Regional Transmission Organizations; Notice of Proposed Rulemaking
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Text
Part III
Department of Energy
_______________________________________________________________________
Federal Energy Regulatory Commission
_______________________________________________________________________
18 CFR Part 35
Regional Transmission Organizations; Proposed Rule
Regional Transmission Organizations; Intent To Prepare and
Environmental Assessment for the Regional Transmission Organizations
Rulemaking, Request for Comments on Environmental Issues, and Public
Scoping Meeting; Notice
Proposed Rules
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM99-2-000]
Regional Transmission Organizations; Notice of Proposed
Rulemaking
May 13, 1999.
AGENCY: Federal Energy Regulatory Commission.
ACTION: Notice of proposed rulemaking.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
proposing to amend its regulations under the Federal Power Act (FPA) to
facilitate the formation of Regional Transmission Organizations (RTOs).
The Commission proposes to require that each public utility that owns,
operates, or controls facilities for the transmission of electric
energy in interstate commerce make certain filings with respect to
forming and participating in an RTO. The Commission also proposes
minimum characteristics and functions that a transmission entity must
satisfy in order to be considered to be an RTO.
DATES: Initial comments are due August 16, 1999. Reply comments are due
September 15, 1999.
ADDRESSES: Send comments to: Office of the Secretary, Federal Energy
Regulatory Commission, 888 First Street, NE., Washington, D.C. 20426.
ating in an RTO. The Commission also proposes
minimum characteristics and functions that a transmission entity must
satisfy in order to be considered to be an RTO.
DATES: Initial comments are due August 16, 1999. Reply comments are due
September 15, 1999.
ADDRESSES: Send comments to: Office of the Secretary, Federal Energy
Regulatory Commission, 888 First Street, NE., Washington, D.C. 20426.
FOR FURTHER INFORMATION CONTACT:
Alan Haymes (Technical Information), Office of Electric Power
Regulation, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, D.C. 20426, (202) 219-2919.
Wilbur C. Earley (Technical Information), Office of Economic Policy,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, D.C. 20426, (202) 208-0100
Brian R. Gish (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, D.C. 20426, (202) 208-0996
SUPPLEMENTARY INFORMATION: In addition to publishing the full text of
this document in the Federal Register, the Commission also provides all
interested persons an opportunity to inspect or copy the contents of
this document during normal business hours in the Public Reference Room
at 888 First Street, N.E., Room 2A, Washington, D.C. 20426.
The Commission Issuance Posting System (CIPS) provides access to
the texts of formal documents issued by the Commission from November
14, 1994, to the present. CIPS can be accessed via Internet through
FERC's Home page (http://www.ferc.fed.us) using the CIPS Link or the
Energy Information Online icon. Documents will be available on CIPS in
ASCII and WordPerfect 6.1. User assistance is available at 202-208-2474
or by E-mail to [email protected].
This document is also available through the Commission's Records
and Information Management System (RIMS), an electronic storage and
retrieval system of documents submitted to and issued by the Commission
after November 16, 1981
mation Online icon. Documents will be available on CIPS in
ASCII and WordPerfect 6.1. User assistance is available at 202-208-2474
or by E-mail to [email protected].
This document is also available through the Commission's Records
and Information Management System (RIMS), an electronic storage and
retrieval system of documents submitted to and issued by the Commission
after November 16, 1981. Documents from November 1995 to the present
can be viewed and printed. RIMS is available in the Public Reference
Room or remotely via Internet through FERC's Home page using the RIMS
link or the Energy Information Online icon. User assistance is
available at 202-208-2222, or by E-mail to [email protected].
Finally, the complete text on diskette in WordPerfect format may be
purchased from the Commission's copy contractor, RVJ International,
Inc. RVJ International, Inc. is located in the Public Reference Room at
888 First Street, N.E., Washington, D.C. 20426.
Table of Contents
I. Introduction and Summary
II. Background
A. The Foundation for Competitive Markets: Order Nos. 888 and
889
B. Developments Since Order Nos. 888 and 889
1. Industry Restructuring and New Stresses on the Transmission
Grid
2. Successes, Failures and Haphazard Development of Regional
Transmission Entities
3. The Commission's ISO and RTO Inquiries; Conferences with
Stakeholders and State Regulators
C. Statutory Framework
III. Discussion
A. Barriers to Assuring an Abundant Supply of Electric Energy
throughout the U.S. with the Greatest Possible Economy
1. Engineering and Economic Inefficiencies in the Operation,
Planning, and Expansion of Regional Transmission Grids
2. Actual and Perceived Discriminatory Conduct by Transmission
Owners to Favor Their Own or Affiliated Merchant Operations
B. Benefits That RTOs Can Offer
1. An RTO Would Improve Efficiencies in the Management of the
Transmission Grid
2. An RTO Would Improve Grid Reliability
3. An RTO Would Remove Opportunities for Discriminatory
Transmission Practices
4
ion of Regional Transmission Grids
2. Actual and Perceived Discriminatory Conduct by Transmission
Owners to Favor Their Own or Affiliated Merchant Operations
B. Benefits That RTOs Can Offer
1. An RTO Would Improve Efficiencies in the Management of the
Transmission Grid
2. An RTO Would Improve Grid Reliability
3. An RTO Would Remove Opportunities for Discriminatory
Transmission Practices
4. An RTO Would Result in Improved Market Performance
5. An RTO Would Facilitate Lighter-Handed Governmental
Regulation
6. Conclusion
C. Concerns Expressed by the State Commissions
1. Federal Mandate
2. Regional Flexibility
3. Retail Markets
4. Effect on States With Low Cost Generation
5. Need for Independent Transmission Operation
6. Transmission Cost Shifting
7. Boundary Drawing
8. Regional Approach to Reliability
9. Pricing Reform
10. Participation of Public Power
11. State Role in RTO Governance
12. Existing Regional Transmission Entities
D. Minimum Characteristics and Functions for a Regional
Transmission Organization
Minimum Characteristics
1. Independence
2. Scope and Regional Configuration
3. Operational Authority
4. Short-term Reliability
Minimum Functions
1. Tariff Administration and Design
2. Congestion Management
3. Parallel Path Flow
4. Ancillary Services
5. OASIS and TTC and ATC
6. Market Monitoring
7. Planning and Expansion
E. Open Architecture
F. Ratemaking for Transmission Facilities under RTO Control
1. Single Transmission Access Rate for Capital Cost Recovery
2. Congestion Pricing
3. Performance Based Rate Regulation
4. Consideration of Incentive Pricing Proposals
G. Public Power Participation in RTOs
H. Other Issues
1. Pre-existing Transmission Contracts
2. Treatment of Existing Regional Transmission Entities
3. Participation by Canadian and Mexican Entities
4. Providing Service to Transmission-owning Utilities That Do
Not Participate in an RTO
5. RTO Filing Requirements
6. Power Exchanges (PXs)
I. Implementation of the Rule
1. Collaborative Process
2
lic Power Participation in RTOs
H. Other Issues
1. Pre-existing Transmission Contracts
2. Treatment of Existing Regional Transmission Entities
3. Participation by Canadian and Mexican Entities
4. Providing Service to Transmission-owning Utilities That Do
Not Participate in an RTO
5. RTO Filing Requirements
6. Power Exchanges (PXs)
I. Implementation of the Rule
1. Collaborative Process
2. Filing Requirements
IV. Environmental Statement
V. Regulatory Flexibility Act
VI. Public Reporting Burden and Information Collection Statement
VII. Public Comment Procedures
Text of the Regulations
Appendix A: Staff Summary of the FERC-Industry ISO Conferences
Appendix B: Staff Summary of FERC Consultations With the States
Appendix C: Existing Configurations
I. Introduction and Summary
In 1996 the Commission put in place the foundation necessary for
competitive wholesale power markets in this country--open access
transmission.1 Since that time, the industry has undergone
sweeping restructuring activity, including a movement by many states to
develop retail competition, the growing divestiture of generation
plants by traditional electric utilities, a significant increase in the
number of mergers among traditional electric utilities and among
electric utilities and gas pipeline companies, large increases in the
number of power marketers and independent generation facility
developers entering the marketplace, and the establishment of
independent system operators (ISOs) as managers of large parts of the
transmission system. Trade in bulk power markets has continued to
increase significantly and the Nation's transmission grid is being used
more heavily and in new ways.
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\1\ See Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities and
Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities, 61 FR 21540 (1996), FERC Stats. & Regs. para. 31,036
's transmission grid is being used
more heavily and in new ways.
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\1\ See Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities and
Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities, 61 FR 21540 (1996), FERC Stats. & Regs. para. 31,036
(1996) (Order No. 888), order on reh'g, Order No. 888-A, 62 FR 12274
(1997), FERC Stats. & Regs. para. 31,048 (1997), order on reh'g,
Order No. 888-B, 62 FR 64688, 81 FERC para. 61,248 (1997), order on
reh'g, Order No. 888-C, 82 FERC para. 61,046 (1998), appeal
docketed, Transmission Access Policy Study Group, et al. v. FERC,
Nos. 97-1715 et al. (D.C. Cir.).
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As a result, the traditional means of grid management is showing
signs of strain and may be inadequate to support the efficient and
reliable operation that is needed for the continued development of
competitive electricity markets. In addition, there are indications
that continued discrimination in the provision of transmission services
by vertically integrated utilities may also be impeding fully
competitive electricity markets. These problems may be depriving the
Nation of the benefits of lower prices, more reliance on market
solutions, and lighter-handed regulation that competitive markets can
bring.
If electricity consumers are to realize the full benefits that
competition can bring to wholesale markets, the Commission must address
the extent of these problems and appropriate ways of mitigating them.
Competition in wholesale electricity markets is the best way to protect
the public interest and ensure that electricity consumers pay the
lowest price possible for reliable service. We believe that further
steps may need to be taken to address grid management if we are to
achieve fully competitive power markets
ust address
the extent of these problems and appropriate ways of mitigating them.
Competition in wholesale electricity markets is the best way to protect
the public interest and ensure that electricity consumers pay the
lowest price possible for reliable service. We believe that further
steps may need to be taken to address grid management if we are to
achieve fully competitive power markets. We further believe that
regional approaches to the numerous issues affecting the industry may
be the best means to eliminate remaining impediments to properly
functioning competitive markets.
Our objective is for all transmission owning entities in the
Nation, including non-public utility entities, to place their
transmission facilities under the control of appropriate regional
transmission institutions in a timely manner. We seek to accomplish our
objective by encouraging voluntary participation. We are therefore
proposing in this rulemaking minimum characteristics and functions for
appropriate regional transmission institutions; a collaborative process
by which public utilities and non-public utilities that own, operate or
control interstate transmission facilities, in consultation with the
state officials as appropriate, will consider and develop regional
transmission institutions; a willingness to consider incentive pricing
on a case-specific basis and an offer of non-monetary regulatory
benefits, such as deference in dispute resolution, reduced or
eliminated codes of conduct, and streamlined filing and approval
procedures; and a time line for public utilities to make appropriate
filings with the Commission and initiate operation of regional
transmission institutions. As a result, we expect jurisdictional
utilities to form Regional Transmission Organizations (RTOs)
egulatory
benefits, such as deference in dispute resolution, reduced or
eliminated codes of conduct, and streamlined filing and approval
procedures; and a time line for public utilities to make appropriate
filings with the Commission and initiate operation of regional
transmission institutions. As a result, we expect jurisdictional
utilities to form Regional Transmission Organizations (RTOs).
As discussed in detail herein, regional institutions can address
the operational and reliability issues now confronting the industry,
and any residual discrimination in transmission services that can occur
when the operation of the transmission system remains in the control of
a vertically integrated utility. Appropriate regional transmission
institutions could: (1) improve efficiencies in transmission grid
management 2; (2) improve grid reliability; (3) remove the
remaining opportunities for discriminatory transmission practices; (4)
improve market performance; and (5) facilitate lighter handed
regulation.
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\2\ Appropriate regional institutions could improve efficiencies
in grid management through improved pricing, congestion management,
more accurate estimates of Available Transmission Capability,
improved parallel path flow management, more efficient planning, and
increased coordination between regulatory agencies.
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--
\2\ Appropriate regional institutions could improve efficiencies
in grid management through improved pricing, congestion management,
more accurate estimates of Available Transmission Capability,
improved parallel path flow management, more efficient planning, and
increased coordination between regulatory agencies.
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Thus, we believe that appropriate regional transmission
institutions could successfully address the existing impediments to
efficient grid operation and competition and could consequently benefit
consumers through lower electricity rates resulting from a wider choice
of services and service providers. There are likely to be substantial
cost savings brought about by regional transmission institutions.
In light of important questions regarding the complexity of grid
regionalization raised by state regulators and applicants in individual
cases, we are proposing a flexible approach. We are not proposing to
mandate that utilities participate in a regional transmission
institution by a date certain. Instead, we act now to ensure that they
consider doing so in good faith. Moreover, the Commission is not
proposing a ``cookie cutter'' organizational format for regional
transmission institutions or the establishment of fixed or specific
regional boundaries under section 202(a) of the FPA.
Rather, the Commission is proposing to establish fundamental
characteristics and functions for appropriate regional transmission
institutions. We will designate institutions that satisfy all of the
minimum characteristics and functions as Regional Transmission
Organizations (RTOs). Hereinafter, the term Regional Transmission
Organization, or RTO, will refer to an organization that satisfies all
of the minimum characteristics and functions
fundamental
characteristics and functions for appropriate regional transmission
institutions. We will designate institutions that satisfy all of the
minimum characteristics and functions as Regional Transmission
Organizations (RTOs). Hereinafter, the term Regional Transmission
Organization, or RTO, will refer to an organization that satisfies all
of the minimum characteristics and functions.
Pursuant to our authority under section 205 of the FPA to ensure
that rates, terms and conditions of transmission and sales for resale
in interstate commerce by public utilities are just, reasonable and not
unduly discriminatory or preferential, and our authority under section
202(a) of the FPA to promote and encourage regional districts for the
voluntary interconnection and coordination of transmission facilities
by public utilities and non-public utilities for the purpose of
assuring an abundant supply of electric energy throughout the U.S. with
the greatest possible economy, we propose the following.3
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\3\ The Commission's legal authority is discussed in Section II.
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First, the Commission proposes minimum characteristics and
functions that an RTO must satisfy. Industry participants, however,
retain flexibility in structuring RTOs that satisfy these
characteristics and functions. For example, we do not propose to
require or prohibit any one form of organization for RTOs or require or
prohibit RTO ownership of transmission facilities. The characteristics
and functions could be satisfied by different organizational forms,
such as ISOs, transcos, combinations of the two, or even new
organizational forms not yet discussed in the industry or proposed to
the Commission.
Second, we propose to adopt an ``open architecture'' policy
regarding RTOs, whereby all RTO proposals must
prohibit RTO ownership of transmission facilities. The characteristics
and functions could be satisfied by different organizational forms,
such as ISOs, transcos, combinations of the two, or even new
organizational forms not yet discussed in the industry or proposed to
the Commission.
Second, we propose to adopt an ``open architecture'' policy
regarding RTOs, whereby all RTO proposals must
allow the RTO and its members the flexibility to improve their
organizations in the future in terms of structure, operations, market
support and geographic scope to meet market needs. In turn, the
Commission will provide the regulatory flexibility to accommodate such
improvement.
Third, we propose guidance on flexible transmission ratemaking that
may be proposed by RTOs, including ratemaking treatments that will
address congestion pricing and performance based regulation. We also
propose to consider on a case-by-case basis incentive pricing that may
be appropriate for transmission facilities under RTO control.
Finally, all public utilities (with the exception of those
participating in an approved regional transmission entity that conforms
to the Commission's ISO principles) that own, operate or control
interstate transmission facilities must file with the Commission by
October 15, 2000 a proposal for an RTO with the minimum characteristics
and functions adopted in the Final Rule,4 or, alternatively,
a description of efforts to participate in an RTO, any existing
obstacles to RTO participation, and any plans to work toward RTO
participation. Each proposed RTO must plan to be operational by
December 15, 2001. We expect that such proposals would include the
transmission facilities of public utilities as well as transmission
facilities of public power and other non-public utility entities to the
extent possible.
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nd any plans to work toward RTO
participation. Each proposed RTO must plan to be operational by
December 15, 2001. We expect that such proposals would include the
transmission facilities of public utilities as well as transmission
facilities of public power and other non-public utility entities to the
extent possible.
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\4\ An RTO proposal includes a basic agreement filed under
section 205 of the FPA setting out the rules, practices and
procedures under which an RTO will be governed and operated, and
requests by the public utility members of the RTO under section 203
of the FPA to transfer control of their jurisdictional transmission
facilities from individual public utilities to the RTO. Most RTO
proposals by public utilities are likely to involve one or more
filings under FPA sections 203, 205, or 206, but the number and
types of filing may vary depending upon the type of RTO proposed,
and the number of public utilities involved in the proposal. Under
the proposed rule, a utility may file a petition for a declaratory
order asking whether a proposed transmission entity would qualify as
an RTO, to be followed by appropriate filings under sections 203,
205 and/or 206.
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A public utility that is a member of an existing transmission
entity that has been approved by the Commission as in conformance with
the eleven ISO principles set forth in Order No. 888 must make a filing
no later than January 15, 2001 that explains the extent to which the
transmission entity in which it participates meets the minimum
characteristics and functions for an RTO, or proposes to modify the
existing institution to become an RTO. Alternatively, the public
utility must file an explanation of efforts, obstacles and plans with
respect to conforming to these characteristics and functions
no later than January 15, 2001 that explains the extent to which the
transmission entity in which it participates meets the minimum
characteristics and functions for an RTO, or proposes to modify the
existing institution to become an RTO. Alternatively, the public
utility must file an explanation of efforts, obstacles and plans with
respect to conforming to these characteristics and functions.
Through the required filings, utilities will make known to the
public any plans for RTO participation so that other utilities and the
competitive market can respond accordingly. This proposal relies
primarily on the enlightened self-interest of stakeholders in each
region. Such public disclosure of plans for transmission facilities
will benefit the industry, the financial community, and public policy
makers as the electric industry restructuring continues.
To facilitate RTO formation in all regions of the Nation, the
Commission proposes to sponsor and support a collaborative process
under section 202(a) to take place in the spring of 2000. Under this
process, we expect that public utilities and non-public utilities, in
coordination with state officials, Commission staff, and all affected
interest groups, will actively work toward the voluntary development of
specific RTOs.
Prior to undertaking this proposed rulemaking, we held eight
technical conferences in 1998 with all industry stakeholders as well as
three technical conferences this year with state regulatory commissions
to obtain their views on the need for, and benefits of, regional
organizations. We gained valuable insight from the participants,
including many state commissions that have undertaken or are
considering state retail choice programs for the consumers in their
states. In light of the comments received, we wish to respond to
several concerns that were raised.
First, we are not proposing to mandate RTOs, nor are we proposing
detailed specifications on a particular organizational form for RTOs
insight from the participants,
including many state commissions that have undertaken or are
considering state retail choice programs for the consumers in their
states. In light of the comments received, we wish to respond to
several concerns that were raised.
First, we are not proposing to mandate RTOs, nor are we proposing
detailed specifications on a particular organizational form for RTOs.
The goal of this rulemaking is to get RTOs in place through voluntary
participation. While this Commission has specific authorities and
responsibilities under the FPA to protect against undue discrimination
and remove impediments to wholesale competition, we believe it is
preferable to meet these responsibilities in the first instance through
an open and collaborative process that allows for regional flexibility
and induces voluntary behavior.
Second, the development of RTOs is not intended to interfere with
state prerogatives in setting retail competition policy. The Commission
believes that RTOs can successfully accommodate the transmission
systems of all states, whether or not a particular state has adopted
retail competition. However, for those states that have chosen to adopt
retail wheeling, RTOs can play a critical role in the realization of
full competition at the retail level as well as at the wholesale level.
In addition, the Commission believes that RTOs will not interfere with
a state's prerogative to keep the benefits of low-cost power for the
state's own retail consumers.
Third, we propose to allow RTOs to prevent transmission cost
shifting by continuing our policy of flexibility with respect to
recovery of sunk transmission costs, such as the ``license plate''
approach.
Fourth, the existence of RTOs has not, and will not in the future,
interfere with traditional state and local regulatory responsibilities
such as transmission siting, local reliability matters, and regulation
of retail sales of generation and local distribution
by continuing our policy of flexibility with respect to
recovery of sunk transmission costs, such as the ``license plate''
approach.
Fourth, the existence of RTOs has not, and will not in the future,
interfere with traditional state and local regulatory responsibilities
such as transmission siting, local reliability matters, and regulation
of retail sales of generation and local distribution. In fact, RTOs
offer the potential to assist the states in their regulation of retail
markets and in resolving matters among states on a regional basis. They
also provide a vehicle for amicably resolving state and Federal
jurisdictional issues.
Finally, we do not propose to establish regional boundaries in this
rulemaking. Our foremost concern is that a proposed RTO's regional
configuration is sufficient to ensure that the required RTO
characteristics and functions are satisfied. To this end, the
Commission proposes guidance regarding the scope and regional
configuration of RTOs.
We now turn to the state of the electric utility industry in the
wake of Order No. 888 and how the development of RTOs achieves
efficient, reliable and competitive power markets.
II. Background
In April 1996, in Order Nos. 888 and 889, the Commission
established the foundation necessary to develop competitive bulk power
markets in the United States: non-discriminatory open access
transmission services by public utilities and stranded cost recovery
rules that would provide a fair transition to competitive markets.
Order Nos. 888 and 889 were very successful in accomplishing much of
what they set out to do. However, they were not intended to address all
problems that might arise in the development of competitive power
markets. Indeed, the nature of the emerging markets and the remaining
impediments to full competition have become apparent in the three years
since the issuance of our orders.
A. The Foundation for Competitive Markets: Order Nos. 888 and 889
ishing much of
what they set out to do. However, they were not intended to address all
problems that might arise in the development of competitive power
markets. Indeed, the nature of the emerging markets and the remaining
impediments to full competition have become apparent in the three years
since the issuance of our orders.
A. The Foundation for Competitive Markets: Order Nos. 888 and 889
In Order Nos. 888 and 889, the Commission found that unduly
discriminatory and anticompetitive
practices existed in the electric industry, and that transmission-
owning utilities had discriminated against others seeking transmission
access.5 The Commission stated that its goal was to ensure
that customers have the benefits of competitively priced generation,
and determined that non-discriminatory open access transmission
services (including access to transmission information) and stranded
cost recovery were the most critical components of a successful
transition to competitive wholesale electricity markets.6
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\5\ Order No. 888, FERC Stats & Regs. at 31,682.
\6\ Id. at 31,652.
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Accordingly, Order No. 888 required all public utilities that own,
control or operate facilities used for transmitting electric energy in
interstate commerce to (1) file open access non-discriminatory
transmission tariffs containing, at a minimum, the non-price terms and
conditions set forth in the Order, and (2) functionally unbundle
wholesale power services
-------------------------------
Accordingly, Order No. 888 required all public utilities that own,
control or operate facilities used for transmitting electric energy in
interstate commerce to (1) file open access non-discriminatory
transmission tariffs containing, at a minimum, the non-price terms and
conditions set forth in the Order, and (2) functionally unbundle
wholesale power services. Under functional unbundling, the public
utility must: (a) take transmission services under the same tariff of
general applicability as do others; (b) state separate rates for
wholesale generation, transmission, and ancillary services; and (c)
rely on the same electronic information network that its transmission
customers rely on to obtain information about its transmission system
when buying or selling power.7 Order No. 889 required that
all public utilities establish or participate in an Open Access Same-
Time Information System (OASIS) that meets certain specifications, and
comply with standards of conduct designed to prevent employees of a
public utility (or any employees of its affiliates) engaged in
wholesale power marketing functions from obtaining preferential access
to pertinent transmission system information.
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\7\ Id. at 31,654-55.
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During the course of the Order No. 888 proceeding, the Commission
received comments urging it to require generation divestiture or
structural institutional arrangements such as regional independent
system operators (ISOs) to better assure non-discrimination. The
Commission responded that, while it believed that ISOs had the
potential to provide significant benefits, efforts to remedy undue
discrimination should begin by requiring the less intrusive functional
unbundling approach. Order No. 888 set forth eleven principles for
assessing ISO proposals submitted to the Commission. 8 Order
No. 888 also stated:
Os) to better assure non-discrimination. The
Commission responded that, while it believed that ISOs had the
potential to provide significant benefits, efforts to remedy undue
discrimination should begin by requiring the less intrusive functional
unbundling approach. Order No. 888 set forth eleven principles for
assessing ISO proposals submitted to the Commission. 8 Order
No. 888 also stated:
\8\ Id. at 31,730.
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[W]e see many benefits in ISOs, and encourage utilities to
consider ISOs as a tool to meet the demands of the competitive
marketplace.
As a further precaution against discriminatory behavior, we will
continue to monitor electricity markets to ensure that functional
unbundling adequately protects transmission customers. At the same
time, we will analyze all alternative proposals, including formation
of ISOs, and, if it becomes apparent that functional unbundling is
inadequate or unworkable in assuring non-discriminatory open access
transmission, we will reevaluate our position and decide whether
other mechanisms, such as ISOs, should be required. 9
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\9\ Id. at 31,655.
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In section III.A.2 of this Notice of Proposed Rulemaking, we
discuss our experiences to date with functional unbundling. It has
become apparent that several types of regional transmission
institutions, in addition to the kinds of ISOs approved to date, may
also be able to provide the benefits attributed to ISOs in Order No.
888.
B. Developments Since Order Nos. 888 and 889
----------------
In section III.A.2 of this Notice of Proposed Rulemaking, we
discuss our experiences to date with functional unbundling. It has
become apparent that several types of regional transmission
institutions, in addition to the kinds of ISOs approved to date, may
also be able to provide the benefits attributed to ISOs in Order No.
888.
B. Developments Since Order Nos. 888 and 889
In the three years since Order Nos. 888 and 889 were issued,
numerous significant developments have occurred in the electric utility
industry. Some of these reflect changes in governmental policies;
others are strictly industry driven. These activities have resulted in
a considerably different industry landscape from the one faced at the
time the Commission was developing Order No. 888, resulting in new
regulatory and industry challenges.
Order Nos. 888 and 889 required a significant change in the way
many public utilities have done business for most of this century, and
most public utilities accepted these changes and made substantial good
faith efforts to comply with the new requirements. Virtually all public
utilities have filed tariffs stating rates, terms and conditions for
third-party use of their transmission systems. In addition, improved
information about the transmission system is available to all
participants in the market at the same time that it is available to the
public utility as a result of utility compliance with the OASIS
regulations.
The availability of tariffs and information about the transmission
system has fostered a rapid growth in dependence on wholesale markets
for acquisition of generation resources. Areas that have experienced
generation shortages have seen rapid development of new generation
resources. For example, New England, where there was deep concern about
adequacy of generation supply only three years ago, now has
approximately 30,000 MW of generation proposed
nsmission
system has fostered a rapid growth in dependence on wholesale markets
for acquisition of generation resources. Areas that have experienced
generation shortages have seen rapid development of new generation
resources. For example, New England, where there was deep concern about
adequacy of generation supply only three years ago, now has
approximately 30,000 MW of generation proposed. That response comes
almost entirely from independent generating plants that are able to
sell power into the bulk power market through open access to the
transmission system. Power resources are now acquired over increasingly
large regional areas, and interregional transfers of electricity have
increased.
The very success of Order Nos. 888 and 889, and the initiative of
some utilities that have pursued voluntary restructuring beyond the
minimum open access requirements , have put new stresses on regional
transmission systems--stresses that call for regional solutions.
1. Industry Restructuring and New Stresses on the Transmission Grid
Open access transmission and the opening of wholesale competition
in the electric industry have brought an array of changes in the past
several years: divestiture by many integrated utilities of some or all
of their generating assets; significantly increased merger activity
both between electric utilities and between electric and natural gas
utilities; increases in the number of new participants in the industry
in the form of independent power marketers and generators; increases in
the volume of trade in the industry, particularly as marketers make
multiple sales; state efforts to create retail competition; and new and
different uses of the transmission grid.
With respect to divestiture, since August 1997, approximately
50,000 MW of generating capacity have been sold (or are under contract
to be sold) by utilities, and an additional 30,000 MW is currently for
sale. In total, this represents more than 10 percent of U.S. generating
capacity
tiple sales; state efforts to create retail competition; and new and
different uses of the transmission grid.
With respect to divestiture, since August 1997, approximately
50,000 MW of generating capacity have been sold (or are under contract
to be sold) by utilities, and an additional 30,000 MW is currently for
sale. In total, this represents more than 10 percent of U.S. generating
capacity. In all, according to publicly available data, 27 utilities
have sold all or some of their generating assets and 7 others have
assets for sale. Buyers of this generating capacity have included
traditional utilities with specified service territories as well as
independent power producers with no required service territory.
Since Order No. 888 was issued, there have been more than 20
applications filed with us to approve proposed mergers involving public
utilities. Most of these mergers have been approved by various
regulatory authorities, including the Commission, although a few have
been rejected or withdrawn, and several mergers are pending regulatory
approval. Most of these merger proposals have been between electric
utilities with contiguous service areas, while some of the proposed
mergers have been between utilities with non-
contiguous service areas. The Commission has also been presented with
merger applications involving the combination of electric and natural
gas assets.
There has been significant growth in the volume of trading in the
wholesale electricity market. In the first quarter of 1995, according
to power marketer quarterly filings, marketer sales totaled 1.8 million
MWh, but by the second quarter of 1998, such sales escalated to 513
million MWh.10 Many new competitors have entered the
industry. For example, in the first quarter of 1995, there were eight
power marketers (either independent or affiliated with traditional
utilities) actively trading in wholesale power markets, but by the
second quarter of 1998, there were 108 actively trading power
marketers
h, but by the second quarter of 1998, such sales escalated to 513
million MWh.10 Many new competitors have entered the
industry. For example, in the first quarter of 1995, there were eight
power marketers (either independent or affiliated with traditional
utilities) actively trading in wholesale power markets, but by the
second quarter of 1998, there were 108 actively trading power
marketers. The Commission has granted market-based rate authority to
well over 500 wholesale power marketers, of which some are independent
of traditional investor-owned utilities, some are affiliated with
traditional utilities, and some are traditional utilities
themselves.11
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\10\ Power marketer quarterly filings, cited in Staff Report to
the Federal Energy Regulatory Commission on the Causes of Wholesale
Electric Pricing Abnormalities in the Midwest During June 1998,
(September 22, 1998) (Staff Price Spike Report) at 3-1 to 3-2. It
must be noted that a significant portion of the sales represent the
retrading of power by a number of different market participants. In
other words, there may be multiple resales of the same generation.
\11\ Id. at 3-1.
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State commissions and legislatures have been active in the past few
years studying competitive options at the retail level, setting up
pilot retail access programs, and, in some states, implementing full
scale retail access programs. As of May 1, 1999, 18 states have enacted
electric restructuring legislation, 3 have issued comprehensive
regulatory orders, and 28 others have legislation or orders pending or
investigations underway.12 Fifteen states have implemented
full-scale or pilot retail competition programs that offer a choice of
suppliers to at least some retail customers. Eight states have set in
motion programs to offer access to retail customers by a date certain
restructuring legislation, 3 have issued comprehensive
regulatory orders, and 28 others have legislation or orders pending or
investigations underway.12 Fifteen states have implemented
full-scale or pilot retail competition programs that offer a choice of
suppliers to at least some retail customers. Eight states have set in
motion programs to offer access to retail customers by a date certain.
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\12\ ``Status of Electric Utility Deregulation Activity as of
May 1, 1999,'' Energy Information Administration.
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Because of the changes in the structure of the electric industry,
the transmission grid is now being used more intensively and in
different ways than in the past. The Commission is concerned that the
traditional approaches to operating the grid are showing signs of
strain. According to the North American Electric Reliability Council
(NERC), ``the adequacy of the bulk transmission system has been
challenged to support the movement of power in unprecedented amounts
and in unexpected directions.'' 13 These changes in the use
of the transmission system ``will test the electric industry's ability
to maintain system security in operating the transmission system under
conditions for which it was not planned or designed.'' 14 It
should be noted that, despite the increased transmission system
loadings, NERC believes that the ``procedures and processes to mitigate
potential reliability impacts appear to be working reliably for now,''
and that even though the system was particularly stressed during the
summer of 1998, ``the system performed reliably and firm demand was not
interrupted due to transmission transfer limitations.'' 15
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s that the ``procedures and processes to mitigate
potential reliability impacts appear to be working reliably for now,''
and that even though the system was particularly stressed during the
summer of 1998, ``the system performed reliably and firm demand was not
interrupted due to transmission transfer limitations.'' 15
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\13\ Reliability Assessment 1998-2007, North American Electric
Reliability Council (September 1998), at 26.
\14\ Id.
\15\ Id.
---------------------------------------------------------------------------
An indication that the increased and different use of the
transmission system is stressing the grid is the increased use of
transmission line loading relief (TLR) procedures. 16 NERC's
TLR procedures were invoked 250 times between January 1 and September
1, 1998 to prevent facility or interface overloads on the Eastern
Interconnection. 17
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\16\ The TLR procedures are designed to remedy overloads that
result when a transmission line or other transmission equipment
carries or will carry more power than its rating, which could result
in either power outages or damage to property. The TLR procedures
are designed to bring overloaded transmission equipment to within
NERC's Operating Security Limits essentially by curtailing
transactions contributing to the overload. See North American
Electric Reliability Council, 85 FERC para. 61,353 (1998) (NERC).
\17\ Reliability Assessment 1998-2007 at 27.
---------------------------------------------------------------------------
y. The TLR procedures
are designed to bring overloaded transmission equipment to within
NERC's Operating Security Limits essentially by curtailing
transactions contributing to the overload. See North American
Electric Reliability Council, 85 FERC para. 61,353 (1998) (NERC).
\17\ Reliability Assessment 1998-2007 at 27.
---------------------------------------------------------------------------
It appears that the planning and construction of transmission and
transmission-related facilities may not be keeping up with increased
requirements. According to NERC, ``Business is increasing on the
transmission system, but very little is being done to increase the load
serving and transfer capability of the bulk transmission system.''
18 The amount of new transmission capacity planned over the
next ten years is significantly lower than the additions that had been
planned five years ago, and most of the planned projects are for local
system support. 19 NERC states that, ``The close
coordination of generation and transmission planning is diminishing as
vertically integrated utilities divest their generation assets and most
new generation is being proposed and developed by independent power
producers.'' 20
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\18\ Id. at 26.
\19\ Id. at 7.
\20\ Id.
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The transition to new market structures has resulted in new
challenges and circumstances. For example, during the week of June 22-
26, 1998, the wholesale electric market in the Midwest experienced
numerous events that led to unprecedented high spot market prices. Spot
wholesale market prices for energy briefly rose as high as $7,500 per
MWh, compared to an average price for the summer of approximately $40
per MWh in the Midwest if the price spikes are excluded
s and circumstances. For example, during the week of June 22-
26, 1998, the wholesale electric market in the Midwest experienced
numerous events that led to unprecedented high spot market prices. Spot
wholesale market prices for energy briefly rose as high as $7,500 per
MWh, compared to an average price for the summer of approximately $40
per MWh in the Midwest if the price spikes are excluded. 21
This experience led to calls for price caps, allegations of market
power, and a questioning of the effectiveness of transmission open
access and wholesale electric competition.
---------------------------------------------------------------------------
\21\ Staff Price Spike Report at 3-8 to 3-11.
---------------------------------------------------------------------------
The Commission staff undertook an investigation of the price spike
incident. Staff's report concluded that the unusually high price levels
were caused by a combination of factors, particularly above-average
generation outages, unseasonably hot temperatures, storm-related
transmission outages, transmission constraints, poor communication of
price signals, lowered confidence in the market due to a few contract
defaults, and inexperience in dealing with competitive markets.
22
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\22\ Id. at v.
---------------------------------------------------------------------------
tures, storm-related
transmission outages, transmission constraints, poor communication of
price signals, lowered confidence in the market due to a few contract
defaults, and inexperience in dealing with competitive markets.
22
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\22\ Id. at v.
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The Commission's staff found that the market institutions were not
adequately prepared to deal with such a dramatic series of events.
Regarding regional transmission entities, the staff report observed:
``The necessity for cooperation in meeting reliability concerns and the
Commission's intent to foster competitive market conditions underscores
the importance of better regional coordination in areas such as
maintenance of transmission and generation systems and transmission
planning and operation.'' 23 Support for this view comes
from many sources. For example, the Public Utilities Commission of
Ohio, in its own report on the price spikes, recommended that policy
makers ``take unambiguous action to require coordination of
transmission system operations by regionwide Independent System
Operators.'' 24
---------------------------------------------------------------------------
\23\ Id. at 5-8.
\24\ Ohio's Electric Market, June 22-26, 1998, What Happened
and Why, A Report to the Ohio General Assembly, at iii.
---------------------------------------------------------------------------
On September 29, 1998, the Secretary of Energy Advisory Board Task
Force on Electric System Reliability published its
-----------------------------------------------------------------
\23\ Id. at 5-8.
\24\ Ohio's Electric Market, June 22-26, 1998, What Happened
and Why, A Report to the Ohio General Assembly, at iii.
---------------------------------------------------------------------------
On September 29, 1998, the Secretary of Energy Advisory Board Task
Force on Electric System Reliability published its
final report. 25 The Task Force was convened in January 1997
to provide advice to the Department of Energy on critical
institutional, technical, and policy issues that need to be addressed
in order to maintain bulk power electric system reliability in a more
competitive industry. The Task Force found that ``the traditional
reliability institutions and processes that have served the Nation well
in the past need to be modified to ensure that reliability is
maintained in a competitively neutral fashion;'' that ``grid
reliability depends heavily on system operators who monitor and control
the grid in real time;'' and that ``because bulk power systems are
regional in nature, they can and should be operated more reliably and
efficiently when coordinated over large geographic areas.''
26
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\25\ Maintaining Reliability in a Competitive U.S. Electricity
Industry; Final Report of the Task Force on Electric System
Reliability (Sept. 29, 1998) (Task Force Report). The Task Force was
comprised of 24 members representing all major segments of the
electric industry, including private and public suppliers, power
marketers, regulators, environmentalists, and academics.
\26\ Task Force Report at x-xi.
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the Task Force on Electric System
Reliability (Sept. 29, 1998) (Task Force Report). The Task Force was
comprised of 24 members representing all major segments of the
electric industry, including private and public suppliers, power
marketers, regulators, environmentalists, and academics.
\26\ Task Force Report at x-xi.
---------------------------------------------------------------------------
The report noted that many regions of the United States are
developing ISOs as a way to maintain electric system reliability as
competitive markets develop. According to the Task Force, ISOs are
significant institutions to assure both electric system reliability and
competitive generation markets. The Task Force concluded that a large
ISO would: (1) be able to identify and address reliability issues most
effectively; (2) internalize much of the loop flow caused by the
growing number of transactions; (3) facilitate transmission access
across a larger portion of the network, consequently improving market
efficiencies and promoting greater competition; and (4) eliminate
``pancaking'' of transmission rates, thus allowing a greater range of
economic energy trades across the network. 27
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\27\ Id. at 76.
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2. Successes, Failures, and Haphazard Development of Regional
Transmission Entities
Since Order No. 888 was issued, there have been both successful and
unsuccessful efforts to establish ISOs, and other efforts to form
regional entities to operate the transmission facilities in various
parts of the country. While we are encouraged by the success of some of
these efforts, it is apparent that the results have been inconsistent,
and much of the country's transmission facilities remain outside of an
operational regional transmission institution
unsuccessful efforts to establish ISOs, and other efforts to form
regional entities to operate the transmission facilities in various
parts of the country. While we are encouraged by the success of some of
these efforts, it is apparent that the results have been inconsistent,
and much of the country's transmission facilities remain outside of an
operational regional transmission institution.
Proposals for the establishment of five ISOs have been submitted to
and approved, or conditionally approved, by the Commission. These are
the California ISO,28 the PJM ISO,29 ISO New
England ISO,30 the New York ISO,31 and the
Midwest ISO.32 In addition, the Texas Commission has ordered
an ISO for the Electric Reliability Council of Texas
(ERCOT).33 Moreover, our international neighbors in Canada
and Mexico are also pursuing electric restructuring efforts that
include various forms of regional transmission entities.34
---------------------------------------------------------------------------
\28\ Pacific Gas & Electric Company, et al., 77 FERC para.61,204
(1996), order on reh'g, 81 FERC para.61,122 (1997) (Pacific Gas &
Electric).
\29\ Pennsylvania-New Jersey-Maryland Interconnection, et al.,
81 FERC para.61,257 (1997), reh'g pending (PJM).
\30\ New England Power Pool, 79 FERC para.61,374 (1997), order
on reh'g, 85 FERC para.61,242 (1998) (order conditionally
authorizing ISO New England); New England Power Pool, 83 FERC
para.61,045 (1998), reh'g pending (order on NEPOOL tariff and
restructuring)(NEPOOL).
\31\ Central Hudson Gas & Electric Corporation, et al., 83 FERC
para.61,352 (1998), order on reh'g, 87 FERC para.61,135 (1999)
(Central Hudson).
\32\ Midwest Independent Transmission System Operator, et al.,
84 FERC para.61,231, order on reconsideration, 85 FERC para.61,250,
order on reh'g, 85 FERC para.61,372 (1998) (Midwest ISO).
\33\ See 16 Texas Administrative Code Sec. 23.67(p)
EPOOL).
\31\ Central Hudson Gas & Electric Corporation, et al., 83 FERC
para.61,352 (1998), order on reh'g, 87 FERC para.61,135 (1999)
(Central Hudson).
\32\ Midwest Independent Transmission System Operator, et al.,
84 FERC para.61,231, order on reconsideration, 85 FERC para.61,250,
order on reh'g, 85 FERC para.61,372 (1998) (Midwest ISO).
\33\ See 16 Texas Administrative Code Sec. 23.67(p).
\34\ See Policy Proposal for Structural Reform of the Mexican
Electricity Industry, Secretary of Energy, Mexico (February 1999);
Third Interim Report of the Ontario Market Design Committee (October
1998); TransAlta Enterprises Corporation, 75 FERC para.61,268 at
61,875 (1996) (recognition of the restructuring in the Province of
Alberta, Canada to create a Grid Company of Alberta).
---------------------------------------------------------------------------
The PJM, New England and New York ISOs were established on the
platform of existing tight power pools. It appears that the principal
motivation for creating ISOs in these situations was the Order No. 888
requirement that there be a single system wide transmission tariff for
tight pools. In contrast, the establishment of the California ISO and
the ERCOT ISO was the direct result of mandates by state governments.
The Midwest ISO, which is not yet operational, is unique. It began
through a consensual process and was not driven by a pre-existing
institution. Two states in the region subsequently required utilities
in their states to participate in either a Commission-approved ISO
(Illinois and Wisconsin), or sell their transmission assets to an
independent transmission company (Wisconsin).
The approved ISOs have similarities as well as differences. All
five Commission-approved ISOs operate, or propose to operate, as non-
profit organizations. All five ISOs include both public and non-public
utility members. However, among the five, there is considerable
variation in governance, operational responsibilities, geographic scope
and market operations
ransmission company (Wisconsin).
The approved ISOs have similarities as well as differences. All
five Commission-approved ISOs operate, or propose to operate, as non-
profit organizations. All five ISOs include both public and non-public
utility members. However, among the five, there is considerable
variation in governance, operational responsibilities, geographic scope
and market operations. Four of the ISOs rely on a two-tier form of
governance with a non-stakeholder governing board on top that is
advised, either formally or informally, by one or more stakeholder
groups. In general, the final decision making authority rests with the
independent non-stakeholder board. One ISO, the California ISO, uses a
board consisting of stakeholders and non-stakeholders.
Four of the five ISOs operate traditional control areas, but the
Midwest ISO does not currently plan to operate a traditional control
area. Three are multi-state ISOs (New England, PJM and Midwest), while
two ISOs (California and New York) currently operate within a single
state. The current Midwest ISO members do not encompass one contiguous
geographic area and there are holes in its coverage. The ISO New
England administers a separate NEPOOL tariff, while the other four
administer their own ISO transmission tariffs.
Three ISOs operate or propose to operate centralized power markets
(New England, PJM and New York), and one ISO (California) relies on a
separate power exchange (PX) to operate such a market.35 The
Midwest ISO did not originally envision an ISO-related centralized
market for its region.36 In addition, at least one separate
PX has begun to do business in California apart from the PX established
through the restructuring legislation.37
---------------------------------------------------------------------------
ornia) relies on a
separate power exchange (PX) to operate such a market.35 The
Midwest ISO did not originally envision an ISO-related centralized
market for its region.36 In addition, at least one separate
PX has begun to do business in California apart from the PX established
through the restructuring legislation.37
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\35\ The California PX offers day-ahead and hour-ahead markets
and the ISO operates a real-time energy market. Participation in the
PX market is voluntary except that the three traditional investor-
owned utilities in California must bid their generation sales and
purchases through the PX for the first five years. New York will
offer day-ahead and real-time energy markets that will be operated
by the ISO. PJM and New England offer only real-time energy markets,
although PJM has proposed to operate a day-ahead market. The ERCOT
ISO is the only other ISO that does not currently operate a PX.
\36\ There are indications, however, that the Midwest ISO is
considering the formation of a power exchange. See Joint Committee
for the Development of a Midwest Independent Power Exchange,
``Solicitation of Interest-Creation of an Independent Power Exchange
for the U.S. Midwest,'' February 5, 1999.
\37\ See Automated Power Exchange, Inc., 82 FERC para. 61,287,
reh'g denied, 84 FERC para. 61,020 (1998), appeals docketed, No. 98-
1415 (D.C. Cir. Sept. 14, 1998) and No. 98-1419 (D.C. Cir. Sept. 14,
1998).
---------------------------------------------------------------------------
Not all efforts to create ISOs have been successful. For example,
after more than two years of effort, the proponents of the IndeGO ISO
in the Pacific Northwest and Rocky Mountain regions ended their efforts
to create an ISO. More recently, members of MAPP, an existing power
pool that covers six U.S.
ept. 14,
1998).
---------------------------------------------------------------------------
Not all efforts to create ISOs have been successful. For example,
after more than two years of effort, the proponents of the IndeGO ISO
in the Pacific Northwest and Rocky Mountain regions ended their efforts
to create an ISO. More recently, members of MAPP, an existing power
pool that covers six U.S.
states and two Canadian provinces, failed to achieve consensus for
establishing a long-planned ISO. In the Southwest, proponents of the
Desert Star ISO have not been able to reach agreement on a formal
proposal after more than two years of discussion.
Various reasons have been advanced to explain why it is difficult
to form a voluntary, multi-state ISO. These include cost shifting in
transmission capital costs; disagreements about sharing of ISO
transmission revenues among transmission owners; difficulties in
obtaining the participation of publicly-owned transmission facilities;
concerns about the loss of transmission rights and prices embedded in
existing transmission agreements; the likelihood of not being able to
maintain or gain a competitive advantage in power markets through the
use of transmission facilities; and the preference of certain
transmission owners to sell or transfer their transmission assets to a
for-profit transmission company in lieu of handing over control to a
non-profit ISO.
Apart from these efforts to create ISOs, we have received proposals
for other types of transmission entities. For example, in October 1998
a group of Arizona entities filed a request with the Commission to
create an ``independent scheduling administrator'' (ISA) in
Arizona.38 Unlike an ISO, this entity would not administer
its own transmission tariff nor would it have any direct operational
responsibilities
efforts to create ISOs, we have received proposals
for other types of transmission entities. For example, in October 1998
a group of Arizona entities filed a request with the Commission to
create an ``independent scheduling administrator'' (ISA) in
Arizona.38 Unlike an ISO, this entity would not administer
its own transmission tariff nor would it have any direct operational
responsibilities. Instead, it appears that its functions would be
limited to monitoring the scheduling decisions and OASIS site operation
of the Arizona utilities that operate transmission
facilities.39 In case of disputes, the ISA would provide a
type of expedited dispute resolution process. The applicants state that
the ISA would be a transitional organization that would ultimately
evolve or be merged into a stronger, multi-state ISO.40 In
other developments, one public utility has recently made a filing with
us to sell its transmission assets to a newly formed
affiliate.41 Another public utility recently filed a request
for declaratory order asking us to find that its proposal to transfer
its transmission assets (in the form of ownership or a lease) to a
``transco'' in return for a passive ownership interest in the transco,
would satisfy the Commission's eleven ISO principles.42
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\38\ Arizona Independent Scheduling Administrator Association,
Docket No. ER99-388-000 (filed October 29, 1998).
\39\ A proposal for a similar entity has been in the Pacific
Northwest. This entity, described as an independent grid scheduler,
would make actual scheduling decisions rather than simply monitoring
the decisions made by current transmission owners. See Regional ISO
Conference (Portland), transcript at 39-40.
\40\ See Applicant's filing, Docket No. ER99-388-000, at 3.
\41\ FirstEnergy, Inc., Docket No. EC99-53-000 (filed March 19,
1999).
\42\ Entergy Services, Inc., Docket No. EL99-57-000 (filed April
5, 1999)
duler,
would make actual scheduling decisions rather than simply monitoring
the decisions made by current transmission owners. See Regional ISO
Conference (Portland), transcript at 39-40.
\40\ See Applicant's filing, Docket No. ER99-388-000, at 3.
\41\ FirstEnergy, Inc., Docket No. EC99-53-000 (filed March 19,
1999).
\42\ Entergy Services, Inc., Docket No. EL99-57-000 (filed April
5, 1999).
---------------------------------------------------------------------------
As part of general restructuring initiatives, several states now
require independent grid management organizations. For example, an
Illinois law requires that its utilities become members of a FERC-
approved regional ISO by March 31, 1999, and Wisconsin law gives its
utilities the option of joining an ISO or selling their transmission
assets to an independent transmission company by June 30, 2000. In both
states, the backstop is a single-state organization if regional
organizations are not developed. Recently, Virginia and Arkansas have
also enacted legislation requiring their electric utilities to join or
establish regional transmission entities.
3. The Commission's ISO and RTO Inquiries; Conferences with
Stakeholders and State Regulators
In light of the various restructuring activities occurring
throughout the U.S., the Commission has, within the past year, held 11
public conferences in 9 different cities across the country to hear the
views of industry, consumers, and state regulators with respect to the
need for RTOs and their appropriate roles and responsibilities.
The Commission initiated an inquiry in March 1998 pertaining to its
policies on ISOs. A notice establishing procedures for a conference
gave the following rationale:
he past year, held 11
public conferences in 9 different cities across the country to hear the
views of industry, consumers, and state regulators with respect to the
need for RTOs and their appropriate roles and responsibilities.
The Commission initiated an inquiry in March 1998 pertaining to its
policies on ISOs. A notice establishing procedures for a conference
gave the following rationale:
In Order Nos. 888 and 889 and their progeny, the Commission
established the fundamental principles of non-discriminatory open
access transmission services. Nevertheless, many issues remain to be
addressed if the Nation is to fully realize the benefits of open
access and more competitive electric markets.
* * * * *
Given the dramatic changes taking place in both wholesale and
retail electric markets and the many proposals under consideration
with respect to the creation of ISOs or other transmission entities,
such as transmission-only utilities, it is time for the Commission
to take stock of its policies in order to determine whether they
appropriately support our dual goals of eliminating undue
discrimination and promoting competition in electric power
markets.\43\
\43\ Inquiry Concerning the Commission's Policy on Independent
System Operators, Notice of Conference, Docket No. PL98-5-000, at 1-
2 (March 13, 1998).
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Accordingly, the Commission held a series of eight conferences in 1998
to gain insight into participants' views on the formation and role of
ISOs in the electric utility industry. The first conference was held in
April 1998 at the Commission's offices in Washington, D.C. Between May
28 and June 8, 1998, the Commission held seven regional conferences in
Phoenix, Kansas City, New Orleans, Indianapolis, Portland, Richmond and
Orlando
s of eight conferences in 1998
to gain insight into participants' views on the formation and role of
ISOs in the electric utility industry. The first conference was held in
April 1998 at the Commission's offices in Washington, D.C. Between May
28 and June 8, 1998, the Commission held seven regional conferences in
Phoenix, Kansas City, New Orleans, Indianapolis, Portland, Richmond and
Orlando. As a result of these conferences, the Commission heard
approximately 145 oral presentations and received a large number of
written comments on the appropriate size, scope, organization and
functions of regional transmission institutions. A number of different
viewpoints were expressed. They will be discussed elsewhere in this
NOPR and are summarized in Appendix A hereto.
On October 1, 1998, the Secretary of Energy delegated his authority
under section 202(a) of the FPA to the Commission. In doing so the
Secretary stated that section 202(a) ``provides DOE with sufficient
authority to establish boundaries for Independent System Operators
(ISOs) or other appropriate transmission entities.'' \44\ The Secretary
also stated,
\44\ 63 FR 53889 (1998).
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FERC is also increasingly faced with reliability-related issues.
Providing FERC with the authority to establish boundaries for ISOs
or other appropriate transmission entities could aid in the orderly
formation of properly-sized transmission institutions and in
addressing reliability-related issues, thereby increasing the
reliability of the transmission system.
------------------------------
FERC is also increasingly faced with reliability-related issues.
Providing FERC with the authority to establish boundaries for ISOs
or other appropriate transmission entities could aid in the orderly
formation of properly-sized transmission institutions and in
addressing reliability-related issues, thereby increasing the
reliability of the transmission system.
On November 24, 1998, we gave notice in this docket of our intent
to initiate a consultation process with State commissions pursuant to
section 202(a).45 The purpose of the consultations was to
afford State commissions a reasonable opportunity to present their
views with respect to appropriate boundaries for regional transmission
institutions and other issues relating to RTOs. Conferences with State
commissioners were held in St. Louis, Missouri on February 11, 1999; in
Las Vegas, Nevada on February 12, 1999; and in Washington, D.C. on
February 17, 1999. In all, we heard oral presentations by
representatives of 41 state commissions during these consultations,
with others monitoring or providing written comments.46
During these sessions, we received much valuable advice. We have set
forth in Appendix B a summary of the comments received, and discuss in
Section III.B below our response to some of the major concerns
expressed.
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\45\ Notice of Intent to Consult Under Section 202(a), 63 FR
66158 1998*), FERC Stats & Regs. para. 35,534 (1998).
\46\ See Appendix B for a list of commenters.
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C. Statutory Framework
elow our response to some of the major concerns
expressed.
---------------------------------------------------------------------------
\45\ Notice of Intent to Consult Under Section 202(a), 63 FR
66158 1998*), FERC Stats & Regs. para. 35,534 (1998).
\46\ See Appendix B for a list of commenters.
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C. Statutory Framework
The Commission is granted the authority and responsibility by FPA
sections 205 and 206, 16 U.S.C. 824d, 824e, to ensure that the rates,
charges, classifications, and service of public utilities (and any
rule, regulation, practice, or contract affecting any of these) are
just and reasonable and not unduly discriminatory, and to remedy undue
discrimination in the provision of such services. In fulfilling its
responsibilities under FPA sections 205 and 206, the Commission is
required to address, and has the authority to remedy, undue
discrimination and anticompetitive effects. The Commission has a
statutory mandate under these sections to ensure that transmission in
interstate commerce and rates, contracts, and practices affecting
transmission services, do not reflect an undue preference or advantage
(or undue prejudice or disadvantage) and are just, reasonable, and not
unduly discriminatory or preferential.47 Additionally, as
discussed in Order No. 888,48 there is a substantial body of
case law that holds that the Commission's regulatory authority under
the FPA ``clearly carries with it the responsibility to consider, in
appropriate circumstances, the anticompetitive effects of regulated
aspects of interstate utility operations pursuant to [FPA] Secs. 202
and 203, and under like directives contained in Secs. 205, 206, and
207.'' 49
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ission's regulatory authority under
the FPA ``clearly carries with it the responsibility to consider, in
appropriate circumstances, the anticompetitive effects of regulated
aspects of interstate utility operations pursuant to [FPA] Secs. 202
and 203, and under like directives contained in Secs. 205, 206, and
207.'' 49
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\47\ Once such a finding is made, the Commission is required to
remedy it. See, e.g., Southern California Edison Company, 40 FERC
para. 61,371 at 62,151-52 (1987), order on reh'g 50 FERC para.
61,275 at 61,873 (1990), modified sub nom., Cities of Anaheim v.
FERC, 941 F.2d 1234 (D.C. Cir. 1991); Delmarva Power and Light
Company, 24 FERC para. 61,199 at 61,466, order on reh'g 24 FERC
para. 61,380 (1983).
\48\ Order No. 888, FERC Stats. & Regs. at 31,669.
\49\ Gulf States Utilities Co. v. FPC, 411 U.S. 747, 758-59,
reh'g denied, 412 U.S. 944 (1973) (Gulf States). See also City of
Huntingburg v. FPC, 498 F.2d 778, 783-84 (D.C. Cir. 1974)
(Commission has a duty to consider the potential anticompetitive
effects of a proposed Interconnection Agreement.)
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The Commission also has the authority and responsibility under
section 203 of the FPA to review mergers and other transactions
involving public utilities, including dispositions of jurisdictional
facilities by public utilities. This includes public utilities'
transfers of control of jurisdictional transmission facilities to
entities such as RTOs. Under section 203, the Commission must approve a
proposed disposition of jurisdictional facilities if it is consistent
with the public interest. The Commission may grant an application under
section 203 upon such terms and conditions as it finds necessary to
secure the maintenance of adequate service and the coordination in the
public interest of jurisdictional facilities
tities such as RTOs. Under section 203, the Commission must approve a
proposed disposition of jurisdictional facilities if it is consistent
with the public interest. The Commission may grant an application under
section 203 upon such terms and conditions as it finds necessary to
secure the maintenance of adequate service and the coordination in the
public interest of jurisdictional facilities.
Further, section 202(a) of the FPA, whose authority has recently
been delegated to the Commission by the Secretary of
Energy,50 authorizes and directs the Commission ``to divide
the country into regional districts for the voluntary interconnection
and coordination of facilities for the generation, transmission, and
sale of electric energy * * *.'' The purpose of this division into
regional districts is for ``assuring an abundant supply of electric
energy throughout the United States with the greatest possible economy
and with regard to the proper utilization and conservation of natural
resources * * *.'' Section 202(a) states that it is ``the duty of the
Commission to promote and encourage such interconnection and
coordination within each such district and between such districts.''
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\50\ 63 FR 53889 (1998).
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III. Discussion
A. Barriers to Assuring an Abundant Supply of Electric Energy
Throughout the United States with the Greatest Possible Economy
on and
coordination within each such district and between such districts.''
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\50\ 63 FR 53889 (1998).
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III. Discussion
A. Barriers to Assuring an Abundant Supply of Electric Energy
Throughout the United States with the Greatest Possible Economy
In light of our experiences with ISOs and other utility
restructuring activity in the aftermath of Order Nos. 888 and 889, and
after almost three years of experience with implementation of Order
Nos. 888 and 889, we believe that there remain important transmission-
related impediments to a competitive wholesale electric market. We have
grouped these remaining impediments into two broad categories. The
first category of impediments consists of engineering and economic
inefficiencies inherent in the current operation and expansion of the
transmission grid--inefficiencies that, in and of themselves, are
hindering fully competitive power markets and imposing unnecessary
costs on electric consumers. The second category of impediments
consists of continuing opportunities for transmission owners to unduly
discriminate in the operation of their transmission systems so as to
favor their own or their affiliates' power marketing activities. Both
sets of impediments unnecessarily restrict the scope of bulk power
markets and inhibit the large-scale competition that we sought in
issuing Order Nos. 888 and 889.
The situation of the electric industry is somewhat analogous to the
natural gas industry after the initial step of open access
transportation was taken. In 1985, the Commission issued Order No.
436,51 which instituted open-access, nondiscriminatory
transportation of natural gas with the goal of increasing competition
and permitting gas users to purchase gas directly from gas merchants
d 889.
The situation of the electric industry is somewhat analogous to the
natural gas industry after the initial step of open access
transportation was taken. In 1985, the Commission issued Order No.
436,51 which instituted open-access, nondiscriminatory
transportation of natural gas with the goal of increasing competition
and permitting gas users to purchase gas directly from gas merchants.
However, the Commission subsequently found that open access alone was
not sufficient to remove all barriers to competition. 52
Because of the different structures of the electric and gas industries,
the specific remaining impediments to competition may not be the same,
but there are similarities in that open access, without sufficient
mechanisms for ensuring that such access is equal and efficient for all
participants, may not be enough to promote a fully competitive market.
53
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\51\ Regulation of Natural Gas Pipelines After Partial Wellhead
Decontrol, Order No. 436, 50 FR 42408 (Oct. 18, 1985), FERC Stats. &
Regs. [Regulations Preambles 1982-1985] para. 30,665 1985), vacated
and remanded, Associated Gas Distributors v. FERC, 824 F.2d 981
(D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988), readopted on
an interim basis, Order No. 500, 52 FR 30334 (Aug. 14, 1987), FERC
Stats. & Regs. [Regulations Preambles, 1986-1990] para.30,761
control, Order No. 436, 50 FR 42408 (Oct. 18, 1985), FERC Stats. &
Regs. [Regulations Preambles 1982-1985] para. 30,665 1985), vacated
and remanded, Associated Gas Distributors v. FERC, 824 F.2d 981
(D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988), readopted on
an interim basis, Order No. 500, 52 FR 30334 (Aug. 14, 1987), FERC
Stats. & Regs. [Regulations Preambles, 1986-1990] para.30,761
(1987), remanded, American Gas Association v. FERC, 888 F.2d 136
(D.C. Cir. 1989), readopted, Order No. 500-H, 54 FR 52334 (Dec. 21,
1989), FERC Stats. & Regs. [Regulations Preambles 1986-1990] para.
30,867 (1989), reh'g granted in part and denied in part, Order No.
500-I, 55 FR 6605 (Feb. 26, 1990), FERC Stats. & Regs. [Regulations
Preambles 1986-1990] para. 30,880 (1990), aff'd in part and remanded
in part, American Gas Association v. FERC, 912 F.2d 1496 (D.C. Cir.
1990), cert. denied, 111 S. Ct. 957 (1991).
\52\ In the case of natural gas, we found that the principal
remaining barrier was the continued existence of bundled city-gate
firm sales service that had a transportation component of higher
quality than available through open access. Hence, we issued Order
No. 636 to unbundle services and equalize the quality of service
offered. See Pipeline Service Obligations and Revisions to
Regulations Governing Self-Implementing Transportation and
Regulation of Natural Gas Pipelines After Partial Wellhead
Decontrol, 57 FR 13267 (April 16, 1992), III FERC Stats. & Regs.
para. 30,939 (April 8, 1992), reh'g granted and denied in part,
Order No. 636-A, 57 FR 36128 (August 12, 1992), III FERC Stats. &
Regs. para. 30,950 (August 3, 1992), order on reh'g Order No. 636-B,
57 FR 57911 (December 8, 1992), 61 FERC para. 61,272 (1992), Notice
of Denial of Rehearing (January 8, 1993), 62 FERC para. 61,007
Decontrol, 57 FR 13267 (April 16, 1992), III FERC Stats. & Regs.
para. 30,939 (April 8, 1992), reh'g granted and denied in part,
Order No. 636-A, 57 FR 36128 (August 12, 1992), III FERC Stats. &
Regs. para. 30,950 (August 3, 1992), order on reh'g Order No. 636-B,
57 FR 57911 (December 8, 1992), 61 FERC para. 61,272 (1992), Notice
of Denial of Rehearing (January 8, 1993), 62 FERC para. 61,007
(1993), aff'd in part and vacated and remanded in part, United Dist.
Companies v. FERC, 88 F.3d 1105 (D.C. Cir. July 16, 1996), order on
remand, Order No. 636-C, 78 FERC para. 61,186 (1997).
\53\ For a discussion of the similarities and differences in the
structure and regulation of the natural gas and electric industries,
see generally Santa and Sikora, Open Access And Transition Costs:
Will The Electric Industry Transition Track The Natural Gas
Restructuring?, 15 Energy L.J. 273 (1994).
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Our current understanding of industry conditions, as set forth
below, will be enhanced by future consultations with and analysis from
all industry stakeholders, including state commissions. The Commission
seeks comments in order to achieve a deeper
appreciation of any impediments to competition in the Nation's
electricity markets and how they should be addressed.
1. Engineering and Economic Inefficiencies in the Operation, Planning
and Expansion of Regional Transmission Grids
The transmission facilities of any one utility in a region are part
of a larger, integrated transmission system. From an electrical
engineering perspective, each of the three interconnections in the
United States (the Eastern, the Western and ERCOT) operates as a single
``machine.'' 54 The Eastern Interconnection also extends
into Canada, and the Western Interconnection includes parts of Canada
and Mexico.
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d transmission system. From an electrical
engineering perspective, each of the three interconnections in the
United States (the Eastern, the Western and ERCOT) operates as a single
``machine.'' 54 The Eastern Interconnection also extends
into Canada, and the Western Interconnection includes parts of Canada
and Mexico.
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\54\ North American Electric Reliability Council, Electric
Reliability Panel, ``Reliable Power: Renewing the North American
Electric Reliability Oversight System,'' December 1997, at 9.
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Problems have arisen over the last three years, in part, because we
have multiple operators of each of these machines. Each separate
operator usually makes independent decisions about the use, limitations
and expansion of its piece of the interconnected grid based on
incomplete information. This approach--separate operation of each
utility's own transmission facilities--would make engineering sense
only if each system operated independently of the others. But the
physical reality is that, within the three interconnected grids, any
action taken by one transmission provider can have major and
instantaneous effects on the transmission facilities of all other
transmission providers.55
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\55\ U.S. Congress, Office of Technology Assessment, ``Electric
Power Wheeling and Dealing, Technological Considerations for
Increasing Competition,'' May, 1989.
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ous effects on the transmission facilities of all other
transmission providers.55
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\55\ U.S. Congress, Office of Technology Assessment, ``Electric
Power Wheeling and Dealing, Technological Considerations for
Increasing Competition,'' May, 1989.
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This is not a new phenomenon. Since the very first transmission
interconnection between two neighboring utilities, interconnected
utilities have had to cope with the fact that electricity will flow
over others' lines. In the past, these effects were often small or
infrequent and the utility could generally pass any costs through to
captive customers. Today, with the increase in bulk power trade and the
large shifts in power flows, the effects may be large, frequent and not
recoverable by the utility bearing the cost.
Another important change is that the structure of the industry that
exists today is very different from the industry that existed three
years ago when we issued Order No. 888. The industry is no longer
composed uniformly of vertically-integrated, self-sufficient public
utilities that do not compete with each other. Instead, it is an
increasingly de-integrated and decentralized industry with many new and
existing participants that actively compete against each
other.56
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issued Order No. 888. The industry is no longer
composed uniformly of vertically-integrated, self-sufficient public
utilities that do not compete with each other. Instead, it is an
increasingly de-integrated and decentralized industry with many new and
existing participants that actively compete against each
other.56
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\56\ For example, there are now about 550 Commission-approved
power marketers. Decentralization has also increased because of
divestiture of generating plants by traditionally vertically
integrated utilities. Such sales are frequently required by state
governments as one element of the structural reforms that accompany
the introduction of retail competition. During the last three years,
utilities have sold or have contracts to sell more than 50,000 MW of
existing generating capacity. About 30,000 MW of additional capacity
is currently being offered for sale.
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As a consequence of these changes in trade patterns and industry
structure, certain operational problems have become more significant
and more difficult to resolve. These include: maintaining reliable grid
operations; determining available transmission capability (ATC);
57 managing transmission congestion; and planning and
investing in new transmission facilities. In addition, traditional
approaches to the pricing and provision of transmission service may be
hindering the further development of competitive and efficient bulk
power markets. These impediments include: pancaking of transmission
access charges; non-market approaches to managing congestion; the
absence of clear transmission rights; the absence of secondary markets
in transmission service; and the possible disincentives created by the
level and structure of transmission rates
e may be
hindering the further development of competitive and efficient bulk
power markets. These impediments include: pancaking of transmission
access charges; non-market approaches to managing congestion; the
absence of clear transmission rights; the absence of secondary markets
in transmission service; and the possible disincentives created by the
level and structure of transmission rates. The Commission believes that
properly structured RTOs can address both sets of problems and further
the development of competitive bulk power markets.
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\57\ See definition of ATC infra.
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a. Reliable Grid Operations
The United States has one of the most reliable power systems in the
world. For over thirty years, NERC and the regional reliability
councils have developed and implemented voluntary standards to maintain
the security of the transmission systems. There is no net public policy
benefit to promoting competition if reliability suffers as a
consequence.58 The promotion of competition must therefore
go hand-in-hand with the creation of new institutions to ensure that
reliability is maintained or improved in any new industry
structure.59 We fully agree with the findings of the DOE
Reliability Task Force:
\58\ Unless otherwise noted, we use the term ``reliability'' to
refer to the reliable or secure operation of the bulk power grid.
This is one component of the broader NERC definition, which also
includes ``adequacy'' (i.e., sufficient generation and transmission
capacity) as a second component of overall reliability. See North
American Electric Reliability Council, ``Glossary of Terms,'' August
1996, at 21.
\59\ See George C. Loehr, ``Ten Myths About Electric
Deregulation: Electrons May Seem Imaginary, But Reliability Is
Real,'' Public Utilities Fortnightly, April 15, 1998, at 28-31
includes ``adequacy'' (i.e., sufficient generation and transmission
capacity) as a second component of overall reliability. See North
American Electric Reliability Council, ``Glossary of Terms,'' August
1996, at 21.
\59\ See George C. Loehr, ``Ten Myths About Electric
Deregulation: Electrons May Seem Imaginary, But Reliability Is
Real,'' Public Utilities Fortnightly, April 15, 1998, at 28-31.
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* * * there is a critical need to be sure that reliability is not
taken for granted as the industry restructures, and thus does not
``fall through the cracks.'' 60
\60\ DOE Task Force Report, at xv.
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The DOE Reliability Task Force also pointed out that with the entry
of many new participants, dramatic increases in unbundled power sales
and shifts in electrical flows, the nation's bulk power system is being
stressed in ways that have never been experienced before. A similar
conclusion was reached by NERC in its 1998 summer assessment of bulk
power reliability:
Throughout the Regions, parallel path flows from increased
electricity transfers are stressing the transmission systems. These
flows are at magnitudes and in directions not anticipated at the
time the systems were designed.* * *The transmission system will be
required to operate under unprecedented, and sometimes unstudied,
conditions.61
\61\ NERC, ``1998 Summer Assessment: Reliability of Bulk
Electricity Supply in North America,'' May 1998, at 2-3.
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e at magnitudes and in directions not anticipated at the
time the systems were designed.* * *The transmission system will be
required to operate under unprecedented, and sometimes unstudied,
conditions.61
\61\ NERC, ``1998 Summer Assessment: Reliability of Bulk
Electricity Supply in North America,'' May 1998, at 2-3.
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These stresses have always existed but not in these magnitudes.
Moreover, they could be more readily accommodated through voluntary ad
hoc agreements when there were fewer industry participants who
generally did not compete against each other in any significant
way.62 But as we have noted, this traditional industry
structure is rapidly disappearing. Our concern is that the reliability
fault lines may become more prominent and dangerous.
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\62\ In assessing the continued viability of the current system,
NERC's blue-ribbon Electric Reliability Panel concluded that: ``The
competitive dynamics among a much larger universe of players is not
at all conducive to a system of voluntary peer compliance.''
Electric Reliability Panel Report, December 1997, at 28.
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It is well accepted that the operation of interconnected
transmission networks requires careful coordination and the exchange of
information between many individual systems. Any operational change on
one system in the network instantly affects other systems. For example,
the shipment of power from one location to another will divide among
all transmission paths from source to destination based on the laws of
physics.63 This is referred to as
ected
transmission networks requires careful coordination and the exchange of
information between many individual systems. Any operational change on
one system in the network instantly affects other systems. For example,
the shipment of power from one location to another will divide among
all transmission paths from source to destination based on the laws of
physics.63 This is referred to as
parallel path or loop flow. Such flows will also affect a neighboring
system's ability to determine ATC accurately. In addition, if a
transmission facility is already loaded close to its operating limit,
the additional flow resulting from a transaction contracted for on a
neighboring system may overload the facility and threaten reliability.
In order to operate the system in a reliable manner, a single,
independent grid operator must know all sources and destinations for
each transaction. The Commission believes that an RTO, as the only
transmission provider and security coordinator in its region, would
have the information needed to identify the effects of parallel flows
and accommodate them in its operations.
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\63\ The amount of power flowing on any path in an electrical
network is inversely proportional to that path's impedance.
Impedance will depend on the actual length of the line and its
voltage. See U.S. Congress, Office of Technology Assessment,
Electric Power Wheeling and Dealing: Technological Considerations
for Increasing Competition, OTA-E-409, May 1989, at 110-11.
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lectrical
network is inversely proportional to that path's impedance.
Impedance will depend on the actual length of the line and its
voltage. See U.S. Congress, Office of Technology Assessment,
Electric Power Wheeling and Dealing: Technological Considerations
for Increasing Competition, OTA-E-409, May 1989, at 110-11.
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At present, the industry's ability to maintain reliable grid
operation is hindered by the existence of many separate organizations
that directly or indirectly affect the operation and expansion of the
grid. There are more than 100 owners of the Nation's grid who operate
about 140 separate control areas.64 In addition, there are
10 regional reliability councils, 23 security coordinators, 5 regional
transmission groups (RTGs) and 5 independent system operators. With so
many entities, the lines of authority and communication are not always
as clear as they should be.65 An additional complication is
that many of these entities also own generation or have a decision
making process that continues to be dominated by traditional vertically
integrated utilities.66 Therefore, their independence and
commercial neutrality as grid operators is subject to question.
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\64\ A control area is an electrical system bounded by
interconnection (tie-line) metering and telemetry. Within a control
area, resources are balanced against load, and generation is
regulated to maintain interchange schedules with other control areas
and to achieve the target frequency (60 hz) for the entire
Interconnection. See NERC Operating Policies Manual (available on
the NERC website at www.nerc.com).
\65\ See, e.g., Western Systems Coordinating Council, EL99-23-
000, comments of Enron Power Marketing, Inc. at 4-5.
\66\ See, e.g., New England Power Pool, 86 FERC para. 61,262 at
61,965 (1999)
hange schedules with other control areas
and to achieve the target frequency (60 hz) for the entire
Interconnection. See NERC Operating Policies Manual (available on
the NERC website at www.nerc.com).
\65\ See, e.g., Western Systems Coordinating Council, EL99-23-
000, comments of Enron Power Marketing, Inc. at 4-5.
\66\ See, e.g., New England Power Pool, 86 FERC para. 61,262 at
61,965 (1999).
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It appears that information that is critical for maintaining
reliability is not being shared as readily now as was generally the
case in the past. NERC recently observed that there is a growing
``reluctance on the part of the market participants to share
operational real-time and operational planning data with TPs
[transmission providers].'' 67 This is not surprising
because, as we have noted before, information that is needed for
reliability purposes may also have a commercial value.68 If
market participants believe that the entity that receives operational
information for reliability reasons may use it for commercial
advantage, they will understandably be reluctant to supply the
information. After spending more than 18 months reviewing the current
reliability system, the DOE Reliability Task Force concluded that this
inherited system, with its patchwork of organizations, inadequate
information sharing and overlapping and sometimes unclear
responsibilities, is ``clearly unsustainable'' and that until new
policies and institutions are in place, ``substantial parts of North
America will be exposed to unacceptable risk.'' 69
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\67\ NERC, Reliability Assessment 1998-2007 at 39 (1998).
\68\ Midwest ISO, 84 FERC at 62, 158-159.
\69\ DOE Task Force Report at vii and xi.
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tutions are in place, ``substantial parts of North
America will be exposed to unacceptable risk.'' 69
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\67\ NERC, Reliability Assessment 1998-2007 at 39 (1998).
\68\ Midwest ISO, 84 FERC at 62, 158-159.
\69\ DOE Task Force Report at vii and xi.
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This is not just a theoretical concern. During last year's regional
ISO conferences, several industry participants described three
``reliability near misses'' in the Midwest. The three incidents on July
22, 1993, August 7, 1996 and July 11, 1997 came very close to producing
major outages throughout the Midwest.70 While there has been
some improvement in coordination among different systems, we believe
that there are limits to the amount of coordination that can be
achieved between separate organizations, especially if they are
competing for the right to use the same limited transmission capacity
and sometimes competing for the same customers. While competition
requires decentralization, we think that reliable and efficient grid
operation requires more coordination. The Commission believes that a
beneficial platform for both competition and reliability is a single
independent grid operator that sees the ``big picture'' by having
access to real-time information on conditions and schedules for the
entire regional grid.71 Such an entity does not exist in
several regions of the country. As a consequence, there is, at present,
a disconnect between electrical flows and information flows that could
have major reliability consequences.
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re'' by having
access to real-time information on conditions and schedules for the
entire regional grid.71 Such an entity does not exist in
several regions of the country. As a consequence, there is, at present,
a disconnect between electrical flows and information flows that could
have major reliability consequences.
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\70\ Regional ISO Conference (Indianapolis), transcript at 24-
29.
\71\ The importance of a single operator for reliability was
stressed in comments of AMEREN and Commonwealth Edison. See Regional
ISO Conference (Indianapolis), transcript at 19-29.
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b. Determining Available Transmission Capability (ATC)
Any transportation service provider should know how much commodity
it can carry. For electric transmission service providers, the
calculations of total transmission capability (TTC) and ATC are needed
to make this determination. TTC and ATC are key elements of the OASIS
information system.72 Order No. 889 requires each
transmission provider to calculate and post TTC and ATC numbers to give
its transmission customers a reasonable estimate of how much power can
be carried between any two locations on the grid and how much capacity
is available to support additional trade at any given time.
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\72\ ATC is a measure of transfer capability remaining in the
physical transmission network for further commercial activity over
and above already committed uses. TTC is the amount of electric
power that can be transferred over the interconnected transmission
network in a reliable manner based on certain specified conditions,
North American Reliability Council, Glossary of Terms (1996).
---------------------------------------------------------------------------
l transmission network for further commercial activity over
and above already committed uses. TTC is the amount of electric
power that can be transferred over the interconnected transmission
network in a reliable manner based on certain specified conditions,
North American Reliability Council, Glossary of Terms (1996).
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We have received many complaints about the accuracy and usefulness
of posted ATC numbers. There are several reasons why it is difficult to
determine available transmission capability accurately.
First, ATC numbers are still calculated on an individual company
basis in many areas of the country. Separate calculations of ATC by
individual companies are fundamentally inconsistent with the physical
reality of an interconnected transmission system. An individual
transmission provider may post ATC numbers in good faith, and attempt
to provide transmission service based on these numbers, only to learn
later that the transfer capability that it thought was available no
longer exists because of decisions made by other transmission providers
that it did not know about at the time it made its calculations.
Accurate ATC numbers would require reliable and timely information
about load, generation, facility outages and transactions on
neighboring systems. Individual transmission operators will generally
not have this information. They also may apply differing assumptions
and criteria to ATC calculations, which may produce wide variations in
posted ATC values for the same transmission path.73 All
these considerations make it virtually impossible for an individual
transmission provider that operates one
part of a large interconnected grid to calculate ATC
accurately.74
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ring assumptions
and criteria to ATC calculations, which may produce wide variations in
posted ATC values for the same transmission path.73 All
these considerations make it virtually impossible for an individual
transmission provider that operates one
part of a large interconnected grid to calculate ATC
accurately.74
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\73\ This, in turn, creates other problems. According to NERC,
the ``inconsistent calculation [of ATC] can increase the use of TLR
and other operational complexities, which has the potential to cause
reliability problems.'' NERC, Reliability Assessment, 1998-2007,
September, 1998, at 40. (See definition of TLR in section II.)
\74\ In addition, it has been frequently alleged that individual
transmission may intentionally post inaccurate ATC numbers to favor
their own power marketing efforts. These allegations are discussed
in section III.A.2.
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Second, requests for transmission service are usually based on
``contract path'' scheduling. This is the practice of finding a
contiguous chain of utilities from the power supplier to the power
consumer and contracting with those utilities to transmit the power.
The implicit assumption is that all the power flows through the
utilities along this ``contract path.'' In fact, the power divides up
and flows along all paths from the supplier to the buyer. All utilities
in the region are affected
The
constraints may reflect voltage, temperature and dynamic limits.
Relieving congestion leads to a more costly pattern of generation
dispatch. The cost of congestion is the additional energy cost
associated with the new pattern of dispatch.
We recognize that even optimally designed systems will normally
experience at least occasional congestion that at times can be
significant and costly. In general, congestion can be managed in two
ways: the construction of new transmission facilities that increase
grid capacity; or the redispatch of existing or new generators to
reduce flows or create counterflows on the constrained facility. The
complete elimination of congestion would typically require the
construction of new transmission facilities. While this may be a
physically effective solution, it may not always be cost effective.
Because of this, we believe that an efficiently operated transmission
system should have in place mechanisms for pricing congestion and then
managing congestion through changes in the pattern of dispatch. Without
mechanisms for determining the cost of congestion, it will be virtually
impossible to make rational, cost effective decisions to expand the
grid.
The Commission believes that efficient congestion management is
best performed at the regional level. At present, outside of the
operational ISOs, transaction curtailment through transmission loading
relief (TLR) procedures is the dominant approach for dealing with
congestion in the Eastern Interconnection. NERC has reported that its
TLR procedures were invoked 329 times between July 1997 and October
1998 on the Eastern Interconnection.78 Current TLR
procedures are cumbersome, inefficient and disruptive to bulk power
markets because they rely exclusively on physical measures of flows
with no attempt to assess the relative costs of different congestion
management options. Moreover, TLR actions are typically taken by one
utility without assessing the costs imposed on other grid users
tober
1998 on the Eastern Interconnection.78 Current TLR
procedures are cumbersome, inefficient and disruptive to bulk power
markets because they rely exclusively on physical measures of flows
with no attempt to assess the relative costs of different congestion
management options. Moreover, TLR actions are typically taken by one
utility without assessing the costs imposed on other grid users. This
inevitably raises the suspicion that the TLR request could be motivated
by competitive rather than reliability concerns. For these reasons, the
Commission has encouraged NERC to develop regional market approaches to
managing congestion.79
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\78\ North American Electricity Reliability Council, Interim
Market Interface Committee, Minutes of Jan. 12 and 13, 1999 meeting,
Exhibit D.
\79\ See NERC, 85 FERC at 62,364.
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The Commission recognizes, however, that NERC may not be able to
comply fully with this policy in the absence of regional organizations
that have the authority and ability to promote regional congestion
markets. There are three considerations that support this conclusion.
First, a regional organization would have accurate and reliable
information about existing and possible future conditions on the grid.
Such information is generally not available to individual transmission
providers. RTOs would have this information because they would function
as both regional security coordinators and regional transmission
providers.
Second, congestion management is best performed at a regional
level. This is shown in the largely unsuccessful efforts of
Commonwealth Edison to create congestion markets that would allow
transmission customers to ``buy-through'' (i.e., firm up) transmission
rights on congested flow gates
because they would function
as both regional security coordinators and regional transmission
providers.
Second, congestion management is best performed at a regional
level. This is shown in the largely unsuccessful efforts of
Commonwealth Edison to create congestion markets that would allow
transmission customers to ``buy-through'' (i.e., firm up) transmission
rights on congested flow gates. After six months of its one year
experiment, we note that Commonwealth concluded that it is ``difficult
for one transmission owner to identify and implement redispatch'' when
the physical limitations and cost effective options for relief exist on
other transmission systems that are beyond their reach.80
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\80\ Commonwealth Edison, Interim Report on Non-Firm Redispatch,
Docket No. ER98-2279, December 17, 1998, at 4, 10.
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Third, RTOs will be able to establish and define rights to the use
of the grid. At present, with multiple and independent operators of the
grid, individual users and owners have unclear and conflicting rights
to the grid. This makes it difficult to establish congestion markets. A
congestion market, like any other market, cannot develop in the absence
of clear rights.\81\ Such rights, whether held by transmission users or
owners, are a necessary prerequisite for establishing congestion
markets. Without establishing such rights, the industry will continue
to grapple with the problem of incomplete markets. Thus, it is
difficult to achieve efficient and competitive regional bulk power
markets if congestion on the transmission grid is not accurately
priced.
---------------------------------------------------------------------------
ssary prerequisite for establishing congestion
markets. Without establishing such rights, the industry will continue
to grapple with the problem of incomplete markets. Thus, it is
difficult to achieve efficient and competitive regional bulk power
markets if congestion on the transmission grid is not accurately
priced.
---------------------------------------------------------------------------
\81\ Robert Cooter and Thomas Ulen, Law and Economics, Scott,
Foresman and Company, 1988, at 91 (``From a legal viewpoint,
property is a bundle of rights'').
---------------------------------------------------------------------------
d. Planning and Expanding Transmission Facilities
Transmission planning and expansion are more difficult today than
three years ago. While uncertainty has always been a fact of life for
any transmission planning exercise, the level of uncertainty has
increased with the increasing number and distance of unbundled
transactions and the wider variation in generation dispatch patterns.
Uncertainty has also increased because:
Generation developers are reluctant to disclose their plans for
future capacity additions. Similarly, utilities intending to
purchase from others are reluctant to speculate on whom or where
their suppliers might be, making modeling of such transactions for
transmission analysis virtually impossible.\82\
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\82\ NERC, ``Reliability Assessment, 1998-2007,'' September
1998, at 39.
One troubling consequence of this uncertainty has been a noticeable
decline in planned transmission investments. NERC recently reported
that the level of planned transmission
such transactions for
transmission analysis virtually impossible.\82\
---------------------------------------------------------------------------
\82\ NERC, ``Reliability Assessment, 1998-2007,'' September
1998, at 39.
One troubling consequence of this uncertainty has been a noticeable
decline in planned transmission investments. NERC recently reported
that the level of planned transmission
additions is significantly lower than five years ago despite an overall
increase in load growth and unbundled transmission service.\83\ While
this could simply reflect better utilization of the existing grid, the
Commission is concerned that it may also reflect an incompatibility of
existing planning institutions with the new market realities.
---------------------------------------------------------------------------
\83\ Id. at 7.
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We are also concerned that the existing approach to transmission
pricing may not sufficiently encourage the investments in transmission
facilities that are needed to improve the reliability and efficiency of
the grid. Inadequate investment could be a major impediment to the
development of regional bulk power markets and a possible source of
future reliability problems. There are at least three concerns about
the way transmission prices are set.
First, although there are varying degrees of investment
coordination around the country, utilities ultimately make transmission
investment decisions individually rather than through joint decisions
that internalize commercial and reliability effects of the investment.
It may be unclear which utility should have the responsibility for
expanding capacity to relieve a transmission constraint. For example,
power flows scheduled by one utility with ample transmission capacity
on its own lines may overload a neighbor's lines
nvestment decisions individually rather than through joint decisions
that internalize commercial and reliability effects of the investment.
It may be unclear which utility should have the responsibility for
expanding capacity to relieve a transmission constraint. For example,
power flows scheduled by one utility with ample transmission capacity
on its own lines may overload a neighbor's lines. The first utility may
be unwilling to expand transmission capacity because it needs no extra
transmission capacity itself, and the second utility may be unwilling
to expand transmission capacity because it collects no revenues from
the power flows scheduled by others. In a multi-utility region,
decisions about where to site new facilities and who should pay for
capacity expansions can be even more complex unless a regional body
provides a forum for discussions and a method for resolving disputes.
Second, the motivation for constructing new facilities is changing
as the industry changes. Formerly, a utility built transmission
primarily to deliver power from its generating plants to its customers.
Inadequate transmission would have hurt power sales, the principal
source of utility revenue. Today, facility expansion may be needed to
transmit power sold by others. As generation and transmission ownership
become increasingly separate and as many states implement or even
merely consider retail access, the transmission owner's traditional
incentive for making new transmission investment to support its power
sales erodes. Incentives for transmission investment need to be related
more to the power needs of the region than the generation stock of the
transmission owners.
Third, the transmission owner that does invest in transmission to
overcome a constraint may be concerned about recovering its investment.
Under traditional ratemaking practices, it must recover its investment
over a long period of time, typically thirty years
transmission investment need to be related
more to the power needs of the region than the generation stock of the
transmission owners.
Third, the transmission owner that does invest in transmission to
overcome a constraint may be concerned about recovering its investment.
Under traditional ratemaking practices, it must recover its investment
over a long period of time, typically thirty years. But subsequent
generation construction on the power-poor side of the constraint may
obviate the need for the line and threaten recovery of its capital
cost. In addition, where there is higher risk, a higher return
commensurate with the higher risk may be appropriate. To support this,
customers and regulators would want assurance that the decision to
invest in transmission is made in the best interests of the region,
considering not only all the transmission options but also the
generation and demand management alternatives to transmission
construction. Therefore, as discussed below, we will consider concrete
proposals from regional transmission organizations for transmission
pricing reforms and the explicit use of pricing incentives to encourage
RTOs to make efficient investments in new transmission facilities.
e. Pancaked Transmission Rates
With the exception of power pools, open access under Order No. 888
focuses on individual, existing transmission providers. Order No. 888
does not require transmission pricing reforms that are needed to
support efficient and competitive bulk power markets. The ``missing''
reforms include, among others, the elimination of pancaked transmission
access charges, the use of reservation-based (as opposed to load-based)
transmission tariffs and the availability of secondary markets in
transmission rights.84 In this section, we will focus on the
problems created by the widespread pancaking of transmission access
charges.85
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the elimination of pancaked transmission
access charges, the use of reservation-based (as opposed to load-based)
transmission tariffs and the availability of secondary markets in
transmission rights.84 In this section, we will focus on the
problems created by the widespread pancaking of transmission access
charges.85
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\84\ See, e.g., Capacity Reservation Open Access Transmission
Tariffs, Notice of Proposed Rulemaking, FERC Stats. and Regs. para.
32,519 (1996) and Inquiry Concerning the Commission's Pricing Policy
for Transmission Services Provided by Public Utilities Under the
Federal Power Act: Policy Statement, 69 FERC para. 61,086 (1994).
\85\ We did, however, require non-pancaked rates for power pools
that offer non-pancaked rates to their own members in Order No. 888.
Order No. 888, FERC Stats, and Regs. at 31,727-28.
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In most of the United States, a transmission customer pays
separate, additive access charges every time its contract path crosses
the boundary of a transmission owner. By raising the cost of
transmission, pancaking reduces the size of geographic power markets.
This, in turn, can result in concentrated electricity markets.
Balkanization of electricity markets hurts electricity consumers, in
general, by forcing them to pay higher prices than they would in a
larger, more competitive, bulk power market.86
---------------------------------------------------------------------------
of
transmission, pancaking reduces the size of geographic power markets.
This, in turn, can result in concentrated electricity markets.
Balkanization of electricity markets hurts electricity consumers, in
general, by forcing them to pay higher prices than they would in a
larger, more competitive, bulk power market.86
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\86\ While it is difficult to estimate the exact impact on
consumers, we note that there have been studies of the deregulated
British power markets that have found excessive concentration in
generation has produced prices 20 to 40 percent above competitive
levels at certain times. Richard Green and David Newbery,
Competition in the British Electricity Spot Market, 100 J. Pol.
Econ., 929, 1992.
---------------------------------------------------------------------------
The Commission has heard from many states about the negative
effects of pancaked rates in their efforts to introduce retail
competition. At this time, about 21 states have introduced or are
planning to introduce competition for retail loads under their
jurisdiction.87 Because the Commission has jurisdiction over
transmission service and rates for unbundled retail customers, we have
an obligation to address these concerns.88 A retail choice
initiative, no matter how well designed at the state level, may fail if
the pool of potential competitors is effectively limited to a few
nearby supply sources because of pancaked transmission charges.
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\87\ ``Status of Electric Utility Deregulation as of May 1,
1999,'' Energy Information Administration.
\88\ Order No. 888, FERC Stats. and Regs. at 31,651-52.
---------------------------------------------------------------------------
ely limited to a few
nearby supply sources because of pancaked transmission charges.
---------------------------------------------------------------------------
\87\ ``Status of Electric Utility Deregulation as of May 1,
1999,'' Energy Information Administration.
\88\ Order No. 888, FERC Stats. and Regs. at 31,651-52.
---------------------------------------------------------------------------
This concern of pancaked rates was highlighted to us in the recent
consultations with our state commission colleagues. Several state
commissioners emphasized that the success of their retail competition
initiatives is related to the adoption of non-pancaked transmission
tariffs and other ISO policies.89 We believe that the
likelihood of success for existing and planned retail choice
initiatives is significantly enhanced if the Commission can ensure fair
and efficient access to a regional market without pancaked transmission
access charges, and that we need to take steps beyond Order No. 888 to
accomplish this.
---------------------------------------------------------------------------
\89\ See, e.g., Comments of Gerald Thorpe (Maryland) and
President Herbert Tate (New Jersey), RTO Conference (Washington,
DC), transcript at 37-39; 49-51.
---------------------------------------------------------------------------
f. Conclusion
We believe that the preferred solution to the engineering and
economic problems discussed in this section is a regional solution.
Notwithstanding it success, Order No. 888 has not been able to produce
a fully efficient and competitive outcome because it does not address
ATC calculations, congestion
-51.
---------------------------------------------------------------------------
f. Conclusion
We believe that the preferred solution to the engineering and
economic problems discussed in this section is a regional solution.
Notwithstanding it success, Order No. 888 has not been able to produce
a fully efficient and competitive outcome because it does not address
ATC calculations, congestion
management, reliability, pancaking of transmission access charges, and
grid planning and expansion. These are regional problems. Therefore, we
are proposing a rule to encourage the development of independent
regional transmission operators that can promote both electric system
reliability and competitive generation markets.
2. Actual and Perceived Discriminatory Conduct by Transmission Owners
to Favor Their Own or Affiliated Merchant Operations
In addition to operational inefficiencies impeding full
competition, there also exist questions about residual discrimination
in the provision of transmission services by public utilities. As
discussed below, many in the industry have expressed a fundamental
mistrust of transmission owners. In addition, there are allegations,
and in some circumstances findings, of actual discrimination by
transmission owners. We discuss below indications of discriminatory
conduct by vertically integrated utilities and seek further comment on
utility practices subsequent to Order No. 888.
Utilities that control monopoly transmission facilities and also
have power marketing interests 90 have poor incentives to
provide equal quality transmission service to their power marketing
competitors. It is, in fact, in the economic self-interest of
transmission-owning utilities to favor their own power marketing
interests and frustrate their competitors. As the Commission stated in
Order No. 888:
that control monopoly transmission facilities and also
have power marketing interests 90 have poor incentives to
provide equal quality transmission service to their power marketing
competitors. It is, in fact, in the economic self-interest of
transmission-owning utilities to favor their own power marketing
interests and frustrate their competitors. As the Commission stated in
Order No. 888:
\90\ The term power marketing interests is used as shorthand
herein to include the utility's own wholesale merchant function as
well as any affiliates with wholesale merchant functions.
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It is in the economic self-interest of transmission monopolists,
particularly those with high-cost generation assets, to deny
transmission or to offer transmission on a basis that is inferior to
that which they provide themselves. The inherent characteristics of
monopolists make it inevitable that they will act in their own self-
interest to the detriment of others by refusing transmission and/or
providing inferior transmission to competitors in the bulk power
markets to favor their own generation, and it is our duty to
eradicate unduly discriminatory practices.\91\
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\91\ Order No. 888, FERC Stats. and Regs. at 31,682.
The exercise of transmission market power allows transmission providers
with power marketing interests to benefit in the short-run by making
more power sales at higher prices, and benefit in the long-run by
deterring entry by other market participants. As a result, prices to
the Nation's electricity consumers will be higher than need be.
It was to eliminate this inherent tendency of a vertically-
integrated utility to favor its own power sales that Order Nos. 888 and
889 required utilities to functionally unbundle their transmission and
power merchant services
ces, and benefit in the long-run by
deterring entry by other market participants. As a result, prices to
the Nation's electricity consumers will be higher than need be.
It was to eliminate this inherent tendency of a vertically-
integrated utility to favor its own power sales that Order Nos. 888 and
889 required utilities to functionally unbundle their transmission and
power merchant services. Generally, functional unbundling requires a
public utility to: separate its transmission system functions and staff
from wholesale generation marketing functions and staff; abide by a
standard of conduct to define impermissible contact between generation
and transmission personnel; take transmission services under the same
open access tariff of general applicability as do others; state
separate rates for wholesale generation, transmission, and ancillary
services; and rely on the same Open Access Same-Time Information System
(OASIS) that its transmission customers rely on to obtain information
about its transmission system when buying or selling
power.92 The Commission imposed these requirements to
establish a foundation for open grid access and competitive electricity
markets.
---------------------------------------------------------------------------
\92\ Id. at 31,654-55.
---------------------------------------------------------------------------
Functional unbundling did not change the incentives of vertically-
integrated utilities to use their transmission assets to favor their
own generation, but instead attempted to reduce the ability of
utilities to act on those incentives. In Order No. 888, the Commission
received and considered numerous comments that functional unbundling
was unlikely to work, and that more drastic restructuring, such as
corporate unbundling, was needed.\93\ However, the Commission decided
at the time to adopt what it considered to be the less intrusive and
less costly remedy.
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No. 888, the Commission
received and considered numerous comments that functional unbundling
was unlikely to work, and that more drastic restructuring, such as
corporate unbundling, was needed.\93\ However, the Commission decided
at the time to adopt what it considered to be the less intrusive and
less costly remedy.
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\93\ Id. at 31,653-54.
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Clearly, Order No. 888 has resulted in wholesale power markets
becoming more competitive, more transmission services being made
available to more potential users than ever before, and generally lower
transaction costs.
However, market participants increasingly have alleged that
numerous transmission service problems related to discriminatory
conduct remain, and that these problems are impeding competitive
wholesale power markets.\94\ Our information about alleged continued
discriminatory practices comes from several sources. These include
formal complaints filed with the Commission, informal complaints made
to the Commission's enforcement hotline, oral and written comments made
in conjunction with public conferences held by the Commission, and
pleadings filed with the Commission in various dockets.
---------------------------------------------------------------------------
\94\ See, e.g., of Roger Fontes on behalf of the Northern
California Power Agency, Regional ISO Conference (Phoenix),
Transcript at 136 (``In general, orders 888 and 889 have not fully
remedied undue discrimination in providing transmission service in
this country.'')
---------------------------------------------------------------------------
-------------------------------------------------
\94\ See, e.g., of Roger Fontes on behalf of the Northern
California Power Agency, Regional ISO Conference (Phoenix),
Transcript at 136 (``In general, orders 888 and 889 have not fully
remedied undue discrimination in providing transmission service in
this country.'')
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Compared to the situation before Order No. 888, transmission-owning
utilities must now resort to more subtle means to frustrate their
marketing competitors and favor their own marketing interests.
Continued discrimination may be conscious and deliberate, but it may
also result from the failure to make sufficient efforts to change the
way integrated utilities have done business for many years. In either
case, the tendency of transmission owners to confer advantages, however
subtle, upon their own marketing interests is discriminatory as against
other marketers.
In the sections that follow, we will outline the information
derived from filings and other sources about remaining impediments to
competition caused by continued discriminatory conduct by transmission
owners. We note, and we are well aware, that many allegations that have
been made in various forums are unproved, and perceived discrimination
may in fact turn out to have justifiable explanations. It is often hard
to determine, on an after-the-fact basis, whether an action was
motivated by an intent to favor affiliates or simply resulted from the
need to serve native load customers or the impartial application of
operating or technical requirements. Given our considerable difficulty
in determining whether there has been compliance with our regulations,
the question arises whether functional unbundling is an appropriate
long-term regulatory solution.
We consider allegations of discrimination, even if not reduced to
formal findings, to be a serious concern for two reasons
r the impartial application of
operating or technical requirements. Given our considerable difficulty
in determining whether there has been compliance with our regulations,
the question arises whether functional unbundling is an appropriate
long-term regulatory solution.
We consider allegations of discrimination, even if not reduced to
formal findings, to be a serious concern for two reasons. First, we may
be seeing only the ``tip of the iceberg.'' We are aware that instances
of actual discriminatory conduct may be undetectable in a non-
transparent market. In addition, there are significant disincentives to
filing and pursuing formal complaints that would result in definitive
findings. Transmission customers often tell the Commission's
enforcement staff that they are reluctant to make even informal
complaints because of concerns that the Commission will not take strong
action, and fear, perhaps most importantly, of retribution by their
transmission supplier.95 We also have been told that
the complaint process is costly and time-consuming,96 and
that the Commission's remedies for transmission violations do not
impose sufficient financial harms on the transmission provider to act
as a significant deterrent.97
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\95\ See Comments of Dan Jones on behalf of the Public Utilities
Commission of Texas, Regional ISO Conference (Kansas City),
Transcript at 1985 (``And we've also heard that these entities are
hesitant to bring those complaints forward because they have to deal
with both sides of that utility'').
\96\ We note that we have recently issued a Final Rule regarding
complaint procedures designed to make them more efficient. See
Complaint Procedures, Final Rule, Docket No. RM98-13-000, 86 FERC
para. 61,324 (issued March 31, 1999).
\97\ Comments of National Energy Marketers Association, Docket
No. RM98-5-000 (filed January 22, 1999).
---------------------------------------------------------------------------
t we have recently issued a Final Rule regarding
complaint procedures designed to make them more efficient. See
Complaint Procedures, Final Rule, Docket No. RM98-13-000, 86 FERC
para. 61,324 (issued March 31, 1999).
\97\ Comments of National Energy Marketers Association, Docket
No. RM98-5-000 (filed January 22, 1999).
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Perhaps the most problematic aspect of relying on after-the-fact
enforcement in the fast-paced business of power marketing, however, is
that there may be no adequate remedy for lost short-term sale
opportunities. For example, the Electric Power Supply Association has
told us:
Furthermore, even if the exercise of such discrimination could
be adequately documented and packaged in the form of a complaint
under Section 206 of the Federal Power Act under a more streamlined
complaint process contemplated by the Commission, it would still be
extremely costly and inefficient to deal with such complaints on a
case-by-case basis. More than likely, the potential power
transactions for which transmission principally was sought would
disappear by the time a Commission ruling was obtained.98
\98\ Motion to Intervene and Comments of Electric Power Supply
Association in Support of Petition for Rulemaking, Docket No. RM98-
5-000 (filed Sept. 21, 1998), at 3.
Accordingly, actual problems with functional unbundling may be more
pervasive than formally adjudicated complaints would suggest, and the
informal allegations we hear provide valuable insight.
Second, we consider the allegations of discrimination to be serious
because, if nothing else, they represent a perception by market
participants that the market is not working fairly because such
participants know that integrated utilities have the incentive and
opportunity to discriminate. Mistrust in the market can itself be a
serious impediment to competition
ear provide valuable insight.
Second, we consider the allegations of discrimination to be serious
because, if nothing else, they represent a perception by market
participants that the market is not working fairly because such
participants know that integrated utilities have the incentive and
opportunity to discriminate. Mistrust in the market can itself be a
serious impediment to competition. If market participants perceive that
other participants have an unfair advantage through the affiliation
with the transmission provider, it can inhibit their willingness to
participate in the market, including, for example, building new
generating units, thus thwarting the development of robust competition.
Such mistrust can also harm reliability. As stated by NERC, there is a
reluctance on the part of market participants to share operational
real-time and planning data with transmission providers because of the
suspicion that they could be providing an advantage to their affiliated
marketing groups.99
---------------------------------------------------------------------------
\99\ NERC Reliability Assessment 1998-2007, at 39.
---------------------------------------------------------------------------
The functional unbundling policy underlying Order No. 888 was an
attempt to regulate the behavior of transmission owners. There are
growing indications, however, that the conflicting incentives that
vertically integrated utilities have regarding transmission access may
be too difficult to police. Many have asserted that it is not realistic
even to expect functional unbundling to eliminate attempts by
transmission owners to gain economic advantage. Companies have an
obligation to maximize value for shareholders, and it should be no
surprise that they will be aggressive in doing so. For example, in
comments to the Commission in the Order No
ission access may
be too difficult to police. Many have asserted that it is not realistic
even to expect functional unbundling to eliminate attempts by
transmission owners to gain economic advantage. Companies have an
obligation to maximize value for shareholders, and it should be no
surprise that they will be aggressive in doing so. For example, in
comments to the Commission in the Order No. 888 proceeding, the Federal
Trade Commission advised the Commission that a functional unbundling
approach ``* * * would leave in place the incentive and opportunity for
some utilities to exercise market power in the regulated system.
Preventing them from doing so by enforcing regulations to control their
behavior may prove difficult.'' A representative of Lafayette Utilities
told us at the New Orleans ISO Conference:
Notwithstanding functional separation and the requirement not to
discriminate, transmission personnel are well aware of the interests
of their company's generation function, and can find a way to give
preferential treatment. * * * 100
---------------------------------------------------------------------------
\100\ Comments of Frank Ledoux on behalf of Lafayette Utilities
System, Regional ISO Conference (New Orleans), Transcript at 180.
---------------------------------------------------------------------------
A representative of a Wisconsin public utility told us:
Administration of the tariff entails a myriad of decisions that
require discretion, as well as ``technical'' judgments (like
[available transmission capability] and [capacity benefit margin])
that have significant competitive ramifications. It is inevitable
that these decisions and judgments will be made with competitive
concerns in mind. Functional separation does not solve this
problem.101
\101\ Statement of Roy Thilly on behalf of Wisconsin Public
Power, Inc. at 2, Docket No. PL98-5-000 (filed April 15, 1998).
[available transmission capability] and [capacity benefit margin])
that have significant competitive ramifications. It is inevitable
that these decisions and judgments will be made with competitive
concerns in mind. Functional separation does not solve this
problem.101
\101\ Statement of Roy Thilly on behalf of Wisconsin Public
Power, Inc. at 2, Docket No. PL98-5-000 (filed April 15, 1998).
Similarly, at our regional ISO conference in Indianapolis, we were
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told:
In a capital intensive industry where a high percentage of the
investment is in generation assets, it is inconceivable that a
utility, which in some cases has very high generation cost, would
somehow manage its transmission system so as not to give its
generation a competitive advantage. I think this is self-
evident.102
\102\ Comments of Kenneth Hegemann on behalf of American
Municipal Power, Ohio, Regional ISO Conference (Indianapolis),
Transcript at 174.
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While it should not be assumed that such problems exist in every
circumstance, clearly many market participants do not believe the
market can yet be trusted with respect to their commercial interests,
at least in some areas. We now turn to some of the areas that have
produced the most complaints about continuing discrimination.
a. Calculation and Posting of Available Transmission Capability in a
Manner Favorable to the Transmission Provider
Perhaps the most significant complaint with respect to alleged
discriminatory conduct under functional unbundling concerns the
important function of calculating and posting the amount of
transmission capability that is available on a transmission provider's
system. The transmission provider is required to calculate and post on
its OASIS the TTC and ATC for each posted transmission
path.103 ATC is the capacity that is stated to be available
for transmission service requests
ct under functional unbundling concerns the
important function of calculating and posting the amount of
transmission capability that is available on a transmission provider's
system. The transmission provider is required to calculate and post on
its OASIS the TTC and ATC for each posted transmission
path.103 ATC is the capacity that is stated to be available
for transmission service requests. As we discussed above in Section
III.A.1, it is not possible to calculate accurately the transmission
capability of one system without knowing the flows scheduled by all
other interconnected transmission providers in the region. Given this
technical problem, it may be impossible to distinguish an inaccurate
ATC presented in good faith from an inaccurate ATC presented for the
purpose of favoring the transmission provider's marketing interests.
---------------------------------------------------------------------------
\103\ See 18 CFR 37.6(b) (1998).
---------------------------------------------------------------------------
Transmission providers with power marketing interests have
incentives to understate ATC on those paths valuable to its marketing
competitors, or to divert transmission capacity so that it is available
for use by its own marketing interests. If there is insufficient ATC,
competitors may be forced to forego power sale transactions or use a
less desirable alternative path if one is available.
The Commission has found violations of ATC postings in three cases.
In Washington Water Power Company,104 the transmission
owning utility showed that it had no firm ATC, which would have
discouraged any potential marketers who needed firm transmission
service to make a sale. However, the utility then offered its power
marketing affiliate, Avista
Energy, an ``interruptible firm'' transmission service that was not
available to competitors. As the Commission explained in finding a
violation of Order No. 888:
ssion
owning utility showed that it had no firm ATC, which would have
discouraged any potential marketers who needed firm transmission
service to make a sale. However, the utility then offered its power
marketing affiliate, Avista
Energy, an ``interruptible firm'' transmission service that was not
available to competitors. As the Commission explained in finding a
violation of Order No. 888:
\104\ 83 FERC para. 61,097 (1998), further order, 83 FERC para.
61,282 (1998).
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Avista received a preference from Washington Water Power that
was not available to any of its competitors. Simply stated, Avista's
customer was deprived of the benefit of choosing among all potential
power suppliers.
The case of Wisconsin Public Power Inc. SYSTEM v. Wisconsin Public
Service Corporation, et al. (Wisconsin Public) 105
demonstrates both the difficulties and suspicions of discrimination
resulting from when a transmission customer requests transmission
service from an integrated utility. WPPI was seeking additional network
transmission service from both Wisconsin Public Service Corporation
(WPSC) and Wisconsin Power & Light Company (WP&L). In both cases, the
requests were denied because of claims that the transmission owners
were using all available capacity. In the case of WPSC, the Commission
initially found that the utility had not properly reserved capacity for
its merchant function and directed that it recompute its ATC without
that reservation. After WPSC submitted additional documentation, the
Commission accepted some of WPSC's merchant priority, but still found
that it had violated its obligations under its tariff, and that its
actions raised serious concerns about the functional separation of its
staff
ty had not properly reserved capacity for
its merchant function and directed that it recompute its ATC without
that reservation. After WPSC submitted additional documentation, the
Commission accepted some of WPSC's merchant priority, but still found
that it had violated its obligations under its tariff, and that its
actions raised serious concerns about the functional separation of its
staff. With respect to WP&L, the Commission found that it provided
unduly preferential treatment to its merchant function, had been
changing its ATC without posting those changes on OASIS, and had been
computing ATC where none exists.106
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\105\ 83 FERC para. 61,198 (1998), order on reh'g, 84 FERC para.
61,120 (1998).
\106\ 83 FERC at 61,860.
---------------------------------------------------------------------------
The Wisconsin Public cases demonstrate, if nothing else, the
difficulty of achieving, and enforcing, functional separation of a
utility's transmission and merchant functions. These types of cases
require substantial Commission investigative and adjudicative
resources, not to mention the resources of the parties involved. The
Commission recognized in Wisconsin Public how RTOs could help eliminate
these problems. The Commission stated:
As we recently explained in Louisville Gas & Electric Company,
et al., 82 FERC para. 61,308 at 62,222 & n. 39 (1998), a properly
structured ISO, or other transmission entity can eliminate the
potential for the strategic use of a transmission owner's priority
to use internal system capacity for native load. The ISO or other
transmission entity can also eliminate the incentive to engage in
strategic curtailments of generation that a transmission operator's
generation service competitors own and can remove any incentive to
game OASIS operations
transmission entity can eliminate the
potential for the strategic use of a transmission owner's priority
to use internal system capacity for native load. The ISO or other
transmission entity can also eliminate the incentive to engage in
strategic curtailments of generation that a transmission operator's
generation service competitors own and can remove any incentive to
game OASIS operations. This will promote generation entry and
competition, since a properly structured ISO or other transmission
entity would have no economic stake in favoring certain market
participants over others and potential entrants would likely see the
transmission market as fair. An ISO, therefore, could help to solve
the problems established in the instant complaints.107
\107\ Id. at 61,859.
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The case of Morgan Stanley Capital Group v. Illinois Power Company
108 also demonstrated problems associated with ATC and a
transmission provider's use of its system for its own purposes. Morgan
Stanley complained that Illinois Power failed to accurately post ATC,
failed to award transmission capacity in a non-discriminatory manner,
and allocated transmission in favor of its own bulk power marketing
arm. Illinois Power admitted the ATC posting error, and the Commission
found other violations of its tariff in responding to Morgan Stanley's
request for service. Although the Commission initially also found that
Illinois Power did not designate its own network resources in the same
manner as network customers are required to designate them, Illinois
Power disputed this, and after showing that its network resource was
legitimate, the Commission dismissed its rehearing as moot.
Nevertheless, this case demonstrates that a combination of ATC errors
and unclear procedures feeds the mistrust in the marketplace with
respect to a transmission owner's ability to use its system to favor
itself
rk customers are required to designate them, Illinois
Power disputed this, and after showing that its network resource was
legitimate, the Commission dismissed its rehearing as moot.
Nevertheless, this case demonstrates that a combination of ATC errors
and unclear procedures feeds the mistrust in the marketplace with
respect to a transmission owner's ability to use its system to favor
itself.
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\108\ 83 FERC para. 61,204, order granting clarification and
dismissing reh'g, 83 FERC para. 61,299 (1998).
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We also have currently pending before us several formal complaints
alleging that a transmission provider is improperly keeping its
transmission capability for its merchant function. In one case, a power
marketer asserts that a transmission provider has refused service over
an interconnection on the basis that the transmission provider needs
all the ATC for native load. The marketer has alleged that the
transmission provider's claims of reliability concerns are a mask to
block competitors from importing power into the transmission provider's
system when the transmission provider has higher cost generation
available.109 In another recent formal complaint filing, it
is alleged that a transmission provider denied transmission service and
then improperly provided it to its merchant group.110
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\109\ Aquila Power Corporation v. Entergy Services, Inc., Docket
No. EL98-36-000, Amended and Restated Complaint at 6 (filed June 23,
1998).
\110\ Arizona Public Service Company v. Idaho Power Company,
Docket No. EL99-44-000 (filed March 3, 1999).
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\109\ Aquila Power Corporation v. Entergy Services, Inc., Docket
No. EL98-36-000, Amended and Restated Complaint at 6 (filed June 23,
1998).
\110\ Arizona Public Service Company v. Idaho Power Company,
Docket No. EL99-44-000 (filed March 3, 1999).
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Aside from these cases involving formal complaints, there have been
a number of other complaints with respect to ATC calculation. For
example, our enforcement staff receives hotline complaints concerning
ATC posting problems. The enforcement staff has confirmed a number of
such ATC errors. In most cases, these errors were corrected within
several months of having them pointed out, and the utilities often
offered explanations based on hardware or software problems. We make no
judgment whether such identified errors were an intentional attempt to
thwart competition; however, they had the potential to have that
effect.
In July 1997, the Commission held a technical conference concerning
how well the OASIS system was working. Several commenters suggested
that erroneous ATC calculation and posting was hurting competition. A
representative from Electric Clearinghouse told us that there is a
pervasive problem of incorrect or stale information on the OASIS sites,
and that ``competition is blocked when this occurs.'' That same
representative stated that very little firm ATC is offered due to the
utility's caution or strategy, and that some providers will not offer
firm ATC because they do not want to curtail their own
transactions.111 At the same conference, a representative
from the American Public Power Association told us:
\111\ Open Access Same Time Information Technical Conference,
Docket No. RM95-9-003 (July 18, 1997), transcript at 23.
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that some providers will not offer
firm ATC because they do not want to curtail their own
transactions.111 At the same conference, a representative
from the American Public Power Association told us:
\111\ Open Access Same Time Information Technical Conference,
Docket No. RM95-9-003 (July 18, 1997), transcript at 23.
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ATC is often understated and inconsistently posted on adjacent
OASIS nodes. Inter-regional coordination is lacking. This fact
limits the usefulness of the system for commercial
purposes.112
\112\ Id. at 28.
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In March 1998, a group referring to themselves as power industry
stakeholders 113 filed a petition for rulemaking on electric
power industry structure.114 Although we are not addressing
here the specific relief they are requesting in that Petition, the
Petition does contain a number of fairly specific allegations
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indicating problems in the market. For example, the Petition asserts:
\113\ The group consists of a number of power marketers and
users, including, for example, Coalition for a Competitive Electric
Market, ELCON, Electric Clearinghouse, Inc., and Enron Power
Marketing, Inc.
\114\ Petition for a Rulemaking on Electric Power Industry
Structure and Commercial Practices and Motion to Clarify or
Reconsider Certain Open-Access Commercial Practices, Docket No.
RM98-5-000.
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example, Coalition for a Competitive Electric
Market, ELCON, Electric Clearinghouse, Inc., and Enron Power
Marketing, Inc.
\114\ Petition for a Rulemaking on Electric Power Industry
Structure and Commercial Practices and Motion to Clarify or
Reconsider
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