Regional Transmission Organizations

SUMMARY: The Federal Energy Regulatory Commission (Commission) is

amending its regulations under the Federal Power Act (FPA) to advance

the formation of Regional Transmission Organizations (RTOs). The

regulations require that each public utility that owns, operates, or

controls facilities for the transmission of electric energy in

interstate commerce make certain filings with respect to forming and

participating in an RTO. The Commission also codifies minimum

characteristics and functions that a transmission entity must satisfy

in order to be considered an RTO. The Commission's goal is to promote

efficiency in wholesale electricity markets and to ensure that

electricity consumers pay the lowest price possible for reliable

service.

EFFECTIVE DATE: This Final Rule will become effective March 6, 2000.

FOR FURTHER INFORMATION CONTACT:

Alan Haymes (Technical Information), Federal Energy Regulatory

Commission, 888 First Street, NE, Washington, DC 20426, (202) 219-2919.

Brian R. Gish (Legal Information), Federal Energy Regulatory

Commission, 888 First Street, NE, Washington, DC 20426, (202) 208-0996.

James Apperson (Collaborative Process), Federal Energy Regulatory

Commission, 888 First Street, NE, Washington, DC 20426, (202) 219-2962.

SUPPLEMENTARY INFORMATION: In addition to publishing the full text of

this document in the Federal Register, the Commission provides all

interested persons an opportunity to view and/or print the contents of

this document via the Internet through FERC's Home Page (http://

www.ferc.fed.us) and in FERC's Public Reference Room during normal

business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First

Street, NE, Room 2A, Washington, DC 20426.

From FERC's Home Page on the Internet, this information is

available in both the Commission Issuance Posting System (CIPS) and the

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Table of Contents

I. Introduction and Summary

II. Background

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

889

B. Developments Since Order Nos. 888 and 889

1. Industry Restructuring and New Stresses on the Transmission

Grid

2. Successes, Failures and Haphazard Development of Regional

Transmission Entities

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

Stakeholders and State Regulators

III. Discussion

A. Existence of Barriers and Impediments to Achieving Fully

Competitive Electricity Markets

B. Benefits That RTOs Can Offer to Address Remaining Barriers

and Impediments

C. Commission's Approach to RTO Formation

1. Voluntary Approach

2. Organizational Form of an RTO

3. Degree of Specificity in the Rule

4. Legal Authority

D. Minimum Characteristics of an RTO

1. Independence (Characteristic 1)

2. Scope and Regional Configuration (Characteristic 2)

3. Operational Authority (Characteristic 3)

4. Short-Term Reliability (Characteristic 4)

E. Minimum Functions of an RTO

1. Tariff Administration and Design (Function 1)

2. Congestion Management (Function 2)

3. Parallel Path Flow (Function 3)

4. Ancillary Services (Function 4)

5. OASIS and Total Transmission Capability (TTC) and Available

Transmission Capability (ATC) (Function 5)

6. Market Monitoring (Function 6)

7. Planning and Expansion (Function 7)

8. Interregional Coordination (Function 8)

F. Open Architecture

G. Transmission Ratemaking Policy for RTOs

1. Pancaked Rates

2. Reciprocal Waiving of Access Charges Between RTOs

3. Uniform Access Charges

4. Congestion Pricing

5. Service to Transmission-Owning Utilities That Do Not

Participate in an RTO

6. Performance-Based Rate Regulation

7. Other RTO Transmission Ratemaking Reforms

8. Additional Ratemaking Issues

9. Filing Procedures for Innovative Rate Proposals

H. Other Issues

1. Public Power and Cooperative Participation in RTOs

2. Participation by Canadian and Mexican Entities

3. Existing Transmission Contracts

4. Power Exchanges (PXs)

5. Effect on Retail Markets and Retail Access

6. Effect on States with Low Cost Generation

7. States' Roles with Regard to RTOs

8. Accounting Issues

9. Market Design Lessons

I. Collaborative Process

J. Implementation Issues

1. Filing Requirements

2. Deadline for RTO Operation

3. Commission Processing Procedures

4. Other Implementation Issues

IV. Environmental Statement

V. Regulatory Flexibility Act Certification

VI. Public Reporting Burden and Information Collection Statement

VII. Effective Date and Congressional Notification

VIII. Document Availability

Regulatory Text

Appendix

Before Commissioners: James J. Hoecker, Chairman; William L. Massey,

Linda Breathitt, and Curt Hebert, Jr.

I. Introduction and Summary

In 1996 the Commission put in place the foundation necessary for

competitive wholesale power markets in this country--open access

[[Page 811]]

transmission. 1 Since that time, the industry has undergone

sweeping restructuring activity, including a movement by many states to

develop retail competition, the growing divestiture of generation

plants by traditional electric utilities, a significant increase in the

number of mergers among traditional electric utilities and among

electric utilities and gas pipeline companies, large increases in the

number of power marketers and independent generation facility

developers entering the marketplace, and the establishment of

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

transmission system. Trade in bulk power markets has continued to

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

more heavily and in new ways.

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

discriminatory Transmission Services by Public Utilities and

Recovery of Stranded Costs by Public Utilities and Transmitting

Utilities, Order No. 888, 61 FR 21,540 (May 10, 1996), FERC Stats. &

Regs. para. 31,036 (1996) (Order No. 888), order on reh'g, Order No.

888-A, 62 FR 12,274 (March 14, 1997), FERC Stats. & Regs. para.

31,048 (1997) (Order No. 888-A), order on reh'g, Order No. 888-B, 81

FERC para. 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC

para. 61,046 (1998), appeal docketed, Transmission Access Policy

Study Group, et al. v. FERC, Nos. 97-1715 et al. (D.C. Cir.).

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On May 13, 1999, the Commission proposed a rule on Regional

Transmission Organizations (RTOs) that identified and discussed our

concerns with the traditional means of grid management.2 In

that Notice of Proposed Rulemaking (NOPR), the Commission reviewed

evidence that traditional management of the transmission grid by

vertically integrated electric utilities was inadequate to support the

efficient and reliable operation that is needed for the continued

development of competitive electricity markets, and that continued

discrimination in the provision of transmission services by vertically

integrated utilities may also be impeding fully competitive electricity

markets. These problems may be depriving the Nation of the benefits of

lower prices and enhanced reliability. The comments on the NOPR

overwhelmingly support the conclusion that independent regionally

operated transmissions grids will enhance the benefits of competitive

electricity markets. Competition in wholesale electricity markets is

the best way to protect the public interest and ensure that electricity

consumers pay the lowest price possible for reliable service.

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\2\ Regional Transmission Organizations, Notice of Proposed

Rulemaking, 64 FR 31,390 (June 10, 1999), FERC Stats. & Regs. para.

32,541 at 33,683-781 (1999).

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Regional institutions can address the operational and reliability

issues now confronting the industry, and eliminate any residual

discrimination in transmission services that can occur when the

operation of the transmission system remains in the control of a

vertically integrated utility. Appropriate regional transmission

institutions could: (1) Improve efficiencies in transmission grid

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

remaining opportunities for discriminatory transmission practices; (4)

improve market performance; and (5) facilitate lighter handed

regulation.

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\3\ As discussed more fully later, appropriate regional

institutions could improve efficiencies in grid management through

improved pricing, congestion management, more accurate estimates of

Available Transmission Capability, improved parallel path flow

management, more efficient planning, and increased coordination

between regulatory agencies.

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Thus, we believe that appropriate RTOs could successfully address

the existing impediments to efficient grid operation and competition

and could consequently benefit consumers through lower electricity

rates resulting from a wider choice of services and service providers.

In addition, substantial cost savings are likely to result from the

formation of RTOs.

Based on careful consideration of the thoughtful comments submitted

in response to the NOPR,4 the Commission adopts a final rule

that generally follows the approach of the NOPR. Our objective is for

all transmission-owning entities in the Nation, including non-public

utility entities, to place their transmission facilities under the

control of appropriate RTOs in a timely manner. Therefore, we are

establishing in this rule minimum characteristics and functions for

appropriate RTOs; a collaborative process by which public utilities and

non-public utilities that own, operate or control interstate

transmission facilities, in consultation with state officials as

appropriate, will consider and develop RTOs; a proposal to consider

transmission ratemaking reforms on a case-specific basis; an

opportunity for non-monetary regulatory benefits, such as deference in

dispute resolution and streamlined filing and approval procedures; and

a time line for public utilities to make appropriate filings with the

Commission to initiate operation of RTOs. As a result of this voluntary

approach, we expect jurisdictional utilities to form RTOs. If the

industry fails to form RTOs under this approach, the Commission will

reconsider what further regulatory steps are in the public interest.

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\4\ The Commission received 334 initial and reply comments in

response to the NOPR. The commenters, and abbreviations for them as

used herein, are listed in an Appendix to this Final Rule.

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Pursuant to our authority under section 205 of the Federal Power

Act (FPA) to ensure that rates, terms and conditions of transmission

and sales for resale in interstate commerce by public utilities are

just, reasonable and not unduly discriminatory or preferential, and our

authority under section 202(a) of the FPA to promote and encourage

regional districts for the voluntary interconnection and coordination

of transmission facilities by public utilities and non-public utilities

for the purpose of assuring an abundant supply of electric energy

throughout the United States with the greatest possible economy, this

rule requires the following.

First, the Commission establishes minimum characteristics and

functions that an RTO must satisfy in the following areas:

Minimum Characteristics:

1. Independence

2. Scope and Regional Configuration

3. Operational Authority

4. Short-term Reliability

Minimum Functions:

1. Tariff Administration and Design

2. Congestion Management

3. Parallel Path Flow

4. Ancillary Services

5. OASIS and Total Transmission Capability (TTC) and Available

Transmission Capability (ATC)

6. Market Monitoring

7. Planning and Expansion

8. Interregional Coordination

Industry participants, however, retain flexibility in structuring RTOs

that satisfy the minimum characteristics and functions. For example, we

do not propose to require or prohibit any one form of organization for

RTOs or require or prohibit RTO ownership of transmission facilities.

The characteristics and functions could be satisfied by different

organizational forms, such as ISOs, transcos, combinations of the two,

or even new organizational forms not yet discussed in the industry or

proposed to the Commission. Likewise, the Commission is not proposing a

``cookie cutter'' organizational format for regional transmission

institutions or the establishment of fixed or specific regional

boundaries under section 202(a) of the FPA.

We also establish an ``open architecture'' policy regarding RTOs,

whereby all RTO proposals must allow the RTO and its members the

flexibility to improve their organizations in the

[[Page 812]]

future in terms of structure, operations, market support and geographic

scope to meet market needs. In turn, the Commission will provide the

regulatory flexibility to accommodate such improvement.

Second, to facilitate RTO formation in all regions of the Nation,

the Commission will sponsor and support a collaborative process to take

place in the Spring of 2000. Under this process, we expect that public

utilities and non-public utilities, in coordination with state

officials, Commission staff, and all affected interest groups, will

actively work toward the voluntary development of RTOs.

Third, we provide guidance on flexible transmission ratemaking that

may be proposed by RTOs, including ratemaking treatments that will

address congestion pricing and performance-based regulation. We also

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

be appropriate for transmission facilities under RTO control.

Finally, all public utilities (with the exception of those

participating in an approved regional transmission entity that conforms

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

interstate transmission facilities must file with the Commission by

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

characteristics and functions to be operational by December 15,

2001,5 or, alternatively, a description of efforts to

participate in an RTO, any existing obstacles to RTO participation, and

any plans to work toward RTO participation. We expect that such

proposals would include the transmission facilities of public utilities

as well as transmission facilities of public power and other non-public

utility entities to the extent possible. Through the required filings,

public utilities will make known to the public any plans for RTO

participation and any obstacles to RTO formation.

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\5\ An RTO proposal includes a basic agreement filed under

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

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

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

of the FPA to transfer control of their jurisdictional transmission

facilities from individual public utilities to the RTO. Most RTO

proposals by public utilities are likely to involve one or more

filings under FPA sections 203 and 205, but the number and types of

filing may vary depending upon the type of RTO proposed and the

number of public utilities involved in the proposal. Under the Rule,

a utility may file a petition for a declaratory order asking, for

example, whether a proposed transmission entity would qualify as an

RTO or if a new or innovative method for pricing transmission

service would be acceptable, to be followed by appropriate filings

under sections 203 and 205.

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A public utility that is a member of an existing transmission

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

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

no later than January 15, 2001. That filing must explain the extent to

which the transmission entity in which it participates meets the

minimum characteristics and functions for an RTO, and either propose to

modify the existing institution to the extent necessary to become an

RTO, or explain the efforts, obstacles and plans with respect to

conforming to these characteristics and functions.

The goal of this rulemaking is to form RTOs voluntarily and in a

timely manner. The alternative to a voluntary process is likely to be a

lengthy process that is more likely to result in greater

standardization of the Commission's RTO requirements among regions.

Although the Commission has specific authorities and responsibilities

under the FPA to protect against undue discrimination and remove

impediments to wholesale competition, we find it appropriate in this

instance to adopt an open collaborative process that relies on

voluntary regional participation to design RTOs that can be tailored to

specific needs of each region.

II. Background

In April 1996, in Order Nos. 888 6 and 889,7

the Commission established the foundation necessary to develop

competitive bulk power markets in the United States: non-discriminatory

open access transmission services by public utilities and stranded cost

recovery rules that would provide a fair transition to competitive

markets. Order Nos. 888 and 889 were very successful in accomplishing

much of what they set out to do. However, the orders were not intended

to address all problems that might arise in the development of

competitive power markets. Indeed, the nature of the emerging markets

and the remaining impediments to full competition that became apparent

in the nearly four years since the issuance of Order Nos. 888 and 889,

and the insightful comments and information presented to us by a wide

array of industry participants in this rulemaking proceeding have made

clear that the Commission must take further action if we are to achieve

the fully competitive power markets envisioned by those orders.

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\6\ See supra note 1.

\7\ Open Access Same-Time Information System (Formerly Real-Time

Information Networks) and Standards of Conduct, Order No. 889, 61 FR

21,737 (May 10, 1996), FERC Stats. & Regs. para. 31,035 (1996),

order on reh'g, Order No. 889-A, 62 FR 12,484 (March 14, 1997), FERC

Stats. & Regs. para. 31,049 (1997), order on reh'g, Order No. 889-B,

81 FERC para. 61,253 (1997).

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

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

discriminatory and anticompetitive practices existed in the electric

industry, and that transmission-owning utilities had discriminated

against others seeking transmission access.8 The Commission

stated that its goal was to ensure that customers have the benefits of

competitively priced generation, and determined that non-discriminatory

open access transmission services (including access to transmission

information) and stranded cost recovery were the most critical

components of a successful transition to competitive wholesale

electricity markets.9

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\8\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,682.

\9\ Id. at 31,652.

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

control or operate facilities used for transmitting electric energy in

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

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

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

wholesale power services. Under functional unbundling, the public

utility must: (1) take transmission services under the same tariff of

general applicability as do others; (2) state separate rates for

wholesale generation, transmission, and ancillary services; and (3)

rely on the same electronic information network that its transmission

customers rely on to obtain information about its transmission system

when buying or selling power.10 Order No. 889 required that

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

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

comply with standards of conduct designed to prevent employees of a

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

wholesale power marketing functions from obtaining preferential access

to pertinent transmission system information.

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\10\ Id. at 31,654-55.

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

received comments urging it to require generation divestiture or

structural institutional arrangements such as regional independent

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

Commission responded that, while it believed that

[[Page 813]]

ISOs had the potential to provide significant benefits, efforts to

remedy undue discrimination should begin by requiring the less

intrusive functional unbundling approach. Subsequent to issuance of

Order No. 888, it has become apparent that several types of regional

transmission institutions, in addition to the kinds of ISOs approved to

date, may also be able to provide the benefits attributed to ISOs in

Order No. 888.

Order No. 888 set forth 11 principles for assessing ISO proposals

submitted to the Commission.11 Order No. 888 also stated:

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\11\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,730.

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

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

marketplace. As a further precaution against discriminatory

behavior, we will continue to monitor electricity markets to ensure

that functional unbundling adequately protects transmission

customers. At the same time, we will analyze all alternative

proposals, including formation of ISOs, and, if it becomes apparent

that functional unbundling is inadequate or unworkable in assuring

non-discriminatory open access transmission, we will reevaluate our

position and decide whether other mechanisms, such as ISOs, should

be required.12

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\12\ Id. at 31,655.

Below, we summarize our experiences with functional unbundling from the

date of issuance of Order Nos. 888 and 889.

B. Developments Since Order Nos. 888 and 889

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

numerous significant developments have occurred in the electric utility

industry. Some of these reflect changes in governmental policies;

others are strictly industry-driven. These activities have resulted in

a considerably different industry landscape from the one faced at the

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

regulatory and industry challenges.

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

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

most public utilities accepted these changes and made substantial good

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

utilities have filed tariffs stating rates, terms and conditions for

comparable service to third-party users of their transmission systems.

In addition, improved information about the transmission system is

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

available to the public utility's merchant function and market

affiliate as a result of utility compliance with the OASIS regulations.

The availability of tariffs and information about the transmission

system has fostered a rapid growth in dependence on wholesale markets

for acquisition of generation resources. Areas that have experienced

generation shortages have seen rapid development of new generation

resources. For example, in the Northeast Power Coordinating Council

(NPCC) region (including New England, New York and parts of eastern

Canada), where there was deep concern about adequacy of generation

supply only three years ago, approximately 30,000 MW of generation is

proposed or actually under construction.13 That response

comes almost entirely from independent generating plants, which are

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

the transmission system. Power resources are now acquired over

increasingly large regional areas, and interregional transfers of

electricity have increased. The very success of Order Nos. 888 and 889,

and the initiative of some utilities that have pursued voluntary

restructuring beyond the minimum open access requirements, have placed

new stresses on regional transmission systems--stresses that call for

regional solutions.

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\13\ Based on data supplied to the Commission by Resource Data

International.

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1. Industry Restructuring and New Stresses on the Transmission Grid

Open access transmission and the opening of wholesale competition

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

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

of their generating assets; significantly increased merger activity

both between electric utilities and between electric and natural gas

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

in the form of both independent and affiliated power marketers and

generators as well as independent power exchanges; increases in the

volume of trade in the industry, particularly sales by marketers; state

efforts to introduce retail competition; and new and different uses of

the transmission grid.

With respect to divestiture, since August 1997, generating

facilities representing approximately 50,000 MW of generating capacity

have been sold (or are under contract to be sold) by utilities, and an

additional 30,000 MW is currently for sale. In total, this represents

more than ten percent of U.S. generating capacity. In all, 27 utilities

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

assets for sale. Buyers of this generating capacity have included

traditional utilities with specified service territories as well as

independent power producers with no required service territory.

Since Order No. 888 was issued, more than 40 applications have been

filed for Commission approval of proposed mergers involving public

utilities.14 Most of these merger proposals involve electric

utilities with contiguous service areas, although some of the proposed

mergers have been between utilities with non-contiguous service areas.

In addition, an increasing number of applications involve the

combination of electric and natural gas assets.

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\14\ See Commission's website, www.ferc.fed.us/electric/mergers.

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

particularly the number of marketers, in the wholesale electricity

market. For example, in the first quarter of 1995, according to power

marketer quarterly filings, marketer sales traded by only eight active

power marketers, totaled 1.8 million MWh. By the first quarter of 1999,

such sales escalated to over 400 million MWh, traded by over 100 power

marketers.15

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\15\ See Commission's website, www.ferc.fed.us/electric/PwrMkt.

The Commission recognizes that a significant portion of the sales

represent the retrading of power by a number of different market

participants, such that there may be multiple resales of the same

generation. Nonetheless, the volume of and intensity of trading

continues to increase in the wholesale electricity market.

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The Commission has granted market-based rate authority to more than

800 entities, of which nearly 500 are power marketers, (including over

100 marketers affiliated with investor-owned utilities). The remaining

entities include approximately equal numbers of affiliated power

producers, investor-owned utilities and other utilities.16

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\16\ See Commission's website, www.ferc.fed.us/electric.

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State commissions and legislatures have been active in the past few

years studying competitive options at the retail level, setting up

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

scale retail access programs. As of November 1, 1999, twenty-one states

had enacted electric restructuring legislation, three had issued

comprehensive regulatory orders, and twenty-six states plus the

District of Columbia had legislation or orders pending or

investigations underway.17 Fifteen states had implemented

full-

[[Page 814]]

scale or pilot retail competition programs that offer a choice of

suppliers to at least some retail customers. Eight states have

initiated programs to offer access to retail customers by a date

certain.

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\17\ See the Energy Information Administration website,

www.eia.doe.gov/cneaf/electricity/chg__str/regmap.html.

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

the transmission grid is now being used more intensively and in

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

traditional approaches to operating the grid are showing signs of

strain. According to the North American Electric Reliability Council

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

challenged to support the movement of power in unprecedented amounts

and in unexpected directions.'' 18 These changes in the use

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

to maintain system security in operating the transmission system under

conditions for which it was not planned or designed.'' 19 It

should be noted that, despite the increased transmission system

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

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

and that even though the system was particularly stressed during the

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

interrupted due to transmission transfer limitations.'' 20

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\18\ Reliability Assessment 1998-2007, North American Electric

Reliability Council (September 1998), at 26 (Reliability

Assessment).

\19\ Id.

\20\ Id.

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An indication that the increased and different use of the

transmission system is stressing the grid is the increased use of

transmission line loading relief (TLR) procedures.21 And,

according to published reports, the incidence of TLRs is growing. While

in all of 1998 over 300 TLRs were called, in the first ten months of

1999, over 400 TLRs have been called, resulting in over 8,000 MW of

power curtailment in the three-month summer period beginning June

1999.22

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\21\ The TLR procedures are designed to remedy overloads that

result when a transmission line or other transmission equipment

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

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

are designed to bring overloaded transmission equipment to within

NERC's Operating Security Limits essentially by curtailing

transactions contributing to the overload. See North American

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

\22\ Power Markets Week, November 8, 1999 at 1, citing NERC

data.

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It appears that the planning and construction of transmission and

transmission-related facilities may not be keeping up with increased

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

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

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

23 The amount of new transmission capacity planned over the

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

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

system support.24 NERC states that, ``The close coordination

of generation and transmission planning is diminishing as vertically

integrated utilities divest their generation assets and most new

generation is being proposed and developed by independent power

producers.'' 25

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\23\ Reliability Assessment at 26.

\24\ Id. at 7.

\25\ Id.

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The transition to new market structures has resulted in new

challenges and circumstances. For example, during the week of June 22-

26, 1998, the wholesale electric market in the Midwest experienced

numerous events that led to unprecedented high spot market prices. Spot

wholesale market prices for energy briefly rose as high as $7,500 per

MWh, compared with an average price for the summer of approximately $40

per MWh in the Midwest if the pricing abnormalities are

excluded.26 This experience led to calls for price caps,

allegations of market power, and a questioning of the effectiveness of

transmission open access and wholesale electric competition.

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\26\ See Staff Report to the Federal Energy Regulatory

Commission on the Causes of Wholesale Electric Pricing Abnormalities

in the Midwest During June 1998, (Sept. 22, 1998) (Staff Price Spike

Report) at 3-8 to 3-11. Unusually high spot market wholesale prices

also occurred during the summer of 1999. The Commission is not aware

that any formal evaluations of market data have been performed for

that occurrence of price abnormalities.

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The Commission staff undertook an investigation of the pricing

abnormalities. Staff's report concluded that the unusually high price

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

average generation outages, unseasonably hot temperatures, storm-

related transmission outages, transmission constraints, poor

communication of price signals, lowered confidence in the market due to

a few contract defaults, and inexperience in dealing with competitive

markets.27

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\27\ Id. at v.

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

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

Regarding regional transmission entities, the staff report observed:

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

Commission's intent to foster competitive market conditions underscores

the importance of better regional coordination in areas such as

maintenance of transmission and generation systems and transmission

planning and operation.'' 28 Support for this view comes

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

Ohio, in its own report on the high spot market prices, recommended

that policy makers ``take unambiguous action to require coordination of

transmission system operations by regionwide Independent System

Operators.'' 29

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\28\ Id. at 5-8.

\29\ Ohio's Electric Market, June 22-26, 1998, What Happened and

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

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

Force on Electric System Reliability published its final

report.30 The Task Force was convened in January 1997 to

provide advice to the Department of Energy on critical institutional,

technical, and policy issues that need to be addressed in order to

maintain bulk power electric system reliability in a more competitive

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

institutions and processes that have served the Nation well in the past

need to be modified to ensure that reliability is maintained in a

competitively neutral fashion;'' that ``grid reliability depends

heavily on system operators who monitor and control the grid in real

time;'' and that ``because bulk power systems are regional in nature,

they can and should be operated more reliably and efficiently when

coordinated over large geographic areas.'' 31

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\30\ Maintaining Reliability in a Competitive U.S. Electricity

Industry; Final Report of the Task Force on Electric System

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

comprised of 24 members representing all major segments of the

electric industry, including private and public suppliers, power

marketers, regulators, environmentalists, and academics.

\31\ Task Force Report at x-xi.

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The report noted that many regions of the United States are

developing ISOs as a way to maintain electric system reliability as

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

significant institutions to assure both electric system reliability and

competitive generation markets. The Task Force concluded that a large

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

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

growing number of transactions; (3) facilitate transmission access

across a larger

[[Page 815]]

portion of the network, consequently improving market efficiencies and

promoting greater competition; and (4) eliminate ``pancaking'' of

transmission rates, thus allowing a greater range of economic energy

trades across the network.32

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\32\ Id. at 76.

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2. Successes, Failures, and Haphazard Development of Regional

Transmission Entities

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

unsuccessful efforts to establish ISOs, and other efforts to form

regional entities to operate the transmission facilities in various

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

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

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

operational regional transmission institution.

Proposals for the establishment of five ISOs have been submitted to

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

the California ISO,33 PJM ISO,34 ISO New

England,35 the New York ISO,36 and the Midwest

ISO.37 In addition, the Texas Commission has ordered an ISO

for the Electric Reliability Council of Texas (ERCOT).38

Moreover, our international neighbors in Canada and Mexico are also

pursuing electric restructuring efforts that include various forms of

regional transmission entities.39

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\33\ Pacific Gas & Electric Company, et al., 77 FERC para.

61,204 (1996), order on reh'g, 81 FERC para. 61,122 (1997) (Pacific

Gas & Electric).

\34\ Pennsylvania-New Jersey-Maryland Interconnection, et al.,

81 FERC para. 61,257 (1997), order on reh'g, 82 FERC para. 61,047

(1998) (PJM).

\35\ New England Power Pool, 79 FERC para. 61,374 (1997), order

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

\36\ Central Hudson Gas & Electric Corporation, et al., 83 FERC

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

(Central Hudson).

\37\ Midwest Independent Transmission System Operator, et al.,

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

61,250, order on reh'g, 85 FERC para. 61,372 (1998) (Midwest ISO).

\38\ See 16 Texas Administrative Code Sec. 23.67(p).

Furthermore, on June 18, 1999, S.B.7 was enacted to restructure the

Texas electric industry allowing retail competition. The bill

requires retail competition to begin by January 2002. Rates will be

frozen for three years, and then a six percent reduction will be

required for residential and small commercial consumers.

\39\ See Policy Proposal for Structural Reform of the Mexican

Electricity Industry, Secretary of Energy, Mexico (Feb. 1999); Third

Interim Report of the Ontario Market Design Committee (Oct. 1998);

TransAlta Enterprises Corporation, 75 FERC para. 61,268 at 61,875

(1996) (recognition of the restructuring in the Province of Alberta,

Canada to create a Grid Company of Alberta).

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

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

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

requirement that there be a single systemwide transmission tariff for

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

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

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

neither required by government nor based on an existing institution.

Two states in the region subsequently required utilities in their

states to participate in either a Commission-approved ISO (Illinois and

Wisconsin), or sell their transmission assets to an independent

transmission company that would operate under a regional ISO

(Wisconsin).

As part of general restructuring initiatives, several states now

require independent grid management organizations. For example, an

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

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

utilities the option of joining an ISO or selling their transmission

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

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

organizations are not developed. Recently, Virginia,40

Arkansas 41 and Ohio42 have also enacted

legislation requiring their electric utilities to join or establish

regional transmission entities.

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\40\ See Virginia Electric Utility Restructuring Act, S1269

(Mar. 25, 1999). In Virginia, electric utilities are required by

January 2001, to join or establish regional transmission entities.

\41\ See The Arkansas Electric Consumer Choice Act of 1999, Act

1, 82nd General Assembly (Apr. 1999).

\42\ See Amended Substitute Senate Bill No. 3, 123rd General

Assembly (July 6, 1999).

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The approved ISOs have similarities as well as differences. All

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

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

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

variation in governance, operational responsibilities, geographic scope

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

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

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

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

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

board consisting of stakeholders and non-stakeholders.

Four of the five ISOs operate a single control area, but the large

Midwest ISO does not currently plan to operate a single control area.

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

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

The current Midwest ISO members do not encompass one contiguous

geographic area. The ISO New England administers a separate NEPOOL

tariff, while the other four administer their own ISO transmission

tariffs.

Three ISOs operate or propose to operate centralized power markets

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

separate power exchange (PX) to operate such a market.43 The

Midwest ISO has not proposed an ISO-related centralized market for its

region.44 In addition, at least one separate PX has begun to

do business in California apart from the PX established through the

restructuring legislation.45

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\43\ The California PX offers day-ahead and hour-ahead markets

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

PX market is voluntary except that the three traditional investor-

owned utilities in California must bid their generation sales and

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

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

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

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

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

\44\ There are indications, however, that the Midwest ISO is

considering the formation of a power exchange. See Joint Committee

for the Development of a Midwest Independent Power Exchange,

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

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

\45\ See Automated Power Exchange, Inc., 82 FERC para. 61,287,

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

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

1998).

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The existing ISOs are also evolving in terms of their governance

structure and as a result of operating experience with the transmission

systems and the various markets they operate. For example, the

Commission rejected the original governance proposals for two ISOs: the

New England ISO and New York ISO. In both cases, the Commission

concluded that the vertically integrated utility members of the ISO

would have too much voting power in the various advisory committees

that provide advice and recommendations to the non-stakeholder Boards.

The ISOs resubmitted governance proposals that gave balanced

representation to the various sectors of stakeholders, and the

Commission subsequently approved both revised governance structures.

In addition, the Commission has considered a number of significant

modifications of market rules proposed by the existing ISOs in the

seven months since issuance of the RTO

[[Page 816]]

NOPR. In particular, a number of rules for the California ISO and New

England ISO have been modified, affecting the products traded in, and

the timing of, the markets for energy, ancillary services, balancing

services and transmission.

An additional few transmission restructuring proposals that were

pending as of the date of issuance of the RTO NOPR have been approved

by the Commission, and others have been filed since that date. In July

1999, the Commission granted a petition for declaratory order filed by

Entergy Services Inc., in which the majority concluded that passive

ownership of a transmission entity by a generating company or other

market participant could meet the ISO principles contained in Order No.

888. The order stated, however, that the passive ownership must be

properly designed, such that the transmission entity is truly

independent of the market participants.46 Another filing

that was pending when the NOPR was issued was the request by

FirstEnergy to sell its transmission assets to a newly-formed

affiliate. The Commission approved the disposition of jurisdictional

facilities, noting that the proposed action would not adversely affect

competition, rates or regulation. In addition, the Commission noted

that the creation of the transmission-owning affiliate would facilitate

the subsequent transfer of FirstEnergy's transmission facilities to an

RTO, which FirstEnergy pledged to do within two years of Commission

approval of the disposition of facilities to its

affiliate.47

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\46\ See Entergy Services, Inc., 88 FERC para. 61,149 (1999)

(Commissioner Massey dissented from this order).

\47\ See FirstEnergy Operating Companies, et al., 89 FERC para.

61,090 (1999).

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Since issuance of the RTO NOPR, the Alliance Companies filed a

proposal to create an RTO. Applicants suggest that the RTO could take

one of two forms, either an ISO or a transco, but note that they prefer

a transco configuration in which, at least initially, the five

transmission-owning participants could hold five percent ownership

stakes in the transco.48

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\48\ See Application of Alliance Companies in Docket No. ER99-

3144-000 (filed June 3, 1999). The Commission issued an order on

this application concurrently with the issuance of this Final Rule.

See Alliance Companies, 89 FERC para.____ (1999) (Alliance

Companies).

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

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

(Independent Grid Operator) ISO in the Pacific Northwest and Rocky

Mountain regions ended their efforts to create an ISO.49

More recently, members of the Mid-American Power Pool (MAPP), an

existing power pool that covers six U.S. states and two Canadian

provinces, failed to achieve consensus for establishing a long-planned

ISO.50 In the Southwest, proponents of the Desert STAR ISO

have not been able to reach agreement to date on a formal proposal

after more than two years of discussion.51 In the interim

period, some of the participants in the Desert STAR ISO have filed at

the Commission a proposal to create the Mountain West Independent

Scheduling Administrator, which would oversee the scheduling of

transmission service within Nevada.52

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\49\ Recently, however, parties in the Pacific Northwest have

resumed RTO discussions.

\50\ However, trade press reports suggest that while MAPP

members continue to try to reach consensus, the Midwest ISO is in

discussion with MAPP members to join the Midwest ISO. See Inside

FERC, July 26, 1999; The Energy Report, Nov. 1, 1999 at 931.

\51\ Recent press reports, however, indicate that Desert STAR

has incorporated as a non-profit organization, a first step toward

the launch of an ISO. See Energy Daily, Nov. 5, 1999 at 2.

\52\ See Application of Mountain West Independent Transmission

Administrator in Docket No. ER99-3719-000 (filed July 23, 1999).

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Various reasons have been advanced to explain the difficulty in

forming a voluntary, multi-state ISO. Reasons include: ``cost

shifting,'' which involves increases in transmission rates for some

parties; disagreements about sharing of ISO transmission revenues among

transmission owners; difficulties in obtaining the participation of

publicly-owned transmission facilities; concerns about the loss of

transmission rights and prices embedded in existing transmission

agreements; and the preference of certain transmission owners to sell

or transfer their transmission assets to a for-profit transmission

company in lieu of handing over control to a non-profit ISO.

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

Stakeholders and State Regulators

In light of the various restructuring activities occurring

throughout the United States, the Commission has held 11 public

conferences in nine different cities across the country to hear the

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

need for RTOs and their appropriate roles and responsibilities.

The Commission initiated an inquiry in March 1998 pertaining to its

policies on ISOs. A notice establishing procedures for a conference

gave the following rationale:

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

established the fundamental principles of non-discriminatory open

access transmission services. Nevertheless, many issues remain to be

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

access and more competitive electric markets.

* * * * *

Given the dramatic changes taking place in both wholesale and

retail electric markets and the many proposals under consideration

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

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

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

appropriately support our dual goals of eliminating undue

discrimination and promoting competition in electric power

markets.53

\53\ Inquiry Concerning the Commission's Policy on Independent

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

2 (March 13, 1998).

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

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

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

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

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

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

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

approximately 145 oral presentations and received a large number of

written comments on the appropriate size, scope, organization and

functions of regional transmission institutions. A number of different

of viewpoints were expressed.54

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\54\ A summary of those views was included as Appendix A to the

NOPR in this docket.

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

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

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

authority to establish boundaries for Independent System Operators

(ISOs) or other appropriate transmission entities.'' 55 The

Secretary also stated: ``FERC is also increasingly faced with

reliability-related issues. Providing FERC with the authority to

establish boundaries for ISOs or other appropriate transmission

entities could aid in the orderly formation of properly-sized

transmission institutions and in addressing reliability-related issues,

thereby increasing the reliability of the transmission system.''

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\55\ 63 FR 53,889 (Oct. 7, 1998).

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

to initiate a consultation process with State commissions pursuant to

section

[[Page 817]]

202(a).56 The purpose of the consultations was to afford

State commissions a reasonable opportunity to present their views with

respect to appropriate boundaries for regional transmission

institutions and other issues relating to RTOs. Conferences with State

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

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

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

representatives of 41 state commissions during these consultations,

with others monitoring or providing written comments.57

During these sessions, we received much valuable advice. Furthermore,

we have had additional consultations since issuance of the RTO NOPR in

May 1999.

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\56\ Regional Transmission Organizations, Notice of Intent to

Consult with State Commission, 63 FR 66,158 (Dec. 1, 1998), FERC

Stats & Regs. para. 35,534 (1998).

\57\ See Appendix for a list of commenters.

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III. Discussion

A. Existing Barriers and Impediments To Achieving Fully Competitive

Electricity Markets

In the NOPR, the Commission expressed its belief that there remain

important transmission-related impediments to a competitive wholesale

electric market. The Commission grouped these remaining impediments

into two broad categories: (1) The engineering and economic

inefficiencies inherent in the current operation and expansion of the

transmission grid, and (2) continuing opportunities for transmission

owners to unduly discriminate in the operation of their transmission

systems so as to favor their own or their affiliates' power marketing

activities.58

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\58\ FERC Stats. & Regs. para. 32,541 at 33,696.

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With respect to engineering and economic inefficiencies, the NOPR

noted that the transmission facilities of any one utility in a region

are part of a larger, integrated transmission system which, from an

electrical engineering perspective, operates as a single

machine.59 Engineering and economic inefficiencies occur

because each separate operator usually makes independent decisions

about the use, limitations and expansion of its piece of the

interconnected grid based on incomplete information, even though any

action taken by one transmission provider can have major and

instantaneous effects on the transmission facilities of all other

transmission providers. The Commission noted that, while this was not a

new phenomenon, the demands placed on the transmission grid had changed

in recent years due to (1) increases in bulk power trade, (2) large

shifts in power flows, and (3) an increasingly de-integrated and

decentralized competitive power industry.60 As a consequence

of these changes in trade patterns and industry structure, certain

operational problems had become more significant and difficult to

resolve.

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\59\ Id. at 33,697.

\60\ See id.

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Engineering and Economic Inefficiencies. The NOPR identified a

number of specific economic and engineering inefficiencies. First, the

NOPR noted that the reliability of the nation's bulk power system was

being stressed in ways that have never been experienced before, and

questioned the continued feasibility of one-on-one coordination of an

interconnected transmission grid encompassing more than 100

transmission owners and 140 separate control areas.61

Second, the NOPR observed that there were increasing difficulties in

accurately computing Total Transmission Capacity (TTC) and Available

Transmission Capacity (ATC), assessments that require reliable and

timely information about load, generation, facility outages and

transactions on neighboring systems, as well as consistency in

methodologies among systems.62 Third, the NOPR noted that

efficient congestion management required regional actions, and that the

current methods for managing congestion (e.g., Transmission Line

Loading Relief procedures in the Eastern Interconnection), which do not

attempt to optimize regional congestion relief, were cumbersome,

inefficient and disruptive to bulk power markets.63 Fourth,

the NOPR expressed concern that the uncertainty associated with

transmission planning and expansion had increased with the increasing

number and distance of unbundled transactions and the wider variation

in generation dispatch patterns. The NOPR pointed to a noticeable

decline in planned transmission investments and expressed concern that,

without a regional approach to planning and expansion, it would be

difficult to address complex and controversial issues that arise when

the benefits of an expansion do not necessarily accrue to the

transmission system that must undertake the expansion.64

Finally, the NOPR explained that pancaked transmission rates (where a

separate access charge is assessed every time the transaction contract

path crosses the boundary of another transmission owner) restrict the

size of regional power markets. The Commission added that the

balkanization of electricity markets hurts consumers who pay higher

transmission rates and have access to fewer generation

options.65

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\61\ See id. at 33,699.

\62\ Id. at 33,700.

\63\ Id. at 33,701-02.

\64\ See id. at 33,702-03.

\65\ Id. at 33,703.

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Continuing Opportunities for Undue Discrimination. With respect to

continuing opportunities for undue discrimination, the NOPR observed

that, when utilities control monopoly transmission facilities and also

have power marketing interests, they have poor incentives to provide

equal quality transmission service to their power marketing

competitors.66 The NOPR explained that the Commission had

made this point in Order No. 888:

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\66\ Id. at 33,704.

It is in the economic self-interest of transmission monopolists,

particularly those with high-cost generation assets, to deny

transmission or to offer transmission on a basis that is inferior to

that which they provide themselves. The inherent characteristics of

monopolists make it inevitable that they will act in their own self-

interest to the detriment of others by refusing transmission and/or

providing inferior transmission to competitors in the bulk power

markets to favor their own generation, and it is our duty to

eradicate unduly discriminatory practices.67

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\67\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,682.

In the NOPR, the Commission noted that functional unbundling does not

change the incentives of vertically integrated utilities to use their

transmission assets to favor their own generation, but instead attempt

to reduce the ability of utilities to act on those

incentives.68

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\68\ As noted in the NOPR, in Order No. 888, the Commission

received and considered numerous comments that functional unbundling

was unlikely to work, and that more drastic restructuring, such as

corporate unbundling, was needed. For example, the Federal Trade

Commission advised the Commission that a functional unbundling

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

for some utilities to exercise market power in the regulated system.

Preventing them from doing so by enforcing regulations to control

their behavior may prove difficult.'' However, the Commission

decided at the time to adopt the less intrusive and less costly

remedy of functional unbundling. FERC Stats. & Regs. para. 32,541 at

33,707.

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The NOPR expressed concern about continuing indications that

transmission service problems related to discriminatory conduct remain

and concluded that these problems are impeding competitive wholesale

power markets.69 The NOPR also noted that

[[Page 818]]

instances of actual discrimination may be undetectable in a non-

transparent market and, in any event, it is often hard to determine, on

an after-the-fact basis, whether an action was motivated by an intent

to favor affiliates or simply reflected the impartial application of

operating or technical requirement. The NOPR added that, while

continued discrimination may be deliberate, it could also result from

the failure to make sufficient efforts to change the way integrated

utilities have done business for many years. The Commission expressed

concern that the difficulty in determining whether there has been

compliance with our regulations raises the question as to whether

functional unbundling is an appropriate long-term regulatory solution.

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\69\ The NOPR described specific examples of undue

discrimination that had been brought to its attention through formal

complaints, informal complaints made to the Commission's enforcement

hotline, oral and written comments made in conjunction with public

conferences held by the Commission, and pleadings filed with the

Commission in various dockets. The complaints generally involved:

(1) Calculation and posting of ATC in a manner favorable to the

transmission provider; (2) standards of conduct violations, (3) line

loading relief and congestion management, and (4) OASIS sites that

are difficult to use. See id. at 33,707-13.

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The NOPR explained that the Commission considers allegations of

discrimination, even if not reduced to formal findings, to be a serious

concern for two reasons. First, this can be indicative of additional,

unreported, discriminatory actions, because there are significant

disincentives to filing and pursuing formal complaints that would

result in definitive findings.70 The NOPR expressed a

concern that actual problems with functional unbundling may be more

pervasive than formally adjudicated complaints would suggest. Second,

the NOPR explained that allegations of discrimination are serious

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

participants that the market is not working fairly. If market

participants perceive that other participants have an unfair advantage

through their ownership or control of transmission facilities, it can

inhibit their willingness to participate in the market, thus thwarting

the development of robust competition. The NOPR added that such

mistrust can also harm reliability.71

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\70\ As noted in the NOPR, transmission customers are reluctant

to make even informal complaints because they fear retribution by

their transmission supplier; the complaint process is costly and

time-consuming; the Commission's remedies for violations do not

impose sufficient financial consequences on the transmission

provider to act as a significant deterrent; and, in the fast-paced

business of power marketing, there may be no adequate remedy for the

lost short-term sales opportunities in after-the-fact enforcement.

See FERC Stats. & Regs. para. 32,541 at 33,706.

\71\ Id.

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The NOPR explained the potential for undue discrimination increases

in a competitive environment unless the market can be made structurally

efficient and transparent with respect to information, and equitable in

its treatment of competing participants. Also, a system that attempts

to control behavior that is motivated by economic self-interest through

the use of standards of conduct will require constant and extensive

policing and requires the Commission to regulate detailed aspects of

internal company policy and communication. The NOPR added that

functional unbundling does not necessarily promote light-handed

regulation and undoubtedly imposes a cost on those entities that have

to comply with the standards of conduct and abide by rules that limit

the flexibility of their internal management activities. The NOPR

stated that the perception that many entities that operate the

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

to build a competitive power market, and it created needless

uncertainty and risk for new investments in generation.72

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\72\ See id. at 33,714.

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Comments. Engineering and Economic Inefficiencies. Virtually all

commenters support the NOPR's premise that engineering and economic

inefficiencies exist in the operation, planning and expansion of the

regional transmission grid and that these inefficiencies hinder

electric system reliability and a fully competitive bulk power

market.73 Many commenters state further that, in the new

industry structure, coordinated regional transmission planning has

become a thing of the past and new transmission additions that will

benefit reliable grid operations are being delayed.74

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\73\ See, e.g., Duquesne, Entergy, Florida Power Corp., NU,

Kentucky Commission, NECPUC, Ohio Commission, Texas Commission, DOE,

American Forest, Arkansas Cities, East Texas Cooperatives, EPSA,

First Rochdale, FMPA, Oglethorpe, PNGC, Powerex, Public Citizen,

SoCal Cities, Sonat, Williams.

\74\ See, e.g., EPRI, Florida Power Corp, Duquesne, Entergy,

SoCal Cities, Merrill Energy, TAPS, IPCF, Powerex.

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FMPA states that grid fragmentation harms reliability.75

NU and EPRI note that recent demand growth has meant new stresses on

grid reliability and there is less coordination of generation and

transmission planning. TXU Electric states that, as the shift from

regulation to competition accelerates, and restructuring efforts

proliferate, the regional transmission grid is being exposed to

stresses that cannot be alleviated without regional solutions.

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\75\ FMPA at 24.

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WPPI describes a situation in 1997 in which the 345-kV transmission

facility between MAPP and MAIN was overloaded as a result of

transactions scheduled within MAPP, and Wisconsin operators became

aware of the problem only when the constrained 345-kV facility

automatically separated in response to the overload. WPPI explains

that, with the 345-kV facility shut down, other transmission facilities

in the region overloaded, causing the transmission system over a large

region to come perilously close to a blackout. WPPI adds that, because

transmission providers do not have information about their neighbors'

on-system transactions to serve native load, they are unable to predict

the impact of potential TLR events. WPPI says that, in the face of this

uncertainty, transmission providers have to make overly conservative,

but inaccurate assumptions which unnecessarily reduce the amount of

transmission capacity available to the market.

TAPS states that, when the owners of a constrained interface

between MAPP and MAIN tried to remove the line for service for

maintenance, they found that 500 MW of flow remained on the line even

after all scheduled transactions were terminated. TAPS explains that

there were so many transactions in the region at the time that

transmission operators could not determine the source of this 500 MW

loop flow and were unable to ask other parties to cut their schedules

to permit the necessary maintenance.76 TAPS asserts that

transmission owners have engaged in ``creative'' concepts such as CBM

to reduce ATC and argues that price spikes are exacerbated, if not

caused by the failure to have regional transmission information and

control in one place.77

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\76\ TAPS, Appendix A, at 8

\77\ TAPS, Appendix A at 2-5.

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TDU Systems complaint that the current system balkanizes regions

into a series of submarkets, each with its own dominant incumbent

transmission owner/generator that collects its own transmission toll.

EPRI contends that the current off-line ATC calculations result in

inconsistencies of ATC values. Entergy argues that the accuracy of ATC

will continue to be a problem as long as contract path pricing is

used.78

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\78\ Entergy at 8.

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Minnesota Power notes that reliability across the broader region

suffers simply because of different standards for ATC calculations

within and across NERC

[[Page 819]]

regions and, indeed, different terminology and operating practices.

Minnesota Power states that: the market currently suffers as

participants attempt to deal with multiple OASIS sites; existing

tagging and reservation practices that limit transactions due to the

complexity of arrangements; its transactions are subject to curtailment

pursuant to two different procedures, NERC TLR and MAPP LLR; and

congestion management alternatives to line loading relief have not

succeeded because they lack regional coordination. Minnesota Power

argues that energy price volatility will continue to increase unless

there is a viable process, supported by transmission rights and

secondary transfer markets, where a participant can secure transmission

daily, or as needed, to bring the least cost supply to its customers.

EPSA asserts that one of the major impediments to robust

competitive bulk power markets is the current balkanization of the

system with dozens of individual utilities, NERC Regional Councils, and

security coordinators, and state laws and regulations imposing a

patchwork of often inconsistent and incompatible rules for the use of

the interstate transmission system. EPSA argues that the operational

and economic inefficiencies detailed in the NOPR are not unique to

certain region as and may be most pronounced in those regions where

competition has yet to take hold.79

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\79\ EPSA specifically points to the SERC as a region where

``state commissions and utilities may be arguing that they don't

`need' RTOs to promote competitive markets,'' at a time when

Southeastern markets trail the rest of the nation in proposed

merchant plant development and power trading, ``both hallmarks of

robust wholesale competition and workable open access policies.''

EPSA notes that SERC is the largest NERC region, both in load and

peak demand, yet SERC and FRCC together constitute only 5.2 percent

of the wholesale power trades nationwide.

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SoCal Edison states that existing transmission systems were

designed to serve native load customers in a defined area, in the most

efficient manner possible, in conjunction with the generation that it

owned and operated, and were not designed to function as common

carriers. SoCal Edison concludes that that radical changes in

downstream generation markets are having, and will continue to have,

significant and largely adverse effects of transmission systems.

Consumers Energy echoes this concern, noting that it should be obvious

that the current transmission system was designed to deliver locally

generated power to local markets with interfaces used primarily for

reliability purposes. Consumers Energy states that the system is simply

not engineered to move large quantities of power from many distant

generation sources to millions of end users.

Williams concludes that problems with congestion management,

pancaked transmission rates, parallel path or loop flows, inaccurate

ATC postings, and transmission facilities management and expansion

planning continue to impede the development of robust, competitive

wholesale electric markets in the United States.

PECO states that current TLR procedures allow one entity to cause

the curtailment of numerous third party transactions on a regular basis

to preserve power delivery in its single control area, regardless of

the impact on other control areas. PECO argues that, while physical

operation of the grid is maintained under these TLR procedures,

reliable, inter-control area power delivery is not assured and market

participants are denied fair access to the grid.

Tampa Electric states that, within peninsular Florida, transmission

users must often go to several individual transmission providers and

OASIS nodes, sign multiple agreements with various providers and

attempt to piece together and navigate through various partial paths to

connect a power sale to a buyer. Tampa Electric concludes that access

to transmission services within this region is not as open as it could

be to facilitate an efficient, robust wholesale market.

AEP states that coordination that previously existed in a fully

integrated electric system of the construction of new generation and

transmission facilities has eroded due to the separation of these

functions. AEP states that congestion constraints could potentially

inhibit the development of additional generation capacity or provide a

disincentive to add generating capacity where needed. AEP also notes

that the priorities of state regulatory agencies sometimes favor the

needs of native load customers that can create conflicts among

competing interest at the regional level. AEP also states that

developers of new merchant generation plants have become less willing

to share their long-term planning goals with transmission owners due to

the business strategies that accompany a more competitive power market.

However, AEP argues that removal of pancaking is not consistent with

economic efficiency and may distort future transmission expansion

because the cost of transmission should be based on distance and

location.\80\

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\80\ AEP at 1, and Attachment to AEP's comments (Statement of

Paul Moul). As discussed in the Transmission Ratemaking section

(Section G), elimination of pancaked rates (multiple access charges

assessed only because the transaction crosses a corporate boundary)

does not constitute a prohibition on distance sensitive rates.

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Several commenters state that needed transmission expansion is not

taking place because of a lack of pricing incentives to build new

transmission.\81\ EPRI states that failure to satisfy grid expansion

needs is resulting in increasing frequency and duration of power

disturbances and outages costing $50 billion per year.

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\81\ See, e.g., Transmission ISO Participants, H.Q. Energy

Services, Powerex.

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WPPI points out that transmission planning must be undertaken on a

regional, not a state basis, noting that import capability from MAPP

into Wisconsin is sometimes constrained by facilities located outside

of Wisconsin, e.g., transformers and lines located in Illinois and

Minnesota. On the other hand, Allegheny asserts that the industry has

not failed to plan and coordinate on a regional basis and cites

examples of study groups and planning committees, such as VEM

(Virginia-ECAR-MAAC) and GAPP (General Agreement on Parallel Paths).

Most commenters assert that pancaked transmission access charges

prevent efficient access to regional markets and distort the generation

market.\82\ A few commenters, however, question the benefits associated

with eliminating rate pancaking. Southern Company observes that the

severity of pancaking effects may vary from region to region.\83\

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\82\ See, e.g., FMPA, IMEA, NECPUC, Ohio Commission, Texas

Commission, American Forest, Arkansas Cities, East Texas

Cooperatives, Oglethorpe, PNGC, Powerex, Williams, WPSC.

\83\ For illustration, Southern Company points out that a

customer in its service area can transmit power 500 miles away for

$3/MWh whereas a customer wanting to transmit power from Boston to

Washington, DC (also a distance of 500 miles) will have to go

through the three PJM, New England and NY ISOs and pay a total of

approximately $14/MWh.

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Continuing Opportunities for Undue Discrimination. Comments dealing

with continuing opportunities for undue discrimination fall generally

into two camps. On the one side, transmission customers and some

transmission providers agree with the NOPR's premise that opportunities

for discrimination exist, that perceptions of discrimination are also a

serious impediment to competitive bulk power markets, and that

functional unbundling does not reflect the optimal long-term regulatory

solution.\84\ On the other side,

[[Page 820]]

a number of transmission providers disagree with these premises.\85\

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\84\ E.g., American Forest, Los Angeles, TAPS, UAMPS, Steel

Dynamics, Turlock, Cinergy, Statoil, WPPI, NJBUS, MidAmerican, LG&E,

Clarksdale, Michigan Commission, New Smyrna Beach, Industrial

Consumers, IMPA, First Rochdale, East Texas Cooperatives, FMPA, TDU

Systems, Canada DNR, Allegheny, IMEA, Sonat, Public Citizen, EPSA,

CCEM/ELCON, UtiliCorp and FTC. [85]:United Illuminating, Southern

Company, MidAmerican, Duke, PSE&G, FP&L, Entergy, FirstEnergy,

Alliance Companies, Lenard and Florida Power Corp.

\85\ United Illuminating, Southern Company, MidAmerican, Duke,

PSE7G, FP&L, Entergy, First Energy, Alliance Companies, Lenard and

Florida Power Corp.

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Comments Asserting That Discrimination Still Exists. AMP-Ohio

points to an event last summer when it was unable to transmit power

from a generator on AEP's system to a load on the FirstEnergy system

and was forced to purchase power from FirstEnergy at $4000/MWh. AMP-

Ohio contends that AEP and FirstEnergy were simultaneously reporting

zero ATC during the hour, i.e., an event that cannot be rationalized by

AMP-Ohio (i.e., an interface that is fully loaded in both directions at

the same time would, in AMP-Ohio's view, cancel out).

UAMPS argues that three transmission owners that jointly own

segments of a single transmission line have avoided releasing the

capacity of this line under their open access tariffs through a series

of contractual arrangements that distributes transmission rights

directly to each of their merchant functions. As a result, only the

transmission owners' merchant functions have the ability the schedule

transmission service over the line. UAMPS contends that this example,

and others, confirm the Commission's perception that the remedies

mandated in Order No. 888 have not eliminated discrimination. UAMPS

states that it is intuitively obvious that when the transmission

function and merchant function ultimately serve the same master,

neither can be truly independent.

Hogan contends that, without an efficient regional spot market and

its ease of access, the problems of discrimination will persist. FTC

concludes that several years of industry experience confirm the concern

that discrimination remains in the provision of transmission services

by utilities that continue to own both generation and transmission. FTC

concludes that reliance on behavioral rules have proved to be less than

ideal.

Cinergy contends that reliance on CBM by some transmission

providers this summer provided their native load an unfair operational

edge over network service in the import of power through interconnects

that were the subject of TLR orders. Cinergy argues that the more

severe impact on market efficiency is caused by the lack of information

underlying the transmission provider's implementation of TLRs, and

raises significant opportunities for transmission providers to use

alleged reliability reasons to hide conduct actually motivated to

protect their own or their affiliate's own power market. Cinergy

concludes that market participants will never know the real answer

because it may be impossible to prove abuse of the TLR procedures with

access to information on the nature and cause of constraints and the

lack of consistency in implementing TLRs across the regions. Cinergy

adds that, even where there may be sufficient evidence to prove

discrimination, potential complainants may fear retribution by the

transmission provider, and may also be hesitant to file complaints

because of the litigation costs of the complaint process and the lack

of remedy for lost short-term market opportunities.

Enron/APX/Coral Power state that the following types of relatively

overt, although difficult to detect, discrimination occur: (1) Offers

of attractive transmission service to a transmission owner's affiliate

or merchant function that are not similarly offered to others; (2)

advance notification to the affiliate or merchant function of the

availability of transmission service or the availability of a new

service; and (3) changes in procedures, such as scheduling deadlines,

for obtaining transmission service in ways that benefit the affiliate

or merchant function. Enron/APX/Coral Power (as well as CCEM/ELCON,

UtiliCorp and EPSA) also argue that a ``principal form of

discrimination grows out of the exemption from the pro forma OATT and

OASIS that is enjoyed by transmission bundled with service to captive

`native-load' customers.'' Enron/APX/Coral Power believes that, if the

Commission were to conduct an investigation of compliance with the

Commission's open access requirements and the uses of their own

transmission system during periods of extreme peak loads and volatile

prices during the past summer, the Commission would uncover evidence of

widespread abuses. According to Enron/APX/Coral Power, these abuses

would include instances where the transmission provider imported power

on a network basis, as if it were intended to service captive, native

load customers, only to turn around and sell that power competitively,

off-system; where scheduling requirements or deadlines were changed

without adequate notice to third parties; and where ATC amounts that

either were not posted or were posted in an untimely manner.

NASUCA concludes that, despite Order No. 888, there is still reason

for concern that continued discrimination in the provision of

transmission services by vertically integrated utilities may be

impeding competitive electric markets.

EPSA states that the prospect of real competition continues to be

threatened by (1) arbitrary and discriminatory curtailment and line

loading relief policies, and (2) needlessly complex and overly

restrictive transmission planning, expansion and interconnection

practices.

TAPS argues that the anticompetitive effects of allowing a subset

of competitors to control essential facilities have been long

recognized.\86\ TAPS provides specific examples that it claims show

that discrimination exists: (1) The price spikes in June 1998 and

Summer of 1999 where the asserted ATC was inadequate to allow external

generation resources to meet the needs of the market; (2) failure of a

transmission owner to provide necessary upgrades; and (3) a

transmission owner taking negotiating positions contrary to a clear

provision of the Open Access Transmission Tariff (OATT). In its reply

comments, TAPS describes a recent situation where AEP, acting in its

role as the NERC Security Coordinator, informed IMPA that it had

implemented a TLR seven minutes earlier, too late for IMPA to replace

the curtailed schedule with another transaction at market prices, which

were $35/MWh. TAPS contends that IMPA had no effective choice but to

make up the shortfall by purchasing emergency energy from AEP at $100/

MWh. In following hours that day, IMPA elected to purchase power from

AEP at $35/MWh rather than continue its other purchase options (at $17/

MWh) and risk further curtailments. TAPS observes that AEP

substantially profited from delayed communication of the TLR, by

selling power to IMPA at nearly three times the then-market price. TAPS

states that, even assuming AEP was acting properly on this occasion,

this example illustrates the inherent conflict of interest in combining

security coordinator functions with that of market participant. TAPS

argues that this diminishes the faith in the market place and breeds

mistrust. Based on the examples it provides and on the evidence

reviewed in the NOPR, TAPS

[[Page 821]]

recommends that the Final Rule make formal findings that undue

discrimination remains widespread throughout the industry.

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\86\ TAPS cites to a 1912 Supreme Court case involving the

control of a railway terminal by several railroads which their

competitors were required to use. See United States v. Terminal RR

Ass'n, 224 U.S. 383, 397 (1912).

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Steel Dynamics states that the Commission needs to build confidence

that transmission customers will not be victimized when markets get

tight and claims the Commission's record to date has been uneven. Steel

Dynamics cites a case in which the Commission determined that Niagara

Mohawk Power Corporation had committed several violations of the OASIS

posting requirements and standards of conduct in order to favor its

marketing affiliate over a third-party user.

Clarksdale states that it has experienced problems with the posting

of ATC by Entergy on the OASIS. Clarksdale states that on July 21,

1999, it attempted to purchase from Cajun Electric Cooperative 20 MW of

power for whatever length of time that Cajun would have had it

available up to one week. Entergy denied the transaction on the basis

that the ATC between Entergy and Cajun was zero. Clarksdale complained

and the next day the ATC for this interface was shown to be 1,700

megawatts; however, by that time Cajun had sold the power to another

entity and it was no longer available for Clarksdale. Clarksdale

submits that the incident, along with others Clarksdale reported,

compels the conclusion that the function of security coordination

should be entirely separate from the transmission owner and from the

generation owner and that participation in an absolutely independent

RTO should be mandated by the Commission in the final rule.

FMPA states that, whether because of discriminatory motivations or

simply because of balkanized perspectives (or both), there have been

numerous instances of Florida's dominant transmission owners falling

short on the transmission planning performance. According to FMPA,

Florida's dominant transmission owners have failed to promptly address

regionally significant constraints (until addressing them became

advantageous for their own merchant function), and have continued to

impose discriminatory transmission-related construction requirements.

FMPA claims that relying on functional separation rules to curb the

self interest of market-interested transmitters when huge sums of money

are at stake is like ``relying on words to hold back the tide.'' \87\

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

\87\ FMPA at 23-24.

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WPPI states that it routinely experiences and observes subtle and

difficult to detect problems in the marketplace. WPPI states that,

because they are subtle and difficult to detect, they are not

susceptible to any prompt and effective regulatory remedy. WPPI adds

that prosecution of complaints is expensive and time consuming and

customers do not have the ability to prosecute each such incident.

WPPI contends that transmission owners are able to dispatch their

resources in order to manipulate their exposure to TLRs, while

customers cannot. WPPI characterizes this tactic as a ``shell game''

because it is purportedly accomplished by designating fictional sources

and sinks and treating one transaction as two separate transactions.

WPPI contends that these actions leave other transmission users to bear

the costs of curtailments and denials of service. WPPI argues that

these manipulations of TLRs are ``rampant.''

WPPI states that during summer peak periods, when it claims power

prices exceeded $5,000/MWh in the Eastern Interconnection, at least one

Midwestern transmission-owning utility appears to have been able to

abuse its control-area operator authority to gain a market advantage.

According to WPPI, as a control-area operator, the transmission owner

at issue declared that power shortages had created an emergency

situation which allowed it to relax the transmission limitations that

it had imposed on other market participants, enabling the transmission

owner to acquire less expensive power from the MAPP region. WPPI claims

that the transmission owner thereby gained a market advantage, at a

time when market advantages were worth huge sums. WPPI claims that most

if not all other control-area operators in the region played by the

rules and did not abuse the system to access less expensive power for

which ATC ostensibly was not available. WPPI asserts that utilities

that are not control-area operators had no choice other than to buy

high cost, locally generated power, and that they ``lack not only the

right, but also the might'' \88\ to declare an emergency or to

recalculate ATC to help themselves. WPPI and Cinergy maintain that this

recent event provides a clear example of the continuing potential,

under present industry structure, for vertically integrated utilities

to abuse their transmission control to gain market advantages and for

that reason, among others, the Commission should mandate that entities

under its jurisdiction participate in RTOs.

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

\88\ WPPI at 31.

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TDU Systems provide a number of examples which raise their concerns

about undue discrimination, including: (1) Failure of an incumbent IOU

to reduce its own out-of-region power sales during a period when the

system was experiencing overloads and the transactions of other

transmission users were jeopardized; (2) overly aggressive and

selective enforcement of tariff requirements on transmission customers

than are imposed on the transmission providers' own merchant function;

(3) selectively targeting generating units that are jointly owned by

competitors when redispatch of the transmission system is required to

relieve line loading; (4) self-serving ATC calculations in

circumstances when transmission customers have no way of knowing

whether access is being denied legitimately or through manipulation for

competitive gain; and (5) onerous and lengthy negotiations to obtain

system studies. TDU Systems contend that there is a fire under the

smoke of allegations of discrimination, and those complaining of the

anecdotal nature of its information haven't provided any evidence to

show that discrimination is not occurring.

TXU Electric states that, if a truly successful, restructured

competitive electric industry is to achieve its full potential, it is

incumbent of all concerned, transmission providers, users and

regulators alike, to move beyond the impediments of the past, including

hidden motivations on the part of some, unfounded fears of hidden

motivations on the part of others, and a general environment of

distrust. TXU Electric adds that, transmission users and regulators

must have confidence that the transmission grid is truly an open, non-

discriminatory and robust commercial highway and transmission providers

must inspire that confidence. TXU Electric concludes that the

Commission's voluntary collaborative approach is an important step in

the right direction.

LG&E states that, under the current system, transmission owners'

operational decisions, even if well intentioned, are surrounded by a

cloud of suspicion that, acting in the name of reliability, the

transmission owner has enhanced its position in the generation market.

LG&E agrees that this perception that the transmission system is not

being operated in an even handed manner undermines confidence in the

non-discriminatory open access implemented under Order No. 888.

Virginia Commission agrees that allegations of discrimination

represent only known problems, and there may be many unknown ones

remaining given that it is difficult for transmission users

[[Page 822]]

to identify and demonstrate instances of discrimination.

Canada DNR states that discriminatory behavior by transmission

operators, identified in the NOPR as the second significant driver for

establishment of RTOs, is not perceived as a key impediment to the

evolution of efficient bulk power markets in Canada.

Dynegy argues that transmission provides have the incentive and

ability to discriminate in today's markets due to the combination of

control over transmission with participation in power markets and the

existing regulatory structure that exempts transmission providers from

the open access rules of Order Nos. 888 and 889 for its bundled, native

load customers. Dynegy argues that the ``native load'' exemption can be

and is often manipulated to favor the transmission providers' own or

affiliated merchant functions.

PECO notes that, in their capacity as vertically integrated

utilities, transmission providers have access to critical market

sensitive information with respect to each transaction (e.g., source,

sink), at a time when they are in direct competition in the same

markets and with the same transmission customers whose market

information they have. PECO argues that, in spite of the existence of

functional unbundling and codes of conduct, the serious potential for

conflicts of interest and abuse inherent in the current structure

cannot be ignored.

Comments Asserting That Discrimination Is Not a Problem. A number

of commenters, mostly transmission owners, do not believe that

significant discrimination problems remain with respect to wholesale

transmission access pursuant to Order No. 888. As a general matter,

those transmission owners whose actions are cited in other pleadings as

examples of undue discrimination disagree with those characterizations

of the cited events and declare that they provide non-discriminatory

transmission service under their OATT. These transmission owners

contend that the disputes cited in the pleadings are not the result of

discriminatory practices; rather, they are the result of the priority

accorded native load customers under the OATT, and good faith errors on

the part of the transmission provider trying to administer complex

rules and tariff changes that have necessitated fundamental changes to

the structure of companies and the way they do business.

EEI contends that many of the difficulties transmission customers

encounter in obtaining price, availability and transmission service

result in a technology gap that can be, and often is, interpreted as

discriminatory behavior. EEI also contends that many allegations of

discrimination are ``rooted at their heart'' on the scarcity of

transmission resources and not overt attempts to discriminate against

specific customers.

PSE&G argues that supposition and anecdotal evidence of alleged

abuses by transmission owners does not justify a radical change in the

existing regulatory scheme. PSE&G contends that, while the incentive to

maximize shareholder value is certainly a powerful force in the

marketplace, the requirements of law, such as Order Nos. 888 and 889,

will prevail.

Duke argues that mere anecdotes of discrimination, involving

unnamed parties and without reference to specific facts, are not

evidence of anything, let alone discrimination, and cannot form the

basis of a reasoned decision. Duke also lists a number of formal

complaint proceedings where the Commission found the transmission

provider to have acted properly. Entergy argues that those alleging

discrimination, as competitors of transmission providers, have an

economic incentive to make their own allegations. Entergy adds that, if

perceptions of discrimination were impeding competitive markets, there

would not be 20,000 MW of generation investment proposed in its region.

United Illuminating complains that many of the allegations of undue

discrimination presuppose that all utilities are the same, i.e.,

vertically integrated transmission, distribution and generation

companies, and do not recognize that a number of utilities are

divesting their generation business.

Southern Company states that the goal of non-discriminatory

transmission service is already being satisfied in the Southeast.

Southern Company asserts that it has separated its transmission and

reliability functions from its wholesale merchant function up to the

level of ``very senior management.'' Southern Company submits that it

is unaware of any pending allegations of discrimination against it.

Southern Company adds that the Southeast is characterized by large

transmission systems such as Southern Company, Tennessee Valley

Authority, and Entergy and that these transmission systems are already

planned and operated on a regional basis. Southern Company also points

out that it alone covers a region as large as (if not larger than) many

ISOs currently in existence. Under these circumstances, Southern

Company believes that the Commission's open access initiatives have

worked in the Southeast and that additional steps are not required to

ensure non-discriminatory transmission service.

MidAmerican asserts that complaints received by the Commission

about alleged discrimination should not be the primary basis for

determining if the market is successful. According to MidAmerican, if

it is assumed that an adequate number of parties are competing

successfully, it could be concluded that the complaints may be

indications of ill-defined problems not yet resolved, isolated market

flaws, or indications of a successful market with somewhat inadequate

tools.

Duke believes that its transmission organization is meeting the

needs of its customers as evidenced by the very few and relatively

insignificant complaints Duke has received regarding the administration

of its OATT. Duke believes that Order No. 888 has been quite successful

and, although it agrees with the Commission that elimination of

balkanized transmission operations through the formation of larger,

regional operations is ultimately preferred, Duke does not believe

Order No. 888 should be abandoned hastily.

Duke argues that disputes are primarily the result of the

complexity of the priority scheme in the Commission's pro forma tariff,

the rules for which are still being developed; the inherent tension

between the Commission's comparability requirement and the requirements

of state-regulated native load customers; and the obligation to ensure

reliability of the transmission grid on a real time basis. Duke asserts

that the vast majority of transactions occurring as a result of Order

No. 888 do not produce transmission disputes and, to the extent that

isolated instances of discrimination have occurred, the Commission has

adequate authority to address the problem.

Duke also maintains that a major source of confusion involves the

rights of native load customers versus wholesale transmission users

under the pro forma tariff and that this issue remains subject to

disagreement and needs further clarification. Duke says its conclusion

is reinforced by its experience as a market participant in areas where

there are ISOs. Duke asserts that the establishment of ISOs in

California, NEPOOL and PJM has not resulted in the elimination of

disputes over tariff ambiguities. Duke questions the assertion that

disagreements between customers and individual transmission owners are

indicative of significant ongoing discrimination.

Florida Power Corp. and FP&L's comments are similar to Duke's.

Florida

[[Page 823]]

Power Corp. and FP&L state that they have not received any formal

complaints alleging undue discrimination with regard to their OATT.

Florida Power Corp. and FP&L agree that the increasing number of

transactions has led to a concomitant increase in transmission

disputes; however, they characterize the disputes as legitimate

disagreements over policy or meaning of the pro forma tariff as opposed

to true allegations of discriminatory conduct. Like Duke, Florida Power

Corp. and FP&L believe that many of the allegations of potentially

discriminatory conduct are attributable to two primary areas: (1)

Rights of native load customers versus wholesale wheeling customers;

and (2) disputes arising from the complex priority scheme in the pro

forma tariff. According to FP&L, disputes will still occur until the

issues relating to priority rights are resolved. FP&L argues that the

Commission cannot expect that any remedy will eliminate discrimination

claims in light of the Eighth Circuit Court's decision in Northern

States Power Co. v. FERC.\89\

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\89\ See Northern States Power Co. (Minnesota) and Northern

States Power Co. (Wisconsin), 83 FERC para. 61,098, clarified, 83

FERC para. 61,338, reh'g, clarification and stay denied, 84 FERC

para. 61,128 (1998), remanded, Northern States Power Co., et al. v.

FERC, 176 F.3d 1090 (8th Cir. 1999), reh'g denied (unpublished order

dated Sept. 1, 1999), order on remand, 89 FERC para. 61,178 (1999)

(request to withdraw curtailment procedures pending) (Northern

States).

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FPL and Florida Power Corp. argue that unsubstantiated allegations

do not constitute evidence of discrimination and should be

characterized as legitimate disputes over tariff interpretation, while

EEI describes some of the allegations as ``one-sided characterizations

of cases now being litigated.'' FPL also contends that some intervenors

adopt the stance that, whenever the transmission provider and customer

are in disagreement, it evidences discrimination. Florida Power Corp.

states that, if undue discrimination exists outside of Florida, it is a

function of the newness of the Commission's open access rules, and it

is far too soon to declare functional unbundling ineffective. Florida

Power Corp. agrees with the Commission's statement that it may be

impossible to distinguish an inaccurate ATC presented in good faith

from an inaccurate ATC posted for the purpose of favoring the

transmission provider's marketing interests, but concludes that, once

technical issues have been resolved about ATC calculations, the volume

of disputes will be greatly diminished. Florida Power Corp. adds that

there is no evidence of a pattern of industry-wide undue

discrimination, and concludes that mere perceptions cannot provide a

justification for generic remedial action.

Entergy, FirstEnergy, Alliance Companies and Lenard argue that

there is no credible or substantial evidence in the record that

transmission owners have been engaging in discriminatory practices in

providing transmission services under Order Nos. 888 and 889 and,

therefore, the Commission should not, and lawfully cannot, rely on mere

allegations of discriminatory conduct. FirstEnergy states that it has

doubled its control area reservation and back office staff to handle

the five percent of its transmission business that is wholesale related

and still is having difficulty keeping pace with OASIS and tagging

administrative processes. FirstEnergy asserts that due to relatively

new processes associated with open access transmission, there are often

good faith disputes over the proper interpretation of the Commission's

requirements and these disputes should not be mischaracterized as

continued discrimination.

Commission Conclusion. Engineering and Economic Inefficiencies. In

this Final Rule, we affirm our preliminary determination that the

engineering and economic inefficiencies identified in the NOPR

90 are present in the operation, planning and expansion of

regional transmission grids, and that they may affect electric system

reliability and impede the growth of fully competitive bulk power

markets. The sources of these inefficiencies involve: difficulty

determining ATC; parallel path flows; the limited scope of available

information and the use of non-market approaches to managing

transmission congestion; planning and investing in new transmission

facilities; pancaking of transmission access charges; the absence of

clear transmission rights; the absence of secondary markets in

transmission service; and the possible disincentives created by the

level and structure of transmission rates. Virtually all commenters

agree that at least some of these inefficiencies exist. There is

substantial agreement among commenters that most of the engineering and

economic obstacles identified by the NOPR arise from the current

industry structure and can be rectified through development of regional

transmission entities.

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\90\ FERC Stats. & Regs. para. 32,541 at 33,697.

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As noted by Allegheny, the industry historically has done an

excellent job of regional coordination in implementing voluntary

standards to maintain the security of the transmission system through

various study groups and planning committees. However, virtually all

commenters agree that new competitive pressures are interfering with

the use of traditional methods of coordinated regional transmission

planning. As a result, new transmission additions that will benefit

reliable grid operations are being delayed. Some commenters state that

the increasing frequency and duration of power outages have cost the

economy billions of dollars, and they predict that unless this problem

is addressed now the reliability of power supply will worsen. The

traditional use of regional coordination through study groups and

planning committees is no longer effective because these entities are

usually not vested with the broad decisionmaking authority needed to

address larger issues that affect an entire region, including managing

congestion, planning and investing in new transmission facilities,

pancaking of transmission access charges, the absence of secondary

markets in transmission service, and the possible disincentives created

by the level and structure of transmission rates.

We recognize, as some commenters point out, that the degree to

which these inefficiencies act as obstacles to electric competition and

reliability varies from system to system. However, we believe it is

clear that such inefficiencies exist and are sufficiently widespread

that they must be addressed to prevent them from interfering with

reliability and competitive electricity markets.

Continuing Opportunities for Undue Discrimination. As noted, many

transmission customers and some transmission providers argue that there

are continuing opportunities for undue discrimination under the

existing functional unbundling approach. A number of the commenters

provide examples of events that, in their view, indicate that

transmission owners are engaging in undue discrimination. These

commenters also generally believe that even the perception of undue

discrimination is a significant impediment to the evolution of

competitive electricity markets. A number of transmission providers

challenge the relevancy of these examples, characterizing them as

unsubstantiated or anecdotal allegations that do not rise to the level

of evidence of undue discrimination necessary to support generic

action. These transmission providers further contend that many disputes

simply reflect good faith efforts of transmission providers to

interpret the Commission's pro forma tariff and standards of conduct.

These

[[Page 824]]

commenters also generally share the view that the Commission should not

base its decisions in this rule on mere perceptions that may be

prevalent in the industry.

For the most part, the challenges mounted by these commenters are

focused against a determination by the Commission that it should

mandate participation in RTOs in this Rule. As noted in Section C.1 of

this Rule, we have also determined that a measured and appropriate

response to the evidence presented and concerns raised is to adopt a

voluntary approach to the formation of RTOs. However, as discussed

below, we do conclude that opportunities for undue discrimination

continue to exist that may not be remedied adequately by functional

unbundling. We further conclude that perceptions of undue

discrimination can also impede the development of efficient and

competitive electric markets. These concerns, in addition to the

economic and engineering impediments affecting reliability, operational

efficiency and competition, provide the basis for issuing this Final

Rule.

At the outset, it is important to note that the conclusion that

there are continuing opportunities for undue discrimination should not

be construed as a finding that particular utilities, or individuals

within those utilities, are acting in bad faith or deliberately

violating our open access requirements or standards of conduct.

However, we cannot ignore the fact that the vertically integrated

structure reflected in the industry today was created to support the

business objectives of a franchised monopoly service provider that

owned and operated generation, transmission and distribution facilities

primarily to serve requirements customers at wholesale and retail in a

non-competitive environment. Clearly, there are aspects of this

vertically integrated structure that are difficult to transition into a

competitive market. As we noted in the NOPR and Order No. 888,

vertically integrated utilities have the incentive and the opportunity

to favor their generation interests over those of their competitors. If

a transmission provider's marketing interests have favorable access to

transmission system information or receive more favorable treatment of

their transmission requests, this obviously creates a disadvantage for

market competitors.

While we have attempted to rely on functional unbundling to address

our concerns about undue discrimination, there are indications that

this is difficult for transmission providers to implement and difficult

for the market and the Commission to monitor and police. In cases in

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

concerns with functional separation and improper information sharing

with respect to at least four public utilities.91 In

addition, our enforcement staff is receiving an increasing number of

telephone calls about standards of conduct issues, ranging from simple

questions about what is permissible conduct to more serious complaints

alleging actual violations of the standards of conduct. In a number of

cases, our staff has verified non-compliance with the standards of

conduct.92 The petitioners for rulemaking in Docket No.

RM98-5-000 allege that there are common instances of ``unauthorized

exchanges of competitively valuable information on reservations and

schedules between transmission system operators and their own or

affiliated merchant operation employees.'' 93 They also cite

OASIS data showing an instance where a transmission provider quickly

confirmed requests for firm transmission service by an affiliate, while

service requests from independent marketers took much longer to

approve. We believe that some of the identified standards of conduct

violations are transitional issues resulting from a new way of doing

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

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

believe that there is great potential for standards of conduct

violations that will never even be reported or detected. Moreover, as

we stated in the NOPR,94 we are increasingly concerned about

the extensive regulatory oversight and administrative burdens that have

resulted from policing compliance with standards of conduct. The use of

standards of conduct is not the best way to correct vertical

integration problems. Their use may be unnecessary in a better

structured market where operational control and responsibility for the

transmission system is structurally separated from the merchant

generation function of owners of transmission.

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\91\ See Wisconsin Public Power Inc. SYSTEM v. Wisconsin Public

Service Corporation, 83 FERC para. 61,198 at 61,855, 61,860, order

on reh'g, 84 FERC para. 61,120 (1998) (WPSC's actions raised

``serious concerns'' as to functional separation; WP&L's actions

demonstrated that it provided unduly preferential treatment to its

merchant function); Washington Water Power Co., 83 FERC para. 61,097

at 61,463, further order, 83 FERC para. 61,282 (1998) (utility found

to have violated standards in connection with its marketing

affiliate); Utah Associated Municipal Power Systems v. PacifiCorp,

87 FERC para. 61,044 (1999) (finding that PacifiCorp had failed to

maintain functional separation between merchant and transmission

functions).

\92\ See, e.g., Communications of Market Information Between

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

(Commission issued declaratory order based on hotline complaint

clarifying that it is an undue preference in violation of section

205 of the FPA for a public utility to tell an affiliate to look for

a marketing offer prior to posting the offer publicly).

\93\ Petition at 15.

\94\ FERC Stats. & Regs. para. 32,541 at 33,711-12.

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We also cannot dismiss the significance of reports of undue

discrimination simply because they are not reduced to formal

complaints. As many intervenors have asserted, the cost and time

required to pursue legal channels to prove discrimination will often

provide an inadequate remedy because, among other things, the

competition may have already been lost.95 The fact that

evidence of discrimination in the fast-paced marketplace is not

systematic or complete is not unexpected. The fact remains that claims

of undue discrimination have not diminished, and there is no evidence

that discrimination is becoming a non-issue.

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\95\ For example, EPSA has told us: ``Furthermore, even if the

exercise of such discrimination could be adequately documented and

packaged in the form of a complaint under section 206 of the Federal

Power Act under a more streamlined complaint process contemplated by

the Commission, it would still be extremely costly and inefficient

to deal with such complaints on a case-by-case basis. More than

likely, the potential power transactions for which transmission

principally was sought would disappear by the time a Commission

ruling was obtained. Motion to Intervene and Comments of Electric

Power Supply Association in Support of Petition for Rulemaking,

Docket No. RM98-5-000 (filed Sept. 21, 1998), at 3.''

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Finally, we continue to believe that perceptions of discrimination

are significant impediments to competitive markets. Efficient and

competitive markets will develop only if market participants have

confidence that the system is administered fairly.96 Lack of

market confidence resulting from the perception of discrimination is

not mere rhetoric. It has real-world consequences for market

participants and consumers. As stated by NERC, there is a reluctance on

the part of market participants to share operational real-time and

planning data with transmission providers because of the suspicion that

they could be providing an advantage to their affiliated marketing

groups,97 and this can, in turn, impair the reliability

[[Page 825]]

of the nation's electric systems. Lack of market confidence may deter

generation expansion, leading to higher consumer prices. Fears of

discriminatory curtailment may deter access to existing generation or

deter entry by new sources of generation that would otherwise mitigate

price spikes of the type that have been experienced during peak periods

in the last two summer peak periods. Mistrust of ATC calculations will

cause transactions involving regional markets to be viewed as more

risky and will unnecessarily constrain the market area, thereby

reducing competition and raising prices for consumers. The perception

that a transmission provider's power sales are more reliable may

provide subtle competitive advantages in wholesale markets, e.g.,

purchasers may favor sales by the transmission provider or its

affiliate, expecting greater transmission service reliability. We

believe that the potential for such problems increases in a competitive

environment unless the market can be made structurally efficient and

transparent with respect to information, and equitable in its treatment

of competing participants.

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\96\ For example, a representative of Blue Ridge told us:

``There simply is no shaking the notion that integrated generation

and transmission-owning utilities have strategic and competitive

interests to consider when addressing transmission constraints.

Functional unbundling and enforcement of [standard of] conduct

standards require herculean policing efforts, and they are not

practical.'' Regional ISO Conference (Richmond), Transcript at 20.

\97\ NERC Reliability Assessment 1998-2007, at 39.

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In summary, we affirm our conclusion in the NOPR that economic and

engineering inefficiencies and the continuing opportunity for undue

discrimination are impeding competitive markets. As noted below, we

conclude that RTOs will remedy these impediments and that it is

essential for the Commission to issue this Final Rule.

B. Benefits That RTOs Can Offer to Address Remaining Barriers and

Impediments

In the NOPR the Commission explained how the use of independent

RTOs could help eliminate the opportunity for unduly discriminatory

practices by transmission providers, restore the trust among

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

for overly intrusive regulatory oversight.98 The Commission

further identified a number of significant benefits of establishing

RTOs: (1) RTOs would improve efficiencies in the management of the

transmission grid; 99 (2) RTOs would improve grid

reliability; (3) RTOs would remove opportunities for discriminatory

transmission practices; (4) RTOs would result in improved market

performance; and (5) RTOs would facilitate lighter-handed governmental

regulation.100 The Commission requested comments on the

benefits of RTOs and the magnitude of these benefits.

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\98\ FERC Stats. & Regs. para. 32,541 at 33,714.

\99\ These efficiencies include, among other things, regional

transmission pricing, improved congestion management of the grid,

more accurate ATC calculations, more effective management of

parallel path flows, reduced transaction costs, and facilitation of

state retail access programs.

\100\ FERC Stats. & Regs. para. 32,541 at 33,716-20.

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Comments. Description of Benefits. Many commenters support the

establishment of RTOs throughout the United States to effectively

remove the remaining impediments to competition in the power

markets.101 Illinois Commission states that the pursuit of

competition as the driving force for markets in the electric industry

requires developing new institutions and accepting new practices, and

RTOs are the logical next organizational step in the electric industry

restructuring process. Entergy agrees that significant benefits can be

achieved by the creation of properly-structured, large RTOs and that

the Commission has accurately described many of those benefits in the

NOPR. Ohio Commission believes that a properly structured RTO will

facilitate efficient regional generation markets, while preventing

incumbent holding companies from improperly exercising their market

power.

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\101\ See, e.g., PJM, DOE, Illinois Commission.

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PG&E acknowledges that the benefits of Order No. 888 have been

largely reaped, and still significant impediments to an efficient

competitive marketplace remain in place where RTOs are not yet

operational. Moreover, industry restructuring has led to new and

complex operational issues that were unanticipated at the time Order

No. 888 was issued. RTOs represent the most promising and efficient

regulatory method for the Commission to address these issues. Without

RTOs, it would be incumbent on the Commission to take very detailed and

intrusive actions because the transmission grid cannot operate reliably

and efficiently unless the competitive and operational issues are

resolved.

Ontario Power agrees that the electric power industry should now

move beyond the functional unbundling approach prescribed in Order Nos.

888 and 889. TDU Systems asserts that wholesale electric markets will

benefit immensely if RTOs can simply provide transmission service on an

unbiased basis, treating all customers fairly, and take the lead role

in regional transmission planning.

On the other hand, a number of vertically integrated utilities do

not support government action to form RTOs. For example, Duke

recognizes that there may be transmission functions performed today

within individual company control centers, within existing control

areas, or within existing reliability councils that may be better and/

or more efficiently performed by a regional transmission organization.

However, Duke also believes that the industry is voluntarily working to

identify such functions or processes and is effecting meaningful

changes and improvements in a timely manner. Accordingly, Duke believes

that this progress should not be pre-empted by regulatory mandates, and

that there are insufficient data, at this time, to draw meaningful

conclusions regarding the magnitude of benefits that will result from

RTO formation.

Similarly, MidAmerican argues that benefits of RTOs can be realized

without RTOs. MidAmerican claims that existing regional organizations,

such as MAPP, are capable of meeting the Commission's concerns about

eliminating existing impediments to an efficient competitive

marketplace. FP&L states that the NOPR does not attempt to quantify any

of the claimed benefits of RTOs. FP&L is unaware of any data that

specifically and objectively show that ISOs have saved ratepayers money

in those areas where ISOs have been established. Nor is it aware of any

specific quantification of any other actual or projected benefits of

ISOs.

Some commenters contend that the costs of establishing RTOs must

not exceed the benefits. Cal DWR argues that significant start-up costs

and costs associated with duplicative efforts have been higher than the

NOPR appears to recognize. These costs entail not only costs of the new

organization itself, but also market participants' costs in travel,

staffing, and other expenses and investments necessary to participate

or operate in new structures. Other commenters suggest that each

proposal contained in the NOPR should be carefully evaluated for its

cost consequences.\102\

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\102\ See, e.g., Cal DWR, California Board, Southern Company,

Aluminum Companies.

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Seattle notes that its region has the lowest cost electricity in

the Nation and an already thriving wholesale market with little price

volatility. Assuming that an RTO is projected to result in additional

transmission costs, Northwest consumers will be less willing to incur

these costs than consumers in regions where power costs are high and

wholesale prices are extremely volatile. Snohomish and Aluminum

Companies assert that one of fatal flaws of the IndeGO proposal \103\

was that its demonstrable benefits did

[[Page 826]]

not clearly outweigh the costs of its start-up and operation. Snohomish

requests that the Commission not impose an RTO with similar flaws upon

the Northwest. A number of commenters also urge the Commission to

reject any RTO filing for the Northwest or other regions that fails to

provide a strong demonstration that its benefits will substantially

outweigh its projected costs.\104\

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\103\ IndeGO is an independent grid operator proposal that has

been discussed for the Pacific Northwest and Rocky Mountain area.

\104\ See, e.g., Big Rivers, Chelan, California Board,

Industrial Customers, Arizona Commission, EEI, Idaho Commission,

Washington Commission.

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To ensure that RTOs are formed in a cost effective and efficient

manner, SRP proposes a phased approach to RTO development that would

allow RTOs to gradually take on new functions and responsibilities in

response to the needs to the market. In addition, the Commission should

require RTOs to establish criteria against which they will measure cost

effectiveness and efficient performance and to make adjustments where

criteria are not being met.

Canada DNR states that structural differences between the Canadian

and American electric power industries mean that there may be fewer

potential benefits from the formation of RTOs in Canada than those

identified by the Commission for the United States. Consequently, it

believes that Canadian jurisdiction should be able to assess the costs

and benefits of RTO proposals. In addition, it notes that some may find

that, although the benefits do warrant the associated costs, they may

address impediments to efficient electricity markets through other

means.

Comments on RTOs Improving Efficiencies in the Management of the

Transmission Grid.\105\ PJM agrees with the Commission that placing as

many grid management functions as possible under an RTO is the best

means of bringing the benefits of RTOs to the marketplace. A number of

commenters address specific RTO actions as examples of grid management

efficiencies, including use of regional transmission pricing, accurate

estimation of ATC, efficient planning for grid expansion, and

facilitating state retail access programs.

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\105\ As noted earlier, many of the principal benefits of RTOs

(e.g., congestion management, improved reliability, parallel path

flow resolution) are discussed in greater detail later as RTO

minimum characteristics and functions; however, some of the

commenters cited here mention these benefits as part of their

overall discussion of RTOs improving efficiencies in the management

of the transmission grid.

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FMPA claims that a just and reasonable RTO transmission rate, with

a unified regional loss factor or factors, would provide a regionally

rational approach, which is not provided by the existing fragmented

regime. Pancaking has long prevented FMPA and its members located on

the Florida Power Corp. transmission system from economically

delivering the output from their portions of the St. Lucie nuclear

plant to their loads. Similarly, WPSC notes that without an RTO that

encompasses the Midwest region, unjustified pancaked transmission rates

may inhibit the efficient flow of power across the region.

PacifiCorp supports the Commission goal of eliminating transmission

pancaking, to the extent practical. PacifiCorp maintains that such a

goal could be furthered by the creation of the most geographically

expansive RTOs that are technically workable. The goal also could be

met, however, if multiple RTOs within the western United States agree

to reciprocally eliminate charges in connection with the ``export'' or

``import'' of power from one RTO to another. In the western United

States, such ``reciprocity'' agreements may be preferable to the

creation of a single RTO that otherwise is too large to be efficient,

safe and reliable, or of a single RTO for which operating principles

must be unreasonably compromised to attract all necessary transmission

owners.

Allegheny asserts that even with an RTO, grid inefficiencies such

as rate pancaking and congestion will continue unless an appropriate

pricing mechanism is adopted. The various RTO structures, regardless of

size and number, would still need to work cooperatively to ensure that

the various interfaces are sufficient to maintain the reliable

operation of the system. The formation of an RTO, by itself, does not

bring a particular benefit.

Rochdale asserts that a properly structured independent RTO, with a

broad geographic scope, could eliminate incorrect calculations of ATC

and TTC. Furthermore, the motive for discrimination and possible

manipulation that exists where transmission owners with affiliated

power marketers are responsible for reporting ATC and TTC would become

moot. FMPA contends that, without an RTO, most market participants

would remain unable to replicate or trust the transmission owners' ATC

calculations. FMPA indicates that customers and regulators cannot

properly review transmission providers' ATC accounting without access

to their TTC starting points; however, existing Florida OASIS sites do

not provide TTC information. In addition, ATC calculations require

extensive application of engineering judgment. FMPA questions whether

market-interested transmission providers can be trusted to exercise

such judgment disinterestedly. Consequently, FMPA believes that an RTO

could provide unbiased ATC information.

Many commenters believe that RTOs would provide more efficient

planning for transmission and generation investments.\106\ For example,

Entergy agrees that the creation of RTOs can lead to more efficient and

effective planning and expansion of the transmission system. However,

to ensure efficient investment in the transmission system, Entergy

proposes that the Commission encourage innovative pricing policies to

replace traditional cost-of-service ratemaking in certain respects.

Minnesota Power also agrees that an RTO would help identify the best

place on the grid to locate new generation. It believes that the

centralization of regional reliability planning is a big step forward

for enabling independent power producers to build projects and also is

a significant benefit to each transmission owner who deals with

requests from generation groups.

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\106\ Comments are addressed in greater detail in the discussion

of planning and expansion as an RTO minimum function.

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Illinois Commission and Texas Commission state that electricity

consumers in states adopting retail direct access can directly and

fully benefit from the operation of properly constituted RTOs and their

concomitant improvements in system efficiency, reliability and market

competition.

Comments on RTOs Improving Grid Reliability. Many commenters agree

that an RTO could provide improved reliability.\107\ Minnesota Power

supports the formation of a single regional body that operates the

regional grid and enforces reliability rules for the entire region. It

suggests that a non-profit RTO can be expected to enforce reliability

rules fairly and aggressively and, thus, require minimal Commission

oversight. On the other hand, a for-profit RTO may be perceived as

biased towards making a profit at the expense of reliability and may

require additional scrutiny by the Commission.

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\107\ Comments are addressed in greater detail in the discussion

of short-term reliability as an RTO minimum characteristic.

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Michigan Commission strongly supports creating an RTO for the

Midwest that is large enough to ensure reliability. It is very

concerned that splitting the Midwest region into improperly sized

competing ISOs, RTOs, and/or Transcos will affect regional reliability

and delay the benefits of competition. Also, splitting a region into

multiple RTOs reduces

[[Page 827]]

access to economic generation due to increased transmission charges.

Michigan Commission believes competition and reliability within the

region will be served best if the Transmission Alliance and Midwest ISO

are joined.

Comments on RTOs Removing Opportunities for Discriminatory

Transmission Practices. Many commenters, mostly transmission customers,

agree that RTOs will remedy continuing opportunities for undue

discrimination.\108\

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\108\ See, e.g., American Forest, TDU Systems, WPPI, Sonat,

Illinois Commission, Arizona Commission, FMPA, Tampa Electric,

Advisory Committee ISO-NE. Comments are addressed in more detail

later in the discussion of existing discriminatory conduct.

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As both a buyer and seller of wholesale electricity, Oglethorpe

supports the evolution of competitive markets for generation service.

To ensure that competitive markets evolve and perform in a workable

manner, market participants should be assured access to the

transmission system on a fair and comparable basis, without regard to

transmission ownership. It believes that true competition can occur

only with widespread, open and nondiscriminatory access to the

transmission system. UtiliCorp claims that removing control over access

to transmission from the remaining large transmission-owning utilities

and placing such control in properly structured RTOs will go a long way

toward eliminating the remaining obstructions to effective competition

in wholesale markets for electric power.

Virginia Commission agrees that discrimination exists and that RTOs

can help facilitate competition and police non-competitive activities.

However, Virginia Commission believes that it is premature to conclude

that there is no role for rigorous governmental regulation. Virginia

Commission urges that the Commission not rely exclusively on RTOs to

detect, prevent and penalize violations of the FPA and should itself

provide for expedited handling of allegations regarding discrimination

and market power abuses.

On the other hand, a number of commenters, mostly transmission

owners, do not believe that RTOs are needed to address undue

discrimination because they do not believe that significant

discrimination problems remain with respect to wholesale transmission

access pursuant to Order No. 888.\109\ PSE&G argues that, if a

misperception exists in the marketplace as to the trustworthiness or

incentives of transmission owners as a whole, it may signal a need for

an industry-wide educational campaign that discusses transmission

operation and system reliability. However, such a misperception does

not, in and of itself, warrant altering the structure of the industry.

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\109\ See, e.g., United Illuminating, Southern Company,

MidAmerican, Duke, PSE&G, FP&L, Entergy, FirstEnergy, Alliance

Companies, Lenard, Florida Power Corp.

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Comments on RTOs Resulting in Improved Market Performance. DOE

asserts that open and comparable transmission access can reduce both

concentration in generation markets (by expanding the boundaries of the

relevant market) and the potential to discriminate through vertical

control but cannot, in its view, eliminate all market power. The

establishment of an independent RTO can and should substantially

mitigate the potential exercise of market power through vertical

control, because dispatch and related transmission services will be

provided by an independent entity with no financial interest in

wholesale market participants. Furthermore, the expected contribution

of an RTO in reducing the risk of horizontal market power will be

realized only if RTOs have sufficient ``critical mass.'' Appropriately

sized RTOs are necessary to assure a transparent and fair marketplace

for all generation.

EPA notes that RTOs can play an important role in the development

of environmentally preferred or ``green'' electricity products for use

by states that are implementing retail electricity competition. As the

operator of the transmission system, an RTO will have access to

detailed information on the operations of individual generators as well

as fuel type and air emissions, even where such information is

considered confidential. RTOs are uniquely situated to assemble the

information necessary to determine environmental attributes of specific

retail electricity products for purposes of consumer information

disclosure. EPA notes that this is already occurring in New England,

where ISO-NE has agreed to provide the states with information on

environmental attributes and resource mix for individual generators. In

addition to facilitating consumer information disclosure, EPA notes

that this information will support other state policies, such as

renewable portfolio standards and generation performance standards.

Comments on RTOs Facilitating Lighter-Handed Governmental

Regulation. Although most commenters agree that properly-designed RTOs

can be self-governing to a certain extent, the vast majority of

commenters believe that the Commission has either overstated the

reliance it should place on self-governance or has reached this

conclusion prematurely. Most of these commenters suggest that there is

insufficient evidence at this time to reach the conclusion that RTO

formation would necessarily result in lighter-handed regulation. A

number of commenters also caution that the Commission should not

significantly reduce its oversight of RTOs until they are proven to be

effective. British Columbia Ministry states that the structure of

future RTOs should minimize additional layers of administration and

oversight. However, at least one commenter, Cal DWR, noting that RTOs

are themselves transmission monopolies subject to the FPA, argues that

the Commission should continue its course of regulating RTOs to ensure

compliance with legal and policy requirements.

PJM generally supports the Commission's conclusion regarding light-

handed regulation. It notes that, where ISOs' decisions are independent

and conducted through an extensive stakeholder processes to produce

collaborative solutions to market issues, the Commission can defer

confidently to those decisions. Under such circumstances, the

Commission can be assured that ISO proposals to changes market rules

and procedures would promote competitive markets and are not designed

to favor any one group of market participants.

PJM argues further that the Commission accord greater flexibility

to properly structured RTOs to change market rules and procedures

without Commission filings. An RTO with an established stakeholder

process could publish some changes in market rules on its internet

site, without requiring prior Commission approval. In the event that a

market participant objected, it could file a complaint with the

Commission. PJM says the benefit is that the market would not be

hindered by delay in implementing new rules. Other rules could be

permitted to go into effect upon filing, rather than at the end of the

Commission review process.

Some commenters suggest that the Commission be particularly

deferential to decisions that result from ADR processes. For example,

PNGC supports strong and broad dispute resolution power in an RTO. It

argues that many small transmission users currently have no effective

way to be heard regarding service complaints, outage restoration, and

adequacy of equipment or maintenance because of the high cost of

bringing such a dispute to the Commission. In addition, Desert STAR

[[Page 828]]

asserts that where the Commission has approved the charter governance

and ADR processes of an RTO as being sufficiently broad-based and

independent, the Commission should give some deference to decisions

reached through the RTO's ADR processes. However, deference in dispute

resolution to an RTO should not impair a transmission user's

fundamental rights under section 211 of the FPA. Because the RTO will

be a jurisdictional entity, the Commission is an appropriate appeals

forum. Similarly, Seattle supports the Commission proposal to defer to

RTOs on matters involving commercial, operating and planning practices,

as well as to resolve disputes, but argues that it is too early to tell

whether ISOs transcos or other forms of RTOs can be deferred to in lieu

of regulatory filings.

MidAmerican welcomes the Commission's proposed lighter-handed

approach to regulation, but questions whether lighter-handed

regulation, in fact, will be derived from the proposed rule.

MidAmerican proposes that the Commission issue a policy statement to

provide general guidance on how it intends to give deference to RTOs.

For example, the policy should outline that, if a transmission owner

follows RTO directives, it will be presumed that the transmission owner

does not have transmission market power and that it is not capable of

transmission market discrimination. The Commission should give

deference to RTOs to design tariffs that include rate incentives and

should permit returns on equity that compensate transmission owners for

additional risks and for competitive market development.

A number of commenters argue that there is as yet no evidence to

support the conclusion that RTO formation should lead to lighter-handed

regulation. Duke and Entergy argue that each of the existing ISOs has

been mired in significant litigation with market participants, and the

Commission's dockets are loaded with cases arising out of decisions

made by ISOs. They and NECPUC suggest that this raises the possibility

that RTOs represent a new layer of regulatory oversight of market

activities, supplementing rather than replacing federal and state

regulation. FP&L states that the independence and objectivity of the

Florida Public Service Commission make it unnecessary to create a

formal (and costly) separate entity to operate and oversee the Florida

grid as an RTO.

Other commenters suggest that the probability that RTOs can be

self-regulating may be overstated. APPA argues that existing ISOs still

represent the interests of the transmission owners that formed these

ISOs. In addition, it argues that each ISO is a market participant

because its revenue recovery is affected by the performance of

transmission, ancillary services, and energy imbalance spot markets. It

suggests that the right to self-regulation must be earned in the

marketplace, not bestowed by regulators in advance.

NECPUC argues that not only must an RTO be properly structured to

be self-regulating, so must the utilities involved, or the RTO will

constantly be involved in the business of dispute resolution. It

suggests that during a transition phase, a certain level of active

regulation may be inescapable. For example, it notes that the

Commission stepped in quite definitively in developing the governance

of the New England Power Pool. NECPUC believes that strong intervention

by the Commission was effective at achieving progress when the parties

in New England stalemated.

PG&E claims that an RTO is uniquely situated to handle a number of

responsibilities, including reliability enforcement and sanctions,

market monitoring, and reporting non-reliability market-related

violations. However, a single entity, no matter how well-structured and

independent, cannot successfully fulfill several competing roles

simultaneously, i.e., serve as judge, jury and advocate. While the RTO

can do much to create region-specific processes that meet the needs of

market participants, the Commission must retain ultimate oversight. The

RTO is not a substitute for this function. With the tremendous volume

of transactions flowing through an RTO, even small errors in energy or

financial accounting can lead to huge cost shifts. Market participants

need to have a remedy at the Commission if issues are not resolved

adequately by the RTO.

Other commenters believe that the Commission may have to play a

strong role in ADR. Arizona Commission urges the Commission to give

respect rather than deference to decisions reached through an RTO's ADR

processes. TDU Systems state that the ability of an RTO transmission

customer to obtain ultimate Commission review of a dispute with the RTO

(or another RTO customer) should not be cut off. RTO tariffs should

contain ADR provisions that allow for mediation or other low-cost forms

of ADR so disputes can, if possible, be resolved without resort to the

Commission. If this is not possible, the Commission should consider any

dispute that comes to it after the conclusion of ADR at an RTO on a de

novo basis.

In dealing with disputes between RTOs and their customers, TDU

Systems suggests that the Commission be sensitive to the issue of

``minority rights.'' The Commission should ensure that transmission

customers with complaints against their RTOs get due process and a full

and fair opportunity to air their concerns. Just because a customer may

take a position in a dispute not shared by many others does not mean

that it is automatically wrong.

Moreover, TDU Systems believe that the Commission, in considering

the ADR issue, should make a distinction between ISOs or other RTOs

that are not-for-profit or quasi-governmental in nature and for-profit

RTOs. For-profit RTOs may not necessarily be well suited to be the

arbiters of disputes, especially where they are an involved party. It

would be inappropriate for the Commission simply to ``off load''

dispute resolution duties to a private for-profit entity, especially if

the entity is an interested party in the dispute. ISOs, on the other

hand, are more quasi-governmental in nature, and if fully independent,

may be in a better position to attempt to resolve a dispute, subject to

Commission review.

Duke asserts that streamlined filings and approval procedures could

reduce costs that would otherwise be borne by market participants.

Reducing regulatory burdens could constitute one form of incentive to

encourage RTO participation. The policy could be applied equally for

non-profit and for-profit RTOs. On the other hand, TDU Systems argues

that opportunities for streamlined RTO filings could set a very

dangerous precedent, especially if applied to incentive rate filings of

for-profit RTOs. RTOs will still be monopolies (although hopefully

large horizontal ones, rather than smaller, vertically integrated

ones). The norm for RTO filings should still be full Commission

scrutiny. Entergy argues that the Commission should encourage proposals

submitted by RTOs designed to increase regulatory efficiencies and

reduce regulatory burdens imposed on RTOs. The Commission should

specifically declare its willingness to entertain proposals to

streamline filing requirements. The Commission could encourage

innovative ways to reduce regulatory costs by authorizing performance-

based rates that reward RTOs for reducing regulatory costs.

Commission Conclusion. We conclude that properly structured RTOs

throughout the United States can provide significant benefits in the

operation of the transmission grid. The comments received reinforce our

preliminary determination in the NOPR

[[Page 829]]

that RTOs can effectively remove existing impediments to competition in

the power markets.

Description of Benefits. We conclude that RTOs will provide the

benefits that we described in detail in the NOPR, and others that

commenters mention.110 While we acknowledge that the level

of RTO benefits may vary from region to region depending on the current

transparency and efficiency of markets, the Commission believes that

benefits from RTO's would be universal. These benefits will include:

increased efficiency through regional transmission pricing and the

elimination of rate pancaking; improved congestion management; more

accurate estimates of ATC; more effective management of parallel path

flows; more efficient planning for transmission and generation

investments; increased coordination among state regulatory agencies;

reduced transaction costs; facilitation of the success of state retail

access programs; facilitation of the development of environmentally

preferred generation in states with retail access programs; improved

grid reliability; and fewer opportunities for discriminatory

transmission practices.111 All of these improvements to the

efficiencies in the transmission grid will help improve power market

performance, which will ultimately result in lower prices to the

Nation's electricity consumers.

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\110\ The benefits described in this section are not intended to

include all benefits that RTOs could provide. Some of the principal

benefits of RTOs (e.g., more effective management of parallel path

flows, improved congestion management) are addressed in later

discussions of RTO minimum characteristics and functions.

\111\ FERC Stats. & Regs. para. 32,541 at 33,716-20.

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As stated in the NOPR, we expect that RTOs can reduce opportunities

for unduly discriminatory conduct by cleanly separating the control of

transmission from power market participants. An RTO would have no

financial interests in any power market participant, and no power

market participant would be able to control an RTO. This separation

will eliminate the economic incentive and ability for the transmission

provider to act in a way that favors or disfavors any market

participant in the provision of transmission services.

Most commenters support the premise that RTOs can be beneficial in

addressing the remaining transmission-related impediments to full

competition in the electricity markets. Although we recognize certain

differences in perspective about the existence of, or potential for,

widespread discrimination by current transmission owners, no one

seriously disputes the benefits of a marketplace where service quality

and availability are uniform, where users of the network are treated

equally, and where commercially important data are readily available to

all. Although some commenters support the NOPR proposal only if the

costs of establishing RTOs do not exceed the benefits, a subject

discussed further below, most believe that the benefits listed in the

NOPR are accurate and can be achieved through an RTO.

We recognize that some commenters believe that either RTOs alone

will not solve all of the identified problems, or individual benefits

can be achieved in ways other than creating RTOs. Both of these

observations may have some merit. However, we believe that the creation

of RTOs is one action that can address all of the identified

impediments to competition and provide all or most of the identified

benefits.

We also recognize that there are those who worry that the costs of

establishing an RTO will outweigh the benefits. We believe this concern

fails to account for the flexibility we have built into this rule.

While many look at the high costs involved with respect to establishing

some existing ISOs and PXs, this rule does not require an RTO to follow

any specific approach. For example, thi

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