated price that will be necessary to ensure the continuation
of transmission service if congestion occurs.
---------------------------------------------------------------------------
\472\ See, e.g., NASUCA, CMUA, NSP, PG&E, Statoil, SMUD,
UtiliCorp, PacificCorp, PJM/NEPOOL Customers, Metropolitan, Cal DWR.
---------------------------------------------------------------------------
Cinergy states that an economically efficient congestion management
system must begin with properly defining information posting
requirements. Accordingly, Cinergy argues that the Final Rule should
ensure that requisite information on congestion is posted on the OASIS.
Similarly, Williams and Industrial Consumers believe that RTO access to
region-wide information on network conditions and power transactions,
coupled with efficient congestion management and well specified
transmission rights, could help RTOs in taking preemptive actions
against potential curtailment incidents. Statoil and EPSA believe that,
ideally, economic rationing schemes should be uniform across RTOs and
should be implemented as an ancillary service under a regional
transmission tariff. Montana Commission asserts that congestion
management must be efficient. CMUA believes that congestion management
mechanisms must do their job, but not unreasonably interfere with
choices by market participants.
Some commenters believe that efficient congestion management
requires a transparent commodity market. Cinergy states that market
mechanisms that include locational pricing and financial rights for
firm transmission have been successfully implemented where they are
supported by a power exchange or pool pricing mechanism that provides
market-clearing prices and price transparency. CalPX emphasizes the
value of a separate power exchange and argues that the bifurcation of
the exchange and transmission operator functions does not add to the
market cost of congestion management, as some have suggested. Also,
Otter Tail believes that the development of an hour-ahead power
exchange within the RTO would improve grid reliability.
Many commenters support the NOPR's requirement that market
mechanisms be used to manage congestion and note the particular value
of using price as a tool to manage congestion.\473\ Some commenters
specifically endorsed the proposed requirement that congestion pricing
proposals must meet the two efficiency objectives set forth in the
NOPR.\474\ PJM/NEPOOL Customers state that these two objectives are
fundamental to the operation of a market and to the ultimate goals of
electricity supply competition.\475\ SMUD believes that a well-designed
congestion management policy, that provides proper locational price
signals without creating opportunities for gaming or cost shifting,
will attract market participation. SMUD agrees that market participants
must be given efficient price signals concerning their use of the
transmission system, but claims that this is difficult because the
existing transmission grid was not designed with the capability to
operate as a common carrier or to serve customers in an open access
manner. Also, a few commenters expressed doubts about the overall value
of using pricing mechanisms to manage congestion,\476\ and others cited
reasons to move cautiously.\477\ Tri-State is skeptical that market
mechanisms for managing congestion will lead to a least-cost dispatch.
Tri-State states that entities with firm transmission rights on the
congested path may be reluctant to participate voluntarily in
generation redispatch that will jeopardize the economics of long-term
power supply contracts or firm resources, even if the result would
lower costs.
---------------------------------------------------------------------------
\473\ See, e.g., PJM/NEPOOL Customers, United Illuminating,
Allegheny, EPSA, SMUD, Los Angeles, NASUCA, Duke, NERC, Professor
Hogan, EME, PJM, DOE, CSU.
\474\ See, e.g., PJM/NEPOOL Customers.
\475\ However, Montana Commission asks the Commission to specify
more precisely the nature of the pricing and congestion management
methods that will satisfy the NOPR's efficiency objectives.
\476\ See, e.g., LIPA, Transmission ISO Participants.
\477\ See, e.g., EPSA, Tri-State.
---------------------------------------------------------------------------
Several commenters suggest principles to guide the design of
congestion pricing mechanisms.\478\ NASUCA states that any mechanism
for using congestion prices for managing transmission system flows
should be easy to implement; designed to minimize cost shifts; designed
to support an economically efficient dispatch; and coordinated with the
underlying transmission rate design. PacifiCorp states that key
components of a good market-based congestion clearing methodology are:
(1) Tradable transmission capacity reservations; (2) a system in which
all parties who can clear congestion can bid to do so; (3) the
establishment of congestion costs far enough in advance to facilitate
reasoned decision-making; and (4) the avoidance of any RTO rules that
substantially reduce liquidity in power markets. UtiliCorp believes
that a congestion management system should establish tradeable rights
for transmission usage, promote efficient regional dispatch, support
the emergence of secondary market for transmission rights, and give
market participants the opportunity to hedge locational differences in
energy prices. However, Enron/APX/Coral Power disagrees on the latter
feature. It contends that the monopoly wires business should not be
allowed to encroach on what they see as the highly competitive and
innovative business of providing hedges against locational price
differences of energy or capacity or against price volatility of these
or any other competitive products.
---------------------------------------------------------------------------
\478\ See, e.g., NASUCA, NJBUS, PJM/NEPOOL Customers, EPSA,
Enron/APX/Coral Power.
---------------------------------------------------------------------------
Cal DWR and Metropolitan urge the Commission to adopt RTO
ratemaking principles that include off-peak rates.
[[Page 881]]
Cal DWR believes that customers should face accurate transmission price
signals and, therefore, transmission prices should be lower in periods
of off-peak demand for transmission. Cal DWR believes that off-peak
pricing provides an accurate price signal over the longer term,
promoting investment necessary to shift transmission usage to off-peak
periods. In addition, Metropolitan believes that off-peak pricing can
help to resolve problems of cost-shifting.
A number of commenters emphasize certain benefits of a well
designed congestion pricing policy, claiming that price signals can
assist RTOs and market participants in determining the efficient size
and location of both new generation and new grid expansions.\479\ Los
Angeles argues that ensuring accurate market signals through the
creation of a congestion pricing mechanism will be the keystone to
future system planning. Los Angeles states that these signals should
alert generators to the advantages of siting in congested areas,
motivate marketers and distribution companies to develop demand-side
management options, and generally foster marketplace innovation. Los
Angeles also believes that congestion price signals should help in
determining the proper size of transmission upgrades that the RTO might
build to relieve congestion. Otter Tail believes there exists a great
need for new transmission capacity and, indeed, argues that the overall
focus of the NOPR and FERC transmission policy should be on providing
the appropriate financial incentives to assure investment in and
expansion of the system.\480\ To ensure that price signals translate
into appropriate expansion of the grid, SMUD believes that the RTO must
be sufficiently independent and strong to require the expansion of the
grid. NASUCA notes that, while congestion cost pricing may help to
signal where new generation and transmission lines are needed, it may
not be necessary for the efficient daily operation of the transmission
grid.
---------------------------------------------------------------------------
\479\ See, e.g., Allegheny, EME, United Illuminating, EPSA,
SMUD, Los Angeles, NASUCA, CSU.
\480\ Other commenters emphasize the need for significant
investments to expand transmission capacity. See, e.g., EPRI,
Salomon Smith Barney.
---------------------------------------------------------------------------
Other commenters believe that it may be difficult to design market
mechanisms to provide incentives for the efficient expansion of the
grid.\481\ H.Q. Energy Services states that currently, the rules for
congestion management do not act as a sufficient incentive to
transmission owners to upgrade facilities. NWCC states that it is
unclear whether congestion charges can act as a means of driving
transmission expansion, since adding transmission is, by nature,
capacity-based. NWCC also states that it is unclear whether congestion
costs will be an adequate incentive for market participants to finance
transmission expansion on their own, given the extensive permitting and
regulatory requirements that are involved. LIPA states that, while new
location-based pricing mechanisms have not been in place long enough to
determine if they will provide empirical evidence that is helpful in
identifying efficient transmission expansions, it believes that the
mechanisms do not provide sufficient incentives for development of
transmission. Also, LIPA claims that they do not provide a useful
signal when reliability, as opposed to economic efficiency, drives the
need for transmission enhancements.
---------------------------------------------------------------------------
\481\ See, e.g., Transmission ISO Participants, SoCal Edison,
H.Q. Energy Services, LIPA, NWCC.
---------------------------------------------------------------------------
SoCal Edison criticizes the congestion management policies
implemented by the Cal ISO, stating that procedures intended to
encourage the voluntary mitigation of congestion through investment in
new transmission may not provide a sufficient incentive. SoCal Edison
contends that, while correct congestion price signals will assist in
the identification of transmission investment needs, they will not
eliminate fundamental disputes among affected market participants over
the responsibility for the costs of new transmission or eliminate the
risks associated with attempting to construct new transmission
projects. It asserts that the Commission cannot simply assume that the
market will respond to congestion signals if, at the same time, it is
creating a regulatory climate that discourages investment in new
transmission. SoCal Edison believes that impediments to grid expansion
can be overcome only if the Commission adopts transmission pricing
policies that more accurately reflect the value that new transmission
investments bring to electric consumers. Similarly, FirstEnergy argues
that if the Commission desires an efficient generation market that
optimizes the public good, then a mechanism that allows transmission
owners to capitalize on increases in the transmission capacity at fair
market value must be found. FirstEnergy contends that the interaction
of these free market forces will drive the proper allocation of
resources between transmission and generation over the long term.
Locational Marginal Pricing. A number of commenters advocate the
use of locational marginal pricing (LMP) for congestion
management.\482\ Professor Hogan states that, with LMP, the security-
constrained economic dispatch process would produce prices for energy
at each location, incorporating the combined effect of generation,
losses and congestion. He states that the corresponding transmission
price between the location where power is supplied and where it is used
would be determined as the difference between the energy prices at the
two locations. Professor Hogan therefore contends that this same
framework is easily extended to include bilateral transactions.
Professor Hogan states that, with LMP, the system operator coordinates
the dispatch and provides the information for settlement payments, with
regulatory oversight to guarantee comparable service through open
access to the pool run by the system operator through a bid-based
economic dispatch. He claims that PJM implemented LMP after
experimenting with an alternative market model and pricing approach
that proved to be fundamentally inconsistent with a competitive market
and user flexibility. He states that the earlier pricing system allowed
market participants the flexibility to choose between bilateral
transactions and spot purchases, but did not simultaneously present
market participants with the costs of their choices. He states that
this created perverse incentives. Professor Hogan argues that LMP is
the only workable system that can support a non-discriminatory
competitive market that allows for participant choice and flexibility.
---------------------------------------------------------------------------
\482\ See, e.g., Professor Hogan, PJM, NERA, Sithe, Allegheny,
Mid-Atlantic Commissions, DOE, Duke, United Illuminating, EME.
---------------------------------------------------------------------------
PJM states that the Commission correctly concludes that LMP will
``encourage efficient use of the transmission system, and facilitate
the development of competitive electricity markets.'' PJM notes that,
under LMP, transmission customers are assessed congestion charges
consistent with their actual use of the system and the actual
redispatch that their transactions cause. It claims that this provides
an economic choice to non-firm transmission customers to self-curtail
their use of the transmission system or pay congestion charges
determined by the market. PJM believes that by basing congestion
charges on the true redispatch cost, parties behave in a rational and
efficient manner. It states that the market determines the clearing
price for transmission congestion and which customers ultimately
utilize the transmission system. PJM states that the use of fixed
transmission rights (FTRs)
[[Page 882]]
enables market participants to pay known, fixed transmission rates and
to hedge against congestion charges.
The FTC believes that accurate LMP signals for investment to reduce
congestion may become even more important as distributed generation
presents opportunities for small-scale, fine-tuned (with respect to
both size and location) generation investments to relieve transmission
congestion, in place of large-scale transmission or generation
investments. EME endorses the LMP pricing approach adopted by PJM and
the New York ISO, and states that the Midwest ISO and the Alliance RTO
should be encouraged to adopt similar approaches. The CalPX notes that
the separation of the CalPX and the ISO in California does not prevent
the use of a locational pricing model that incorporates the individual
buses and transmission lines in the network.
Allegheny believes that ``[c]onsistent locational marginal price
dislocations readily identify system expansion, or other congestion
relief, requirements as well as serve as an indicator of the most
economic fix to congestion patterns over time.'' It claims that there
would be no incentives for the RTO or transmission owners to maintain
congestion, since there is no financial impact on them from LMP because
any excess payments received by the RTO during congestion are returned
to holders of FTRs. Allegheny recommends that the Commission remain
flexible in considering other pricing innovations for congestion
management, but believes that a simplified locational marginal pricing
methodology should be established as a default market mechanism against
which other pricing innovations are evaluated.
Some commenters, however, criticize the locational marginal pricing
approach to congestion management.\483\ APX argues that, because LMP
requires the RTO to implement a centrally optimized dispatch, it will
discourage, if not eliminate, the commitment of forward contracts in
the energy market and replace the price discovery of forward markets
with ex post pricing. APX contends that because LMP price calculations
occur only periodically and in a single iteration, price visibility is
restricted compared to a continuous forward market. APX claims that
this diminished visibility can make the result less efficient and more
vulnerable to an exercise of market power. APX contends that, for most
industries, a process of continuous trading creates efficiency in a
competitive market, while the LMP optimization process has no role for
trading. APX asserts that no competitive industry uses optimization to
simulate and substitute for market outcomes. APX contends that under
LMP, the system operator, not the market, will specify the structure of
the optimization problem. APX claims that markets process information
much more flexibly and comprehensively through the self-interested
trading behavior of buyers and sellers. APX asserts that this is the
strength of markets and the critical shortcoming of LMP.
---------------------------------------------------------------------------
\483\ See, e.g., APX, LIPA, TDU Systems, CP&L, Virginia
Commission, Tri-State, Dynegy.
---------------------------------------------------------------------------
Dynegy claims that markets for FTRs have yet to fulfill their
promise to provide market participants with critically important price
certainty for their transmission transactions. For example, Dynegy
states that allocation problems still exist, in that only a small
portion of available FTRs is being auctioned off in certain markets
while a large number are being withheld for incumbents' use. Dynegy
argues that in order for FTRs to provide a truly effective hedge
against transmission price increases resulting from LMP in the hourly
market, hourly FTRs would have to be available in a liquid market at a
moment's notice, but nothing close to such a market exists. Dynegy
suggests that, because the LMP model has yet to be implemented
successfully due to the lack of a liquid FTR market, the time is ripe
to look at other models, such as a physical rights model.
LIPA claims that neither the opportunity to obtain fixed
transmission rights nor the prospect of locational price reductions are
sufficient to encourage efficient generation and transmission
expansions. For example, LIPA notes that awarding a transmission
expander transmission rights that entitle it to collect congestion
rents on the expanded capacity creates an incentive that runs counter
to the purpose of the expansion; i.e., the more successful the
expansion is in eliminating congestion, the less value the incentive
has for the expander. Also, LIPA believes that locational pricing
systems are biased toward using generation to solve congestion problems
on the transmission grid and, as a result, could lead to market power
abuse by an operator that sites a new generator in a load pocket and
then takes advantage of transmission limitations to manipulate the
operation of other generators that it owns.
The Virginia Commission claims that pricing mechanisms
incorporating locational marginal prices tend to produce intense
signals over short time frames, particularly when constraints are
seasonal and driven by extraordinary events such as extreme weather.
The Virginia Commission therefore believes that, at least initially,
locational marginal prices may provide incentives for short-term
actions for congestion relief, rather than longer term solutions such
as the construction of additional transmission or generating facilities
in a particular location.\484\ The Virginia Commission also states that
the use of locational marginal pricing is heavily dependent on the
existence of transparent short-term competitive power markets. It urges
the Commission to evaluate carefully proposals that place greater
reliance on market mechanisms through the use of price signals, and to
condition the use of such mechanisms on the existence of such things as
fully functioning power exchanges, the establishment of fixed
transmission rights and the existence of secondary markets for such
rights.
---------------------------------------------------------------------------
\484\ The Brattle Group believes that, in addition to locational
congestion pricing, some form of regulatory incentives may be needed
to bring about efficient investment in the transmission grid.
---------------------------------------------------------------------------
CP&L argues that while the proposed congestion management rule
appears to permit only PJM-redispatch types of arrangements, CP&L does
not believe that the PJM model is the only workable congestion
management process. Rather, CP&L believes that congestion is best
managed through the coordinated reservation and scheduling of
transactions on the grid rather than post-congestion fixes. Also, TDU
Systems states that it may be difficult to transplant the PJM model to
regions that do not have a centrally dispatched, tight power pool to
use as an RTO platform.
Some commenters claim that LMP is more complex than necessary,\485\
although Allegheny believes that today's technology mitigates these
concerns. The FTC states that, despite the apparent virtues of LMP, it
may be reasonable to back away from a full application of an LMP
approach if doing so provides benefits to consumers from increased
competition in generation markets. For example, the FTC states that, in
light of its alleged complexity and the difficulty that financial
markets may have in anticipating congestion charges, LMP may inhibit
the formation of efficiency-enhancing futures markets in electricity
generation and trading because congestion prices are more uncertain
under LMP than under other pricing approaches (such as zonal
transmission congestion pricing). The FTC thus suggests that the
Commission may want to continue to entertain alternatives to LMP if a
reasonable case is made that benefits to consumers are
[[Page 883]]
greater under the alternatives than under LMP.
---------------------------------------------------------------------------
\485\ See, e.g., PG&E, PJM/NEPOOL Customers, FTC, Tri-State,
Dynegy.
---------------------------------------------------------------------------
Managing Congestion with Tradable Transmission Rights. Several
commenters emphasize the importance of including explicit transmission
rights in any congestion management plan that relies on market
mechanisms.\486\ EPSA believes that when transmission rights are
clearly defined and allocated, ATC calculations can be made more
accurately and congestion management simplified. DOE notes that
financial transmission rights will provide a hedge against long-term
fluctuations in spot prices, will encourage the development of
competitive markets and will likely contribute to efficient generation
and transmission resource planning. SMUD emphasizes that, without the
pricing hedge provided by such rights, it cannot guarantee its
customer-owners low cost or reliable transmission service.
---------------------------------------------------------------------------
\486\ See, e.g., PJM, SMUD, DOE, Enron/APX/Coral Power, EPSA,
NSP, Seattle, Professor Hogan, EME.
---------------------------------------------------------------------------
A number of commenters emphasize that transmission rights must be
tradeable in a secondary market.\487\ Indeed, some commenters believe
that the use of firm (physical) transmission rights along with a robust
secondary market in these rights is the most workable solution for
efficient congestion management.\488\ Seattle notes that with an
effective market for transmission rights, market participants may be
afforded transmission-based options for resolving congestion. It states
that market participants that invest in transmission facilities that
increase capacity can receive the right to use or sell that capacity.
Enron/APX/Coral Power believes that the RTO should be charged with
developing a workable market approach to congestion and parallel-path
management based on clear and tradeable rights for transmission usage
that promote efficient regional dispatch, and support the emergence of
secondary markets for transmission rights. Enron/APX/Coral Power
contends that this will require that RTO systems be operated as they
are in the Western Interconnection based on physical rights. It
suggests that, in order to ensure a firm right to schedule service over
an interface when it is constrained, a customer would have to
demonstrate ownership of sufficient property rights in the interface.
Enron/APX/Coral Power suggests three options for obtaining rights: (1)
From the RTO in the primary auction or other primary form of
allocation; (2) from holders of rights in the secondary market; and (3)
from the RTO in the form of short-term released rights not scheduled by
their holders. Enron/APX/Coral Power states that by defining and
enhancing physical property rights, the market for those rights will
provide ex ante transmission prices that include the cost of purchasing
rights in constrained interfaces. It claims that this will permit
dispatch decisions to be made on the basis of delivered energy prices.
Enron/APX/Coral Power states that to ensure that no market participant
can exercise market power by hoarding property rights, the rights
should be designed as use-or-lose so that if a right is not scheduled
it can be used by others on a non-firm basis.
---------------------------------------------------------------------------
\487\ See, e.g., DOE, NSP, Enron/APX/Coral Power, Seattle,
Nevada Commission.
\488\ See, e.g., APX, Enron/APX/Coral Power, Tri-State, Desert
STAR.
---------------------------------------------------------------------------
Similarly, Dynegy proposes a physical rights model in which a
limited amount of firm physical rights would be sold and only those
holding physical rights would be allowed to schedule when capacity is
constrained. Under Dynegy's proposal, only those with preassigned FTRs
would be allowed to schedule on a firm basis at a set price. Dynegy
states that others could submit non-firm schedules, subject to
curtailment, or, if the party is willing, redispatch. Dynegy adds that
the proponents of rights that are financial only argue that it is
impossible to define physical rights as ``100 percent firm'' from a
given source to a given sink. Dynegy states that, while such arguments
are convincing, the capacity between a source and sink may actually be
available for a significant percentage of the time to a reasonable
degree of certainty and, accordingly, could be sold as firm.
APX states that the definition of transmission property rights
requires the calculation of stable power distribution factors that show
the proportion of a power transaction that flows over each path on the
grid connecting the source-sink pair. It states that after defining the
property rights, the RTO can conduct an auction to allocate them. APX
states that, following the auction, holders of transmission rights can
retain them or trade them in a secondary forward market. APX believes
that FTR trading will provide a more direct and comprehensive valuation
of rights than LMP. Desert STAR states that it plans to rely on firm
transmission rights markets as the primary vehicle for managing
commercially significant congestion, and the use of incremental/
decremental generation bids to manage other congestion.
Other commenters, however, doubt that a system of physical
transmission rights can be used effectively to manage congestion.\489\
NERA states that most commodity markets operate according to a process
based on physical contracts or rights traded in decentralized markets
separated from physical operations. NERA adds, however, that most
commodities do not flow on an integrated grid where network
externalities are so strong and complex that a monopoly system operator
is needed. NERA argues that network externalities on any complex
electricity grid make it virtually impossible to define physical
transmission rights that will use the system fully and yet can be
traded in decentralized markets. Also, Professor Joskow believes that
on complex electric power networks with loop flow, a financial rights
system can be designed more easily and can work more smoothly and
efficiently than can a physical rights system.\490\
---------------------------------------------------------------------------
\489\ See, e.g., NERA, Professor Joskow, Allegheny.
\490\ Professor Joskow notes that Enron/APX/Coral Power claims
that two unpublished papers he has co-authored with Jean Tirole
conclude that physical rights designed on a use-it-or-lose-it basis
(so that they cannot be hoarded) more effectively prevent the
exercise of market power than financial rights, which can always be
hoarded. He states that this is not what the papers conclude.
---------------------------------------------------------------------------
Some commenters offer additional notes of caution regarding the use
of transmission rights. For example, APPA states that one must guard
against market participants using transmission rights to act
strategically. APPA argues that if a generator can adversely affect
transfer capability, it may seek to purchase and resell transmission
rights in the secondary market after manipulating its internal
operations to create congestion on the grid. RECA considers proposals
that allow customers to purchase long-term rights to mitigate the risk
of congestion pricing to be unacceptable because such proposals result
in long-term firm customers having to pay a premium for price
stability. Also, CSU contends that no party should hold any entitlement
over a constrained path due to transmission ownership which predates
the formation of the RTO. CSU argues that, because all parties
dedicating bulk transmission assets to the RTO will be fully
compensated for their embedded costs, there should exist no reserved
rights of use other than those purchased from the RTO. In addition,
Great River is concerned that the NOPR's proposal regarding the
establishment of clear and tradable transmission rights is not
consistent with the flexibility that transmission customers currently
have under network service. Great River urges the Commission to
carefully consider congestion management proposals that preserve
network-like
[[Page 884]]
service, even if such proposals do not result in the identification of
asset-based transmission rights.
Other Mechanisms for Managing Congestion. Some commenters support
yet other market mechanisms for managing congestion.491 EPSA
notes that other pricing approaches that deserve consideration include
the RTO's use of supply-side bids to relieve congestion in load
pockets, as well as the use of bilateral arrangements to solve
congestion problems. Also, NSP recommends that the RTO offer a
``firming'' service, at posted rates, that would provide customers with
the assurance that their transaction will occur under most curtailment
conditions. In addition, NSP proposes that the RTO offer a real-time
redispatch service that will allow transmission customers to buy
through congestion at real-time prices. Cal ISO notes that the
Commission has accepted its zonal approach to congestion management,
which relies on market mechanisms to manage inter-zonal congestion.
PG&E claims, however, that while providing a more understandable
picture of congestion, such a system must still solve the problem of
intra-zonal congestion. Also, the Montana Commission recommends that
the congestion management regime that was developed as a part of the
IndeGO proposal serve as a model for how to manage congestion on the
transmission system. However, Avista claims that the IndeGo proposal
proved to be too complicated to solve a problem that exists only on a
few select transmission paths in the Pacific Northwest.
---------------------------------------------------------------------------
\491\ See, e.g., Cal ISO, Montana Commission.
---------------------------------------------------------------------------
Costs and Revenues in Congestion Management. A number of commenters
urge the Commission to pay close attention to issues related to the
distribution of the costs and revenues of congestion management among
market participants.492 In particular, several commenters
caution that congestion pricing mechanisms should ensure that
congestion costs are fairly allocated and should not result in
excessive revenues or monopoly profits for transmission
owners.493 APPA states that only after we have a nationwide
framework of truly independent RTOs should the Commission consider a
new approach to transmission pricing that would allow the RTO to price
transmission capacity rights and usage on congested paths above
embedded costs while discounting uncongested paths below embedded
costs, subject to a balancing account to ensure that the total
transmission revenue requirement is not over-recovered.
---------------------------------------------------------------------------
\492\ See, e.g., TDU Systems, NCPA, Los Angeles, Wyoming
Commission, SMUD, South Carolina Authority.
\493\ See, e.g., APPA, RECA, TDU Systems, Los Angeles, EPSA.
---------------------------------------------------------------------------
Similarly, TDU Systems believe that while the formation of RTOs is
a unique opportunity to experiment with new forms of transmission
pricing, the Commission should be mindful that an RTO will be a large
regional transmission monopoly. TDU Systems question the wisdom of
designing congestion pricing mechanisms to ensure that limited
transmission capacity is used by market participants who value that use
most highly. It states that such an auction-to-the-highest-bidder
approach could reap monopoly rents for transmission providers, at the
expense of consumers. TDU Systems thus argues that over-reliance on
economic self-interest and market mechanisms in transmission pricing
may become a recipe for new forms of undue discrimination. It suggests
that an incentive to avoid expanding the system in order to collect
monopoly rents can be removed by placing any excess revenues from
congestion pricing in a fund earmarked for transmission system
expansion.
TDU Systems also recommends that the Commission encourage
congestion management plans that distinguish between congestion caused
by the RTO's obligation to provide service to firm transmission
customers, and congestion caused for economic reasons. It argues that,
in the case of the former, the costs of relieving the congestion should
be averaged over the firm RTO transmission customers that are using its
system. However, it claims that economic congestion occurs because
market participants wish to take advantage of short-term production
cost economies to minimize their power costs. In this case, TDU Systems
argues that the specific loads purchasing the generation should pay the
associated congestion costs. Also, RECA states that long-term firm
transmission customers are the ones that use and pay to support the
system throughout the year, but the auction approach allows a short
term trader to outbid these customers at the very times they need it
most. Enron/APX/Coral Power notes that, if the RTO's regulated rates
for transmission service, including congestion management, are properly
designed to reward the RTO for cutting operating costs and maximizing
throughput, then it would not have to assign the grid expansion costs
to new generators that interconnect. Instead, the RTO would charge the
new generator only the cost of local interconnection with the grid.
Dynegy claims that, with respect to each transmission provider's
system, there is a predictable level of constraints and, similarly,
some representative level of costs associated with relieving those
constraints. Dynegy believes that such costs should be rolled into firm
transmission rates that can be quoted up front and with certainty.
Dynegy argues that transmission providers would have an economic
incentive to operate their transmission systems efficiently if they are
given an uplift cost target, and are rewarded for beating the target
and penalized for exceeding the target. EPSA states that some
congestion pricing mechanisms can impose potentially huge costs on
individual transactions, which can be detrimental to the goal of
fostering wholesale competition. EPSA thus urges the Commission to
consider whether these pricing mechanisms provide greater benefits than
a system that internalizes more of the congestion costs. Indeed, EPSA
argues that it is still appropriate to spread many of those costs to
all system users because redispatch generally benefits all users of the
transmission system.
NCPA asserts that, in order to prevent large increases in the cost
of generation for customers in congested areas, some non-discriminatory
way must be found to return the extra revenues collected to those
customers. NCPA believes that this will require restructuring of
tariffs, but failure to address the problem is likely to keep utilities
with customers in congested areas out of the California ISO. Similarly,
the South Carolina Authority is concerned that certain centralized
market mechanisms would cause cost shifts for those participating in an
RTO, and if so, potential participants opt out. Also, the Wyoming
Commission is concerned that, by offering rewards for transmission
investment such as a higher return on equity, the Commission would
effectively be discouraging a more market-oriented review of
alternatives to building transmission to solve congestion problems.
Some commenters emphasize the importance of ensuring full cost
recovery for generators that are redispatched by an RTO to alleviate
transmission constraints or to provide other support
services.494 NERC contends there must not be disincentives,
in the form of unrecovered costs, to having generators perform these
vital functions. MidAmerican asserts that optimal dispatch will occur
during congestion management as long as all power suppliers are fully
compensated at
[[Page 885]]
market prices. Cinergy claims that, unless generators have the ability
to recover lost revenues for reducing generation in response to
congestion management needs, generators have no incentive to follow
dispatch orders. SMUD contends that the Commission needs to develop
congestion management principles that ensure that market participants
will receive fair market value for facilities that they have owned and
operated for many years.
---------------------------------------------------------------------------
\494\ See, e.g., Allegheny, Platte River, NERC.
---------------------------------------------------------------------------
Importance of Scale in Congestion Management. A number of
commenters argue that the achievement of an appropriate scale by an RTO
will be important to the effective management of
congestion.495 LG&E states that the Commission should
require RTOs to be of sufficient size to be capable of meaningfully
addressing congestion. It believes that if a proposed RTO's ability to
address congestion would be impaired by its size or configuration, then
the Commission should either refuse the RTO's application or should
condition approval on attaining the necessary size and configuration to
manage regional congestion issues. Industrial Consumers state that,
although congestion management can be addressed with non-market
solutions such as transmission loading relief procedures, it is far
better to internalize the problem within an RTO with an appropriate
scope and configuration. Minnesota Power notes that, currently, it can
have transactions curtailed by two different procedures, NERC
Transmission Loading Relief and MAPP Line Loading Relief. It claims
that an RTO will provide transmission users with region-wide, standard,
congestion management.
---------------------------------------------------------------------------
\495\ See, e.g., LG&E, ComEd, Midwest ISO Participants, Midwest
ISO.
---------------------------------------------------------------------------
The Midwest ISO states that an appropriately sized RTO will be able
to relieve congestion on a broad scale. However, it claims that its own
redispatch options will be limited by the failure of border companies,
such as FirstEnergy and AEP, to join it. Also, it notes that longer
term congestion relief involves the construction of transmission
facilities. It claims that, if border companies are not members, the
Midwest ISO will not have the ability to coordinate required
transmission construction by those entities. Also, the Midwest ISO
Participants state that new transmission facilities required to relieve
constraints may involve both the companies of the Alliance RTO and the
Midwest ISO Participants. The Midwest ISO Participants believe that,
with planning and authority split between these two regional entities,
these facilities may not be optimally constructed or located.
Ontario Power, however, takes a different view. It claims that many
of the advantages that would flow from expanding U.S. markets to
include Ontario can be realized without requiring the Independent
Electricity Market Operator (IMO) in Ontario to join a larger RTO at
this time. Ontario Power believes that these advantages could be
achieved by negotiating agreements between the IMO and other RTOs.
Also, Central Maine states that if transmission line loading relief is
performed on a market basis, many of the benefits that might result
from merging existing ISOs could be realized without actually requiring
those ISOs to merge.
Tri-State argues that the Commission should provide an incentive
for non-participating transmission owners to join an RTO by allowing
the RTO to use a pricing and congestion management structure that
withholds the benefits of the RTO from entities that refuse to turn
control of their transmission assets over to the RTO. Also, Vernon
claims that non-participants can take unfair advantage of ISO-
controlled facilities by scheduling their own loads over ISO grid
facilities that parallel the non-participant paths, instead of
scheduling them over their own wires. Vernon contends that having thus
freed up their own wires, the non-participants can then put their
facilities to various uses, such as to avoid the increased ISO grid
congestion.
Congestion Management Between RTOs. Many commenters believe that
effective congestion management must take into account effects that
extend beyond the RTO's boundaries.496 NERC states that
congestion management approaches that work within a particular region
may not adequately deal with transactions that originate or terminate
outside the region. NERC believes that as RTOs develop congestion
management approaches, the Commission must require that they be
compatible with what is happening elsewhere.
---------------------------------------------------------------------------
\496\ See, e.g., NERC, Mass Companies, Industrial Consumers,
Montana Commission, Indiana Commission, AEP.
---------------------------------------------------------------------------
Industrial Consumers believe that congestion management, especially
during emergency conditions, is an interconnection-wide responsibility.
It asserts that, if multiple RTOs are allowed within an
interconnection, congestion management must be coordinated across RTO
boundaries. Industrial Consumers argues that an RTO can accomplish this
only by sharing data on system conditions (e.g., ATC calculations) with
neighboring RTOs, agreeing to protocols for cross-boundary actions to
mitigate congestion, and cooperating in a process to ensure fair
compensation to generators that are redispatched.
UAMPS believes that if a state is involved in the consideration of
various potential solutions to regional congestion, it will likely be
more willing to accept that a particular proposal to construct new
transmission within its borders is indeed the most efficient solution
to a genuine problem, and to provide the necessary approvals for that
construction.
Transcos and Congestion Management. Some commenters are concerned
that, if a for-profit company owns transmission (e.g., a transco), it
may not have the correct incentives to manage congestion
efficiently.497 ISO-NE argues that if such a company seeks
to operate transmission and markets as an RTO, it will have competing
responsibilities and economic interests. ISO-NE believes that, given
the company's economic motivations, market participants may have
insufficient confidence in such a company's determinations of whether a
transmission-expansion solution to congestion is preferable to a
generation-based solution. EAL believes that compensating a wire-owning
RTO on the basis of invested capital could lead to over-building of
transmission. New Smyrna Beach is concerned that a for-profit
transmission company will exhibit a bias toward transmission
construction when other, more economical alternatives might exist. New
Smyrna Beach states that the Commission should consider requiring the
RTO to conduct a competitive bidding process when it determines that
transmission construction, or an alternative, is needed to relieve
transmission constraints.
---------------------------------------------------------------------------
\497\ See, e.g., ISO-NE, EAL, New Smyrna Beach, Industrial
Consumers.
---------------------------------------------------------------------------
Industrial Consumers asserts that transcos would compete head-on
with generation companies wherever there is congestion. It thus
believes that transcos-as-RTOs would have a serious conflict of
interest if they have the authority over congestion management and over
the decision whether to eliminate congestion with new generation or
transmission facilities. Industrial Consumers believes that where new
generation is a more cost-effective option than construction of new
transmission facilities, the cheaper option should be built, and
markets should be given the opportunity to make
[[Page 886]]
the choice. Industrial Consumers believes, however, that this will
require that the markets have access to redispatch costs, congestion
valuations (from a secondary market for capacity reservations), and
other data on grid conditions. This is information that is better
disclosed by a disinterested independent RTO than a self-interested
transco or generation company.
Cal DWR questions whether either ISOs or transcos have an incentive
to use transmission alternatives (such as demand-side management, load
shedding, distributed generation, or generation) to reduce the overall
cost of transmission. However, it believes that this problem may be
more acute for a transco, for which revenues and return are directly
tied to the use of their transmission assets.
However, other commenters claim that there is no basis for concerns
that a transco will favor a transmission solution to
constraints.498 Entergy contends that, if a generation
solution is the most efficient way to resolve congestion, a new
generator will likely realize that and try to locate in the appropriate
area. Entergy states that an RTO's obligations as an open access
transmission provider leave it with no choice but to interconnect with
the new generator. Also, Entergy argues that an RTO will not have the
unfettered ability to propose and build inefficient transmission
solutions. It believes that review by state regulators with siting
authority, and prudence review by the Commission, will make it
difficult for an RTO to build inefficient and unnecessary transmission
additions. Enron/APX/Coral Power and JEA believe that a transco may, in
fact, be well suited for congestion management. Enron/APX/Coral Power
states that placing responsibility for managing congestion in the RTO's
hands complements their view that an RTO-Transco must be obligated to
assume delivery risk (i.e., deliver physically firm power) in exchange
for being rewarded for cutting costs and increasing system throughput.
---------------------------------------------------------------------------
\498\ See, e.g., Trans-Elect, FirstEnergy, Entergy.
---------------------------------------------------------------------------
The Need for Flexibility in the Design of Market Mechanisms.
Commenters in general showed considerable support for the NOPR's
proposal to give RTOs considerable flexibility in experimenting with
different market approaches to managing congestion.499 Mass
Companies state that the NOPR's willingness to allow RTOs latitude to
develop local approaches to congestion management is particularly
appropriate, given the difference in conditions in different parts of
the country. CP&L believes that congestion management is an area where
a one-size-fits-all solution would miss the mark and unnecessarily
increase the cost of forming and operating an RTO. SRP believes that a
flexible approach is needed because the use of market mechanisms for
congestion management is in its infancy, and poorly designed market
mechanisms can exacerbate problems and adversely impact reliability.
---------------------------------------------------------------------------
\499\See, e.g., Mass Companies, SRP, CP&L, Southern Comany, PJM/
NEPOOL Customers, United Illuminating, Georgia Commission, JEA,
Florida Commission, NYPP, Cinergy.
---------------------------------------------------------------------------
The Florida Commission states that the details of proposals for
managing congestion using a market mechanism should be determined on a
regional basis with endorsement by the state regulatory body. The
Florida Commission recommends that the Commission continue to monitor
discussions of these issues within NERC and not duplicate or foreclose
their development and resolution at NERC.
Montana-Dakota recommends that the Commission not limit the
experimentation with market mechanisms to the provision of firm
transmission service. Montana-Dakota believes that there is potential
to further improve transmission services by allowing RTOs the ability
to implement congestion management methods for non-firm services rather
than relying only on the use of TLR to curtail such services.
Many commenters express support for the proposal to allow RTOs
flexibility in developing approaches to congestion
pricing.500 Some, such as Florida Power Corp. and Desert
STAR, believe that allowing flexibility in pricing may provide
incentives for transmission owners to join or form an RTO. Florida
Power Corp. argues that such flexibility allows transmission owners to
deal with issues such as cost shifting, and believes that providing
more specific guidance will only limit possible options.
---------------------------------------------------------------------------
\500\ See, e.g., PJM/NEPOOL Customers, United Illuminating,
Florida Power Corp., Desert STAR, Oregon Commission, NERC.
---------------------------------------------------------------------------
However, the FTC cautions that the Commission should not allow its
policy of flexibility to continue indefinitely. The FTC states that
although experimentation with transmission congestion pricing
alternatives to LMP may be appropriate at present, it does not believe
that great uncertainty about the most effective approach to
transmission congestion management need exist indefinitely. It suggests
that the Commission may wish to establish a date in the not-too-distant
future when it will undertake a comparative analysis of the consumer
costs and benefits of alternative transmission pricing regimes. The FTC
states that if one or more approaches provide substantially superior
results for consumers, the Commission may wish to initiate a rulemaking
on policies to encourage RTOs to adopt these approaches. The Oregon
Commission recommends that the Commission evaluate the effectiveness
and efficiency of various congestion pricing experiments, and based on
its evaluation, require RTOs to use the better methods. However, the
Oregon Commission estimates that the process of refining congestion
pricing methods may take a decade or more.
NERC states that there are strongly held, differing opinions
throughout the industry on how congestion prices should be designed.
NERC states that, while flexibility is one important consideration, the
various regional solutions must be able to work together. It believes
that the Commission can provide the leadership needed to bring the
industry to closure on these issues. NERC notes that this may require
the Commission to be more proscriptive, and it should not hesitate to
do so. In this regard, Minnesota Power suggests that the Commission
encourage neighboring RTOs with constrained interfaces to jointly
develop constraint relief procedures including common constraint
pricing where appropriate.
Timing of Implementation.With regard to the NOPR's proposal to
allow RTO's up to one year after start-up to implement the congestion
management function, commenters express a variety of opinions. Some
indicate that one year is an appropriate additional time
period.501 Others, however, believe that it is essential
that the RTO have some form of congestion management system in place
when it begins operation.502 SMUD and CMUA state that a
significant deterrent to participating in the Cal ISO has been the fact
that, in California, Cal ISO transmission is strictly a short-term
transaction given that Cal ISO has not yet fully implemented FTRs. SMUD
emphasizes that, without the hedge provided by FTRs, it cannot
guarantee its customer-owners low cost or reliable transmission
service. TANC believes that allowing an RTO to begin operations without
a congestion management procedure in place greatly increases the
opportunity for market power abuses as well as market inefficiency.
---------------------------------------------------------------------------
\501\ See, e.g., Industrial Consumers, Allegheny, PGE, Entergy.
\502\ See, e.g., SMUD, Tri-State, CMUA, TANC, Desert STAR,
Cinergy.
---------------------------------------------------------------------------
[[Page 887]]
Duke states that, ideally, the permanent congestion management
function should be in place on the first day of RTO operation. Then,
Duke notes, it would not be necessary to incur the cost of
implementing, and developing strategies and behavior appropriate to an
initial system, only to have to incur additional costs and changes in
behavior to adapt to a permanent system. However, Duke states that
congestion management issues are complex and substantial information
management systems must be put in place. Consequently, Duke believes
one year from the time the RTO becomes operational may not be a
sufficient length of time to implement the congestion management
function.
Desert STAR states that the new approaches to congestion management
called for by newly competitive markets will take additional time to
work out and, therefore, the Commission should be willing to consider
additional time on a case-by-case basis. However, in order to ensure
reliable operation, Desert STAR believes some congestion management
system must be in place when the RTO begins operation.
Some commenters believe that more than one year of additional time
may be needed for the RTO to implement the congestion management
function. NSP states that if the RTO has a state-estimator model with
the necessary properties, it is possible that a congestion management
system, of the type preferred by NSP, could be implemented within about
18 months from the time of project initiation. However, for regions
without the necessary models, NSP expects the time-line would likely be
three years from time of project initiation.
Montana Power believes that there will be many ``growing pains''
associated with implementation of RTOs that will take time to work out,
especially in areas like the Pacific Northwest, which have no history
of tight pool operation. Montana Power believes that allowing one-year
for implementing a market mechanism for congestion management is a very
aggressive schedule. Montana Power thus encourages the Commission to
allow up to three years. Similarly, Avista states that, with the IndeGo
experience in mind, it encourages the Commission to allow two to three
years for implementation of this function, especially where it is
demonstrated that the RTO will comply immediately with other
characteristics and functions identified in the Commission's Final
Rule.
The Florida Commission believes that the Commission should not
impose any arbitrary time period for implementation of congestion
management. It states that NERC is working with the regions on this
issue and FERC should monitor those activities before setting any
deadlines, if at all. Also, JEA believes that requiring the congestion
management function to be in place within one year from the start-up of
RTO operation may be feasible only for those RTOs structured as
transcos from the beginning.
Commission Conclusion. As we proposed in the NOPR, we conclude that
an RTO must ensure the development and operation of market mechanisms
to manage congestion. Furthermore, as we proposed, we will require that
responsibility for operating these market mechanisms reside either with
the RTO itself or with an another entity that is not affiliated with
any market participant.
We agree with the large number of commenters that believe that the
use of market mechanisms to manage congestion is superior to the use of
administrative curtailment procedures or other approaches that do not
take into account the relative value of transactions that are curtailed
and those that are allowed to go forward. In addition, we conclude that
the RTO or an independent entity must assume an active role in
developing and implementing any congestion market mechanisms, because
the use of such mechanisms must necessarily be closely coordinated with
the operational activities that the RTO performs on a day-to-day and,
in many cases, moment-to-moment basis.
Some commenters argue that an RTO should not be allowed to operate
a centralized market for congestion management. The commenters contend
that, if such a market is operated by an RTO or other entity that is
independent of the market, a robust market in forward contracts for
energy will not develop. As a result, these commenters claim, society
will never obtain the efficiency benefits that would otherwise flow
from a marketplace in which buyers and sellers are able to trade
actively among themselves. These commenters also argue that the price
certainty provided by forward markets will be replaced with the
uncertainty of prices that are determined after the fact.
We disagree with these commenters and see no reason why the RTO's
operation of a market for congestion management should inhibit the
ability of others to offer forward contracts for energy, or other
market instruments that provide price certainty. We recognize that some
of the market redispatch programs undertaken to date are experimenting
with various ways to manage congestion efficiently-including relying
upon decentralized markets to effect the necessary
redispatch.503 It is too early to tell if these
decentralized markets will work efficiently. But given the short time
frame in which system operators often must react to congestion
situations, experience may ultimately show that markets for congestion
management can achieve more efficient and effective results if they are
centrally operated. Therefore, we will not deny here the RTO, or other
independent entity, the opportunity to operate a market--either
centralized or de-centralized--for congestion management.
---------------------------------------------------------------------------
\503\ See, e.g., the market redispatch experiment of NERC
(Docket No. ER99-2012-000).
---------------------------------------------------------------------------
As we proposed in the NOPR, we will require the RTO to implement a
market mechanism that provides all transmission customers with
efficient price signals regarding the consequences of their
transmission use decisions. We are convinced that efficient congestion
management requires that transmission customers be made aware of the
cost consequences of their actions in an accurate and timely manner,
and we believe that this is best accomplished through such a market
mechanism. Also, as we proposed in the NOPR, we believe that congestion
pricing proposals should seek to ensure that (1) the generators that
are dispatched in the presence of transmission constraints are those
that can serve system loads at least cost, and (2) limited transmission
capacity is used by market participants that value that use most
highly. Although we agree with some commenters that price signals can
also assist in determining the efficient size and location of new
generation and grid expansions, we share the view of LIPA and others
that price signals alone cannot be relied upon to identify all needed
enhancements.
While we will not prescribe a specific congestion pricing
mechanism, we note that some approaches appear to offer more promise
than others. As we stated in our order approving the PJM ISO and
reiterated in the NOPR, markets that are based on locational marginal
pricing and financial rights for firm transmission service appear to
provide a sound framework for efficient congestion
management.504 A number of commenters express strong support
for the LMP approach. As PJM notes in its comments, LMP assesses
congestion charges directly to transmission customers in a manner
consistent with
[[Page 888]]
each customer's actual use of the system and the actual dispatch that
its transactions cause. In addition, LMP facilitates the creation of
financial transmission rights, which enable customers to pay known
transmission rates and to hedge against congestion charges. We further
note that, where financial rights holders are entitled to receive a
share of congestion revenues, the availability of such rights helps to
address the concerns of commenters who fear that congestion pricing can
lead to the over-recovery of transmission costs. The Commission
recognizes, however, that LMP can be costly and difficult to implement,
particularly by entities that have not previously operated as tight
power pools.
---------------------------------------------------------------------------
\504\ See PJM, 81 FERC at 62,252-53.
---------------------------------------------------------------------------
The principal alternative to LMP advocated by commenters is an
approach that manages congestion by means of physical transmission
rights that are tradable in a secondary market. Under this approach,
the RTO may be required to issue the transmission rights initially
through an auction or allocation process. Market participants would
then generally have to demonstrate ownership of sufficient rights in a
constrained interface before they would be allowed to schedule firm
service over the interface. Such an approach greatly reduces the role
of the RTO in congestion management. While the approach of trading
physical transmission rights in a secondary market may prove to be
workable in regions where congestion is minor or infrequent, in other
regions where congestion is more of a chronic problem, it may not be
workable. Also, commenters such as NERA and Professor Hogan claim that
the network interactions on complex electricity grids make it difficult
to define physical transmission rights that will use the system fully
and yet can be traded in decentralized markets. We expect RTOs and any
affected stakeholders to consider carefully such issues as they
formulate specific pricing proposals.
While our experience has shown that, in specific situations, some
approaches to congestion pricing appear to have advantages over others,
we have not yet identified one approach as being clearly superior to
all others. Furthermore, the Commission recognizes that an RTO's choice
of a congestion pricing method will depend on a variety of factors,
many of which may be unique to that RTO. Therefore, we will allow RTOs
considerable flexibility to propose a congestion pricing method that is
best suited to each RTO's individual circumstances.
Some commenters appear to confuse the need to redispatch generators
to maintain reliability with the need to take specific actions to
relieve congestion. Commenters generally agree that the RTO should have
clear authority to order redispatch for reliability purposes. However,
for congestion management, we conclude here that the RTO should attempt
to rely on market mechanisms to the maximum extent practicable. We
recognize, of course, that there may be times when even well-
functioning markets will fail to provide the RTO with the options it
needs to alleviate a specific instance of congestion. In those cases,
the RTO must have the authority to curtail one or more transmission
service transactions that are contributing to the congestion. Although
the act of curtailing a transaction may sometimes require the
redispatch of generation, we clarify that we are not requiring the RTO
to redispatch any generators exclusively for the purpose of managing
congestion.
In the NOPR, we stated that a workable market approach to
congestion management should establish clear and tradeable rights for
transmission usage, promote efficient regional dispatch, support the
emergence of secondary markets for transmission rights, and provide
market participants with the opportunity to hedge locational
differences in energy prices. Most commenters agree that these are
reasonable features of any congestion management proposal. However,
Enron/APX/Coral Power believes that the RTO should not be allowed to
provide a hedging instrument. It contends that the ``monopoly wires
business'' should not be allowed to encroach on what it views as the
highly competitive and innovative business of providing hedges against
locational price differences of energy or capacity, or against price
volatility of these or any other competitive products. In response, we
note that, while decentralized markets may ultimately prove to be
capable of providing such products, as these commenters claim, we do
not yet have evidence to that effect. Therefore, in the interest of
allowing RTOs flexibility to experiment with different market
approaches, we will not prohibit the RTO from offering such products
through markets that it may operate.
Finally, with regard to the timing of implementation of the
congestion management function, we will adopt our proposal to allow the
RTO to take up to one year after start-up to implement market
mechanisms for managing congestion. Most commenters agree that some
period of time is needed for implementation. However, a number of them
indicate that the RTO must have some form of congestion management
system in place when it begins operation. We agree, and clarify that,
upon start-up, the RTO must have in place effective protocols for
managing congestion while preserving reliability. Because the NOPR did
not make this point explicitly, we do so here.
3. Parallel Path Flow (Function 3)
In the NOPR, the Commission proposed to require that an RTO develop
and implement procedures to address parallel path flow issues within
its region and with other regions.\505\ The Commission noted that
measures to address parallel path flow between regions may not
necessarily be in place on the first day of RTO operation, and proposed
to allow up to three years after start-up for this function to be
implemented.\506\ The Commission sought comments on whether such an
additional implementation time period is warranted, and whether three
years is an appropriate additional time period.
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\505\ The terms ``parallel path flow'' and ``loop flow'' are
sometimes used interchangeably to refer to the unscheduled
transmission flows that occur on adjoining transmission systems when
power is transferred in an interconnected electrical system.
\506\ FERC Stats. and Regs. para. 32,541 at 33,743-44.
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Comments. Virtually all commenters support the NOPR's proposal to
require that an RTO develop and implement procedures to address
parallel path flow issues as a separate function.\507\ Industrial
Consumers states that parallel path flow-related disputes will diminish
as a result of RTOs addressing this issue.\508\ But PGE notes that
grandfathering existing transmission contracts may impede the RTO's
ability to address loop flow.
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\507\ See, e.g., ComEd, East Texas Cooperatives, EPSA,
Industrial Consumers, LG&E, NASUCA, NSP, PJM, Southern Company and
Williams. However, Cinergy argues that parallel path flows should
not be considered as a separate function but should be considered as
a characteristic under the scope and regional configuration because
that will allow an RTO to address congestion management issues along
with parallel path issues.
\508\ Industrial Consumers also notes that the first sentence in
the proposed regulation should be modified to read as ``RTO must
develop and implement procedures to address parallel path flow
issues within its region and with other regions in the
interconnection within which it resides.'' (Suggested change
underlined)
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Many commenters assert that parallel path flow and congestion
management issues are closely related to one another since both the
issues involve identification of power flows resulting from a specific
transaction.\509\ Therefore, they argue that any solution to parallel
path flow should recognize
[[Page 889]]
this close relationship. For example, Industrial Consumers believes
that an RTO can take preemptive actions against potential curtailment
situations to manage congestion resulting from loading of chronically
constrained transmission interfaces due to loop flow. PJM suggests that
the use of redispatch solutions like LMP not only is more efficient and
beneficial to a competitive market, but is preferable to curtailing
transactions under TLR to address congestion due to loop flow. South
Carolina Authority is convinced that over the long run the problem of
parallel path flow needs to be addressed as a planning issue, focusing
on appropriate reinforcements to constrained transmission lines.
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\509\ See, e.g., EPSA, Florida Power Corp., FTC, Georgia
Transmission, LG&E, Mass Companies, NSP and PJM.
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Many commenters recommend that an RTO should encompass as large a
region as possible so that it can ``internalize'' most of the loop flow
within its region.\510\ However, others argue that the loop flow issue
can be solved satisfactorily only if it is addressed at the
interconnection level.\511\ They believe that while a large RTO will
``internalize'' most of the parallel path flows within its region,
parallel path flows between RTOs will remain. Some other commenters are
convinced that cooperative efforts among regional entities works best
when it comes to resolving issues such as parallel path flow
issue.\512\ NERC notes that it is in the process of developing the
needed information system to address the parallel path flow issue on an
interconnection basis and urges the Commission to direct the RTOs to
work closely with it to coordinate efforts to resolve this issue.
Southern Company and Industrial Consumers support NERC's initiative in
solving the loop flow issue. Cleveland states that the national grid
should be viewed as a single electrical system which calls for a
universal approach rather than a regional approach to resolve the loop
flow issue. The universal approach, Cleveland argues, will not only
improve the integrity and reliability of the national grid but also
eliminate the need for any policy shift in the future.
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\510\ See, e.g., LG&E, Michigan Commission, NASUCA, New Smyrna
Beach, NSP, PJM and South Carolina Authority.
\511\ See, e.g., Cleveland, East Texas Cooperatives, Georgia
Transmission, Industrial Consumers, NY ISO, Southern Company, TEP.
Industrial Consumers note that several other issues need to be
addressed at the interconnection level and not at the regional
level. They are ATC calculation, inadvertent flows and congestion
management.
\512\ Central Maine Reply at 9; NYPP Reply at 10.
---------------------------------------------------------------------------
Commenters from Western System Coordinating Council (WSCC) assert
that the loop flow issue in their region was solved by the adoption of
WSCC Flow Mitigation Plan (Plan) that provides for controlling
unscheduled flows through the use of phase shifting transformers.\513\
SRP suggests loop flow in WSCC should continue to be addressed at the
WSCC level and not at the RTO level because WSCC may end up with four
or more RTOs. PG&E recommends that the establishment of property rights
such as FTRs be explored as a means to solve loop flow issues, on the
basis that developing property rights will ensure the most efficient
use of the transmission lines. Enron/APX/Coral Power urges RTOs in the
Eastern Interconnection to move toward the Western model. NASUCA
believes that RTOs should perform a cost-benefit analysis of
controlling loop flows with phase shifting transformers.
---------------------------------------------------------------------------
\513\ See, e.g., PG&E, Seattle, SRP and TEP.
---------------------------------------------------------------------------
Most commenters support the NOPR's proposal for an additional
implementation time period of three years for coordination among
RTOs.\514\ They argue that the proper resolution of loop flow presents
a number of complex issues that may require negotiations and agreements
among neighboring RTOs and that the additional time period will give
them an opportunity to coordinate their efforts. Allegheny supports an
additional time period for implementation of this function but urges
the contract path methodology be replaced at a faster pace than three
years. Industrial Consumers notes that an additional time period of
three years is necessary for NERC to solve the loop flow issue at the
interconnection level. However, Florida Power Corp. and Florida
Commission observe that the severity of parallel path flow varies from
region to region and therefore opposes setting an arbitrary time limit
for the implementation of this function. Duke likewise believes that
the deadline for the implementation of this function should be
determined by the Commission on a case-by-case basis.
---------------------------------------------------------------------------
\514\ See, e.g., Cal ISO, Desert STAR, Entergy, Industrial
Consumers, NECPUC, NERC, NY ISO, PGE, SRP, Tri-State, TVA, UtiliCorp
and WPSC. Cleveland also argues that a similar grace period should
be given for the implementation of function # 5. (TTC and ATC
Calculation). Cleveland at 14.
---------------------------------------------------------------------------
Commission Conclusion. We reaffirm our preliminary determination
that an RTO should develop and implement procedures to address parallel
path flow issues within its region and with other regions. Most
commenters agree that the formation of RTOs, with their widened
geographic scope of transmission scheduling and expanded coverage of
uniform transmission pricing structures, provide an opportunity to
``internalize'' most, if not all, of the effect of parallel path flow
in their scheduling and pricing process within a region. NERC notes
that it is in the process of developing the needed information system
to address parallel path issues on an interconnection basis, and we
will direct RTOs to work closely with NERC, or its successor
organization, to resolve this issue. As noted by Industrial Consumers,
parallel path flow-related disputes will diminish as a result of RTOs
addressing this issue.
Commenters from Western System Coordinating Council (WSCC) state
that they adopted the WSCC Flow Mitigation Plan (Plan) to address
parallel path flow issue in their region. SRP suggests that parallel
path flow in WSCC continue to be addressed at the WSCC level and not at
the RTO level because WSCC may end up with more than one RTO. We will
not here make any judgments on the merits of WSCC's Plan as a solution
for parallel path flow issues. However, we clarify that this rule does
not prevent addressing parallel path flow issues on a larger-than-
single-RTO basis. In fact, we require RTOs to develop and implement
procedures for addressing parallel flow issues with other regions.
In the NOPR we proposed that the RTO have measures in place on the
date of initial operation to address parallel path flow issues within
its own region. We also noted that measures to address parallel path
flow issues between RTO regions may not necessarily be in place on the
first day of RTO operation. We proposed to allow up to three years
after start-up for this function to be implemented. Most commenters
support the NOPR's proposal for an additional time period of three
years. A few commenters \515\ prefer a case-by-case approach. Since
severity of the parallel path flow varies from region to region, some
parts of the Nation may choose to resolve inter-regional parallel path
flow issues sooner than the required three years. Consequently, we will
adopt our proposal in the NOPR that the RTO have measures in place to
address parallel path flow issues in its region on the date of initial
operation. We also adopt three years as an adequate time period for
implementation of measures to address parallel path flow issues between
regions.
---------------------------------------------------------------------------
\515\ Florida Power Corp., Florida Commission and Duke.
---------------------------------------------------------------------------
We recognize that these measures to address parallel path flows
combined with the requirement that the RTO be the sole provider of
transmission services over facilities that it owns or controls will
eliminate or diminish the ability of transmission users to choose among
different contract paths owned by different service providers within
the
[[Page 890]]
RTO region. However, these users will have the ability to move power
anywhere within the RTO at a single rate and under a single set of
terms and conditions. We believe this is pro-competitive and represents
one of the fundamental benefits that is envisioned by the Rule. As we
noted in the NOPR, the creation of large RTOs that can internalize
most, if not all, of the effect of parallel path problems through their
scheduling and pricing actions provides a unique opportunity to resolve
a major operating concern that has caused problems on both the Eastern
and Western Interconnections and which is a significant impediment to
promoting efficient competition in generation markets.\516\ Therefore,
in reviewing the competitive implications of a proposed RTO application
under section 203, we believe that any inability of transmission
customers to choose among different contract path suppliers within an
RTO will be outweighed by their enhanced ability to reach numerous
buyers and sellers of electricity throughout the region.
---------------------------------------------------------------------------
\516\ See FERC Stats. and Regs. para. 32,541 at 33,744.
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4. Ancillary Services (Function 4)
The fourth proposed minimum function is that the RTO must serve as
the supplier of last resort for all ancillary services required by
Order No. 888.\517\ This supply obligation for the RTO is necessary
because only the single grid operator will be able to provide certain
ancillary services, not all transmission customers may be able to self-
supply (some own generation, others do not), and because it typically
is more efficient for the RTO to provide some ancillary services for
all transmission users on an aggregated basis.
---------------------------------------------------------------------------
\517\ FERC Stats. and Regs. para. 32,541 at 33,744.
---------------------------------------------------------------------------
In carrying out this function, the Commission proposed that all
market participants would have the option of self-supplying or
acquiring ancillary services from third parties. In addition, the RTO
must have the authority to decide the minimum required amounts of each
ancillary service and, if necessary, the locations at which these
services must be provided; must be able to exercise direct or indirect
operational control over all ancillary service providers; must promote
the development of competitive markets for ancillary services whenever
feasible; and must ensure that its transmission customers have access
to a real-time balancing market.
Comments. Supplier of Last Resort. Comments on whether an RTO
should serve as a supplier of last resort are mixed. A large number of
commenters support the Commission's proposal, as written.\518\ Detroit
Edison believes that the RTO should serve as the sole supplier of
ancillary services to transmission customers and that the RTO should be
permitted either to purchase services directly from generation
suppliers or to purchase generation resources for this purpose. First
Energy believes that the RTO's obligation as the supplier of last
resort for ancillary services cannot be eliminated, since it is the
basis of reliability.\519\
---------------------------------------------------------------------------
\518\ See, e.g., Entergy, Industrial Consumers, NECPUC, Cal ISO,
EPSA, FirstEnergy, LG&E, PacifiCorp, Empire District, EME, Southern
Company, UtiliCorp, PGE, PNGC, PSNM, TDU Systems, Nevada Commission.
\519\ See also Florida Power Corp.
---------------------------------------------------------------------------
On the other hand, a few commenters suggest that the Commission
allow flexibility. Duke believes that an RTO should always have the
responsibility for ensuring that transmission customers have arranged
adequate ancillary service and that those services are delivered. They
suggest that where a competitive market for ancillary services exists,
the RTO should not be required to provide such ancillary services as a
supplier of last resort.\520\ And a number of commenters take issue
with one or more aspects of the proposed requirements, although many of
these commenters generally support the proposal.
---------------------------------------------------------------------------
\520\ See, e.g., NASUCA, Seattle, CalPX, Mass Companies.
---------------------------------------------------------------------------
For example, some commenters suggest that more information is
needed. Southern Company suggests that the Commission allow NERC to
finalize an ancillary services policy before mandating changes to
ancillary service requirements.\521\ Professor Hogan suggests further
investigation into developments in ancillary services.\522\
---------------------------------------------------------------------------
\521\ Southern Company notes that NERC's Interconnected
Operations Services Working Group is currently addressing the
ancillary services that should be required in a competitive
environment and has issued a proposed policy for public comment and
review.
\522\ NWCC recommends that additional research regarding the
application of ancillary services to wind and other intermittent
generation technologies be conducted.
---------------------------------------------------------------------------
Other commenters believe that the focus of the proposal should be
narrowed. Los Angeles suggests that an RTO should be the ``safety net''
of last resort for providing generation-based ancillary services. As
such, the RTO would not play a significant role in the energy market
and can remain essentially indifferent to energy market issues. PG&E
believes that an RTO could set appropriate rules for ancillary services
but would not itself procure such services from the marketplace absent
clearly defined emergency situations or in its role as provider of last
resort. Avista states that while a transitional ``supplier of last
resort'' role may be appropriate, an RTO should generally not become
deeply involved in any of the markets for generation services.
A number of commenters suggest that the obligation to provide
ancillary services should be expanded to include more or different
sellers. MidAmerican believes that each control area should retain
responsibility for the provision of ancillary services and should be
allowed to self-provide or acquire necessary ancillary services in the
most economical means it sees fit to meet performance compliance
standards. East Texas Cooperatives suggests that the Commission require
both transmission owners and the RTO to offer ancillary services at
cost-based rates unless a seller can demonstrate a competitive market
in a particular ancillary service. PPC and Desert STAR also believe
that the role of provider of last resort of ancillary services would
better rest with local control areas or independent generators that can
supply ancillary services. Steel Dynamics requests that the final rule
require generation-owning members of RTOs to maintain Commission
approved cost-based tariff schedules for ancillary services. Georgia
Transmission believes that any RTO members that are capable of
providing ancillary services should be the providers of ``first
resort,'' and the ability to acquire such services from different
providers would enhance competition in these markets.
While not specifically objecting to the RTO being the supplier of
last resort for ancillary services, some parties suggest that the
Commission should allow other mechanisms to work.\523\ California Board
urges the Commission to allow consideration of other means for ensuring
that the need for ancillary services is addressed. It recommends that
the final rule reflect a requirement that the RTO filings must indicate
how default provision of ancillary services will be accomplished
without necessarily requiring the RTO to be the provider of last
resort. Enron/APX/Coral Power advocates a form of performance-based
ratemaking in which the RTO would have an incentive to perform its
ancillary service function as efficiently and economically as possible.
Florida Commission recommends that an RTO only be responsible for
providing non-competitive ancillary services and
[[Page 891]]
should require users to purchase or self-provide the other competitive
services.
---------------------------------------------------------------------------
\523\ See, e.g., CMUA, LPPC, California Board, San Francisco,
Oneok, SMUD, Avista, Sithe, Seattle.
---------------------------------------------------------------------------
Similarly, FTC suggests that the Commission consider arrangements
in which the RTO's primary role is to provide a market mechanism for
transmission customers to acquire ancillary services for themselves. It
argues that this method may reduce costs by allowing customers to
customize their purchases of ancillary services to better fit their
specific needs.\524\ Some commenters suggest that final RTO regulations
expressly recognize the administration of an ancillary service exchange
as an alternative to the provider-of-last-resort obligation that is
imposed on a RTO under the proposed regulations.\525\ For example, ISO-
NE believes that a competitive market for ancillary services is a
superior supply mechanism, and ISO-NE suggests that the text of
proposed Sec. 35.34(j)(4) be amended to read:
\524\ See also Empire District.
\525\ See, e.g., Cinergy, APX, EAL, NY ISO, JEA.
---------------------------------------------------------------------------
An RTO must develop and maintain a market or other contractual
arrangements for the supply of all ancillary services required by
Order No. 888, FERC Stats. & Regs. para. 31,036 (Final Rule on Open
Access and Stranded Costs), and subsequent orders.
Comments were also sought on the circumstances under which an RTO's
obligation as supplier of last resort could be eliminated.\526\ Several
commenters believe that the supplier of last resort obligation can be
eliminated once a viable competitive market develops within the RTO
region.\527\ For example, WPSC suggests that an RTO must continue to
fulfill the role of supplier of last resort for these services or a
power exchange must be available to supply these services. WPSC
believes that it would be difficult to predict the circumstances under
which the market for ancillary services is sufficiently robust that the
RTO's role as supplier of last resort may be eliminated. WPSC believes
that it would be a mistake to eliminate that role in any market where
the generation market concentration levels as measured by the
Herfindahl-Hirschman Index exceed 1,800. TDU Systems states that it is
not aware of a market in any of the ancillary services that is now
sufficiently competitive to warrant elimination of an ancillary service
from this obligation. However, TDU Systems acknowledges that there may
never be a competitive market for certain ancillary services and that
an alternative mechanism must be created.
---------------------------------------------------------------------------
\526\ FERC Stats. and Regs. para. 32,541 at 33,745.
\527\ See, e.g., WPSC, APS, Florida Commission, Duke.
---------------------------------------------------------------------------
The NOPR also asked for comments on whether a different set of
ancillary services requirement for RTOs is needed because RTOs will not
own generating resources. Comments on this issue were mixed.
Sithe and several other commenters 528 generally believe
the Commission's initial set of guidelines on ancillary services is
reasonable, and that a new set of ancillary services requirements for
RTOs is unnecessary. LG&E adds that, as already is the case under the
open access tariff, an RTO should be allowed to choose to add to the
list of ancillary services in recognition of local or regional
conditions. MidAmerican believes that while no additional or revised
ancillary services are required, an RTO must ensure that sufficient
transmission capacity is available to allow delivery of backup supply,
planning reserves and the existing six ancillary services.
---------------------------------------------------------------------------
\52\ See, e.g., PGE, TDU Systems, Cal ISO, Duke, Tri-State.
---------------------------------------------------------------------------
On the other hand, Los Angeles believes that a different set of
ancillary services requirements than those required currently from a
vertically integrated utility should apply to an RTO which does not own
generation resources. They envision an ultimate industry structure of
complete desegregation of generation and transmission assets so that
any incentive (either real or perceived) for the transmission provider
to act in a discriminatory manner is eliminated.
NSP requests that the Commission refer to the draft NERC policy
that discusses the role of an operating authority as an unbundled
procurement agent for community ancillary services. They describe this
document as a good ``guidepost'' for the Commission to follow in the
RTO NOPR, and for the establishment of additional ancillary services
such as system blackstart and frequency responsive reserve.\529\ Desert
STAR and Cal ISO agree that additional blackstart ancillary service may
be required. TDU Systems believes that RTOs should be required to offer
backup service and an additional load following service. It describes
backup service as required to meet contingencies during periods
following those covered by the OATT's reserve services, and load
following service as required to complement the OATT's minute-to-minute
regulation service with a service matching hour-to-hour variations in
load. Industrial Consumers recommends that the Commission remove
Schedule 4 (energy imbalance service) from any tariff administered by
an RTO. They suggest that this service be provided by the real-time
balancing market as proposed in the NOPR.
---------------------------------------------------------------------------
\529\ See also Eric Hirst.
---------------------------------------------------------------------------
Self-Supply Option. Nearly all who commented on the self supply
option generally agree that, where feasible, all market participants
should have the option of self-supplying or acquiring ancillary
services from third parties. \530\ Some commenters strongly endorse the
self-supply model. For example, APS believes that it should be the aim
of the RTO to have each transmission customer self-supply its
generation-related ancillary service requirements to the fullest extend
practical. Los Angeles suggests that the role of the RTO should be
limited to ensuring that the transmission customer has adequately
provided for the necessary ancillary services for each transaction, and
the RTO provide such services only in the event of non-compliance. It
believes that the RTO should develop specific rules and protocols that
would support the self-provision of ancillary services. Some
commenters, including PJM/NEPOOL Customers and LG&E, suggest that it is
important for the development of a competitive market in ancillary
services that RTO customers not be required to purchase them from the
RTO, and that an RTO must not prohibit or interfere with the ability of
all market participants to have the option of acquiring competitive
ancillary services or providing such services through buy/sell
transactions from customer-owned generation.
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\530\ See, e.g., CMUA, Cal ISO, LG&E, PG&E, PJM/NEPOOL
Customers, PPC, APX, Metropolitan, MidAmerican, NSP, Seattle, SMUD,
Desert STAR, TDU Systems, Tri-State.
---------------------------------------------------------------------------
On the other hand, FirstEnergy states that the Commission should be
very cautious that policies that encourage self-supply of ancillary
services do not compromise the very ability of the RTO to ensure
reliable and secure network operation. It maintains that the provision
of ``self-supplying'' ancillary services is untested, the
infrastructure needed is as yet undeveloped, and the process of
providing them could potentially lead to abuses. FirstEnergy identifies
this issue as one of the reasons that NERC is pushing for mandatory
compliance requirements.\531\ It believes that an RTO must have the
ability to evaluate and accept/approve those NERC-certified sources
that reliably contribute to support the grid.
---------------------------------------------------------------------------
\531\ FirstEnergy notes that NERC is developing certification
and verification criteria for ancillary service providers.
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Authority to Determine Amounts and Location of Ancillary Services.
Most commenters generally support the proposal that the RTO have the
[[Page 892]]
authority to determine the quantities and, where appropriate, the
location at which ancillary services must be provided.\532\ In
addition, CMUA suggests that the RTO be responsible for enforcing
compliance with established standards.
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\532\ See, e.g., Industrial Consumers, PJM, Turlock, Cal ISO,
Florida Power Corp., PJM/NEPOOL Customers, LPPC, PGE, SMUD, TDU
Systems, NYPP, Tri-State, Nevada Commission.
---------------------------------------------------------------------------
PJM/NEPOOL Customers requests that RTO decisions regarding the
amounts and locations of ancillary services consider both stakeholder
input and NERC standards. It believes that this requirement would
ensure that the RTO does not impose unnecessarily high ancillary
service obligations that will inhibit the operation of the competitive
market. In addition, PJM/NEPOOL Customers asks that the Commission
ensure that the RTO exercises this authority only to the extent
necessary for reliability purposes, since decisions regarding ancillary
services could impact the competitive electricity supply market.
NYPP requests that the RTO's authority not be exclusive. It
suggests that properly constituted local and regional reliability
councils authorized by FERC should have the authority to establish
criteria necessary to maintain the reliability of the transmission
system including the reliability of discrete locations.
Duke notes that the Commission has previously recognized NERC's
leadership role in developing concepts in the area of ancillary
services.\533\ It encourages the Commission to recognize and adopt
NERC's development of ancillary service definitions and reliability
standards.\534\
---------------------------------------------------------------------------
\533\ Citing FERC Stats. & Regs. para. 31,036 at 31,705 (1996).
\534\ See also Eric Hirst.
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Industrial Consumers and Steel Dynamics request that the Commission
first approve the standards by which the RTO determines the
requirements. They requests that these standards include the
development of ``metrics,'' i.e., standardized units of measurement
such that the performance of each service can be verified. In addition,
Industrial Consumers recommends modifying the requirement to ensure
seamless application between multiple RTOs and for transactions that
only go through an RTO. It suggests adding an additional requirement to
Sec. 35.34(j)(4)(ii):
The Regional Transmission Organization must support the minimum
required amounts of each ancillary service for transactions between
itself and other Regional Transmission Organizations in the
interconnection and through itself.
Control Over Ancillary Services Providers. All commenters that
commented on this subject believe that the RTO should be able to
exercise some operational control, either directly or indirectly, over
any supplier of ancillary services.535 SMUD supports the RTO
establishing well documented and specific operating criteria and the
ability to require compliance with such operating criteria, including
monetary penalties and commission-approved sanctions. JEA believes that
this control should be exerted only where pre-existing contractual
rights are established.536
---------------------------------------------------------------------------
\535\ See, e.g., PJM, Cal ISO, Florida Power Corp., Cinergy, Los
Angeles, PSNM, SMUD, Duke.
\536\ See also Cinergy.
---------------------------------------------------------------------------
Some commenters would broaden the requirement. For example,
FirstEnergy is concerned that limiting the RTO's control to ancillary
services providers rather than all generation located within the RTO
may compromise the RTO's ability to operate the transmission system
reliably. It suggests that the Commission allow a greater flexibility
for the RTO and all generation owners located within the RTO to develop
an agreement for provision of ancillary services through the RTO that
provides for the necessary requirements for voluntary generation
participation in the ancillary services market including operational
control if appropriate, and the necessary requirements for calling on
ancillary services from connected generation necessary for the reliable
operation of the transmission system.
On the other hand, PJM/NEPOOL Customers suggest that the RTO
control be limited to those providers that the RTO will rely on to
fulfill its obligation as supplier of last resort for ancillary
services. It claims that control over additional generators is
unnecessary and may affect the operation of the competitive market.
Metropolitan recommends that the Commission allow RTO indirect
control of existing large hydroelectric plants to protect and
facilitate use of existing systems that have been operational for a
substantial period of time and to preserve the integrity of the FERC
hydro license. It states that allowing indirect control would eliminate
the need for costly installation of software and
infrastructure.537
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\537\ See also NYPP, PSNM.
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Promote Competitive Markets for Ancillary Services.Most commenters
support the proposal in the NOPR that RTOs promote competitive markets
for ancillary services.538 Seattle suggests that the RTO
provide incentives to ensure a robust, transparent market with many
buyers and sellers of ancillary services. PJM/NEPOOL Customers states
that it is important that the RTO not impede the development of
competitive markets for ancillary services and that the RTO actually
facilitate the development of these markets. However, it stresses that
the RTO and incumbent transmission owners should not be permitted to
have market-based rates for ancillary services until a viable
competitive market for such services develops.539
---------------------------------------------------------------------------
\538\ See, e.g., FTC, LPPC, Avista, APX, PJM/NEPOOL Customers,
Seattle.
\539\ See also TDU Systems.
---------------------------------------------------------------------------
Sithe advocates that the final rule grant RTOs the authority to
administer spot markets for ancillary services and establish rules
obligating all participants to meet uniform requirements. PG&E believes
that the RTO should not be the sole purchaser of ancillary services.
Instead, it should facilitate the development of bilateral markets for
as many of the ancillary services as possible, thereby allowing market
participants to self-provide those ancillary services.
Access to Real-Time Balancing Markets. In the NOPR, the Commission
proposed that an RTO must ensure that its transmission customers have
access to a real-time balancing market. We proposed that the RTO must
either develop and operate such markets itself or ensure that this task
is performed by another entity that is not affiliated with any market
participant. The Commission noted that although system-wide balancing
is a critical element of reliable short-term grid operation, this does
not necessarily require that there be a moment-to-moment balance
between the individual loads and resources of bilateral traders and
load-serving entities and the schedules and actual production of
individual generators. We also noted that unequal access to balancing
options for individual customers can lead to unequal access in the
quality of transmission service available to different customers, and
that this could be a significant problem for RTOs that serve some
customers who operate control areas and other customers who do not. The
Commission proposed to give RTOs considerable discretion in how a real-
time balancing market would be operated.
We invited comments on the use of market mechanisms to support
overall system balancing and imbalances of individual transmission
users. In addition, we invited responses to the following questions. Is
it feasible to rely on markets to support a function that is so time-
sensitive? Can such markets be
[[Page 893]]
made to function efficiently if the RTO is not a control area operator?
For the imbalances of individual transmission customers, should a
distinction be made between loads and generators? Should customers have
the option of paying for all imbalances in such a market or only
imbalances within a specified band?
Several commenters hold the view that it is indeed feasible to rely
on markets to support a balancing function that is time-
sensitive,540 and many agree that access to a real-time
balancing market would be of considerable benefit to market
participants.541 NERA claims that technical logic dictates
that an electricity system have a central process to co-ordinate real-
time physical operations. NERA argues that to the extent that this
process is not based on markets, it must be based on less efficient
command-and-control methods. NERA also claims that economic and
commercial logic requires that a commodity market have short-term
trading arrangements to bring market positions into agreement with
physical reality, and argues that to the extent that market trading
does not reflect physical reality, some non-market process must close
the gap between the market and reality. NERA asserts that these two
propositions imply that the best way to maximize the role of the market
and minimize the role of non-market processes is to base real-time
physical operations on a spot market and to allow market participants
to use this market for commercial purposes to the extent they find this
useful.
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\540\ See, e.g., Duke, PJM, Illinois Commission, Cal ISO, NERA.
\541\ See, e.g., Enron/APX/Coral Power, Eric Hirst, NYPP,
Powerex, East Texas Cooperatives, Industrial Consumers, Professor
Hogan.
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Enron/APX/Coral Power states that access to a real-time energy
balancing market is central to assuring comparability in open access,
and Industrial Consumers believes that this proposal is the beginning
of a much needed ``paradigm shift'' in the manner in which ancillary
services are defined and provided in the marketplace. Eric Hirst states
that implementation of a real-time balancing market would permit FERC
to eliminate the Order No. 888 requirement that transmission providers
offer an energy imbalance service to transmission customers. He argues
that elimination of energy imbalance service, with its awkward and
arbitrary deadband and penalty payments, would be a pro-competitive
change. Professor Hogan claims that without an efficient spot market
and the associated transparent spot prices, it will be much more
expensive and difficult to arrange balancing and settlement for the
increasing number of retail access programs in the states. East Texas
Cooperatives agrees that real-time balancing markets are desirable but
believe that simply commanding RTOs to promote the development of
competitive markets for ancillary services provides no incentive for
the RTO and its members to do so.
Also, two commenters argue that access to real-time balancing
markets would eliminate some significant barriers to entry for non-
traditional resources such as renewable and distributed
energy.542 In particular, EPA notes that providing such
access would eliminate arbitrary energy imbalance penalties that are a
major barrier to intermittent resources such as wind and solar energy.
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\542\ See EPA and Project Groups.
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Some commenters believe that the RTO itself should develop and
operate a real-time balancing market.543 PJM/NEPOOL
Customers believe that the development of such a market is an essential
function of the RTO that will facilitate the further development of
retail competitive supply markets. PJM states that a real-time
balancing market can best be provided through a power exchange operated
by an RTO. Commenters are divided as to whether the development of a
real-time balancing market requires that the RTO be a control area
operator. Several believe that such markets are possible whether or not
the RTO operates a control area.544 Indeed, MidAmerican
believes that, to function efficiently, these markets normally must
operate in a region that is larger than a typical control area.
However, others take an opposite view.545 FirstEnergy, for
example, argues that the timing, dispatch and telecommunications
infrastructure needed to operate a real-time balancing market today can
only be done by a control area operator and then only for a combined
load within a control area with ample generation resources under
automatic generation control.
---------------------------------------------------------------------------
\543\ See, e.g., PJM, PJM/NEPOOL Customers, Professor Hogan,
NERA.
\544\ See, e.g., Tri-State, Illinois Commission, MidAmerican,
Duke.
\545\ See, e.g., PJM/NEPOOL Customers, Southern Company,
FirstEnergy.
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Some commenters provide detailed recommendations regarding the
rules that should govern the RTO's operation of real-time balancing
markets.546 Professor Hogan notes that the complex network
interactions in an electric grid require that there be an entity that
can provide certain critical coordinating services, and that the most
obvious example of such services is energy balancing. He states that
the operator should offer an energy balancing redispatch service where
market participants can make offers to buy and sell energy.
---------------------------------------------------------------------------
\546\ See, e.g., Professor Hogan, Allegheny.
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He believes that the best approach would be to run the balancing
market as a ``bid-based, security-constrained economic dispatch'' with
voluntary participation by generators and loads. Professor Hogan
emphasizes that the RTO must not reject voluntary bids, stating that
the natural extension of open access and the principles of choice would
suggest that participation in the coordinated balancing market offered
by the operator should be voluntary. He states that market participants
can evaluate their own economic situation and make their own choice
about participating in the operator's economic dispatch or finding
similar services elsewhere. He believes that any other rule would
require some form of discrimination, and adds that there should be a
strong burden of proof for those who argue that it is necessary to
restrict voluntary bids, or discard consideration of some bids.
Professor Hogan claims that experience in PJM and elsewhere shows that
his suggested approach can work.
However, several commenters take a very different view, claiming
that the development of a real-time balancing market is not a viable
option.547 For example, FirstEnergy is concerned that a
real-time balancing market is not practical to implement. It claims
that transmission customers do not yet have the real-time metering and
associated communication needed to dispatch and match fluctuating loads
to generation. FirstEnergy argues that it would be much better to tie
this service to the NERC effort of certifying ancillary service
providers for control of generation, and activate the service when the
technology and installation can be accommodated. Seattle states that it
performs its own real-time energy balancing and expects to continue to
do so. Seattle opposes adding this function to an RTO because Seattle
believes it will increase the overhead costs of the organization.
Seattle believes that market participants that require this service
should contract with third parties that stand ready to provide it.
Florida Power Corp. states that, given the complexity of implementing
short term transmission service in general, it is difficult to imagine
that a market for
[[Page 894]]
energy imbalance service could be developed. It argues that if the
market is limited to the generators needed for control, the development
of market mechanisms will depend on resolving issues such as the
mitigation of potential market power. Florida Power Corp. suggests that
an RTO could contract with generators to perform this balancing
function using a mechanism that is market-like in that generators would
be selected based on their bids to perform the function over some
designated period of time, albeit not on an hourly basis.
---------------------------------------------------------------------------
\547\ See, e.g., Seattle, FirstEnergy, Florida Power Corp.
---------------------------------------------------------------------------
Several commenters believe that control areas or RTOs should not be
the sole provider of energy imbalance services,548 while
others argue that the role of RTOs should be limited to that of a
supplier of last resort. 549 UtiliCorp states that, in
addition to serving as a supplier of last resort, the RTO must ensure
public access to real-time balancing information. SMUD argues that any
burden on the RTO that falls outside of the core function of ensuring
regional transmission reliability will add cost and complexity to an
already costly and complex endeavor. SMUD recommends that the
Commission should limit its focus on generation to the role that
generation-related service plays in promoting reliable transmission.
Desert STAR and FirstEnergy believe that the Commission should give
deference to RTOs regarding the development of markets for real-time
balancing.
---------------------------------------------------------------------------
\548\ See, e.g., Southern Company, Tri-State.
\549\ See, e.g., UtiliCorp, Avista, APX.
---------------------------------------------------------------------------
FirstEnergy believes that, ultimately, ancillary service provision
must be based on a free-market pricing mechanism, and Southern Company
believes that if a real-time balancing market is desired in a region,
it will develop without a mandate. FirstEnergy asserts that the
detrimental effects of regulated and capped ancillary service markets
have been observed in the California and PJM markets. Also, APX
believes that the Commission should let the market, not the RTO,
provide the trading arrangements in the power industry. APX asserts
that efficiency in the competitive market comes from the de-centralized
trading activity of self-interested buyers and sellers, and that
competition will develop further when market participants self-provide
their ancillary services which they acquire in forward contract
markets. In APX's view, the RTO should not provide a centrally
optimized dispatch because a central dispatch will discourage, if not
eliminate, the commitment of forward contracts in the energy market and
replace the price discovery of forward markets with ex post pricing. To
the extent that the RTO must acquire ancillary services, including
balancing services, APX believes that the RTO should acquire them from
a market created by market participants, and not create its own
markets. NERA, however, states that this argument ignores the fact that
preventing the ISO from operating balancing markets does not eliminate
the network interactions and real-time events that are inherent in any
electricity network. Rather, according to NERA, it merely forces the
ISO to manage these interactions and events by less efficient and more
intrusive non-market means. NERA contends that if the objective really
is to maximize the role of competitive market forces and minimize the
extent to which the monopoly ISO determines the outcome, the ISO should
operate market-clearing mechanisms that reflect network interactions
and real-time events as accurately as possible. Similarly, ISO-NE
claims that it does not understand how operating a market in which (as
in New England, currently) an RTO does not buy and sell the pertinent
commodities can constitute ``taking a position'' in those markets such
that its operation is perceived as biased. ISO-NE believes that because
it does not own market assets or commodities, an ISO-type RTO is
exceptionally well situated to run a fair and non-discriminatory
market. ISO-NE states that the linkages among transmission operation/
dispatch, generation commitment/dispatch, and economic and market
forces strongly support the integration of a physical market with an
RTO's operations. Nevertheless, ISO-NE states that other financial
power markets are welcome and can co-exist in the same region with an
RTO market.
Several commenters offered their views as to whether unequal access
to balancing options leads to unequal access in the quality of
transmission service available to different customers, and whether this
is a significant problem when RTOs serve some customers that operate
control areas and other customers that do not.\550\ A number of
commenters believe that the present system does lead to undue
discrimination.\551\ Enron/APX/Coral Power states that both the NERC
and pro forma tariff rules are inequitable and discriminatory in that
large customers rarely will be significantly out of balance due to the
law of large numbers. Enron/APX/Coral Power states that such customers
are given great flexibility to balance their scheduled deliveries and
load, while smaller customers are much more likely to exceed the 1.5
percent deviation band, making them immediately subject to penalties.
Enron/APX/Coral Power believes that by offering real-time balancing to
all transmission customers, the NOPR promises to redress this inequity.
TDU Systems recommends that, pending the development of competitive
balancing markets, the existing inequity between control area operators
and other users be partially redressed by enlarging the deadband for
imbalances to be repaid or received in kind to no less than five
percent of scheduled amounts. It also recommends that the penal
character of these charges should be reduced to a ten percent premium,
except in cases of abuse.
---------------------------------------------------------------------------
\550\ See, e.g., Enron/APX/Coral Power, LG&E, PJM/NEPOOL
Customers, FirstEnergy, TDU Systems, Florida Power Corp.
\551\ See, e.g., Enron/APX/Coral Power, PJM/NEPOOL Customers,
TDU Systems.
---------------------------------------------------------------------------
PJM/NEPOOL Customers argue that, to the extent current control area
operators wish to maintain access to inadvertent energy accounts to pay
back imbalances and avoid penalties, other transmission customers must
have the same opportunity. In the alternative, it recommends that all
users be required to cash-out through the RTO balancing process.
Utility Engineers recommends implementing a pricing plan for
inadvertent interchange by participants of the RTO, where the price for
inadvertent interchange is geographically differentiated to reflect
losses and constrained transmission paths. They claim that such a
pricing plan would need a continuous auction, which could be achieved
through establishing a pricing formula.
With regard to providing access to inadvertent energy accounts,
other commenters argue that there are valid reasons for distinguishing
between customers that are control areas and those that are not.
FirstEnergy argues that no other entity, other than control areas, can
or should have that access to inadvertent accounts. It claims that, if
market participants are provided with the authority to ``go
inadvertent'' as control area operators currently have, the strain on
the grid would drastically degrade system reliability, requiring much
higher reserve capacity requirements. FirstEnergy believes that
marketers would ``borrow'' from the grid during high price time periods
and make whole on their borrowing during low price time periods, thus
distorting the true price signal. Florida Power Corp. notes that in
addition to balancing generation against load, control area balancing
also includes a requirement for contributing to the maintenance of
[[Page 895]]
system frequency. In contrast, it notes that the non-control area
transmission customer's balancing requirement is limited to the
directly measured load it serves. Florida Power Corp. also claims that,
if a system of payments was substituted for the inadvertent payback
system presently used, control area operators would simply be
circulating large sums of dollars between themselves to accomplish the
same result at a higher administrative cost. LG&E suggests that the
Commission treat such technical issues separate from the RTO NOPR and
work in conjunction with NERC's parallel efforts in this area. Also,
Florida Commission believes that inadvertent energy accounting between
control areas should continue to be allowed within the operating
standards of NERC.
With regard to any requirement that loads and resources must be in
balance from moment-to-moment, Professor Hogan and Eric Hirst believe
there is no need for individual loads and generation to balance their
schedules separately, and PJM/NEPOOL Customers states that balancing
should be required only to ensure that generators deliver the amount
scheduled and committed. Professor Hogan argues that individual
balancing requirements both complicate the task for the RTO and provide
a device to reinforce market power. Eric Hirst states that the RTO's
costs of providing or absorbing imbalance energy should be charged
equitably to those that under-generate and over-consume, with
compensation to those that over-generate and under-consume. He states
that this will result in charges and payments netting roughly to zero
in each hour. However, Enron/APX/Coral Power believes that any RTO
proposal should include development of an ex post energy balancing
market in which buyers and sellers are given a finite amount of time
after the market has closed to find others with offsetting positions.
Regarding the imbalances of individual transmission customers,
commenters disagree as to whether a distinction should be made between
loads and generators. MidAmerican and Florida Power Corp. believe that
loads and generators should be treated differently. MidAmerican
contends that it is much easier to control generators than it is to
control load, and in the future managing imbalances will become more
complex in that control from the load-side will involve the response of
potentially thousands of entities that may or may not respond as
quickly as central generation. MidAmerican states that a distinction
exists between loads and generators both in magnitude and response
time. Florida Power Corp. claims that load and generators are not
always similarly situated. It states that the nature of energy
imbalance service depends on whether a generator and the load that it
serves are in the same control area or are in different control areas.
Eric Hirst, TDU Systems, and Duke believe that, in general, the market
rules and principles should be the same or comparable for generators
and loads, although TDU Systems believes that loads may be less likely
than generators to abuse the system by leaning on it. Eric Hirst states
that the use of imbalance markets would eliminate the asymmetry between
generation and load in FERC's definition of energy imbalance.
Finally, the NOPR also asked whether customers should be able to
pay for all imbalances in a market or only imbalances within a
specified band. Duke believes that it is appropriate to let the market
participants determine how imbalances will be determined and paid. PJM/
NEPOOL Customers believes that the RTO should provide transmission
users with as many service offerings as possible, including the ability
to opt for different balancing pricing proposals. Florida Power Corp.,
however, believes that there should only be one method of settling the
imbalance market. It claims that complexity and opportunities for
gaming increase with options for settlement.
MidAmerican believes that transmission customers should pay for all
energy imbalances caused by the mismatch of scheduled energy and actual
load. It recommends that imbalance charges be based on market prices at
the time the imbalance occurred, and should include a penalty, in
appropriate circumstances, to deter future imbalances. MidAmerican
contends that if transmission customers are allowed to avoid payment
within a specified bandwidth, gaming of the transmission system will
occur.
PJM/NEPOOL Customers and Professor Hogan, however, argue that the
RTO should not be allowed to impose balancing penalties on transmission
users. Eric Hirst states that RTOs should maximize the use of price
signals rather than penalties to encourage appropriate behavior on the
part of generators and loads, and Professor Hogan states that such
prices should reflect the marginal cost for power. Eric Hirst believes
that penalties should be imposed only to counter the perverse
incentives that are created when metering or billing procedures require
prices to be calculated over time intervals that do not correspond to
those used to measure generation and consumption quantities. Using the
example of the California ISO, he states that mismatches between ten
minute prices and hourly quantities provide unintended incentives to
generators to ignore ISO dispatch instructions or to ignore their
schedules. He claims that aligning the time periods for price
determination and billing would eliminate these perverse incentives. He
adds that, where penalties are needed, they should be closely tied to
the costs incurred by the ISO.
TDU Systems argues that if markets for balancing services are fully
competitive, transmission users should be able to use them to deal with
any amount of imbalance. TDU Systems recommends that until such markets
are fully competitive, it may be necessary to restrict such purchases
to a deadband to prevent abuse. It believes that any such deadband
should be less restrictive than that of the pro forma tariff. In that
regard, it recommends that the minimum within-band allowance should be
no less than the greater of two megawatts or five percent for loads or
capacities up to 200 MW, with declining percentage tolerances as loads
and capacities increase in size.
Commission Conclusion. We conclude that an RTO must serve as the
provider of last resort of all ancillary services required by Order No.
888 and subsequent orders.
Since some commenters interpreted the ``supplier'' of last resort
obligation as proposed in the NOPR to require that the RTO be the
direct supplier of ancillary services,552 we have made a
minor change to the requirement by substituting the term ``provider''
for ``supplier.'' We clarify that this obligation requires that the RTO
have adequate arrangements in place for the provision of ancillary
services.
---------------------------------------------------------------------------
\552\ See, e.g., LPPC, Los Angeles, Georgia Transmission, JEA,
PPC. A direct supplier of ancillary services either owns or operates
generation.
---------------------------------------------------------------------------
The ancillary services adopted in Order No. 888 were defined using
the control area and its operator as the basis because a majority of
transmission service was provided by control area operators and they
controlled the generation facilities that supplied ancillary services.
We note that since we are not requiring the RTO to be a single control
area operator, we can not require an RTO that owns no generation to be
the direct supplier of ancillary services. Therefore we will give the
RTO and its participants flexibility in developing adequate
arrangements for the provision of ancillary services to all
transmission
[[Page 896]]
customers that request service over the facilities under RTO control.
The RTO could fulfill its ancillary services obligations through a
variety of mechanisms, including contractual arrangements, indirect or
direct control of specified generation facilities, or market
mechanisms. However, regardless of the method of provision, the
ancillary services must be included in the RTO administered tariff so
that transmission customers will have access to one-stop shopping for
transmission service.
We conclude that all market participants must continue to have the
option of self-supplying or acquiring ancillary services from third
parties subject to any general restrictions imposed by the Commission's
ancillary services regulations in Order No. 888 and subsequent orders.
In such instances, the RTO must determine if the transmission customer
has adequately obtained these services. The Commission believes that
allowing self-supply provides a possible competitive check on the RTO
to ensure that to the extent it does provide the services, it acquires
them at lowest cost.
In the NOPR we asked whether additional or revised ancillary
services are needed. While a completely unbundled and competitive
environment may require a modification to the ancillary services
required by Order No. 888, comments suggest that an immediate change is
unnecessary. We will not, at this time, make changes to the ancillary
services described in Order No. 888. However, we will allow an RTO to
propose other services in recognition of local or regional conditions.
We conclude that the RTO must have the authority to decide the
minimum required amounts of each ancillary service and, if necessary,
the locations at which these services must be provided. All generators
or other facilities that provide ancillary services must be subject to
direct or indirect operational control by the RTO. The RTO must promote
the development of competitive markets for ancillary services whenever
feasible. To ensure the reliable operation of the system, an RTO must
have authority to determine quantities and locations for ancillary
services. The RTO should consider stakeholder input as well as
established industry standards in determining these requirements. The
Commission anticipates that some of the generation-based ancillary
services could be acquired in short-term markets. This has been the
approach taken by most of the ISOs that we have approved, and we see no
reason that this would be different for transcos or other types of RTO
entities. Apart from establishing the general requirement to use
competitive markets, the Commission will allow the RTO considerable
flexibility in determining many of the detailed market design
questions, with case-by-case review by us.
As we proposed in the NOPR, we conclude that an RTO must ensure
that its transmission customers have access to a real-time balancing
market that is developed and operated by either the RTO itself or
another entity that is not affiliated with any market participant. We
have determined that real-time balancing markets are necessary to
ensure non-discriminatory access to the grid and to support emerging
competitive energy markets. Furthermore, we believe that such markets
will become extremely important as states move to broad-based retail
access, and as generation markets move toward non-traditional
resources, such as wind and solar energy, that may operate only
intermittently.
Some commenters believe that implementation of real-time balancing
markets presents technical problems that may prevent RTOs in some areas
of the country from making such markets available to market
participants. For example, some argue that it is difficult if not
impossible for an RTO that is not a control area operator to operate an
efficient real-time balancing market. These commenters suggest that to
the extent such markets are feasible and desirable in a particular
region, the RTO, its stakeholders and market participants should be
given the flexibility to develop markets in accordance with their needs
and capabilities.
We are not convinced that, at this time, technical considerations
preclude the development of a real-time balancing market for any
potential RTO. As discussed elsewhere in this Final Rule, we are
requiring each RTO to be the security coordinator for its region and to
have, at a minimum, the authority to exercise a combination of direct
and functional control over facilities within its region. Thus, even if
an RTO is not a control area operator, it should have sufficient
operational authority to ensure that a real-time balancing market can
be implemented. With regard to the issue of flexibility, we believe
that real-time balancing markets are essential for development of
competitive power markets. Therefore, although we will give RTOs
considerable discretion in how they operate real-time balancing
markets, we will not allow implementation of such markets to be
discretionary.
Our conclusions regarding provision of real-time balancing markets
are similar to our conclusions regarding markets for congestion
management; that is, we will not prevent an entity other than an RTO
that is unaffiliated with market participants, from seeking to offer
transmission customers a real-time balancing market. However, because
this function is so time-sensitive and requires such close coordination
with the actual dispatch, experience may ultimately show that it cannot
be performed to a high degree of efficiency unless it is made a part of
the RTO's central or hierarchical dispatch activities. Also, we do not
agree that an RTO's operation of a real-time balancing market will
interfere unduly with the efforts of others to establish markets in
forward contracts for energy.
We asked in the NOPR whether customers should have the option of
paying for all imbalances in a real-time balancing market or only
imbalances within a specified band. Based on the comments received, we
decline to give a generic solution for all RTOs in this rule. An RTO
may propose one approach or the other but should explain how it
proposes to overcome any disadvantages of the approach selected.
In the NOPR, we noted that unequal access to balancing options can
lead to unequal access in the quality of transmission service, and that
this could be a significant problem for RTOs that serve some customers
who operate control areas and other customers who do not. We conclude
that control area operators should face the same costs and price
signals as other transmission customers and, therefore, also should be
required to clear system imbalances through a real-time balancing
market. We believe that providing options for clearing imbalances that
differ among customers would be unduly discriminatory.
Finally, we asked in the NOPR whether, for the imbalances of
individual transmission customers, a distinction should be made between
loads and generators. We conclude that, for the purpose of determining
cost responsibility for imbalances, no distinction needs to be made.
The system-wide balance between load and generation is affected
comparably by changes in load and changes in generation. Therefore, the
cost of an imbalance is unaffected whether the imbalance is determined
ultimately to be the responsibility of load or of generation. However,
commenters point out certain differences between loads and generators
(such as in the time needed to respond to an operator's
[[Page 897]]
instructions) that are important from the standpoint of system
operation. These differences can be relevant to the determination of
the appropriate penalties to assess to loads and generators that fail
to submit accurate schedules. Thus, for purposes of assessing penalties
for inaccurate schedules, we conclude that a penalty mechanism that
treats loads and generators differently may be appropriate.
5. OASIS and Total Transmission Capability (TTC) and Available
Transmission Capability (ATC)
In the NOPR, the Commission proposed that an RTO must be the single
OASIS site administrator for all transmission facilities under its
control and independently calculate TTC and ATC. The Commission stated
that the most controversial aspect of OASIS operation is the
calculation and posting of ATC \553\ and noted that there is widespread
dissatisfaction with the reliability of posted ATC numbers. To
alleviate this problem, the Commission proposed that the RTO become the
administrator of a single OASIS site for all transmission facilities
over which it is the transmission provider.\554\ The NOPR outlined
three levels at which an RTO could be involved in ATC calculations. At
Level 1, the RTO would post ATC values received from transmission
owners. At Level 2, the RTO would receive raw data from transmission
owners and itself calculate ATC values. At Level 3, the RTO would
itself calculate ATC values based on data developed partially or
totally by the RTO.
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\553\ FERC Stats. and Regs. para. 32,541 at 33,747.
\554\ Id. at 33,748.
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In the NOPR, the Commission envisioned that RTOs would operate at
Level 3 to ensure that ATC values are based on accurate information and
to minimize the opportunities for manipulation.\555\ The Commission
also proposed that: (1) An RTO must formulate a validation system to
check any ATC data supplied by others; (2) in the event of a dispute
over ATC values, the RTO's data should be used pending the outcome of
the dispute resolution process; and (3) the RTO must formulate the
operating standards (subject to regional and national reliability
requirements) underlying ATC calculations.\556\
---------------------------------------------------------------------------
\555\ See id.
\556\ Id.
---------------------------------------------------------------------------
Comments. Most commenters who address the subject agree with the
Commission's observations regarding dissatisfaction with ATC/TTC data.
Moreover, most commenters on the subject endorse the proposal that an
RTO must be the single OASIS site administrator for all transmission
facilities under its control.\557\ Some commenters, however, are
opposed to mandating the RTO as the OASIS site administrator. For
example, Central Maine argues that it should not be precluded from
operating its own site because as a ``wires-only company'' it has an
incentive to operate an efficient site in order to maximize use of
transmission capacity. EEI asserts that OASIS operation can occur
independently of formation of an RTO and that the tasks and problems of
OASIS operation will not become naturally easier to solve with the
creation of an RTO.
---------------------------------------------------------------------------
\557\ See, e.g., NASUCA, WPSC, EAL, NERC, Industrial Consumers,
Entergy, Mass Companies, JEA, LG&E, NY ISO, NJBUS, Sithe, TAPS, How
Group, Southern Company, PG&E, PJM, UtiliCorp, Williams, Cinergy,
Oneok, East Texas Cooperatives, Cal DWR, Tri-State, Seattle, New
Smyrna Beach, RUS, Cinergy, Nevada Commission, and Enron/APX/Coral
Power.
---------------------------------------------------------------------------
Most commenters also support the Commission's proposal to have the
RTO independently calculate ATC and TTC.\558\ In addition, a number of
commenters emphasize that independent and disinterested RTOs could be
trusted and empowered to maintain reliable ATC data and calculate
accurate values.\559\ Moreover, several commenters are concerned with
consistency across RTOs and contend that RTOs must also coordinate ATC
values with adjacent regions and with the NERC regional reliability
councils.\560\
---------------------------------------------------------------------------
\558\ See, e.g., Sithe, RUS, TAPS, PG&E, SMUD, Cal DWR, New
Smyrna Beach, East Texas Cooperatives, WPSC, EAL, NERC, NASUCA,
Seattle, Georgia Transmission, First Rochdale, Tri-State, Industrial
Consumers, Enron/APX/Coral Power, Cinergy, Oneok, PJM, Williams,
Empire District, PJM/NEPOOL Industrial Customers, Entergy, Mass
Companies, Nevada Commission, NJBUS, and LG&E.
\559\ E.g., FMPA, East Texas Cooperatives, NJBUS, Empire
District, Entergy, Oneok, First Rochdale, Seattle, EAL, Sithe, WPSC,
Sithe, PG&E, SMUD, New Smyrna Beach, and PJM/NEPOOL Customers.
\560\ See, e.g., Industrial Consumers, Seattle and WPSC.
---------------------------------------------------------------------------
Many commenters concur with the Commission's conclusions about the
different levels of RTO involvement in ATC calculations. These
commenters believe that Level 1 is insufficient for reliable and
trustworthy data and that an RTO should independently calculate ATC
values. Several commenters, however, disagree about the appropriate
timing for Level 3 compliance. Some commenters, such as Cinergy, argue
that upon commencement of operation, an RTO should be required to
perform all studies and analysis needed for accurate ATC values
consistent with Level 3. APX supports each RTO reaching Level 3 as
quickly as possible. Enron/APX/Coral Power asserts that upon
commencement of operation, an RTO should operate at Level 2 and, as it
gains operational experience, migrate to Level 3. SMUD supports RTO
operation at Level 3 but is concerned about the significant costs
associated with developing data.
JEA is opposed to any RTO structure that gives an RTO complete
authority over ATC calculations for transmission that JEA will continue
to own. JEA asserts that transmission owners are in the best position
to assess the capabilities of their own transmission system. Therefore,
absent formation of a transco, JEA does not support relying on an RTO
for ATC and TTC calculations because JEA argues that ownership and
control of the assets would be split between two or more entities whose
interests are not always the same.
Both Cal ISO and NY ISO argue that the final rule should provide
flexibility in the OASIS requirements to accommodate network systems
like the Cal ISO and the NY ISO in which transmission service is not
explicitly reserved. In addition, numerous commenters argue that the
Commission should expand the minimum requirements to have every RTO
employ a single set of OASIS practices and terminology.\561\ They note
that consistency in OASIS procedures will allow seamless trades across
RTOs.
---------------------------------------------------------------------------
\561\ See, e.g., Williams, EPSA, Cinergy, Empire District and
PJM/NEPOOL Customers.
---------------------------------------------------------------------------
How Group also focuses its comments on the standardization of
transmission transactions. It notes that without some level of
standardization only a limited number of market participants who learn
all of the differences between RTOs can perform transactions that span
multiple RTOs. How Group proposes that each RTO establish a
coordinating committee with neighboring RTOs and transmission customers
in order to: (1) Coordinate the naming of interconnected facilities,
sources, sinks, paths, points of receipt and/or delivery between the
RTO and its neighbors; (2) coordinate the sharing of necessary data for
the calculation of transmission capability on interconnected paths; and
(3) foster coordination with neighbors in adopting standardized
business practices. It also suggests that continued industry-wide
coordination is necessary to formulate common definitions for types of
transmission and ancillary services, curtailment priorities, and timing
[[Page 898]]
requirements for arrangement of transmission services.
Only one commenter expressed concern about the proposal to use the
RTO's ATC values in the event of a dispute. Southern Company contends
that the existing transmission owner's data are preferable to the RTO's
data. Southern Company argues that existing transmission owners have
experience in operating the regional transmission facilities and,
therefore, are best qualified to determine ATC values.
Some commenters raise other OASIS-related issues that were not
addressed in the NOPR. For example, commenters argue that: (1) All
reservations and scheduling, including that for network service, should
occur on the OASIS; (2) sanctions should be levied against transmission
providers that skew their ATC values; and (3) the power flow
methodology rather than the contract path model should be used for
scheduling.\562\ A few commenters address issues relating to Capacity
Benefit Margin (CBM). NASUCA argues that administration of CBM should
be a required function of RTOs and that a uniform methodology for
calculating CBM is needed. Similarly, Idaho Commission asserts that
requiring the posting of CBM on OASIS with a narrative explanation of
its derivation would be beneficial. Empire District states that the
Commission should provide better guidance about how to calculate CBM.
---------------------------------------------------------------------------
\562\ See, e.g., Ontario Power, Williams, NERC and EPSA.
---------------------------------------------------------------------------
Commission Conclusion. After considering the comments, we continue
to believe that an RTO must be the single OASIS site administrator for
all transmission facilities under its control. As numerous commenters
note, independent RTOs can be trusted to maintain an OASIS site with
reliable and current data that is easy to use. In addition, a single
OASIS site for each region instead of multiple sites will enable
transactions to be carried out more efficiently.
However, in response to those who argue for flexibility in OASIS
requirements, we clarify that this requirement does not mean that each
RTO must itself operate the OASIS for its region. Our concern is that
there be no more than one OASIS site for the facilities under the RTO's
control, and that the RTO ensure that the OASIS site operator have the
same attributes of independence we require for an RTO. Thus, we will
allow an RTO the flexibility to contract out OASIS responsibilities to
another independent entity, if justified. More specifically, we do not
intend to keep an RTO from participating in a ``super-OASIS'' jointly
with other RTOs.
We reaffirm that an RTO should operate at what the NOPR
characterizes as Level 3 for ATC/TTC calculations, which requires the
RTO itself to calculate ATC values based on data developed partially or
totally by the RTO. Most commenters believe that Levels 1 and 2, where
the RTO would accept the transmission owners' ATC calculations or data,
are insufficient for reliable and trustworthy ATC values. Level 3
ensures that ATC values are based on accurate information and
consistent assumptions. When data are supplied by others, the RTO must
create a system for tests and checks that ensure customers of
coordinated and unbiased data. We also agree with commenters who
recommend that RTOs coordinate ATC values with adjacent regions.
We recognize that the NOPR was silent on the appropriate timing for
Level 3 compliance. Commenters suggested that: (1) An RTO should reach
Level 3 compliance upon commencement of operation; (2) an RTO should
reach Level 3 as quickly as possible; or (3) an RTO should operate at
either Level 1 or 2 upon commencement of operation and as it gains
operational experience, migrate to Level 3. We conclude that an RTO
OASIS site, including ATC calculations, must be fully operational at
Level 3 upon commencement of service. All parties to a transmission
transaction need precise ATC values to make scheduling decisions.
We affirm that in the event of a dispute over ATC values, the RTO's
values should be used pending the outcome of a dispute resolution
process. Only one commenter, Southern Company, disagreed with this
proposal and we are not persuaded by its arguments. Each RTO must
develop procedures to validate its ATC values.
How Group and other commenters address issues relating to the
standardization of transmission transactions. Standardization of
transactions involves two separate concerns: (1) Many transactions will
cross RTO boundaries; and (2) numerous customers will do business with
multiple RTOs. Without standardized communications protocols and
business practices, the costs of doing business will be increased as
market participants will be required to install additional software and
add personnel to transact with different RTOs and regions. Therefore,
to promote interregional trade, standardized methods of moving power
into, out of, and across RTO territories will be needed.
We believe that standards for communications between customers and
RTOs must be developed to permit customers to acquire expeditiously
common services among RTOs. For example, we envision the creation of
standardized communications protocols to schedule power movements and
to acquire auction rights. These protocols would not standardize what
the rights are, or the nature of the auctions. Instead, the focus of
the communications protocols would be on how customers communicate
their intentions to an RTO and how customers receive an RTO's
responses.
We agree with How Group and others that certain business and
communication standards \563\ are necessary, and we believe that these
standards will facilitate the development of efficient markets. We
believe, however, that these issues need further examination based on a
complete record.
---------------------------------------------------------------------------
\563\ We believe that the communications standards and protocols
would, like the current OASIS, make use of: (1) The Internet for
communications; (2) interactive displays using World Wide Web
browsers; (3) file uploads and downloads for computer-to-computer
communication; and (4) templates defining the file uploads and
downloads.
---------------------------------------------------------------------------
A few other commenters discussed issues that were not addressed in
the NOPR. For example, commenters argue that: (1) All transmission
transactions (reservations and scheduling) should occur on the OASIS;
(2) sanctions should be levied against transmission providers that skew
their ATC values; and (3) the power flow methodology for scheduling,
rather than the contract path model, should be utilized. In addition,
NASUCA, Empire District and the Idaho Commission raise issues relating
to CBM. These issues are too detailed for this proceeding and we will
not address them at this time. Commenters will have the opportunity to
bring up these issues in response to specific RTO filings, as well as
during OASIS Phase II proceedings and in the CBM docket (Docket No.
EL99-46-000).
6. Market Monitoring (Function 6)
In the NOPR, the Commission proposed that RTOs perform a market
monitoring function. Specifically, RTOs would be required to: (1)
Monitor markets for transmission service and the behavior of
transmission owners and propose appropriate action; (2) monitor
ancillary services and bulk power markets that the RTO operates; (3)
periodically assess how behavior in markets operated by others affects
RTO operations and how RTO operations
[[Page 899]]
affect those markets; and (4) provide reports on market power abuses
and market design flaws to the Commission and affected regulatory
authorities, including specific recommendations. In addition, the
Commission asked a number of questions regarding the role of RTOs in
market monitoring, the tools RTOs should use, and similar issues.
Comments. Commenters address a number of issues regarding the
market monitoring function. The issues can be grouped into three
general areas: (1) The need for and scope of a market monitoring
function; (2) who should perform the market monitoring function and how
it should be performed; and (3) what are the specific components or
procedures of a market monitoring plan.
Need For and Scope of Market Monitoring. As a general proposition,
a variety of commenters favor having RTOs serve as market
monitors.\564\ Commenters, such as Blue Ridge, argue that RTOs should
conduct market monitoring because they will be in the best position to
deal with the growing volume of multiparty transactions and discern any
manipulation or preferential treatment. Several commenters, such as the
Florida Commission, note that the appropriate role for RTOs in market
monitoring and the various aspects of the function will depend upon the
nature of the RTO that is ultimately established. TEP claims that RTO
market monitoring needs to be flexible given the costs involved in such
a function. PP&L Companies believes that RTO market monitoring should
focus on properly structuring business rules to foster efficient
transactions and gathering statistical information to make available to
the Commission or other enforcement agencies. EEI and Allegheny
recommend that RTO market monitoring identify market design flaws and
propose solutions that lead to greater efficiency, competitiveness and
reliability.
---------------------------------------------------------------------------
\564\ See, e.g., New York Commission, South Carolina Authority,
Mass Companies, LG&E, ISO-NE, TAPS, SMUD, NECPUC, WPSC, Project
Groups and Tri-State.
---------------------------------------------------------------------------
A number of commenters support having the RTO should serve as the
``first line of defense'' for detecting design flaws and market power
abuses.\565\ Cal ISO suggests that the RTO serve as a first line of
defense in conjunction with state commissions and local regulatory
authorities in the region, particularly in the operation of hourly and
real-time markets where potential buyers may not have the ability to
decline electric service, and where transmission and ancillary services
markets tend to have high concentrations. PJM believes that market
monitoring by RTOs provides a continual check on market activities and
accordingly, RTOs should have clear authority to investigate potential
market power abuses or flaws and to compel market participants to
produce relevant information. SMUD contends that although RTO
monitoring should be the first line of defense, an independent RTO
monitoring unit must not be a substitute for review by the Commission
and other regulatory agencies.
---------------------------------------------------------------------------
\565\ See, e.g., Metropolitan, DOE, CMUA, NASUCA and Project
Groups.
---------------------------------------------------------------------------
In contrast, some commenters, such as Cinergy, argue that, if
transmission markets realize the efficiencies envisioned in the NOPR,
the commodity market should be able to regulate itself, with the
Commission and the courts serving as backstops. SNWA cautions that RTOs
may be too focused on safe and reliable operations to be a first line
of defense. Some commenters, such as Metropolitan and Southern Company,
claim that there is no benefit in having RTO monitoring replicate the
costly regulatory responsibility that already exists in state and
Federal agencies.
Several commenters propose an expansive RTO market monitoring role.
NECPUC proposes that monitoring include mitigation of both market flaws
and market power. East Texas Cooperatives and SMUD believe that RTO
market monitoring should include remedying market abuse. Project Groups
believes that an RTO should monitor energy and ancillary services
markets and their interplay, and develop indices and criteria to
evaluate activities and behaviors that may reflect market power abuse.
Advisory Committee ISO-NE suggests that the RTO monitor transmission
and ancillary services markets to identify design flaws and market
power, and to administer or propose remedial actions. Dynergy claims
that monitoring should include oversight of transmission owners'
behavior. EPSA proposes that the RTO also document any significant
market impacts attributable to application of reliability rules.
Some commenters support limits on market monitoring by the RTO.
Commenters, such as Southern Company and Entergy, argue that RTO
monitoring should not reach to any market the RTO does not operate, nor
should it encompass market power abuse and the effect of existing
structural conditions on the competitiveness of electricity markets.
Entergy adds that the RTO will not be in a good position to monitor
markets it does not operate. Several commenters claim that the purpose
of monitoring should be to look for market flaws, not act as policeman
looking for bad behavior.\566\ Desert STAR recommends that any proposed
remedy be restricted to market flaws within the RTO's area of
operation. Enron/APX/Coral Power argues that evaluation of the
structure of power markets and policing market power lies outside of an
RTO's core competencies as the operator of the transmission system.
Tri-State opposes RTO monitoring of power markets because it would add
to the complexity and cost of RTOs and impermissibly involve the RTO in
issues about generation market power. NY ISO opposes monitoring to the
extent that it encompasses the RTO playing an investigative and
enforcement role. Nonetheless, in its view, the RTO could mitigate
evident market power problems on a prospective basis by applying pre-
approved remedies.
---------------------------------------------------------------------------
\566\ See, e.g., Desert STAR, CRC and Tri-State.
---------------------------------------------------------------------------
Sithe recommends that RTOs not have the authority to compel the
provision of commercially sensitive data and should instead rely on
nonproprietary information to monitor markets. PG&E contends that
commercially sensitive information should not be released to anyone
except in accordance with Commission-approved rules. PP&L raises
concerns regarding the ability of the RTO market monitoring
organization to guarantee confidentiality of commercially sensitive
information supplied to it. Seattle argues that any claims of
commercial sensitivity must be tempered by the need to create an
efficient, self-policing, transparent market for nondiscriminatory
transmission services.
Various commenters would limit the RTO market monitoring function
to information gathering.\567\ They argue that the NOPR proposal is
overly broad, too extensive and open-ended, and a potentially
burdensome requirement. Sithe argues that the application of mitigation
measures by the RTO could have real commercial impacts on market
participants that often cannot easily be measured or repaid after the
fact; therefore, market participants should have an opportunity to
review and comment on monitoring procedures prior to their
implementation. Seattle claims that the Commission should take a
minimalist approach by facilitating market monitoring through greater
public information disclosure. PG&E believes that the RTO should not
regulate the functioning of the energy market. Duke supports RTO
identification and description of alleged market abuses to appropriate
authorities
[[Page 900]]
through the regulatory framework that exists today.
---------------------------------------------------------------------------
\567\ See, e.g., CP&L, TDU Systems, PP&L and PG&E.
---------------------------------------------------------------------------
Other commenters question the need for or otherwise oppose an RTO
market monitoring function, in general, as a form of back door
regulation.\568\ They contend that RTO monitoring will be unduly
burdensome, overtaxing and costly to the ratepayers. Los Angeles and
Salomon Smith Barney argue that RTO monitoring may interfere with the
proper relationship between the RTO and its customers, which they claim
should be focused solely on providing nondiscriminatory open access
transmission services. UtiliCorp argues that the assignment of market
monitoring functions to a commercial entity such as a transco (other
than those functions concerned strictly with transmission pricing) may
raise antitrust concerns both for the transco and its customers.
---------------------------------------------------------------------------
\568\ See, e.g., Industrial Consumers, Williams, Southern
Company, PSE&G, Arizona Commission, Georgia Transmission and East
Kentucky.
---------------------------------------------------------------------------
Commenters differ on whether market monitoring should continue
indefinitely. East Texas Cooperatives believes that continuous RTO
market monitoring is necessary because, in its view, antitrust laws and
complaints to the Commission provide only a slow, after-the-fact
remedy. Entergy recommends that any RTO self-monitoring be allowed to
terminate after a fixed period, subject to Commission approval.
Industrial Consumers suggests that market monitoring be limited to the
period when the risk of discriminatory conduct is greatest. Los Angeles
claims that, once the Commission determines that generation markets are
workably competitive, market forces should be allowed to discipline the
markets. If an RTO market monitoring function is required, PSE&G
suggests a five-year sunset provision.
Who Should Perform Market Monitoring and How Should it Be
Performed. Many commenters address the issue of whether the RTO should
perform market monitoring depending on the form of the RTO (i.e.,
whether the RTO is a for-profit or a not-for-profit organization). Most
commenters raise concerns about and generally oppose a for-profit RTO
monitoring markets.\569\ The commenters generally argue that, due to
its economic and business interests, a for-profit RTO cannot
objectively monitor itself. CP&L submits that a for-profit RTO may be a
competitor of other market participants in the provision of congestion
relief and ancillary services, which would make unbiased monitoring of
those markets difficult. TDU Systems would limit a for-profit RTO's
role to data collection. Other commenters recommend that for-profit
RTOs employ a fully independent organization to monitor market
conditions.\570\ A few commenters, however, support for-profit RTOs
serving as market monitors.\571\ Entergy claims that market monitoring
conducted by a transco could be as effective as for any other type of
RTO as long as procedures are in place that ensure its independence.
---------------------------------------------------------------------------
\569\ See, e.g., Dynegy, South Carolina Authority, Industrial
Consumers and East Texas Cooperatives.
\570\ See, e.g., PJM/NEPOOL Customers, Cal ISO, Tri-State and
Metropolitan.
\571\ See, e.g., Entergy and Duke.
---------------------------------------------------------------------------
Commenters also address whether an RTO that is an ISO needs to
insulate its market monitoring function from other RTO functions to
ensure independence and objectivity. A number of commenters generally
believe it is appropriate for ISOs to internally monitor market
activities either through staff devoted to the function or through a
committee of ISO members assigned to the function.\572\ They argue that
an ISO, which would be free of commercial interests, can be trusted by
market participants, and therefore should not have to undertake costly
establishment of autonomous monitoring units. Mid-Atlantic Commissions
note that PJM ISO's monitoring unit is a neutral body that has access
to and maintains confidentiality of market sensitive data in accordance
with sharing arrangements with each of the states in the region.
California Board contends that, if the internal unit is independent and
has the ability to report and/or consult with state and Federal
authorities without needing additional approval, those regulators are
likely to respect the opinions and recommendations of the market
monitoring unit. CalPX suggests that RTOs and separate power exchanges
coordinate their market monitoring functions and jointly conduct
research to lower costs. EPSA suggests that the information and market
data, if collected by an independent and unbiased RTO, could be relied
upon by market participants in formulating business strategies, and by
regulators for purposes of reviewing and approving modifications to
regulated aspects of RTO structures and operations.
---------------------------------------------------------------------------
\572\ See, e.g., PJM, ISO-NE, NY ISO, WPSC and East
---------------------------------------------------------------------------
Most commenters, however, would require an ISO (i.e., a not-for-
profit RTO) to make its market monitoring function more independent.
Pennsylvania Commission contends that an independent ISO is absolutely
necessary to perform market monitoring functions. EEI points out that
while an RTO's independence may ensure that its recommendations do not
favor particular market participants, this does not ensure that it will
monitor its own performance objectively. In its view, an ISO should use
outside experts within the monitoring committee or on an ad hoc basis
to address concerns about objectivity. Similarly, PG&E contends that
experience has shown that an ISO's rules and actions may interfere with
the proper functioning of the market. Industrial Consumers contend that
an RTO's operations must be sufficiently transparent that it is the
market participants that do the real monitoring. FTC suggests that
internal RTO monitoring could be problematic if the internal monitoring
unit is given enforcement powers, because this could both devolve into
re-regulation and raise conflict of interest issues. FTC recommends
that the Commission's RTO rules explicitly make clear that self-
monitoring controlled by an RTO does not create an antitrust exemption
for the RTO and its participants.
Los Angeles believes that market monitoring should be conducted by
an independent body. CP&L, however, believes that delegation to a
private party is questionable, where its objectivity may also be
challenged on grounds of conflict of interest, particularly, if the
delegated authority includes the ability to impose sanctions and
penalties. Oregon Commission believes that RTOs should appoint a local
committee to use RTO data to monitor the market for ancillary services
because RTOs, as major buyers and sellers of such services, will want
to protect their market shares. The Commission should consider
establishing its own regulatory advisory bodies to monitor markets. DOE
also claims that the Commission should avoid reliance upon RTO
monitoring to the exclusion of the Commission's own monitoring efforts.
Alliant believes that moving responsibility for monitoring market power
to another organization would allow the RTO to focus on the many
technical demands that will be placed on it. Metropolitan believes
market monitoring should occur on two levels: an internal group
responsible for data gathering and publication and frequent preliminary
analysis of anomalous conduct; and formal analyses performed by a group
or committee independent of RTO management whose results and
recommendations would not require RTO approval.
LG&E proposes that the RTO make its monitoring findings public and
refer
[[Page 901]]
them to an appropriate regulatory body. Industrial Consumers opposes
giving deference to the RTO's recommendations for correcting such
market power abuses and flaws. Instead, it believes that stakeholders
and market participants should use the RTO reports to make their own
recommendations.
NYPP believes that structural solutions are matters for
legislators, courts or regulatory agencies. In contrast, PJM believes
that, if the market issue is a structural one, the RTO should be able
to propose structural remedies to the Commission.
In the case of localized market power, MidAmerican submits that it
would be inappropriate for the RTO to take corrective competitive
actions in the case of localized must run generating unit market power.
Similarly, PG&E contends that RTOs should allow temporary supply and
price issues to be resolved by the competitive forces of the market,
unless there is a threat to the physical supply of power or a
Commission determination that markets are not workably competitive.
CalPX believes that monitoring and reporting should be simplified
in order to reduce costs and to rationalize staff and committee work
loads. Also, the RTO and power exchange compliance related staffs
should jointly conduct research that is beneficial both to increase
coordination and reduce costs. NY ISO submits that RTOs that are ISOs
should not be required to establish costly and otherwise burdensome
autonomous market monitoring units.
Many commenters address the issue of the appropriate role for the
Commission and the state commissions in market monitoring. Commenters
overwhelmingly believe that the Commission and state commissions have
an important role to play, whether it is a primary role as market
monitors, or a secondary role providing oversight of market monitoring
activities by RTOs.
Some commenters believe that market monitoring is better handled by
the existing statutory and regulatory agency frameworks than by
RTOs.\573\ They suggest a continuing, if not mandatory, role for the
Commission and other Federal and state authorities in conjunction with
any market monitoring undertaken by RTOs.\574\ PP&L Companies argues
that, in Gulf States Utilities Co. v. FPC,\575\ the Supreme Court made
it clear that the Commission is charged with serving as the first line
of defense to protect and preserve competition in wholesale power
markets.
---------------------------------------------------------------------------
\573\ See, e.g., Salomon Smith Barney, South Carolina
Commission, PG&E, Enron/APX/Coral Power and Duke.
\574\ See, e.g., SMUD, Tri-State, Cinergy, TDU Systems, EPSA,
Industrial Consumers, CMUA, PJM/NEPOOL Customers, NY ISO, ISO-NE and
DOE.
\575\ 411 U.S. 747 (1973).
---------------------------------------------------------------------------
TDU Systems and Sithe contend that regulatory commissions cannot
abdicate to RTOs the responsibility to ensure that wholesale electric
markets are free of market power. Many commenters see RTOs serving to
forward any claims of market abuse and market power to the various
federal and local regulatory agencies consistent with their respective
jurisdictions. PJM and LG&E see the Commission reviewing remedies and
approving penalties and sanctions. Desert STAR and CRC see the
Commission acting as a backstop to an RTO's ADR process or mitigation
plan. EEI suggests that RTOs regularly inform the Commission about
monitoring results, which will enable it to respond quickly to problems
not resolved by the RTO. SoCal Cities suggest that RTOs share
responsibility to remedy structural defects in the market or impose
general sanctions for market power abuse with appropriate state and
federal agencies, but not duplicate their responsibilities such as
implementation of the FPA. CalPX believes that there is a decreasing
role for regulatory oversight as a result of a progression toward
greater RTO self-regulation.
Florida Power Corp. and Nevada Commission suggest close
coordination of RTO market monitoring with state regulators. Nevada
Commission also suggests that RTOs collaborate their monitoring efforts
with neighboring RTOs, as well as audit the records of those parties
who violate the RTO's rules. Project Groups recommends adding an eighth
minimum function under which RTOs provide data support for states'
policies, monitoring the competitive impacts of emissions regulations,
verifying compliance with state generation portfolio standards.
NARUC claims that the states need to be heavily involved in RTO
market monitoring and that the Commission should work with the states
to make utility codes of conduct more effective. In its view, such
collaboration is the most effective means of monitoring market power in
generation, since the RTO would have information for the region on
transmission planning, generation expansion and transmission
constraints, and state commissions would have utility specific data and
information on local operations. NARUC argues that such collaboration
is critical because state commissions are responsible for both
evaluating local markets to assure competitiveness and for licensing
electric supplies, and abusers of market power can inhibit competition
and distort the prices of locally regulated services. NASUCA similarly
claims that market participants, state and federal regulatory agencies,
and state consumer advocates periodically review the indices and
screens to be used for RTO market monitoring. The RTO should
periodically issue confidential reports to federal and state regulatory
authorities and state consumer advocate offices, that describe the
state of the markets and the results of matters under investigation.
A number of state commissions suggest a continuing oversight role
over RTO monitoring by the Commission and the states.\576\ Oregon
Commission recommends that the Commission establish its own regulatory
advisory bodies to monitor ancillary services markets. For a for-profit
RTO, it recommends that a regional oversight committee perform this
function with the Commission reviewing any oversight committee reports.
---------------------------------------------------------------------------
\576\ See, e.g., Florida Commission, New York Commission and
Michigan Commission.
---------------------------------------------------------------------------
Commenters also address a number of issues related to the ability
of RTOs to perform self-assessments. A number of commenters believe
that RTOs are capable of objective analysis. NY ISO contends that an
ISO will have no incentive to distort the results of its analysis.
Cinergy recommends that RTOs be limited to monitoring the behavior of
the markets they administer because of the ready access to relevant
information. Los Angeles comments that, if the RTO is not primarily
responsible for providing ancillary services, it should not be burdened
with surveying that market.
Other commenters oppose RTOs monitoring the markets that they
operate because of conflict of interest concerns.\577\ EEI argues that
independence from market participants does not ensure that the RTO will
be able to monitor its own performance objectively, e.g., a non-profit
RTO may not have sufficient incentives to minimize the costs under its
control. Oregon Commission comments that RTOs cannot be entrusted to
monitor ancillary services markets, where they will be providing
services and have incentives to protect market share. Industrial
Consumers contends that market participants must perform monitoring
and, accordingly, an RTO's operations should be fully transparent. SNWA
and PG&E claim that the RTO
[[Page 902]]
should establish an independent body to monitor and evaluate its
performance.
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\577\ See, e.g., Florida Power Corp., CMUA and DOE.
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Some commenters, such as Salomon Smith Barney and Michigan
Commission, oppose the RTO monitoring markets where the RTO takes a
market position because the RTO plays the dual role of seller of
services and policeman. Alliant contends that an RTO will be competing
with generation providers in congestion management and have an
incentive to build transmission facilities. Similarly, CP&L contends
that a for-profit RTO may compete with others in providing ancillary
services, and therefore any proposal by the RTO monitor for remedial
action raises serious conflict of interest concerns. Industrial
Consumers suggests that, even in markets where the RTO is the supplier
of last resort, the RTO should not have quasi-regulatory powers.
Commenters also address the issue of whether RTOs should be
required to provide periodic assessments of markets they do not
participate in or operate, thereby assessing the effect of existing
structural conditions on the competitiveness of their region's
electricity markets. Some commenters oppose this proposal. Tri-State
opposes an RTO monitoring of power markets because it would not only
violate the Commission's goal of separation between transmission and
power sales, it would also add a level of complexity and cost to the
operation of the RTO. Justice Department believes that the RTO cannot
reasonably be expected to monitor activities with which it has no
involvement. Justice Department therefore recommends that the
Commission consider requiring each separate electric power trading
institution to monitor any market that it operates.
On the other hand, a number of commenters favor extending RTO
monitoring responsibility to markets they do not operate. PJM/NEPOOL
Customers argues that the independence of the RTO would enable market
participants and the Commission to have confidence in the RTO's
assessments. ISO-NE favors RTOs monitoring power markets. NASUCA
recommends that RTOs monitor bulk power markets, capacity markets,
transmission rights markets, ancillary services markets and any other
potentially competitive markets. FTC suggests that, where an RTO is
smaller than one of the major interconnects, the Commission may wish to
encourage all the RTOs within each of the interconnects to coordinate
their efforts to examine the effects of market rules or variations
between RTOs in market rules on the volume and price of inter-RTO
transactions. Cal ISO also sees collaborative market monitoring and
assessment by neighboring RTOs and at the national level.
Florida Power Corp. recommends that an RTO that is an ISO be
required to make regular assessments as to whether it has sufficient
operational authority to ensure its ongoing ability to provide
reliable, open access transmission service on a comparable basis to all
customers--nonetheless, the RTO should not be self-regulating.
For those regions where the real-time balancing function is
performed by an ISO, Advisory Committee believes that the ISO should
monitor market power in generation markets. SoCal Edison claims that,
where markets are not yet workably competitive, the RTO, with
Commission approval, should ensure that prices are just and reasonable
through appropriate temporary mechanisms such as price caps. PG&E
counters that, in no case, should RTOs be permitted to use control of a
power exchange for unilaterally capping prices set by the market.
Many commenters address the issue of how the RTO should report, if
at all, its monitoring activities. The Commission did not propose to
establish detailed standards on the format and content of monitoring
reports, noting that such matters are best left to the RTO. We asked
commenters to address whether reporting should be limited to when a
specific problem is encountered, or whether periodic reporting on the
state of competition and transmission access would be more appropriate.
Commenters express mixed views on reporting requirements. CRC
supports the concept of RTOs reporting to the Commission regarding RTO
design flaws, and New York Commission suggests that RTOs report on
market power abuse as well. Florida Power Corp. submits that, if market
monitoring is necessary, it should be performed by the RTO reporting
and filing appropriate information with state and Federal regulators.
Project Groups wants the provision of data to support state programs
pertaining to the monitoring of the competitive impacts of emissions
regulations. Project Groups argue that RTOs would be uniquely
positioned to support data collection for verification of green
marketing claims and compliance with information disclosure
requirements and portfolio standards. EEI opposes a Commission mandate
for RTOs to track generation source and emissions data. EEI recommends
the RTO voluntarily undertake this task to meet specific state
compliance requirements provided appropriate safeguards protect
competitively sensitive information. EEI expresses concern regarding
the possibility that the RTO would have authority to collect and
disclose information from a generation source where the state has not
imposed such a requirement.
Several commenters favor issuance of monitoring reports at regular
intervals. Project Groups believes that RTO monitoring units should
issue public reports on their activities and findings, including annual
reports on the general state of the market. Metropolitan supports
reporting at regular intervals from an external monitoring source;
however, during initial startup, more frequent reporting is advisable
to assist participants' understanding of the market operation. East
Texas Cooperatives believes that RTOs should prepare periodic reports
to the Commission with the precise form left to the discretion of the
RTO.
California Board contends that regular reports on market
performance should issue at least on a yearly basis, and include all
relevant data that can be made publicly available. NASUCA contends
that, to further create trust in the RTOs' ability to effectively and
objectively monitor the market, RTOs should periodically issue reports
describing the state of the markets that it is monitoring, items under
investigation by the RTO, and any results from completed
investigations. In its view, market participants, state and federal
regulatory agencies and state consumer advocates should participate in
the development and periodic review of the indices and screens the RTO
will use to monitor the operation of the markets. Reports should be
provided to state and federal regulatory authorities as well as state
consumer advocate offices, on a confidential basis, to enable them to
independently assess whether additional investigation is merited. Cal
ISO submits that the Commission should specify regular reporting
requirements for the RTO's monitoring unit. PJM believes that RTOs
should periodically report results of monitoring activities to the
Commission and state agencies.
Components of a Market Monitoring Plan. Commenters address various
issues regarding particular elements of a market monitoring plan. Many
commenters address the issue of whether RTOs should be allowed to
impose penalties and sanctions. Most commenters would limit the RTO's
ability to impose penalties or sanctions. Many of them argue that such
authority should remain the province of the
[[Page 903]]
regulatory and antitrust agencies.\578\ Justice Department claims that
RTOs lack experience either in detecting exercises of market power or
in making recommendations on correcting market power problems. SPRA
questions whether the imposition of sanctions by the RTO may conflict
with the Supremacy Clause of the Constitution and whether affected
public power bodies could only consent to such sanctions if they do not
create indefinite or uncertain liabilities. PP&L argues that, because
it will be judge and jury, the RTO must demonstrate competitive harm
before taking any market action. Some commenters, such as CP&L, note
that a for-profit RTO may not be objective in imposing sanctions
because it competes with other market participants. Other commenters,
such as Salomon Smith Barney, claim that RTOs should be limited to
extracting ordinary commercial penalties when market participants fail
to follow the market's rules. EPSA claims that RTOs should be empowered
to intervene in a market within the strict confines of the Commission's
oversight only when a situation has the potential to become
catastrophic. Mass Companies opposes allowing a private RTO or one that
is operated by a non-stakeholder board to enforce violations of market
standards and impose sanctions and penalties.
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\578\ See, e.g., Entergy, Duke, PG&E, PSE&G, PJM/NEPOOL
Customers and Williams.
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Canada DNR claims that it will be problematic for Canadian entities
subject to the jurisdiction of Canadian provincial and Federal energy
regulators also to be subject to an RTO that has its disciplinary
authority backstopped by the Commission. In its view, the issue will
not be resolved by simply having the appropriate Canadian regulator
serve as the regulatory backstop to the RTO for each Canadian entity
because the Canadian regulator may take a different position than the
Commission.
A few commenters support authority for RTOs to impose penalties and
sanctions. Among them, CalPX believes that RTO governing boards and
power exchange market monitoring committees must be able to take
appropriate action either by referral to regulatory agencies or
directly through applicable sanctioning authority. It views this as
critical for self-policing and providing prompt remedies before
problems detrimentally affect market results. ISO-NE believes that an
RTO should have the ability to impose penalties and sanctions, but
suggests that the RTO not act as an antitrust agency, in order to
increase the acceptability of sanctions among participants.
The Commission specifically sought comment on whether penalties
should be limited to violations of RTO rules and procedures, or whether
the RTO should be allowed to impose penalties for the exercise of
market power. More commenters oppose than support RTOs imposing
sanctions and penalties for market power abuse. Among them, Allegheny
and Metropolitan claim that this is a proper function of regulatory or
antitrust authorities. Central Maine argues that the Commission cannot
grant RTOs the authority to impose corrective actions without affording
the affected public utilities with procedural due process. EEI believes
that the RTO tariff may include RTO authority to impose fines or
sanctions to ensure compliance with RTO rules in accordance with the
costs imposed by their actions. Pointing to similar positions taken by
Justice Department and FTC, EEI contends, however, that the RTO should
not attempt to define or prosecute alleged exercise of market power
because it is not a regulatory body or an antitrust agency authorized
to take such actions. It also suggests that limited additional
authority might be granted during the transition to restructured
markets to permit the RTO to deal effectively and timely with
identified market design flaws, software errors, or other unanticipated
situations that could be costly if no action is taken.
Cinergy also argues that the RTO should not be allowed to take
corrective action against individual market participants. It believes
that claims of market abuse and the exercise of market power should be
forwarded to the Commission to address consistent with its
jurisdiction. Similarly, MidAmerican recommends that RTO penalties be
limited to (1) willful violations of material RTO directives related to
the operation of regional transmission facilities, Commission approved
RTO standards for transmission facility operations, and material
provisions of RTO agreements that conflict with the RTO transmission
tariff, and (2) violations of RTO transmission tariff provisions
relating to operating reserves and energy imbalances. NASUCA recommends
that compliance with RTO rules be enforced with penalties and sanctions
imposed through a collaborative process involving all market
participants, regulatory agencies and consumer advocates. However, the
Final Rule should specify that any actions taken by the RTO cannot
substitute for penalties or other remedies which may stem from
independent investigations by governmental authorities. Similarly, ISO-
NE and SNWA generally would impose sanctions based on a participant's
engaging in patterns of conduct defined in the RTO's rules or its
tariff.
NYPP, DOE, and LG&E generally concur that RTO sanctions and
penalties should only be levied for violations of RTO rules and
procedures, whereas penalties and sanctions for market power abuses are
matters for the regulatory and antitrust agencies, legislators, or the
courts. Florida Power Corp. argues that, since an RTO does not have
authority to grant or terminate market-based rate authorizations
premised respectively on the absence or presence of market power, the
RTO should therefore have no role in passing judgement or imposing
penalties for the exercise of market power.
On the other hand, some commenters, such as East Texas
Cooperatives, are more comfortable with RTO imposition of penalties and
sanctions for market power abuse. PJM recommends that RTOs be able to
take corrective action to ameliorate market abuses or flaws and to seek
Commission approval to add penalties and sanctions to its market
monitoring plan. NECPUC recommends that market monitoring be expanded
to include formalized mitigation and sanction rules in connection with
market design, implementation flaws and market power. NY ISO claims
that RTOs should mitigate evident market power problems, on a
prospective basis, by applying pre-approved remedies. CRC submits that
RTOs investigate whether market power abuse results from a design flaw
and report the results to the Commission for approval of its mitigation
plan. WPSC sees RTOs being effective because they will have access to
real-time data on system conditions and should be given authority to
take appropriate corrective action immediately to respond to market
abuses.
Some commenters also want sanctions against market participants for
reliability rule violations. PSNM claims that RTOs should defer to
existing mechanisms where they exist (such as the WSSC's Reliability
Management System RMS, and NERC Reliability Standards and Measures) for
sanctions against market participants for poor performance, rather than
create new monitoring and sanction systems for RTOs. Similarly, Desert
STAR submits that any RTO should be allowed to pass the reliability
performance standards sanctions on to participants who do not comply.
SMUD concurs that an important aspect of enforcing reliability
standards is ensuring that the RTO has sufficient authority to police
and
[[Page 904]]
investigate the markets they administer, and assess fines and other
appropriate penalties, or resolve disputes amongst market participants
as to any alleged market abuse.
A few commenters also address the Commission's questions about how
much discretion the RTO should have in setting penalties (e.g., should
the RTO's penalty authority be limited to collecting liquidated
damages). Nevada Commission submits that RTOs should be allowed to
impose specific penalties and sanctions for non-compliance with RTO
rules based on liquidated damages and not punitive damages. Cal ISO and
Metropolitan believe that penalties should be limited to liquidated
damages. Cal ISO argues that for cases of repeated or intentional
violations or serious abuses of market power, the RTO should seek
relief, including imposition of punitive damages, from the Commission
or other appropriate agencies such as the Justice Department.
Metropolitan argues that liquidated damages sought by an RTO should be
approved by the Commission. And Duke opposes the RTO assuming the role
of market monitor and enforcer; therefore, it recommends that terms and
conditions for any penalties the RTO might impose should be agreed upon
by contract during the RTO development process.
On the other hand, WPSC claims that the RTO should have the
discretion to determine the amounts of adequate sanctions and penalties
to discourage anti-competitive conduct. Whether the RTO has acted
properly can always be reviewed after the fact through a dispute
resolution procedure either through the Commission or the Justice
Department. NASUCA contends that sanctions and other penalties should
be large enough to be an effective deterrent. It suggests that a for-
profit RTO may have incentives to impose unjustified penalties and
should be required to allocate all revenue derived from sanctions and
penalties in a way that benefits customers. SMUD offers that, since
liquidated damages are a mere proxy designed to make a victim whole for
a transgression, they do not really serve as a deterrent to market
abusive conduct.
Several commenters address whether the SEC model of regulating
stock exchanges, i.e., requiring extensive and sophisticated market
monitoring of stock exchanges, should applicable to RTO market
monitoring. Some commenters, such as EEI and PP&L, do not believe the
model is applicable. EEI claims that monitoring scheme in the
securities industry is an exception because in most industries the
market participants bring competitive problems to the attention of
antitrust authorities. Sithe also opposes any emulation of the NASD or
NYMEX model of self-regulation at this time because of the limited
amount of market experience to date.
PJM/NEPOOL Customers and Cal ISO, however, contend that the RTO
monitoring function should be similar to that of a stock exchange
because the RTO is designed to ensure that the exchange of electricity
can occur readily and easily in a competitive marketplace.
Commission Conclusion. In the NOPR, the Commission proposed that
RTOs perform a market monitoring function. Many commenters raise a
number of issues regarding market monitoring. The issues largely
encompass the following concerns: the need for and scope of a market
monitoring function; who should perform this function and how it should
be performed; and what are the specific components or procedures of a
market monitoring plan.
The Commission recognizes that the market monitoring concept is new
and not yet well-refined, either at the Commission or within existing
ISOs. We also acknowledge the apprehensions of some parties that market
monitoring by an RTO could intrude into markets and affect their
behaviors. The Commission, however, is engaged in finding ways to
understand market operations in real-time, so that it can identify and
react to any problems that are preventing the most efficient
operations. It also has a responsibility to protect against
anticompetitive effects in electricity markets. \579\ If we are to
satisfy this goal, we must systematically assess whether our policies
and decisions are consistent with this responsibility. Market
monitoring is an important tool for ensuring that markets within the
region covered by an RTO do not result in wholesale transactions or
operations that are unduly discriminatory or preferential or provide
opportunity for the exercise of market power. In addition, market
monitoring will provide information regarding opportunities for
efficiency improvements.
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\579\ See Gulf States Utilities v. FPC, 411 U.S. 747, 758-59
(1973).
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However, in light of the different forms of RTOs that could be
developed by market participants and the varying types of markets an
RTO may be operating within its region, different market monitoring
plans are likely to be appropriate for different RTOs. Consequently,
after careful consideration of the comments, the Commission will
require that RTO proposals contain a market monitoring plan that
identifies what the RTO participants believe are the appropriate
monitoring activities the RTO, or an independent monitor, if
appropriate, will perform. We believe that such approach will provide
those proposing an RTO sufficient flexibility to design a monitoring
plan that fits the corporate form of the RTO as well as the types of
markets the RTO will operate or administer. We have revised the
regulatory text for the RTO market monitoring function to reflect our
decision to allow this flexible approach.
Although we decline at this time to prescribe a particular market
monitoring plan or the specific elements of such a plan, the RTO must
propose a monitoring plan that contains certain standards. The
monitoring plan must be designed to ensure that there is objective
information about the markets that the RTO operates or administers and
a vehicle to propose appropriate action regarding any opportunities for
efficiency improvement, market design flaws, or market power identified
by that information. The monitoring plan also must evaluate the
behavior of market participants, including transmission owners, if any,
in the region to determine whether their behavior adversely affects the
ability of the RTO to provide reliable, efficient and nondiscriminatory
transmission service. Because not all market operations in a region may
be operated or administered by the RTO (e.g., there may be markets
operated by unaffiliated power exchanges), the monitoring plan must
periodically assess whether behavior in other markets in the RTO's
region affect RTO operations and, conversely, how RTO operations affect
the efficiency of markets operated by others. Reports on opportunities
for efficiency improvement, market design flaws and market power abuses
in the markets the RTO operates and administers also must be filed with
the Commission and affected regulatory authorities.
In developing its market monitoring plan, the RTO should identify
the markets that will be monitored, i.e., transmission, ancillary
services or any other market it may develop (e.g., congestion
management). With regard to those markets, the monitoring plan should
examine the structure of the market, compliance with market rules,
behavior of individual market participants and the market as a whole,
and market power and market power abuses. The monitoring plan should
also address how information will be used and reported. The monitoring
plan
[[Page 905]]
should indicate whether the RTO will only identify problems and/or
abuses or whether it also will propose solutions to such problems. We
note that sanctions and penalties may be appropriate for certain
actions such as noncompliance with RTO rules. However, the monitoring
plan should clearly identify any proposed sanctions or penalties and
the specific conduct to which they would be applied, provide the
rationale to support any sanctions, penalties or remedies (financial or
otherwise) and explain how they would be implemented. With regard to
the reporting of market monitoring information, the monitoring plan
should indicate the types and frequency of reports that will be made
and to whom the reports will be sent. Under the FPA, the Commission has
the primary responsibility to ensure that regional wholesale
electricity markets served by RTOs operate without market power. An
appropriate market monitoring plan must provide an objective basis to
observe markets and, if appropriate, provide reports and/or market
analyses. Market monitoring also will be a useful tool to provide
information that can be used to assess market performance. This
information will be beneficial to many parties in government as well as
to power market participants. This includes state commissions that
protect the interests of retail consumers, especially where they are
overseeing the development of a competitive electric retail market. We
note, however, that the market monitoring function for the RTO does not
limit the ability of each state within the RTO's region or other
authorities to decide the nature and extent of its own market
monitoring activities.
We are not requiring a plan that necessarily involves the
collection of data the RTO would not collect in its ordinary course of
business. We believe that the information collected through the RTO
market monitoring plan will reflect data that the RTO will collect or
have access to in the normal course of business (e.g., bid data,
operational information). In light of our requirements that the RTO
have operational control over the transmission facilities transferred
to it and the RTO be the security coordinator for its region, the RTO
will be in the best position to perform (or provide information to
another entity, if appropriate, for it to perform) objective monitoring
functions for the markets that the RTO operates or administers in the
region.
In response to commenters' arguments that RTO market monitoring
results in an impermissible shift of Commission authority to other
entities, we emphasize that performance of market monitoring by RTOs is
not intended to supplant Commission authority. Rather it will provide
the Commission with an additional means of detecting market power
abuses, market design flaws and opportunities for improvements in
market efficiency. Further, because market monitoring plans will be
required to be filed with and approved by the Commission as part of an
RTO proposal, we will retain the ability to determine what, how and by
whom activities will be performed in the first instance.
Because we believe market monitoring is essential, we decline to
set any sunset date for monitoring at this time. However, as bulk power
markets evolve and become more competitive, we may revisit the need for
the type of monitoring the Rule requires.
7. Planning and Expansion (Function 7)
In the NOPR, the Commission proposed that the RTO planning and
expansion process must satisfy certain standards. Specifically, RTOs
would be required to: (1) Encourage market-motivated operating and
investment actions for preventing and relieving congestion; and (2)
accommodate efforts by state regulatory commission to create multi-
state agreements to review and approve new transmission facilities,
coordinated with programs of existing Regional Transmission Groups
(RTGs) where necessary. We suggested that RTOs be designed to promote
efficient use, which requires efficient price signals such as
congestion pricing, and efficient expansion of their regional grid,
which requires control over planning and expansion. We specifically
proposed that the RTO have ultimate responsibility for both
transmission planning and expansion within its region. If the RTO is
unable to satisfy the planning and expansion requirement when it
commences operation, we proposed that the RTO must file a plan with
specified milestones that will ensure that it meets this requirement no
later than three years after initial operation. In addition, the
Commission sought comment on whether three years is an appropriate
amount of time for implementation of this function.\580\
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\580\ FERC Stats. & Regs. para. 32,541 at 33,751-53.
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Comments. Encourage Market-Motivated Operating and Investment
Actions for Preventing and Relieving Congestion. Many commenters
support the Commission's proposal to require that an RTO must ensure
the development and operation of market mechanisms to plan and
refinance transmission system expansion. As part of this an RTO should
provide all transmission customers with efficient price signals that
show the consequences for their transmission use decisions.\581\
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\581\ See, e.g., United Illuminating, Wyoming Commission,
Industrial Consumers, Champion, NSP, PG&E, Williams, LG&E, FTC and
APX.
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Some commenters, such as JEA and Williams believe that this role is
best performed by for-profit entities because system expansion
decisions must be driven by economic considerations. Entergy also
contends that a transco will not create any bias in the method of grid
expansion.
Los Angeles agrees that an RTO should rely upon market signals and
market solutions in assessing all feasible options (e.g., construction
of new generation, redispatch of existing generation, grid expansion)
to assure the least-cost option is pursued. NASUCA also argues that the
Commission should mandate that RTOs use least-cost planning on a
region-wide basis for transmission system expansions and upgrades. It
notes that the larger the region over which least-cost planning is
conducted, the more economically efficient the outcome is likely to be.
If market solutions do not develop or are not timely, Los Angeles
believes that the RTO must have the power to resolve the transmission
problem. LG&E proposes that RTOs be permitted to use competitive
bidding as a means to meet new transmission investment needs.
EPA believes that RTOs should adopt a resource planning process
with sufficient flexibility to consider non-traditional resources and
to assign appropriate values to their unique benefits. EPA further
believes that RTOs should be encouraged to take into account
environmental costs and benefits that are not reflected in resource
prices.
Puget suggest that the Commission should recognize that the concept
of RTOs may contain some elements that do not enhance the reliable
operation of the transmission grid. Puget requests that the Commission
should address more fully how it will mitigate the effects of the
severance of generation and transmission planning and operation and how
it plans to ensure maximum reliability at the lowest integrated costs.
NASUCA recommends that the Commission require RTOs to develop a
baseline regional transmission expansion plan that would identify the
regional system's ability to meet essential NERC reliability criteria
and
[[Page 906]]
isolate potential constraint areas of the existing system where
upgrades may be necessary or additional generation desirable. Such a
baseline plan could provide a valuable tool to market participants in
signaling the best locations for new generation projects. Entergy
proposes the use of a regional transmission plan that includes a
regional transmission planning summit process involving all
stakeholders.
TAPS, however, questions whether market-based mechanisms to expand
the transmission grid will emerge readily from an efficient short-term
transmission pricing regime that accounts properly for the costs of
congestion. TAPS asserts that, while efficient congestion pricing is an
important component of a well-designed transmission regime, it is not
the answer to the concerns that have been raised regarding the lack of
economic and regulatory incentives to expand the transmission grid.
Many commenters agree that RTOs should be responsible for
conducting the studies necessary to assess the need for new
transmission system enhancement.\582\ However, some commenters argue
that the role of the RTO should be to facilitate market investment by
others in new transmission and generation, not to lead the market by
making its own plans for new facilities. For example, Seattle suggests
that the RTO should generate information on the locations, frequencies
and costs of congested paths to guide capital investment. It believes
that the RTO need not make capital investments directly; rather it
should seek market mechanisms, such as requesting bids for needed
capacity, to encourage investments. EME states that performance of this
role requires accurate accounting for the impact of congestion and new
generation, and proper allocation of costs to those that require such
costs to be incurred.
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\582\ See, e.g., EME and Seattle.
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To ensure that transmission expansion decisions are not biased,
ComEd proposes that RTO functions be performed by two linked
organizations that together make up a ``Binary RTO.'' ComEd envisions
that the Binary RTO would consist of for-profit independent
transmission companies (ITCs), each operating a large aggregation of
existing transmission systems, under the oversight of an independent,
not-for-profit Regional Transmission Board (RTB). The ITCs will
identify transmission additions, upgrade opportunities, and prepare
long-range plans which would be reviewed by the RTB and subsequently
integrated in an RTB-wide planning system.
Powerex believes that it is better to eliminate congestion at its
source through facilities upgrades, if economically and environmentally
feasible, than to attempt to manage congestion on a long-term basis
through congestion pricing schemes.
Many commenters support the concept that RTOs must be responsible
for transmission planning and that single-system planning should be the
objective of the RTO planning process.\583\ Commenters differ, however,
on the extent of the RTO's role in the planning process. Some
commenters, such as Powerex, argue that the RTO must have control over
transmission service, planning, system impact studies and facilities
studies, and the authority to determine the need for, and require the
implementation of, transmission upgrades by member utilities. Other
commenters, such as LIPA and H.Q. Energy Services, propose that, in the
absence of transmission expansion proposals from current or proposed
market participants, the RTO should have the responsibility for
assessing whether transmission improvements are needed and, if a need
is found, the RTO should have the authority to order such expansion.
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\583\ See, e.g., PNGC, Wisconsin Commission, EAL, Entergy, PJM,
Minnesota Power and Montana-Dakota.
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Some commenters such as NY ISO, on the other hand, express concern
that exclusive authority by the RTO over transmission planning is
overly restrictive. NY ISO claims that entities which are responsible
for coordinating transmission expansion, but which lack authority to
make enforceable planning decisions, can nevertheless achieve the
Commission's primary transmission expansion-related goal, i.e.,
ensuring that investments in new transmission facilities are
coordinated to ensure a least-cost outcome that maintains or improves
existing reliability levels.
H.Q. Energy Services objects to NY ISO's arguments as being merely
concerned with preserving its so-called ``two-tier'' governance system
which provides NY ISO transmission owners with significant authority,
or veto power, over interconnections with generating facilities and
over decisions related to transmission system planning and expansion.
H.Q. Energy Services does not believe that the two-tier approach is
appropriate unless the RTO has ultimate decision-making authority.
Many commenters agree with the proposal that an RTO must be
ultimately responsible for all transmission expansions and
upgrades.\584\ These commenters claim that transmission operations must
be conducted on an independent and fair basis and must be undertaken by
an impartial entity if transmission services are to be offered on a
truly non-discriminatory basis. They argue that vesting the RTO with
the ultimate responsibility for expanding transmission systems
eliminates the conflict that is inherent in vesting these
responsibilities with an entity that also has commercial interests that
are competing with users of the system.
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\584\ See, e.g., San Francisco, SoCal Cities and CMUA.
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Although SMUD supports having the RTO be responsible for
transmission planning and expansion, it cautions that, in such a
paradigm, people that have no responsibility to the ratepayers will be
deciding planning and expansion issues. Therefore, SMUD argues that the
Commission needs to scrutinize the recovery of the costs of such
expansion to ensure that such expansion decisions and costs are
prudent, just and reasonable.
Several commenters agree that the RTOs can and should play a
significant role in the transmission planning and expansion
process.\585\ Some of these commenters, such as NYPP and Mass
Companies, however, do not believe that the Commission should require
that RTOs have authority to order a transmission owner to modify or
expand its transmission system. Nevada Commission believes that
transmission owners should be allowed to assist an RTO in the
development of grid planning criteria and could take the lead in such
grid planning with RTOs performing more of an overview role. Professor
Joskow states that the transmission owners, operating through a sound
RTO/ISO transmission planning process should be expected to be the
primary, but not necessarily the exclusive, source of network
enhancement initiatives. WEPCO argues that transmission owners should
be integrated into the RTO regional transmission plans where they can
be improved and expanded to meet regional needs most efficiently.
Turlock contends that the RTO's authority over the transmission system
it operates must be limited to that system. Turlock argues that the RTO
should not have the ability to force expansion of lower voltage or
tangentially related facilities which are beyond the area of its
responsibility, even if those other facilities might have a small but
[[Page 907]]
theoretically possible impact on the RTO's facilities.
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\585\ See, e.g., NYPP, Industrial Customers, Mass Companies and
Nevada Commission.
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CP&L supports a coordinated planning approach which would be
similar to the planning approaches identified in the Midwest ISO and
the Alliance RTO filings, where the RTO would have responsibility for
review of the transmission plan, but the individual transmission-owning
entities would provide the necessary input to facilitate the
development of the comprehensive RTO transmission plan. East Kentucky
argues, however, that an individual transmission owner should be able
either to require or to veto the building of a particular RTO facility.
MidAmerican disagrees with the proposal that the RTO have the
ultimate responsibility for both transmission planning and expansion in
the region. MidAmerican claims that existing regional transmission
groups (RTGs) have clear and prominent roles in transmission expansion
decisions in which planning for transmission improvements are
coordinated through collaborative processes that already involve many
interested stakeholders in the widest fashion possible. MidAmerican
states that throughout the MAPP region there is broad support for
continuing transmission planning and expansion decisionmaking as a
collaborative function and that the existing collaborative processes
adequately accommodate RTO participation.
Central Maine believes that RTOs/ISOs can and should play a
significant role in the transmission planning and expansion process,
but disagrees with the Commission's proposal to give ISOs ultimate
responsibility for transmission planning and expansion. Central Maine
does not object to ISOs having oversight responsibility in these area,
but Central Maine believes that the planning and engineering functions
should be a shared responsibility between utilities and RTO, i.e., the
Commission should consider utility planners as a satellite to the ISO/
RTO similar to satellite function served by utility control centers in
monitoring, switching and dispatching. Central Maine states that the
Commission should grant individual transmission owning utilities an
equal voice in determining the technical aspects of transmission
planning and expansion.
Although Big Rivers believes that, as proposed in the NOPR, the RTO
should be the default provider of transmission planning and expansion,
it agrees with NRECA that incumbent transmission owners should have the
first opportunity to build required transmission system expansion with
RTO ability to facilitate needed construction by others.
Some commenters suggest specific tasks and functions that the RTO
should perform or have the ability to require as part of the
transmission planning and expansion function.\586\ For example, SRP
proposes that at a minimum, each RTO should have the authority to: (1)
Direct transmission owners to study and evaluate system performance and
to develop plans to solve known reliability or adequacy problems; (2)
revise or combine elements of transmission owners' plans to achieve the
most efficient and reliable transmission expansion plan; (3) approve or
reject any component of the RTO transmission plan developed by a
transmission owner; and (4) approve facility additions by third
parties.
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\586\ See, e.g., Project Groups, LIPA and SRP.
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Accommodate Efforts by State Regulatory Commission to Create Multi-
State Agreements to Review and Approve New Transmission Facilities.
Many comments concur that multi-state agreements are to be encouraged
and that the RTO should be designed to work within that structure.\587\
Commenters, including NSP and Nevada Commission, encourage the
Commission to provide an active role for RTOs to participate with state
and local government in the siting and licensing of new facilities. PJM
states that a cooperative relationship between RTOs and the states is
essential to effective transmission expansion planning. In PJM's view,
states are more likely to trust the planning decisions of RTOs that
have no commercial interest in transmission and generation expansion
than decisions made by transmission-owning entities, which have
commercial interests.
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\587\ See, e.g., Illinois Commission, DOE and New Smyrna Beach.
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Cinergy recommends that the final rule include a Commission
commitment to proceed aggressively to establish a forum to encourage
coordination of RTO planning and expansion among states through multi-
state certification agreements and multi-state regional planning
boards. Cinergy notes, however, that the creation of a forum or agency
to review grid planning and expansion that would consider the public
interest beyond the constraints of state boundaries may require federal
legislation. If so, the Commission should be aggressive in its dialogue
with Congress to obtain the requisite legislative relief.
The Kentucky Commission suggests creating a voluntary ``Joint Board
on Regional Transmission Siting'' to develop and review standards for
transmission expansion. The Joint Board would include participation
from the Commission, state commissions, RTOs, and other interested
parties. The Joint Board would also convene ad hoc committees to review
specific transmission expansion proposals. Pennsylvania Commission also
prefers a joint Federal-state approach towards regulating RTO site
approvals, expansion, innovation and customer service. It notes that a
joint Federal-state approach has been used with success in other areas,
such as the Susquehanna River Basin Commission, the Delaware River
Basin Commission and the Joint Pipeline Office which regulates the
Trans-Alaska Pipeline System.
Illinois Commission recommends that accommodation of multi-state
efforts be expanded to include the possibility of multi-state regional
regulatory oversight organizations. Such organizations could be
instrumental in coordinating regional solutions to regulatory and
policy issues.
Otter Tail expresses concern that multi-state agreements may not
actually add to the efficient use and expansion of the interstate
transmission system due to a danger that these types of agreements
could be mired in state-versus-state political conflict and become
unworkable, to the detriment of transmission owners, generators, and
ultimately customers. Industrial Consumers also does not believe that
requiring an accommodation with ``multi-state agreements'' is
necessarily productive. It states that nothing now prevents such
coordination among states, yet there is no obvious evidence that this
will work. Industrial Customers believes that states will always
reserve the right to veto a project that may be partially situated
within their jurisdiction, regardless of the benefits elsewhere.
East Texas Cooperatives believes that retention of state public
utility commission authority over siting (and other necessary
approvals) is necessary to control the risk of overbuilding because
RTOs will have no real incentive to limit facility construction.
Commenters generally express support for the proposal that the RTO
build on existing RTG processes.\588\ For example, Industrial Consumers
urges that the Commission require existing RTGs to merge their
functions with the RTOs because RTGs should not be allowed to develop
an institutional
[[Page 908]]
culture that diverges from the goals and objectives of RTOs.
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\588\ See, e.g., Wisconsin Commission, Industrial Customers and
SRP.
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New Smyrna Beach and Oneok claim that market participants will
undoubtedly benefit from a multi-state siting process for transmission
because it may make siting of new generation easier if there is more
certainty that related transmission siting decisions will be made on a
timely basis with one-stop shopping.
Several commenters address the role of the Commission in the RTO
planning and expansion process. Detroit Edison and Wolverine
Cooperative support the establishment of the Commission as the primary
channel of certification for transmission siting, construction, and
expansion. Detroit Edison states that regional reliability
organizations and the RTOs in each reliability region should be
permitted to determine necessary changes and additions in transmission
with input from transmission owners, control area operators, and other
interested parties. It is vital, it states, that a single
administrative agency resolve issues related to the siting of
transmission facilities on a regional basis and have the authority to
approve transmission expansion plans on a timely basis. Detroit Edison
believes that the Commission should fill the important role of sole
regulator over transmission siting and construction, just as it
currently does in approving the siting and construction of natural gas
pipelines, and it urges the Commission to work to gain such authority.
Pennsylvania Commission recommends that, if an RTO determines that
transmission expansion is necessary, it should file with the Commission
to demonstrate that need. Once the Commission determines a need exists
within the RTO, the RTO should then file with the appropriate states
for a determination of the siting issues. Pennsylvania Commission
believes that vesting authority for determining the need for
transmission expansion with the Commission solves several problems that
are certain to arise in state forums. Federal determination of the need
for transmission expansion obviates the burden of filing with multiple
jurisdictions and possibly receiving conflicting determinations.
Otter Tail states that Commission should seriously consider whether
the public interest would be better served through adoption of a
transmission siting policy that is similar to review of interstate
natural gas pipelines.
NY ISO claims that in many cases transmission expansion is delayed
or blocked entirely by environmental and other transmission siting
regulations. Nevertheless, NY ISO supports the NOPR's proposal that
RTOs participate in efforts to create multi-state transmission
expansion agreements.
East Kentucky believes that there needs to be some regulatory
oversight authority for facilities that are deemed necessary by an RTO
planning staff. East Kentucky proposes that this regulatory authority
be the Commission or a regional regulatory authority.
Conlon recommends that the Commission have the necessary authority
to enforce reasonable siting request, or critically needed future
transmission lines could be delayed causing a reliability risk.
Granting the right of eminent domain to transcos or ISOs in Federal
legislation would be another approach. This could be accomplished by
the Commission recommending to Congress that it have the right of
eminent domain.
LG&E believes that it is important that state authority over system
expansion not impede necessary improvements that enhance the efficiency
of the regional grid that is, or will be, subject to RTO control.
Ultimately there may be a need for a congressional solution to the
current balkanized system for authorizing grid expansion. In its
comments, the East Central Area Reliability Council explicitly calls
for such legislative action based on its concern that transmission
facility expansion requests will fail as they become bogged down in
multiple state reviews. LG&E shares this concern. Still, until such
time as the statutory framework for transmission expansion is amended,
LG&E believes that RTOs represent an opportunity for coordinating
regional transmission expansion needs among transmission owners and
state authorities.
Project Groups maintains that RTOs should be required to coordinate
and lead in the development of comprehensive least cost regional plans
for assuring short-and long-term system reliability, and they must
coordinate the actions necessary for implementing timely system
upgrades and additions pursuant to those plans. For example, RTOs must
be given the authority to petition state and local regulators for
necessary siting authorizations, including certificates of need or
public necessity and environmental permits, as well as the authority to
order construction of facilities sited and permitted under state
regulatory authorities. The Commission should encourage state reliance
on RTO-approved plans as the primary basis for the exercise of eminent
domain powers under state law.
Puget notes that state condemnation powers granted to utilities are
usually limited for the benefit of the citizens of the state in which
the utility operates. It is not clear that a state utility can delegate
its state condemnation power to a regional RTO. Therefore, the final
rule should expressly address how state condemnation authority can be
legally exercised by a regional RTO.
NASUCA maintains that the RTO regional planning efforts must not
displace state government siting authority. NASUCA states that the
final rule should specifically recognize state statutory authority to
regulate siting of transmission facilities. For other planning and
expansion matters, the Commission should require RTOs to establish a
process to ensure that the RTO obtains input from state government
agencies with respect to the regional transmission plan. Nevada
Commission states that it is imperative that the RTO coordinate
transmission siting and planning with state agencies. Tri State
believes that states should continue to fulfill their traditional roles
in siting transmission facilities. However, it notes that it may be
necessary for the states to consult with the RTO on transmission
facility certification since the RTO will be charged with overall
responsibility for transmission planning and will be required to work
cooperatively with states and other regional groups.
CP&L supports state and local governments retaining the authority
for certification and siting of new transmission facilities. These
government agencies are closer to the local residents who will be
affected and can best evaluate the great number of factors that must be
considered in approving transmission routes.
Several commenters address the issue of eminent domain authority as
a component of the transmission planning and expansion function. East
Kentucky believes that the issue of eminent domain needs to be
addressed for not only RTOs, but also for the entire open access
transmission network. East Kentucky questions whether an entity, if
required by an RTO or the Commission to construct a transmission
facility, has eminent domain authority that is sufficient to allow the
entity to acquire all property rights necessary to construct the
required facility. Consequently, East Kentucky argues that, as a
general proposition, Congress needs to grant federal eminent domain
authority to any entity that is required by the Commission or any form
of RTO to build a facility so that such entity can acquire private
property rights under Federal law. Because it believes that siting of
transmission has become the principal impediment to transmission
[[Page 909]]
expansion, EPSA also advocates that the RTO should be delegated
sufficient authority to direct transmission owners or others to excise
their eminent domain authority, as necessary, to implement transmission
system expansion plans independent of the source of funds or the
beneficiary of the project. Under current law, this authority must come
from the states. Thus, EPSA also advocates the passage of Federal
legislation that vests the Commission with primary jurisdiction over
major transmission planning and siting decisions, perhaps subject to a
requirement that the Commission consult with a regional siting
authority or a consortium of affected state siting boards.
Central Maine disagrees and recommends that the Commission should
reject EPSA's comments. Central Maine notes that, if a state government
intends that an RTO have the power of eminent domain, the state
legislature will grant it. Central Maine argues that RTOs should not be
granted the power to do something indirectly that they may not do
directly. Consequently, it believes that EPSA must pursue its proposal
through the enactment of state legislation.
Whether Three Years Is an Appropriate Amount of Time for
Implementation of This Function. Several commenters support the
Commission's proposal to allow up to three years to implement the
planning and expansion function.\589\ Some commenters, however, believe
that three years is too short.\590\ South Carolina Authority suggests a
five-year period. Florida Commission believes that it is premature to
set any time limit for implementation of the planning and expansion
function.
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\589\ See, e.g., Tri State, SoCal Edison and PNM.
\590\ See, e.g., NECPUC, Duke and South Carolina Authority.
---------------------------------------------------------------------------
On the other hand, several commenters believe that three years is
too long a period.\591\ Most of these commenters believe that the
planning and expansion is such an important function that its
implementation should not be delayed at all. NYC suggests that
implementation should not be delayed more than a year. SRP argues that
the uncertainty that currently exists about who ultimately will be
responsible for building and paying for new transmission facilities is
causing delays in upgrades. According to SRP, requiring the RTO to
perform this function upon commercial operation will eliminate this
uncertainty. Industrial Customers also argues that any delay should not
be used as an excuse to stall the construction of any facility for
which the need has been established. SRP suggests that, if a delay in
implementation is permitted, the RTO should be required to identify the
entity responsible for financing and building transmission expansion
prior to the RTO assuming such responsibility.
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\591\ See, e.g., Champion, NYC, Turlock, SRP, TDU Systems and
Industrial Customers.
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Commission Conclusion. We reaffirm the NOPR proposal that the RTO
must have ultimate responsibility for both transmission planning and
expansion within its region that will enable it to provide efficient,
reliable and non-discriminatory service and coordinate such efforts
with the appropriate state authorities. In carrying out this overall
responsibility, the Commission has concluded that the NOPR's three
separate requirements for RTO planning and expansion must also be
satisfied or, in the alternative, the RTO must demonstrate that an
alternative proposal is consistent with or superior to these three
requirements. Specifically, an RTO must satisfy the requirement to: (1)
Encourage market-motivated operating and investment actions for
preventing and relieving congestion; (2) accommodate efforts by state
regulatory commissions to create multi-state agreements to review and
approve new transmission facilities, coordinated with programs of
existing Regional Transmission Groups (RTGs) where necessary; and (3)
file a plan with the Commission with specified milestones that will
ensure that it meets the overall planning and expansion requirement no
later than three years after initial operation, if the RTO is unable to
satisfy this requirement when it commences operation.
As noted above, the RTO should have ultimate responsibility for
both transmission planning and expansion within its region. The
rationale for this requirement is that a single entity must coordinate
these actions to ensure a least cost outcome that maintains or improves
existing reliability levels. In the absence of a single entity
performing these functions, there is a danger that separate
transmission investments will work at cross-purposes and possibly even
hurt reliability. We also recognize that the RTO's implementation of
this general standard requires addressing many specific design
questions, including who decides which projects should be built and how
the costs and benefits of the project should be allocated.\592\ As with
other requirements of the Final Rule, we propose to give RTOs
considerable flexibility in designing a planning and expansion process
that works best for its region. It is both inevitable and desirable
that the specific features of this process ``should take account of and
accommodate existing institutions and physical characteristics of the
region.'' \593\ We emphasize that, as the transmission provider in the
region, the RTO is required to provide service under a tariff that is
consistent with or superior to the Commission's pro forma tariff, and
that tariff obligates the transmission provider to expand and modify
its system to provide the services requested under the pro forma
tariff.\594\ Because an RTO may not own all of the facilities it
operates, we clarify that nothing in this Rule relieves any public
utility of its existing obligation under the pro forma transmission
tariff to expand or upgrade its transmission system upon request.
Accordingly, we shall evaluate each RTO proposal to ensure that the RTO
can direct or arrange for the construction of expansion projects that
are needed to ensure reliable transmission services.\595\ However, the
Commission reiterates, as discussed below, its strong preference for
market-motivated operating and investment actions.
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\592\ FERC Stats. and Regs. para. 32,541 at 33,751-52.
\593\ Id. at 33,752.
\594\ See, e.g., Section 15.4 of the pro forma tariff which
requires the transmission provider to use due diligence to expand or
modify its transmission system to provide requested services. Also,
Section 28.2 of the pro forma tariff requires the transmission
provider to plan, construct, operate and maintain its transmission
system in order to provide network service, and to endeavor to
construct and place into service sufficient transmission capacity to
deliver network resources to network customers on a basis comparable
to its own use of the transmission system.
\595\ We note that existing ISOs have addressed similar issues
successfully. For example, the PJM ISO is responsible for expansion
planning, but the transmission owners remain obligated to undertake
upgrades necessitated by the plan, 81 FERC para. 61,257 at 62,275
(1997).
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We further note that the pricing mechanisms and actions used by the
RTO as part of its transmission planning and expansion program should
be compatible with the pricing signals for shorter-term solutions to
transmission constraints (i.e., congestion management) so that market
participants can choose the least-cost response. Otherwise, their
choices may reflect less efficient outcomes for the marketplace. For
example, if the price of expansion overstates its cost (or the price of
congestion management understates actual congestion cost), market
participants likely will continue congestion management solutions to a
transmission constraint when
[[Page 910]]
expanding the system to relieve congestion is more efficient.
Market-Motivated Actions. Planning new generation or new
transmission requires a coordinated approach to ensure reliability and
efficient congestion management. However, this does not necessarily
imply that all transmission expansions must be centrally planned by the
RTO. Where feasible, an RTO should encourage market approaches to
relieving congestion. A market approach will require providing all
transmission customers with access to well-defined transmission rights
and efficient price signals that show the consequences of their
transmission usage decision. If the RTO's market approach is
successful, the decisions of where, when and how to relieve congestion
will be driven by economic considerations.
Most commenters agree with the NOPR proposal that RTOs should rely
upon market signals and market solutions in assessing all feasible
options (e.g., construction of new generation, redispatch of existing
generation, as well as expansion of the transmission grid) to assure
that the least costly option is pursued. If an RTO can facilitate
market-motivated decisions, several commenters point out that its
planning role may largely be limited to extreme circumstances where
continuing congestion in an area threatens reliability. However, we
also recognize that different market approaches to relieving congestion
are still in the early stages of development. Similarly, while market
approaches to expansion are the subject of much discussion, they are
also in the early stages of development.\596\ It is not the intent of
the Commission either to mandate a market approach to the exclusion of
an executive decision by the RTO or to mandate any particular market
approach.
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\596\ For example, TDU Systems and other commenters suggest
that, by promoting competition for new construction, the RTO can
minimize construction cost and also reduce its own risk profile. For
example, an ISO in Victoria, Australia (VPX), which operates, but
does not own transmission assets, uses competitive bidding for new
transmission facilities. At the Regional ISO Conference in Richmond,
Virginia on June 8, 1998, Raymond Coxe described how VPX's strategy
resulted in a number of bidders competing for the right to build,
own and operate new facilities. He concluded that the ``result of
this competition was a lower price to the consumers of Victoria than
would have resulted from regulated transmission service by the
largest incumbent provider.'' Transcript at 86, Docket PL98-5-006.
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Nevertheless, if any market-driven approach is to be successful,
there must be accurate price signals that reflect the costs of
congestion and expansion costs. As we stated in the NOPR, accurate
price signals are the link between current usage and future expansion.
Therefore, as discussed in more detail in Section III.E.2 Congestion
Management, every RTO must establish a system of congestion management
that establishes clear rights to transmission facilities and provides
market participants with price signals that reflect congestion and
expansion costs. In implementing its planning and expansion
responsibility, an RTO must ensure that its decisions are not unduly
discriminatory and produce efficient outcomes.
The Commission reaffirms its statement in the NOPR that independent
governance of the RTO is a necessary condition for nondiscriminatory
and efficient planning and expansion. While accurate price signals can
signal the need for expansion, such expansion may not be achieved if an
RTO operates under a faulty governance system (e.g., a governance
system that allows market participants to block expansions that will
harm their commercial interests).
Multi-State Agreements and RTGs. The final rule fully recognizes
the statutory authority of the states to regulate siting of
transmission facilities. Currently, state and local governments and
regulatory agencies have exclusive authority over the siting process.
Therefore, an RTO's planning and expansion process must be designed to
be consistent with these state and local responsibilities.
RTOs must accommodate efforts by state regulatory commissions to
create multi-state agreements to review and approve new transmission
facilities. The Commission encourages the development of multi-state
agreements or compacts to review and approve new transmission
facilities. This would expedite transmission construction and eliminate
duplicative (and possibly conflicting) reviews by multiple states. To
facilitate any voluntary actions taken by our state colleagues, we will
require that the RTO planning and coordination system must be able to
accommodate the possible emergence of new regional regulatory systems.
Existing RTGs have clear and prominent roles in transmission
expansion decisions in which planning for transmission improvements are
coordinated through collaborative processes. To avoid duplicative
efforts, the RTO process must build on existing RTG planning processes.
Over time, since the RTO will have ultimate responsibility for planning
the entire transmission system within its region, we expect that the
functions of an RTG will be assumed by an RTO to avoid unnecessary
duplication of effort.
Three-Year Implementation. If the RTO is unable to satisfy the
planning and expansion function when it commences operation, it must
file a plan with the Commission with specified milestones that will
ensure that it meets this requirement no later than three years after
initial operation. Recognizing that the planning and expansion function
may require coordination among multiple parties and regulatory
jurisdictions, we do not require this function to be in place at the
initial operation of the RTO. We continue to believe that three years
is a reasonable deadline for creating an operational planning and
expansion system. Therefore, we will not extend this deadline or the
requirement to file a plan with the Commission with an implementation
timetable. This time period could be affected by the RTO's scope, the
number of states and market participants, and implementation costs;
however, the urgent needs of the electricity markets make us
disinclined to extend these deadlines.
However, the delay should not stall the construction of new or
enhanced facilities for which needs have been established, unless the
RTO makes a positive decision that the facility is not in the best
interests of the region. Delaying transmission expansion could result
in significant market inefficiencies as well as unacceptable risks to
reliability given the long regulatory and construction lead times
required to build new facilities.
8. Interregional Coordination (Function 8)
In Order No. 888, the Commission identified eleven principles it
would use to assess Independent System Operator (ISO) proposals
submitted to the Commission.\597\ One of these principles required that
the ISO develop mechanisms to coordinate with neighboring control areas
to ensure reliability and the provision of transmission services that
cross system boundaries. The RTO NOPR encouraged transmission entities
to consider ways to reduce impediments to transactions among
themselves,\598\ but a coordination requirement was not included
explicitly in the RTO NOPR. Several commenters pointed out that there
was no explicit coordination requirement proposed in the RTO NOPR and
recommended including a function for RTOs similar to the coordination
principle in Order No. 888.
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\597\ Order No. 888, FERC Stats. and Regs. para. 31,036 at
31,730-32.
\598\ FERC Stats. and Regs. para. 32,541 at 33,758.
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[[Page 911]]
Comments. Several commenters identify coordination with other
regions as a necessary element that should be added more explicitly to
the RTO functions.\599\ These commenters express this need as either
required to ensure reliability or necessary for bulk power markets to
operate over sufficiently large areas. For example, NERC states that
the need for such coordination effort has increased as the management
of short-term reliability of the interconnected bulk power system and
the operation of increasingly competitive bulk power markets have
become inseparable. Accordingly, NERC recommends that an additional
function be added to the final rule that requires RTOs to integrate
their market interface practices and reliability practices. It
identifies OASIS standards, information sharing with neighboring RTOs,
ancillary services requirements, parallel path flows, transmission
loading relief, and interregional congestion management, as practices
and standards that need to be integrated.
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\599\ Many parties supported this requirement including NERC,
Justice Department, NARUC, NASUCA, Oneok, PJM, Duquesne and
Industrial Consumers.
---------------------------------------------------------------------------
Duquesne states that efficiencies can be realized from coordinating
and developing a seamless marketplace. It recommends that the
Commission require RTOs to coordinate and plan for seamless and uniform
transmission rules, scheduling systems and procedures, and reliability
standards. In addition, Oneok suggests that the Commission encourage
neighboring RTOs to form reliability compacts under which loop flow and
other issues involving interregional reliability impacts can be
resolved.\600\ Also, Wyoming Commission believes that the Commission
should be flexible with respect to inter-RTO interaction and that it
may be appropriate to address these issues later rather than in initial
RTO filings.
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\600\ ISO-NE, NY ISO and PJM recently signed a memorandum of
understanding concerning interregional coordination activities.
---------------------------------------------------------------------------
Commission Conclusion. Coordination of activities among regions is
a significant element in maintaining a reliable bulk transmission
system and for the development of competitive markets. In the NOPR, we
discussed several region-to-region coordination activities in
connection with the parallel path, congestion management, and expansion
planning functions. However, the comments persuade us to add a more
general interregional coordination requirement as one of the minimum
RTO functions.
We will require an RTO to develop mechanisms to coordinate its
activities with other regions whether or not an RTO yet exists in these
other regions.\601\ If it is not possible to set forth the coordination
mechanisms at the time an RTO application is filed, the RTO applicant
must propose reporting requirements, including a schedule, for itself
to provide follow-up details as to how it is meeting the coordination
requirements of this function. We expect the RTO to work closely with
other regions to address interregional problems and problems at the
``seams'' between the RTOs. Therefore, as recommended by NERC and
others, we will add the following regulatory text to our RTO Final Rule
functions:
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\601\ This is similar to the existing ISO Principle #10 in Order
No. 888 for single control area ISOs: ``An ISO should develop
mechanisms to coordinate with neighboring control areas.''
(8) Interregional Coordination: The Regional Transmission
Organization must ensure the integration of reliability practices
within an interconnection and market interface practices among
---------------------------------------------------------------------------
regions.
An RTO proposal must explain how the RTO will ensure the
integration of reliability and market interface practices. An RTO may
ensure the integration of these practices either by developing
integration practices itself or by cooperating in the development of
integrated practices with an independent entity that covers all regions
or, for reliability practices, covers an entire interconnection. The
term, interconnection,\602\ refers here to any one of three large U.S.
transmission systems. The Eastern Interconnection covers most of the
area east of the Rocky Mountains in the United States and Canada. The
Western Interconnection covers an area that is mostly west of the Rocky
Mountains in the United States and Canada, as well as a small portion
of Mexico. The Electric Reliability Council of Texas (ERCOT)
Interconnection covers much of Texas.
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\602\ ``Interconnection'' is a term used by the North American
Electric Reliability Council and others to refer to an
interconnected alternating current transmission system. Engineering
considerations require all generators connected to any one
interconnection to operate in a coordinated manner, that is,
synchronously.
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This provision does not mean that all RTOs necessarily must have a
uniform practice, but that RTO reliability and market interface
practices must be compatible with each other, especially at the
``seams.'' RTOs must coordinate their practices with neighboring
regions to ensure that market activity is not limited because of
different regional practices.
We understand, as NERC pointed out in its comments, that the
reliability and market interface practices are becoming highly
interrelated. The reliability practices affect how markets interface
with each other, and the market interface practices affect reliability.
For example, TLR and congestion management are both used to unload an
overloaded transmission interface, and these two practices must work
together. We consider congestion management and TLR are best used as
sequential steps to unload a line, with congestion management used
first to unload a line in a market-oriented manner, and TLR used to
unload a line in a fair manner when either congestion management is
unavailable or an emergency condition requires immediate action. We
therefore list below TLR as a reliability practice and congestion
management as a market interface practice, understanding that these and
other practices listed affect both reliability and markets.
The integration of reliability practices involves procedures for
coordination of reliability practices and sharing of reliability data
among regions in an interconnection, including procedures that address
parallel path flows, ancillary service standards, transmission loading
relief procedures, among other reliability-related coordination
requirements in this Final Rule.
The integration of market interface practices involves developing
some level of standardization of inter-regional market standards and
practices, including the coordination and sharing of data necessary for
calculation of TTC and ATC, transmission reservation practices,
scheduling practices, and congestion management procedures, as well as
other market coordination requirements covered elsewhere in this Final
Rule.
F. Open Architecture
In the NOPR, the Commission stated its commitment to a policy of
``open architecture'' and proposed to require that RTOs be designed so
that they can evolve over time. The Commission noted that there should
be no provision in any RTO proposal that precludes the RTO and its
members from improving their organization to meet market needs.\603\
The Commission sought comments regarding the open architecture policy
in general and the flexibility needs of RTOs in particular.
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\603\ FERC Stats. and Regs. para. 32,541 at 33,753.
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Comments. Virtually all commenters support the NOPR's open
architecture concept and recommend that an RTO have the ability to
evolve over time as
[[Page 912]]
it gains operating experience.\604\ They endorse the principle of
flexibility to accommodate the changing needs of the market.\605\ WEPCO
notes that open architecture should permit flexibility and urges the
Commission not to require an RTO to be the only control area operator
in the region.\606\ Ontario Power states that the open architecture
policy should enable RTOs to accommodate Canadian entities in the
future. Oglethorpe observes that open architecture policy would allow
RTOs to utilize existing infrastructure and avoid high transition
costs.
---------------------------------------------------------------------------
\604\ See, e.g., APX, Arizona Commission, Cal ISO, Central
Maine, Consumers Energy, CP&L, Conectiv, Desert STAR, DOE, Duke,
Entergy, EPSA, FirstEnergy, Florida Commission, Georgia
Transmission, Illinois Commission, Industrial Consumers, LG&E, NERC,
NPCC, NSP, NU, NY ISO, Oglethorpe, PJM, Seattle, Southern Company,
SMUD, SRP, TDU Systems, TEP, Tri-State and WEPCO.
\605\ NSP states that the configuration of electric markets will
be much different five or ten years from now.
\606\ WEPCO notes that costs savings associated with creating
large, efficient electricity markets will dwarf the savings attained
by reducing the number of operators through control area
consolidation.
---------------------------------------------------------------------------
However, Central Maine and Southern Company argue that the
flexibility implied by open architecture should not be used carte
blanche. For example, there should be limits to an RTO's evolution
process because transmission owners have some fundamental rights, such
as: (1) The right to terminate their participation in the RTO; (2) the
right to switch to another RTO; (3) the right to merge RTOs; (4) the
right to recover their costs and a return on investment; and (5) the
right to protect their assets and employees from damages and injuries.
LG&E states that the flexibility inherent in the open architecture
concept should be applied fairly to all market participants, including
those transmission owners that have already committed to existing or
proposed ISOs. For example, a member of an existing ISO should be
allowed to move to another RTO.
Industrial Consumers perceives a potential downside to the open
architecture policy in that it may give existing IOUs a license to
continue their opportunistic behavior rather than facilitating true
market transformation. Therefore, Industrial Consumers argues that it
supports the notion of flexibility inherent in the open architecture
policy only in the absence of market power. Illinois Commission argues
that the pace of evolutionary improvement of RTOs should not remain in
the hands of vertically integrated utilities because their interest in
structural change may not be consistent with the public interest.
Cinergy, EPSA and Georgia Transmission state that the flexibility
implied by open architecture should not be used to support deviations
from minimum characteristics and functions. However, CP&L believes that
the proposed minimum characteristics and functions are too stringent
and do not allow for much flexibility that a changing market
needs.\607\ Georgia Transmission supports the Commission's commitment
to providing regulatory flexibility to allow RTOs to evolve.
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\607\ CP&L and Southern Company state that the Commission should
establish basic RTO guidelines through a policy statement rather
than by a rule. They contend that the rules under the NOPR are too
prescriptive, and will stifle the development of new RTOs.
---------------------------------------------------------------------------
Many commenters state that the open architecture concept is so
broad that it will prevent stakeholders from developing meaningful RTO
proposals. To bring some certainty to the negotiating parties to an RTO
proposal, CP&L recommends that the Commission find that some necessary
and reasonable limitations on modifications to RTOs are permissible,
and these can be overridden only by unanimous consent or a
supermajority vote.\608\ MidAmerican states that the Commission should
accept RTO proposals that contain stated limitations, such as a
transmission owner's right to withdraw from an RTO. MidAmerican argues
that such limitations are consistent with the Commission's open
architecture policy and would prevent transmission owners from being
discouraged to join RTOs. To promote certainty, Entergy notes that the
Commission should establish a general policy of grandfathering
previously approved RTOs and not altering their requirements except in
extraordinary circumstances.\609\
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\608\ CP&L notes that participants in Midwest ISO identified
certain conditions that could be altered only by the transmission
owners, including revenue distribution, pricing methodology and
withdrawal rights.
\609\ Entergy at 42.
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Southern Company is concerned that RTOs could evolve in ways that
are undesirable to the participants that initiated its formation.
Therefore, it argues that the parties should have some assurance that
certain key provisions of an RTO would not change in the name of RTO
evolution. For example, functions, boundaries, transmission rate
design, and allocation of transmission revenues should not be amended
by the RTO except by vote of the transmission owners, at least for the
duration of a specified transition period. Southern Company contends
that the transmission owners will then know what they are ``getting
into'' when they join an RTO.
Many commenters recommend that the Commission should not mandate
the ultimate organizational form of the RTO given the electric
industry's current state of structural flux and the uncertainty of the
future. These commenters argue that the Commission's open architecture
policy should encourage market participants to develop transmission
institutions that are effective in meeting the needs of the
marketplace. FirstEnergy and NU state that there is a range of
organizational and functional forms--power pool (tight and loose):
gridco, transco, marketco--which can accomplish the Commission's goal
of improving the efficiency of the transmission grid, and only time and
market forces should determine which form is best suited for a specific
region of the country. Southern Company believes that there should be
no requirement that would prohibit an RTO with no transmission
ownership to transform into one that owns transmission (i.e., change
from an ISO to a transco).
PJM urges the Commission to clarify that RTOs can propose
improvements to the RTO independently of its members to meet changing
market needs. PSE&G is opposed to giving such authority to RTOs because
it believes that the market participants rather than RTOs should drive
changes in the structure and operation of electric markets.\610\ Cal
ISO recommends that the Commission's open architecture policy should
support the creation of a structure that facilitates the addition of
new participants, both within and outside of the existing RTO
boundaries. Illinois Commission urges the Commission to modify the
proposed paragraph 35.34(k) of proposed regulations to include an
affirmative expectation that RTOs will change to meet new competitive
market needs and to improve over time.
---------------------------------------------------------------------------
\610\ PSE&G Reply Comments at 6-7.
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Commission Conclusion. As proposed in the NOPR, we adopt the
principle of open architecture in order that the RTO and its members
have the flexibility to improve their organizations in the future in
terms of structure, geographic scope, market support and operations to
meet market needs. We will require that the RTO design have the ability
to evolve over time. In addition, we will provide flexibility to allow
RTOs to propose changes to their enabling agreements to meet changing
market, organization and policy needs.
[[Page 913]]
Open architecture will permit RTOs to evolve in several ways, as
long as proposed changes continue to satisfy RTO minimum
characteristics and functions. As a first example, open architecture
will allow basic changes in the organizational form of the RTO to
reflect changes in facility ownership and revised corporate strategies.
As noted by Southern Company, an RTO that initially does not own any
transmission facilities might acquire ownership of some or all of those
facilities. With an open architecture design, the RTO's enabling
agreements should anticipate and facilitate changes of this nature.
Second, open architecture design accommodates change in the
geographical scope of RTOs. Electric markets are evolving quickly and
future market trading patterns cannot be foreseen at the time of RTO
organization. An open architecture design will enable an RTO to grow
geographically and possibly merge with another RTO as changes in
markets suggest a realignment of organizations to meet evolving market
needs.
Third, market support is another area that benefits from open
architecture design. For example, an RTO may not initially operate a PX
to support a regional spot market, but later determine that the
establishment of a PX would provide additional benefit in its region.
With open architecture, the RTO can propose to add a PX function (or a
PX monitoring function) to its design. Open architecture design ensures
that such future developments that are beneficial to the marketplace
are not foreclosed.
Fourth, open architecture design accommodates changing operational
needs. Most commenters agree that, as RTOs gain operating experience,
some changes will become necessary. Cal ISO acknowledges that it had to
make significant changes to its tariff and operational practices as it
gained operating experience, and it believes further modifications are
likely to be identified as additional experience is gained regarding
evolving competitive markets.
Finally, as noted in the NOPR, technological change make changes in
RTO design inevitable and desirable. Accommodating that change will
require flexibility and adaptability in the RTO organization; open
architecture will permit design modification to keep pace with
technology.
Some commenters argue that the flexibility implied by open
architecture design should not be interpreted to mean unfettered
ability on the part of the RTO to modify its structure or processes. We
agree. Although under our open architecture policy the RTO will have
the ability to propose whatever changes it believes are appropriate to
meet the evolving needs of the RTO and the region, any such proposals
or changes to existing agreements, which will be changes to the RTO's
jurisdictional rate schedule(s) and contracts, will be subject to
Commission review and approval under the FPA. The Commission will
consider the merits of any changes to an approved RTO on a case-by-case
basis. Interested parties will have the opportunity to comment on any
such proposal. This process will enable all parties and the Commission
to guard against proposed changes that are likely to stifle
competition.
G. Transmission Ratemaking Policy for RTOs
We have concluded that the success of the Commission's efforts to
have effective and efficient RTOs is dependent in large measure on the
feasibility and vitality of the stand-alone transmission business. For
that reason, and to promote economic efficiency, the RTO transmission
ratemaking policies of the Commission are an important factor of RTO
success. In light of the restructuring of markets and market
institutions that is taking place, we now believe that it will be
helpful to inform the industry about what we consider to be appropriate
and inappropriate transmission pricing practices for RTOs, and about a
framework for RTOs to propose efficient and fair pricing reform.
Accordingly, we provide guidance below on a number of fundamental
ratemaking issues.
We believe that it is critically important for RTOs to develop
ratemaking practices that: eliminate regional rate pancaking; manage
congestion; internalize parallel path flows; deal effectively and
fairly with transmission owning utilities that choose not to
participate in RTOs; and provide incentives for transmission owning
utilities to efficiently operate and invest in their systems. In
particular, the Commission encourages RTOs to develop and propose
innovative ratemaking practices, particularly with respect to
efficiency incentives. We therefore devote a significant portion of the
discussion in this section of the Final Rule to performance-based
regulation (PBR) and other RTO transmission ratemaking reforms.
In addition to the guidance offered here, we have added regulatory
text (section 35.34(e)) with regard to PBR and other RTO transmission
ratemaking reforms,\611\ which now identifies a select list of
innovative transmission rate treatments. The Commission will consider
such innovative rate treatments for entities that file proposals under
the new section 35.34 and that meet the minimum characteristics and
functions required in the Final Rule. The Applicant must explain how
the proposed rate treatment would help achieve the goals of RTOs,
including efficient use of and investment in the transmission system
and reliability benefits to consumers; provide a cost-benefit analysis,
including rate impacts; and explain why the proposed rate treatment is
appropriate for the RTO proposed by the Applicant. This means that
filings under section 35.34(e) must be complete and fully explained;
must demonstrate that the resulting rates are just, reasonable, and not
unduly discriminatory or preferential; must identify how the rate
treatment promotes efficiency and what benefits result; and must
demonstrate that the rate treatment does not impede the RTO from
meeting the minimum characteristics and functions required under this
Final Rule. The Commission encourages properly developed transmission
pricing proposals from RTOs that comply with the guidance set forth
below and the amended regulatory text.
---------------------------------------------------------------------------
\611\ We have adopted and expanded the regulatory text proposed
by Edison Electric Institute in its comments (see EEI, Appendix E).
---------------------------------------------------------------------------
We agree with those commenters that urge the Commission to reform
its transmission pricing policies to reflect new realities of the
industry. For example, a number of commenters point to the unbundling
requirements of Order Nos. 888 and 889, the vertical de-integration of
generation and transmission for some utilities, the advent of wholesale
and retail competition in energy markets, entry into markets of a range
of new players, including independent generators and marketers, and
other developments as a signal that the Commission's traditional cost-
of-service ratemaking practices for transmission assets should be
reevaluated. Some commenters suggest that the advent of competitive
power markets necessitates a more robust transmission network as well
as enhanced operating capabilities of the network, compared to the
previous era of vertically integrated utilities providing service in
monopoly franchise areas. They argue that the Commission's traditional
transmission ratemaking practices are unlikely to support such a robust
transmission network and enhanced operating capabilities.
[[Page 914]]
To put our concerns about transmission pricing in perspective, the
NOPR said that ``the Commission expects RTOs to reform transmission
pricing, and in return we propose to allow RTOs greater flexibility in
designing pricing proposals.'' \612\ The NOPR also said that our
willingness to provide flexibility in reviewing pricing proposals dates
back to the Transmission Pricing Policy Statement, issued by the
Commission in 1994. In the Policy Statement, we identified five
principles that transmission pricing proposals should conform to,
including the principle that pricing proposals should meet the
traditional revenue requirement. In order that this principle not
undermine innovative pricing proposals, the Policy Statement noted that
non-conforming pricing proposals would be considered, but that such
proposals would have to satisfy additional factors, i.e., promote
competitive markets and produce greater overall consumer benefits. In
the five years since the Policy Statement was issued, we have approved
five ISOs with innovative transmission pricing, but otherwise have
received few innovative transmission pricing proposals. We believe
that, as a general matter, sensible pricing reform that could promote
competition and efficiency in other contexts will achieve maximum
benefits only when applied on a regional, rather than a single-system
basis. This is true because of the inability of single systems to
capture such efficiencies, but sensible pricing reform is one of the
efficiencies that will likely flow from RTOs. And while we do not think
the Policy Statement has been an impediment to transmission pricing
innovation, we now believe, based on the myriad comments we received,
that the Commission should now provide greater specificity on
appropriate transmission pricing reforms by RTOs.
---------------------------------------------------------------------------
\612\ FERC Stats. & Regs. para. 32,541 at 33,754.
---------------------------------------------------------------------------
The rationale for providing greater specificity on transmission
pricing for RTOs and amending the regulatory text at this time is
three-fold. First, we recognize that transmission pricing issues are
some of the most complex issues facing the industry. Second, a
potential barrier to the development of RTOs, at least RTOs that span
multiple transmission systems, is the difficulty that stakeholders have
had reaching consensus on transmission pricing. This is not surprising,
given that transmission pricing reform to accommodate regional needs
and usage patterns can affect what customers pay for transmission
service and how transmission revenues are allocated among multiple
owners of transmission within a region. Third, we are concerned that as
we move to greater reliance on market forces, the incentives that
market participants have to make efficient operating and investment
decisions for both generation and transmission facilities are based in
part on the price signals that flow from transmission pricing. That is,
transmission pricing is a key determinant of the efficient operation of
energy, ancillary service and balancing markets, and congestion
management.
At the outset, we want to make clear that, contrary to the
apprehensions of some commenters, the Commission is not proposing to
``bribe'' transmission-owning utilities to join an RTO. Rather, the
Commission stated in the NOPR that it would consider innovative pricing
proposals because we believed then, and now believe more strongly, that
a reassessment of transmission pricing policy is warranted, given the
fundamental changes in industry structure that have already occurred as
well as those which may flow from the RTO Final Rule. In addition, as
pointed out by Professor Joskow, delays in RTO formation occasion costs
because of more limited competition in generation markets, and these
costs may be avoided to the extent that the Commission considers
transmission pricing reforms. Furthermore, as discussed below, since
the costs of transmission are a small portion of total electric costs,
getting transmission pricing right means that the industry will be able
to capture significant net benefits from promoting competitive
generation markets.
While the NOPR did not propose specific rules on transmission
pricing reform, we believe it is now critical to provide further
specificity to the industry. We recognize the need to establish clear
and specific requirements for RTO development, provide certainty and
clarity about our willingness to entertain transmission pricing reforms
that are appropriate for RTOs, and assure utilities that they will not
be penalized for RTO participation. To the extent consistent with
ensuring that transmission rates are just, reasonable, and not unduly
discriminatory, we believe transmission pricing disincentives to
joining an RTO should be eliminated so that transmission-owning
utilities will find RTO participation to be a dynamic business
opportunity. Utilities that join RTOs should be accorded transmission
pricing that reflects the financial risks of turning facilities over to
an RTO and that reflects other changes in the structure of the
industry. Those risks may increase or decrease in particular instances.
At the same time, we wish to make clear that the Commission is very
concerned about potential impacts of market restructuring on the
customers in ``low-cost'' states, and the Commission therefore intends
to monitor the effects of RTO formation on such customers, specifically
the potential for cost-shifting effects of RTO pricing proposals.
Traditional transmission pricing approaches reflect the industry
structure as it existed when Order No. 888 was issued: a vertically
integrated industry where transmission systems were designed primarily
to meet the needs of local loads. Our primary focus, both in terms of
access and pricing was comparability; that is, all transmission users
should receive access under rates, terms and conditions comparable to
those the transmitting utility applies to itself to serve its own
customers. RTOs reflect a somewhat different approach, in which the
transmission system must also be designed and operated to meet the
needs of regional markets. It is not unreasonable to expect that, as
the transmission system is restructured to meet these changing needs,
significant pricing reform may be needed as well. Indeed, since a
properly developed RTO will be designing methods to support regional
congestion management and regional expansion, transmission pricing
reform is inevitable.
We caution that we do not view transmission pricing reform as a
program designed for the sole purpose of enhancing the revenues of
transmission owners at the expense of transmission customers. Nor are
we abandoning the fundamental underpinnings of our traditional
transmission pricing policies, i.e., that transmission prices must
reflect the costs of providing the service.\613\ While many aspects of
transmission pricing reform are labeled incentive pricing, many are
aimed at eliminating disincentives to the efficient use and expansion
of regional transmission grids to support emerging competition in
generating markets.
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\613\ See, e.g., Federal Power Commission v. Hope Natural Gas
Co., 320 U.S. 591 (1944); Bluefield Water Works & Improvement Co. v.
Public Service Commission of West Virginia, 262 U.S. 679 (1923).
---------------------------------------------------------------------------
We view transmission pricing reform, not only as an important
component of how stand-alone transmission companies can become viable
and efficient network businesses, but also as an important means for
transmission-owning utilities which maintain ownership but cede control
of their transmission assets to an RTO to capture
[[Page 915]]
the benefits of more efficient system operation and additional grid
investment. We believe that the opportunities for pricing reform
identified in this Rule should have no effect on an RTO's decision
about how it will be structured. All RTOs, regardless of ownership
structure, are therefore eligible to propose transmission pricing
reforms that suit their strategic and economic objectives to the extent
consistent with this Final Rule.
We also believe that the potential for any increase in
transmission-related revenues available to transmission providers that
are efficient and responsive in meeting the needs of their customers
must be balanced by the potential for a decrease in profits if the
transmission provider does not meet those needs. Moreover, a properly
developed RTO can be expected to produce significant efficiencies, and
we would expect that transmission owners, transmission customers and
generation market participants will share in the economic benefits
resulting from the efficient design and operation of the RTO.
As the industry begins the collaborative process of establishing
RTOs, it is important that the Commission provide some certainty and
specificity about the preferred types of transmission pricing reforms,
and some certainty and specificity about the types of proposed
transmission pricing reforms that appear more problematic. Accordingly,
the remainder of this section discusses eight specific transmission
ratemaking topics: pancaked rates; reciprocal waiving of access charges
between RTOs; use of single system access charges; congestion pricing;
service to transmission-owning utilities that do not participate in an
RTO; performance-based regulation; other RTO transmission ratemaking
reforms; and additional ratemaking issues.
1. Pancaked Rates
As described in the NOPR, the elimination of rate pancaking for
large regions is a central goal of the Commission's RTO policy, and has
been a feature of all five ISOs the Commission had approved. Rate
pancaking occurs when a transmission customer is charged separate
access charges for each utility service territory the customer's
contract path crosses. The NOPR proposed that RTO tariffs not result in
transmission customers paying multiple access charges to recover
capital costs over facilities that it controls. The NOPR sought
comments on the impact of the non-pancaked rate requirement on
voluntary RTO formation because of abrupt rate changes. It also sought
comments on how the regional configuration may relate to these
potential rate changes.
Comments. The overwhelming majority of the comments favor the
proposed prohibition on pancaked rates,\614\ although some commenters
express concern over cost shifting. Some commenters, such as Minnesota
Power, suggest that the cost shifting effect of non-pancaked rates
would discourage voluntary RTO formation.
---------------------------------------------------------------------------
\614\ See, e.g., NASUCA, PJM, LG&E, Industrial Consumers and
WEPCO.
---------------------------------------------------------------------------
Some commenters suggest alternative approaches to the strict non-
pancaked rate described in the NOPR. For example, WPSC advocates the
use of flow-based, distance-sensitive rates as a replacement for
pancaked rates. Allegheny argues that removing rate pancaking can cause
disruptive shifts in rates and revenue requirements which are solved
only temporarily with transitional rates. Allegheny proposes its form
of locational marginal pricing method to solve this problem. NSP favors
non-pancaked rates but notes that rates for the high-voltage system
that differ from those for the low-voltage system may be an effective
long-term rate strategy. MidAmerican recommends that the prohibition
against rate pancaking be changed to allow transmission owners to
charge a home-zone rate based on local cost determination and a wide-
area charge outside the home area. MidAmerican argues that this
approach would minimize cost shifting. The pancaked rate prohibition
would change to: ``promote wide-area transmission rates with due
consideration to shifting of costs among transmission service providers
and between state and federal delivery rates. Finally, Williams
recommends that the Commission also consider other pricing methods such
as those based on mileage or network usage and market-based rates,
where possible, because it considers cost of service rates inefficient
and unresponsive to the market.
A few commenters question an absolute prohibition against pancaked
rates. AEP and Florida Power Corp. warn that a strict prohibition
against pancaked rates may, at times, work against efficient solutions.
There should not be a strict prohibition without regard to size or
locational factors. Florida Power Corp. argues that this approach is
consistent with the Commission's Transmission Pricing Policy Statement.
Customers of both AEP and Florida Power Corp. dispute this view.\615\
Southern Company notes that an absolute prohibition against pancaked
rates may hurt retail customers whose rates are supported by
transmission revenue. Transmission owners should be assured in the
final rule that they will be able to recover their full revenue
requirement in the face of any pancaked rate prohibition. The
Commission should, according to Southern Company, also clarify that a
prohibition against pancaked rates does not prevent the use of zonal or
other distance-sensitive rates. Desert STAR argues that a single
region-wide rate may not be appropriate in a large region with
legitimate cost differences among companies, and suggests that license
plate rates may mitigate cost shifting but will not always eliminate
it.
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\615\ See New Smyrna Beach and Coalition of Alliance Users.
---------------------------------------------------------------------------
Commission Conclusion. In the NOPR, we described the elimination of
rate pancaking as a central goal of our RTO policy. After receiving
comments on the subject, mostly in favor of the proposed prohibition,
we affirm that the RTO tariff must not result in transmission customers
paying multiple access charges to recover capital costs.\616\
---------------------------------------------------------------------------
\616\ Section 35.34(k)(1)(ii). However, see the discussion below
regarding service to transmission-owning utilities that do not
participate in an RTO.
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Except for transactions within the ISOs now in place, transmission
customers are faced with additional access charges for every utility
border they cross. The distances need not be great to be assessed two,
three or more access charges for a single transaction. This duplication
can severely restrict the area in which generation can economically be
secured. A main reason that an RTO can expand the marketplace for
generation to a large region is that an RTO can implement non-pancaked
rates for each transaction. A wider area served by a single rate means
more generation is economically available to any customer which means
greater competition for energy.
Some commenters warn that a blind adherence to non-pancaked rates
can produce inefficiencies in some circumstances. Some argue that large
distances and special conditions can add to transmission costs in a way
not reflected in single system rates. They would leave open the option
for distance-sensitive rates or completely new rate innovations that
may not fit the strict definition of a non-pancaked rate. We are
sensitive to some of these concerns, but we do not view a policy
requiring non-pancaked rates as posing the problems that some
commenters
[[Page 916]]
describe. We take this opportunity to reaffirm that we will continue to
be receptive to distance-sensitive rates and other rate features that
can be supported.
2. Reciprocal Waiving of Access Charges Between RTOs
The elimination of pancaked rates within an RTO was intended to
increase the efficiency of trade in that region. The NOPR furthered
that concept by encouraging RTOs to agree among themselves to waive
access charges on a reciprocal basis for transactions that cross RTO
borders. If accomplished, this would have the effect of increasing
effective trading areas. The NOPR sought comments on how the Commission
could facilitate reciprocal waivers of access charges, and whether
there are other impediments to inter-regional trade.
Comments. A majority of the commenters support the concept of a
reciprocal waiver of access charges to encourage inter-regional
trade.\617\ Of those who support waivers, some, including Duke and SRP,
specifically recommend that waivers be voluntary. Some supporters of
waiving access charges note that it is not just the pancaked charges
that inhibit inter-regional trade but also variations in business
practices and procedures between RTOs. These commenters \618\ recommend
that the Commission ensure that such incompatibilities not be allowed
to hamper trade between RTO regions.
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\617\ See, e.g., Sithe, WPSC, Minnesota Power, Ohio Commission,
and Midwest ISO Participants.
\618\ See, e.g., Ontario Power and Oregon Office.
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Several commenters, both supporting and opposed to waiver of access
charges, warn that the waivers proposed in the NOPR can cause cost
shifting. Duke argues that cost shifting can be remedied by the
structure of the rate. DOE and First Energy also express concerns about
cost shifting. Southern Company generally opposes waivers of access
charges unless transmission owners' revenues are protected.
Some commenters oppose waiving access charges between RTOs for
reasons other than cost shifting concerns. South Carolina Authority
claims that reciprocal agreements between RTOs waiving access charges
are discriminatory and that independent monitoring groups would be
needed to prevent gaming of reciprocity agreements. CP&L argues that
waivers create a bias to sell outside of the RTO. Tri-State proposes
the use of distance-sensitive export pricing mechanisms instead of
waivers.
PP&L Companies claim that inter-regional trade solutions should be
arrived at through a collaborative effort of stakeholders. NECPUC and
Desert STAR argue that the Commission should grant deference to
participants' solutions for inter-regional trade. Florida Commission
argues that the Commission should wait until intra-regional trade
barriers are dismantled before dealing with inter-regional trade.
Commission Conclusion. We asked in the NOPR for comments on the
policy of allowing RTOs to reach reciprocal agreements to waive access
charges for transmission that crosses an RTO border. Most commenters
supported the approval of such waivers and some asked the Commission to
further support inter-regional trade by requiring uniform practices and
procedures among RTOs. Some commenters maintain that incompatible or
varying procedures between RTOs can be as dampening to inter-regional
trade as multiple rates.
We will continue to encourage reciprocal waivers of access charges
between RTOs as long as they are reasonable in terms of cost recovery,
cost shifting, efficiency, and discrimination. We also encourage terms
and procedures that are compatible from region to region to the extent
appropriate. Accordingly, we have added an RTO function to integrate
reliability and market interface practices with other regions, as
discussed above.
3. Uniform Access Charges
Each ISO approved by the Commission has struggled with the problem
of cost shifting among the various individual transmission owners that
make up the ISO. A single access rate would mean that the customers of
low-cost transmission providers would see a rate increase and high-cost
transmission providers would be concerned about not meeting their
revenue requirements. The potential for cost shifting has been a
stumbling block for several regions seeking to establish regional
transmission organizations.
The Commission has allowed a flexible approach to this problem, and
in each ISO approved by the Commission to date the solution has been to
adopt a ``license plate'' rate for a transitional period of five to ten
years before moving to a single uniform access charge. A license plate
rate provides access to the regional transmission system at a single
rate although that rate may vary based on where the customer is
located.\619\ The NOPR proposed to continue to employ a flexible
approach, including the use of license plate rates. The NOPR requested
comments on whether the license plate approach is appropriate for the
long term.\620\
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\619\ Consider that registering a car in one state, paying that
state's fees, and obtaining a license plate from that state, allows
that car to be driven on the roads and highways of all other states.
\620\ FERC Stats. & Regs. para. 32,541 at 33,754.
---------------------------------------------------------------------------
Comments. A clear majority of commenters favors the use of license
plate rates in general, with a nearly even split between those that
would allow license plate rates only for a transitional period \621\
and those that would allow them as a permanent feature.\622\ Of the
approximately 64 commenters who addressed this subject, only about nine
were clearly opposed to license plate rates for either the long term or
for a transitional period. And several commenters advocate the use of
license plate rates as a general concept but did not address directly
the NOPR's question concerning their long-term use.\623\
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\621\ See, e.g., Montana Commission, Oglethorpe, Tri-State,
FirstEnergy, Alliance Companies, AEP and DOE.
\622\ See, e.g., Allegheny, Industrial Consumers, Northwest
Council, APS, Desert STAR and SPP.
\623\ See, e.g., Kentucky Commission, Gainesville, Big Rivers,
Puget and Ontario Power.
---------------------------------------------------------------------------
Several commenters argued that the use of license plate rates
should be for a transition period roughly coincident with the phase-in
of retail competition. For example, Duke argues that license plate
rates avoid cost-shifting, and will therefore make it easier for
companies to collect their retail revenue requirements in jurisdictions
without retail competition, where state regulators may disallow higher
transmission rates.
Commenters that support license plate rates as a long-term solution
argue that license plate rates are an aid to RTO formation.\624\ SoCal
Edison claims that license plate rates avoid cost shifts, are
administratively more efficient, provide a basis for efficient
transmission operation, and provide incentives for system expansion.
SoCal Edison favors their use in the long term.
---------------------------------------------------------------------------
\624\ See eg., East Kentucky and PJM.
---------------------------------------------------------------------------
Of those opposed to license plate rates in general, some suggest a
different pricing methodology. CMUA prefers an integrated, two-part
rate. The first part of the rate reflects the revenue requirement of
the overall RTO (principally above 200 kV) and the second part reflects
the local systems to the extent used. CMUA argues that license plate
rates do not follow the rules of cost causation, do not promote needed
enhancements and do not promote comparability in rates. Minnesota Power
recommends a two-part rate with a demand component to
[[Page 917]]
collect fixed costs and a variable component for losses. WPSC advocates
the use of flow-based, distance-sensitive rates rather than license
plate rates. APPA claims that license plate rates do not go far enough.
A four part approach is suggested in their place: assure recovery of
revenue requirement; honor existing contracts and phase in regional
rates; sub-functionalize the grid by voltage; and, once trusted RTOs
are in place, allow congestion rates above embedded costs and non-
congestion rates below, all subject to a revenue requirement true-up.
RECA recommends that zones for transmission access charges be formed
based on cost and other differences, not on existing service areas.
SMUD claims that Cal ISO's license plate rate encourages inefficient
operation.
Some commenters provide more general reactions to the cost shifting
problem. Wyoming Commission recommends that the Commission not codify a
specific approach to license plate rates and other measures with cost-
shifting ramifications but rather defer to regional and state processes
to establish guidelines within a region. PSNM is concerned about the
impact of the loss of existing contracts on its license plate rate
calculation. Manitoba Board is concerned about shifting costs to low-
cost, transmission-dependent areas. Platte River does not want its low
costs averaged with higher cost systems. United Illuminating encourages
the Commission to continue its flexibility in permitting different
approaches in the recovery of sunk costs. Aluminum Companies argues
that the Commission needs to offer more guidance on cost shifting and
that rate increases due to cost shifting should be constrained to the
benefits involved. Further, cost shifts should not be allowed unless
competition is fostered.
Commission Conclusion. We conclude that the Commission should
continue to provide flexibility with respect to RTO proposals for
allocation of fixed transmission cost recovery. The Commission will
permit RTO proposals to use license plate rates, as defined above, for
several reasons. First, commenters overwhelmingly support the use of
license plate rates, and demonstrated convincingly that problems
associated with cost-shifting are not easily resolved by means other
than the use of license plate rates. Second, the Commission is
concerned that the potential for cost-shifting could act as an
impediment to RTO formation, thereby denying all stakeholders the
benefits that come from RTO membership.
Moreover, although license plate rates are not necessarily an ideal
method for fixed cost recovery, we note that all ISOs have sought
approval from the Commission for license plate rates, at least during
their startup phase. No commenter has provided convincing evidence that
the use of license plate rates by existing ISOs produces significant
harms, although several commenters suggest various rate designs,
including multi-part rates, as alternatives to license plate rates.
Although commenters overwhelmingly support the use of license plate
rates, they are split on whether such rates should be used only for a
transitional period, or whether the Commission should allow them as a
permanent feature. This is a difficult issue. On the one hand, we are
reluctant to require RTOs to suspend use of license plate rates after
some arbitrary date certain at which time they will be required to
transition to single system access rates; on the other hand, we are
reluctant to announce generically that license plate rates may be a
permanent feature of an RTO. Furthermore, the use of license plate
rates could depend on idiosyncratic facts, e.g., the geographic makeup
of the RTO, or the transmission cost differences in various subregions
of the RTO.
We therefore believe that it is appropriate to allow RTOs to
propose the use of license plate rates for a fixed term of the RTO's
choosing. However, RTOs that propose the use of license plate rates
must make clear how transmission expansion will be priced, that is,
whether license plate rates or some other mechanism will be applied to
the cost of new transmission facilities, and how such pricing affects
incentives for efficient expansion. In addition, we will require that
before the end of the fixed term, the RTO must complete an evaluation
of fixed cost recovery policies based on the factual situation of the
particular RTO, and file with the Commission its recommendations on any
changes that should be instituted. We emphasize that we are not
requiring that the RTO continue or abandon the use of license plate
rates at that time, but we will require the RTO to justify its choice
to continue or discontinue using license plate rates, or otherwise
change the method for fixed cost recovery. We believe that this
approach provides participants in RTOs significant flexibility, and is
consistent with the principles articulated in the open architecture
requirement for RTOs.
4. Congestion Pricing
Congestion pricing and congestion management are closely related.
Comments on these issues have been treated jointly, and are summarized
above in the discussion of congestion management.
Commission Conclusion. With respect to congestion pricing, the
Commission emphasized that it intends to be flexible in reviewing
pricing innovations, and sought comments on what specific requirements,
if any, best suited the Commission's RTO goals. A number of commenters
agreed with the Commission's conclusion in the NOPR that ``markets that
are based on locational marginal pricing and financial rights for
transmission provide a sound framework for efficient congestion
management.'' \625\
---------------------------------------------------------------------------
\625\ FERC Stats. and Regs. para. 32,541 at 33,742.
---------------------------------------------------------------------------
We reemphasize the basic principles for congestion pricing
articulated in the NOPR, i.e., that proposals should ``ensure that the
generators that are dispatched in the presence of transmission
constraints must be those that can serve system loads at least cost,
and limited transmission capacity should be used by market participants
that value that use most highly.'' \626\
---------------------------------------------------------------------------
\626\ Id. at 33,754-55.
---------------------------------------------------------------------------
We recognize that congestion pricing, especially when complex
problems associated with parallel path flows are addressed, is in its
infancy. Rather than prescribe a specific method, we encourage
experimentation with reasonable congestion management techniques. We
would expect that such experiments be consistent with the open
architecture requirements of the rule, and that information from such
experiments be made widely available to all interested parties, so that
other RTOs can learn from each others' experience.
5. Service to Transmission-Owning Utilities That Do Not Participate in
an RTO
The Commission asked commenters to discuss the treatment by an RTO
of a non-participating transmission owner in a region if the
transmission owner does not participate in its region's RTO.\627\ For
example, we asked whether it would be appropriate to allow RTO members
to provide transmission service at individual system rates to non-
participating transmission owners located in the RTO region thereby
denying non-participants the benefits of non-pancaked transmission
rates.
---------------------------------------------------------------------------
\627\ Id. at 33,759.
---------------------------------------------------------------------------
Comments. Of those commenters that generally support the proposed
strategy,
[[Page 918]]
most argue that non-participants should not enjoy the benefits of non-
pancaked rates.\628\ PG&E submits that the reasoning the Commission
applied in Order No. 888 applies here (i.e., in Order No. 888, the
Commission rejected the claim that a reciprocity requirement required
explicit Commission jurisdiction over the transmission customer finding
that, as a matter of fairness, a public utility providing open access
through a non-discriminatory tariff deserved the right to obtain
comparable access over the transmission systems of its customers).
Empire District is particularly concerned that utilities on the border
of an RTO may receive many advantages of the RTO without accepting any
of the burdens of participation, yet at the same time make it more
difficult for competitors to service its load by staying out of the
RTO.
---------------------------------------------------------------------------
\628\ Montana-Dakota, Allegheny, PG&E, Tri-State, PNGC and
Empire District.
---------------------------------------------------------------------------
Other commenters are conditional in their support. For example,
Oneok wants the Commission to draw a hard line on non-participation and
be willing to employ negative incentives; however, Oneok points out
that denial of non-pancaked rates will be more costly to marketers and
consumers. South Carolina Authority suggests that the Commission
consider the extent to which the transmission owner is actually able to
participate in an RTO before permitting denial of RTO service under
non-pancaked rates. In the case of publicly owned utilities, there may
be restrictions in the enabling act or charter, the applicable state
constitution or the utility's bond covenant that effectively prohibit
it from participating in a particular RTO. This would also apply if the
RTO is not the product of the ``region's RTO'' involving all
stakeholders in the designated region but is a business entity designed
to advance the financial objectives of particular sponsors. Similarly,
SPRA argues that, in the event that it is unable to immediately join an
RTO, the RTO should recognize that SPRA has an OATT that provides for
comparable treatment to the RTO. And New Smyrna Beach states that,
although denial of non-pancaked rates to nonparticipants has merit, it
may be a moot issue in Florida where FP&L's transmission is so
extensive that pancaked rates would be a more costly alternative for
marketers and consumers of electricity.
Other commenters believe the proposal is a flawed concept or
otherwise oppose it. Avista and PPC argue that it is not appropriate to
allow an RTO to provide transmission service at individual system rates
to non-participating transmission owners as such a policy would deny
them the benefits of non-pancaked rates and defeat the central goal of
its proposal. Metropolitan concurs that non-participating transmission
owners should share in the benefits of non-pancaked rates. Southern
Company and CP&L claim that the Commission cannot punish utilities that
find it in the best interests of their stakeholders not to join an RTO.
SMUD believes that RTOs must provide nondiscriminatory access to
transmission it controls at cost-based rates to all customers, since
they contribute to the RTO's cost recovery. SMUD argues that the
Commission, through its NOPR has, in essence, found that pancaked rates
are not just and reasonable and that they should be corrected; thus,
the Commission cannot allow an RTO to charge pancaked rates in
violation of the FPA section 205 prohibition on unjust or unreasonable
rates.
Snohomish, Turlock, Big Rivers and Dairyland all make similar
arguments--charging higher pancaked rates to utilities that do not
participate in the RTO is patently unfair, violates the Commission's
duty to eliminate discriminatory rates, and would penalize consumers of
customer-owned utilities who have no practicable choice about whether
to participate in the RTO. Dairyland says that this could open the door
to creation of RTOs that purposely do not accommodate non-public
utilities. SRP posits that imposition of pancaked rates on non-
participants in an RTO would effectively turn the Commission's stated
policy goal of voluntary participation into an RTO mandate inviting
years of litigation.
Two state commissions question the effectiveness of pancaked rate
sanctions against non-participants. Indiana Commission contends that a
recalcitrant utility may not perceive pancaked rates as detrimental and
may not feel compelled to join an RTO. Illinois Commission feels that
imposition of penalties involving restricted access to RTO transmission
rates would either be self-defeating for the Commission or detrimental
to the electricity consumers of the affected utility. In its view, the
solution to this conundrum is for the Commission to abandon its
unworkable voluntary approach to RTO participation, and utilize its
authority under FPA sections 205 and 206 and examine its authority
under FPA sections 202(a), 211 and 212 to mandate participation.
However, Nevada Commission submits that the Commission must ensure that
a transmission-owning utility that refuses to join an RTO should not be
allowed to derive any economic benefit from the existence of RTOs.
ISO commenters have diverse views on this issue. Desert STAR argues
that a blanket ban on prohibiting a party that does not join an RTO
from deriving any benefit from the RTO whatsoever may be too broad an
approach. NYPP, citing Associated Gas Distributors v. FERC \629\ and
Richmond Power & Light v. FERC \630\ for the proposition that the
Commission cannot achieve indirectly what it cannot do directly, submit
that the Commission cannot impose any coercive measure on or deny
benefits to utilities that do not participate in an RTO. In addition,
NY ISO argues that previously approved ISO's transmission-owning
members should be eligible for whatever RTO participation incentives
and benefits are ultimately adopted in this proceeding. On the other
hand, PJM/NEPOOL Customers support denial of non-pancaked transmission
rates to nonparticipants.
---------------------------------------------------------------------------
\629\ 824 F.2d 981, 1024 (D.C. Cir. 1987).
\630\ 574 F.2d 610, 620 (D.C. Cir. 1978).
---------------------------------------------------------------------------
Canadian entities generally oppose imposition of pancaked rates
against non-participants. Canada DNR contends that a decision not to
participate in an international RTO by a Canadian jurisdiction should
not place entities in that jurisdiction engaged in trade with the U.S.
at a disadvantage relative to U.S. RTO participants. BC Hydro concurs
that the decision to join an RTO should not be made a prerequisite for
participation of Canadian provincial utilities or their affiliates to
participate in the U.S. electricity market. CEA observes, however, that
Canadian utilities see access to the U.S. market as a significant
business opportunity that requires a transparent and open bulk
transmission system operating in both directions. Grand Council et al.
submits, however, that applying no penalties or incentives to Canadian
utilities, while giving them unfettered access to U.S. markets without
being subject to corresponding obligations, is inconsistent with the
RTO concept. And H.Q. Energy Services submits that, if the Commission
decides not to require RTO participation, it should strongly encourage
voluntary participation by denying certain benefits such as the use of
the system-wide tariff to nonparticipants.
Commission Conclusion. Regarding the question raised in the NOPR
about whether a non-participating transmission owner in an RTO region
should receive all the benefits of the RTO in its region, we share the
concerns
[[Page 919]]
of most commenters that transmitting utilities may receive the benefits
of an RTO in its region without accepting any of the burdens of
participation in the RTO. Accordingly, where a transmission customer of
an RTO or the customer's affiliate owns, controls or operates
transmission in the RTO's region, and is not participating in that
particular RTO, we intend to permit that RTO to propose rates, terms,
and conditions of transmission service that recognize the participatory
status of the customer.
We do not intend that every such proposal will necessarily be
accepted by the Commission. Each RTO must justify any proposal on a
case-by-case basis. The proposal should recognize the various
situations of non-participating transmission owners. As pointed out by
commenters, some transmission owners may face legal obstacles to
participation that may need to be taken into account in the proposal.
It is not our intent to permit an RTO to apply such a proposal to a
non-participating transmission owner in another region. As discussed
above, Empire District expressed concern about whether this provision
would apply to a non-participating owner ``on the border'' of an RTO.
We would permit an RTO to argue that the non-participant should be part
of its RTO region based on engineering or other objective criteria.
An RTO will provide several benefits for parties in the region,
including elimination of individual system rates. We asked in the NOPR
whether it would ``be appropriate to allow RTO members to provide
transmission service at individual system rates to non-participating
transmission owners located in the RTO region.'' (emphasis added) \631\
SMUD argues that the Commission in its NOPR has found, in effect, that
individual system rates are not just and reasonable and so cannot allow
transmission-owning utilities in an RTO to charge individual system
rates.
---------------------------------------------------------------------------
\631\ FERC Stats. & Regs. para. 32,541 at 33,759.
---------------------------------------------------------------------------
SMUD is incorrect. We have not made a generic determination that
individual system rates are not just and reasonable in an RTO region. A
non-participating public utility transmission owner in an RTO region
may itself file a single company rate and argue that it is just and
reasonable for use by its neighbors who join the RTO.
Instead of making a generic determination about these matters, we
will permit an RTO and its transmission-owning public utility members
to make the case that it is just and reasonable to charge individual
system rates to a transmission customer who is a non-participating
transmission owner in its RTO region. We will decide each RTO proposal
on its merits.
6. Performance-Based Rate Regulation
The NOPR suggested that, once RTOs are formed, performance based
regulation (PBR) can facilitate good grid operation.\632\ We noted that
PBR can incorporate price/revenue caps, price incentives, or
performance standards. The NOPR sought comments on how PBR should be
applied to an RTO and whether it should be voluntary.
---------------------------------------------------------------------------
\632\ Id., at 33,755.
---------------------------------------------------------------------------
Comments. The vast majority of commenters favor PBR of some form to
promote efficient operations by RTOs.\633\ And most commenters that
favor PBR specifically state that PBR should be voluntary for RTO
participants.\634\
---------------------------------------------------------------------------
\633\ See, e.g., EPSA, PJM, Los Angeles, Georgia Transmission,
Illinois Commission, Pacific Corp and Desert STAR.
\634\ See, e.g., Florida Power Corp., MidAmerican, Tri-State,
FirstEnergy, Alliance Companies, Duke and PGE.
---------------------------------------------------------------------------
Professor Joskow recommends that the Commission promote the view
that PBR will eventually be required. He suggests that there is
sufficient experience with PBR, such as in England and Wales. He argues
that PBR should be based on a standard price cap that focuses not only
on direct transmission service costs, but also focuses on the cost of
congestion management, losses, ancillary services, reactive power, and
connection of new generators. EEI notes that a price cap, based on a
reasonable ROE revenue requirement, is the most widely used method. EEI
argues that price caps reduce rate cases, give an incentive to improve
productivity, and share productivity savings with customers. Brattle
Group does not propose a specific PBR scheme but says that, at this
point, approval should be case-by-case. Care should be taken that a PBR
is not based on a single element, causing distortions elsewhere.
Other supporters have specific comments regarding the
implementation of PBR. Entergy recommends that the Commission provide
more specific guidance on the use of PBR. DOE warns that PBR should not
be allowed to prevent a PMA that is a part of an RTO to under-recover
its revenue requirement. New Smyrna Beach and Oneok only support PBR if
there is a downside as well as an upside potential associated with
transmission performance. Allegheny states that the Commission must
settle on a definition of performance, the performance criterion should
be economic reliability, the owner must have an opportunity to recover
investment, the Commission should recognize that some aspects of
performance will be outside of the control of the RTO, and the
particular PBR rate calculation should be considered on a case-by-case
basis.
A number of commenters recommend that PBR not be instituted
immediately upon the formation of the RTO. California Board, Trans-
Elect, and WPSC maintain that time is needed to establish base year
benchmarks. PG&E and APPA say that PBR should be set aside until the
RTO is up and functioning and Arkansas Consumers and Wyoming Commission
argue that the RTO should first demonstrate that it can and will
provide reliable and non-discriminatory service before PBR is
established.
At least eight commenters were opposed to PBR for RTOs as a
Commission policy. Industrial Consumers, Williams, and CMUA do not
think that PBR can be effective in promoting efficiency in the
operation of RTOs. Salomon Smith Barney and East Texas Cooperatives
believe that RTOs will be able to game the system and take advantage of
PBR. PJM/NEPOOL Customers, Lincoln, and NASUCA argue that PBR should
not be allowed for RTOs because they are unnecessary. NASUCA is also
skeptical of PBR for RTOs because some areas where performance is
important are not under the RTO's control. NJBUS argues that PBR will
not put a stop to transmission discrimination.
NEPCO et al. disagree with those commenters who oppose PBR.\635\
PBR is effective, as shown in the United Kingdom, and they are not
``bribes'' given freely to transmission owners. Enron/APX/Coral Power
does not agree with NASUCA and California Board that there is not
enough experience on which to base PBR. According to Enron/APX/Coral
Power, there is a large amount of experience in regulating transmission
plus a lot of experience with the ramifications of EPAct.
---------------------------------------------------------------------------
\635\ See, e.g., APPA, Minnesota Power and CMUA.
---------------------------------------------------------------------------
A few additional commenters neither strongly support nor oppose
PBR, but offer specific comments about PBR use. Project Groups
recommends that the Commission construct a way to de-couple revenues
from transmission rates so that efficient transmission service rather
than total throughput determines revenue. Florida Commission states
that questions as to the advisability and particulars of a PBR
mechanism should be left to regional solutions that have the
endorsement of the state regulatory
[[Page 920]]
bodies. Big Rivers states that PBR is inappropriate for cooperatives
and public power utilities. WEPCO believes that RTOs should be not-for-
profit and that PBR should be available only to the for-profit
transmission owner. Metropolitan is concerned that PBR might cause RTOs
to neglect needed expansions and upgrades and jeopardize reliability.
Commission Conclusion. At the outset, we think it is important to
emphasize that PBR is far from a new concept. Over the last 10 to 20
years, a significant amount of research, primarily by economists, has
been done regarding the conceptual basis of, and efficient designs for,
PBR.\636\ This research addresses its use in the electric utility
industry as well as other regulated industries. It is also important to
note that the Commission has been receptive to PBR proposals, at least
since issuance of the Policy Statement on Incentive Regulation in
October 1992. In that Policy Statement, we provided guidance to public
utilities as well as natural gas and oil pipelines considering
proposing some form of PBR.\637\ Although the Policy Statement invited
public utilities to develop and file incentive regulation proposals,
the Commission has not received any proposals from public
utilities.\638\
---------------------------------------------------------------------------
\636\ See, e.g., Paul Joskow and Richard Schmalensee, Incentive
Regulation for Electric Utilities, Yale Journal of Regulation, Vol.
4 at 1-49 (1986); Sanford Berg and Rajiv Sharma, Techniques for
Assessing Firm Efficiency, University of Florida Public Utilities
Research Center Working Paper (June 1999); Peter Navarro, Seven
Basic Rules for the PBR Regulator, Electricity Journal at 24-30
(April 1996); G. Alan Comnes, Steven Stoft, et al., Six Useful
Observations for Designers of PBR Plans, Electricity Journal at 16-
23 (April 1996); Lorenzo Brown and Ingo Vogelsang, Incentive
Regulation: a Research Report, Federal Energy Regulatory Commission,
Office of Economic Policy, Technical Report 89-3 (1989); and Jean-
Jacques Laffont and Jean Tirole, A Theory of Incentives in
Procurement and Regulation, MIT Press (1993).
\637\ The Policy Statement articulated five regulatory
standards: (1) incentive ratemaking must be prospective; (2)
participation must be voluntary; (3) incentive mechanisms must be
understood by all parties; (4) benefits to consumers must be
quantifiable; and (5) quality of service must be maintained.
\638\ We note that PBR mechanisms have been widely used by state
regulators and the FCC as applied to the U.S. telecommunications
industry. See, e.g., John Kwoka, Implementing Price Caps in
Telecommunications, Journal of Policy Analysis and Management, Vol
12, No 4 at 726-52 (1993).
---------------------------------------------------------------------------
The Commission's current interest in PBR stems from the proposition
that PBR will allow the Commission to rely on market-like forces, to
the maximum extent possible, to create incentives for RTOs to
efficiently operate and invest in the transmission system. This does
not mean that we expect that transmission services will be provided in
competitive markets any time soon, or at all. We recognize that
transmission service will retain most or perhaps all of the
characteristics of a natural monopoly for the foreseeable future, and
that some type of explicit price regulation will therefore be required
to prevent monopoly abuse. But we believe that PBR, especially if
accompanied by explicit and well-designed incentives, may provide
significant benefits over traditional forms of cost-of-service
regulation. We believe this view of PBR is entirely consistent with
other initiatives taken by the Commission, such as Order Nos. 888 and
889, to promote competitive power markets, and given the impracticality
of competitive transmission markets, to rely on market-like forces to
the maximum extent possible.
Before providing further specificity on PBR, it is useful to
restate the overarching concerns of commenters. A large number of
commenters support the use of PBR, and many of them, as discussed
above, believe that PBR and other forms of incentive regulation will
significantly enhance the incentives RTOs have to make efficient
operating and investment decisions. For example, Professor Joskow
notes:
It is very important for the Commission to adopt regulatory
mechanisms that provide transmission owners and operators with
powerful economic incentives to operate transmission networks
efficiently and to invest the resources necessary to expand their
capabilities efficiently. These incentives should be an integral
component of a performance-based regulatory (PBR) framework for the
regulation of transmission rates that rewards transmission owners
for achieving these objectives and penalizes them for failing to do
so.\639\
---------------------------------------------------------------------------
\639\ Professor Joskow at ES-iv.
On the other hand, a somewhat smaller group of commenters, mostly
transmission customers, oppose the use of PBR. They express doubts
about whether PBR will provide good incentives for RTOs to operate and
invest efficiently. They are also concerned that PBR design is so
difficult that RTOs will easily game the system, which will likely
result in higher revenues for RTOs and therefore higher prices for
transmission services for all transmission customers.
Commenters describe a wide array of PBR mechanisms, including some
relatively unsophisticated proposals and others which are analytically
complex. For example, a number of commenters have proposed that the
Commission entertain transmission rate moratoriums, e.g., where
transmission rates are locked into their current levels for a limited
period of years. To the extent the transmission provider can achieve
any transmission costs savings, these would be retained by the
transmission provider. In this sense, it falls within the concept of
PBR.
It is argued that this rate treatment may promote the establishment
of independent transmission companies because it provides the certain
revenue stream that is needed to obtain financing for the purchase of
transmission systems from existing owners. It is also argued that this
approach is analogous to a hold harmless commitment for existing
customers which may simplify the efforts of those state regulators who
value transmission rate certainty during their conversion to retail
choice. This approach would also reduce litigation at the Commission
during the moratorium.
Finally, if the rate level selected takes into account the existing
transmission component of bundled retail power rates, it addresses the
concern expressed by many that one deterrent to participation in RTOs
is the fear and uncertainty that transferring retail transmission
services from state to Commission jurisdiction leads to reduced
revenues.
Other commenters suggest that the essence of PBR is to set cost and
performance benchmarks and then reward or penalize an RTO based on
performance relative to those targets. Clearly, such an approach
presents significant analytical challenges. Ideally, an RTO's cost and
operating performance can be compared with other, similar entities. One
benefit of setting such targets is that it overcomes the asymmetric
information problem, i.e., a transmission service provider will usually
have better knowledge of the potential efficiency gains than will
regulators. Benchmarking performance helps reduce the information
imbalance.\640\
---------------------------------------------------------------------------
\640\ We note that there have been some early attempts to
compare the relative cost and performance of ISOs in the U.S. See,
e.g., California ISO, ``A Comparative Analysis of Operating ISOs in
the United States'' (Oct. 15, 1998).
---------------------------------------------------------------------------
We have carefully considered all of the comments about PBR. We
conclude that the Commission should encourage RTOs to consider use of
PBR, although we recognize the difficult analytical challenges that
RTOs will face. To facilitate such consideration, we are providing
additional specificity on PBR. We address several threshold procedural
issues, and articulate additional design principles that should provide
a framework for RTO consideration of PBR.
[[Page 921]]
A first threshold issue is whether the Commission should require
that RTOs use PBR or whether it should be voluntary. There is almost no
support for making PBR mandatory, and we therefore will not require RTO
filings to include PBR proposals, although we encourage such proposals.
A second threshold issue is what types of RTOs are eligible for
PBR. As discussed above, some commenters argue that PBR is not
appropriate for cooperatively-owned and publicly-owned transmission
owning utilities. Similarly, other commenters argue that PBR is
appropriate only for profit-making RTOs. We conclude that, although the
application of PBR may vary according to the type of RTO, there is no
reason to limit the applicability of PBR to certain members or types of
RTOs. The Commission welcomes RTO filings with PBR proposals from any
source. For example, in the context of an ISO or a tiered ISO/transco
that has been described by some commenters, the activities that
contribute to performance may be shared between the RTO and the
transmission owners. This does not invalidate the use of PBRs; however,
the RTO design would simply ensure that the rewards and penalties
associated with activities performed by transmission owners flow
through to the owners to achieve the desired result.\641\ In addition,
we see no impediment to the use of PBR to provide incentives for
efficient behavior by non-profit RTOs. We note that some existing ISOs
have in place performance incentives for some of their managers, and
such an incentive scheme may have application for RTOs which do not own
the transmission assets they control.
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\641\ For example, PJM states that it can facilitate the
application of PBRs to its transmission owners by using the
stakeholder process to set the performance parameters and, once the
parameters are in place, to independently evaluate the transmission
owners' performance and apply the PBR.
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A third threshold issue is how PBR proposals will be formulated and
when they will be filed. The Commission recognizes that PBR design
involves highly complicated issues, and that there is the possibility
that a bad PBR proposal can result in lower quality transmission
service, at higher costs, compared with service that might prevail
under traditional ratemaking practices. One key element in the process
of designing a PBR proposal would be to ensure adequate input from all
stakeholders. We believe that the best PBR designs will emerge when all
stakeholders have an opportunity for input, even if a filed PBR design
does not represent full consensus. We therefore conclude that RTOs that
wish to implement PBR need not necessarily file the PBR proposal at the
time the RTO makes its compliance filing if more time is needed to
negotiate among stakeholders the details of a well-designed PBR. Some
commenters suggest that an additional consideration in allowing delayed
filings of PBR is the need to evaluate operating experience of the RTO
before appropriate benchmark measures for PBR can be developed.
The Commission also believes it is appropriate to provide
additional specificity on what constitutes good PBR design. We continue
to endorse the regulatory standards included in the Incentive
Regulation Policy Statement, described above. And we note that in some
regions, certain types of PBR mechanisms may be better suited than
others. For example, where there are already state-imposed rate
moratoriums, continuation of such programs after RTO formation may be
an appropriate PBR approach. Alternatively, a transmission rate
moratorium based on the existing rate level may be appropriate for a
transitional period during RTO formation.\642\ Similarly, in an area
that has experience with a particular performance-based mechanism,
extension and perhaps refinement of such a program after RTO formation
may be the most appropriate policy.
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\642\ As noted infra, this is one of the pricing reforms that
will be available for a defined transition period during which RTOs
are being established.
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We encourage RTOs to file fully documented PBR proposals that are
consistent with the amended regulatory text. PBR proposals should
include a detailed explanation of how the PBR mechanism will work, as
well as all of the information necessary for the Commission and all
market participants to evaluate the benefits and costs of implementing
the PBR mechanism.
Based on the comments we received in this docket, as well as our
understanding of international \643\ and state experience with
incentive regulation, we expand on the considerations for PBR addressed
in the amended regulatory text by offering the following additional
principles for RTOs to consider in designing PBR proposals.
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\643\ We note that a PBR system that uses a variant of price cap
regulation of the National Grid Company has been in use for nine
years in England and Wales. More recently, the price cap has been
combined with a separate incentive mechanism that focused on
reducing congestion on the grid. Since this is the longest-running
PBR targeted to grid operations, we encourage any RTO that intends
to propose PBR to examine the strengths and weaknesses of the
British approach.
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PBR should not be applied piecemeal. To the extent possible, PBR
programs should focus on the entire operation of the RTO, rather than
smaller parts of the operation. Commenters caution that PBR programs
that focus narrowly, e.g., only on the cost aspects of RTO operations,
may result in inattention by the RTO to the quality of service offered.
Similarly, a focus on only one aspect of costs, e.g., short-run costs,
may result in reduced costs for that single aspect, but higher total
costs for the RTO.
PBR should encompass both rewards and penalties. Although some PBR
designs employ either rewards or penalties, but not both, most
commenters suggest, and the Commission agrees, that the most effective
and most fair designs will likely encompass both. One rationale for
this is that it is not always clear what incentives an RTO will respond
to, and therefore the prospect of higher revenues as well as the threat
of lower revenues may induce an RTO to provide the best possible
performance. An additional rationale is that under the FPA, the
Commission is required to set rates for transmission service at just
and reasonable levels. To the extent that rates may vary within a
range--both up and down--as a function of RTO performance, this
statutory requirement may be better satisfied.
PBR rewards and penalties should create incentives for an RTO to
make efficient operating and investment decisions, and should not
compromise system reliability. A significant concern in any PBR
application is the possibility that incentives will distort RTO
decisionmaking. For example, commenters caution that an RTO may manage
congestion through a combination of generation redispatch and
investment in transmission infrastructure, and that poorly designed PBR
mechanisms could distort RTO decisionmaking toward the most profitable,
rather than the least-cost, solution, or toward an approach that
inappropriately reduces system reliability. An additional concern is
that PBR mechanisms may create bias with respect to the trade-off
between investment in generation and transmission, or in siting
generation and transmission facilities in the most efficient places on
the grid.
The benefits of PBR should be shared between the RTO and its
customers. The Commission believes that as a matter of fairness, the
efficiency gains occasioned by PBR should be shared. This will involve
difficult analytical issues, including identifying efficiency gains,
[[Page 922]]
measuring them, and determining the effect of sharing such gains on the
strength of the incentives faced by the RTO. The Commission does not
believe it would be appropriate to specify the exact distribution of
such gains, as such a decision is better left to negotiation by all
stakeholders.
To the extent possible, the rewards and penalties should be
prescribed in advance based on known and measurable benchmarks. PBR
designs involve an inevitable trade-off between simplicity and
administrative ease on the one hand, and the potential benefits of the
program. Although relatively simple designs such as rate freezes
provide significant incentives for an RTO to reduce its costs, they
produce relatively limited incentives to maintain reliability, promote
service quality, or manage congestion. PBR mechanisms that benchmark an
RTO's performance, either to its own historical performance, to
industry performance indices, to some normative goal, or to a
combination of these, may be designed to provide incentives for more
efficient operation and investment decisionmaking. The Commission
recognizes that designing sophisticated PBR mechanisms will be a
significant challenge for RTOs already grappling with other development
issues. The Commission, therefore, will make its staff available
through our pre-filing process to work with RTOs to help identify and
resolve issues on an informal basis prior to their filing a PBR
proposal.\644\
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\644\ Alternatively, the RTO could seek guidance in a more
formal proceeding, e.g., if an RTO files a petition for a
declaratory order seeking approval of its PBR proposal.
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7. Other RTO Transmission Ratemaking Reforms
The Commission proposed in the NOPR to consider innovative pricing
proposals for transmission owners who turn over control of their
transmission facilities to an RTO.\645\ The types of pricing that the
Commission proposed to consider include: a higher ROE on transmission
plant; allowing the transmission owner to retain the benefits of cost
saving attributable to RTO formation; acceleration of transmission cost
recovery in rates; non-traditional valuation of transmission assets
such as an estimate of replacement costs for assets purchased at higher
than net original cost; and liberalized allowance of levelized or non-
levelized rate methods. The Commission proposed that transmission
owners meet all of the requirements to become an RTO before an
innovative pricing proposal is accepted.\646\
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\645\ FERC Stats. and Regs. para. 32,541 at 33,755.
\646\ Id. at 33,756.
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Comments. A large number of commenters addressed the Commission's
proposals to consider transmission pricing reforms for RTOs. About 30
commenters expressed support, and about 30 commenters expressed
opposition. There were also a number of comments which did not
explicitly support or oppose this aspect of the NOPR.
Supporting Innovative Pricing.\647\ Of the commenters that support
innovative pricing, a common theme is that if RTO formation is to be
voluntary, incentives are required to encourage participation.\648\ For
example, Justice Department recommends that the positive and negative
incentives be designed to secure universal compliance rather than have
some utilities not participate because the advantage of continuing
outside of the RTO is greater than the incentive to join. EEI supports
incentives since RTO formation will probably not generate increased
earnings for transmission owners since most of the efficiencies will be
a benefit to others. EEI suggests that an application for RTO formation
and incentives should include some assessment of the benefits from
which the incentives are generated but a precise calculation of
benefits should not be required because of the extreme difficulty in
making such an estimate. PacifiCorp is in favor of incentives but is
concerned that a ``case by case'' consideration of incentives may
jeopardize their realization because customers will call for lower
transmission rates in the short term once the RTO has been formed.
PacifiCorp argues that a more detailed uniform policy on incentives
``up front'' is preferred.
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\647\ While we used the term incentive pricing in the NOPR, this
term is an imprecise description of the various transmission pricing
reforms that will be addressed in this Rule, and we now describe
these pricing reforms as innovative rate proposals. However, the
comments sections that follow continue to use the term incentive
because the parties used this term in their comments.
\648\ See, e.g., Avista, TEP, Duquesne, APS, NEPCO et al.,
Florida Power Corp.
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On the other hand, several commenters suggest that the Commission
should consider incentives only on a case-by-case basis. Desert STAR
says that different RTOs may need different sets of incentives as will
public power transmission owners. MidAmerican supports case-by-case
consideration of incentives to join an RTO, and favors a higher ROE
reflecting the fact that transmission is not limited to selling to a
captive customer base in a bundled context but is serving a wholesale
marketplace at greater risk. Duke is in favor of incentives for
transmission expansion, but cautions that incentives should not bias
investment and other decisions, should be considered on a case-by-case
basis, and may not be very effective where operation is separated from
ownership. Oregon Office is in favor of incentives for meeting all of
the RTO characteristics and functions faster than the industry average,
but not for average speed in accomplishing RTO formation.
A number of commenters favor offering incentives to public
utilities that are already members of an ISO as well as to provide
incentives for public utilities to join an RTO. For example, PJM says
that incentive rates should be offered to new and existing RTO members
to reflect the benefits generated and to prevent inefficient
consequences such as transmission owners moving from an existing ISO to
a new RTO to receive incentive rates. PSE&G favors a correspondingly
higher ROE and faster depreciation of transmission assets for
transmission owners who participate in RTOs, including those who have
already joined an existing organization. LG&E says that incentive plans
can be useful in promoting RTO participation and that existing members
of RTOs should be allowed to propose incentive rates as well. LG&E
stresses that it is just as important not to enact policies on rates
that might jeopardize revenue requirement recovery and thus act as a
disincentive. An additional consideration is offered by PP&L Companies
which argues that existing participants in RTOs should be allowed the
same incentive rates as those which are just forming because the
benefits of an existing RTO are greater than those of a start-up RTO
not yet in operation.
The proposed incentive addressed most frequently by commenters is
allowing a higher rate of return on transmission assets. Georgia
Transmission believes that higher ROEs as an incentive to voluntarily
join an RTO is appropriate because of the benefits that participation
would bring. NSP and others argue that ROE must be sufficient to
attract capital and compensate utilities for the risks involved.
Conectiv and EEI argue that the current rate of return policy should be
modified, arguing that the DCF method gives results that are too low to
provide adequate returns to transmission owners causing a reduction in
building at a time when more transmission is critically needed.
According to Conectiv, the DCF method should be abandoned or its
application
[[Page 923]]
should be modified to account for the current industry situation and be
more reflective of conditions in the general economy and reflect
reasonable transmission asset lives. Cinergy, in reply comments
contends that the record in this proceeding is sufficient to establish
a presumption of reasonableness for higher ROEs.
SoCal Edison does not believe that pure incentives in the form of
ROE ``awards'' are necessary for encouraging participation in RTO but
it does argue that higher returns may be justified on transmission
assets controlled by an RTO because the original owner no longer has
control over planning and expansion decisions. In addition, distributed
generation and bypass may be found to increase risk. SoCal Edison says
that it is very important to prevent the move to RTO control from being
a financial loss due to Commission rate setting or because of greater
risk and higher costs. SoCal Edison does agree with the proposal to
allow accelerated depreciation of transmission assets to encourage
participation.
TXU Electric is in favor of consideration of higher ROEs for RTO
participants and thinks it is more important to take a more global look
at transmission ROEs in a new and uncertain industry environment where
transmission investment is important. TXU Electric warns that it would
be inappropriate to penalize RTO participation with reduced earning
potential because unbundled transmission ROEs are lower than ROEs
allowed in bundled rates. Conlon suggests that the Commission could
allow a higher return on assets of a transco or ISO to serve as an
incentive for IOUs to transfer ownership. Southern Company explains
that there are major tax consequences to the sale of transmission
assets to form a transco and recommends that the Commission find ways
to accommodate such a transition. As to rate incentives, Southern
Company advocates a change in the Commission's ratemaking policy in
order to increase returns to be more commensurate with non-regulated
businesses. Southern claims that recent court rulings support higher
returns on transmission service.
A number of commenters argue that participation in an RTO increases
financial risk, and that incentives are therefore required to encourage
RTO participation. For example, Empire District says that turning over
control of transmission assets to an RTO increases the risk because
someone else will control their operation, justifying higher ROEs for
participation. PSE&G argues that a stand-alone transmission company or
an RTO is more risky than an integrated electric utility where
transmission was a strategic asset. FirstEnergy justifies higher ROEs
by noting a number of sources of risk, including emergence of
distributed generation, vulnerability of firms that are less
diversified than integrated utilities, and quicker phase out of older
generation plants which may result in stranding some transmission
plants. Midwest ISO argues that RTO membership may cause a loss in
earnings due to reduced transmission revenues, higher costs, and
operational risks. United Illuminating believes that risk for
transmission investment is higher for assets controlled by an RTO and
that accelerated depreciation is warranted because transmission
companies can no longer count on captive customers, and industry
changes have the possibility to abandon transmission plant before its
physical life is over. WPSC is in favor of higher ROEs for transmission
owners who join RTOs but not as a pure incentive. WPSC's justification
for higher ROEs would be the greater risk due to removal of pancaked
rates, new generation options, loss of higher state returns, and new
technologies. WPSC supports the other rate incentives as long as the
benefits exceed the costs based on careful examination.
Some commenters address the broad range of proposed incentives. For
example:
Trans-Elect argues in favor of incentives to include:
acquisition premiums, hypothetical capital structures, higher ROE,
accelerated recovery of costs, rate moratoriums, and expedited FPA
section 205 and 203 approvals. Trans-Elect would limit incentives to
those that do not harm transmission customers. It notes that PBRs would
allow transmission owners to share in cost savings but some operating
history may be needed before they are put in place. It argues that
acquisition premiums may assist in the formation of independent
transcos, and suggests that if there is a rate moratorium in place,
RTOs should be allowed to recover acquisition premiums after the
moratorium.
FirstEnergy advocates flow through of cost savings to
owners, non-traditional valuation of assets, flexibility in the use of
levelized rate methodology, retention of hourly non-firm revenues,
deference to management in dispute resolution, elimination of codes of
conduct where there is structural separation, and simplification of
filing requirements. Some of these measures should be offered on a
limited basis to RTOs not yet meeting all of the characteristics and
functions. Incentive plans should weigh costs versus benefits. Cal DWR
goes further, saying that incentives should not be allowed until
benefits are actually proven.
Los Angeles recommends that the Commission consider
several options for the valuation of assets transferred to an RTO in
order to reflect the true value of the assets to native load customers.
Selected options to explore include: an up-front acquisition premium
used to moderate rates to native load customers, provide native load
customers a congestion premium, or grant native load customers an
exemption to congestion charges.
NYPP is in favor of sufficient ROE to provide for
expansion and accelerated depreciation to compensate for increased
risks as opposed to a ``bonus'' type incentive to join an RTO. Its
members contend that this type of incentive should be available to all
transmission owners, not just the ones who meet the NOPR's
characteristics and functions.
A number of commenters note that incentives are needed to
facilitate efficient expansion of transmission assets.\649\
Transmission ISO Participants view the incentive needed to induce new
transmission construction as more important than incentives to
encourage RTO formation. IPCF suggests that FERC should offer
transmission owners incentives to expand their networks without meeting
all of the requirements of becoming an RTO in order to reverse the
trend against building caused by Order No. 888. Williams says that
decisions to expand transmission facilities must be made by for-profit
entities, must be driven by economic considerations, and the returns
allowed must be commensurate with the greater risks today, Williams
cautions that returns for RTO participants certainly should not be at a
rate that results in a penalty.
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\649\ See, e.g., AEP, United Illuminating, PP&L Companies, NU,
Otter Tail, NYPP, FirstEnergy, Transmission ISO Participants,
Allegheny and Salomon Smith Barney.
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Opposing Innovative Pricing. Many commenters oppose the use of
incentives for many different reasons. One common theme is that
incentives are inappropriate because RTO participation should be
mandatory.\650\ PJM/NEPOOL Customers argues that the Commission should
mandate RTO formation because of the transmission owners' duty to
operate in an efficient manner, and because transmission customers will
likely pay the costs of the incentives. Ohio Commission
[[Page 924]]
prefers mandatory participation and questions whether the proposed
incentives will be effective. If incentives are used, Ohio Commission
recommends that the Commission consider evaluating which incentives
will be effective, balancing incentives with disincentives, and
recognize regional differences especially in arriving at a solution for
the Midwest.
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\650\ PJM/NEPOOL Customers, Lincoln, TDU Systems, APPA, WEPCO.
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Another common theme is that the costs of incentives may well
outweigh the benefits of RTO participation. Illinois Commission argues
that if the Commission finds that there are benefits in RTO creation,
they should be mandatory. According to Illinois Commission, the
examples of incentives proposed in the NOPR, i.e., ROE enhancement,
revaluation of transmission facilities at replacement cost, accelerated
depreciation, and flexibility in use of levelized cost, would consist
of money transfers to transmission owners without contributing to cost
control or efficiency. South Carolina Authority is opposed to
incentives or disincentives to promote RTO participation unless a
factual determination is made that they are absolutely necessary.
Similarly, RECA is generally opposed to incentives but would recommend
their consideration if savings to the public are well established. RECA
finds the rate freeze proposal the least objectionable.
APPA advocates mandatory participation in RTOs and strongly objects
to the use of incentives to achieve participation. It argues incentives
would be ineffective because of the small proportion that Commission-
regulated transmission makes up of the total utility revenue compared
to the value of transmission in maximizing generation and merchant
revenue. To be effective, APPA argues that the cost would be so large
that it would not be offset by the benefits of the RTO. Also, APPA
raises the participation issue of whether to give incentives to
existing ISO members. Seattle warns against transmission owners
``dumping'' transmission facilities into an RTO to receive incentives
when those particular facilities are of no benefit to the RTO being
formed.
Some commenters argue that it is inappropriate for the Commission
to provide incentives for the provision of a monopoly service.
Metropolitan argues that incentives should not be offered because many
of the customers who pay for the incentives are the same customers who
paid for the original transmission facilities. TDU Systems argues that
ROEs for transmission service in an RTO is less risky because of the
concentration of monopoly business and the lack of any regulatory gap
since all transmission under an RTO will be regulated by the
Commission. TDU Systems notes that transmission entities, since they
are monopolies, should not earn the same return as firms in other
industries. TDU Systems argues that other NOPR proposals, including
rate freezes, accelerated recovery of costs and investment, and
revaluation of assets, are also an inappropriate enrichment of
transmission owners and are unneeded to attract investors. And TDU
Systems argues that the proposal for an acquisition premium is
troublesome because customers have already been paying for these assets
for years. TDU Systems also suggests it will be difficult to calculate
what level of incentives would be required to persuade a transmission
owner to participate in an RTO and the likelihood of offering a greater
incentive than is needed.
Some commenters suggest that providing incentives would violate the
Commission's statutory requirement to set rates at just and reasonable
levels. NRECA believes that transmission owners should not be rewarded
for unjust conduct with incentives and that the Commission should rely
on standard cost-of-service based rates. TAPS, which favors mandatory
RTO formation, argues that incentives are unnecessary and could nullify
the benefits of electric industry restructuring. TAPS argues that
incentive rates, including each of the examples suggested in the NOPR,
would violate FPA's requirement for just and reasonable rates because
they do not reflect the cost of providing transmission service. TAPS
does recommend that the Commission remedy unintended disincentives such
as utilities' fear of the unknown. UAMPS also favors mandatory
participation, and argues that incentives would unfairly raise
transmission costs to the benefit of monopoly transmission owners.
UAMPS also argues that it is not feasible to divide the benefit of RTO
participation before these benefits are even known. In response to the
comments of several IOUs, UAMPS argues that the claim that stand-alone
transmission companies are more risky is unsubstantiated and should be
heard in another proceeding. NASUCA argues that EEI and others are
incorrect in saying that the DCF method does not produce reasonable
results. According to NASUCA, the DCF method takes explicit account of
the transmission owners' risk and the realities of the current
regulatory climate.
Some commenters suggest that incentives will not necessarily
increase RTO participation, or will not necessarily produce the
benefits which the NOPR describes. For example, ICUA notes that
incentives cannot be relied upon to achieve participation by all
necessary utilities. WPPI opposes incentives to participate in RTOs
citing the RTO activity that has already taken place without incentives
and the contention that the Commission should designate boundaries and
require participation within one year.
Wyoming Commission does not agree that increasing the ROE will be
sufficient to encourage more transmission building. According to
Wyoming Commission, low building activity may be attributable to
difficulty in meeting siting requirements, uncertainty related to
retail access and native load, and competition for more localized
generation. Wyoming Commission does not think that the Commission
should rush too quickly into some innovative ratemaking before the
industry has committed to making RTOs work as planned. And the Wyoming
Commission suggests that a higher ROE for transmission investment may
discourage a balanced consideration of options.
A number of commenters generally opposed incentives, believing that
sanctions or penalties against public utilities which do not join RTOs
is superior to providing incentives. NASUCA argues that mandates or
disincentives for not joining at the time of merger or market-based
rate requests should be used rather than incentives. Incentives would
not be cost based and would therefore make rates unjust and
unreasonable. As to specific incentive proposals, NASUCA says that
using replacement cost for transferred assets would allow higher rates
than necessary as an incentive and would charge customers for assets
they have already paid for. Such incentives could set off a
transmission sell-off in anticipation of an adjustment and some
companies may refuse to form transcos until they were granted the same
adjustment as any other company. NASUCA is opposed to accelerated
depreciation of assets for similar reasons. NASUCA also states that
incentive rates could harm electric competition by increasing
transmission costs. And Big Rivers states that the incentives proposed
in the NOPR are inappropriate for rural electric cooperatives.
Other Comments. A few commenters did not take an explicit position
on the use of incentives, but made general comments on the Commission's
proposals. For example:
Cal ISO is more concerned that there not be disincentives
to RTO
[[Page 925]]
participation than offering incentives. In particular, Cal ISO points
out the disincentive created by the Commission's annual fee policy,
from which temporary relief was granted \651\ but a permanent solution
is needed.
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\651\ PJM Interconnection L.L.C., 88 FERC para.61,109 (1999).
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New Century recommends against the use of ``remedial
measures'' to encourage participation such as the suspension of market-
based rate authority, denial of merger authority, and denial of non-
pancaked rate access to RTO facilities.
Entergy says that the NOPR's statements on incentives are
vague and would cause too much regulatory uncertainty. Entergy asks the
Commission to provide more explicit provisions as to what incentives
would be approved.
Canada DNR is concerned that Canadian transmission owners
not be placed at a disadvantage for non-participation in an RTO in
terms of incentives and disincentive.
SRP supports incentives as long as they are applied to
both public power entities and investor owned companies equitably.
Metropolitan contends that it would not receive much
benefit from any incentives offered to RTOs because it is a public
entity and because its asset base is so heavily depreciated. However,
replacement cost methodology could be of use in mitigating cost shifts
from rolling in higher costs of other utilities.
Commission Conclusion. As noted earlier, the NOPR and the comments
use the term incentive pricing as a label for the transmission pricing
reforms that we raised for discussion. Certainly, good pricing affects
behavior. But good pricing also achieves a valuable goal, in terms of
competition, system expansion, or efficient practices that benefit more
than the transmission owners or the RTO. In this section we provide
greater specificity with respect to certain transmission pricing
mechanisms that may be appropriate for RTOs. These mechanisms were
described in the NOPR or otherwise proposed by commenters, and are
included in the amended regulatory text.\652\ We emphasize that we do
not intend this policy guidance to be interpreted as a Commission
regulatory requirement for a specific transmission pricing method, nor
should it be interpreted as a guarantee that the Commission will
approve any particular innovative pricing proposal. We emphasize that
all innovative pricing proposals filed by RTOs must be fully and
adequately supported in accordance with this Final Rule and the
regulatory text. We believe that we are providing sufficient guidance
for RTOs to make critical decisions with respect to transmission
pricing policies. If industry participants believe that further
guidance from the Commission is needed to resolve transmission pricing
issues, they may request such guidance through requests for declaratory
orders or further rulemakings.
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\652\ Note that these mechanisms are discussed below on a
thematic basis, although the regulatory text lists them on an
individual basis.
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As discussed earlier, transmission pricing reform is needed as a
result of the rapid restructuring of the industry that is underway,
particularly with respect to changes in the ownership and control of
transmission assets, and changes in the transmission services being
provided in competitive generating markets. As a result of these
changes, and consistent with a number of commenters' arguments, we have
concluded that the Commission, at a minimum, needs to mitigate various
``disincentives'' that may prevent transmission owners from efficiently
operating their systems. Commenters cite to the potential that
transmission owners will earn lower returns for providing unbundled
transmission service than they earned for providing bundled service,
even though risks associated with transmission ownership have
increased. Commenters suggest a number of sources of increased risk.
One source is the potential for bypass of transmission assets due to
distributed generation and the phasing out of older generators from
service. Other sources are directly related to RTO formation. For
example, some commenters assert that stand-alone transmission companies
(e.g., transcos) are riskier because they have a less-diversified
portfolio of assets than a vertically integrated utility. Other
commenters argue that participation in an RTO that is an ISO is
inherently riskier, suggesting that increased risk comes from ownership
of transmission assets that are ceded for purposes of operational
control to another, non-affiliated entity.
Other commenters argue that a reevaluation of transmission pricing
is needed because it is absolutely critical that the transmission grid
support competitive generating markets, and the only way that the
Commission can ensure this will happen is to pursue pricing policies
that encourage it. Some commenters suggest that because the
contribution of transmission to total costs of energy is relatively
small\653\ overinvestment in transmission will not significantly affect
delivered electricity prices. Further, the Commission should be much
more concerned about underinvestment, not overinvestment, in the
transmission grid.\654\ Stated another way, an efficient transmission
grid is a prerequisite to achieving competitive generating markets, and
the potential benefits for consumers far exceed any limited
overinvestment that may occur on transmission service. A related
argument is that efficiency benefits of improved transmission service
will be captured by producers and customers of generation, not
transmission providers; therefore, greater incentives for RTOs to
provide good transmission operations and efficient investments in the
grid are warranted.
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\653\ For example, Salomon Smith Barney, citing to an article by
Leonard Hyman notes that the direct, total osts of transmission
service represents about six to seven percent of the average
customer's bill, and raising transmission prices even as high as 25
percent in order to attract capital adds only two percent to the
overall electric bill.
\254\ Professor Joskow points out that the external factors,
such as licensing requirements, the need for rights of way, and
NIMBY (i.e., ``not in my backyard'') opposition to transmission
expansion already places significant constraints on overinvestment
in major new transmission projects.
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The NOPR sought comments on several procedural issues related to
transmission pricing reform and incentives. One issue was whether these
pricing reforms should be available to participants of existing ISOs,
or be available only to transmission owners that join RTOs as a result
of the Commission's RTO initiative. We have concluded that members of
an existing ISO organization that satisfy the minimum RTO requirements
in the regulatory text should be allowed to seek transmission pricing
reform as newly formed RTOs, so that they can avail themselves of the
same incentives for efficient operation of and investment in the
transmission grid. Furthermore, we believe that the Commission's
approach to evaluating innovative transmission reforms should be
neutral with respect to the organizational structure of the Applicant,
so that RTOs that own transmission assets as well as RTOs that do not
own transmission assets would be equally eligible for such ratemaking
treatments.
Another issue is whether the Commission would prescribe which
transmission pricing reforms it would accept and which it would not
accept, or whether the Commission would consider such proposals on a
case-by-case basis. We conclude that a case-by-case evaluation of
transmission pricing
[[Page 926]]
reform proposals is appropriate, given that such proposals are not
generic in nature, and a proposal may be appropriate in some RTO
circumstances but not in others. However, the Commission believes some
further specificity on transmission pricing reform is warranted to
provide industry participants with the Commission's evolving views, as
RTOs consider the appropriateness of various reform measures.
Therefore, we provide greater specificity on three transmission
pricing reform measures: (1) ROE; (2) levelized rates; and (3)
accelerated depreciation and incremental pricing for new transmission
investments. We note that some of these measures may be useful only as
transitional devices that may be necessary to spur the prompt creation
of RTOs and, therefore, we intend to offer these pricing options only
for a defined period of time, as detailed later in this Final Rule. On
the other hand, other pricing reforms may be useful as permanent
features, and will not be limited only to the period during which RTOs
are forming. Finally, while certain of these innovative pricing
proposals may be more helpful to one RTO structure than another (e.g.,
ISO vs transco), we do not believe that any of these pricing proposals
would be incompatible with any particular structure adopted by RTOs.
a. Return on Equity (ROE). More commenters focused on ROE-based
proposals than any other type of transmission pricing reform. These
commenters make two main points. One argument is that higher ROEs will
be demanded by the market as a matter of course as the industry
restructures and the risk of transmission business increases, and the
Commission must allow higher ROE to reflect participation in RTOs. A
second argument is that joining an RTO adds another level of risk that
warrants a specific adjustment to ROE (e.g., going to the high end in
the range of reasonable ROE, or a specific basis point
adjustment).\655\
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\655\ Some commenters recommend abandoning the DCF method of
calculating ROE entirely. We are not adopting that recommendation.
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As discussed above, commenters urge the Commission to provide
flexibility in allowing ROE-based programs for RTOs. Many of these
commenters specifically urge the Commission to ensure that there are
sufficient incentives for an RTO to make needed investments in
transmission infrastructure. On the other hand, a number of commenters
oppose ROE-based programs on the grounds that they constitute a
``bribe'' for utilities to provide service that they are statutorily
required to provide.
We believe that there are a number of issues surrounding ROE that
must be addressed by the Commission. For example, we believe that
allowing an RTO to propose a formula rate for determining return on
equity is consistent with our view that risks and rewards for
transmission owners should reflect market-like forces to the extent
possible. Allowing a formula rate of return would decouple a
transmission owner's earnings from its own equity valuation, and would
tie it more to external standards such as industry-wide performance.
Such an approach is also consistent with the benchmarking that may
occur under PBR.
We also agree that the risk profile of the transmission business is
changing as the industry restructures, and that it may vary as a
function of the structure each transmission company elects. For
example, the risk associated with owning facilities that are leased for
a sum certain to another entity operating an RTO may be different from
the risk associated with operating a stand-alone transco that is facing
a significant expansion program. We therefore conclude that ROE-based
initiatives--as well as other ratemaking reforms discussed below--may
be applicable to all types of RTOs, without regard to organizational
structure.
We further recognize that historical data typically used to
evaluate ROEs may not be reliable since it reflects a different
industry structure from the one that exists recently. And we believe
that as patterns of transmission ownership and control evolve, new
approaches to compensating transmission owners for different capital
structure mixes may be warranted, including allowing a transmission
owner to seek a return on invested capital, independent of its exact
capital mix.\656\ As noted above, we are willing to consider
moratoriums tied to the rates the transmission provider earns on
transmission assets with respect to bundled retail power sales, and the
moratorium option may be tied to the existing transmission rate level,
or to the existing return on equity.\657\
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\656\ As noted infra, this is one of the pricing reforms that
will be available only for a defined transition period during which
RTOs are being established.
\657\ As noted infra, moratoriums are among the pricing reforms
that will be available for a defined transition period during which
TROs are being established.
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Finally, we agree that the uncertainty associated with the
transition of the industry, and in particular participation in RTOs,
may increase risks in the short-run. Certainly, our goals have not
changed, which are to ensure that customers have access to
nondiscriminatory service at just and reasonable rates, and that
transmission owners have an opportunity to earn a reasonable rate of
return on their investment. We recognize that in this era of rapid
change, new approaches to setting ROE may be needed to implement that
standard. We therefore invite RTOs to submit proposals for ROE-based
programs that are in conformance with these new approaches.
We note that pricing reforms involving ROE would clearly be
compatible with all types of RTO structures that involve a
determination of return on equity on transmission rate base, e.g.,
transcos, ISOs, or tiered organizational structures.
b. Levelized Rates. A number of commenters argue that the
Commission should allow RTOs to adopt levelized rates. A levelized rate
is designed to recover all capital costs through a uniform, nonvarying
payment over the life of the asset, just as a traditional home mortgage
payment does. The Commission, has held in a number of recent
proceedings that both levelized and nonlevelized rates can produce
reasonable results, depending on the circumstances.\658\ The Commission
stated in these cases that where a utility proposes to switch from a
nonlevelized net plant rate design method, ``[i]n supporting such a
switch, a utility must prove that its proposed method is reasonable in
light of its past recovery of capital costs using a different method.''
\659\
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\658\ See, e.g., American Electric Power Service Corp., Opinion
440, 88 FERC para. 61,141 at 61,441-42 (1999) (AEP); Allegheny Power
Service Corp., Opinion 433, 85 FERC para. 61,275 at 62,117 (1998);
Kentucky Utilities Co., Opinion 432, 85 FERC para. 61,274 at 62,100-
03 (1998) (KU).
\659\ See AEP, 88 FERC at 61,441-42.
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The Commission believes that levelized rates are preferable in an
RTO environment because all customers, regardless of when they take
service, face the same price. Also, given a depreciated investment
base, levelized rates based on existing investments will be higher than
non-levelized rates and will address concerns that RTO formation will
decrease revenues.
The principal objection to allowing levelized rates for RTOs is
that it may raise RTO transmission rates in the short-run. The
Commission has been reluctant outside the RTO context to approve
switches from or to levelized rates proposed by public utilities under
traditional cost-of-service ratemaking because of the opportunities
that switching may provide for utilities to
[[Page 927]]
over recover transmission costs. However, consistent with our
discussion above of how market restructuring may require innovation in
transmission pricing, we believe that levelized rates may be
appropriate in circumstances, as here, where an RTO reflects a fresh
start with respect to the provision of transmission services, and
potentially the customers for those services. This is especially true
in cases where RTO formation occurs coincident with market
restructuring, such that the transmission customers of the RTO may be
significantly different than the traditional, captive customers, that
formerly took transmission service. We therefore conclude that the
Commission should allow increased flexibility for RTO proposals that
include ratemaking practices based on levelized rates. Clearly, this
pricing reform, which relates to the method used to compute the
transmission revenue requirement in the first instance, is compatible
with any type of RTO structure, e.g., transco, ISO, or tiered
structure.
c. Accelerated Depreciation and Incremental Pricing for New
Transmission Investments. While a number of commenters have suggested
accelerated depreciation as a transmission pricing reform that should
be considered, these arguments are premised on the possibility that
transmission costs will be stranded by changes in the industry, such as
bypass of portions of the transmission system. We think that these
concerns are speculative at this point in the industry's restructuring.
For example, we are not convinced that the problem of stranded
transmission assets is anywhere near the level of concern that stranded
generating assets represents.\660\ In any event, should certain limited
transmission facilities become stranded, nothing prevents proposals to
recover prudent costs under traditional ratemaking policies.
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\660\ See Order No. 888, wherein the Commission allows recovery
of stranded costs (primarily generation related) only when they are
unrecoverable from customers that depart the system, and only upon a
definitive showing that the utility had a reasonable expectation of
continuing to serve the customer after the customer's departure.
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We will, however, make a distinction between accelerated
depreciation for existing transmission assets, and accelerated
depreciation for new transmission facilities. While we will not bar
proposals of this type for existing assets, we cannot give any
encouragement to them in the Final Rule. On the other hand, we believe
that it is appropriate for the Commission to provide those willing to
make new transmission investments with the flexibility to propose that
such assets follow non-traditional depreciation schedules. The purpose
of providing such flexibility is to remove disincentives for the
construction of new facilities. We think such flexibility is warranted
because the fundamental nature of transmission investment may be
changing with respect to the entities that will make investments in the
transmission system in the future and who pays for the new transmission
facilities. Furthermore, given the rapid changes in market structure
and dynamics that have occurred and will likely continue, we are not
certain that traditional determinations of the economic life of new
transmission facilities remain appropriate.
In addition, we believe it is appropriate for the Commission to
provide flexibility for pricing of new facilities, such that proposals
for pricing of new facilities that combine elements of incremental
prices with embedded-cost access fees will be considered. Although we
are concerned that such ratemaking practices have the potential to lead
to higher prices for new transmission services, and also potential to
lead to overinvestment in transmission facilities, e.g., where
generation redispatch could accomplish the same objective at lower
cost, we believe that such practices, if carefully constructed, will
create appropriate incentives for efficient investment in new
transmission facilities. We also believe that this pricing reform will
be attractive to all types of RTO structure, e.g., transcos, ISOs, or
tiered structures. It may also be used by any RTO that chooses to rely
on third parties to construct new facilities.
d. Acquisition Adjustments. A number of commenters suggest that the
Commission adopt new policies for acquisition adjustments that would
provide assurances to purchasers of transmission facilities that
acquisition premiums would be recoverable through transmission rates.
We do not adopt this suggestion in this Final Rule.\661\
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\661\ See Minnesota Power & Light Company and Northern States
Power Company, 43 FERC para. 61,104 at 61,342 (1988), for a
discussion of the Commission's existing policies with respect to the
ratemaking treatment for acquisition premiums. See also Duke Energy
Moss Landing LLC, et al. 83 FERC para. 61,318 (1998).
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8. Additional Ratemaking Issues
A number of comments on ratemaking issues address topics not
specifically enumerated in the NOPR.
Comments
Williams, CSU, Alliance Companies and WPSC encourage the
Commission to consider rate designs based on mileage or network usage.
Great River, NCPA and IMPA raise the concern that
cooperatives and public power entities need assurance that they will
receive full customer credit and compensation as was explicitly stated
in Order No. 888. SoCal Edison claims that full compensation will be
forthcoming and will not be a problem.
Ohio Commission recommends that a tariff for border
transactions (between RTOs) be implemented that makes the market over
the combined regions seamless to persuade some regional organizations
to combine.
PPC notes that IndeGO ran into a problem with developing
rates for combined systems with very different levels of quality and
cost, and that systems at a position of lower quality should be
required to meet combined system standards at their own cost.
Puget argues that RTO rates must provide for the
collection of stranded costs.
PSNM sees a problem with load-side generation customers
who do not have to pay their fair share of total system transmission
costs.
Powerex objects to the proposal to segment companies'
service areas into sub-zones for pricing purposes.
Alliance Companies and AEP favor the flexibility in RTO
rate filings that would allow companies to make proposals that reflect
market forces.
Alliant Energy is concerned that RTO structures promote
workable markets and that transmission rates be permitted to include a
fair accounting of RTO start-up costs.
East Texas Cooperatives recommends that RTO pricing
structures adequately compensate small transmission owners who join the
RTO, creating an incentive to join and be a more equitable system.
Georgia Transmission says that ratemaking for RUS
borrowers must take into account the requirements of any RUS loans. In
addition, Georgia Transmission recommends that the cost of RTO
formation be allowed in RTO rates.
Metropolitan, Cal DWR, and SoCal Cities favor the use of
time-of-use pricing or off-peak rates for transmission.
Oregon Office recommends load-based fees for transmission
rather than volume based charges.
IMEA argues that the RTO start-up and administrative costs
should be
[[Page 928]]
allocated to all customers including bundled native retail load. In
contrast, LG&E notes that if native load is assigned RTO administrative
costs there may be under recovery because of retail rate freezes.
Industrial Customers argue that assets used for remote
generation should be excluded from the RTO.
Merrill Energy says that the incremental pricing of new
transmission upgrades prevents expansion because customers are
unwilling to pay.
NERC is concerned about the recovery of costs related to
reliability-related generators.
NRECA is concerned about compensation by an RTO for low-
use transmission facilities owned by cooperatives, because large
transmission owners are opposed to revenue sharing. NRECA notes that if
a cooperative joins an RTO, transactions for all will increase and
there is more to share. Also, there should be protection for joint use
agreement income.
Project Groups says that pricing must facilitate entry and
usage by efficient, environmentally benign resources. Grid access
barriers to these resources need to be eliminated. NMA/WFA/CEED respond
by saying that the policies that Project Group objects to are equitable
overall.
Seattle argues that hub and spoke pricing should be used
and discrete inter-regional tariffs are needed.
NWCC notes that the characteristics of wind-produced power
presents problems fitting into an RTO pricing arrangement and says that
wind power works best with energy-based pricing systems.
Detroit Edison advocates a two-part pricing structure
similar to that proposed by the Alliance RTO. It includes a local rate
and a regional rate. To encourage participation, Detroit Edison
proposes that the Commission allow RTOs to develop market-based
transmission pricing methodologies.
Commission Conclusion. Commenters raise a number of important
ratemaking issues that must be considered in the establishment of RTOs.
We clarify that the reasonable costs of developing an RTO may be
included in transmission rates. Other issues are at a level of detail
and specificity that we do not believe should be resolved in this Final
Rule. Therefore, these issues will be considered as they apply to
individual RTO proposals on a case-by-case basis.
9. Filing Procedures for Innovative Rate Proposals
We shall evaluate all RTO proposals including any innovative rate
treatment based on the applicant's demonstration of how the proposed
rate treatment would help achieve the goals of regional transmission
organizations, including efficient use of and investment in the
transmission system and reliability benefits. We shall also require
applicants to provide a cost-benefit analysis, including rate impacts,
and demonstrate that the proposed rate treatment is appropriate for the
proposed RTO and that the rate proposal is just, reasonable, and not
unduly discriminatory.
In addition, pricing proposals involving moratoriums and returns on
equity that do not vary according to capital structure may not be
included in RTO rates after January 1, 2005. Thus, if the Commission
approves an RTO rate proposal involving, e.g., a rate moratorium,
unless otherwise ordered, the moratorium would end on or before January
1, 2005. We are limiting these rate proposals for a defined period
during the formative stage of RTOs because, while either may be
appropriate as transitional rate mechanisms, they do not promote long-
term efficiency through rate design. In addition, the limited duration
for these rate treatments will encourage the earliest possible filings,
while at the same time giving some flexibility to those filings that
may be delayed.
H. Other Issues
1. Public Power and Cooperative Participation in RTOs
In the NOPR, the Commission stated its objective of encouraging all
transmission owning entities including transmission owned or controlled
by public power entities and cooperatives, including Federal Power
Marketing Agencies (PMAs), Tennessee Valley Authority (TVA), and other
state and local entities to place their transmission facilities under
the control of an RTO.\662\ To this end, we expressed an expectation
that public power entities would fully participate in the collaborative
process for forming RTOs.\663\ In addition, we noted that some public
power entities filed open access tariffs with the Commission and others
are participating in ISOs and other regional institutions. The
Commission, however, is aware and concerned that public power entities
face several difficult issues regarding RTO formation and
participation.\664\
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\662\ FERC Stats. and Regs. para. 32,541 at 33,756-57.
\663\ Id. at 33,757.
\664\ See id.
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The first issue is the Internal Revenue Service (IRS) Code
``private use'' restrictions on the transmission facilities of public
power entities financed by tax-exempt bonds. We noted that IRS
temporary regulations may allow facilities financed by outstanding tax-
exempt bonds to be used to wheel power in accordance with Order No.
888, but that these temporary regulations may not allow the issuance of
additional tax-exempt bonds for expanded transmission or permit
transfer of operational control of existing transmission facilities
financed by tax-exempt bonds to a for-profit transco.\665\ The
Commission asked for comments on the extent to which IRS Code
restrictions may limit the transfer of operational control or other
forms of control, or ownership of public power transmission facilities
to a for-profit transco or other forms of an RTO.
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\665\ Id.
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The Commission also requested comments on state and local charter
limitations, prohibitions on participating in stock-owning entities,
the current policies of various local regulatory entities that affect
or impede full public power participation in RTOs and legal
restrictions or other considerations regarding PMAs that prevent their
participation in RTOs. We questioned whether the Commission should
consider some forms of associate membership or participation and other
special accommodations in order for public power entities to overcome
obstacles to RTO participation.\666\
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\666\See id.
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Comments. Most commenters support the Commission's position that a
properly formed RTO should include all transmission owners, including
cooperatives and public power, in a specific region.\667\ As EEI notes,
public power participation will enhance the reliability and economic
benefits of an RTO. Furthermore, some commenters argue that in some
areas of the country, especially in the Northwest and Southeast, RTO
formation may be impractical without public power participation.\668\
Virtually all commenters recognize that regulatory and legal
restrictions exist that may impede public power and cooperative
participation in RTOs. EEI, SERC and Metropolitan argue that the best
way to
[[Page 929]]
facilitate non-jurisdictional utility participation in RTOs is for the
Commission to avoid a ``one-size-fits-all approach'' and to provide
flexible rules in order to accommodate the unique needs of public power
entities.
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\667\ See, e.g., Oglethorpe, Allegheny, Montana Power, CREDA,
Tallahassee, Arkansas Cities, PPC, California Board, Industrial
Customers, Entergy, BC Hyrdo, Powerex, Aluminum Companies, MEAG,
Arizona Commission, Nevada Commission, East Texas Cooperatives,
Lincoln, NPPD, Wyoming Commission, Georgia Transmission, WPSC, PGE,
Montana Commission, SMUD, Cal ISO, MLGW, Loveland Customers, NASUCA,
Duke, LG&E, CP&L, South Carolina Authority, STDUG, NCPA, PP&L
Companies, Desert STAR, PG&E and EEI.
\668\ See, e.g., EEI, Snohomish, MLGW, Loveland Customers,
Montana Commission, Wyoming Commission, Aluminum Companies,
Industrial Customers and Powerex.
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Section 141 of the IRS code imposes limitations on the use of non-
governmental entities of public power facilities financed with tax
exempt bonds. These private use limitations restrain the form and
extent of participation by public power systems in RTOs. The key
private use limitation that is material to RTO participation is a bar
on the sale of the output of facilities financed with tax exempt debt
to non-governmental entities on terms not available to the general
public. Commenters note that in January 1998, the IRS issued temporary
regulations relating to the application of the private use rules to
public power entities that provide some relief for transmission
facilities. These temporary regulations permit issuers of outstanding
tax exempt bonds to offer open access transmission services and
competitive access to distribution systems, and to join RTOs, provided
that certain conditions are met, particularly that the facilities
continue to be owned by the municipal entity. The temporary
regulations, however, do not provide the same relief to issuers of new
tax exempt bonds. Many commenters assert that the temporary regulations
will expire in January 2001 and that these regulations are incomplete
and not permanent.\669\ LPPC notes that the ability of issuers to
continue to rely on the temporary regulations after expiration is
unclear and therefore, issuers taking actions permitted under the
temporary regulations risk having tainted the tax-exempt status of
their bonds on the expiration of the regulations.
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\669\ E.g., Los Angeles, SoCal Cities, LPPC, APPA, Tacoma, NCPA,
SRP, TAPS, EEI, NPPD and East Texas Cooperatives.
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Commenters offer varying solutions to the ``private use''
restriction problem. Many commenters urge the Commission to actively
attempt to influence the IRS and Congress to remove and/or mitigate the
tax impediment.\670\ SRP also recommends that the Commission require
all RTOs to demonstrate that they have made a good faith effort to
reduce barriers to participation and to accommodate legal restrictions
faced by potential participants. Arkansas Cities proposes a
transitional grandfathering of existing tax-exempt bonds. Arkansas
Cities notes that such legislation is pending in Congress and is
identified as the Bond Fairness and Protection Act (BFPA). Arkansas
Cities states ``that if enacted, the BFPA would clarify tax laws and
regulations governing tax exempt bonds so that publicly owned utilities
would be able to participate in the development of competitive electric
utility markets.'' \671\ Duke asserts that the leasing of transmission
facilities to an RTO is a viable option. Moreover, LPPC states that
public power entities have to be allowed to participate in a way that
permits them to retain sufficient operational control of their
transmission systems to stay within the private use limitations. In
addition, LPPC, Snohomish, Arkansas Cities and East Texas Cooperatives
argue that public power entities need an opt-out provision if their tax
exempt status is threatened. TEP recommends that the final rule contain
a template for addressing how transactions can be administered if they
involve the use of tax exempt facilities. TEP proposes that (1) an RTO
should operate in a manner that either preserves the tax exempt status
of such facilities or provides compensation to the facilities' owner to
the extent it incurs economic harm; and (2) that an RTO should develop
specific rules governing the operation and administration of tax-
exempted financed facilities.
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\670\ See, e.g., EEI, TAPS, SRP, Georgia Transmission, Arkansas
Cities, Nevada Commission, PP&L Companies, TANC, Desert STAR, NCPA,
Montana-Dakota Enron/APX/Coral Power and Tallahassee.
\671\ See Reply Comments of Arkansas Cities at 6.
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NRECA details the obstacles confronting cooperatives including the
requirement that in order to maintain tax exempt status under Section
501(c)(12) of the IRS Code, at least 85 percent of a cooperative's
income must come from the cooperative's members. If such member-derived
revenue does not equal at least 85 percent of total revenue, then a
cooperative would lose its tax-exempt status. Georgia Transmission
argues that there is a real risk that participation in an RTO could
result in a cooperative losing its tax exempt status if the revenue
received from the RTO (assuming the RTO is not a member of a
cooperative) exceeds 15 percent of the cooperative's total income. The
revenue received from the RTO would stem from revenue attributed to use
of the cooperative's transmission facilities controlled by the RTO.
One remedy to this problem, suggested by AEPCO and Wolverine
Cooperative, is to increase an RTO's compensation to the cooperative to
include a gross-up of net margins to cover the income tax expense.
Under this approach, the RTO would pay the cooperative the full revenue
requirement for the transmission facilities, including any other taxes.
East Kentucky proposes that a conduit or a pass-through relationship
between the RTO and the cooperative would satisfy the IRS restrictions
and allow a cooperative to maintain its member-derived character.
According to East Kentucky, the RTO would act as an agent for the
cooperative by collecting the transmission revenues and holding these
revenues in a trust on behalf of the cooperative. Furthermore, Georgia
Transmission suggests that the Commission allow a cooperative to leave
an RTO if it appears that it may lose its tax exempt status because of
the level of RTO and other non-member revenue it expects to receive in
a given year.
Another impediment to public power participation in RTOs is
mortgage restrictions. AEPCO notes that under the terms of a typical
RUS mortgage, either transfer of control of transmission assets to an
RTO or a sale, unless authorized by RUS, would be an event of default.
East Texas Cooperatives argues that the Commission should require all
RTOs to accommodate mortgage restrictions by allowing cooperatives to
retain control of their facilities until the mortgage restriction is
lifted or a creditor or RUS approves the transfer. In its comments, RUS
recognizes that development of RTOs may offer considerable benefits to
RUS borrowers, and RUS states that it is exploring means to facilitate
borrower participation consistent with the Rural Electrification Act
and RUS's fiduciary duties to the U.S. Treasury and taxpayers.
According to several commenters,\672\ many public power entities
operate under explicit state constitutional restraints with respect to
their ability to participate in the ownership of a privately-owned
RTO.\673\ Further, some state constitutions include restrictions on the
use of public funds.\674\ Several states, however, expressly authorize
public power entities to join with other
[[Page 930]]
public entities in the ownership and operation of electric transmission
facilities.\675\ In addition, state and local laws impose additional
restrictions on the activities and operations of public power entities
that could affect the operations of any RTO in which they hold an
ownership interest. For example, some laws prohibit the sale or lease
of transmission facilities to a for-profit entity.\676\
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\672\ See, e.g., LPPC, NPRB, Snohomish, Clarksdale, MEAG and
CAMU.
\673\ For example, the Nebraska Constitution provides: ``No
city, county, town, precinct, municipality or other sub-division of
the state, shall ever become a subscriber to the capital stock, or
owner of such stock, or any portion or interest therein of any * * *
private corporation or association.''
\674\ For example, the Colorado Constitution states: ``Neither
the state, nor any county, city, town, or township shall lend or
pledge credit or faith thereof, directly or indirectly, in any
manner to, or in aid of, any person, company or corporation, public
or private, for any amount, or for any purpose whatever; or become
responsible for any debt, contract or liability of any person,
company or corporation, public or private, in or out of the state.''
\675\ For example, Washington law provides: ``Any two or more
[Washington] cities or public utility districts or combinations
thereof may form an operating agency * * * for the purpose of
acquiring, constructing, operating, and owning plants, systems and
other facilities and extensions thereof, for the generation and
transmission of electric energy and power.''
\676\ Nebraska law provides that: ``[T]he plant, property, or
equipment of a public power district shall never * * * by outright
sale, or lease, become the property or come under the control of any
private person, firm, or corporation engaged in the business of
generating, transmitting, or distributing electricity for profit.''
Nebraska Rev. Stat. Sec. 70-646.01.
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In states in which laws allow a public utility district to sell or
lease its transmission facilities to an RTO, the laws impose
requirements on such sale or lease. For instance, Washington law would
require the property to be offered in a competitive bidding process,
and no sale could occur without voter approval.\677\ Furthermore, LPPC
notes that state and local laws in California, Florida, Nebraska, and
Texas would require the approval of the City Council, the public
utility commission, the governing board, or other governmental
authority before a transfer of facilities could occur. CAMU and NPPD
also state that many municipals and power authorities have statutory
authority to condemn property and that it is unlikely that this eminent
domain authority can be delegated to an RTO.
---------------------------------------------------------------------------
\677\ See LPPC at 17.
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Enron/APX/Coral Power notes that an unwillingness to participate in
an RTO for commercial reasons should render non-jurisdictional
transmission owners ineligible for RTO services and savings. Moreover,
Duke argues that public power must take the lead in resolving these
issues for themselves. Duke notes that investor-owned utilities have
overcome numerous obstacles to become RTO participants. Furthermore,
Enron/APX/Coral Power argues that public power and other non-
jurisdictional transmission owners that elect to share in the benefits
of an RTO must be held to the same characteristics and functions as
jurisdictional transmission owners. Cinergy suggests that the
Commission commence regional technical conferences to address legal
obstacles to public power entities' participation in RTOs and to
explore possible alternatives to operational and functional integration
of public power systems into RTOs.
Commenters also address issues relating specifically to PMAs. Many
commenters support the expansion of the FPA to give the Commission
jurisdiction over all transmission owners.\678\ CREDA points out that
PMAs are restricted by: (1) enabling statutes; (2) congressional
appropriations; (3) the inability to grant indemnification without
congressional approval; (4) the sovereign immunity doctrine; and (5)
their load serving responsibilities. MLGW notes that other PMA
restrictions include the TVA ``fence restriction,'' whereby, TVA's
organic statute prohibits TVA from performing any transmission service
that would result in the delivery of power generated by TVA outside the
specified TVA service area. MLGW further notes that existing long-term
contracts between TVA and its distributors are another barrier to RTO
participation by PMAs. To remedy these problems, TVA and others \679\
argue that the Final Rule should provide enough flexibility to ensure
that public power obstacles can be addressed and mitigated.
---------------------------------------------------------------------------
\678\ See, e.g., LG&E, Otter Tail, WPSC, Alabama Commission,
Montana Commission, and DOE.
\679\ See, e.g., CAMU, CMUA, STDUG, CREDA, NY ISO, Powerex, PP&L
Companies, Desert STAR, CP&L, LPPC, MEAG and Tennessee Authority.
---------------------------------------------------------------------------
On the issue of whether the Commission should consider special
accommodation, commenters disagree over whether the Commission should
provide incentives to public power entities in order to make RTO
membership financially attractive. EEI and APPA urge the Commission to
adopt an RTO policy that makes membership attractive to public power
entities in terms of efficiency and benefits.
SoCal Edison is strongly opposed to the Commission providing
incentives in the form of uniform grid-wide rates or transmission
credits. SoCal Edison argues that these incentives are nothing more
than inequitable cost shifts to retail ratepayers. Likewise, Duke
argues that public power entities should not be provided with
competitive advantages in order to encourage voluntary RTO
participation.
In contrast, IMPA and SoCal Cities urge the adoption of a final
rule that provides proper credits or compensation for facilities
contributed to an RTO, including customer-owned facilities.
Furthermore, East Kentucky states that return on equity can be
mitigated by allowing cooperatives to earn a rate of return similar to
investor-owned utilities. Vernon argues that the entitlement for
transmission facilities contributed to the RTO grid and the appropriate
level of compensation are matters that should not be determined
nationally on a generic basis, but rather, should be decided in the
context of each RTO. SRP supports PBRs and other incentives as long as
they are applied to both public power entities and investor owned
companies equitably. Metropolitan contends that it would not receive
much benefit from any ROE incentives offered to RTOs because it is a
public entity and because its asset base is so heavily depreciated.
However, a replacement cost methodology could be of use in mitigating
cost shifts for Metropolitan due to rolling in higher costs of other
utilities. Oregon Office recommends that public power entities be
eligible for the same incentives as offered others to the extent that
the Commission regulates their rates.
A few commenters discuss issues relating to public power and the
filing requirements. South Carolina Authority states that any RTO
proposal should contain a detailed description of the efforts made by
petitioners to accommodate the transmission facilities of publicly
owned utilities. Similarly, SRP, APPA and LPPC recommend that the
Commission require each RTO proposal to demonstrate: (1) how a good
faith effort was made to accommodate public power participants,
particularly deciding ownership structure; and (2) where public power
entities are not included, why there are no reasonable terms and
conditions under which the RTO could accommodate its participation.
Lincoln and Cinergy essentially concur.
Commission Conclusion. We reaffirm our preliminary determination
that a properly formed RTO should include all transmission owners in a
specific region, including municipals, cooperatives, Federal Power
Marketing Agencies (PMAs), Tennessee Valley Authority and other state
and local entities. As noted by some commenters, public power and
cooperative participation in RTOs will enhance the reliability and
economic benefits of an RTO. Furthermore, participation by public power
entities and cooperatives is vital to ensure that each RTO is
appropriate in size and scope.
Virtually all commenters note that public power entities and
cooperatives face numerous regulatory and legal obstacles regarding RTO
participation. Commenters assert that these obstructions include: (1)
IRS ``private use'' restrictions and the temporary regulations enacted
to mitigate the ``private use'' restrictions; (2) the
[[Page 931]]
requirement that at least 85 percent of a cooperative's income must
come from the cooperative's members (IRS Code Section 501(c)(12)); (3)
RUS mortgage restrictions; (4) state constitutional restraints; (5)
state and local laws; and (6) specific legal restrictions applicable to
PMAs. In addition, commenters offer a variety of solutions to mitigate
or eliminate these obstacles to public power participation in RTO
formation and operation.
We acknowledge that public power entities face several difficult
issues regarding RTO participation and we appreciate the potential
solutions offered by numerous commenters. At this time, however, we
will not analyze each of the specific resolutions proposed by the
various commenters. Instead, on an RTO-by-RTO basis, we will examine
submitted proposals that provide public power and cooperatives with the
flexibility to join an RTO without jeopardizing their tax or mortgage
status. We note, however, that the offered solutions must be consistent
with the minimum functions and characteristics outlined in the Final
Rule.
We are aware that some public power entities and cooperatives have
found ways to participate in existing ISOs. For example, we approved
the formation of the NY ISO contingent upon a ruling of the Internal
Revenue Service that the formation and operation of the NY ISO would
not jeopardize the tax-exempt status of the New York Power
Authority.\680\ Furthermore, we are encouraged by the recent efforts of
the Member Systems of the New York Power Pool (NYPP) to include and
accommodate the participation of Long Island Power Authority (LIPA) in
the NY ISO. NYPP proposed language in their OATT that provides LIPA
will not be required to provide transmission service where the
provision of such service would result in the loss of its tax-exempt
status for its bonds. NYPP also proposed additional scheduling
protocols and procedures to ensure the continued tax-exempt status of
LIPA. The Commission accepted the proposed language as described
above.\681\ We also note that there are two cooperatives Hoosier Energy
Rural Electric Cooperative, Inc. and Wabash Valley Power Association
that are members of the Midwest ISO.\682\ We are hopeful that similar
agreements between RTOs and public power entities and cooperatives can
be reached to provide flexibility and achieve broad regional RTO
participation by all entities.
---------------------------------------------------------------------------
\680\ See Central Hudson Gas & Electric Corp., et al., 83 FERC
para. 61,352 at 62,405 (1998).
\681\ See Central Hudson Gas & Electric Corp., et al., 88 FERC
para. 61,138 at 61,402-03 (1999).
\682\ See Midwest Independent Transmission System Operator,
Inc., et al., 84 FERC para. 61,231 (1998).
---------------------------------------------------------------------------
We expect public power entities and cooperatives to participate
fully in the collaborative process for forming RTOs. During the
collaborative process, the Commission hopes that the parties will
explore, in detail, the impediments and various solutions to public
power and cooperative participation in RTOs. As discussed below with
respect to the collaborative process, we will make staff resources
available to assist in facilitating communication between all entities
and in designing regional solutions to full RTO formation and
participation. Moreover, in all filings under this Rule, we require a
description of efforts made to accommodate participation by public
power entities and cooperatives in RTOs.
We recognize that there is uncertainty regarding what may happen
after the IRS temporary ``private use'' regulations expire on January
22, 2001. Accordingly, we intend to continue to support efforts to
mitigate the ``private use'' and other tax restrictions. Furthermore,
in its comments, RUS recognizes that the development of RTOs may offer
considerable benefits to RUS borrowers. RUS states that it is exploring
means to facilitate borrower participation in RTOs. The Commission
welcomes the efforts of RUS to facilitate borrower participation in
RTOs, and also encourages RTOs to seek ways to accommodate mortgage
restrictions. It would be unfortunate if public power entities and
cooperatives were not able to participate in RTOs and share in the
benefits available in a regional organization because of tax rules and
other government restrictions.
2. Participation by Canadian and Mexican Entities
In the NOPR, the Commission noted that currently, electricity
trading regions exist across national borders and therefore, Mexican
and Canadian involvement in RTO formation would be beneficial to both
countries, as well as to the United States.\683\ The Commission
asserted that regional institutions should include all market
participants in order to provide direct access to information and the
benefits of non-pancaked rates. The NOPR also proposed that in order to
prevent wasteful duplication of grid facilities, reliability standards
implemented by RTOs must be acceptable to the affected nations.\684\
The Commission also emphasized that Canadian and Mexican authorities
would be responsible for approving prices and other terms and
conditions of transmission service provided over any RTO transmission
facilities located in their country.\685\
---------------------------------------------------------------------------
\683\ FERC Stats. and Regs. para. 32,541 at 33,758.
\684\ Id. at 33,758-59.
\685\ Id. at 33,759.
---------------------------------------------------------------------------
Comments. The U.S. entities that submitted comments on this issue
support the efforts by the Commission to encourage participation in
RTOs by Canadian and Mexican entities.\686\ For example, PG&E states
that given the high degree of operational interconnection between our
national grid and components of their systems, participation by these
entities is beneficial.
---------------------------------------------------------------------------
\686\ See PG&E, Desert STAR, Michigan Commission and Industrial
Consumers.
---------------------------------------------------------------------------
Similarly, some Canadian entities believe that significant benefits
can be achieved by trading over ``natural'' or ``appropriate''
transmission regions that do not necessarily stop at the border.\687\
Other Canadian entities welcome the opportunity to participate in the
RTO proceedings and support the Commission's efforts to encourage
international collaboration.\688\
---------------------------------------------------------------------------
\687\ See, e.g., Ontario Power, H.Q. Energy Services, BC Hydro
and Canada DNR.
\688\ See, e.g., Powerex, CEA, Manitoba Board, British Columbia
Ministry, Alberta, Canada DNR, BC Hydro and Ontario IMO.
---------------------------------------------------------------------------
Canadian entities are concerned with sovereignty issues and urge
the Commission to adopt flexible RTO rules that allow voluntary
participation by Canadian utilities.\689\ According to the Manitoba
Board and Ontario IMO, one option in this regard would be to allow
members of an RTO the freedom to conduct transactions--through a
contractual relationship--at the international border with foreign
utilities that do not join a cross-border RTO. Furthermore, Canada DNR
asserts that a decision not to participate in an international RTO by a
Canadian jurisdiction should not place entities in Canada engaged in
trade with United States at a disadvantage. Grand Council et al.
proposes that the Commission sever the Canadian issues from this
proceeding and open a separate docket to examine the international
issues raised by the restructuring of electricity markets. Grand
Council et al. urges the Commission to cooperate with Canada and Mexico
to establish a genuine tri-national consultative process in order to
resolve international issues based on an adequate record. Alberta notes
that each
[[Page 932]]
individual Province has jurisdictional responsibility for the
development of the electrical industry within each Providence and
accordingly, only the Province has the jurisdiction to pass legislation
to develop a competitive electricity market.
---------------------------------------------------------------------------
\689\ E.g., Manitoba Board, British Columbia Ministry, BC Hydro,
Canada DNR, CEA and Ontario Power.
---------------------------------------------------------------------------
Commission Conclusion. After reviewing the comments, we continue to
believe that Canadian and Mexican involvement in RTO formation and
operation would be beneficial to both countries, as well as to the
United States. As we stated in the NOPR, expansion of electricity trade
in the North American bulk power market requires that regional
institutions include all market participants so that everyone may enjoy
direct access to market information and the benefits of non-pancaked
transmission rates. Commenters from the United States and Canada agree
that significant benefits can be achieved by trading over ``natural''
or ``appropriate'' transmission regions that do not necessarily stop at
the border.
We note first that we are pleased with the level of participation
in our proceedings by Canadian parties, and we encourage their
continued participation as RTO formation progresses. We especially
appreciate the RTO Consultation Conference sponsored by Natural
Resources Canada in Ottawa in November 1999.
In response to Canadian comments, we point out that the Final Rule
makes participation in an RTO voluntary for U.S. transmission owners,
and participation is certainly voluntary for Canadian transmission
owners. Further, we emphasize that our RTO Rule does not in any way
require competition in retail electricity markets, whether they are
located in the United States under state regulation or in Canada under
provincial regulation. For those Canadian entities that want to join an
RTO, the Final Rule is flexible: they may propose a cross-border RTO or
a Canadian-only RTO that is compatible with the Rule. The Final Rule is
not exclusionary: Canadian entities are not precluded from joining a
cross-border RTO.
Several parties were concerned that a cross-border RTO would have
its rates, terms, and conditions subject to the rate jurisdiction of at
least two regulators. If a cross-border RTO forms, we will be open to
proposals for innovative approaches for jointly overseeing a cross-
border RTO with domestic and foreign utilities. For example, one
approach might be for the cross-border RTO to try to develop a proposal
acceptable to both regulators, with the understanding that any
regulatory difficulty would normally be referred back to the RTO for
resolution and resubmission to both regulators. Another approach might
be to have different but complementary rate designs in the two
countries.
In the case of a Canada-only RTO, some Canadian transmission
providers believe that having contractual and other agreements for
coordination between separate RTOs aross the border is better than
having a cross-border RTO. However, some Canadian transmission
customers are concerned that this would maintain a lack of
standardization of market rules across the border. The RTO Rule is
intended to permit a U.S. RTO on the Canadian border to develop
contractual and other agreements for coordination with its Canadian RTO
neighbor. Further, we have added a new minimum RTO function that an RTO
must ensure the integration of reliability practices with other regions
in the same interconnection and market interface practices with other
regions. We clarify here that this provision applies to integration
with interconnected regions in Canada and Mexico.
For either a cross-border or a Canada-only RTO, we acknowledge the
sovereign authority of Canadian governments over Canadian entities and
transactions that take place in Canada. Moreover, we re-emphasize that
our Rule does not affect the authorities of Canadian government
entities to approve prices and other terms and conditions of
transmission service provided over any transmission facilities located
in Canada. These conclusions apply equally to Mexico.
We encourage Canadian and Mexican entities to participate in
continued RTO consultations and, if appropriate, formation and filings
for cross-border RTOs. In particular, we urge Canadian and Mexican
entities to attend the appropriate regional workshops to be held in the
spring of 2000. These workshops will provide a forum for initial
discussion of the issues associated with a cross-border RTOs.
Regarding the suggestion to establish a tri-national consultative
process with Canadian and Mexican authorities to resolve international
electric industry issues, we note that there are existing institutions
and processes for resolving international disputes. The RTO process is
just getting underway, and it is not clear that significant
international disputes will develop or, if they should develop, that
they would require a non-traditional method of resolution. Indeed, the
RTO itself through its dispute resolution process may provide a new and
quicker way to resolve some disputes.
3. Existing Transmission Contracts
In the NOPR, the Commission asked for comments addressing what the
appropriate treatment should be for existing transmission agreements
when an RTO is formed. We noted that in Order Nos. 888 and 888-A, the
Commission specifically chose not to abrogate existing requirements
contracts and transmission contracts when the utility filed an open
access transmission tariff.\690\ We stated, however, that an RTO
represents an entirely different context. In the NOPR, the Commission
recognized the importance of balancing a uniform approach for
transmission pricing with the equities inherent in existing
transmission contracts.\691\ Furthermore, we noted that the potential
financial impact of giving up an advantageous transmission arrangement
may serve as a disincentive to joining an RTO. In the NOPR, we proposed
to address the issue of existing transmission contracts on an RTO-by-
RTO basis, rather than resolve the issue generically.\692\
---------------------------------------------------------------------------
\690\ FERC Stats. & Regs. ] 32,541 at 33,757.
\691\ See id. at 33,757-58.
\692\ Id. at 33,758.
---------------------------------------------------------------------------
Comments. Many commenters argue that the Commission should preserve
and protect existing transmission contracts.\693\ These commenters note
that existing contracts represent negotiated rights and obligations
achieved through mutual negotiation. SRP believes that the Commission
should grandfather existing transmission contracts in order to protect
customers from cost shifts and prevent uncertainty in the marketplace.
Turlock argues that the preservation of existing contracts, while
cumbersome, is the bedrock of predictability and reliability and a key
element of contract law. NPRB states that existing contracts should be
honored until the contract expires or until the parties come to a new
agreement. STDUG asserts that in order to be properly inclusive, an RTO
must take members as it finds them, existing contracts, warts, and all.
In contrast, CP&L asserts that the elimination of grandfathered
agreements to the greatest extent possible ensures the most level
playing field for all market participants.
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\693\ E.g., TANC, Turlock, UAMPS, Desert STAR, CMUA, Sithe,
Georgia Transmission, Lincoln, PG&E, NPRB, NCPA, Great River, NRECA,
Loveland Customers, San Francisco, Platte River, Florida Commission,
Nevada Commission, DOE, Wolverine Cooperative, Tri-State, CREDA,
EPSA, Big Rivers, SPP, SoCal Cities, TEP, PJM/NEPOOL Customers,
Metropolitan, STDUG and PacifiCorp.
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[[Page 933]]
A few commenters propose a reasonable transition period to allow
parties to existing contracts to conform their arrangements to an RTO
tariff.\694\ EPSA notes that the transition period should be of
sufficient length to reduce the financial and other burdens on the
customer and on the original transmission provider. PSNM argues that at
a minimum, a transition period of as long as ten years is needed to
move the existing transmission contracts to RTO service. Furthermore,
TAPS proposes that the Commission provide entities with an open season
for transmission customers to choose to terminate or switch service
under the terms of an RTO tariff. Alternatively, TAPS suggests that the
Commission apply a just and reasonable standard to all transmission
customers who seek contract modifications. Regarding contract
modification, Southern Company asserts that in order to promote
fairness, both parties to a contract must have an equal opportunity to
modify the existing agreement. In addition, Entergy argues that the
Commission should encourage all entities to re-negotiate existing
contracts.
---------------------------------------------------------------------------
\694\ See, e.g., Williams, EPSA, First Energy, Duke, PSNM, LG&E,
PGE and MidAmerican.
---------------------------------------------------------------------------
Several commenters support the Commission's preference that issues
relating to the continued validity of existing transmission contracts
be addressed on an RTO-by-RTO basis.\695\ WPSC argues that treatment of
existing transmission contracts within a particular RTO should be
consistent. Turlock urges the Commission to proceed with caution when
addressing existing contracts. On the other hand, PSE&G asserts that
the Commission should not address the treatment of existing contracts
on a case-by-case basis because this leads to arbitrary and
inconsistent results. Instead, PSE&G and Dalton Utilities argue that
the Commission should address the issue of existing transmission
contracts on a generic basis consistent with Order No. 888 and the
Mobile-Sierra doctrine (recognizing the need to preserve the sanctity
of contracts where possible).\696\ Sithe and NRECA concur that a
generic policy is appropriate.
---------------------------------------------------------------------------
\695\ See, e.g., WPSC, Great River, DOE, ICUA, Entergy, TDU
Systems, TEP, South Carolina Authority, MidAmerican, SNWA, UAMPS and
TAPS.
\696\ See United Gas Pipe Line Co. v. Mobile Gas Serv. Corp.,
350 U.S. 332, 338 (1956); FPC v. Sierra Pacific Power Co., 350 U.S.
348, 353 (1956).
---------------------------------------------------------------------------
Cal ISO argues that the Commission's policies on existing contracts
deserve revisiting, at a minimum for the limited purpose of conforming
scheduling and metering rules to those of the RTO/control area
operator. Cal ISO states that it has experienced the challenges of
workability when the ISO was required to honor existing contracts, but
not permitted to interpret them or conform their scheduling rules to
those of the regional organization. Cal ISO notes that it has
experienced the most significant market inefficiencies associated with
existing contracts in the area of scheduling and information gathering.
A few commenters note that not honoring existing contracts would
create disincentives for both transmission customers and owners to join
an RTO.\697\ For example, CMUA and Georgia Transmission argue that the
financial impact of giving up an advantageous transmission arrangement
would be a significant disincentive to RTO membership.
---------------------------------------------------------------------------
\697\ E.g., CMUA, Desert STAR, Georgia Transmission, Wolverine
Cooperative, Cal ISO, Entergy, Tri-State, SNWA, Metropolitan and
TEP.
---------------------------------------------------------------------------
Commission Conclusion. At this time, we continue to believe that it
is not appropriate to order generic abrogation of existing transmission
contracts. We recognize that existing contracts represent negotiated
rights and obligations achieved through mutual negotiation. However, in
PJM \698\ and the Midwest ISO \699\ we adopted the rationale that it
was unreasonable and discriminatory to maintain the pancaked rates in
existing contracts for others when transmission-owning utilities had
designed a non-pancaked rate approach for their own transactions. In
our examination of existing contracts, we intend to balance the
preference for preservation of existing contracts with the importance
of consistency in transmission pricing and the elimination of pancaked
rates.
---------------------------------------------------------------------------
\698\ See PJM, 81 FERC para. 61,257 at 62,280-81 (1997).
\699\ See Midwest Independent Transmission System Operator,
Inc., et al., 84 FERC para. 61,231 at 62,169-70, order on reh'g, 85
FERC para. 61,372 at 62,418-20 (1998).
---------------------------------------------------------------------------
As the above comments demonstrate, there is no consensus on how the
Commission should manage the transition from existing transmission
contacts to RTO service. In fact, parties offer diverse and conflicting
views as to what the Commission should do regarding existing
transmission contracts. Some commenters would have us let all contracts
run their course with no opportunity to modify or terminate. Others
advocate an elimination of existing agreements to the greatest extent
possible. Yet others argue for a transition period ranging in duration
for up to ten years to move existing transmission contracts to RTO
service.
Rather than adopting one extreme position or the other, we will
take a measured approach with regard to the treatment of existing
transmission contracts. We intend to address the issue of existing
transmission contracts on an RTO-by-RTO basis, rather than resolve the
issue generically. Accordingly, each RTO can propose whatever contract
reform is necessary, including the limited changes suggested by the Cal
ISO for the limited purpose of conforming scheduling, information
gathering, and metering rules to those of the RTO. To this end, we
encourage each RTO to address how and when it might convert existing
contracts and submit a contract transition plan that contains specific
details about the procedures to be utilized involving the conversion
from existing contracts to RTO service. Again, our goal in reviewing
existing transmission contracts and contract transition plans is to
balance the desire to honor existing contractual arrangements with the
need for a uniform approach for transmission pricing and the
elimination of pancaked rates.
4. Power Exchanges (PXs)
The NOPR described the apparent advantages and disadvantages of
having a power exchange coincident with an RTO. As further described in
the NOPR, supporters state that PXs can reduce price volatility by
providing price transparency, reduce the impact of defaults by
spreading transaction risks among all participants through credit
standards and reserve fund requirements, facilitate risk hedging by
providing a basis for a futures market, and help facilitate retail
access programs. Detractors argue that the principal functions of a PX
are not natural monopoly functions. They contend that PXs, compared
with bilateral markets, force participants to buy and sell electricity
using standardized contracts, which may not suit their particular
needs. They further argue that competition within the electricity
market and its full benefits can only be achieved if there is
competition for the PX market.
The NOPR left it to each region to determine whether there is a
need for a power exchange and whether the RTO should operate it.\700\
The NOPR said that the Commission will accept any RTO proposal that
includes a power exchange in its design as long as its operation of the
power exchange does not compromise its independence as a
[[Page 934]]
transmission service provider. The Commission sought comments on a
number of questions related to power exchanges, including whether
regional flexibility is appropriate and how RTOs should deal with an
independent power exchange.
---------------------------------------------------------------------------
\700\ FERC Stats. and Regs. para. 32,541 at 33,760.
---------------------------------------------------------------------------
Comments. Commenters' views on power exchanges are mixed. The
largest group of commenters basically agree with the NOPR.\701\ A
smaller group of commenters recommend that the Commission require that
RTO applications include provisions for a power exchange,\702\ with
some recommending that the power exchange be internal to the RTO \703\
and some recommending that the PX be independent of the RTO.\704\ CalPX
argues strongly that a power exchange should be separate from the RTO,
given the continuing need to separate market and transmission
functions; the need for market transparency to facilitate determination
of whether congestion is being exploited; the need to provide a
credible reference price for new retail choice market entrants; and the
potential need for the RTO and power exchange to serve differing
geographic areas. CalPX also submits that there is no concrete evidence
that an RTO-operated power exchange will be more efficient and
economical than an unrelated power exchange. NYMEX agrees that an RTO
should be permitted to operate a power exchange, as long as a proper
code of conduct is in place. PJM points to its success with a combined
ISO/power exchange.
---------------------------------------------------------------------------
\701\ See, e.g., Entergy, NJBUS, NY ISO, TDU Systems, Wisconsin
Commission and UtilitCorp.
\702\ See, e.g., Pennsylvania Commission, Duke and California
Board.
\703\ See, e.g., PJM, ISO-NE and TAPS.
\704\ See, e.g., EPSA and MidAmerican.
---------------------------------------------------------------------------
Another group of commenters argue that power exchanges should not
be included in RTOs, but should be allowed to occur naturally as
needed.\705\ Elaborating on this point of view, Salomon Smith Barney
advises that the power exchange should not be in the RTO because it
could throttle innovation and that the Commission should let the market
decide. If there are really advantages to be gained, as some claim,
from the operation of a single power exchange associated with the RTO,
then such a power exchange will naturally develop. Florida Power Corp.
argues that, while a region may prefer that its RTO closely coordinate
with the power exchange, the two should not be part of the same
organization because there is a fundamental difference in the business
objectives of the two . Similarly, EPSA contends that the Commission's
vision of an RTO being an entity independent from all generation and
power marketing interests is fundamentally incompatible with an RTO-run
power exchange. Nevada Commission offers that a power exchange is not
necessary to the formation of an RTO. And while PG&E sees every region
needing a real-time balancing market regardless of whether it is run
in-house by the RTO, PG&E also prefers that markets should otherwise be
left to develop on their own accord.
---------------------------------------------------------------------------
\705\ See, e.g., APX, SMUD, Southern Company, Tri-State and
Lincoln.
---------------------------------------------------------------------------
Comments were received on additional aspects of the power exchange
concept. PG&E argues that an RTO should not be allowed to use control
of a power exchange to alter or cap prices set by the market. LG&E
submits that the RTO should be required to be the provider of last
resort for ancillary services, although market participants should not
be required to purchase from the RTO. NASUCA notes that the NOPR does
not cover some important power exchange issues such as exactly which
markets would be included. NASUCA recommends that a NOI on power
exchanges and related power market issues be initiated soon after the
final rule.
Several commenters state that multiple power exchanges in a region
should have equal standing before the RTO.\706\ FTC, however,
recommends that the Commission assess whether competition is feasible
in power exchange services. Similarly, CalPX notes that multiple power
exchanges may hurt the market's function because each power exchange
would be small, and therefore would not offer high levels of depth,
liquidity and efficiency. NYMEX counters that there should be no
credence given to the idea that one power exchange should enjoy any
form of artificial franchise vis-a-vis others.
---------------------------------------------------------------------------
\706\ See, e.g., Duke, Florida Power Corp. and Desert STAR.
---------------------------------------------------------------------------
Commission Conclusion. The NOPR proposed leaving it to each region
to determine whether there is a need for a power exchange and whether
the RTO should operate the power exchange. We have Decided to adopt the
NOPR proposal. As the commenters have pointed out, there are advantages
and disadvantages to the inclusion of a PX in the RTO structure. We do
not believe that including a PX as part of the RTO structure would
necessarily preclude the market benefits associated with bilateral
transactions. We believe an RTO can accommodate both a bilateral market
and a PX market. As the individual structures of the various RTOs
supported by the regions are likely to be quite varied, we think that
it is best to let market preferences dictate the form of any one or
more regional power exchanges and whether the RTO should operate a
power exchange.
5. Effect on Retail Markets and Retail Access
The NOPR addressed the impact of RTOs and any associated PXs on
retail competition and the states' jurisdiction over retail
competition. For example, the Commission found that RTOs will enhance
the effectiveness of retail competition:
We believe that the likelihood of success for existing and
planned retail choice initiatives is significantly enhanced if the
Commission can ensure fair and efficient access to a regional market
without pancaked transmission access charges, and that we need to
take steps beyond Order No. 888 to accomplish this.\707\
---------------------------------------------------------------------------
\707\ FERC Stats. and Regs. para. 32,541 at 33,704.
In addition, the Commission found that an RTO does nothing to
interfere with the state's authority to decide retail access policy,
but asked whether a PX is necessary for successful retail competition.
Comments. Several commenters state that RTOs were either essential
or of great benefit in the implementation of retail competition.\708\
Mid-Atlantic Commissions notes that PJM has worked closely with the
Pennsylvania, New Jersey and Delaware Commissions to assist with the
implementation of their retail choice legislation in an organized
fashion, while maintaining that the grid will be operated in a reliable
fashion without any major economic or operational changes. According to
Mid-Atlantic Commissions, this has also further provided those states
in the region that have not implemented retail choice with a stable
organization that continues to maintain reliability.
---------------------------------------------------------------------------
\708\ See, e.g., TXU Electric, DOE, First Rochdale, Illinois
Commission and Williams.
---------------------------------------------------------------------------
A few commenters express concern that the Commission's RTO policy
could threaten the states' ability to control the pace of retail access
and retail competition.\709\ South Carolina Commission counsels that
the Commission should try to avoid affecting retail restructuring
through its efforts to establish an RTO process. Central Maine raises
the concern that retail choice programs already developed in concert
with existing ISOs may be adversely impacted by any changes to such
ISOs that are found to be necessary for them to conform to the RTO
requirements (e.g., energy service
[[Page 935]]
company and other load serving entity contracts entered into in
reliance upon the existing ISO market structures).
---------------------------------------------------------------------------
\709\ See, e.g., Iowa Board and Puget.
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Puget views allowing RTOs to make FPA section 205 filings that
unilaterally propose changes to the RTO tariff as conflicting with the
Commission's commitment to respect the retail access efforts of the
individual states. Puget argues that a unilateral decision by an RTO to
provide transmission service to a retail customer and make that
customer an eligible customer under the pro forma tariff would force
states without retail access to accept such access as a fait accompli.
Puget also fears that the term ``market participant'' as ultimately
defined may include any entity that buys or sells electric energy in
the RTO's region or in any neighboring region that might be affected by
the RTO's actions. If so, since market participants must also have the
option of self-supplying or acquiring ancillary services from third
parties, this further suggests that retail customers may have the
ability to acquire transmission service regardless of whether the
affected state has yet decided retail choice and stranded cost recovery
issues. Industrial Customers, however, question the legal basis for
Puget's apparent suggestion that utilities be allowed to decide which
retail customers may access RTO transmission.
EPSA contends that, while states tout each state's rights to
protect its retail native load customers, some actions taken under this
banner to limit exports of power actually disadvantage adjoining
state's retail customers or participants in the bulk power markets.
Therefore, the Commission should move forward with a rulemaking to
assure full transmission comparability for retail customers of all
states, and to prevent individual states from continuing to
disadvantage each other and to prevent individual utilities from
continuing to disadvantage other market participants. New York
Commission also submits that this proceeding is not the place to
address the issue of preemption of state jurisdiction over bundled
retail electric sales.
TAPS raises the question of jurisdictional conflict as to which
facilities need to be regulated at the federal or state level, and
whether the policies of the Commission toward open access will be
undercut by transmission owners using the seven factor transmission/
distribution classification test to place new generation at a
disadvantage relative to existing generation owned by the transmission
provider. TAPS contends that the Commission must take steps to ensure
that RTOs contain the appropriate facilities and that
refunctionalization of transmission to distribution does not interfere
with competition by creating RTOs that control little or no
transmission.
Another concern expressed is that RTOs may cause cost shifting to
retail customers that could interfere with restructuring.\710\ As to
the impact of the power exchange on retail competition, both CalPX and
MidAmerican argue that power exchanges assist in the effectiveness of
retail competition programs by providing transparent and credible
reference prices.
---------------------------------------------------------------------------
\710\ See, e.g., LG&E and Southern Company.
---------------------------------------------------------------------------
Commission Conclusion. We continue to be persuaded that RTOs can
positively affect each state's implementation of its retail choice
program, without interfering with those states that have not yet
adopted such programs. As noted by commenters, existing ISOs have
already successfully facilitated retail choice programs in areas where
only some of the states have adopted such programs, and the ISOs were
able to do so without clashing with or frustrating the other states
that have not undertaken such programs. We do not believe that an RTO
could interfere with a state's decisions on whether or how fast to
implement retail choice within its borders, either through the RTO's
Section 205 filing authority or otherwise through the RTO's
jurisdictional obligation to provide non-discriminatory and non-
preferential transmission service.
Commenters pointed to potentially extensive reclassification of
transmission facilities to local distribution as part of the unbundling
of retail rate schedules to implement retail choice programs, and how
this might lead to RTOs that are ``empty vessels'' with little
significant transmission under their control. We agree that RTOs must
control all transmission facilities that are necessary to support
competitive wholesale power markets. For this reason, we specified the
scope, configuration and operational control requirements adopted in
this Final Rule. We will judge any proposed reclassification on a case-
by-case basis. We note that any reclassification of transmission
facilities to local distribution will require Commission approval and
will not remove from the Commission's jurisdiction any facilities used
to deliver power to wholesale customers. Furthermore, under the
principle of open architecture (discussed supra in section III.F), the
Commission expects RTOs to remain flexible such that, if over time
circumstances should change and certain facilities need to be
reclassified as transmission, procedures will be in place to do so.
With regard to RTO pricing causing transmission cost shifting that
adversely affects retail choice customers, this issue is discussed in
the Transmission Ratemaking section of this Final Rule.\711\ The
Commission will continue to review transmission rate proposals to
ensure that they are just and reasonable, and not unduly
discriminatory.
---------------------------------------------------------------------------
\711\ See supra section III.G.
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Finally, on the matter of whether a power exchange is needed to
facilitate states' retail choice programs, it is our view that, to the
extent that a region forming an RTO chooses to voluntarily establish an
RTO-affiliated power market, we anticipate that any such power exchange
would provide retail choice customers with transparent and credible
reference prices for power and other information that otherwise might
not be available.\712\
---------------------------------------------------------------------------
\712\ For a further discussion of PXs, see supra section
III.H.4.
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6. Effect on States with Low Cost Generation
In the NOPR, we recognized that states with relatively low cost
power are concerned that an RTO would result in local utilities selling
their low cost power to other states.\713\ However, we noted that a
state that is low cost today may not be low cost tomorrow without an
RTO in its area.\714\ In addition, we stated that utilities that now
have low cost generation will help assure access to future low cost
generating plants by participating in an RTO and that new low cost
generation plants are more likely to be attracted to regions with a
well-functioning regional market governed by an RTO. We sought comment
from state commissions regarding how an RTO in their state would affect
power costs.
---------------------------------------------------------------------------
\713\ FERC Stats. and Regs. para. 32,541 at 33,722.
\714\ See id.
---------------------------------------------------------------------------
Comments.--A number of commenters raise concerns about the effect
of RTOs on states with low cost electricity. These concerns center
around one issue--that the costs of creating an RTO may outweigh the
benefits.
South Carolina Commission argues that customers in South Carolina
enjoy very high quality service and pay some of the lowest rates. Duke
power concurs, noting that, it is not necessarily true that North
Carolina and South Carolina will conclude that sufficient long-term
benefits exist for these states to justify costs of RTO membership.
Duke argues
[[Page 936]]
that any proposed RTO should be shown to provide tangible benefits to
the relevant region.
Alabama Commission believes that RTOs will cause states to lose the
efficiency of integrated systems and lead to retail competition,
whether it is in the interest of customers or not. Southern Company
agrees, noting that due in large part to the low cost status of
southeastern states, they are proceeding cautiously with retail
competition and restructuring initiatives. This does not mean that
these states are ignoring the potential benefits of restructuring.
Indeed, Southern Company notes that states in its service territory are
actively studying the potential advantages and disadvantages of retail
competition but have not yet concluded that the potential benefits
outweigh the costs and risks associated with changing the current
industry structure.
SMUD points out that it has not joined the Cal ISO over similar
concerns. It indicates that its customers already enjoy low cost
electricity and that participation in the Cal ISO could not ensure that
SMUD's retail rates would be any lower, and on the contrary, the cost
of participation would cause rate increases.
Kentucky Commission indicates that inefficiencies may occur for a
variety of reasons and examples of inefficiencies include: multiple
RTOs in a small region; several layers of governance within one RTO;
and too many tasks shifted from the RTO members to the RTO itself.
Kentucky Commission argues that if the proposed transmission
organizations are not operated at levels of maximum efficiencies and
minimum reasonable costs, the Commission will have failed to promote
one of its primary objectives, the growth and success of the wholesale
power market. Kentucky Commission further argues that the Commission
must be mindful of these costs in developing rules for the
establishment of RTOs.
Commission Conclusion. We are mindful of the potential costs of
setting up and running an RTO, but we anticipate that the collaborative
process will result in an RTO proposal that incorporates a design that,
overall, increases the existing level of transmission system and market
efficiency for each region. As we discuss more fully in the Scope,
Implementation and Benefits sections of this Final Rule, we are taking
a results-oriented, practical approach to establishment, organization,
implementation and operation of RTOs. We do not expect that regions
with no existing institutions will necessarily invest in new, high-cost
RTO infrastructure. Instead, such a region may propose an RTO that
relies on existing infrastructure to accomplish its mission. However,
we expect the RTO to satisfy the minimum characteristics and functions
and to improve the efficiency of regional transmission service.
In response to the concern of low cost states that RTOs could
result in exports of their low cost power to other states, we do not
believe that an RTO will cause utilities to sell their lowest cost
power out of state. While retail choice arguably might lead to low cost
power being sold out of state because incumbent utilities no longer
have an obligation to serve local in-state loads, this would occur with
or without an RTO in the region. Where there is no retail choice, our
Final Rule does not affect a state commission's authority to require a
utility to sell its lowest cost power to native load, as it always has.
We point out that, if the utility's transmission is operated by an RTO
and its higher cost power can be sold more readily to new, more distant
customers, this will lead to recovery of more capital costs and lower
retail rates. In the long term, low cost states may benefit from an RTO
that facilitates expanded access to wholesale electricity markets,
increasing the choice of low cost resources available to utilities as
they acquire new power resources.
7. States' Roles with Regard to RTOs
In the NOPR, we noted that states want a role in the governance of
any RTOs for their states, and we proposed to be flexible in
accommodating the states' needs.\715\ The NOPR encouraged RTO design to
accommodate appropriate state oversight, especially with regard to
planning and siting new multi-state transmission facilities. We sought
comments on the appropriate state role in RTOs on these and other RTO
matters.
---------------------------------------------------------------------------
\715\ FERC Stats. and Regs. para. 32,541 at 33,724.
---------------------------------------------------------------------------
Comments. Comments on the states' roles in RTO development and
governance were fairly extensive, with by far the greater percentage of
comments supporting a strong and clearly defined state role. Comments
can be grouped into four primary categories: (1) governance; (2)
formation; (3) siting and planning authority; (4) regional regulation.
Governance. Almost all commenters on this issue expressed support
for a clear state role in governance; however, there were differences
as to exactly what that role should be. Some commenters believe that
states should be allowed to determine their own role in governance,
either as members of advisory panels to the board of directors, as
voting members of the board, as non-voting members of the board, or
having authority to appoint board members. Some commenters, however,
feel strongly that states should not be permitted to be voting members
of boards.
Commenters argue that the appropriate state role in an RTO is a
matter of local control. For example, Northwest Council states that the
Commission should not set restrictive rules on the type of state
participation in RTO governance, but should allow the states to propose
to the Commission the kind of roles they view as appropriate, e.g.,
voting members of a stakeholder board, ex officio status on an
independent board, and so forth.
The California Board suggested that state officials should be
allowed as either voting or non-voting members. Los Angeles has no
objection to state board membership, either voting or non-voting, if a
state has determined that a government official can best represent that
state's interests. The Washington Commission agrees that states should
be able to define their own role. Mid-Atlantic Commissions note that
they have a Memorandum of Understanding with the PJM ISO Board of
Managers to facilitate communication and promote a cooperative
relationship.
Some commenters, however, think that state officials should not
have voting membership on boards of directors since that could raise
conflict of interest problems where the state official would have to
approve decisions of the board while sitting as a regulator. For
example, Minnesota Power believes that state cooperation will be
enhanced if state officials participate as members of an RTO advisory
board, but they should not participate as voting members of an RTO
because the RTO process could be compromised by parochial state
politics. ISO-NE agrees, pointing out that some states' conflict of
interest laws may expressly prohibit such service, and that it might be
difficult for an official from one state to make decisions as a board
member that are good for residents of all states encompassed by the
RTO.\716\ WEPCO believes the appropriate role of the states in RTO
governance includes active participation in regional planning efforts
and continued oversight of siting of new transmission facilities. In
addition, many commenters supported
[[Page 937]]
an advisory role for state officials, through advisory boards.\717\
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\716\ See also MidAmerican, Montana-Dakota, PSNM, East Kentucky
and NPRB.
\717\ E.g., ISO-NE, PJM, Midwest ISO, MidAmerican, Project
Groups, PSNM, Iowa Board, Arizona Commission and UAMPS.
---------------------------------------------------------------------------
Formation. Numerous commenters supported a role for states in the
formation of RTOs. ISO-NE points out that the states in its region had
a significant role in the development of the ISO. In addition, the
California Board argues that states should have a role in determining
the structure of the RTO and any other market institutions that are
formed to serve the citizens of their respective states. California
Board further notes that mechanisms to ensure that states' interests
are protected might include statutory or regulatory reliability
criteria; independent market monitoring by the states or requiring
market monitoring reports to be provided to the state; and
accountability to the states to ensure adequacy of transmission and
generation planning.
The Michigan Commission notes that most states have ittle direct
authority to order the development of an RTO, especially when the RTO
encompasses several states. According to the Michigan Commission, at
best state commissions should serve in an advisory role as the
utilities develop the structure and guidelines of the RTO proposal. The
Michigan Commission, however, joins a few other states in urging the
Commission to defer to state recommendations once the basic RTO
characteristic and functional guidelines have been met.
NARUC comments extensively on the potential collaborative process
and the importance of state participation in this process and other
steps in the formation of RTOs. To achieve the public policy goal of
assuring reliable service at an affordable cost, NARUC argues that
states should fully participate in RTO development and formation,
particularly in matters for end-use native load customers. NARUC notes
that based on some states' retail choice or ISO experiences, state
oversight can play a significant role in assuring a well-functioning
ISO and competitive wholesale and retail markets.
NARUC further suggests that once RTOs are formed, continuing
interaction is necessary, and market development and evolution will be
continuous. NARUC believes that RTO formation must continue to be a
dynamic process requiring continuing dialogue between FERC and the
states. NARUC further believes that once organizations are formed and
approved, some type of formal reporting to FERC and the states by the
organizations on an annual basis would be appropriate.
Nine Commissions suggests that state commissions are well
positioned to balance the competitive motivations of utilities in the
RTO formation process with the interests of all other stakeholders in
defining markets in their respective regions and conforming the RTO
boundaries to those markets. According to Nine Commissions, the state
commissions' continued cooperation with FERC will ensure that the
mutual public interests of providing reliable electric service will be
met, and that market participants in every region of the country will
be treated comparably.
Siting, Planning and Reliability. A number of commenters, many
state commissions, and quite a few other parties, argue strongly that
the Commission should be careful not to preempt traditional state
regulatory authority in promulgating its rule. In particular,
commenters suggest that the Commission should not usurp state
authorities over siting, planning, and reliability of the transmission
system. Some commenters proposed solutions to state/Federal
jurisdiction issues in the RTO context, such as joint state/Federal
review bodies. The Alabama Commission suggests that FERC should not
take any action that would infringe on state jurisdiction.
South Carolina Commission asserts that transmission siting should
remain in the hands of the states and local governments. South Carolina
Commission further asserts that states must continue to have a
significant role with regard to matters of reliability for end-use
native load customers. The Iowa Board concurs and suggests that the
Commission's RTO policies cannot alter states' continued interest in
local matters such as transmission and generation siting, local
transmission and distribution interface issues, adequacy of generation
and transmission, service quality, and retail rates.
The Montana Commission notes that in roughly half the states with
siting laws the function is not vested in the regulatory commission,
but rather in a separate energy policy, environmental or commerce
agency. They recommend that the Commission amend the language in the
Final Rule to make it clear that the Commission does not intend to
preempt state siting authority as part of this NOPR.
UAMPS warns that RTOs may create a separation between generation
planning and transmission planning that endangers reliability. UAMPS
argues that states must be left with authority to assure reliability
and that retail competition issues should also be left to the states.
UAMPS suggests that because state cooperation and participation will be
so critical to an RTO's effectiveness, in addition to the four minimum
characteristics the Commission has proposed, RTOs should be required to
provide specifically for significant state involvement in their
development and operation. Allegheny, on the contrary, states that
system operations in an RTO will be pursued for the good of the RTO
service area, not of any one state. Allegheny notes that if that fact
yields a dilution of state authority it must be the price paid for RTO
benefits.
Regional Regulation. A number of commenters propose or support
regional regulatory cooperation or joint state/Federal sharing of
jurisdiction. The Kentucky Commission proposes the creation of a
Federal/state ``joint board,'' that is styled similarly to the
Universal Service Joint Board currently used by the Federal
Communications Commission, state utility commissions, and other
parties. The Kentucky Commission suggests creating this voluntary Board
to develop and review standards for transmission expansion. The Joint
Board would include participation from FERC, state commissions, RTOs,
and other interested parties. The Joint Board would also convene ad hoc
committees to review specific transmission expansion proposals. These
committees would include the participants described above, and would
include representatives from regulatory commissions in states where the
expansion is proposed. The RTO would present the ad hoc committee with
a plan for transmission expansion with appropriate documentation for
need, cost effectiveness, and alternatives. The committee would in turn
pass on its recommendation or refusal of support for the plan to the
specific state commissions for their official approval. The Kentucky
Commission believes that such an arrangement could avoid Federal/state
conflict while allowing both levels of government to exercise
appropriate jurisdiction. In addition, ISO-NE points to existing
regional regulatory groups such as NECPUC that could continue to
provide valuable assistance to the Commission in the collaborative
process to encourage RTO formation envisioned in the NOPR.
Nine Commissions argues that an appropriate regional oversight
venue will lead to more consistent treatment of issues and parties
between state and Federal regulatory forums. With appropriate deference
by both FERC and the states, such a regional venue could
[[Page 938]]
obviate the need for many parties to expend redundant resources to
participate in multiple state and Federal regulatory processes for
matters relating to transmission and RTOs.
Nine Commissions notes that one possible mechanism to effectuate
such a regional venue is interstate compacts, which are provided for in
the Administration's proposed electric industry restructuring
legislation. Nine Commissions argues that regional regulatory
organizations have the advantage of being able to coordinate state
interests for providing regional recommendations to FERC. State
oversight functions (e.g. siting, local outages, customer complaints)
would not change. According to Nine Commissions, such regional
regulatory organizations would provide greater coordination among
states within the region, allowing for ADR processes that could satisfy
multiple state jurisdictional requirements, and such organizations
would monitor markets that have evolved beyond state borders and
facilitate joint FERC and multi-state facilities siting.
Pennsylvania Commission prefers a joint Federal/state approach
toward regulating RTO siting approvals, expansion, innovation and
customer service. Pennsylvania Commission notes that a joint approach
would resolve the vexing problem of Federal/state jurisdictional
uncertainty and a joint Federal/state approach would avoid the
potential for creative forum shopping by individual stakeholders, who
will always seek to cast a dispute in jurisdictional terms so as to
dictate a jurisdictional resolution to the perceived favorable outcome.
A joint Federal/state approach has been used with success in other
areas, such as the Susquehanna River Basin Commission, the Delaware
River Basin Commission and the Joint Pipeline Office for the Trans-
Alaska Pipeline System. Likewise, the Virginia Commission believes that
there is no conflict between state goals and Commission goals and that
the two levels of government should be able to work together and avoid
conflict as long as both parties recognize that the common goal is the
public interest.
Commission Conclusion. We continue to believe that states have
important roles to play in RTO matters. For example, most states must
approve a utility joining an RTO, and several states have required
their utilities to turn over their transmission facilities to an
independent transmission operator. Also, states must approve the siting
of transmission facilities that are called for in an RTO expansion
plan.
We believe, however, that it is not appropriate to try to set out a
full set of states' roles in this Rule. It is difficult, and not
necessary, to reach generic conclusions about states' roles given the
diversity of possible RTO forms and state authorities. For example, a
state's role may be different for an ISO, transco, and other
organizational form, and it may be different for a multistate RTO and a
single-state RTO, if any. States differ regarding the authorities they
have vested in their regulatory and siting agencies. Further, states
differ regarding their jurisdiction over municipal and cooperative
utility owners of transmission facilities.
Regional interests forming an RTO should consult with the states
about what state roles best fit the agencies' authorities and
preferences and the organizational form of the RTO. This role could
vary from state to state within an RTO. Therefore, this Rule takes a
flexible approach that allows states to play appropriate roles in RTO
matters, consistent with this Commission's exclusive responsibilities
and authorities under the FPA.
We note that we have discussed the role of states for particular
RTO functions elsewhere in this Final Rule. Regarding RTO formation,
the Background discussion above discusses the role that several states
played in creating many of the existing ISOs. It also describes our
initial consultations with state regulators on RTO formation and our
roles in FPA section 202(a) implementation; in those consultations we
offered to continue the RTO dialogue with states in the future. The
form of consultation to be used should be decided based on the issues
and the region so we will not endorse or reject here any particular
form of collaboration. However, in the Collaborative Process discussion
below, we set out our plans to invite states and others to work with us
to foster RTO formation beginning early next year.
In our discussion above of the Independence characteristic, we
discuss the role of state agencies in governance, making the point that
states will play a key role in RTO formation and development but
declining to specify generically a state's role in governance. Also, in
our discussion above of the RTO Planning and Expansion function we
recognize the exclusive authority of state and local governments and
regulatory agencies over the siting of transmission facilities, and we
include in our regulations the standard that an RTO must accommodate
efforts by state regulatory commissions to create multi-state
agreements to review and approve new transmission facilities.
8. Accounting Issues
Although not discussed in the NOPR, EEI commented on some
accounting aspects of RTOs. It urges the Commission to address two
primary accounting issues for RTOs: (1) The need to revise the Uniform
System of Accounts (USofA) and related reports to reflect new RTO and
other unbundled rate structures; and (2) the ability of RTOs to use
regulatory accounting.
a. Revision of the Uniform System of Accounts
Comments. EEI contends that because the Commission's USofA was
developed when utilities' products were bundled and fully regulated, it
needs to be revised to support the Commission's adopted policies and
this proposed rule. EEI believes that with unbundling of rates, the
USofA will need to be revised to reflect, among other things,\718\ cost
functionalization (e.g., by generation, transmission, distribution,
etc.). EEI also believes that the Commission should specifically
address the accounting to be used for RTO reporting purposes, as the
current USofA was not designed for use by RTOs. EEI states that it is
very willing to work with the Commission's staff to address the
specific changes that should be made to the USofA.
---------------------------------------------------------------------------
\718\ Another significant area cited is whether the Commission
should modify its original cost accounting requirements for property
acquisitions to conform with the evolving fair value requirements of
the Financial Accounting Standards Board (FASB). See Appendix I to
EEI Comments at 11.
---------------------------------------------------------------------------
Commission Conclusion. The Final Rule permits the various regions
to select different organizational forms for RTOs. Our open
architecture structure for RTOs permits applicants to select the
business organization best suited to the needs of its members and RTO
participants. It would therefore be difficult to prescribe in this
proceeding specific changes to our existing USofA that would
accommodate the needs of all RTOs.
We believe a better course at this juncture would be to require
RTOs to conform their accounting to our USofA (as have ISOs) and to
submit questions of doubtful interpretation to the Commission for
individual or generic rulings on particular transactions, events and
circumstances.
However, we agree with EEI's observation that unbundling of utility
services, and other changes in the industry require the Commission to
re-examine its existing accounting and related reporting requirements.
This is true not only for the new types of utilities that have emerged
in the industry such as ISOs, PXs and RTOs,
[[Page 939]]
but also for traditional public utilities. The Commission staff has
been and will continue to meet with EEI and others, and will continue
its efforts to address the specific changes that may be needed as the
industry restructures.
b. Ability to Use Special Accounting
Comments. EEI asks the Commission to consider the impact of its
actions on the ability of RTOs to use the special accounting rules
applicable to cost-based rate-regulated entities.\719\ EEI believes
that the ability to use regulated accounting would be advantageous to
RTOs and viewed favorably by the investment community.\720\ EEI urges
the Commission to structure alternative ratemaking methods (e.g., price
and revenue caps, incentive-based rates and price indexing) to allow
RTOs to continue to use the special accounting of SFAS 71. In this
regard, EEI believes that if the Commission decides it is advantageous
to stimulate the establishment of RTOs by ensuring that all start-up
costs are ultimately recovered through FERC jurisdictional rates, it
could issue ratemaking orders that defer expense recognition of these
costs, and allow for future ratemaking recovery. Similarly, EEI urges
the Commission to address the time frame over which software
development costs could be recovered through rates and to allow
utilities to defer expense recognition of such costs. To enhance cash
flows from operations, EEI suggests that the Commission accelerate the
amortization of all capitalized software costs. These actions,
according to EEI, would likely be viewed favorably by the investment
community.
---------------------------------------------------------------------------
\719\ The special accounting rules are primarily contained in
Statement of Financial Accounting Standards No. 71, Accounting for
the Effects of Certain Types of Regulation (SFAS 71). One of the
primary accounting differences is the ability to defer expense
recognition of an incurred cost if it is probable that the utility
will recover that cost in future cost-based regulated rates.
\720\ Conversely, according to EEI, the inability of an entity
to use SFAS 71 accounting could have an adverse effect on earnings,
which may be viewed unfavorably by investors. According to EEI, one
example would be where the Commission approves a rate levelization
plan (e.g., under capital lease transactions) under which rate
recovery of certain costs would be deferred until future years. If a
utility could not defer expense recognition of such costs, earnings
would be depressed in the early years of the levelization plan.
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Commission Conclusion. RTOs may propose and we are willing to
consider alternative ratemaking methods including proposals to delay
rate recovery of certain expenses. We will not prescribe any specific
requirements at this time but allow RTOs to propose those methods which
are appropriate for each RTO's facts and circumstances. In this regard,
we intend to take a flexible regulatory approach toward approving RTO
rate design proposals and strive to include adequate information in our
rate orders on the appropriate accounting treatments.
9. Market Design Lessons
We expect that bid-based markets will be a central feature in many
RTO proposals. To date, the Commission has analyzed and approved, with
various modifications, bid-based market designs for four ISOs. The
purpose of this section is to summarize the lessons learned from these
real-world market experiments. The summary provided below is not
intended to favor one market design over another, but is intended to
assist RTOs in evaluating existing market designs and meeting the
deadlines set forth in this rule.\721\
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\721\ The Commission has already given considerable guidance on
numerous market design issues in a number of orders. See
Pennsylvania-New Jersey-Maryland Interconnection, L.L.C., 81 FERC
para. 61,257 (1997); Central Hudson Gas & Electric Corp., et al. 86
FERC para. 61,062 (1999); New England Power Pool, et al. 87 FERC
para. 61,045 (1999); AES Redondo Beach, et al., 87 FERC ] 61,208
(1999).
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Cal ISO, PJM and ISO-NE have had operational experience with their
respective market designs. For the most part the markets operated by
these ISOs have functioned well, and they have not experienced many of
the problems encountered in the bilateral markets in the Midwest and
the Southeast.\722\ However, each of the operational ISOs has
encountered some market design problems that have resulted in
unexpected or undesirable market outcomes.\723\ These outcomes have led
some ISOs to file many market design changes and requests for temporary
remedies or protections until permanent design changes can be
implemented.\724\
---------------------------------------------------------------------------
\722\ See Staff Report to the Federal Energy Regulatory
Commission on the Causes of Wholesale Electric Pricing Abnormalities
in the Midwest During June 1998 (September 28, 1998).
\723\ The NY ISO has had little operational experience with the
particulars of its markets design.
\724\ See New England Power Pool, et al., 87 FERC para. 61,055
(1999); AES Redondo Beach, et al., 87 FERC 61,208 (1999); New York
Independent System Operator, Inc. et al., 88 FERC para. 61,228
(1999).
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a. Multiple Product Markets
The bid-based markets that we have approved to date are premised on
the assumption that acceptance of voluntary supply and demand bids
which maximize overall net benefits will also maximize efficiency. Each
approved ISO design employs some bid-based mechanism to ramp resources
up and down to balance the system, manage congestion, and to supply
some ancillary services. Employing bids that indicate a generator's
willingness to be ramped down, ramped up, or placed in reserve is an
economic way to balance the system, manage congestion and maintain
appropriate reserves, both in real time and in any day-ahead markets.
However, if more than one product is being sold in the same temporal
market,\725\ efficiency is maximized when arbitrage opportunities
reflected in the bids are exhausted (i.e., after the RTO's markets have
cleared, no technically qualified market participant would have
preferred to be in another of the RTO's markets). In addition,
efficient bid-based markets elicit prices that are consistent with
technical and cost requirements.\726\ For example, a situation where
generating units are paid more for not generating than for generating
as has happened in ISO-NE and the Cal ISO may be an indication of an
inefficient market.\727\
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\725\ For example, energy and operating reserve products may be
offered in real-time.
\726\ One would expect that services with more stringent
technical requirements ordinarily have higher costs for providing
those services. The prices of these services should reflect the
costs. For example, spinning reserves have more stringent
requirements and would be expected to command a higher price than
non-spinning reserves.
\727\ See Report of the Market Surveillance Committee of the
California Independent System Operator, October 18, 1999 (MSC
October Report). Both ISOs have seen prices for services such as
non-spinning reserve products, which do not require a unit to be
running, higher than the energy price. Also, according to the Market
Surveillance Committee (MSC) of the Cal ISO, market participants
have an incentive to submit schedules that will cause congestion so
that their units can be called upon to relieve the congestion and
receive payments for not generating that are greater than payments
received for generating.
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b. Physical Feasibility
Proper design of the market clearing procedures ensures that prices
balance the supply and demand for energy, and all transactions, in the
aggregate, are physically feasible with appropriate levels of reserves.
Some market designs have allowed ISOs to accept schedules that have not
been physically feasible (e.g., Cal ISO), while other ISO market
designs include mechanisms to ensure the physical feasibility of
transactions (e.g., the NY ISO and PJM). Some ISOs have encountered
instances where transmission constraints have prevented the use of
needed reserves,\728\ and this is inconsistent with the operator's
obligation to make certain that reserve requirements are met and that
reserves, along with necessary transmission, are available to respond
appropriately to contingencies.
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\728\ See MSC October Report, at 67, 74-75.
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[[Page 940]]
c. Access to Real-Time Balancing Market
Real-time balancing refers to the moment-to-moment matching of
loads and generation on a system-wide basis. Real-time balancing is
usually achieved through the direct control of select generators (and,
in some cases, loads) that increase or decrease their output (or
consumption in the case of loads) in response to instructions from the
system operator. Over the last several years, the Commission has seen
an increasing use by system operators of market mechanisms that rely on
bids from generators to achieve, overall, real-time balancing. In order
to maintain system balance, the operator also manages congestion while
maintaining the appropriate level of reserves. It is expected that any
RTO balancing markets will be available to all grid users, i.e.,
including individual grid users that engage in bilateral transactions.
The fact that the overall system must be in balance moment-to-moment
does not mean that there must be a moment-to-moment balance between the
specific load and resources involved in individual bilateral
transactions. Making a real-time balancing market available to all grid
users ensures that all users are treated equally for purposes of
settling their individual imbalances. The four operating ISOs approved
by the Commission already operate such markets.
d. Market Participation
Markets are most efficient when generators and loads, whether
internal or external to the RTO, are allowed full and flexible
participation in the markets. While generators and loads have the
option to choose between participating in any RTO-facilitated markets
or other markets, the RTO must have generation and ancillary service
quantity information, and any necessary technical information, from
self-schedulers in order to balance the system and ensure reliability.
This allows bilateral and forward financial markets and independent PX
markets to co-exist and complement RTO physical markets. Participants
that self-schedule would be expected to pay for the costs that they
impose on the physical system at market prices and be paid for the
benefits that they supply to the physical system at market prices.\729\
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\729\ Costs and benefits associated with self-schedules are
congestion costs created by the transaction or congestion relief
that the transaction makes possible.
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Unnecessary constraints on the imports of services can lead to
increases in price volatility due to thin markets.\730\ Allowing
exports will give generators flexibility to take advantage of
opportunities outside of the RTO boundaries, while allowing load
serving entities external to the RTO a chance to purchase services.
Broadening market participation deepens the market and enhances overall
efficiency.
---------------------------------------------------------------------------
\730\ Thin markets refers to a situation in which the amount bid
into the market is either not enough to match demand, or just enough
to match demand.
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e. Demand-Side Bidding
Existing ISO markets offer generators flexible participation, but
they often do not offer customers demand-side bidding options. Demand-
side bidding is desirable to the extent it is technically feasible,
because without it, demand response decreases and market power is
easier to exercise.\731\ The availability of price responsive demand
also reduces price volatility in the markets.
---------------------------------------------------------------------------
\731\ The flexibility of demand-side bidding may be limited
unless real-time meters are installed. Otherwise, demand-side
bidding can simply take the form of interruptible load.
---------------------------------------------------------------------------
f. Bidding Rules
A market that provides the flexibility for all generators to bid a
reasonable approximation of the costs they incur including start-up,
minimum load, energy, and ramping costs will be efficient. Whether it
is cost-effective to start up a generator and make it available for
dispatch depends on the prices and scheduled quantities over the
multiple hours and services for which the generator is committed, not
on the prices in any single hour or for any single service. Allowing
participants to bid these costs helps provide for a more efficient
dispatch of generating units to meet load and other services, because
it allows the start-up decisions underlying the dispatch schedules to
be based on prices and quantities for a period greater than a single
hour. Not permitting start-up and minimum load bids can reduce
efficiency because the decision to start up and dispatch generators is
made separately for each hour, resulting in start up decisions that can
cause losses for generators. Also, when the start-up and minimum load
bids are submitted along with minimum run and down times, generators
are ensured that they will not be dispatched in a way that is
physically damaging to the unit.
g. Transaction Costs and Risk
Transaction costs associated with participation in well functioning
RTO markets should be low, and market participation should involve no
unnecessary risks. For example, in sequentially clearing markets,
bidders are exposed to the risk that they may be chosen in one of the
markets that clears first, yet would have preferred to have been chosen
in a market that cleared later. In order to hedge against such risks,
bidders may undertake expensive and time consuming bid preparation
strategies to decrease the likelihood that such profitable
opportunities would be missed.
h. Price Recalculations
In some instances, it may be necessary to post prices on a
preliminary basis while the final price calculations are verified. For
example, in ISO-NE, the computer algorithms generate new dispatch
points every five minutes, and preliminary market clearing prices are
based on these dispatch algorithms. However, the actual dispatch
instructions are issued manually. In circumstances where time does not
permit all changes in dispatch to be communicated and effected through
manual processes in a timely manner, the market clearing price
resulting from the computer algorithm must be adjusted to reflect the
actual dispatch in the hour.\732\ While an RTO must ensure that the
final market clearing prices are correct, market clearing procedures
should minimize price recalculations. Also, any price recalculation
should be done quickly. Otherwise, market participants could incur
large transaction costs in attempts to hedge against such risk. Risk
exposure can be further reduced if market participants can engage in
bilateral transactions, or participate in other markets, to lock in
prices prior to participating in the RTO-facilitated markets.
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\732\ See ISO New England, Internal Review of Operations, June
7-8, 1999, Report issued August 20, 1999. Electronic dispatch is
under consideration in ISO-NE.
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i. Multi-Settlement Markets
Multi-settlement markets may involve a day-ahead and real-time
market. For real-time markets, prices are determined by real-time
dispatch quantities, and deviations from day-ahead schedules are priced
at the real-time price. When day-ahead schedules are financially
binding, they are financial commitments subject to payments for
deviations at the real-time price. If market participants adhere to
day-ahead schedules, they need not participate in the real-time
markets. If needed for reliability, bids need to be physically binding
and may be subject to Commission-approved penalties for failure to
adhere to the bid. Without financially binding commitments in the day-
ahead market, the riskiness of market participation
[[Page 941]]
increases since the day-ahead bids could be changed before real-time
dispatch. If bids for ancillary services are accepted, the accepted
capacity must be physically ready to meet reliability commitments when
called upon. The lack of a physical capacity commitment has been a
problem in some ISOs.
j. Preventing Abusive Market Power
An efficient market design does not favor market participants that
have the potential to exercise market power and minimizes the
incentives for market participants to engage in abuse of market power.
For example, since large players are more likely to cause market power
problems, a market design that favors large players (e.g., portfolio
bidding \733\) may create an incentive for consolidation and resulting
market power problems. Fewer restrictions on imports of services will
help guard against thin markets, which in turn will help mitigate
market power. ISO's have experienced problems with thin markets, and
easing restrictions on imports should help.\734\ Also, artificially
segmenting a product market into separate geographic markets for the
same product can also create additional price volatility and
opportunities for the exercise of market power.\735\
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\733\ Portfolio bidding refers to bids that aggregate all
generating units under the same ownership. This is in contrast to
generation owners bidding in each unit separately.
\734\ Report of the Market Surveillance Committee of the
California Independent System Operator, August 19, 1998 at 35-36
(MSC August Report).
\735\ The Cal ISO at one time segmented their product markets
into separate geographic markets that corresponded to the defined
congestion zones even when no congestion existed. It has since
reformed this practice. See MSC August Report, at 32-33.
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If market participants are allowed to submit bids which can then be
changed before financial settlements are completed, these non-binding
bids can be used as a signaling device to facilitate collusive
behavior.
k. Market Information and Market Monitoring
One property of an efficient market has market clearing prices and
quantities being made available immediately. This information enables
market participants and potential future market participants to assess
the market and plan their businesses efficiently. It will also allow
market participants to spot errors in the market clearing process and
get them corrected.
Disclosure of individual bids could be made eventually, but not
immediately. Such disclosures will allow detection of market design and
implementation flaws, and allow study of the market by independent
analysts and market participants. It may lead to the exposure of the
exercise of market power. To detect the withholding of capacity, a
simple screen is to provide the output, reserve quantities, and maximum
capacity of each generator. Immediate disclosure of individual bids is
undesirable because it might facilitate collusion by the market
participants. It also might affect the bids of market participants who
wish to keep their costs confidential. However, after six months or a
year, the information on individual bids has essentially no value for
collusion and discloses little new information about any bidder's
current costs. Nonetheless, the information's value for market
monitoring remains high.\736\
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\736\ The Commission approved the disclosure of bid information
in the following orders. See PJM Interconnection, L.L.C., 86 FERC
para. 61,247 at 61,890, order on reh'g, 88 FERC para. 61,274 (1999);
Central Hudson Gas & Electric Corp. et al. 86 FERC para. 61,062 at
61,204, order on reh'g, 88 FERC para. 61,138 (1999).
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l. Prices and Cost Averaging
Market designs that base prices on the averaging or socialization
of costs,\737\ may distort consumption, production, and investment
decisions and ultimately lead to economically inefficient outcomes.
Where possible and cost effective, cost causality principles can be
used to price services and eliminate averaging.\738\
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\737\ Socialization of costs means that costs that could be
assigned to a particular market participant(s) are instead spread
over all participants regardless of whether or not they caused the
costs.
\738\ While it is desirable from an efficiency standpoint to
eliminate the averaging of costs, the costs associated with
calculating cost causation in some instances could be shown to
outweigh the benefits of eliminating averaging.
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For example, in some congestion management mechanisms, the cost of
alleviating congestion is spread over all loads. This scheme could have
some generators creating monetary benefits for other generators. In
addition, it could lead to over-consumption of power by some loads and
under-consumption by other loads. Moreover, such averaging mechanisms
for congestion management do not send the correct price signals for the
location of new generation, thus leading to problems with long-term
implications.\739\
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\739\ MSC October Report, at 112.
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Moreover, if pass-throughs or uplift charges are paid by all load
to ensure bid-cost recovery, as in some approved ISO market designs, it
may be appropriate to couple these pricing mechanisms with incentive
mechanisms for the RTO to control them.
I. Collaborative Process
The Commission proposed a regional collaborative process to
facilitate the creation of RTOs. State commissions had encouraged the
Commission to sponsor activities in each region of the country that
will bring together representatives of public and private electric
utilities, state regulators, consumer groups, representatives from
Canada or Mexico, as appropriate, and any other interested parties that
need to be part of such a process. The Commission proposed that
regional workshops be held after the Final Rule is issued to determine
what, if any, impediments exist to the formation of RTOs in a
particular region and how the Commission staff could help to overcome
those impediments. Staff resources that will be available for the
collaborative process include technical staff, dispute resolution
staff, and any other staff assistance that would be beneficial.
Comments. Almost all commenters support the Commission's
collaborative proposal. Of the 49 comments that addressed this issue,
47 are generally supportive. These commenters include a number of state
commissions.\740\ In addition, NARUC supports the continuation of a
``dynamic process requiring continuing dialogue between FERC and the
states.'' A number of public power entities also support the
process.\741\ Numerous Canadian entities also filed comments regarding
the usefulness of a collaborative process for the international aspects
of RTO formation.\742\
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\740\ See, e.g., Nine Commissions, Illinois Commission, Indiana
Commission, Michigan Commission, Montana Commission, Nevada
Commission, South Carolina Commission, Wisconsin Commission and
Wyoming Commission.
\741\ See, e.g., APPA, NRECA, CMUA, SRP, Snohomish, Seattle,
RUS, East Texas Cooperatives, IMEA, and Arkansas Cities.
\742\ See, e.g., Powerex, BC Hydro and Canada DNR.
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Only Florida Commission and CP&L are not fully supportive. Florida
Commission suggests that FERC collaboration will not work in Florida
but may work in other regions of the country. CP&L is not supportive
because the collaborative process could be used by the Commission ``as
a means of forcing utilities to develop RTO proposals on the
Commission's timetable'' which results in the Commission ``being
disingenuous when it describes its RTO policy as `voluntary'.''
Otherwise, CP&L believes the conferences will only serve as an
opportunity for participants to ``posture'' and that limited Commission
resources should not be used for
[[Page 942]]
meetings that ``are not likely to produce positive results.''
Specific comments about the collaborative process address three
basic issues: inclusiveness, process and procedures, and outcomes.
Inclusiveness. The NOPR stated that ``the Commission expects public
utilities and non-public utilities, in coordination with appropriate
state officials, and affected interest groups in a region to fully
participate in working to develop an RTO.'' It further stated that the
regional public workshops will be convened in cooperation with the
affected state officials and that transmission owners and operators
will be invited.
Many commenters advocate an open collaborative process that would
include a full complement of participants. They suggest that the
regional meetings include representatives of all stakeholders, for-
profit transmission companies, not-for-profit transmission entities,
state regulators, state legislators, state Governors, state energy
officials, state and non-state consumer advocates, state economic and
environmental regulators, environmental action interests and public
power/municipals. Some commenters indicate that in certain regional
efforts to form an RTO, the deliberations have excluded key interests
and, as a result, the outcomes were not widely supported. For example,
PJM/NEPOOL Customers note with respect to the PJM formation process
that ``[O]nly after all stakeholders were included in organizational
discussions was true progress made toward implementing an ISO that
adequately addresses all parties' needs.'' PNGC states that ``[I]f
other users do not have a seat at the table while merchant functions
do, obviously a level playing field is not created.'' New Orleans cites
Entergy's ``failure to even attempt to build a regional consensus
concerning its transco as a reason that inclusive regional conferences
are needed.''
Process and Procedures. Commenters raise a number of questions
regarding the collaborative process and specifically with respect to
the regional public workshops. Many commenters support the use/
availability of the Commission's Dispute Resolution Service (DRS) staff
or the use of outside facilitators. Some commenters request that the
Commission clarify that the meetings will be open meetings that can be
attended by any person. Several commenters urge the Commission to take
the cost and travel time to attend meetings into account in planning
the regional public workshops. Some specific locations are suggested
for sites for the regional workshops: New Orleans, Minneapolis/St.
Paul, and Seattle or Portland.
Several commenters suggest that the collaborative process begin
prior to spring 2000 in at least one region of the country--the Upper
Midwest. Commenters suggest that there is no need to wait and that the
region would benefit by immediate assistance from Commission staff as
described in the NOPR.
Some commenters ask the Commission to be mindful that the number of
regional meetings scheduled may not only be costly but unproductive as
well. Two commenters specifically say that we must not allow the
``death by meetings'' syndrome to be realized. Some interests may want
to stall RTO formation by promoting an ``endless'' series of meetings
that are not productive but are designed to ``preserve the status
quo.'' A few commenters suggest that the role of Commission staff at
the regional events should not be that of meeting referee but primarily
to provide policy guidance on key RTO issues and proposals. NRECA
proposes the creation of several Commission staff teams to ``facilitate
and informally monitor each RTO formation process'' and provide
``neutral guidance'' in the regions. Some commenters ask that the
Commission establish procedural rules in writing in advance of the
regional workshops so that all parties will know and understand the
rules prior to the meetings. Some commenters also request that all
reports, information and data produced for the meetings be readily
available to all participants.
Outcomes. The Project Groups suggest that the Commission should
``clearly delineate the substantive results expected'' from the
collaborative process. They suggest that collaboration progress reports
be filed with the Commission and that ``work products'' be required,
including: (1) Identification of RTO boundaries; (2) a list of all
transmission owners and facilities in the region; (3) a draft operating
agreement; (4) a draft governance structure and bylaws; (5) proposed
operating protocols; (6) a proposed budget/financial structure; (7) a
draft tariff; and (8) how the proposals meet the Commission's
guidelines, including a timetable.
Commission Conclusion. A key element of this Final Rule is our
commitment to the use of the collaborative process to assist in the
voluntary formation of RTOs. By collaborative process, we mean a
process whereby transmission owners, market participants, interest
groups, and governmental officials can attempt to reach mutual
agreement on how best to establish RTOs in their respective regions. We
reiterate our commitment of Commission staff resources, to the extent
possible, to assist parties in developing RTO proposals.
We are encouraged that state Commissions, public utilities, public
power entities and cooperative utilities, power marketing interests,
and consumer and environmental groups support the use of a
collaborative process. We are further encouraged that efforts to
develop RTOs continue in the West and Midwest, and that other areas are
reviewing the potential benefits of RTOs in their respective areas. We
believe that this represents a growing recognition throughout the
nation that RTOs will improve competition in electric markets and
enhance the reliability of the nation's electric grid.
We welcome participation in the RTO collaborative process by our
sovereign neighbors, Canada and Mexico. We believe that it is in our
mutual best interest to have electricity flow efficiently and
economically across our international boundaries. We pledge to continue
to work cooperatively with officials from Canada and Mexico to
encourage the operation and improvement of an international electric
system that benefits all consumers.
The Commission believes that the collaborative process must
accommodate the fact that different regions of the country are in
different stages of RTO formation and must be flexible enough to allow
for these differences. Therefore, we will initiate the collaborative
process with a series of five workshops in the Spring of 2000. The
primary objective of each workshop will be to develop a consensus
agreement by regional participants establishing a strategic process and
a schedule for any further collaboration. The appropriate collaboration
process will depend on whether the region is considering formation of
an ISO, transco, or other form of RTO. To achieve this objective,
participants will share information about the status of RTOs or RTO
proposals in the region, identify impediments to RTO formation in the
area, explore which process(es) could most expeditiously advance
agreements on RTO formation, and determine what role(s), if any,
Commission staff should play in advancing discussions in each region.
One result of these discussions may be regional decisions that more
than one RTO would be appropriate in the area encompassed by
participants at the workshop. Therefore, the collaborative
[[Page 943]]
processes that follow the various workshops may differ significantly.
This includes possible variations in the role that will be played by
Commission staff in each RTO formation effort.
The Commission believes that regional workshops in the Spring of
2000 will expedite the RTO formation process. In selecting locations
for the initial Spring 2000 workshops, we recognize trends in the
broader regionalization of the nation's electric system. We also
consider the evolving electric markets as well as the configuration of
the regional grid. We emphasize that the selection of locations for
initial workshops is not to indicate a preference for specific RTO
boundaries, but to provide convenient workshop locations. With these
considerations in mind, we designate the following workshop locations.
Parties may attend more than one regional workshop. We expect all
transmission owners to attend at least one workshop.
Workshops will be held in the following cities in February, March
or April, 2000:
1. Philadelphia, Pennsylvania
2. Cincinnati, Ohio
3. Atlanta, Georgia
4. Kansas City, Missouri
5. Las Vegas, Nevada
Workshops are expected to last for two days. Additional information
about the regional workshops will be provided in January 2000.
At the request of parties, the Commission staff may play a role in
the formation of RTOs. Commission staff will convene the regional RTO
workshops and provide policy and technical guidance consistent with
this rule. The Commission will supply meeting space for the five
initial Spring 2000 workshops. Regional participants are expected to
bear the costs of collaborative meetings after the initial five
workshops. Commission staff time and staff travel expenses will be
provided as resources allow.
We believe that it is critical to make the Spring 2000 Workshop
phase of the collaborative process open to all interested parties. In
order to promote an open process, we will provide public notice of
Spring 2000 Workshop events to allow all interested parties to attend.
We shall also make available agendas and procedural rules to all
parties in advance of the regional workshops. Agendas may vary from one
workshop to another.
The Spring 2000 Workshops represent the initial step of the
collaborative process. We expect that other meetings will be convened
following the workshops by parties in each region to bring the parties
together to form an RTO in each region. Commission staff may also
convene additional meetings if this would help RTO formation. The post-
workshop meetings of parties in regions may be held with or without
Commission staff participation. We will make available the Commission's
Alternative Dispute Resolution staff upon the request of an RTO group
in formation. At the request of such a group, independent private
professional facilitation services may be arranged by Commission staff
and must be sponsored by the parties within the region. As needed and
requested by parties forming an RTO in a region, Commission staff
members will be available to act as settlement judges, mediators,
facilitators or observers.
We believe that the best interests of the nation's electric
consumers will be served by the formation of RTOs. Therefore, we
encourage parties to establish strategic schedules at the Spring 2000
Workshops and to convene subsequent meetings with the goal of forming
an RTO expeditiously. Commission staff will monitor progress with
respect to the results or outcomes in each region.
We expect that, following the initial Commission-sponsored
workshops, parties in each region will work collaboratively to identify
the appropriate RTO regions, identify all transmission owners and
facilities in each region, and develop a timely application in
accordance with the Final Rule.
We have designated James Apperson of the Commission Staff to serve
as the collaborative process contact. He may be contacted at (202) 219-
2962 with any questions or comments about the RTO collaborative
process.
J. Implementation Issues
1. Filing Requirements
In the NOPR, the Commission proposed that all public utilities that
own, operate or control interstate transmission facilities (except
those already participating in a regional transmission entity in
conformance with the eleven ISO principles enumerated in Order No. 888)
must file with the Commission by October 15, 2000 either (1) a proposal
to participate in an RTO that will be operational no later than
December 15, 2001, or (2) an alternative filing describing efforts to
participate in an RTO, obstacles to RTO participation, and any plans
and timetable for future efforts.\743\ For those public utilities that
file an RTO proposal on or before October 15, 2000, we proposed to
permit them to file a petition for a declaratory order asking whether a
proposed transmission entity that would be operational by December 15,
2001, would qualify as an RTO, with a description of the organization
and operational structure, a list of the intended participants of the
institution, an explanation of how the institution would satisfy each
of the RTO minimum characteristics and functions, and a commitment to
submit necessary FPA section 203, 205 and 206 filings promptly after
receiving the Commission's determination on the declaratory order
petition. Finally, we proposed that the requirements not apply to a
public utility that owns, operates or controls transmission that also
is a member of an existing transmission entity that the Commission has
found to be in conformance with the Order No. 888 eleven ISO
principles; instead, each such public utility would be required to make
a filing no later than January 15, 2001, that (1) explains the extent
to which the transmission entity in which it participates meets the
minimum characteristics and functions of an RTO; (2) proposes to modify
the existing institution to become an RTO; or (3) explain efforts,
obstacles and plans with respect to conforming to these characteristics
and functions.
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\743\ FERC Stats. & Regs para. 32,541 at 33,761-63.
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Comments. Most commenters responding on this issue oppose one or
more aspects of the proposed filing requirements. For example, a number
of public utilities and two state commissions argue that the October
15, 2000, filing requirement does not provide enough time. Southern
Company contends that the proposed filing deadline requirement is
likely to be counterproductive because it imposes an artificial
deadline that may interfere with regional discussions. Moreover, once
established, a prematurely formed RTO may itself prove to be an
obstacle to more effective transmission organizations. Southern Company
also claims that the proposed mandatory filing requirements are
inconsistent with a truly voluntary approach. If the requirement is
retained, Southern Company suggests that the Commission clarify that
the alternative filings will be treated as status reports and not be
subject to deficiency orders or otherwise lead to proceedings in which
punitive measures might be taken, because any consideration or use of
penalties seriously undermines the Commission commitment to the
voluntary nature of RTOs.
Wyoming Commission recommends that the deadlines not be made
[[Page 944]]
mandatory in any way in the Final Rule because RTO formation is
supposed to be voluntary. Since it is unclear as to what happens to
those entities who file an explanation as to why they did not join an
RTO, Wyoming Commission urges the Commission to defer to each region's
process and timetable in developing an RTO and acknowledge that not all
regions are processing at the same pace. It recommends that the
Commission convert the October 15, 2000, deadline into a milepost for
reporting RTO development.
CP&L submits that the time frame is unrealistic because it
contemplates that new RTOs can be developed, approved by the
Commission, set up, and begin operation in less than two years.
Experience has shown that almost every RTO to date has taken at least
four years to go through that process. Therefore, the Commission should
modify the filing requirements to simply require informational filings
on the status of RTO development.
Sierra Pacific is concerned about insufficient time being allowed
for transcos to form. It points out that the precedent regarding ISOs
is much more well-developed than that regarding transcos. The certainty
surrounding ISOs makes them more attractive particularly when a
decision to form the entity must be made relatively quickly to meet the
proposed October 15, 2000, filing date. To lessen the incentive to rush
to join an ISO, Sierra Pacific suggests that: (1) The date for filing
an RTO proposal should be extended to June 15, 2002; (2) the Commission
permit transition mechanisms that will allow transmission owners to
eventually join transcos; and (3) the Commission not require
participation in an ISO to become a trap from which a transmission
owner cannot extricate itself. ComEd provides supporting arguments,
noting that where divestiture of transmission assets is involved to
form transcos, the necessary transition period will largely be dictated
by the sheer complexity--legal, financial (bonds and mortgage), real
estate (titles/easements), taxation--of separating a designated portion
of any electric utility that has historically been a vertically
integrated utility.
Based on its experience with the Midwest ISO formation process,
Kentucky Commission also argues that the proposed date to join an RTO
or respond with reasons for not joining is too short. It points out
that, if the Commission completes the Final Rule by the end of 1999,
transmission owners will have less than one year to make a final
decision on participation. Kentucky Commission urges the Commission to
give transmission owning utilities additional time to look into joining
an RTO, so that RTOs are not pushed so quickly that the best model
fails to materialize as a result of market evolution that remains
underway. South Carolina Commission and Big Rivers share the concern
that the proposed timeframe is too ambitious, given the complexity of
RTO related matters and the need to reach some level of consensus among
those with vested interests.
Several commenters noted that meeting the October 15, 2000, filing
requirement will depend on the Commission's standard of review of those
filings. For example, TDU Systems observes that the proposed filing
requirements have no teeth. TDU Systems contends that a public utility
that decides not to participate in an RTO can make an alternative
filing setting out the reasons why it is not doing so and what plans it
has to work towards participation. In TDU Systems' view, while the
proposed regulations are consistent with voluntary participation, they
are inconsistent with full and effective participation in RTOs. TDU
Systems counsels that the Commission should resist calls to water down
the RTO regulations even more, so as to treat alternative filings as
mere status reports that allow transmission monopolists to hold on to
their monopolies.
Duke submits that if the Commission is willing to accept valid,
well-justified explanations as to why a utility has not become an RTO
member, the October 15, 2000, filing requirement is reasonable, noting
that until state commission review of restructuring and RTOs is
completed, it may be premature for a utility to commit resources to RTO
membership. Similarly, Iowa Board suggests that, where transmission
providers are making legitimate progress, a report to that effect
should not be received with automatic disfavor. Alternative filings and
legitimate progress reports should be given equal validity with
definitive proposal filings.
A few commenters explicitly support the October 15, 2000, filing
requirements. For example, SRP believes it to be an acceptable balance
between mandated participation and the status quo. PJM/NEPOOL Customers
also support the filing by a date certain because this would expedite
the collaborative process and ensure that no entity can effectively
block RTO formation by engaging in inappropriate negotiation tactics.
And Oglethorpe views the October 15, 2000, time frame as necessary to
assure the timely development of RTOs and help develop fully
competitive efficient wholesale markets. Cinergy, noting that only
after the Commission has had opportunity to review the October 15,
2000, filings will it be able to determine whether it should order
participation in or reconfiguration of particular RTOs, suggests that
by April 15, 2000, all public utilities be required to file a statement
of position in which each utility identifies each state in which it
owns transmission, and the RTO in which it is considering membership
and its potential scope and configuration to the best of its knowledge.
A number of commenters address issues and treatments relating to
existing ISOs. Virtually all of the existing ISOs assert that the
Commission should allow the previously Approved ISOs to continue to
develop without undue interference in order to foster experimentation
and testing of proposals.\744\ Cal ISO argues that the Commission
should find that existing regional entities generally meet the RTO
criteria and that the Commission should confirm its determination not
to require substantial changes in approved ISOs that would undermine
difficult to reach consensus on critical issues. Similarly, the
Pennsylvania and New York Commissions recommend that FERC grandfather
the existing ISOs that meet the RTO characteristics and functions. The
Pennsylvania Commission states that it does not want to tinker with the
inner workings of PJM, nor constantly revisit and revise operations and
functions. The New York Commission is concerned that the New York ISO
tariff may have to incorporate the ``ordinary negligence'' liability
and indemnification provisions set forth in the pro forma tariff if the
ISO becomes qualified as an RTO, and that this will increase the ISO's
exposure to litigation. The South Carolina Commission supports NARUC's
position urging the Commission to grandfather existing ISO boundaries
that are satisfactory to the states. Similarly American Forest, CalPX
and Mid-Atlantic Commissions want the Commission to respect existing
ISOs.
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\744\ See, e.g., NY ISO, Cal ISO, NYPP and ISO-NE.
---------------------------------------------------------------------------
Furthermore, PJM/NEPOOL Customers contend that their ISOs are in
basic conformance with the minimum functions and characteristics. To
the extent that any deficiencies are found, the ISOs should be allowed
to engage in continued experimentation without interference from the
Commission. The Wyoming Commission also fails to see why existing ISOs,
already having gone through a rigorous approval process, should have to
re-certify as RTOs.
[[Page 945]]
Moreover, EEI notes that the Commission should weigh the incremental
gains achieved through economies of scale, efficiency, and additional
savings against the potential incremental costs of reorganization, new
computer programming, infrastructure changes, and changes required to
achieve effective communication and coordination. NYPP proposes that
ISOs be allowed to evaluate the costs and benefits of forming an RTO
after some years of market experience; hence, they oppose putting
members of existing ISOs on the same time frame for compliance as non-
members of ISOs/RTOs. United Illuminating recommends that the
Commission continue to honor and not abrogate pricing arrangements of
existing ISOs. United Illuminating also contends that, since existing
ISO members have no opportunity to discriminate because they have
turned control of their transmission over to their respective ISO, the
Commission cannot generically abrogate existing ISO pricing
arrangements pursuant to its FPA section 206 authority in this
rulemaking. Central Maine offers that consolidating the PJM, New
England and New York ISOs into a super-ISO will require costly
expansion of telemetry, communication, and computer equipment, that it
could result in a decrease in reliability, and that simple
interregional coordination could accomplish the Commission's goals
without consolidation.
A few non-ISO entities oppose any grandfathering of existing
regional transmission organizations.\745\ For example, New Orleans
argues that the Commission should not exempt existing regional
transmission entities from requirements of RTO formation because only
through universal application will all regions of the country receive
the benefits of open and competitive electric markets. H.Q. Energy
Services suggests that a larger territory, such as the combined
territory served by the existing New York, PJM and New England ISOs,
would be more effective than the NY ISO standing alone. PG&E counsels
that freezing the existing ISO structures in place would not serve
reliability or the marketplace and would be inconsistent with the open
architecture requirement. It believes that the Commission has struck an
appropriate balance imposing a reporting requirement on existing ISOs.
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\745\ E.g., Illinois Commission, New Orleans, SMUD and Turlock.
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Most commenters agree that existing operational transmission
entities should gradually evolve toward RTOs during a transition
period, rather than making immediate and drastic changes.\746\
According to SMUD, a transition period will enable customers to avoid
bearing unnecessary costs.
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\746\ See, e.g., SMUD, PJM/NEPOOL Customers, NYPP, Cal DWR,
MEAG, American Forest and Central Maine.
---------------------------------------------------------------------------
A few commenters address the specific filing requirements outlined
in the NOPR. The New York Commission asserts that the NY ISO should not
have to make a filing because it possesses the requirements of an RTO.
In addition, the Cal ISO argues that existing entities, rather than
individual public utilities, should be responsible for the RTO filing
requirements. Likewise, PJM suggests that existing ISOs report to the
Commission prior to any report by its public utility members, as the
existing ISO is in a better position to provide the Commission with the
most accurate information by which to evaluate whether the ISO
satisfies the minimum characteristics and functions for RTOs. PJM
suggests that existing ISOs and existing transmission entities file
reports no later than December 31, 2000, explaining whether they
satisfy the Commission's requirements for RTOs and identifying any
additional authority they may require for this purpose. On the other
hand, EPSA welcomes the proposal requiring a showing of how the
existing transmission institutions meet the minimum characteristics and
functions by January 15, 2001, as a way to help address and solve
continuing discrimination within current ISOs and address whether these
institutions should be combined into larger groupings. Similarly, NYC
wants the NY ISO's January 15, 2001, filing to demonstrate how its
efforts to improve regional cooperation will overcome the institutional
impediments that have contributed to the city's load pocket condition.
Finally, commenters raise a number of miscellaneous issues: Puget
questions whether there will be negative implications for any entity
the choose to cease participation in an RTO; DOE points out that RTOs
may need to fund pensions for transferred employees, and existing
transmission providers may need to fund early retirements or other
compensation for displaced employees; UMPA recommends that recourse to
the Commission in a de novo capacity must be part of all RTO dispute
resolution procedures; and Indiana Commission, Snohomish and Midwest
ISO express concern about how the Commission intends to handle multiple
RTO proposals covering approximately the same region.
Commission Conclusion. The Commission will adopt the NOPR proposal
requiring that all public utilities that own, operate or control
interstate transmission facilities (except those already participating
in an approved regional transmission entity) file by October 15, 2000,
either a proposal to participate in an RTO or an alternative filing
describing efforts and plans to participate in an RTO. As proposed
initially, we will consider a petition for declaratory order setting
forth the items listed in section 35.34(d)(3) as a proposal to
participate in an RTO.
We believe that the October 15, 2000, date for filing proposals is
realistic. It is not overly aggressive, given the amount of guidance we
have provided in this Rule and the amount of flexibility we are
permitting in how to satisfy the minimum characteristics and functions.
In addition, the collaborative process that we are promoting in this
Rule will provide an opportunity for all interested parties with their
varied interests to resolve many of their differences, in advance, and
reach consensus on the RTO solution that best fits the overall needs of
their respective region. The October 15, 2000, filing date should help
keep the parties focused and accelerate their efforts toward selecting
an appropriate RTO model.
The October 15, 2000, date for filing is also reasonable because,
even if a public utility is unable to file an RTO proposal at that
time, we are permitting the public utility to make an alternative
filing reporting on the status of pertinent RTO formation and
development, the obstacles that have prevented the filing of an
appropriate RTO proposal, and any of the public utility's plans and
timetable for future efforts directed toward RTO formation and
participation.\747\ Given the importance that the Commission places on
RTO development, it is important for us to understand no later than
October 15, 2000 just how much progress the industry is making on
forming RTOs. If the October 15, 2000, filings reveal obstacles that
prevent serious progress toward RTO formation are reported for a given
region, we will be able to act early enough to provide guidance on what
steps we think are appropriate to help address the obstacles (e.g.,
further collaborative efforts). And where serious regional progress is
reported, but more time is requested in connection with meeting a
particular RTO requirement, we will be able to act early enough to try
to accommodate the local needs,
[[Page 946]]
complications and complexities that the particular region faces.
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\747\ Of course, these reports may be filed prior to October 15,
2000.
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Some concern has been expressed that the October 15, 2000, filing
date is too short to allow transcos to form because of the inherent
legal, financial, real estate and taxation complexities associated with
the transfer of ownership of the affected transmission assets. We are
not proposing that the restructuring be completed by October 15, only
that a proposal be filed, or an alternative filing as described in this
Rule. Moreover, we take note of the fact that other forms of major
corporate restructuring, including mergers, have proceeded from initial
idea to formal proposal in a shorter time when the motivation is
sufficient. Therefore, we do not think the time allowed is too short
for transco proposals.
We also reaffirm the proposed January 15, 2001, filing date for
transmitting public utility members of an existing approved
transmission entity to address the extent to which that entity conforms
to the minimum characteristics and functions of an RTO, any plans to
make it conform, and any obstacles to full conformance with our Final
Rule. We note that RTOs will not be ``starting from scratch.'' There is
significant information available about both the good and bad
experiences with ISOs, and this information should help RTOs meet this
filing deadline.
While we are allowing a later filing date for existing transmission
institutions to file (January 15, 2001, versus October 15, 2000), we do
this because, in general, the transmission owners in those regions have
already made substantial progress in establishing regional entities.
Nonetheless, the Commission needs to know, for all regions, including
those covered by existing approved transmission institutions, the
extent of progress toward formation of fully functional RTOs. To the
extent that an existing ISO, for example, is less than adequate with
regard to one of the necessary characteristics or functions, we would
expect the existing institution to be working on a plan of action to
make the remedial improvements that are required to bring it into
conformance with the Final Rule.
In sum, we continue to believe that the October 15, 2000, and
January 15, 2001, filing dates represent an acceptable balance between
the need to move toward RTOs as soon at possible and the need for
sufficient time for transmission owners and market participants to
develop proposals.
2. Deadline for RTO Operation
The Commission proposed that all public utilities participate in an
RTO that will be operational by December 15, 2001. In addition, we
contemplated implementation of the congestion management function
within one year after startup (by December 15, 2002), and
implementation of inter-regional parallel path flow coordination and
transmission planning and expansion functions within three years after
startup (by December 15, 2004).
Comments. Most commenters suggest the December 15, 2001, deadline
should be changed to a later date or that the Commission provide
greater flexibility in meeting the deadline. On the other hand, Oregon
Commission explicitly favors the December 15, 2001, deadline, arguing
that the time line is designed in stages so that the easiest
requirements come earliest. EPSA fears that further delay of any of the
operational deadlines for any of the required RTO functions (i.e., for
initial startup, congestion management, parallel path flow
coordination, or transmission planning and expansion) will only
encourage further debate and dialogue without driving the industry
towards acceptable resolutions, and prolong the problems of residual
discrimination and remaining market inefficiencies.
Two commenters propose an earlier deadline. PG&E contends that the
transition period for RTOs to meet all requirements must be as short as
possible--no more than one or two years to fully operational RTOs may
be reasonable. Sithe similarly argues that, while the negotiations and
proceedings associated with voluntarily RTOs can take years to
complete, the California experience suggests that an RTO can be
established quickly if a deadline exists. Sithe recommends that the
Commission reconsider its time frame and do everything it can to hasten
the process of putting in place RTOs with all minimum characteristics
and functions. It observes that, as proposed in the NOPR, an RTO could
defer for up to three years the filing of a plan for transmission
planning and grid expansion. The details may not be finally approved by
the Commission for at least another year such that a delay of over five
years could result.
SRP and American Forest express concern about who will be
responsible for building and paying for new transmission facilities
until the RTO takes on this responsibility. In particular, SRP suggests
that the Commission require each RTO filing to describe who will be
responsible for financing and building transmission expansions during
the interim.
Most commenters, however, view the proposed deadline as too
aggressive, and recommend that it be eliminated or extended. CP&L views
the operating deadline as arbitrary and capricious, and argues that the
deadline will impose higher implementation costs and inefficiency that
will not benefit the public or the industry. South Carolina Authority
believes that to assume that a large group of stakeholders with diverse
interests can somehow come together and agree on a particular RTO model
and configuration by October 15, 2000 that is up and running by
December 31, 2001, is unrealistic. East Kentucky suggests that the
timetable be extended approximately two years. Montana Power encourages
extension by one year because areas like the Pacific Northwest will
probably need significant infrastructure to be developed or re-deployed
and the 14 month time frame contemplated after RTO proposals are due on
October 15, 2000, is not sufficient time.
A number of commenters favor a flexible approach and allowing
provisional RTO status. Cinergy offers that, to overcome obstacles such
as legal impediments to public power participation, alternative means
of RTO participation be considered such as joint operations without the
functional integration of public systems' facilities to allow them to
control the private use of their systems. SERC generally concurs.
Williams contends that not all RTOs will be able to develop at the same
pace, and supports provisional RTO status with dates certain respecting
those functions not able to be performed at startup.\748\ SNWA
recommends that, if necessary, a phase-in approach should be used in
the implementation of an RTO to smooth the implementation process.
Project Groups contends that, given the California experience, the cost
of attempting to do everything at once is significant. Transmission ISO
Participants urges flexibility for transmission owning members of
exiting ISOs since the current structure represents an imperfect and
probably unfinished agenda. EEI contends that the Commission should
allow flexible timetables to establish RTOs that are transcos,
contending that a vertically integrated utility that selects the option
of moving transmission assets to a transco faces complex financial and
tax issues. Nevada Commission urges the
[[Page 947]]
Commission to clarify that there is no prohibition against forming
interim organizations such as an independent system administrator until
such time as a viable RTO for the region is formed. South Carolina
Commission claims that each RTO proposal should be reviewed on a case-
by-case basis for general adherence to the Commission's overall policy
goals.
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\748\ Note that a number of comments opposing deadlines are
based on the difficulty of attaining specific RTO functions. These
comments are also addressed in the sections regarding the specific
functions.
---------------------------------------------------------------------------
Indiana Commission cautions, however, that careful consideration
should be given to what will be lost by the acceptance of an RTO
``lite.'' It argues that existing transmission entities may see little
value in maintaining relatively high standards and could view the
Commission acceptance of lower standards as an incentive to gravitate
to lower standards. PG&E recommends the Commission grant waivers from
its requirements only in limited cases and only for short durations.
AEPCO, contends that there should be a reasonable basis for granting
waivers, particularly for non-jurisdictional entities. In particular, a
request for waiver should consider: (1) How much additional RTO
transmission would result from inclusion of the facilities in an RTO;
and (2) whether the RTO would be functional without inclusion of the
entity's facilities. Sithe argues that care should be taken when
considering whether to permit RTOs to go into effect without meeting
functions and in granting waivers, and suggests that the Commission
establish clear requirements for RTO approval, strictly scrutinize
proposals, and not hesitate to reject inadequate proposals.
Commission Conclusion. We have decided to retain the originally
proposed startup and other functional implementation deadlines (RTO
startup by December 15, 2001, implementation of congestion management
by December 15, 2002, and implementation of the parallel path flow
coordination and transmission planning and expansion functions by
December 15, 2004).
As a general proposition, we believe that, given the urgent needs
of electricity markets as discussed elsewhere in our Final Rule, we
have an obligation to promote RTO operation at the earliest feasible
date. Even where a market may already be served by an ISO or other
approved transmission entity, we are concerned that such market may
remain hampered to the extent that the approved entity has yet to fully
conform with our Final Rule.
In response to those who contend that December 15, 2001, is too
ambitious for RTO start-up, we note several points. First, we, and the
industry, now have had the benefit of the experience of the formation
of five ISOs under Commission jurisdiction, an ISO in ERCOT, some
international experience with regional transmission entities, and
substantial discussion of the subject of regional transmission entities
within the industry. While the timeframe we are suggesting for RTO
formation may have been unrealistic several years ago, much has been
learned since then which should facilitate more rapid formation.
Second, our Final Rule is providing substantial flexibility that
should permit an RTO to satisfy the minimum characteristics and
functions in a cost efficient manner. For example, we are not requiring
control area consolidation; we are not requiring the establishment of a
PX; we are allowing an RTO to meet its operational control obligation
through indirect or hierarchical control arrangements via contractual
agreements with the existing infrastructure such as transmission owners
and control area operators; and we are allowing an RTO to satisfy its
security coordinator functions through contractual arrangements with an
external security coordinator, as long as it is independent. An
acceptable RTO structure need not be a monolithic organization that
requires an extended period of time to become fully set up so that it
can directly ``push all of the buttons.'' Moreover, we are allowing a
longer phase-in period for functions that may be more difficult to
establish, such as congestion management, parallel path flow measures,
and transmission planning and expansion.
With respect to the comments that question the December 15, 2002,
deadline for implementing the congestion management function, we
believe that lack of effective and market-oriented congestion
management is a critical issue in the industry, and that it needs
attention soon. We acknowledge that developing a sophisticated
congestion management program can be an extremely complex and time
consuming matter. However, implementation of economic approaches to
congestion management by some of the approved ISOs shows the
feasibility of these concepts where there is an institution to
undertake the organization of this function over a large area.
Some say that transmission congestion is not a serious problem in
their regions, and that they therefore should not be required to
develop a complex congestion management plan within a short time-frame.
We agree that an RTO should not have to expend large resources to
address a problem that does not exist. However, we are concerned that
an RTO fully analyze the extent to which transmission congestion does
or could interfere with electricity sales in its region, and that it be
prepared to address congestion if it becomes a more serious problem
through changing markets. As markets become more competitive and the
volume of discrete transaction increases, transmission congestion may
become serious unless action is undertaken beforehand. Where
transmission congestion is infrequent, this Rule does not preclude the
establishment of relatively less complex forms of market-compatible
congestion management such as generation redispatch protocols.
In sum, we think that the phased startup and other functional
implementation deadlines are reasonable.
3. Commission Processing Procedures
The Commission recognized that RTO formation would be complicated
by the requirements for Commission approval of transfer of control of
jurisdictional facilities under FPA section 203 and Commission approval
of RTO transmission rates, terms and conditions under FPA section 205.
In the NOPR, the Commission requested comments on whether the
Commission should provide expedited or streamlined processing
procedures for RTO filings and asked for suggestions regarding how the
Commission can further expedite and streamline procedures.\749\
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\749\ FERC Stats. and Regs. para. 32,541 at 33,759.
---------------------------------------------------------------------------
Comments. Views on streamlined and expedited processing of RTO
filings are mixed. Commenters that generally favor streamlining include
Desert STAR and TEP, which suggests that filing requirements be kept
simple and flexible.
A number of commenters offer specific suggestions for streamlining
and expediting the process, including:
Florida Commission believes that once an RTO or other
structure has been agreed upon by a group of entities, the Commission
should expedite all required processes in order to allow the
participants to start implementing the agreed upon changes.
Tallahassee recommends that the Commission should clarify
that it is not revisiting the functional test for distinguishing
transmission and distribution facilities addressed in Order No. 888.
Entergy asserts that significant delay in obtaining
Commission approvals will make it difficult for Entergy to institute a
transco within the time-lines established by state restructuring laws
in Arkansas and Texas. Providing clear rules on the
[[Page 948]]
required and permissible features of RTOs as the Commission did in its
July 30, 1999 Declaratory Order for Entergy and providing clear
standards on pricing policies will help. Entergy argues that the
Commission should make explicit its willingness to consider requests
for expedited approval when a showing is made that expedition is
necessary, as it has done for California ISO.
Trans-Elect notes that if a transfer of facilities cannot
close under Section 203 until the related FPA section 205 proceeding is
concluded, an expedited Section 205 filing must also take place. One
way to do this is to waive an Initial Decision and set a date certain
for the Commission's section 205 decision.
PJM/NEPOOL Customers recommend that a standard RTO
governance structure be adopted that allows participation by all
stakeholder groups. It would expedite processing by requiring that any
RTO filing demonstrate that all stakeholders were included in the
formation process.
SMUD recommends that the Final Rule require that RTOs be
designed, developed and implemented in a manner that does not require
numerous tariff amendments to remedy market ills that could be
addressed prospectively or at a speed that does not dramatically
increase RTO development costs.
On the other hand, some commenters urged the Commission to exercise
caution regarding streamlining and expediting:
East Texas Cooperatives observes that a poorly configured
RTO can potentially be more harmful to the industry than the status
quo, by allowing large transmission owners to dominate regional grid
management, maintain pancaked rates and discriminate in allocating
transmission revenue.
Indiana Commission recommends that state commissions and
other interested parties have full opportunity to thoroughly review,
comment, and have an impact on the RTO proposals once they are filed
with the Commission.
Puget indicates that a negative implication of allowing
streamlined filing and approval procedures for RTO participants is that
regulatory burdens will be leveled against nonparticipants while those
who join an RTO will be freed from what the Commission implicitly
recognizes are unnecessary requirements. A truly voluntary system would
not continue to impose unnecessary regulatory requirements on
nonparticipants and there is no reason for the Commission to delay
implementing these regulatory reforms now before a final decision is
made regarding the wisdom or efficacy of RTOs, or to condition the
implementation of such reforms on an entity's participation in an RTO.
Duke contends that, given the size and complexity of the
typical section 203 and 205 of the FPA filings, it is not clear that
reducing the time that parties are granted to review such filings and
provide initial comments may be appropriate. Nonetheless, the
Commission should work to dismiss irrelevant issues used as leverage to
extract concessions unrelated to RTO formation, it should consider use
of less formal hearing procedures for issues that do not require
discovery, and the Commission should limit the time period allowed for
evidentiary hearings. Duke acknowledges that the effect of streamlined
filing and approval procedures could be to reduce costs that would
otherwise be born by market participants.
Commission Conclusion. While there is broad-based consensus for
simplifying the Commission's RTO filing process and responding to RTO
proposals expeditiously, we must maintain an appropriate balance
between streamlining and expediting the filing and processing of RTO
proposals and ensuring due process and the development of an adequate
record. Given the amount of flexibility we have built into the Rule as
to organizational structure, it is difficult to predict what issues
will be raised by the RTO proposals and the degree of complexity raised
by such issues. Accordingly, while the Commission has the goal of
ensuring the rapid formation of RTOs, and will attempt to process each
RTO proposal as expeditiously as possible, certain RTO proposals will
take longer to analyze and review depending upon the complexity of the
issues and the level of support among the affected parties. Therefore,
in addition to the specific guidance provided elsewhere in this Rule,
we provide further guidance and note the following factors which are
intended to assist public utilities in streamlining their required
filings and help expedite the processing of the RTO proposals.
One factor that should facilitate faster processing is that the
Final Rule permits delayed implementation dates for various highly
complex FPA section 205 related RTO provisions (congestion management
by December 15, 2002, and parallel path flow coordination and
transmission planning and expansion each by December 15, 2003).
Therefore, initial RTO proposals need not contain the details for these
provisions, but need only contain a commitment to complete the
provision and a timetable for submitting appropriate future filings.
Likewise, we need not act on those matters initially in our RTO orders.
Expeditious processing of an RTO submittal is more likely to occur
if the RTO proposal is the result of a comprehensive and open
collaborative process with widespread support from transmission owners,
market participants, and affected state commissions. While we cannot
pre-approve unopposed proposals, many of our potential concerns could
be minimized to the extent the proposal has broad support.
Another potential streamlining measure is that public utilities are
permitted to file RTO proposals jointly with other entities. For
example, in the case of existing ISOs and other approved regional
transmission entities, the regional entity may file on behalf of the
individual public utilities. This will reduce the volume of submittals
that must be developed by public utilities and be reviewed by the
Commission.
We note that, with the exception of governance, experience gained
from past ISO proceedings, will be directly transferable whether the
form of RTO is an ISO or a transco. For transcos, as discussed
elsewhere in the Final Rule, restrictions on ownership of transcos that
we have adopted are designed to work in tandem with restrictions on
governance in order to ensure adequate levels of independence.
We believe that RTO proposals that reflect the above factors,
should allow the Commission to minimize the amount of time necessary to
analyze and process the submittal. While the Commission cannot
guarantee that we will be able to respond to every proposal within a
pre-set period of time, we will make every reasonable effort to issue
an initial order on an RTO proposal within 60 days,\750\ after the
comment period closes.\751\ With respect to RTO proposals that present
contested issues or problematic RTO provisions, we will make every
effort to expedite
[[Page 949]]
consideration of the proposed RTO and we will continue to consider
alternatives to formal procedures (e.g., ADR procedures), where
warranted, to avoid initiating a hearing.
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\750\ We recognize that, while there is no statutory deadline to
act on section 203 filings, there is a 60-day statutory clock
requiring action on section 205 related filings within 60 days from
the date of filing, in the absence of a proposed effective date
extending beyond the 60-day time frame. However, in most instances,
we expect that the RTO submittals will typically propose FPA section
205 effective dates that will be beyond the 60-day nominal clock.
\751\ This proposed time frame refers to applications that are
consistent with the guidance provided in this Rule and that provide
all the necessary information. We further note that the Commission's
review process will restart in the event that applicants modify
their proposal or supplement the supporting information in their
application.
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What the Commission has approved for ISO forms of governance can be
used as models for governance of RTOs that are ISOs. Nothing in this
Rule prohibits the types of independent governance structures we have
approved to date. All of the ISOs approved to date, except one, have a
two-tier form of governance wherein a non-stakeholder board at the top
generally has final decision-making authority on most issues. Below
this board are advisory groups or committees comprised of stakeholders
that provide advice and may share some decision-making authority. With
regard to the second-tier, the Commission has required that no one
constituency in any group or committee be allowed to dominate the
recommendation or decision-making process over the objection of the
other classes, and that no one class holds veto power over the will of
the remaining classes. The California ISO's governance structure is
different. It has a single-tier hybrid decision-making board comprised
of both stakeholders and non-stakeholders. No two classes can push
through a decision over the objection of other classes, and no one
class has veto power over the will of the remaining classes.
4. Other Implementation Issues
Commission Conclusion. An additional issue some commenters raised
in connection with implementation concerns how the Commission intends
to handle multiple RTO proposals that pertain to the same or
overlapping regions. We expect that proper adherence to the
collaborative process and the RTO scope and configuration factors we
have identified, in the first instance, will bring order to the
formation of RTOs such that the Commission will not need to step in and
decide the matter of competing RTOs at the filing stage.
Several miscellaneous RTO implementation issues that were raised by
some commenters concern the terms of withdrawal for members from an
RTO, the RTO's funding of staff compensation in connection with
transfers of personnel from other entities, and the Commission serving
as a backstop for RTO's ADR processes. These matters, however, are best
left to case-specific determinations in response to particular RTO
proposals.
In response to those who argue for or against rejection or waiver
in connection with less-than-fully-conforming RTO submittals, we
believe the concepts of rejection and waiver are not appropriate. We
have provided a significant degree of flexibility in the minimum
characteristics and functions, and in many instances specifically allow
for alternative ways to satisfy those characteristics and functions.
Proposals that do not satisfy the minimum characteristics and functions
will not be approved as RTOs. That does not mean that such a proposal
would be summarily rejected; in fact, it may still be an improvement
over the status quo as long as it is consistent with the FPA
requirements. However, it may be questioned the extent to which
entities that are not participating in RTOs have acted to eliminate the
impediments to competition we have identified in this Final Rule.
IV. Environmental Statement
This section reviews and adopts the Environmental Assessment (EA)
prepared by the Commission staff in connection with this Final Rule. It
identifies the alternatives considered by the agency in reaching its
decision; analyzes and considers whether and to what extent, if any,
the chosen alternative--adoption of this Final Rule--affects the
quality of the human environment; and states the Commission's decision.
Summary
The analysis compares generation and emission trends under the
Final Rule to baseline trends without the Final Rule. The analysis
indicates that the Final Rule will result in little generation change
on a net national basis, but there may be shifts in regional
generation. Economic benefits of the Final Rule can be realized with no
significant, adverse environmental impacts. Further, the potential
exists for environmental benefits to be realized, through the
encouragement of newer, cleaner resources.
Discussion
A. Background
To further the policies and goals of the National Environmental
Policy Act of 1969 (NEPA), Commission staff prepared an EA in order to
examine potential impacts that could result from implementing the
Commission's Rule, and to serve as the basis for considering whether
the Final Rule will have significant impacts on the quality of the
human environment. On May 14, 1999, the Commission issued a notice of
intent to prepare an EA, and a request for comments on the scope of the
issues that should be addressed in the EA. On July 8, 1999, a public
scoping meeting was held at the Commission. On October 22, 1999, the
Commission issued an EA, and invited interested parties to comment on
the EA. Comments were due on November 22, 1999.
The Commission received two filed comments on the EA (NMA/WFA/CEED
and Project Groups on behalf of multiple public interest groups).
Specific comments are addressed in the relevant sections below.\752\
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\752\ As noted in the EA, a number of comments filed during
scoping relate to matters outside the scope of the EA, and for the
most part deal with policy issues that are addressed in the Rule.
---------------------------------------------------------------------------
B. Scope of the Analysis
The EA examines potential environmental impacts that could result
from implementing the Commission's Final Rule. The impacts are
necessarily uncertain because they would be the product of changes in
economic regulation that may alter the future behavior and perhaps the
future structure of electricity supply markets. In turn, these
behavioral and structural changes could lead to a different set of
environmental conditions than would otherwise be the case. The analysis
recognizes the uncertainty of the Rule's potential effects on future
markets. It presents a systematic view of possible future market
changes and assesses a range of possible responses to market changes,
but should not be seen as predictive of specific market or
environmental outcomes.
The EA addresses a broad range of potential economic changes that
could result from the Rule. These impacts include changes in the mix of
electric generating plants built in the future, shifts in the
utilization of existing plants, and increases in interregional
transmission. The analysis, therefore, includes major air pollutants:
sulfur dioxide (SO2), nitrogen oxides (NOX),
mercury, and carbon dioxide associated with various types of generating
plants and fuels. The EA addresses potential environmental impacts at
national and regional levels.
Project Groups expressed concern that the EA does not
retrospectively analyze the impacts of open access policies to date. As
stated in 1.3.2 of the EA, we believe it is neither possible nor
desirable to analyze such changes. Data collection lags, and the short
period of time that has elapsed since the issuance of Order No. 888,
would preclude us from drawing meaningful conclusions.
Project Groups also stated that economic impacts are not
specifically reported in the EA, making it more difficult to evaluate
the impacts of the
[[Page 950]]
Rule. We note, however, that the modeling and analysis conducted for
the EA are the basis for the economic discussion contained in the Final
Rule. These economic results do not provide a complete analysis of the
potential economic impacts because the analysis considers only economic
effects which may relate to operating decisions or new capacity, and
thus may lead to environmental consequences. However, there are other
economic benefits from competitive wholesale electric power markets
which have little or no effect on the environment.
C. Analytic Approach
Because the impacts that could result from the rulemaking are
uncertain, an analytic approach known as scenario analysis was used. In
this approach, alternative views of the future are postulated and
analyzed with and without the Final Rule. Potential environmental
impacts are evaluated by comparing the analytic results of the
scenarios. First, an analytic base case was developed. This base case
relies on the assumption that the Commission would pursue current
policy with respect to wholesale electric competition using existing
rules and procedures, including case-by-case implementation of regional
market arrangements.
Having established an appropriate base case, the EA analyzed future
impacts assuming that the Rule is in effect. Staff adopted the
assumption that the Final Rule, although voluntary, would result in the
establishment of RTOs throughout the study area with the
characteristics and functions set forth in the Final Rule. Three
scenarios were developed to reflect a range of possible economic and
environmental outcomes: Transmission Efficiency Scenario; Transmission/
Generation Efficiency Scenario; New Entry Scenario.
D. Alternatives to the Rule
The primary alternative to the Final Rule is for the Commission to
maintain the status quo, that is, to continue its existing open access
policies. The result of this no-action alternative, without
implementing the Final Rule, is that the Commission would effectuate an
open transmission grid, but not address changes in the industry that
have occurred since Order No. 888 was adopted. However, the no-action
alternative describes what is likely to happen if the Commission takes
no action over and beyond implementation of existing policies. Once
this baseline is established to portray what is likely to happen in the
electric industry during the study period, the projected impacts of the
Final Rule can then be determined against this backdrop.
In addition to the Final Rule and the no-action alternative,
several alternative approaches were considered and ultimately rejected.
The alternative of analyzing mandatory RTOs, as compared with voluntary
RTOs as set forth in the Final Rule, was rejected as moot, since the EA
assumes that voluntary RTO formation proceeds with little delay and is
successful in creating RTOs with the functions and characteristics
contained in the Rule. Hence, assumptions for voluntary RTOs and
mandatory RTOs are analytically indistinguishable in terms of their
effects on the transmission grid and on the electric sector generally.
The other major alternative considered was the analysis of
alternative fuel price assumptions. Project for Sustainable FERC Energy
Policy suggested that we prepare such an analysis. However, as we noted
in the EA, this alternative was ultimately rejected for two reasons.
First, as reflected in scenarios analyzed in the EIS for Order No. 888,
plausible variation in gas prices relative to coal prices is unlikely
to have a major impact on the environmental effects of the Final Rule.
Therefore, a gas price scenario was selected that had the general
characteristics of other forecasts, namely, that gas prices will rise
relative to coal prices. The selection of this gas price scenario does
not represent an endorsement of this particular gas price path.
Although we believe it to be a reasonable projection, it is a merely a
representative projection of gas prices for purposes of the EA. Second,
there is no need to consider an alternative where competition favors
gas over coal because such a scenario would have little adverse impact,
especially when compared with scenarios that tend to favor increased
coal use relative to gas use. In the rule scenario we selected, we
included, therefore, a number of improvements in coal technology as a
result of the RTO Rule, to ensure that the potential impacts of any
increased coal use relative to the base case would be considered in
assessing the environmental consequences of the rule.
E. Analytic Framework and Assumptions
It is expected that the impacts of the Final Rule will result
primarily from changes in the types and locations of power plants and
transmission facilities constructed in the future and changes in the
operating patterns of existing power plants, including changes in the
fuel mix. To examine the impacts thoroughly, the modeling approach
chosen includes detailed representations of electric power plants and
the electric transmission grid, and allows for an economic (least-cost)
compliance with existing and future environmental regulatory
requirements.
Computer modeling capable of simulating regional electric utility
dispatch and capacity expansion over time was used to characterize
electric power markets in the base case and rule scenarios. We used a
large supply optimization model of the U.S. electricity supply sector,
which emphasizes pollution estimation and pollution control. It has
been used for Environmental Protection Agency (EPA) regulatory analysis
in publicly accessible proceedings since 1996.
Analytic assumptions are a critical part of the modeling. Because
the model cannot tell us directly what the RTO-related changes will be,
it must assess how a set of assumed changes in the cost and/or physical
properties or the electricity system could lead to changes in the use
of the system, and hence to changes in emissions.
A series of specific assumptions were developed to model the base
case and scenarios. Assumptions common to all modeled cases include
current and future prices of fossil fuels, particularly coal and
natural gas, and current and future requirements imposed on the
electric sector by environmental laws and regulations. These
requirements include: for SO2, continuation of the Title IV
Acid Rain Program, with Phase II coverage and levels of permitted
emissions; for NOX, Title IV requirements on coal-fired
boilers (Phase I and Phase II); emissions cap restrictions in the Ozone
Transport Region starting in 1999, and implementation of the Final Rule
governing ozone transport issued by the EPA in 1997, modeled in
accordance with the EPA's guidance. This EPA Rule imposes a cap on
NOX on large utility boilers in 22 states in the eastern
United States and limiting summer NOX emissions to 543,800
tons; no regulatory restrictions are assumed for mercury or
CO2.
Project Groups commented that, since assumptions made in the EA
about future environmental regulations are critical in determining the
outcome of the analysis, changes in future environmental regulations
(particularly due to legal challenges) from those assumed in the EA
could result in different environmental impacts. Accordingly, the
comment states that the EA should reflect possible changes. We note
that there are many important analytic assumptions embodied in the
[[Page 951]]
modeling for the EA. Environmental regulations are directly represented
in the analysis, and changes in these assumed regulations do have a
large effect on the results of the modeling. In particular, the
presence or absence of SO2 and NOX caps is a key
assumption. Nevertheless, these assumptions are based on regulations
which are final, as opposed to proposed regulations or speculative
regulatory actions. These rules and associated regulatory analyses from
EPA were used as the basis for the EA assumptions. Accordingly, it
would be premature and speculative to consider changes, if any, from
pending legal challenges or speculative future regulatory changes.
In a broader sense, it is clear that successful competitive energy
markets will be complemented by cost-effective environmental
regulation, because the incentives for efficient behavior on the part
of market participants can be decentralized and the need for intrusive
regulatory action is lessened. Emissions trading programs such as those
for SO2 and NOX are an important example of such
cost-effective regulation.
Other invariant assumptions include: net electric demand growth
(with the exception of New Entry Scenario); load shape (how demand
varies with season and time of day within each model region); costs and
performance of new power plants; and capacity and generation of
nuclear, hydroelectric, pumped storage, and import supply.
Because of the importance of the transmission system in the Rule,
assumptions were made about potential changes that may come about
either because of the Rule's requirements or because of its increased
incentives for better grid operation and investment. In addition, the
Final Rule is expected to develop more competitive bulk electric power
markets. Competition is expected to increase the incentives for
efficient behavior among market participants. To assess the potential
effects of such increased efficiencies on the environment, some
assumptions affecting new and existing power plants were changed.
Finally, to respond to concerns expressed by parties in the scoping
process regarding the role of new entrants in developing competitive
power markets, particularly the RTOs, a model scenario was developed
that specifically addresses new entry and enhanced consumer choice.
F. Impacts
The EA analyzes the electric power capacity and generation
projections on a national and regional level for the base case, and
presents the corresponding environmental impacts. Projected trends in
generating capacity, including economic additions, retirements and
modifications, and generation by plant type for the base case, are
analyzed for the years 2005, 2010, and 2015. The data indicate that
virtually all future capacity additions are expected to be gas-fired
combined cycle or combustion turbine units; coal will nevertheless
remain the dominant fuel for generation. Growth in natural gas,
however, will be rapid, with the share of generation increasing from 13
percent in 1997 to 32 percent in 2015; total generating capacity is
expected to grow at a slower rate than demand, resulting in plants that
will generally be operated at higher capacity factors; regional
patterns of generation reflect regional demand growth as well as
changes in interregional trade in electricity. In most regions, growth
in demand is met by gas-fired (or oil/gas switching) plants, although
in the Midwest existing coal-fired capacity meets part of the growth in
the early years of the forecast.
The EA projects national emissions in the base case for
SO2, NOX, mercury, and CO2. There are
also regional emissions projections for NOX. The analysis
indicates the following:
1. SO2 emissions will decline gradually to 9.5 million
tons in 2015. Variations in such emissions during the forecast period
primarily reflect economic use of the Title IV emissions banking
program, under which emitting parties may elect to over-control
SO2 in any year and bank the extra reductions as emission
credits for later use;
2. Regional SO2 emissions generally will follow the same
pattern as the national emissions total. However, emissions reductions
and shifts are not expected to occur uniformly across regions because
the SO2 emissions trading program allows emitting parties
with higher costs of pollution control to purchase allowances from
emitting parties with lower control costs. This can lead to increases
in emissions from certain regions;
3. NOX emissions are projected to decline to 4.1 million
tons in 2015. These reductions are due to the development of
NOX regulations under the Clean Air Act. Furthermore, summer
or ``ozone season'' (May to September) NOX emissions are
projected to decrease to 1.3 million tons in 2015;
4. Regional NOX emissions are projected to follow a
pattern similar to the national trend; however, the implementation of
NOX controls is assumed to take the form of an emission cap
and permit trading program similar to the Title IV SO2
program. Consequently, certain regions may experience different
NOX emissions trends because of the relative costs of
controlling NOX and the possibility of trading between
emitting parties;
5. CO2 is projected to increase throughout the analysis
period by 27 percent. Because CO2 is an unregulated
pollutant at the present time, and because both coal and natural gas
emit CO2, the rise in both coal and gas-fired generation
leads to a substantial increase in CO2 emissions during the
analysis period; and
6. Mercury emissions range between 50.6 and 53.2 tons during the
forecast period with no clear trend distinguishable. Mercury is also
uncontrolled at the present time, but emissions are closely linked to
coal use (with considerable variation of mercury content in coal from
specific seams). The relative stability of coal-fired generation in
later years of the analysis period leads to the observed pattern of
mercury emissions.
The analysis indicates that the Midwest is expected to produce
slightly more power, the East Coast to produce slightly less power.
These changes are likely to be greatest in the near-term, and to
decline toward baseline levels over time. The Final Rule would result
in the slight shifting of the baseline fuel mix projections toward coal
and away from fuel oil and, to some extent, natural gas; these changes
are small relative to the overall trend in the fuel mix, in which
natural gas remains the most rapidly growing fuel. This is consistent
with the change in regional levels of generation.
The analysis shows that the overall emissions of SOX,
NOX, mercury, and CO2, are directionally
consistent with the observed changes in power generation and fuel mix.
That is, emissions tend to increase early in the forecast period and
then decline over time, with several instances of emissions reductions.
The greatest change in any regulated pollutant (a rise of 3.6 percent
or 381,000 tons of SO2 in one scenario) occurs as a result
of changing patterns of emissions banking and trading, which is
consistent with the design of the SO2 cap and trade
regulatory program. Regional variations in annual and summer
NOX are also possible and are also consistent with
regulatory program design. Emissions budgets are met at all times.
Other emission changes are relatively small because coal-fired plants,
which contribute a disproportionate share of these emissions, are
already heavily utilized and so are unable to increase their output
significantly in the rulemaking scenarios. In one scenario designed to
examine increased new entry and demand flexibility,
[[Page 952]]
substantial emissions reductions occur as a result of lower demand for
electricity combined with cleaner new supply options.
V. Regulatory Flexibility Act Certification
The Commission received no comments on its certification, in the
NOPR, that the proposed rule would not have a significant economic
impact on a substantial number of small entities and that an initial
regulatory flexibility analysis is not required by 5 U.S.C. Sec. 603.
The Commission adheres to its earlier reasoning and thus concludes that
a final regulatory flexibility analysis also is not required.\753\ In
making this determination, the Commission is required to examine only
the direct compliance costs that a rulemaking imposes upon small
businesses. It is not required to consider indirect economic
consequences, nor is it required to consider costs that an entity
incurs voluntarily.\754\ This rulemaking does not impose significant
compliance costs upon small entities. Instead, it leaves them with the
choice of whether to join an RTO. The only costs that are mandated are
the minimal costs associated with filing a statement, in the event a
public utility does not make an RTO filing, explaining its efforts to
join an RTO, any barriers it encountered, and any future plans to join
an RTO. Thus, this rulemaking will not have a significant economic
impact upon any small entities.
---------------------------------------------------------------------------
\753\ See 5 U.S.C. 604.
\754\ Mid-Tex Elec. Coop. v. FERC, 773 F.2d 327 (D.C. Cir. 1985)
(Commission need only consider small entities ``that would be
directly regulated''); Colorado State Banking Bd. v. RTC, 926 F.2d
931 (10th Cir. 1991) (Regulatory Flexibility Act not implicated
where regulation simply added an option for affected entities and
did not impose any costs).
---------------------------------------------------------------------------
VI. Public Reporting Burden and Information Collection Statement
The OMB regulations require OMB to approve certain reporting and
recordkeeping (collections of information) imposed by agency rule.\755\
The NOPR was submitted to OMB at the time of issuance. OMB did not
comment nor did it take any action on the proposed rule. FERC
identifies the information provided under Part 35 as FERC-516 \756\ and
under Part 33 as FERC-519.\757\
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\755\ 5 CFR 1320.11, 44 U.S.C. 3507(d).
\756\ Electric Rate Schedule Filings.
\757\ Application for Sale, Lease, or Other Disposition, Merger
or Consolidation of Facilities or for the Purchase or Acquisition of
Securities of a Public Utility.
---------------------------------------------------------------------------
No comments from the public on the burden estimate were received.
The filing requirements remain essentially the same as those in the
NOPR so, therefore, the estimated annual filing burden remains the
same. The burden estimates for complying with this proposed rule are
set out in Table 1. The total annual hours for collection (reporting +
recordkeeping (if appropriate)) is 7,600.
Information Collection Costs: The Commission has projected the
average annualized cost for all respondents to be: Annualized Costs
(Operations & Maintenance): $401,518 (7,600 hours 2080 hours
per year x $109,889=$401,518). The cost per respondent is $7,722
(participants and non-participants).
Table 1.--Estimated Annual Burden
----------------------------------------------------------------------------------------------------------------
Number of Number of Hours Per Total Annual
Data Collection Respondents Responses Response Hours
----------------------------------------------------------------------------------------------------------------
FERC-516 \1\.................................... 12 1 300 3,600
FERC-516 \2\.................................... 40 1 40 1,600
FERC-519 \1\.................................... 12 1 200 2,400
---------------------------------------------------------------
Totals.................................... .............. .............. .............. 7,600
----------------------------------------------------------------------------------------------------------------
\1\ Filings to propose participation in an RTO under Sec. 35.34(d).
\2\ Alternative filings under Sec. 35.34(g).
Comments were solicited on the Commission's need for this
information, whether the information will have practical utility, the
accuracy of the provided burden estimates, ways to enhance the quality,
utility, and clarity of the information to be collected, and any
suggested methods for minimizing respondents' burden, including the use
of automated information techniques.
Title: FERC-516, Electric Rate Schedule Filings; FERC-519
Application for Sale, Lease, or Other Disposition, Merger or
Consolidation of Facilities or for the Purchase or Acquisition of
Securities of a Public Utility.
Action: Proposed Data Collections.
OMB Control No.: 1902-0096 and 1902-0082.
The applicant shall not be penalized for failure to respond to this
collection of information unless the collection of information displays
a valid OMB control number.
Respondents: Business or other for profit, including small
businesses.
Frequency of Responses: One time.
Necessity of Information: The Final Rule revises the requirements
contained in 18 CFR part 35. The Commission is promoting the voluntary
establishment of RTOs nationwide by December 2001. In particular, the
Commission will establish in this rule characteristics and functions
which applicants must meet to become Commission-approved RTOs. The
Commission will engage in a collaborative process with state officials
and others to facilitate RTO development. The rule will require that
each public utility that owns, operates or controls transmission
facilities participate in one-time filings proposing an RTO or make a
filing explaining why they are not participating in an RTO proposal.
Internal Review: The Commission has assured itself, by means of
internal review, that there is specific, objective support for the
burden estimates associated with the information requirements. The
Commission's Office of Markets, Tariffs and Rates will use the data
included in filings under 18 CFR 35.34 to evaluate efforts for the
interconnection and coordination of the U.S. electric transmission
system and to ensure the orderly formation of RTOs as well as for
general industry oversight. These information requirements conform to
the Commission's plan for efficient information collection,
communication, and management within the electric power industry.
The Commission received approximately 334 comments and reply
comments on its NOPR but none on its reporting burden. The Commission's
responses to the comments are addressed in the preamble of this Final
[[Page 953]]
Rule. The Commission is submitting a copy of the Final Rule along with
information collection submissions for the data collections identified
above to OMB for its review and approval.
Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street, NE, Washington, DC 20426 [Attention:
Michael Miller, Office of the Chief Information Officer, Phone: (202)
208-1415, fax: (202) 208-2425, E-mail: mike.miller@ferc.fed.us] or send
your comments to the Office of Management and Budget, Office of
Information and Regulatory Affairs, Washington, DC 20503, [Attention:
Desk Officer for the Federal Energy Regulatory Commission, phone: (202)
395-3087, fax: (202) 395-7285].
VII. Effective Date and Congressional Notification
This rule will take effect March 6, 2000. The Commission has
determined, with the concurrence of the Administrator of the Office of
Information and Regulatory Affairs of the Office of Management and
Budget, that this Rule is a ``major rule'' within the meaning of
section 351 of the Small Business Regulatory Enforcement Act of
1996.\758\ The Rule will be submitted to both Houses of Congress and
the Comptroller General prior to its publication in the Federal
Register.
---------------------------------------------------------------------------
\758\ 5 U.S.C. 804(2).
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VIII. Document Availability
In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.fed.us) and in
FERC's Public Reference Room during normal business hours (8:30 a.m. to
5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, Washington,
D.C. 20426.
From FERC's Home Page on the Internet, this information is
available in both the Commission Issuance Posting System (CIPS) and the
Records and Information Management System (RIMS).
CIPS provides access to the texts of formal documents
issued by the Commission since November 14, 1994. CIPS can be accessed
using the CIPS link or the Energy Information Online icon. The full
text of this document will be available on CIPS in ASCII and
WordPerfect 8.0 format for viewing, printing, and/or downloading.
RIMS contains images of documents submitted to and issues
by the Commission after November 16, 1981. Documents from November 1995
to the present can be viewed and printed from FERC's Home Page using
the RIMS link or the Energy Information Online icon. Descriptions of
documents back to November 16, 1981, are also available from RIMS-on-
the-Web; requests for copies of these and other older documents should
be submitted to the Public Reference Room.
User assistance is available for RIMS, CIPS, and the Website during
normal business hours from our Help line at (202) 208-2222 (e-mail to
WebMaster@ferc.fed.us) of the Public Reference Room at (202) 208-1371
(e-mail to public.referenceroom@ferc.fed.us).
During normal business hours, documents can also be viewed and/or
printed in FERC's Public Reference Room, where RIMS, CIPS, and the FERC
Website are available. User assistance is also available.
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements
By the Commission.
David P. Boergers,
Secretary.
In consideration of the foregoing, the Commission amends Part 35,
Chapter I, Title 18 of the Code of Federal Regulations, as follows:
PART 35--FILING OF RATE SCHEDULES
1. The authority citation for Part 35 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
2. Part 35 is amended by adding a new Subpart F and a new
Sec. 35.34 to read as follows:
Subpart F--Procedures and Requirements Regarding Regional
Transmission Organizations
Sec. 35.34 Regional Transmission Organizations.
(a) Purpose. This section establishes required characteristics and
functions for Regional Transmission Organizations for the purpose of
promoting efficiency and reliability in the operation and planning of
the electric transmission grid and ensuring non-discrimination in the
provision of electric transmission services. This section further
directs each public utility that owns, operates, or controls facilities
used for the transmission of electric energy in interstate commerce to
make certain filings with respect to forming and participating in a
Regional Transmission Organization.
(b) Definitions.
(1) Regional Transmission Organization means an entity that
satisfies the minimum characteristics set forth in paragraph (j) of
this section, performs the functions set forth in paragraph (k) of this
section, and accommodates the open architecture condition set forth in
paragraph (l) of this section.
(2) Market participant means:
(i) Any entity that, either directly or through an affiliate, sells
or brokers electric energy, or provides transmission or ancillary
services to the Regional Transmission Organization, unless the
Commission finds that the entity does not have economic or commercial
interests that would be significantly affected by the Regional
Transmission Organization's actions or decisions; and
(ii) Any other entity that the Commission finds has economic or
commercial interests that would be significantly affected by the
Regional Transmission Organization's actions or decisions.
(3) Affiliate means the definition given in section 2(a)(11) of the
Public Utility Holding Company Act (15 U.S.C. 79b(a)(11)).
(4) Class of market participants means two or more market
participants with common economic or commercial interests.
(c) General rule. Except for those public utilities subject to the
requirements of paragraph (h) of this section, every public utility
that owns, operates or controls facilities used for the transmission of
electric energy in interstate commerce as of March 6, 2000 must file
with the Commission, no later than October 15, 2000, one of the
following:
(1) A proposal to participate in a Regional Transmission
Organization consisting of one of the types of submittals set forth in
paragraph (d) of this section; or
(2) An alternative filing consistent with paragraph (g) of this
section.
(d) Proposal to participate in a Regional Transmission
Organization. For purposes of this section, a proposal to participate
in a Regional Transmission Organization means:
(1) Such filings, made individually or jointly with other entities,
pursuant to sections 203, 205 and 206 of the Federal Power Act (16
U.S.C. 824b, 824d, and 824e), as are necessary to create a new Regional
Transmission Organization;
[[Page 954]]
(2) Such filings, made individually or jointly with other entities,
pursuant to sections 203, 205 and 206 of the Federal Power Act (16
U.S.C. 824b, 824d, and 824e), as are necessary to join a Regional
Transmission Organization approved by the Commission on or before the
date of the filing; or
(3) A petition for declaratory order, filed individually or jointly
with other entities, asking whether a proposed transmission entity
would qualify as a Regional Transmission Organization and containing at
least the following:
(i) A detailed description of the proposed transmission entity,
including a description of the organizational and operational structure
and the intended participants;
(ii) A discussion of how the transmission entity would satisfy each
of the characteristics and functions of a Regional Transmission
Organization specified in paragraphs (j), (k) and (l) of this section;
(iii) A detailed description of the Federal Power Act section 205
rates that will be filed for the Regional Transmission Organization;
and
(iv) A commitment to make filings pursuant to sections 203, 205 and
206 of the Federal Power Act (16 U.S.C. 824b, 824d, and 824e), as
necessary, promptly after the Commission issues an order in response to
the petition.
(4) Any proposal filed under this paragraph (d) must include an
explanation of efforts made to include public power entities in the
proposed Regional Transmission Organization.
(e) Innovative transmission rate treatments for Regional
Transmission Organizations.
(1) The Commission will consider authorizing any innovative
transmission rate treatment, as discussed in this paragraph (e), for an
approved Regional Transmission Organization. An applicant's request
must include:
(i) A detailed explanation of how any proposed rate treatment would
help achieve the goals of Regional Transmission Organizations,
including efficient use of and investment in the transmission system
and reliability benefits to consumers;
(ii) A cost-benefit analysis, including rate impacts; and
(iii) A detailed explanation of why the proposed rate treatment is
appropriate for the Regional Transmission Organization.
The applicant must support any rate proposal under this paragraph
(e) as just, reasonable, and not unduly discriminatory or preferential.
(2) For purposes of this paragraph (e), innovative transmission
rate treatment means any of the following:
(i) A transmission rate moratorium, which may include proposals
based on formerly bundled retail transmission rates;
(ii) Rates of return that:
(A) Are formulary;
(B) Consider risk premiums and account for demonstrated adjustments
in risk; or
(C) Do not vary with capital structure;
(iii) Non-traditional depreciation schedules for new transmission
investment;
(iv) Transmission rates based on levelized recovery of capital
costs;
(v) Transmission rates that combine elements of incremental cost
pricing for new transmission facilities with an embedded-cost access
fee for existing transmission facilities; or
(vi) Performance-based transmission rates.
(3) A request for performance-based transmission rates under this
paragraph (e) may include factors such as:
(i) A method for calculating initial transmission rates (including
price caps and any provisions for discounting);
(ii) A mechanism for adjusting initial rates, which may be derived
from or based upon external factors or indices or a specific
performance measure;
(iii) Time periods for redetermining initial rates; and
(iv) Costs to be excluded from performance-based rates.
(4) An innovative transmission rate treatment or any other rate
proposal made for an approved Regional Transmission Organization may be
requested as part of any filing that is made under paragraph (d) of
this section or in any subsequent rate change proposal under section
205 of the Federal Power Act (16 U.S.C. 824d). Unless otherwise ordered
by the Commission, an approved Regional Transmission Organization may
not include in rates any innovative transmission rate treatment under
paragraphs (e)(2)(i) and (e)(2)(ii)(C) of this section after January 1,
2005.
(f) Transfer of operational control. The public utility's proposal
to participate in a Regional Transmission Organization filed pursuant
to paragraph (c)(1) of this section must propose that operational
control of that public utility's transmission facilities will be
transferred to the Regional Transmission Organization on a schedule
that will allow the Regional Transmission Organization to commence
operating the facilities no later than December 15, 2001.
Note to paragraph (f): The requirement in paragraph (f) of this
section may be satisfied by proposing to transfer to the Regional
Transmission Organization ownership of the facilities in addition to
operational control.
(g) Alternative filing. Any filing made pursuant to paragraph
(c)(2) of this section must contain:
(1) A description of any efforts made by that public utility to
participate in a Regional Transmission Organization;
(2) A detailed explanation of the economic, operational,
commercial, regulatory, or other reasons the public utility has not
made a filing to participate in a Regional Transmission Organization,
including identification of any existing obstacles to participation in
a Regional Transmission Organization; and
(3) The specific plans, if any, the public utility has for further
work toward participation in a Regional Transmission Organization, a
proposed timetable for such activity, an explanation of efforts made to
include public power entities in the proposed Regional Transmission
Organization, and any factors (including any law, rule or regulation)
that may affect the public utility's ability or decision to participate
in a Regional Transmission Organization.
(h) Public utilities participating in approved transmission
entities. Every public utility that owns, operates or controls
facilities used for the transmission of electric energy in interstate
commerce as of March 6, 2000, and that has filed with the Commission on
or before March 6, 2000 to transfer operational control of its
facilities to a transmission entity that has been approved or
conditionally approved by the Commission on or before March 6, 2000 as
being in conformance with the eleven ISO principles set forth in Order
No. 888, FERC Statutes and Regulations, Regulations Preamble January
1991-June 1996 para. 31,036 (Final Rule on Open Access and Stranded
Costs), must, individually or jointly with other entities, file with
the Commission, no later than January 15, 2001:
(1) A statement that it is participating in a transmission entity
that has been so approved;
(2) A detailed explanation of the extent to which the transmission
entity in which it participates has the characteristics and performs
the functions of a Regional Transmission Organization specified in
paragraphs (j) and (k) of this section and accommodates the open
architecture conditions in paragraph (l) of this section; and
(3) To the extent the transmission entity in which the public
utility participates does not meet all the requirements of a Regional
Transmission Organization specified in paragraphs (j), (k), and (l) of
this section,
[[Page 955]]
(i) A proposal to participate in a Regional Transmission
Organization that meets such requirements in accordance with paragraph
(d) of this section,
(ii) A proposal to modify the existing transmission entity so that
it conforms to the requirements of a Regional Transmission
Organization, or
(iii) A filing containing the information specified in paragraph
(g) of this section addressing any efforts, obstacles, and plans with
respect to conformance with those requirements.
(i) Entities that become public utilities with transmission
facilities. An entity that is not a public utility that owns, operates
or controls facilities used for the transmission of electric energy in
interstate commerce as of March 6, 2000, but later becomes such a
public utility, must file a proposal to participate in a Regional
Transmission Organization in accordance with paragraph (d) of this
section, or an alternative filing in accordance with paragraph (g) of
this section, by October 15, 2000 or 60 days prior to the date on which
the public utility engages in any transmission of electric energy in
interstate commerce, whichever comes later. If a proposal to
participate in accordance with paragraph (d) of this section is filed,
it must propose that operational control of the applicant's
transmission system will be transferred to the Regional Transmission
Organization within six months of filing the proposal.
(j) Required characteristics for a Regional Transmission
Organization. A Regional Transmission Organization must satisfy the
following characteristics when it commences operation:
(1) Independence. The Regional Transmission Organization must be
independent of any market participant. The Regional Transmission
Organization must include, as part of its demonstration of
independence, a demonstration that it meets the following:
(i) The Regional Transmission Organization, its employees, and any
non-stakeholder directors must not have financial interests in any
market participant.
(ii) The Regional Transmission Organization must have a decision
making process that is independent of control by any market participant
or class of participants.
(iii) The Regional Transmission Organization must have exclusive
and independent authority under section 205 of the Federal Power Act
(16 U.S.C. 824d), to propose rates, terms and conditions of
transmission service provided over the facilities it operates. Note to
paragraph (j)(1)(iii): Transmission owners retain authority under
section 205 of the Federal Power Act (16 U.S.C. 824d) to seek recovery
from the Regional Transmission Organization of the revenue requirements
associated with the transmission facilities that they own.
(2) Scope and regional configuration. The Regional Transmission
Organization must serve an appropriate region. The region must be of
sufficient scope and configuration to permit the Regional Transmission
Organization to maintain reliability, effectively perform its required
functions, and support efficient and non-discriminatory power markets.
(3) Operational authority. The Regional Transmission Organization
must have operational authority for all transmission facilities under
its control. The Regional Transmission Organization must include, as
part of its demonstration of operational authority, a demonstration
that it meets the following:
(i) If any operational functions are delegated to, or shared with,
entities other than the Regional Transmission Organization, the
Regional Transmission Organization must ensure that this sharing of
operational authority will not adversely affect reliability or provide
any market participant with an unfair competitive advantage. Within two
years after initial operation as a Regional Transmission Organization,
the Regional Transmission Organization must prepare a public report
that assesses whether any division of operational authority hinders the
Regional Transmission Organization in providing reliable, non-
discriminatory and efficiently priced transmission service.
(ii) The Regional Transmission Organization must be the security
coordinator for the facilities that it controls.
(4) Short-term reliability. The Regional Transmission Organization
must have exclusive authority for maintaining the short-term
reliability of the grid that it operates. The Regional Transmission
Organization must include, as part of its demonstration with respect to
reliability, a demonstration that it meets the following:
(i) The Regional Transmission Organization must have exclusive
authority for receiving, confirming and implementing all interchange
schedules.
(ii) The Regional Transmission Organization must have the right to
order redispatch of any generator connected to transmission facilities
it operates if necessary for the reliable operation of these
facilities.
(iii) When the Regional Transmission Organization operates
transmission facilities owned by other entities, the Regional
Transmission Organization must have authority to approve or disapprove
all requests for scheduled outages of transmission facilities to ensure
that the outages can be accommodated within established reliability
standards.
(iv) If the Regional Transmission Organization operates under
reliability standards established by another entity (e.g., a regional
reliability council), the Regional Transmission Organization must
report to the Commission if these standards hinder it from providing
reliable, non-discriminatory and efficiently priced transmission
service.
(k) Required functions of a Regional Transmission Organization. The
Regional Transmission Organization must perform the following
functions. Unless otherwise noted, the Regional Transmission
Organization must satisfy these obligations when it commences
operations.
(1) Tariff administration and design. The Regional Transmission
Organization must administer its own transmission tariff and employ a
transmission pricing system that will promote efficient use and
expansion of transmission and generation facilities. As part of its
demonstration with respect to tariff administration and design, the
Regional Transmission Organization must satisfy the standards listed in
paragraphs (k)(1) (i) and (ii) of this section, or demonstrate that an
alternative proposal is consistent with or superior to satisfying such
standards.
(i) The Regional Transmission Organization must be the only
provider of transmission service over the facilities under its control,
and must be the sole administrator of its own Commission-approved open
access transmission tariff. The Regional Transmission Organization must
have the sole authority to receive, evaluate, and approve or deny all
requests for transmission service. The Regional Transmission
Organization must have the authority to review and approve requests for
new interconnections.
(ii) Customers under the Regional Transmission Organization tariff
must not be charged multiple access fees for the recovery of capital
costs for transmission service over facilities that the Regional
Transmission Organization controls.
(2) Congestion management. The Regional Transmission Organization
must ensure the development and operation of market mechanisms to
[[Page 956]]
manage transmission congestion. As part of its demonstration with
respect to congestion management, the Regional Transmission
Organization must satisfy the standards listed in paragraph (k)(2)(i)
of this section, or demonstrate that an alternative proposal is
consistent with or superior to satisfying such standards.
(i) The market mechanisms must accommodate broad participation by
all market participants, and must provide all transmission customers
with efficient price signals that show the consequences of their
transmission usage decisions. The Regional Transmission Organization
must either operate such markets itself or ensure that the task is
performed by another entity that is not affiliated with any market
participant.
(ii) The Regional Transmission Organization must satisfy the market
mechanism requirement no later than one year after it commences initial
operation. However, it must have in place at the time of initial
operation an effective protocol for managing congestion.
(3) Parallel path flow. The Regional Transmission Organization must
develop and implement procedures to address parallel path flow issues
within its region and with other regions. The Regional Transmission
Organization must satisfy this requirement with respect to coordination
with other regions no later than three years after it commences initial
operation.
(4) Ancillary services. The Regional Transmission Organization must
serve as a provider of last resort of all ancillary services required
by Order No. 888, FERC Statutes and Regulations, Regulations Preamble
January 1991-June 1996 para. 31,036 (Final Rule on Open Access and
Stranded Costs), and subsequent orders. As part of its demonstration
with respect to ancillary services, the Regional Transmission
Organization must satisfy the standards listed in paragraphs (k)(4)(i)-
(iii) of this section, or demonstrate that an alternative proposal is
consistent with or superior to satisfying such standards.
(i) All market participants must have the option of self-supplying
or acquiring ancillary services from third parties subject to any
restrictions imposed by the Commission in Order No. 888, FERC Statutes
and Regulations, Regulations Preamble January 1991-June 1996 para.
31,036 (Final Rule on Open Access and Stranded Costs), and subsequent
orders.
(ii) The Regional Transmission Organization must have the authority
to decide the minimum required amounts of each ancillary service and,
if necessary, the locations at which these services must be provided.
All ancillary service providers must be subject to direct or indirect
operational control by the Regional Transmission Organization. The
Regional Transmission Organization must promote the development of
competitive markets for ancillary services whenever feasible.
(iii) The Regional Transmission Organization must ensure that its
transmission customers have access to a real-time balancing market. The
Regional Transmission Organization must either develop and operate this
market itself or ensure that this task is performed by another entity
that is not affiliated with any market participant.
(5) OASIS and Total Transmission Capability (TTC) and Available
Transmission Capability (ATC). The Regional Transmission Organization
must be the single OASIS site administrator for all transmission
facilities under its control and independently calculate TTC and ATC.
(6) Market monitoring. To ensure that the Regional Transmission
Organization provides reliable, efficient and not unduly discriminatory
transmission service, the Regional Transmission Organization must
provide for objective monitoring of markets it operates or administers
to identify market design flaws, market power abuses and opportunities
for efficiency improvements, and propose appropriate actions. As part
of its demonstration with respect to market monitoring, the Regional
Transmission Organization must satisfy the standards listed in
paragraphs (k)(6)(i) through (k)(6)(iii) of this section, or
demonstrate that an alternative proposal is consistent with or superior
to satisfying such standards.
(i) Market monitoring must include monitoring the behavior of
market participants in the region, including transmission owners other
than the Regional Transmission Organization, if any, to determine if
their actions hinder the Regional Transmission Organization in
providing reliable, efficient and not unduly discriminatory
transmission service.
(ii) With respect to markets the Regional Transmission Organization
operates or administers, there must be a periodic assessment of how
behavior in markets operated by others (e.g., bilateral power sales
markets and power markets operated by unaffiliated power exchanges)
affects Regional Transmission Organization operations and how Regional
Transmission Organization operations affect the efficiency of power
markets operated by others.
(iii) Reports on opportunities for efficiency improvement, market
power abuses and market design flaws must be filed with the Commission
and affected regulatory authorities.
(7) Planning and expansion. The Regional Transmission Organization
must be responsible for planning, and for directing or arranging,
necessary transmission expansions, additions, and upgrades that will
enable it to provide efficient, reliable and non-discriminatory
transmission service and coordinate such efforts with the appropriate
state authorities. As part of its demonstration with respect to
planning and expansion, the Regional Transmission Organization must
satisfy the standards listed in paragraphs (k)(7)(i) and (ii) of this
section, or demonstrate that an alternative proposal is consistent with
or superior to satisfying such standards.
(i) The Regional Transmission Organization planning and expansion
process must encourage market-driven operating and investment actions
for preventing and relieving congestion.
(ii) The Regional Transmission Organization's planning and
expansion process must accommodate efforts by state regulatory
commissions to create multi-state agreements to review and approve new
transmission facilities. The Regional Transmission Organization's
planning and expansion process must be coordinated with programs of
existing Regional Transmission Groups (See Sec. 2.21 of this chapter)
where appropriate.
(iii) If the Regional Transmission Organization is unable to
satisfy this requirement when it commences operation, it must file with
the Commission a plan with specified milestones that will ensure that
it meets this requirement no later than three years after initial
operation.
(8) Interregional coordination. The Regional Transmission
Organization must ensure the integration of reliability practices
within an interconnection and market interface practices among regions.
(l) Open architecture.
(1) Any proposal to participate in a Regional Transmission
Organization must not contain any provision that would limit the
capability of the Regional Transmission Organization to evolve in ways
that would improve its efficiency, consistent with the requirements in
paragraphs (j) and (k) of this section.
(2) Nothing in this regulation precludes an approved Regional
Transmission Organization from seeking to evolve with respect to its
organizational design, market design,
[[Page 957]]
geographic scope, ownership arrangements, or methods of operational
control, or in other appropriate ways if the change is consistent with
the requirements of this section. Any future filing seeking approval of
such changes must demonstrate that the proposed changes will meet the
requirements of paragraphs (j), (k) and (l) of this section.
Note: The following appendix will not appear in the Code of
Federal Regulations.
Appendix to Preamble--List of Commenters
Abbreviation--Commenter
1. Advisory Committee ISO-NE--Advisory Committee to the Board of
Directors of ISO New England.
2. AEP--American Electric Power Service Corporation and its
public utility operating company subsidiaries: Appalachian Power
Company, Columbus Southern Power Company, Indiana Michigan Power
Company, Kentucky Power Company, Kingsport Power Company, Ohio Power
Company. and Wheeling Power Company.
3. AEPCO--Arizona Electric Power Cooperative, Inc.
4. Alabama Commission--Alabama Public Service Commission.
5. Alberta--Provence of Alberta, Electricity Branch.
6. Allegheny--Allegheny Energy, Inc.
7. Alliance Companies--American Electric Power Service
Corporation, Consumers Energy Company, Detroit Edison Company,
FirstEnergy Corp. and Virginia Electric and Power Company.
8. Alliant Energy--Alliant Energy Corporation.
9. Aluminum Companies--Alcoa Inc., Columbia Falls Aluminum
Company, Kaiser Aluminum & Chemical Corporation and Vanalco, Inc.
10. American Forest--American Forest & Paper Association.
11. AMP-Ohio--American Municipal Power-Ohio, Inc.
12. APPA--American Public Power Association.
13. APPA et al. (WP)--Legal White Paper prepared on behalf of
and sponsored jointly by the American Public Power Association, the
Electric Consumers Resource Council, the Transmission Access Policy
Study Group and the Transmission Dependent Utility Systems.
14. APS--Arizona Public Service Company.
15. APX--Automated Power Exchange, Inc.
16. Arizona Authority--Arizona Power Authority.
17. Arizona Commission--Arizona Corporation Commission.
18. Arizona ISA--Arizona Independent Scheduling Administrator
Association.
19. Arkansas Cities--Cities of Benton, Bentonville, North Little
Rock, Osceola, Piggott, Prescott and Siloam Springs, Arkansas; the
Clarksville Light and Water Company; Conway Corporation; Hope Water
and Light Commission; City Water and Light Plant of the City of
Jonesboro, Arkansas; Paragould Light and Water Commission; and the
West Memphis, Arkansas Utilities Commission.
20. Arkansas Consumers--Arkansas Electric Energy Consumers.
21. Avista--Avista Corporation, Inc.
22. Bangor Hydro--Bangor Hydro-Electric Company.
23. BC Hydro--British Columbia Hydro & Power Authority.
24. Big Rivers--Big Rivers Electric Corporation.
25. Blue Ridge--Blue Ridge Power Agency.
26. Brattle Group--The Brattle Group (Peter Fox-Penner and
Philip Hanser).
27. British Columbia Ministry--British Columbia, Canada,
Ministry of Employment and Investment, Electricity Development
Branch.
28. Cal DWR--California Department of Water Resources.
29. Cal ISO--California Independent System Operator Corporation.
30. California Board--California Electricity Oversight Board.
31. California Commission--Public Utilities Commission of the
State of California.
32. CalPX--California Power Exchange Corporation.
33. CAMU--Colorado Association of Municipal Utilities.
34. Canada DNR--Canada Department of Natural Resources.
35. CCEM/ELCON--Coalition for a Competitive Electricity Market
and the Electricity Consumers Resources Council.
36. CEA--Canadian Electricity Association.
37. Consumers Energy--Consumers Energy Company.
38. Central Maine--Central Maine Power Company and Maine
Electric Power Company.
39. Champion--Champion International Corporation.
40. Chelan--Public Utility District No. 1 of Chelan County.
41. Cinergy--Cinergy Services, Inc.
42. Clarksdale--Clarksdale Public Utilities Commission.
43. Cleco--Cleco Corporation.
44. Cleveland--City of Cleveland, Ohio.
45. CMUA--California Municipal Utilities Association.
46. Coalition of Alliance Users--Coalition of Municipal and
Cooperative Users of Alliance Companies' Transmission.
47. ComEd--Commonwealth Edison Company.
48. Conectiv--Conectiv (Atlantic City Electric Company and
Delmarva Power & Light Company.
49. Conlon--Mr. P. Gregory Conlon.
50. Consumer Groups--Industrial Consumers, American Public Power
Association, National Rural Electric Cooperative Association,
Transmission Access Policy Study Group, Transmission Dependent
Utility Systems, Consumer Federation of America and International
Mass Retail Association.
51. CP&L--Carolina Power & Light Company.
52. CRC--Colorado River Commission of the State of Nevada.
53. CREDA--Colorado River Energy Distributors Association.
54. CSU--Colorado Springs Utilities.
55. CTA--Competitive Transmission Association, Inc.
56. Dalton Utilities--Board of Water, Light and Sinking Fund
Commissioners of the City of Dalton, Georgia.
57. Dairyland--Dairyland Power Cooperative.
58. Desert STAR--Desert STAR.
59. Detroit Edison--Detroit Edison Company.
60. Distributed Power--Distributed Power Coalition of America.
61. DOE--United States Department of Energy.
62. Dr. Illic--Dr. Marija Illic and Yong Yoon.
63. Duke--Duke Energy Corporation.
64. Duquesne--Duquesne Light Company.
65. Dynegy--Dynegy Inc.
66. EAL--ESBI Alberta Ltd.
67. East Kentucky--East Kentucky Power Cooperative, Inc.
68. East Texas Cooperatives--East Texas Electric Cooperative,
Inc., Northeast Texas Electric Cooperative, Inc., Sam Rayburn G&T
Electric Cooperative, Inc., Tex-La Electric Cooperative of Texas,
Inc.
69. ECAR--East Central Area Reliability Council.
70. EEI--Edison Electric Institute.
71. EME--Edison Mission Energy.
72. Empire District--Empire District Electric Company.
73. Enron/APX/Coral Power--Enron Power Marketing, Inc.,
Automated Power Exchange and Coral Power, L.L.C.
74. Entergy--Entergy Services Inc.
75. EPA--United States Environmental Protection Agency.
76. EPRI--Electric Power Research Institute.
77. EPSA--Electric Power Supply Association.
78. Eric Hirst--Mr. Eric Hirst.
79. Fertilizer Institute--The Fertilizer Institute.
80. First Rochdale--1st Rochdale Cooperative Group, Ltd.
81. FirstEnergy--FirstEnergy Corp.
82. Florida Commission--Florida Public Service Commission.
83. Florida Power Corp.--Florida Power Corporation.
84. FMPA--Florida Municipal Power Agency.
85. FP&L--Florida Power & Light Company.
86. FTC--Staff of the Bureau of Economics of the Federal Trade
Commission.
87. Gainesville--Gainesville Regional Utilities.
88. Georgia Transmission--Georgia Transmission Corporation.
89. GPU Energy--GPU Energy.
90. Grand Council et al.--Grand Council of the Crees, Greenpeace
Canada, the Sierra Club of Canada, Mouvement Au Courant, the Centre
D'Analyses de Politiques Energetiques and New England Coalition for
Energy Efficiency and the Environment.
91. Great River--Great River Energy.
92. H.Q. Energy Services--Energy Services Group of Hydro-Quebec
and H.Q. Energy Services (U.S.) Inc.
93. How Group--OASIS How Working Group.
94. ICUA--Idaho Consumer-Owned Utilities Association.
[[Page 958]]
95. Idaho Commission--Idaho Public Utilities Commission.
96. Idaho Power--Idaho Power Company.
97. Illinois Commission--Illinois Commerce Commission.
98. IMEA--Illinois Municipal Electric Agency.
99. IMPA--Indiana Municipal Power Agency.
100. Indiana Commission--Indiana Utility Regulatory Commission.
101. Indianapolis P&L--Indianapolis Power & Light Company.
102. Industrial Consumers--Electricity Consumers Resource
Council, the American Iron & Steel Institute and the Chemical
Manufactures Association.
103. Industrial Customers--Industrial Customers of Northwest
Utilities.
104. INGAA--Interstate Natural Gas Association of America.
105. Iowa Board--Iowa Utilities Board.
106. IPCF--International Powerline Communications Forum.
107. ISO-NE--ISO New England Inc.
108. JEA--JEA.
109. Justice Department--United States Department of Justice.
110. Kentucky Commission--Kentucky Public Service Commission.
111. Konolige/Ford/Fleishman--Kit Konolige, Daniel F. Ford and
Steven I. Fleishman.
112. Lenard--Mr. Thomas M. Lenard.
113. LEPA--Louisiana Energy & Power Authority.
114. LG&E--LG&E Energy Corp.
115. Lincoln--Lincoln, Nebraska Electric System.
116. LIPA--Long Island Power Authority.
117. Los Angeles--Los Angeles Department of Water and Power.
118. Loveland Customers--Loveland Area Customers Association.
119. LPPC--Large Public Power Council.
120. Manitoba Board--Manitoba Hydro-Electric Board.
121. MAPP--Mid-Continent Area Power Pool.
122. Mass Companies--Boston Edison Company, Cambridge Electric
Light Company and Commonwealth Electric Company.
123. Massachusetts Division--Massachusetts Division of Energy
Resources.
124. MEAG--Municipal Electric Authority of Georgia.
125. Merrill Energy--Merrill Energy LLC.
126. Metropolitan--Metropolitan Water District of Southern
California.
127. Michigan Commission--Michigan Public Service Commission.
128. MidAmerican--MidAmerican Energy Company.
129. Mid-Atlantic Commissions--Delaware Public Service
Commission, District of Columbia Public Service Commission, Maryland
Public Service Commission, New Jersey Board of Public Utilities and
Pennsylvania Public Utility Commission.
130. Midwest Energy--Midwest Energy, Inc.
131. Midwest ISO--Midwest Independent Transmission System
Operator, Inc.
132. Midwest ISO Participants--Allegheny Energy, Ameren, Central
Illinois Light Company, Cinergy Corp., Commonwealth Edison Company,
Hoosier Energy Rural Electric Cooperative, Inc., Illinois Power
Company, Kentucky Utilities Company, Louisville Gas & Electric
Company, Southern Indiana Gas & Electric Company, Southern Illinois
Power Cooperative, Wabash Valley Power Association, Inc. and
Wisconsin Electric Power Company.
133. Midwest Municipals--Missouri River Energy Services, Iowa
Association of Municipal Utilities and Minnesota Municipal Utilities
Association.
134. Minnesota Commission--Minnesota Public Utilities
Commission.
135. Minnesota Power--Minnesota Power.
136. Missouri Commission--Missouri Public Service Commission.
137. MLGW--Memphis Light, Gas and Water Division.
138. Montana Commission--Montana Public Service Commission and
Montana Department of Environmental Quality.
139. Montana Power--Montana Power Company.
140. Montana-Dakota--Montana-Dakota Utilities Co.
141. NARUC--National Association of Regulatory Utility
Commissioners.
142. NASUCA--National Association of State Utility Consumer
Advocates.
143. NCPA--Northern California Power Agency.
144. NEMA--National Energy Marketers Association.
145. NECPUC--New England Conference of Public Utilities
Commissioners, Inc.
146. NEPCO et al.--New England Power Company, National Grid
Group, plc and Montaup Electric Company.
147. NERA--National Economic Research Associates, Inc.
148. NERC--North American Electric Reliability Council.
149. Nevada Commission--Public Utilities Commission of Nevada
150. New Century--New Century Energies, Inc. and its operating
utility companies: Public Service Company of Colorado, Southwestern
Public Service Company and Cheyenne Light, Fuel and Power Company.
151. New Orleans--Council of the City of New Orleans.
152. New Smyrna Beach--Utilities Commission, City of New Smyrna
Beach, Florida.
153. New York Commission--New York State Public Service
Commission
154. Nine Commissions--Pennsylvania Public Utility Commission,
Virginia State Corporation Commission, Public Utilities Commission
of Ohio, Indiana Utility Regulatory Commission, Illinois Commerce
Commission, Michigan Public Service Commission, Missouri Public
Service Commission, Arkansas Public Service Commission and Oklahoma
Corporation Commission.
155. NiSource--NiSource Incorporated.
156. NJBUS--New Jersey Business Users.
157. NMA/WFA/CEED--National Mining Association, Western Fuels
Association, Inc. and Center for Energy and Economic Development.
158. NU--Northeast Utilities System.
159. Northwest Council--Northwest Power Planning Council.
160. NPCC--Northeast Power Coordinating Council.
161. NPPD--Nebraska Public Power District.
162. NPRB--Nebraska Power Review Board.
163. NRECA--National Rural Electric Cooperative Association.
164. NSP--Northern States Power Company.
165. NU--Northeast Utilities System.
166. NWCC--National Wind Coordinating Committee.
167. NY ISO--New York Independent System Operator, Inc.
168. NYC--City of New York.
169. NYEBF--New York Energy Buyers Forum.
170. NYMEX--New York Mercantile Exchange.
171. NYPP--Member Systems of the New York Power Pool (Central
Hudson Gas & Electric Corporation, Consolidated Edison Company of
New York, Inc., Long Island Power Authority, New York State Electric
& Gas Corporation, Niagara Mohawk Power Corporation, Orange and
Rockland Utilities, Inc., Rochester Gas and Electric Corp. and Power
Authority of the State of New York).
172. Oglethorpe--Oglethorpe Power Corporation.
173. Ohio Commission--Public Utilities Commission of Ohio.
174. Oneok--Oneok Power Marketing.
175. Ontario IMO--Ontario Independent Electricity Market
Operator.
176. Ontario Power--Ontario Power Generation Inc.
177. Oregon Office--Oregon Office of Energy.
178. Otter Tail--Otter Tail Power Company.
179. PacifiCorp--PacifiCorp.
180. PECO--PECO Energy Company and Horizon Energy.
181. Pennsylvania Commission--Pennsylvania Public Utility
Commission.
182. PG&E--PG&E Corporation.
183. PGE--Portland General Electric Company.
184. PGP--Public Generating Pool.
185. PJM--PJM Interconnection, L.L.C.
186. PJM/NEPOOL Customers--PJM Industrial Customer Coalition,
NEPOOL Industrial Customer Coalition and Coalition of Midwest
Transmission Customers.
187. Platte River--Platte River Power Authority.
188. PNGC--Pacific Northwest Generating Cooperative.
189. Powerex--British Columbia Power Exchange Corporation.
190. PP&L Companies--PP&L Inc., PP&L EnergyPlus Co., L.L.C.,
PP&L Montana, L.L.C.
191. PPC--Public Power Council.
192. Professor Hogan--Professor William W. Hogan.
193. Professor Joskow--Professor Paul L. Joskow.
194. Professor Koch--Professor Charles H. Koch, Jr.
195. Project Groups--Alliance for Affordable Energy, American
Wind Energy Association, Center for Clean Air Policy, Center for
Energy Efficiency and Renewable Technologies, Citizen Power, Inc.,
Citizens
[[Page 959]]
for Pennsylvania's Future, Delaware Division of the Public Advocate,
Environmental Law & Policy Center of the Midwest, Land & Water Fund
of the Rockies, Legal Environmental Assistance Foundation,
Minnesotans for an Energy-Efficient Economy, Natural Resources
Defense Council, Northwest Energy Coalition, Office of the People's
Counsel of the District of Columbia, Pace Energy Project,
Pennsylvania Energy Project, Public Citizen, PJM Public Interest/
Environmental User Group, Renew Wisconsin, Southern Environmental
Law Center, Tennessee Valley Energy Reform Coalition, Union of
Concerned Scientists, Wisconsin's Environmental Decade.
196. PSE&G--Public Service Electric and Gas Company.
197. PSNM--Public Service Company of New Mexico.
198. Public Citizen--Public Citizen.
199. Puget--Puget Sound Energy, Inc.
200. Rayburn--Rayburn Country Electric Cooperative, Inc.
201. RECA--Residential Electric Consumers Association.
202. Reliant--Reliant Energy, Incorporated.
203. RUS--Rural Utilities Service of the Department of
Agriculture.
204. Salomon Smith Barney--Global Power Group of Salomon Smith
Barney.
205. San Francisco--City and County of San Francisco.
206. SCE&G--South Carolina Electric & Gas Company.
207. Seattle--Seattle City Light Department.
208. SERC--Southeastern Electric Reliability Council.
209. Sierra Pacific--Sierra Pacific Resources, Inc.
210. Sithe--Sithe Energies, Inc.
211. SMUD--Sacramento Municipal Utility District.
212. Snohomish--Public Utility District No. 1 of Snohomish
County, Washington.
213. SNWA--Southern Nevada Water Authority.
214. SoCal Cities--Cities of Anaheim, Azusa, Banning, Colton,
and Riverside, California.
215. SoCal Edison--Southern California Edison Company.
216. Sonat--Sonat Power Marketing, L.P.
217. South Carolina Authority--South Carolina Public Service
Authority.
218. South Carolina Commission--Public Service Commission of
South Carolina.
219. Southern Company--Southern Company Services, Inc., acting
as agent for Alabama Power Company, Georgia Power Company, GulfPower
Company, Mississippi Power Company and Savannah Electric and Power
Company.
220. SPP--Southwest Power Pool, Inc.
221. SPRA--Southwestern Power Resources Association.
222. SRP--Salt River Project Agricultural Improvement and Power
District.
223. St. Joseph--St. Joseph Light & Power Company.
224. Statoil--Statoil Energy, Inc.
225. STDUG--Southwest Transmission Dependent Utility Group.
226. Steel Dynamics--Steel Dynamics, Inc.
227. Tacoma Power--City of Tacoma, Department of Public
Utilities, Light Division.
228. Tallahassee--City of Tallahassee, Florida.
229. Tampa Electric--Tampa Electric Company.
230. TANC--Transmission Agency of Northern California.
231. TAPS--Transmission Access Policy Study Group.
232. TDU Systems--Alabama Electric Cooperative, Inc., Arkansas
Electric Cooperative Corporation, Golden Spread Electric
Cooperative, Kansas Electric Power Cooperative, Inc., North Carolina
Electric Membership Corporation, Old Dominion Electric Cooperative,
Seminole Electric Cooperative, Inc., and South Mississippi Electric
Power Association.
233. Tennessee Authority--Tennessee Regulatory Authority.
234. TEP--Tucson Electric Power Company.
235. Texas Commission--Public Utility Commission of Texas.
236. Trans-Elect--Trans-Elect, Inc.
237. Transenergie--Transenergie.
238. Transmission ISO Participants--Baltimore Gas & Electric,
Boston Edison Company, Cambridge Electric Light Company,
Commonwealth Energy Company, Conectiv, GPU Energy, Niagara Mohawk
Power Company, Northeast Utilities Service Company, PECO Energy
Company, PP&L, Inc., Potomac Electric Power Company, Public Service
Electric and Gas Company, Vermont Electric Power Company, Inc.
239. Tri-State--Tri-State Generation and Transmission
Association, Inc.
240. Turlock--Turlock Irrigation District.
241. TVA--Tennessee Valley Authority.
242. TXU Electric--TXU Electric Company.
243. UAMPS--Utah Associated Municipal Power Systems.
244. UMPA--Utah Municipal Power Agency.
245. United Illuminating--United Illuminating Company.
246. UtiliCorp--UtiliCorp United, Inc.
247. Utility Engineers--Utility Economic Engineers.
248. Vernon--City of Vernon, California.
249. Virginia Commission--Virginia State Corporation Commission.
250. Virginia Power--Virginia Electric and Power Company.
251. Washington Commission--Washington Utilities and
Transportation Commission.
252. WEPCO--Wisconsin Electric Power Company.
253. WICF--Western Interconnection Coordination Forum.
254. Williams--Williams Companies, Inc.
255. Wisconsin Commission--Public Service Commission of
Wisconsin.
256. Wolverine Cooperative--Wolverine Power Supply. Cooperative,
Inc.
257. WPPI--Wisconsin Public Power, Inc.
258. WPSC--Wisconsin Public Service Corporation.
259. Wyoming Commission--Wyoming Public Service Commission.
[FR Doc. 00-2 Filed 1-5-00; 8:45 am]
BILLING CODE 6717-01-P
