Regional Transmission Organizations; Notice of Proposed Rulemaking

SUMMARY: The Federal Energy Regulatory Commission (Commission) is

proposing to amend its regulations under the Federal Power Act (FPA) to

facilitate the formation of Regional Transmission Organizations (RTOs).

The Commission proposes to require that each public utility that owns,

operates, or controls facilities for the transmission of electric

energy in interstate commerce make certain filings with respect to

forming and participating in an RTO. The Commission also proposes

minimum characteristics and functions that a transmission entity must

satisfy in order to be considered to be an RTO.

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

September 15, 1999.

ADDRESSES: Send comments to: Office of the Secretary, Federal Energy

Regulatory Commission, 888 First Street, NE., Washington, D.C. 20426.

FOR FURTHER INFORMATION CONTACT:

Alan Haymes (Technical Information), Office of Electric Power

Regulation, Federal Energy Regulatory Commission, 888 First Street,

NE., Washington, D.C. 20426, (202) 219-2919.

Wilbur C. Earley (Technical Information), Office of Economic Policy,

Federal Energy Regulatory Commission, 888 First Street, NE.,

Washington, D.C. 20426, (202) 208-0100

Brian R. Gish (Legal Information), Office of the General Counsel,

Federal Energy Regulatory Commission, 888 First Street, NE.,

Washington, D.C. 20426, (202) 208-0996

SUPPLEMENTARY INFORMATION: In addition to publishing the full text of

this document in the Federal Register, the Commission also provides all

interested persons an opportunity to inspect or copy the contents of

this document during normal business hours in the Public Reference Room

at 888 First Street, N.E., Room 2A, Washington, D.C. 20426.

The Commission Issuance Posting System (CIPS) provides access to

the texts of formal documents issued by the Commission from November

14, 1994, to the present. CIPS can be accessed via Internet through

FERC's Home page (http://www.ferc.fed.us) using the CIPS Link or the

Energy Information Online icon. Documents will be available on CIPS in

ASCII and WordPerfect 6.1. User assistance is available at 202-208-2474

or by E-mail to [email protected].

This document is also available through the Commission's Records

and Information Management System (RIMS), an electronic storage and

retrieval system of documents submitted to and issued by the Commission

after November 16, 1981. Documents from November 1995 to the present

can be viewed and printed. RIMS is available in the Public Reference

Room or remotely via Internet through FERC's Home page using the RIMS

link or the Energy Information Online icon. User assistance is

available at 202-208-2222, or by E-mail to [email protected].

Finally, the complete text on diskette in WordPerfect format may be

purchased from the Commission's copy contractor, RVJ International,

Inc. RVJ International, Inc. is located in the Public Reference Room at

888 First Street, N.E., Washington, D.C. 20426.

Table of Contents

I. Introduction and Summary

II. Background

A. The Foundation for Competitive Markets: Order Nos. 888 and

889

B. Developments Since Order Nos. 888 and 889

1. Industry Restructuring and New Stresses on the Transmission

Grid

2. Successes, Failures and Haphazard Development of Regional

Transmission Entities

3. The Commission's ISO and RTO Inquiries; Conferences with

Stakeholders and State Regulators

C. Statutory Framework

III. Discussion

A. Barriers to Assuring an Abundant Supply of Electric Energy

throughout the U.S. with the Greatest Possible Economy

1. Engineering and Economic Inefficiencies in the Operation,

Planning, and Expansion of Regional Transmission Grids

2. Actual and Perceived Discriminatory Conduct by Transmission

Owners to Favor Their Own or Affiliated Merchant Operations

B. Benefits That RTOs Can Offer

1. An RTO Would Improve Efficiencies in the Management of the

Transmission Grid

2. An RTO Would Improve Grid Reliability

3. An RTO Would Remove Opportunities for Discriminatory

Transmission Practices

4. An RTO Would Result in Improved Market Performance

5. An RTO Would Facilitate Lighter-Handed Governmental

Regulation

6. Conclusion

C. Concerns Expressed by the State Commissions

1. Federal Mandate

2. Regional Flexibility

3. Retail Markets

4. Effect on States With Low Cost Generation

5. Need for Independent Transmission Operation

6. Transmission Cost Shifting

7. Boundary Drawing

8. Regional Approach to Reliability

9. Pricing Reform

10. Participation of Public Power

11. State Role in RTO Governance

12. Existing Regional Transmission Entities

D. Minimum Characteristics and Functions for a Regional

Transmission Organization

Minimum Characteristics

1. Independence

2. Scope and Regional Configuration

3. Operational Authority

4. Short-term Reliability

Minimum Functions

1. Tariff Administration and Design

2. Congestion Management

3. Parallel Path Flow

4. Ancillary Services

5. OASIS and TTC and ATC

6. Market Monitoring

7. Planning and Expansion

E. Open Architecture

F. Ratemaking for Transmission Facilities under RTO Control

1. Single Transmission Access Rate for Capital Cost Recovery

2. Congestion Pricing

3. Performance Based Rate Regulation

4. Consideration of Incentive Pricing Proposals

G. Public Power Participation in RTOs

H. Other Issues

1. Pre-existing Transmission Contracts

2. Treatment of Existing Regional Transmission Entities

3. Participation by Canadian and Mexican Entities

4. Providing Service to Transmission-owning Utilities That Do

Not Participate in an RTO

5. RTO Filing Requirements

6. Power Exchanges (PXs)

I. Implementation of the Rule

1. Collaborative Process

2. Filing Requirements

IV. Environmental Statement

V. Regulatory Flexibility Act

VI. Public Reporting Burden and Information Collection Statement

VII. Public Comment Procedures

Text of the Regulations

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

Appendix B: Staff Summary of FERC Consultations With the States

Appendix C: Existing Configurations

I. Introduction and Summary

In 1996 the Commission put in place the foundation necessary for

[[Page 31391]]

competitive wholesale power markets in this country--open access

transmission.1 Since that time, the industry has undergone

sweeping restructuring activity, including a movement by many states to

develop retail competition, the growing divestiture of generation

plants by traditional electric utilities, a significant increase in the

number of mergers among traditional electric utilities and among

electric utilities and gas pipeline companies, large increases in the

number of power marketers and independent generation facility

developers entering the marketplace, and the establishment of

independent system operators (ISOs) as managers of large parts of the

transmission system. Trade in bulk power markets has continued to

increase significantly and the Nation's transmission grid is being used

more heavily and in new ways.

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\1\ See Promoting Wholesale Competition Through Open Access Non-

discriminatory Transmission Services by Public Utilities and

Recovery of Stranded Costs by Public Utilities and Transmitting

Utilities, 61 FR 21540 (1996), FERC Stats. & Regs. para. 31,036

(1996) (Order No. 888), order on reh'g, Order No. 888-A, 62 FR 12274

(1997), FERC Stats. & Regs. para. 31,048 (1997), order on reh'g,

Order No. 888-B, 62 FR 64688, 81 FERC para. 61,248 (1997), order on

reh'g, Order No. 888-C, 82 FERC para. 61,046 (1998), appeal

docketed, Transmission Access Policy Study Group, et al. v. FERC,

Nos. 97-1715 et al. (D.C. Cir.).

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As a result, the traditional means of grid management is showing

signs of strain and may be inadequate to support the efficient and

reliable operation that is needed for the continued development of

competitive electricity markets. In addition, there are indications

that continued discrimination in the provision of transmission services

by vertically integrated utilities may also be impeding fully

competitive electricity markets. These problems may be depriving the

Nation of the benefits of lower prices, more reliance on market

solutions, and lighter-handed regulation that competitive markets can

bring.

If electricity consumers are to realize the full benefits that

competition can bring to wholesale markets, the Commission must address

the extent of these problems and appropriate ways of mitigating them.

Competition in wholesale electricity markets is the best way to protect

the public interest and ensure that electricity consumers pay the

lowest price possible for reliable service. We believe that further

steps may need to be taken to address grid management if we are to

achieve fully competitive power markets. We further believe that

regional approaches to the numerous issues affecting the industry may

be the best means to eliminate remaining impediments to properly

functioning competitive markets.

Our objective is for all transmission owning entities in the

Nation, including non-public utility entities, to place their

transmission facilities under the control of appropriate regional

transmission institutions in a timely manner. We seek to accomplish our

objective by encouraging voluntary participation. We are therefore

proposing in this rulemaking minimum characteristics and functions for

appropriate regional transmission institutions; a collaborative process

by which public utilities and non-public utilities that own, operate or

control interstate transmission facilities, in consultation with the

state officials as appropriate, will consider and develop regional

transmission institutions; a willingness to consider incentive pricing

on a case-specific basis and an offer of non-monetary regulatory

benefits, such as deference in dispute resolution, reduced or

eliminated codes of conduct, and streamlined filing and approval

procedures; and a time line for public utilities to make appropriate

filings with the Commission and initiate operation of regional

transmission institutions. As a result, we expect jurisdictional

utilities to form Regional Transmission Organizations (RTOs).

As discussed in detail herein, regional institutions can address

the operational and reliability issues now confronting the industry,

and any residual discrimination in transmission services that can occur

when the operation of the transmission system remains in the control of

a vertically integrated utility. Appropriate regional transmission

institutions could: (1) improve efficiencies in transmission grid

management 2; (2) improve grid reliability; (3) remove the

remaining opportunities for discriminatory transmission practices; (4)

improve market performance; and (5) facilitate lighter handed

regulation.

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\2\ Appropriate regional institutions could improve efficiencies

in grid management through improved pricing, congestion management,

more accurate estimates of Available Transmission Capability,

improved parallel path flow management, more efficient planning, and

increased coordination between regulatory agencies.

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Thus, we believe that appropriate regional transmission

institutions could successfully address the existing impediments to

efficient grid operation and competition and could consequently benefit

consumers through lower electricity rates resulting from a wider choice

of services and service providers. There are likely to be substantial

cost savings brought about by regional transmission institutions.

In light of important questions regarding the complexity of grid

regionalization raised by state regulators and applicants in individual

cases, we are proposing a flexible approach. We are not proposing to

mandate that utilities participate in a regional transmission

institution by a date certain. Instead, we act now to ensure that they

consider doing so in good faith. Moreover, the Commission is not

proposing a ``cookie cutter'' organizational format for regional

transmission institutions or the establishment of fixed or specific

regional boundaries under section 202(a) of the FPA.

Rather, the Commission is proposing to establish fundamental

characteristics and functions for appropriate regional transmission

institutions. We will designate institutions that satisfy all of the

minimum characteristics and functions as Regional Transmission

Organizations (RTOs). Hereinafter, the term Regional Transmission

Organization, or RTO, will refer to an organization that satisfies all

of the minimum characteristics and functions.

Pursuant to our authority under section 205 of the FPA to ensure

that rates, terms and conditions of transmission and sales for resale

in interstate commerce by public utilities are just, reasonable and not

unduly discriminatory or preferential, and our authority under section

202(a) of the FPA to promote and encourage regional districts for the

voluntary interconnection and coordination of transmission facilities

by public utilities and non-public utilities for the purpose of

assuring an abundant supply of electric energy throughout the U.S. with

the greatest possible economy, we propose the following.3

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\3\ The Commission's legal authority is discussed in Section II.

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First, the Commission proposes minimum characteristics and

functions that an RTO must satisfy. Industry participants, however,

retain flexibility in structuring RTOs that satisfy these

characteristics and functions. For example, we do not propose to

require or prohibit any one form of organization for RTOs or require or

prohibit RTO ownership of transmission facilities. The characteristics

and functions could be satisfied by different organizational forms,

such as ISOs, transcos, combinations of the two, or even new

organizational forms not yet discussed in the industry or proposed to

the Commission.

Second, we propose to adopt an ``open architecture'' policy

regarding RTOs, whereby all RTO proposals must

[[Page 31392]]

allow the RTO and its members the flexibility to improve their

organizations in the future in terms of structure, operations, market

support and geographic scope to meet market needs. In turn, the

Commission will provide the regulatory flexibility to accommodate such

improvement.

Third, we propose guidance on flexible transmission ratemaking that

may be proposed by RTOs, including ratemaking treatments that will

address congestion pricing and performance based regulation. We also

propose to consider on a case-by-case basis incentive pricing that may

be appropriate for transmission facilities under RTO control.

Finally, all public utilities (with the exception of those

participating in an approved regional transmission entity that conforms

to the Commission's ISO principles) that own, operate or control

interstate transmission facilities must file with the Commission by

October 15, 2000 a proposal for an RTO with the minimum characteristics

and functions adopted in the Final Rule,4 or, alternatively,

a description of efforts to participate in an RTO, any existing

obstacles to RTO participation, and any plans to work toward RTO

participation. Each proposed RTO must plan to be operational by

December 15, 2001. We expect that such proposals would include the

transmission facilities of public utilities as well as transmission

facilities of public power and other non-public utility entities to the

extent possible.

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\4\ An RTO proposal includes a basic agreement filed under

section 205 of the FPA setting out the rules, practices and

procedures under which an RTO will be governed and operated, and

requests by the public utility members of the RTO under section 203

of the FPA to transfer control of their jurisdictional transmission

facilities from individual public utilities to the RTO. Most RTO

proposals by public utilities are likely to involve one or more

filings under FPA sections 203, 205, or 206, but the number and

types of filing may vary depending upon the type of RTO proposed,

and the number of public utilities involved in the proposal. Under

the proposed rule, a utility may file a petition for a declaratory

order asking whether a proposed transmission entity would qualify as

an RTO, to be followed by appropriate filings under sections 203,

205 and/or 206.

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A public utility that is a member of an existing transmission

entity that has been approved by the Commission as in conformance with

the eleven ISO principles set forth in Order No. 888 must make a filing

no later than January 15, 2001 that explains the extent to which the

transmission entity in which it participates meets the minimum

characteristics and functions for an RTO, or proposes to modify the

existing institution to become an RTO. Alternatively, the public

utility must file an explanation of efforts, obstacles and plans with

respect to conforming to these characteristics and functions.

Through the required filings, utilities will make known to the

public any plans for RTO participation so that other utilities and the

competitive market can respond accordingly. This proposal relies

primarily on the enlightened self-interest of stakeholders in each

region. Such public disclosure of plans for transmission facilities

will benefit the industry, the financial community, and public policy

makers as the electric industry restructuring continues.

To facilitate RTO formation in all regions of the Nation, the

Commission proposes to sponsor and support a collaborative process

under section 202(a) to take place in the spring of 2000. Under this

process, we expect that public utilities and non-public utilities, in

coordination with state officials, Commission staff, and all affected

interest groups, will actively work toward the voluntary development of

specific RTOs.

Prior to undertaking this proposed rulemaking, we held eight

technical conferences in 1998 with all industry stakeholders as well as

three technical conferences this year with state regulatory commissions

to obtain their views on the need for, and benefits of, regional

organizations. We gained valuable insight from the participants,

including many state commissions that have undertaken or are

considering state retail choice programs for the consumers in their

states. In light of the comments received, we wish to respond to

several concerns that were raised.

First, we are not proposing to mandate RTOs, nor are we proposing

detailed specifications on a particular organizational form for RTOs.

The goal of this rulemaking is to get RTOs in place through voluntary

participation. While this Commission has specific authorities and

responsibilities under the FPA to protect against undue discrimination

and remove impediments to wholesale competition, we believe it is

preferable to meet these responsibilities in the first instance through

an open and collaborative process that allows for regional flexibility

and induces voluntary behavior.

Second, the development of RTOs is not intended to interfere with

state prerogatives in setting retail competition policy. The Commission

believes that RTOs can successfully accommodate the transmission

systems of all states, whether or not a particular state has adopted

retail competition. However, for those states that have chosen to adopt

retail wheeling, RTOs can play a critical role in the realization of

full competition at the retail level as well as at the wholesale level.

In addition, the Commission believes that RTOs will not interfere with

a state's prerogative to keep the benefits of low-cost power for the

state's own retail consumers.

Third, we propose to allow RTOs to prevent transmission cost

shifting by continuing our policy of flexibility with respect to

recovery of sunk transmission costs, such as the ``license plate''

approach.

Fourth, the existence of RTOs has not, and will not in the future,

interfere with traditional state and local regulatory responsibilities

such as transmission siting, local reliability matters, and regulation

of retail sales of generation and local distribution. In fact, RTOs

offer the potential to assist the states in their regulation of retail

markets and in resolving matters among states on a regional basis. They

also provide a vehicle for amicably resolving state and Federal

jurisdictional issues.

Finally, we do not propose to establish regional boundaries in this

rulemaking. Our foremost concern is that a proposed RTO's regional

configuration is sufficient to ensure that the required RTO

characteristics and functions are satisfied. To this end, the

Commission proposes guidance regarding the scope and regional

configuration of RTOs.

We now turn to the state of the electric utility industry in the

wake of Order No. 888 and how the development of RTOs achieves

efficient, reliable and competitive power markets.

II. Background

In April 1996, in Order Nos. 888 and 889, the Commission

established the foundation necessary to develop competitive bulk power

markets in the United States: non-discriminatory open access

transmission services by public utilities and stranded cost recovery

rules that would provide a fair transition to competitive markets.

Order Nos. 888 and 889 were very successful in accomplishing much of

what they set out to do. However, they were not intended to address all

problems that might arise in the development of competitive power

markets. Indeed, the nature of the emerging markets and the remaining

impediments to full competition have become apparent in the three years

since the issuance of our orders.

A. The Foundation for Competitive Markets: Order Nos. 888 and 889

In Order Nos. 888 and 889, the Commission found that unduly

discriminatory and anticompetitive

[[Page 31393]]

practices existed in the electric industry, and that transmission-

owning utilities had discriminated against others seeking transmission

access.5 The Commission stated that its goal was to ensure

that customers have the benefits of competitively priced generation,

and determined that non-discriminatory open access transmission

services (including access to transmission information) and stranded

cost recovery were the most critical components of a successful

transition to competitive wholesale electricity markets.6

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\5\ Order No. 888, FERC Stats & Regs. at 31,682.

\6\ Id. at 31,652.

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Accordingly, Order No. 888 required all public utilities that own,

control or operate facilities used for transmitting electric energy in

interstate commerce to (1) file open access non-discriminatory

transmission tariffs containing, at a minimum, the non-price terms and

conditions set forth in the Order, and (2) functionally unbundle

wholesale power services. Under functional unbundling, the public

utility must: (a) take transmission services under the same tariff of

general applicability as do others; (b) state separate rates for

wholesale generation, transmission, and ancillary services; and (c)

rely on the same electronic information network that its transmission

customers rely on to obtain information about its transmission system

when buying or selling power.7 Order No. 889 required that

all public utilities establish or participate in an Open Access Same-

Time Information System (OASIS) that meets certain specifications, and

comply with standards of conduct designed to prevent employees of a

public utility (or any employees of its affiliates) engaged in

wholesale power marketing functions from obtaining preferential access

to pertinent transmission system information.

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\7\ Id. at 31,654-55.

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During the course of the Order No. 888 proceeding, the Commission

received comments urging it to require generation divestiture or

structural institutional arrangements such as regional independent

system operators (ISOs) to better assure non-discrimination. The

Commission responded that, while it believed that ISOs had the

potential to provide significant benefits, efforts to remedy undue

discrimination should begin by requiring the less intrusive functional

unbundling approach. Order No. 888 set forth eleven principles for

assessing ISO proposals submitted to the Commission. 8 Order

No. 888 also stated:

\8\ Id. at 31,730.

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[W]e see many benefits in ISOs, and encourage utilities to

consider ISOs as a tool to meet the demands of the competitive

marketplace.

As a further precaution against discriminatory behavior, we will

continue to monitor electricity markets to ensure that functional

unbundling adequately protects transmission customers. At the same

time, we will analyze all alternative proposals, including formation

of ISOs, and, if it becomes apparent that functional unbundling is

inadequate or unworkable in assuring non-discriminatory open access

transmission, we will reevaluate our position and decide whether

other mechanisms, such as ISOs, should be required. 9

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\9\ Id. at 31,655.

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In section III.A.2 of this Notice of Proposed Rulemaking, we

discuss our experiences to date with functional unbundling. It has

become apparent that several types of regional transmission

institutions, in addition to the kinds of ISOs approved to date, may

also be able to provide the benefits attributed to ISOs in Order No.

888.

B. Developments Since Order Nos. 888 and 889

In the three years since Order Nos. 888 and 889 were issued,

numerous significant developments have occurred in the electric utility

industry. Some of these reflect changes in governmental policies;

others are strictly industry driven. These activities have resulted in

a considerably different industry landscape from the one faced at the

time the Commission was developing Order No. 888, resulting in new

regulatory and industry challenges.

Order Nos. 888 and 889 required a significant change in the way

many public utilities have done business for most of this century, and

most public utilities accepted these changes and made substantial good

faith efforts to comply with the new requirements. Virtually all public

utilities have filed tariffs stating rates, terms and conditions for

third-party use of their transmission systems. In addition, improved

information about the transmission system is available to all

participants in the market at the same time that it is available to the

public utility as a result of utility compliance with the OASIS

regulations.

The availability of tariffs and information about the transmission

system has fostered a rapid growth in dependence on wholesale markets

for acquisition of generation resources. Areas that have experienced

generation shortages have seen rapid development of new generation

resources. For example, New England, where there was deep concern about

adequacy of generation supply only three years ago, now has

approximately 30,000 MW of generation proposed. That response comes

almost entirely from independent generating plants that are able to

sell power into the bulk power market through open access to the

transmission system. Power resources are now acquired over increasingly

large regional areas, and interregional transfers of electricity have

increased.

The very success of Order Nos. 888 and 889, and the initiative of

some utilities that have pursued voluntary restructuring beyond the

minimum open access requirements , have put new stresses on regional

transmission systems--stresses that call for regional solutions.

1. Industry Restructuring and New Stresses on the Transmission Grid

Open access transmission and the opening of wholesale competition

in the electric industry have brought an array of changes in the past

several years: divestiture by many integrated utilities of some or all

of their generating assets; significantly increased merger activity

both between electric utilities and between electric and natural gas

utilities; increases in the number of new participants in the industry

in the form of independent power marketers and generators; increases in

the volume of trade in the industry, particularly as marketers make

multiple sales; state efforts to create retail competition; and new and

different uses of the transmission grid.

With respect to divestiture, since August 1997, approximately

50,000 MW of generating capacity have been sold (or are under contract

to be sold) by utilities, and an additional 30,000 MW is currently for

sale. In total, this represents more than 10 percent of U.S. generating

capacity. In all, according to publicly available data, 27 utilities

have sold all or some of their generating assets and 7 others have

assets for sale. Buyers of this generating capacity have included

traditional utilities with specified service territories as well as

independent power producers with no required service territory.

Since Order No. 888 was issued, there have been more than 20

applications filed with us to approve proposed mergers involving public

utilities. Most of these mergers have been approved by various

regulatory authorities, including the Commission, although a few have

been rejected or withdrawn, and several mergers are pending regulatory

approval. Most of these merger proposals have been between electric

utilities with contiguous service areas, while some of the proposed

mergers have been between utilities with non-

[[Page 31394]]

contiguous service areas. The Commission has also been presented with

merger applications involving the combination of electric and natural

gas assets.

There has been significant growth in the volume of trading in the

wholesale electricity market. In the first quarter of 1995, according

to power marketer quarterly filings, marketer sales totaled 1.8 million

MWh, but by the second quarter of 1998, such sales escalated to 513

million MWh.10 Many new competitors have entered the

industry. For example, in the first quarter of 1995, there were eight

power marketers (either independent or affiliated with traditional

utilities) actively trading in wholesale power markets, but by the

second quarter of 1998, there were 108 actively trading power

marketers. The Commission has granted market-based rate authority to

well over 500 wholesale power marketers, of which some are independent

of traditional investor-owned utilities, some are affiliated with

traditional utilities, and some are traditional utilities

themselves.11

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\10\ Power marketer quarterly filings, cited in Staff Report to

the Federal Energy Regulatory Commission on the Causes of Wholesale

Electric Pricing Abnormalities in the Midwest During June 1998,

(September 22, 1998) (Staff Price Spike Report) at 3-1 to 3-2. It

must be noted that a significant portion of the sales represent the

retrading of power by a number of different market participants. In

other words, there may be multiple resales of the same generation.

\11\ Id. at 3-1.

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State commissions and legislatures have been active in the past few

years studying competitive options at the retail level, setting up

pilot retail access programs, and, in some states, implementing full

scale retail access programs. As of May 1, 1999, 18 states have enacted

electric restructuring legislation, 3 have issued comprehensive

regulatory orders, and 28 others have legislation or orders pending or

investigations underway.12 Fifteen states have implemented

full-scale or pilot retail competition programs that offer a choice of

suppliers to at least some retail customers. Eight states have set in

motion programs to offer access to retail customers by a date certain.

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\12\ ``Status of Electric Utility Deregulation Activity as of

May 1, 1999,'' Energy Information Administration.

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Because of the changes in the structure of the electric industry,

the transmission grid is now being used more intensively and in

different ways than in the past. The Commission is concerned that the

traditional approaches to operating the grid are showing signs of

strain. According to the North American Electric Reliability Council

(NERC), ``the adequacy of the bulk transmission system has been

challenged to support the movement of power in unprecedented amounts

and in unexpected directions.'' 13 These changes in the use

of the transmission system ``will test the electric industry's ability

to maintain system security in operating the transmission system under

conditions for which it was not planned or designed.'' 14 It

should be noted that, despite the increased transmission system

loadings, NERC believes that the ``procedures and processes to mitigate

potential reliability impacts appear to be working reliably for now,''

and that even though the system was particularly stressed during the

summer of 1998, ``the system performed reliably and firm demand was not

interrupted due to transmission transfer limitations.'' 15

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\13\ Reliability Assessment 1998-2007, North American Electric

Reliability Council (September 1998), at 26.

\14\ Id.

\15\ Id.

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An indication that the increased and different use of the

transmission system is stressing the grid is the increased use of

transmission line loading relief (TLR) procedures. 16 NERC's

TLR procedures were invoked 250 times between January 1 and September

1, 1998 to prevent facility or interface overloads on the Eastern

Interconnection. 17

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\16\ The TLR procedures are designed to remedy overloads that

result when a transmission line or other transmission equipment

carries or will carry more power than its rating, which could result

in either power outages or damage to property. The TLR procedures

are designed to bring overloaded transmission equipment to within

NERC's Operating Security Limits essentially by curtailing

transactions contributing to the overload. See North American

Electric Reliability Council, 85 FERC para. 61,353 (1998) (NERC).

\17\ Reliability Assessment 1998-2007 at 27.

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It appears that the planning and construction of transmission and

transmission-related facilities may not be keeping up with increased

requirements. According to NERC, ``Business is increasing on the

transmission system, but very little is being done to increase the load

serving and transfer capability of the bulk transmission system.''

18 The amount of new transmission capacity planned over the

next ten years is significantly lower than the additions that had been

planned five years ago, and most of the planned projects are for local

system support. 19 NERC states that, ``The close

coordination of generation and transmission planning is diminishing as

vertically integrated utilities divest their generation assets and most

new generation is being proposed and developed by independent power

producers.'' 20

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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. 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.

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

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The Commission staff undertook an investigation of the price spike

incident. Staff's report concluded that the unusually high price levels

were caused by a combination of factors, particularly above-average

generation outages, unseasonably hot temperatures, storm-related

transmission outages, transmission constraints, poor communication of

price signals, lowered confidence in the market due to a few contract

defaults, and inexperience in dealing with competitive markets.

22

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\22\ Id. at v.

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The Commission's staff found that the market institutions were not

adequately prepared to deal with such a dramatic series of events.

Regarding regional transmission entities, the staff report observed:

``The necessity for cooperation in meeting reliability concerns and the

Commission's intent to foster competitive market conditions underscores

the importance of better regional coordination in areas such as

maintenance of transmission and generation systems and transmission

planning and operation.'' 23 Support for this view comes

from many sources. For example, the Public Utilities Commission of

Ohio, in its own report on the price spikes, recommended that policy

makers ``take unambiguous action to require coordination of

transmission system operations by regionwide Independent System

Operators.'' 24

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\23\ Id. at 5-8.

\24\ Ohio's Electric Market, June 22-26, 1998, What Happened

and Why, A Report to the Ohio General Assembly, at iii.

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On September 29, 1998, the Secretary of Energy Advisory Board Task

Force on Electric System Reliability published its

[[Page 31395]]

final report. 25 The Task Force was convened in January 1997

to provide advice to the Department of Energy on critical

institutional, technical, and policy issues that need to be addressed

in order to maintain bulk power electric system reliability in a more

competitive industry. The Task Force found that ``the traditional

reliability institutions and processes that have served the Nation well

in the past need to be modified to ensure that reliability is

maintained in a competitively neutral fashion;'' that ``grid

reliability depends heavily on system operators who monitor and control

the grid in real time;'' and that ``because bulk power systems are

regional in nature, they can and should be operated more reliably and

efficiently when coordinated over large geographic areas.''

26

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\25\ Maintaining Reliability in a Competitive U.S. Electricity

Industry; Final Report of the Task Force on Electric System

Reliability (Sept. 29, 1998) (Task Force Report). The Task Force was

comprised of 24 members representing all major segments of the

electric industry, including private and public suppliers, power

marketers, regulators, environmentalists, and academics.

\26\ Task Force Report at x-xi.

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The report noted that many regions of the United States are

developing ISOs as a way to maintain electric system reliability as

competitive markets develop. According to the Task Force, ISOs are

significant institutions to assure both electric system reliability and

competitive generation markets. The Task Force concluded that a large

ISO would: (1) be able to identify and address reliability issues most

effectively; (2) internalize much of the loop flow caused by the

growing number of transactions; (3) facilitate transmission access

across a larger portion of the network, consequently improving market

efficiencies and promoting greater competition; and (4) eliminate

``pancaking'' of transmission rates, thus allowing a greater range of

economic energy trades across the network. 27

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\27\ Id. at 76.

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2. Successes, Failures, and Haphazard Development of Regional

Transmission Entities

Since Order No. 888 was issued, there have been both successful and

unsuccessful efforts to establish ISOs, and other efforts to form

regional entities to operate the transmission facilities in various

parts of the country. While we are encouraged by the success of some of

these efforts, it is apparent that the results have been inconsistent,

and much of the country's transmission facilities remain outside of an

operational regional transmission institution.

Proposals for the establishment of five ISOs have been submitted to

and approved, or conditionally approved, by the Commission. These are

the California ISO,28 the PJM ISO,29 ISO New

England ISO,30 the New York ISO,31 and the

Midwest ISO.32 In addition, the Texas Commission has ordered

an ISO for the Electric Reliability Council of Texas

(ERCOT).33 Moreover, our international neighbors in Canada

and Mexico are also pursuing electric restructuring efforts that

include various forms of regional transmission entities.34

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\28\ Pacific Gas & Electric Company, et al., 77 FERC para.61,204

(1996), order on reh'g, 81 FERC para.61,122 (1997) (Pacific Gas &

Electric).

\29\ Pennsylvania-New Jersey-Maryland Interconnection, et al.,

81 FERC para.61,257 (1997), reh'g pending (PJM).

\30\ New England Power Pool, 79 FERC para.61,374 (1997), order

on reh'g, 85 FERC para.61,242 (1998) (order conditionally

authorizing ISO New England); New England Power Pool, 83 FERC

para.61,045 (1998), reh'g pending (order on NEPOOL tariff and

restructuring)(NEPOOL).

\31\ Central Hudson Gas & Electric Corporation, et al., 83 FERC

para.61,352 (1998), order on reh'g, 87 FERC para.61,135 (1999)

(Central Hudson).

\32\ Midwest Independent Transmission System Operator, et al.,

84 FERC para.61,231, order on reconsideration, 85 FERC para.61,250,

order on reh'g, 85 FERC para.61,372 (1998) (Midwest ISO).

\33\ See 16 Texas Administrative Code Sec. 23.67(p).

\34\ See Policy Proposal for Structural Reform of the Mexican

Electricity Industry, Secretary of Energy, Mexico (February 1999);

Third Interim Report of the Ontario Market Design Committee (October

1998); TransAlta Enterprises Corporation, 75 FERC para.61,268 at

61,875 (1996) (recognition of the restructuring in the Province of

Alberta, Canada to create a Grid Company of Alberta).

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The PJM, New England and New York ISOs were established on the

platform of existing tight power pools. It appears that the principal

motivation for creating ISOs in these situations was the Order No. 888

requirement that there be a single system wide transmission tariff for

tight pools. In contrast, the establishment of the California ISO and

the ERCOT ISO was the direct result of mandates by state governments.

The Midwest ISO, which is not yet operational, is unique. It began

through a consensual process and was not driven by a pre-existing

institution. Two states in the region subsequently required utilities

in their states to participate in either a Commission-approved ISO

(Illinois and Wisconsin), or sell their transmission assets to an

independent transmission company (Wisconsin).

The approved ISOs have similarities as well as differences. All

five Commission-approved ISOs operate, or propose to operate, as non-

profit organizations. All five ISOs include both public and non-public

utility members. However, among the five, there is considerable

variation in governance, operational responsibilities, geographic scope

and market operations. Four of the ISOs rely on a two-tier form of

governance with a non-stakeholder governing board on top that is

advised, either formally or informally, by one or more stakeholder

groups. In general, the final decision making authority rests with the

independent non-stakeholder board. One ISO, the California ISO, uses a

board consisting of stakeholders and non-stakeholders.

Four of the five ISOs operate traditional control areas, but the

Midwest ISO does not currently plan to operate a traditional control

area. Three are multi-state ISOs (New England, PJM and Midwest), while

two ISOs (California and New York) currently operate within a single

state. The current Midwest ISO members do not encompass one contiguous

geographic area and there are holes in its coverage. The ISO New

England administers a separate NEPOOL tariff, while the other four

administer their own ISO transmission tariffs.

Three ISOs operate or propose to operate centralized power markets

(New England, PJM and New York), and one ISO (California) relies on a

separate power exchange (PX) to operate such a market.35 The

Midwest ISO did not originally envision an ISO-related centralized

market for its region.36 In addition, at least one separate

PX has begun to do business in California apart from the PX established

through the restructuring legislation.37

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\35\ The California PX offers day-ahead and hour-ahead markets

and the ISO operates a real-time energy market. Participation in the

PX market is voluntary except that the three traditional investor-

owned utilities in California must bid their generation sales and

purchases through the PX for the first five years. New York will

offer day-ahead and real-time energy markets that will be operated

by the ISO. PJM and New England offer only real-time energy markets,

although PJM has proposed to operate a day-ahead market. The ERCOT

ISO is the only other ISO that does not currently operate a PX.

\36\ There are indications, however, that the Midwest ISO is

considering the formation of a power exchange. See Joint Committee

for the Development of a Midwest Independent Power Exchange,

``Solicitation of Interest-Creation of an Independent Power Exchange

for the U.S. Midwest,'' February 5, 1999.

\37\ See Automated Power Exchange, Inc., 82 FERC para. 61,287,

reh'g denied, 84 FERC para. 61,020 (1998), appeals docketed, No. 98-

1415 (D.C. Cir. Sept. 14, 1998) and No. 98-1419 (D.C. Cir. Sept. 14,

1998).

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Not all efforts to create ISOs have been successful. For example,

after more than two years of effort, the proponents of the IndeGO ISO

in the Pacific Northwest and Rocky Mountain regions ended their efforts

to create an ISO. More recently, members of MAPP, an existing power

pool that covers six U.S.

[[Page 31396]]

states and two Canadian provinces, failed to achieve consensus for

establishing a long-planned ISO. In the Southwest, proponents of the

Desert Star ISO have not been able to reach agreement on a formal

proposal after more than two years of discussion.

Various reasons have been advanced to explain why it is difficult

to form a voluntary, multi-state ISO. These include cost shifting in

transmission capital costs; disagreements about sharing of ISO

transmission revenues among transmission owners; difficulties in

obtaining the participation of publicly-owned transmission facilities;

concerns about the loss of transmission rights and prices embedded in

existing transmission agreements; the likelihood of not being able to

maintain or gain a competitive advantage in power markets through the

use of transmission facilities; and the preference of certain

transmission owners to sell or transfer their transmission assets to a

for-profit transmission company in lieu of handing over control to a

non-profit ISO.

Apart from these efforts to create ISOs, we have received proposals

for other types of transmission entities. For example, in October 1998

a group of Arizona entities filed a request with the Commission to

create an ``independent scheduling administrator'' (ISA) in

Arizona.38 Unlike an ISO, this entity would not administer

its own transmission tariff nor would it have any direct operational

responsibilities. Instead, it appears that its functions would be

limited to monitoring the scheduling decisions and OASIS site operation

of the Arizona utilities that operate transmission

facilities.39 In case of disputes, the ISA would provide a

type of expedited dispute resolution process. The applicants state that

the ISA would be a transitional organization that would ultimately

evolve or be merged into a stronger, multi-state ISO.40 In

other developments, one public utility has recently made a filing with

us to sell its transmission assets to a newly formed

affiliate.41 Another public utility recently filed a request

for declaratory order asking us to find that its proposal to transfer

its transmission assets (in the form of ownership or a lease) to a

``transco'' in return for a passive ownership interest in the transco,

would satisfy the Commission's eleven ISO principles.42

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\38\ Arizona Independent Scheduling Administrator Association,

Docket No. ER99-388-000 (filed October 29, 1998).

\39\ A proposal for a similar entity has been in the Pacific

Northwest. This entity, described as an independent grid scheduler,

would make actual scheduling decisions rather than simply monitoring

the decisions made by current transmission owners. See Regional ISO

Conference (Portland), transcript at 39-40.

\40\ See Applicant's filing, Docket No. ER99-388-000, at 3.

\41\ FirstEnergy, Inc., Docket No. EC99-53-000 (filed March 19,

1999).

\42\ Entergy Services, Inc., Docket No. EL99-57-000 (filed April

5, 1999).

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As part of general restructuring initiatives, several states now

require independent grid management organizations. For example, an

Illinois law requires that its utilities become members of a FERC-

approved regional ISO by March 31, 1999, and Wisconsin law gives its

utilities the option of joining an ISO or selling their transmission

assets to an independent transmission company by June 30, 2000. In both

states, the backstop is a single-state organization if regional

organizations are not developed. Recently, Virginia and Arkansas have

also enacted legislation requiring their electric utilities to join or

establish regional transmission entities.

3. The Commission's ISO and RTO Inquiries; Conferences with

Stakeholders and State Regulators

In light of the various restructuring activities occurring

throughout the U.S., the Commission has, within the past year, held 11

public conferences in 9 different cities across the country to hear the

views of industry, consumers, and state regulators with respect to the

need for RTOs and their appropriate roles and responsibilities.

The Commission initiated an inquiry in March 1998 pertaining to its

policies on ISOs. A notice establishing procedures for a conference

gave the following rationale:

In Order Nos. 888 and 889 and their progeny, the Commission

established the fundamental principles of non-discriminatory open

access transmission services. Nevertheless, many issues remain to be

addressed if the Nation is to fully realize the benefits of open

access and more competitive electric markets.

* * * * *

Given the dramatic changes taking place in both wholesale and

retail electric markets and the many proposals under consideration

with respect to the creation of ISOs or other transmission entities,

such as transmission-only utilities, it is time for the Commission

to take stock of its policies in order to determine whether they

appropriately support our dual goals of eliminating undue

discrimination and promoting competition in electric power

markets.\43\

\43\ Inquiry Concerning the Commission's Policy on Independent

System Operators, Notice of Conference, Docket No. PL98-5-000, at 1-

2 (March 13, 1998).

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Accordingly, the Commission held a series of eight conferences in 1998

to gain insight into participants' views on the formation and role of

ISOs in the electric utility industry. The first conference was held in

April 1998 at the Commission's offices in Washington, D.C. Between May

28 and June 8, 1998, the Commission held seven regional conferences in

Phoenix, Kansas City, New Orleans, Indianapolis, Portland, Richmond and

Orlando. As a result of these conferences, the Commission heard

approximately 145 oral presentations and received a large number of

written comments on the appropriate size, scope, organization and

functions of regional transmission institutions. A number of different

viewpoints were expressed. They will be discussed elsewhere in this

NOPR and are summarized in Appendix A hereto.

On October 1, 1998, the Secretary of Energy delegated his authority

under section 202(a) of the FPA to the Commission. In doing so the

Secretary stated that section 202(a) ``provides DOE with sufficient

authority to establish boundaries for Independent System Operators

(ISOs) or other appropriate transmission entities.'' \44\ The Secretary

also stated,

\44\ 63 FR 53889 (1998).

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FERC is also increasingly faced with reliability-related issues.

Providing FERC with the authority to establish boundaries for ISOs

or other appropriate transmission entities could aid in the orderly

formation of properly-sized transmission institutions and in

addressing reliability-related issues, thereby increasing the

reliability of the transmission system.

On November 24, 1998, we gave notice in this docket of our intent

to initiate a consultation process with State commissions pursuant to

section 202(a).45 The purpose of the consultations was to

afford State commissions a reasonable opportunity to present their

views with respect to appropriate boundaries for regional transmission

institutions and other issues relating to RTOs. Conferences with State

commissioners were held in St. Louis, Missouri on February 11, 1999; in

Las Vegas, Nevada on February 12, 1999; and in Washington, D.C. on

February 17, 1999. In all, we heard oral presentations by

representatives of 41 state commissions during these consultations,

with others monitoring or providing written comments.46

During these sessions, we received much valuable advice. We have set

forth in Appendix B a summary of the comments received, and discuss in

[[Page 31397]]

Section III.B below our response to some of the major concerns

expressed.

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\45\ Notice of Intent to Consult Under Section 202(a), 63 FR

66158 1998*), FERC Stats & Regs. para. 35,534 (1998).

\46\ See Appendix B for a list of commenters.

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C. Statutory Framework

The Commission is granted the authority and responsibility by FPA

sections 205 and 206, 16 U.S.C. 824d, 824e, to ensure that the rates,

charges, classifications, and service of public utilities (and any

rule, regulation, practice, or contract affecting any of these) are

just and reasonable and not unduly discriminatory, and to remedy undue

discrimination in the provision of such services. In fulfilling its

responsibilities under FPA sections 205 and 206, the Commission is

required to address, and has the authority to remedy, undue

discrimination and anticompetitive effects. The Commission has a

statutory mandate under these sections to ensure that transmission in

interstate commerce and rates, contracts, and practices affecting

transmission services, do not reflect an undue preference or advantage

(or undue prejudice or disadvantage) and are just, reasonable, and not

unduly discriminatory or preferential.47 Additionally, as

discussed in Order No. 888,48 there is a substantial body of

case law that holds that the Commission's regulatory authority under

the FPA ``clearly carries with it the responsibility to consider, in

appropriate circumstances, the anticompetitive effects of regulated

aspects of interstate utility operations pursuant to [FPA] Secs. 202

and 203, and under like directives contained in Secs. 205, 206, and

207.'' 49

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\47\ Once such a finding is made, the Commission is required to

remedy it. See, e.g., Southern California Edison Company, 40 FERC

para. 61,371 at 62,151-52 (1987), order on reh'g 50 FERC para.

61,275 at 61,873 (1990), modified sub nom., Cities of Anaheim v.

FERC, 941 F.2d 1234 (D.C. Cir. 1991); Delmarva Power and Light

Company, 24 FERC para. 61,199 at 61,466, order on reh'g 24 FERC

para. 61,380 (1983).

\48\ Order No. 888, FERC Stats. & Regs. at 31,669.

\49\ Gulf States Utilities Co. v. FPC, 411 U.S. 747, 758-59,

reh'g denied, 412 U.S. 944 (1973) (Gulf States). See also City of

Huntingburg v. FPC, 498 F.2d 778, 783-84 (D.C. Cir. 1974)

(Commission has a duty to consider the potential anticompetitive

effects of a proposed Interconnection Agreement.)

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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.

Further, section 202(a) of the FPA, whose authority has recently

been delegated to the Commission by the Secretary of

Energy,50 authorizes and directs the Commission ``to divide

the country into regional districts for the voluntary interconnection

and coordination of facilities for the generation, transmission, and

sale of electric energy * * *.'' The purpose of this division into

regional districts is for ``assuring an abundant supply of electric

energy throughout the United States with the greatest possible economy

and with regard to the proper utilization and conservation of natural

resources * * *.'' Section 202(a) states that it is ``the duty of the

Commission to promote and encourage such interconnection and

coordination within each such district and between such districts.''

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\50\ 63 FR 53889 (1998).

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III. Discussion

A. Barriers to Assuring an Abundant Supply of Electric Energy

Throughout the United States with the Greatest Possible Economy

In light of our experiences with ISOs and other utility

restructuring activity in the aftermath of Order Nos. 888 and 889, and

after almost three years of experience with implementation of Order

Nos. 888 and 889, we believe that there remain important transmission-

related impediments to a competitive wholesale electric market. We have

grouped these remaining impediments into two broad categories. The

first category of impediments consists of engineering and economic

inefficiencies inherent in the current operation and expansion of the

transmission grid--inefficiencies that, in and of themselves, are

hindering fully competitive power markets and imposing unnecessary

costs on electric consumers. The second category of impediments

consists of continuing opportunities for transmission owners to unduly

discriminate in the operation of their transmission systems so as to

favor their own or their affiliates' power marketing activities. Both

sets of impediments unnecessarily restrict the scope of bulk power

markets and inhibit the large-scale competition that we sought in

issuing Order Nos. 888 and 889.

The situation of the electric industry is somewhat analogous to the

natural gas industry after the initial step of open access

transportation was taken. In 1985, the Commission issued Order No.

436,51 which instituted open-access, nondiscriminatory

transportation of natural gas with the goal of increasing competition

and permitting gas users to purchase gas directly from gas merchants.

However, the Commission subsequently found that open access alone was

not sufficient to remove all barriers to competition. 52

Because of the different structures of the electric and gas industries,

the specific remaining impediments to competition may not be the same,

but there are similarities in that open access, without sufficient

mechanisms for ensuring that such access is equal and efficient for all

participants, may not be enough to promote a fully competitive market.

53

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\51\ Regulation of Natural Gas Pipelines After Partial Wellhead

Decontrol, Order No. 436, 50 FR 42408 (Oct. 18, 1985), FERC Stats. &

Regs. [Regulations Preambles 1982-1985] para. 30,665 1985), vacated

and remanded, Associated Gas Distributors v. FERC, 824 F.2d 981

(D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988), readopted on

an interim basis, Order No. 500, 52 FR 30334 (Aug. 14, 1987), FERC

Stats. & Regs. [Regulations Preambles, 1986-1990] para.30,761

(1987), remanded, American Gas Association v. FERC, 888 F.2d 136

(D.C. Cir. 1989), readopted, Order No. 500-H, 54 FR 52334 (Dec. 21,

1989), FERC Stats. & Regs. [Regulations Preambles 1986-1990] para.

30,867 (1989), reh'g granted in part and denied in part, Order No.

500-I, 55 FR 6605 (Feb. 26, 1990), FERC Stats. & Regs. [Regulations

Preambles 1986-1990] para. 30,880 (1990), aff'd in part and remanded

in part, American Gas Association v. FERC, 912 F.2d 1496 (D.C. Cir.

1990), cert. denied, 111 S. Ct. 957 (1991).

\52\ In the case of natural gas, we found that the principal

remaining barrier was the continued existence of bundled city-gate

firm sales service that had a transportation component of higher

quality than available through open access. Hence, we issued Order

No. 636 to unbundle services and equalize the quality of service

offered. See Pipeline Service Obligations and Revisions to

Regulations Governing Self-Implementing Transportation and

Regulation of Natural Gas Pipelines After Partial Wellhead

Decontrol, 57 FR 13267 (April 16, 1992), III FERC Stats. & Regs.

para. 30,939 (April 8, 1992), reh'g granted and denied in part,

Order No. 636-A, 57 FR 36128 (August 12, 1992), III FERC Stats. &

Regs. para. 30,950 (August 3, 1992), order on reh'g Order No. 636-B,

57 FR 57911 (December 8, 1992), 61 FERC para. 61,272 (1992), Notice

of Denial of Rehearing (January 8, 1993), 62 FERC para. 61,007

(1993), aff'd in part and vacated and remanded in part, United Dist.

Companies v. FERC, 88 F.3d 1105 (D.C. Cir. July 16, 1996), order on

remand, Order No. 636-C, 78 FERC para. 61,186 (1997).

\53\ For a discussion of the similarities and differences in the

structure and regulation of the natural gas and electric industries,

see generally Santa and Sikora, Open Access And Transition Costs:

Will The Electric Industry Transition Track The Natural Gas

Restructuring?, 15 Energy L.J. 273 (1994).

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Our current understanding of industry conditions, as set forth

below, will be enhanced by future consultations with and analysis from

all industry stakeholders, including state commissions. The Commission

seeks comments in order to achieve a deeper

[[Page 31398]]

appreciation of any impediments to competition in the Nation's

electricity markets and how they should be addressed.

1. Engineering and Economic Inefficiencies in the Operation, Planning

and Expansion of Regional Transmission Grids

The transmission facilities of any one utility in a region are part

of a larger, integrated transmission system. From an electrical

engineering perspective, each of the three interconnections in the

United States (the Eastern, the Western and ERCOT) operates as a single

``machine.'' 54 The Eastern Interconnection also extends

into Canada, and the Western Interconnection includes parts of Canada

and Mexico.

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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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This is not a new phenomenon. Since the very first transmission

interconnection between two neighboring utilities, interconnected

utilities have had to cope with the fact that electricity will flow

over others' lines. In the past, these effects were often small or

infrequent and the utility could generally pass any costs through to

captive customers. Today, with the increase in bulk power trade and the

large shifts in power flows, the effects may be large, frequent and not

recoverable by the utility bearing the cost.

Another important change is that the structure of the industry that

exists today is very different from the industry that existed three

years ago when we issued Order No. 888. The industry is no longer

composed uniformly of vertically-integrated, self-sufficient public

utilities that do not compete with each other. Instead, it is an

increasingly de-integrated and decentralized industry with many new and

existing participants that actively compete against each

other.56

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\56\ For example, there are now about 550 Commission-approved

power marketers. Decentralization has also increased because of

divestiture of generating plants by traditionally vertically

integrated utilities. Such sales are frequently required by state

governments as one element of the structural reforms that accompany

the introduction of retail competition. During the last three years,

utilities have sold or have contracts to sell more than 50,000 MW of

existing generating capacity. About 30,000 MW of additional capacity

is currently being offered for sale.

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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. 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.

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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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These stresses have always existed but not in these magnitudes.

Moreover, they could be more readily accommodated through voluntary ad

hoc agreements when there were fewer industry participants who

generally did not compete against each other in any significant

way.62 But as we have noted, this traditional industry

structure is rapidly disappearing. Our concern is that the reliability

fault lines may become more prominent and dangerous.

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\62\ In assessing the continued viability of the current system,

NERC's blue-ribbon Electric Reliability Panel concluded that: ``The

competitive dynamics among a much larger universe of players is not

at all conducive to a system of voluntary peer compliance.''

Electric Reliability Panel Report, December 1997, at 28.

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It is well accepted that the operation of interconnected

transmission networks requires careful coordination and the exchange of

information between many individual systems. Any operational change on

one system in the network instantly affects other systems. For example,

the shipment of power from one location to another will divide among

all transmission paths from source to destination based on the laws of

physics.63 This is referred to as

[[Page 31399]]

parallel path or loop flow. Such flows will also affect a neighboring

system's ability to determine ATC accurately. In addition, if a

transmission facility is already loaded close to its operating limit,

the additional flow resulting from a transaction contracted for on a

neighboring system may overload the facility and threaten reliability.

In order to operate the system in a reliable manner, a single,

independent grid operator must know all sources and destinations for

each transaction. The Commission believes that an RTO, as the only

transmission provider and security coordinator in its region, would

have the information needed to identify the effects of parallel flows

and accommodate them in its operations.

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\63\ The amount of power flowing on any path in an electrical

network is inversely proportional to that path's impedance.

Impedance will depend on the actual length of the line and its

voltage. See U.S. Congress, Office of Technology Assessment,

Electric Power Wheeling and Dealing: Technological Considerations

for Increasing Competition, OTA-E-409, May 1989, at 110-11.

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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).

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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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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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\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).

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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

[[Page 31400]]

part of a large interconnected grid to calculate ATC

accurately.74

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\73\ This, in turn, creates other problems. According to NERC,

the ``inconsistent calculation [of ATC] can increase the use of TLR

and other operational complexities, which has the potential to cause

reliability problems.'' NERC, Reliability Assessment, 1998-2007,

September, 1998, at 40. (See definition of TLR in section II.)

\74\ In addition, it has been frequently alleged that individual

transmission may intentionally post inaccurate ATC numbers to favor

their own power marketing efforts. These allegations are discussed

in section III.A.2.

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Second, requests for transmission service are usually based on

``contract path'' scheduling. This is the practice of finding a

contiguous chain of utilities from the power supplier to the power

consumer and contracting with those utilities to transmit the power.

The implicit assumption is that all the power flows through the

utilities along this ``contract path.'' In fact, the power divides up

and flows along all paths from the supplier to the buyer. All utilities

in the region are affected. Contract path scheduling provides little or

no information about actual flows on the grid.75 In its

October 1997 report to the Commission, the Commercial Practices Working

Group commented that: ``Reserving and scheduling transmission on a

contract path basis does not even closely resemble the physical impact

on the system.'' 76 We note that NERC is encouraging

initiatives that would move the industry toward recognizing actual

flows in scheduling.77

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\75\ See Allegheny Power Service Corporation et al., 78 FERC

para. 61,314 at 62,339.

\76\ October 31, 1997 report, at 39.

\77\ See NERC, 85 FERC at 62,363.

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c. Managing Congestion

Congestion occurs when requests for transmission service exceed the

capability of the grid. When transmission constraints limit the amount

of power that can be transmitted, the loads on the system may not be

able to be served by the least-cost mix of available generators. The

constraints may reflect voltage, temperature and dynamic limits.

Relieving congestion leads to a more costly pattern of generation

dispatch. The cost of congestion is the additional energy cost

associated with the new pattern of dispatch.

We recognize that even optimally designed systems will normally

experience at least occasional congestion that at times can be

significant and costly. In general, congestion can be managed in two

ways: the construction of new transmission facilities that increase

grid capacity; or the redispatch of existing or new generators to

reduce flows or create counterflows on the constrained facility. The

complete elimination of congestion would typically require the

construction of new transmission facilities. While this may be a

physically effective solution, it may not always be cost effective.

Because of this, we believe that an efficiently operated transmission

system should have in place mechanisms for pricing congestion and then

managing congestion through changes in the pattern of dispatch. Without

mechanisms for determining the cost of congestion, it will be virtually

impossible to make rational, cost effective decisions to expand the

grid.

The Commission believes that efficient congestion management is

best performed at the regional level. At present, outside of the

operational ISOs, transaction curtailment through transmission loading

relief (TLR) procedures is the dominant approach for dealing with

congestion in the Eastern Interconnection. NERC has reported that its

TLR procedures were invoked 329 times between July 1997 and October

1998 on the Eastern Interconnection.78 Current TLR

procedures are cumbersome, inefficient and disruptive to bulk power

markets because they rely exclusively on physical measures of flows

with no attempt to assess the relative costs of different congestion

management options. Moreover, TLR actions are typically taken by one

utility without assessing the costs imposed on other grid users. This

inevitably raises the suspicion that the TLR request could be motivated

by competitive rather than reliability concerns. For these reasons, the

Commission has encouraged NERC to develop regional market approaches to

managing congestion.79

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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. 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.

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\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'').

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d. Planning and Expanding Transmission Facilities

Transmission planning and expansion are more difficult today than

three years ago. While uncertainty has always been a fact of life for

any transmission planning exercise, the level of uncertainty has

increased with the increasing number and distance of unbundled

transactions and the wider variation in generation dispatch patterns.

Uncertainty has also increased because:

Generation developers are reluctant to disclose their plans for

future capacity additions. Similarly, utilities intending to

purchase from others are reluctant to speculate on whom or where

their suppliers might be, making modeling of such transactions for

transmission analysis virtually impossible.\82\

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

1998, at 39.

One troubling consequence of this uncertainty has been a noticeable

decline in planned transmission investments. NERC recently reported

that the level of planned transmission

[[Page 31401]]

additions is significantly lower than five years ago despite an overall

increase in load growth and unbundled transmission service.\83\ While

this could simply reflect better utilization of the existing grid, the

Commission is concerned that it may also reflect an incompatibility of

existing planning institutions with the new market realities.

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\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. The first utility may

be unwilling to expand transmission capacity because it needs no extra

transmission capacity itself, and the second utility may be unwilling

to expand transmission capacity because it collects no revenues from

the power flows scheduled by others. In a multi-utility region,

decisions about where to site new facilities and who should pay for

capacity expansions can be even more complex unless a regional body

provides a forum for discussions and a method for resolving disputes.

Second, the motivation for constructing new facilities is changing

as the industry changes. Formerly, a utility built transmission

primarily to deliver power from its generating plants to its customers.

Inadequate transmission would have hurt power sales, the principal

source of utility revenue. Today, facility expansion may be needed to

transmit power sold by others. As generation and transmission ownership

become increasingly separate and as many states implement or even

merely consider retail access, the transmission owner's traditional

incentive for making new transmission investment to support its power

sales erodes. Incentives for transmission investment need to be related

more to the power needs of the region than the generation stock of the

transmission owners.

Third, the transmission owner that does invest in transmission to

overcome a constraint may be concerned about recovering its investment.

Under traditional ratemaking practices, it must recover its investment

over a long period of time, typically thirty years. But subsequent

generation construction on the power-poor side of the constraint may

obviate the need for the line and threaten recovery of its capital

cost. In addition, where there is higher risk, a higher return

commensurate with the higher risk may be appropriate. To support this,

customers and regulators would want assurance that the decision to

invest in transmission is made in the best interests of the region,

considering not only all the transmission options but also the

generation and demand management alternatives to transmission

construction. Therefore, as discussed below, we will consider concrete

proposals from regional transmission organizations for transmission

pricing reforms and the explicit use of pricing incentives to encourage

RTOs to make efficient investments in new transmission facilities.

e. Pancaked Transmission Rates

With the exception of power pools, open access under Order No. 888

focuses on individual, existing transmission providers. Order No. 888

does not require transmission pricing reforms that are needed to

support efficient and competitive bulk power markets. The ``missing''

reforms include, among others, the elimination of pancaked transmission

access charges, the use of reservation-based (as opposed to load-based)

transmission tariffs and the availability of secondary markets in

transmission rights.84 In this section, we will focus on the

problems created by the widespread pancaking of transmission access

charges.85

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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

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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.

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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.

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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.

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\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.

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f. Conclusion

We believe that the preferred solution to the engineering and

economic problems discussed in this section is a regional solution.

Notwithstanding it success, Order No. 888 has not been able to produce

a fully efficient and competitive outcome because it does not address

ATC calculations, congestion

[[Page 31402]]

management, reliability, pancaking of transmission access charges, and

grid planning and expansion. These are regional problems. Therefore, we

are proposing a rule to encourage the development of independent

regional transmission operators that can promote both electric system

reliability and competitive generation markets.

2. Actual and Perceived Discriminatory Conduct by Transmission Owners

to Favor Their Own or Affiliated Merchant Operations

In addition to operational inefficiencies impeding full

competition, there also exist questions about residual discrimination

in the provision of transmission services by public utilities. As

discussed below, many in the industry have expressed a fundamental

mistrust of transmission owners. In addition, there are allegations,

and in some circumstances findings, of actual discrimination by

transmission owners. We discuss below indications of discriminatory

conduct by vertically integrated utilities and seek further comment on

utility practices subsequent to Order No. 888.

Utilities that control monopoly transmission facilities and also

have power marketing interests 90 have poor incentives to

provide equal quality transmission service to their power marketing

competitors. It is, in fact, in the economic self-interest of

transmission-owning utilities to favor their own power marketing

interests and frustrate their competitors. As the Commission stated in

Order No. 888:

\90\ The term power marketing interests is used as shorthand

herein to include the utility's own wholesale merchant function as

well as any affiliates with wholesale merchant functions.

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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. 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.

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

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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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\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.

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\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. First, we may

be seeing only the ``tip of the iceberg.'' We are aware that instances

of actual discriminatory conduct may be undetectable in a non-

transparent market. In addition, there are significant disincentives to

filing and pursuing formal complaints that would result in definitive

findings. Transmission customers often tell the Commission's

enforcement staff that they are reluctant to make even informal

complaints because of concerns that the Commission will not take strong

action, and fear, perhaps most importantly, of retribution by their

transmission supplier.95 We also have been told that

[[Page 31403]]

the complaint process is costly and time-consuming,96 and

that the Commission's remedies for transmission violations do not

impose sufficient financial harms on the transmission provider to act

as a significant deterrent.97

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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).

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Perhaps the most problematic aspect of relying on after-the-fact

enforcement in the fast-paced business of power marketing, however, is

that there may be no adequate remedy for lost short-term sale

opportunities. For example, the Electric Power Supply Association has

told us:

Furthermore, even if the exercise of such discrimination could

be adequately documented and packaged in the form of a complaint

under Section 206 of the Federal Power Act under a more streamlined

complaint process contemplated by the Commission, it would still be

extremely costly and inefficient to deal with such complaints on a

case-by-case basis. More than likely, the potential power

transactions for which transmission principally was sought would

disappear by the time a Commission ruling was obtained.98

\98\ Motion to Intervene and Comments of Electric Power Supply

Association in Support of Petition for Rulemaking, Docket No. RM98-

5-000 (filed Sept. 21, 1998), at 3.

Accordingly, actual problems with functional unbundling may be more

pervasive than formally adjudicated complaints would suggest, and the

informal allegations we hear provide valuable insight.

Second, we consider the allegations of discrimination to be serious

because, if nothing else, they represent a perception by market

participants that the market is not working fairly because such

participants know that integrated utilities have the incentive and

opportunity to discriminate. Mistrust in the market can itself be a

serious impediment to competition. If market participants perceive that

other participants have an unfair advantage through the affiliation

with the transmission provider, it can inhibit their willingness to

participate in the market, including, for example, building new

generating units, thus thwarting the development of robust competition.

Such mistrust can also harm reliability. As stated by NERC, there is a

reluctance on the part of market participants to share operational

real-time and planning data with transmission providers because of the

suspicion that they could be providing an advantage to their affiliated

marketing groups.99

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

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The functional unbundling policy underlying Order No. 888 was an

attempt to regulate the behavior of transmission owners. There are

growing indications, however, that the conflicting incentives that

vertically integrated utilities have regarding transmission access may

be too difficult to police. Many have asserted that it is not realistic

even to expect functional unbundling to eliminate attempts by

transmission owners to gain economic advantage. Companies have an

obligation to maximize value for shareholders, and it should be no

surprise that they will be aggressive in doing so. For example, in

comments to the Commission in the Order No. 888 proceeding, the Federal

Trade Commission advised the Commission that a functional unbundling

approach ``* * * would leave in place the incentive and opportunity for

some utilities to exercise market power in the regulated system.

Preventing them from doing so by enforcing regulations to control their

behavior may prove difficult.'' A representative of Lafayette Utilities

told us at the New Orleans ISO Conference:

Notwithstanding functional separation and the requirement not to

discriminate, transmission personnel are well aware of the interests

of their company's generation function, and can find a way to give

preferential treatment. * * * 100

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\100\ Comments of Frank Ledoux on behalf of Lafayette Utilities

System, Regional ISO Conference (New Orleans), Transcript at 180.

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

A representative of a Wisconsin public utility told us:

Administration of the tariff entails a myriad of decisions that

require discretion, as well as ``technical'' judgments (like

[available transmission capability] and [capacity benefit margin])

that have significant competitive ramifications. It is inevitable

that these decisions and judgments will be made with competitive

concerns in mind. Functional separation does not solve this

problem.101

\101\ Statement of Roy Thilly on behalf of Wisconsin Public

Power, Inc. at 2, Docket No. PL98-5-000 (filed April 15, 1998).

Similarly, at our regional ISO conference in Indianapolis, we were

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told:

In a capital intensive industry where a high percentage of the

investment is in generation assets, it is inconceivable that a

utility, which in some cases has very high generation cost, would

somehow manage its transmission system so as not to give its

generation a competitive advantage. I think this is self-

evident.102

\102\ Comments of Kenneth Hegemann on behalf of American

Municipal Power, Ohio, Regional ISO Conference (Indianapolis),

Transcript at 174.

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While it should not be assumed that such problems exist in every

circumstance, clearly many market participants do not believe the

market can yet be trusted with respect to their commercial interests,

at least in some areas. We now turn to some of the areas that have

produced the most complaints about continuing discrimination.

a. Calculation and Posting of Available Transmission Capability in a

Manner Favorable to the Transmission Provider

Perhaps the most significant complaint with respect to alleged

discriminatory conduct under functional unbundling concerns the

important function of calculating and posting the amount of

transmission capability that is available on a transmission provider's

system. The transmission provider is required to calculate and post on

its OASIS the TTC and ATC for each posted transmission

path.103 ATC is the capacity that is stated to be available

for transmission service requests. As we discussed above in Section

III.A.1, it is not possible to calculate accurately the transmission

capability of one system without knowing the flows scheduled by all

other interconnected transmission providers in the region. Given this

technical problem, it may be impossible to distinguish an inaccurate

ATC presented in good faith from an inaccurate ATC presented for the

purpose of favoring the transmission provider's marketing interests.

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

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Transmission providers with power marketing interests have

incentives to understate ATC on those paths valuable to its marketing

competitors, or to divert transmission capacity so that it is available

for use by its own marketing interests. If there is insufficient ATC,

competitors may be forced to forego power sale transactions or use a

less desirable alternative path if one is available.

The Commission has found violations of ATC postings in three cases.

In Washington Water Power Company,104 the transmission

owning utility showed that it had no firm ATC, which would have

discouraged any potential marketers who needed firm transmission

service to make a sale. However, the utility then offered its power

marketing affiliate, Avista

[[Page 31404]]

Energy, an ``interruptible firm'' transmission service that was not

available to competitors. As the Commission explained in finding a

violation of Order No. 888:

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

61,282 (1998).

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Avista received a preference from Washington Water Power that

was not available to any of its competitors. Simply stated, Avista's

customer was deprived of the benefit of choosing among all potential

power suppliers.

The case of Wisconsin Public Power Inc. SYSTEM v. Wisconsin Public

Service Corporation, et al. (Wisconsin Public) 105

demonstrates both the difficulties and suspicions of discrimination

resulting from when a transmission customer requests transmission

service from an integrated utility. WPPI was seeking additional network

transmission service from both Wisconsin Public Service Corporation

(WPSC) and Wisconsin Power & Light Company (WP&L). In both cases, the

requests were denied because of claims that the transmission owners

were using all available capacity. In the case of WPSC, the Commission

initially found that the utility had not properly reserved capacity for

its merchant function and directed that it recompute its ATC without

that reservation. After WPSC submitted additional documentation, the

Commission accepted some of WPSC's merchant priority, but still found

that it had violated its obligations under its tariff, and that its

actions raised serious concerns about the functional separation of its

staff. With respect to WP&L, the Commission found that it provided

unduly preferential treatment to its merchant function, had been

changing its ATC without posting those changes on OASIS, and had been

computing ATC where none exists.106

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\105\ 83 FERC para. 61,198 (1998), order on reh'g, 84 FERC para.

61,120 (1998).

\106\ 83 FERC at 61,860.

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The Wisconsin Public cases demonstrate, if nothing else, the

difficulty of achieving, and enforcing, functional separation of a

utility's transmission and merchant functions. These types of cases

require substantial Commission investigative and adjudicative

resources, not to mention the resources of the parties involved. The

Commission recognized in Wisconsin Public how RTOs could help eliminate

these problems. The Commission stated:

As we recently explained in Louisville Gas & Electric Company,

et al., 82 FERC para. 61,308 at 62,222 & n. 39 (1998), a properly

structured ISO, or other transmission entity can eliminate the

potential for the strategic use of a transmission owner's priority

to use internal system capacity for native load. The ISO or other

transmission entity can also eliminate the incentive to engage in

strategic curtailments of generation that a transmission operator's

generation service competitors own and can remove any incentive to

game OASIS operations. This will promote generation entry and

competition, since a properly structured ISO or other transmission

entity would have no economic stake in favoring certain market

participants over others and potential entrants would likely see the

transmission market as fair. An ISO, therefore, could help to solve

the problems established in the instant complaints.107

\107\ Id. at 61,859.

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The case of Morgan Stanley Capital Group v. Illinois Power Company

108 also demonstrated problems associated with ATC and a

transmission provider's use of its system for its own purposes. Morgan

Stanley complained that Illinois Power failed to accurately post ATC,

failed to award transmission capacity in a non-discriminatory manner,

and allocated transmission in favor of its own bulk power marketing

arm. Illinois Power admitted the ATC posting error, and the Commission

found other violations of its tariff in responding to Morgan Stanley's

request for service. Although the Commission initially also found that

Illinois Power did not designate its own network resources in the same

manner as network customers are required to designate them, Illinois

Power disputed this, and after showing that its network resource was

legitimate, the Commission dismissed its rehearing as moot.

Nevertheless, this case demonstrates that a combination of ATC errors

and unclear procedures feeds the mistrust in the marketplace with

respect to a transmission owner's ability to use its system to favor

itself.

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\108\ 83 FERC para. 61,204, order granting clarification and

dismissing reh'g, 83 FERC para. 61,299 (1998).

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We also have currently pending before us several formal complaints

alleging that a transmission provider is improperly keeping its

transmission capability for its merchant function. In one case, a power

marketer asserts that a transmission provider has refused service over

an interconnection on the basis that the transmission provider needs

all the ATC for native load. The marketer has alleged that the

transmission provider's claims of reliability concerns are a mask to

block competitors from importing power into the transmission provider's

system when the transmission provider has higher cost generation

available.109 In another recent formal complaint filing, it

is alleged that a transmission provider denied transmission service and

then improperly provided it to its merchant group.110

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\109\ Aquila Power Corporation v. Entergy Services, Inc., Docket

No. EL98-36-000, Amended and Restated Complaint at 6 (filed June 23,

1998).

\110\ Arizona Public Service Company v. Idaho Power Company,

Docket No. EL99-44-000 (filed March 3, 1999).

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Aside from these cases involving formal complaints, there have been

a number of other complaints with respect to ATC calculation. For

example, our enforcement staff receives hotline complaints concerning

ATC posting problems. The enforcement staff has confirmed a number of

such ATC errors. In most cases, these errors were corrected within

several months of having them pointed out, and the utilities often

offered explanations based on hardware or software problems. We make no

judgment whether such identified errors were an intentional attempt to

thwart competition; however, they had the potential to have that

effect.

In July 1997, the Commission held a technical conference concerning

how well the OASIS system was working. Several commenters suggested

that erroneous ATC calculation and posting was hurting competition. A

representative from Electric Clearinghouse told us that there is a

pervasive problem of incorrect or stale information on the OASIS sites,

and that ``competition is blocked when this occurs.'' That same

representative stated that very little firm ATC is offered due to the

utility's caution or strategy, and that some providers will not offer

firm ATC because they do not want to curtail their own

transactions.111 At the same conference, a representative

from the American Public Power Association told us:

\111\ Open Access Same Time Information Technical Conference,

Docket No. RM95-9-003 (July 18, 1997), transcript at 23.

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ATC is often understated and inconsistently posted on adjacent

OASIS nodes. Inter-regional coordination is lacking. This fact

limits the usefulness of the system for commercial

purposes.112

\112\ Id. at 28.

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In March 1998, a group referring to themselves as power industry

stakeholders 113 filed a petition for rulemaking on electric

power industry structure.114 Although we are not addressing

here the specific relief they are requesting in that Petition, the

[[Page 31405]]

Petition does contain a number of fairly specific allegations

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indicating problems in the market. For example, the Petition asserts:

\113\ The group consists of a number of power marketers and

users, including, for example, Coalition for a Competitive Electric

Market, ELCON, Electric Clearinghouse, Inc., and Enron Power

Marketing, Inc.

\114\ Petition for a Rulemaking on Electric Power Industry

Structure and Commercial Practices and Motion to Clarify or

Reconsider Certain Open-Access Commercial Practices, Docket No.

RM98-5-000.

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Concepts such as ATC and the OASIS have become vehicles for

obstructing and curtailing, rather than accommodating, transactions.

Incumbents are able to deny new entrants access to critical,

accurate information across control areas. This can take the form of

out-of-date or incorrect postings of ATC or, in some instances,

intentional withholding of actual ATC. Regardless of the cause, more

transmission capability is physically available than is being

released for sale.115

\115\ Petition at 7-8.

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The Petition alleges the existence of ``ATC exclusions,

inaccuracies and misuses that deny new entrants the ability to evaluate

market opportunities, and therefore, prevent reasonable access to the

grid.'' 116 The Petition cited specific instances of

inconsistent ATC calculations for the same interconnection by the

systems on either side; an OASIS showing ATC that was not in fact made

available for scheduling; and an OASIS showing no ATC but the utility

then using that path for a sale.117

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\116\ Id. at 15.

\117\ Id. at Appendix D.

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EPSA, the trade association representing certain power suppliers,

filed comments in support of the Petition and echoed many of the same

experiences:

EPSA agrees that this discriminatory conduct persists

principally because of the continuing incentives and opportunity for

transmission owning public utilities covertly to discriminate

against other transmission customers, by, for example, minimizing

reported available transmission capability (ATC), delaying or

inaccurately posting ATC on the OASIS, or otherwise manipulating

market operations.118

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

September 21, 1998).

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EPSA further stated that, ``The manipulation of ATC--whether with

the intent to deceive or as the result of poor OASIS management--is a

serious entrance barrier for competitive power suppliers.''

119

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\119\ Id. at 8.

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At our regional ISO conference in New Orleans, we were told by a

representative from the Public Service Commission of Yazoo City,

Mississippi, of a specific instance of what it considered to be

discriminatory treatment:

Yazoo City, as a participant, has experienced first hand an

individual [transmission] owner's continued ability to use its

ownership and control [of] transmission to disadvantage competitors,

notwithstanding Order 888's mandate of non-discriminatory

transmission access.

The representative then went on to describe an instance where a

marketer could not complete a 10 MW power sale because of transmission

restrictions, but then the transmission provider offered to supply the

capacity itself.120 The representative concluded that Orders

Nos. 888 and 889 have not fully eliminated undue discrimination and

this will not be achieved ``as long as transmission owners are allowed

to fence in transmission-dependent utilities and others located on

their transmission system to enhance the value of their generation

assets at increased cost to competitors.''

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\120\ Comments of Rebert D. Priest on behalf of the Public

Service Commission of Yazoo City, Regional ISO Conference (New

Orleans), Transcript at 201-03. After hearing this assertion,

Entergy Services, Inc. filed a letter in which it stated that it was

unable to identify any Entergy-imposed restrictions that would have

prevented the power purchase. See Letter in Docket No. PL98-5-000

(filed July 1, 1998).

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One specific area where there have been allegations that

transmission owners are using ATC to favor their own merchant

operations concerns the calculation and use of Capacity Benefit Margin

(CBM). Although there is no single accepted definition, CBM is

generally used to mean an amount of transmission transfer capability

reserved by load serving entities to ensure access to generation from

interconnected systems to meet their generation reliability

requirements.121 Some utilities subtract CBM from their

total transmission capability to arrive at ATC. There is no uniform

method for calculating CBM. The ability to withhold CBM to ensure

reliability not only confers a reliability advantage for the

transmission provider, but may give the transmission provider the

opportunity to selectively withhold ATC over paths and interconnections

useful to its generation competitors.

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\121\ NERC, Available Transfer Capability Definitions and

Determinations (June 1996), at 14.

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The use of CBM is an issue that is currently being considered in

several cases pending before the Commission.122 For example,

with respect to the formation of the PJM ISO, the Commission noted that

it was not demonstrated that the PJM Pool's historical practice of

withholding firm transmission interface capacity as a substitute for

installed generating reserves is consistent with our open access

policies. The Commission observed that the load serving entities that

own generating capacity within the PJM control area appeared to benefit

from this practice as suppliers in addition to benefitting as load

serving entities.123 The Commission set the issue for

further briefing and it remains pending. In another pending proceeding

concerning WPSC's CBM calculation, two of the parties assert that CBM

``removes firm transmission capacity from open access offerings,

thereby raising an unnecessary and unjustifiable barrier to

competition,'' and ``fosters discrimination by giving merchant

functions gatekeeping control over CBM-related transmission access and

by giving individual interface transmission owners broad discretion

over where and how much CBM is withdrawn from ATC.'' 124 In

the same proceeding, Electric Clearinghouse, Inc. asserts that ``the

CBM set-aside embodies undue discrimination in access to the monopoly

owned transmission wires because it ensures certain users a priority

over the reserved transmission interface capacity to the exclusion of

other firm transmission users.'' 125

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\122\ The Commission recently noticed a technical conference, to

be held May 20 and 21, 1999, on the issue of CBM. See Capacity

Benefit Margin in Computing Available Transmission Capacity, Notice

of Technical Conference, Docket No. EL99-46-000.

\123\ PJM, 81 FERC at 62,277.

\124\ Protest of Madison Gas & Electric Company and Wisconsin

Public Power Inc., Docket No. EL98-2-003 at 3 (filed August 21,

1998).

\125\ Protest of Electric Clearinghouse, Inc., Docket No. EL98-

2-003, at 3 (filed Ausust 21, 1998).

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As we stated above, we fully recognize that these are assertions

made in pending cases in which we have not yet made findings. They are

referenced here as illustrative of the suspicions in the industry of

continuing opportunities for discriminatory treatment that may

disadvantage certain competitors where generation owners continue to

operate transmission.

b. Standards of Conduct Violations

To ensure the functional separation of a transmission provider's

transmission and merchant functions, the Commission adopted standards

of conduct that prohibit the transmission provider's marketing interest

employees from having any more access to transmission system

information than is available on OASIS, and requires the transmission

provider's transmission employees to provide impartial service to all

transmission customers.126 If a transmission provider's

marketing interests have favorable access to transmission system

information or receive more favorable treatment of their transmission

requests, this obviously creates a disadvantage for marketing

competitors.

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

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

perception by

[[Page 31406]]

many market participants that the transmission provider's marketing and

transmission interests are not fully functionally separated. In cases

in which the Commission has issued formal orders, we have found serious

concerns with functional separation and improper information sharing

with respect to at least four public utilities.127 In

addition, our enforcement staff receives numerous telephone calls about

standards of conduct issues; some of these are simply questions about

what is permissible conduct, but others are complaints of a violation.

In a number of cases, our staff has verified non-compliance with the

standards of conduct.128

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\127\ See Wisconsin Public, 83 FERC at 61,855, 61,860 (WPSC's

actions raised ``serious concerns'' as to functional separation;

WP&L's actions demonstrated that it provided unduly preferential

treatment to its merchant function); Washington Water Power, 83 FERC

at 61,463 (utility found to have violated standards in connection

with its marketing affiliate); Utah Associated Municipal Power

Systems v. PacifiCorp, 87 FERC para. 61,044 (1999) (finding that

PacifiCorp had failed to maintain functional separation between

merchant and transmission functions).

\128\ See, e.g., Communications of Market Information Between

Affiliates, Docket No. IN99-2-000, 87 FERC para. 61,012 (1999)

(Commission issued declaratory order based on hotline complaint

clarifying that it is an undue preference in violation of section

205 for a public utility to tell an affiliate to look for a

marketing offer prior to posting the offer publicly).

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The petitioners for rulemaking in Docket No. RM98-5-000 allege that

there are common instances of ``unauthorized exchanges of competitively

valuable information on reservations and schedules between transmission

system operators and their own or affiliated merchant operation

employees.'' 129 They also cite OASIS data showing an

instance where a transmission provider quickly confirmed requests for

firm transmission service by an affiliate, while service requests from

independent marketers took much longer to approve.

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\129\ Petition at 15.

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We believe that some of the identified standards of conduct

violations are transitional issues resulting from a new way of doing

business, and we acknowledge that many utilities are making good-faith

efforts to properly implement standards of conduct. However, we also

believe that there is great potential for standards of conduct

violations that will never even be reported or detected. The use of

standards of conduct is not the optimal procedure for ensuring a fair

marketplace, and may be unnecessary in a properly structured and

operated market.

We are increasingly concerned about the extensive regulatory

oversight and administrative burdens that have resulted from policing

compliance with standards of conduct. We have discussed above some of

the cases in which the Commission had to address potential violations

of the standards of conduct. In addition, transmission providers were

required to file their standards of conduct for Commission review. In

response, the Commission initially issued 8 orders concerning 126

public utilities' standards of conduct.130 Generally, these

orders required the utilities to revise their standards of conduct and

post, on the OASIS, organizational charts and job descriptions for

transmission/reliability and wholesale merchant function employees. The

Commission subsequently issued 13 more orders requiring the public

utilities to further revise their standards of conduct and/or

organizational charts and job descriptions.131 The

Commission has also issued three orders on rehearing of the standards

of conduct orders.132

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\130\ The citations for these orders are: 81 FERC para. 61,332

(1997), 81 FERC para. 61,338 (1997), 81 FERC para. 61,339 (1997), 82

FERC para. 61,028 (1998), 82 FERC para. 61,073 (1998), 82 FERC para.

61,132 (1998), 82 FERC para. 61,193 (1998) and 82 FERC para. 61,246

(1998).

\131\ The citations for these orders are: 84 FERC para. 61,131

(1998), 84 FERC para. 61,255 (1998), 84 FERC para. 61,320 (1998), 84

FERC para. 61,327 (1998), 85 FERC para. 61,068 (1998), 85 FERC para.

61,145 (1998), 85 FERC para. 61,227 (1998), 85 FERC para. 61,390

(1998), 86 FERC para. 61,044 (1999), 86 FERC para. 61,079 (1999), 86

FERC para. 61,146 (1999), 86 FERC para. 61,185 (1999) and 86 FERC

para. 61,246

\132\ The citations for these orders are: 82 FERC para. 61,131

(1998), 83 FERC para. 61,357 (1998), and 85 FERC para. 61,382

(1998).

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As of April 1, 1999, 51 utilities' standards of conduct and

organizational charts and job descriptions have been accepted and 75

utilities' standards of conduct and/or organizational charts and job

descriptions have not been accepted and are pending review. This is an

indication of the significant regulatory effort required by both public

utilities and the Commission to make the standards of conduct approach

workable--a regulatory effort that could be greatly reduced through

more distinct organizational separation.

c. Line Loading Relief and Congestion Management

A number of complaints have been made alleging that transmission

providers are acting in a discriminatory manner in implementing line

loading relief, which is required when a transmission line is in danger

of being overloaded. Such complaints allege that the transmission

providers are not providing redispatch service, are favoring their own

transactions, and are failing to follow curtailment priorities

established in Order No. 888.133 All of these actions by

transmission providers may provide subtle competitive advantages in

wholesale markets. For example, for those purchasers for whom service

reliability is particularly important, purchasing power from a

transmission provider may be viewed as offering enhanced reliability.

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\133\ We set for evidentiary hearing a formal complaint by

Wisconsin Electric Power Company making these types of allegations.

Wisconsin Electric Power Company v. Northern States Power Company

(Minnesota) and Northern States Power Company (Wisconsin), 86 FERC

para. 61,121 (1999). The parties subsequently filed a settlement

agreement.

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Like the issue of calculating ATC, the fact that curtailment of

service in times of congestion is in the control of the transmission

provider, who also has power transactions on the affected transmission

lines, leads to suspicions of discriminatory behavior that are

difficult to verify. For example, a representative of Blue Ridge Power

Agency told us at one of our ISO conferences:

There simply is no shaking the notion that integrated generation

and transmission-owning utilities have strategic and competitive

interests to consider when addressing transmission constraints.

Functional unbundling and enforcement of [standard of] conduct

standards require herculean policing efforts, and they are not

practical. 134

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

Likewise, we were told at another ISO conference that operators

with reliability responsibility possess actual controlling authority

over transactions, ``thereby giving them a tremendous advantage over

competitors.'' 135

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\135\ Comments of Marvin Carraway on behalf of Clarksdale Public

Utilities Commission, Regional ISO Conference (Kansas City),

Transcript at 107.

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d. OASIS Sites That Are Difficult To Use

Aside from the problems alleged with respect to posting inaccurate

ATC calculations on OASIS sites, there have been complaints that some

transmission providers have implemented their OASIS sites as a tool to

impede competition rather than as it was intended--as a tool to foster

competition. It has been alleged that transmission providers have no

incentive to make the sites easier to use, because it is primarily the

transmission providers' marketing competitors who would benefit from

better OASIS sites. 136 The petitioners in Docket No. RM98-

5-000 asserted:

\136\ See, e.g., Comments of representative from Enron Power

Marketing speaking at Commission's July 1997 OASIS Technical

Conference, transcript at 43-44.

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[[Page 31407]]

Indeed, to gain a competitive advantage over those who are

dependent on the timeliness and accuracy of OASIS, vertically

integrated transmission owners have an incentive to make OASIS as

slow and uninformative as possible.137

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\137\ Petition at 37.

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Similarly, EPSA has told us that ``the present transmission regime

gives existing transmission-distribution utilities an inherent

advantage to reserve capacity for their own native load use, and

provides them with no incentive to maintain a properly functioning

OASIS.'' 138

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

September 21, 1998).

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As we stated above with respect to ATC calculation, we are not in a

position to make a judgment that transmission providers are

deliberately making their OASIS sites difficult to use in order to

disadvantage marketing competitors. In fact, we are aware that some

OASIS sites are well run and engender few complaints from users, and

that there may be legitimate technical and transitional difficulties

responsible for some of the problems complained of. However, this is

another example of the situation where market participants perceive

discriminatory intent, whether or not one exists, because of the

apparent opportunity and incentive to discriminate.

e. Other Issues Related to Functional Unbundling and Dealing With

Remaining Undue Discrimination

While the Commission here has not attempted to provide an

exhaustive compilation of the remaining opportunities for

discriminatory practices by transmission operators who are also in the

power business,139 it believes that the potential for such

problems increases in a competitive environment unless the market can

be made structurally efficient and transparent with respect to

information, and equitable in its treatment of competing participants.

We invite public comments on the extent to which there remains undue

discrimination in transmission services, and if it remains, in what

forms. Those comments should address both the areas of alleged

discrimination we have discussed above, as well as any other areas that

commenters may have experienced. In addition, we are asking for

comments about what remedies we should impose in an effort to eliminate

any remaining discriminatory conduct. For example, should we require

mandatory participation in an RTO, or are there other possible

remedies? Could a performance-based rate system be designed to realign

economic interests to remove the motive for discrimination?

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\139\ There have been other violations alleged. For example,

many relate to pricing and discounting.

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One thing that seems apparent is that a system that attempts to

control behavior that is motivated by economic self-interest through

the use of standards of conduct will require constant and extensive

policing. This kind of regulation goes beyond traditional price

regulation and forces us to regulate very detailed aspects of internal

company policy and communication. For functional unbundling to be

successful, we have to be concerned, in some sense, about ``who spoke

to whom'' in the company cafeteria. Functional unbundling does not

necessarily promote light-handed regulation. It also undoubtedly

imposes a cost on those entities that have to comply with the standards

of conduct who face additional training and rules that create

rigidities in their internal management activities.

It appears, based upon our experience thus far, that no matter how

detailed the standards of conduct and how intensive our enforcement,

competitors will continue to be suspicious that the wall between

transmission operations and power sales is being breached in subtle and

hard to detect ways. The perception that many entities that operate the

transmission system cannot be trusted is not a good foundation on which

to build a competitive power market. It creates needless uncertainty

and risk for new investments in generation.

In section III.B below, we will address how the use of independent

RTOs can help eliminate the opportunity for unduly discriminatory

practices by transmission providers, restore the trust among

competitors that all are playing by the same rules, and reduce the need

for overly intrusive regulatory oversight.

B. Benefits That Regional Transmission Organizations Can Offer

In the preceding sections, we have set forth what we consider to be

at least some of the remaining transmission related impediments to full

competition in the electricity markets. These impediments include

engineering and economic inefficiencies in the operation and structure

of the existing transmission grid that inhibit the development of

broad-based markets for electric power, and remaining opportunities for

discriminatory practices by transmission owners with power marketing

interests.

We now believe that the establishment of properly structured RTOs

throughout the U.S. can effectively remove the remaining impediments to

competition in the power markets. As discussed elsewhere in this NOPR,

a properly structured RTO will be an entity that is independent from

all generation and power marketing interests, and has the exclusive

responsibility for grid operations, short-term reliability, and

transmission service within a region. Such an entity would not only

confer benefits related to removing impediments to competition, but

would also enhance reliability and allow for less intrusive government

regulation of transmission providers.

We note that the Commission's recognition of the benefits of

regional transmission organizations is not new. The Commission has

encouraged the industry to create such institutions for more than six

years. In 1993, the Commission issued a policy statement encouraging

the formation of RTGs, which were defined as voluntary organizations of

transmission owners, users, and other entities interested in

coordinating transmission planning (and expansion), operation and use

on a regional and inter-regional basis. 140 The Commission

summarized the benefits of such entities as enabling the market for

electric power to operate in a more competitive, and thus more

efficient manner; providing coordinated regional planning of the

transmission system to assure that system capabilities are adequate to

meet system demands; decreasing the delays that are inherent in the

regulatory process, resulting in a more market-responsive industry; and

resolving technical transmission issues (e.g., loop

flow).141

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\140\ Policy Statement Regarding Regional Transmission Groups,

FERC Stats. & Regs. para. 30,976 at 30,870 and n.4 (1993) (RTG

Policy Statement).

\141\ RTG Policy Statement, FERC Stats. & Regs. at 30,871.

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One year later, the Commission issued a transmission pricing policy

statement which encouraged RTGs to address transmission pricing and

offered to provide more latitude to RTGs than to individual utilities

for innovative pricing proposals, recognizing that issues such as loop

flow required a regional approach.142 Then, two years after

that in Order No. 888, the Commission encouraged the industry to

consider ISOs, and gave specific guidance on characteristics and

functions in the form of 11 principles.

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\142\ Inquiry Concerning the Commission's Pricing Policy for

Transmission Services Provided by Public Utilities Under the Federal

Power Act, 59 FR 55031 (November 3, 1994), FERC Stats. & Regs.,

Regulations Preambles para. 31,005, at 31,140, 31,145 (Transmission

Pricing Policy Statement.)

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[[Page 31408]]

The Commission has not been alone in recognizing the benefits of

RTOs. In fact, there is surprising unanimity about the benefits of

regional transmission solutions to grid management. For example, the

Edison Electric Institute adopted a resolution that ``recognizes the

potential benefits of voluntary grid regionalization in addressing

pancaked transmission rates, congestion management and reliability,

transmission planning, and market power * * *'' and supported

``flexible, voluntary, market-based approaches'' toward grid

regionalization.143 The American Public Power Association

has stated that ``mandating RTOs will prevent further inequities in the

provision of wholesale transmission service, provide guidance to the

states, advance regional solutions to reliability issues to head off

future crisis situations such as the 1998 Midwest Price Spikes, and

partially mitigate serious market power concerns that have arisen due

to the high number of recent mergers in the electric utility

industry.'' 144 The National Energy Marketers Association

urges the Commission to ``take bold steps necessary to create larger

regional transmission organizations (RTOs) and to force maximum

participation into (sic) these organizations.'' 145 Other

industry groups representing very different interests have reached

similar conclusions.146

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\143\ Edison Electric Institute, Resolution Regarding Grid

Regionalization, adopted by the Board of Directors, January 7, 1999.

\144\ Motion of American Public Power Association For Leave To

Lodge, Docket No. RM99-2-000, filed March 17, 1999, at 2.

\145\ NEA, ``National Guidelines For Restructuring The Electric

Generation Transmission and Distribution Industries,'' January 1999,

at 6.

\146\ The Electric Power Supply Association recommends that

``ISOs Must be Regional in Scope.'' (EPSA Position Statement on

Independent System Operators, January 1997, at 1.) The Electricity

Consumers Resource Council (ELCON) states that ``a competitive

electricity marketplace requires the formation of large, regional

independent system operators.'' (ELCON, ``Independent System

Operators,'' Profiles On Electricity Issues, No. 18, March 1997, at

2.

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States are also recognizing the need for regional approaches to

grid operation. At least five states have passed laws or issued

regulations requiring transmission owning utilities in their states to

participate in regional transmission entities.147 Other

state regulators have highly praised the new regional transmission

entities that are functioning in their regions.148

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\147\ Laws to encourage participation in regional ISOs or

transcos have been passed in Wisconsin, Illinois, Virginia, and

Arkansas. Regulations to encourage this outcome have been issued by

the Nevada commission.

\148\ See, e.g., Comments of Commissioner Marlene Johnson, RTO

Conference (District of Columbia), transcript at 23-24; Commissioner

Gerald Thorpe (Maryland), transcript at 39-40; President Herbert

Tate (New Jersey), transcript at 47-50; and Commissioner Nora Mead

Brownell (Pennsylvania), transcript at 54.

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While these industry groups and state regulators may not agree on

the form of such regional organizations and how aggressive the

Commission should be in encouraging their development, they do

generally agree that such entities would provide substantial benefits.

We note, additionally, that this same conclusion has also been

reached in other countries. In almost every country that has chosen to

introduce competition in its power sector, a single regional or

national grid management organization has or will be created as the

necessary platform for achieving fair and efficient bulk power

competition.149

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\149\ Government of Mexico, Secretaria de Energia, Policy

proposal for structural reform of the Mexican electricity sector,

1999; World Bank, Reforms and Private Participation in the Power

Sector of Selected Latin American and Caribbean and Industrialized

Countries, 1994; National Regulatory Research Institute, Electric

Power industry Restructuring in Australia: Lessons From Down Under,

Occasional Paper #20, Ohio State University, January 1997; World

Bank (Industry and Energy Department), Central and Eastern Europe:

Power Sector Reform in Selected Countries 1997; Ontario (Canada)

Market Design Committee, The Fourth and Final Report, January, 1999;

Alberta (Canada) Department of Energy, Moving To Competition, A

Guide to Alberta's New Electricity Structure, 1994; Jan Moen, A

Common Electricity Market in Norway and Sweden: Prerequisites,

Development and Results So Far, Norwegian Water Resources and Energy

Administration, May, 1996; National Grid Company, Grid System

Management, Coventry, England; and J. Culy, E. Read and B. Wright,

``The Evolution of New Zealand's Electricity Supply Structure,'' in

International Comparisons of Electricity Regulation, Gilbert and

Kahn, editors, Cambridge University Press, 1996.

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In the following discussion, we address the significant benefits of

establishing RTOs.

1. An RTO Would Improve Efficiencies in the Management of the

Transmission Grid

As discussed in section III.A above, numerous inefficiencies in the

current operation and structure of the transmission grid may be

impeding full competition. Establishing RTOs could help remove most, if

not all, of those inefficiencies in a number of ways.

First, an RTO would improve efficiency through regional

transmission pricing. The Commission has long recognized that

transmission pricing reform is most effectively accomplished on a

regional basis.150 An RTO would have the geographic scope

needed to eliminate pancaked transmission rates within its region. This

would broaden the generation market and could result in more potential

suppliers and less concentrated generation markets, thereby fostering

more competitive markets and lower prices to consumers.

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\150\ Transmission Pricing Policy Statement, FERC Stats. & Regs.

at 31,145.

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Second, regional scope would improve congestion management on the

grid. An RTO would improve the way congestion is managed over a large

area, thus expanding the number of potential transactions over existing

facilities while reducing the number of curtailments.

The scheduling of power by multiple utilities over a regional grid

can lead to unexpected overloads on constrained facilities. This can be

a serious barrier to competitive power trading because some power sale

transactions may have to be curtailed. With a regional scope, an RTO

would be better able to manage congestion. An RTO would be in a better

position to prevent congestion or control it through application of

appropriate regionwide congestion pricing to ration use of the grid if

necessary. An RTO would also more readily identify schedules that could

lead to congestion, and relieve congestion through regional redispatch

authority. A pricing approach to capacity allocation would improve

efficiency by ensuring that the most highly valued transactions remain

on the grid and possibly result in less curtailment than under the

present approach.

Third, an RTO would improve efficiency by providing more accurate

estimates of ATC than those currently provided by individual systems.

Conditions on all parts of the regional grid affect ATC on individual

utility systems. Factors such as load estimates, generation and

transmission outages, generation dispatch orders and

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