21540 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

DEPARTMENT OF ENERGY

Federal Energy Regulatory

Commission

18 CFR Parts 35 and 385

[Docket Nos. RM95–8–000 and RM94–7–

001; Order No. 888]

Promoting Wholesale Competition

Through Open Access NonDiscriminatory Transmission Services

by Public Utilities; Recovery of

Stranded Costs by Public Utilities and

Transmitting Utilities

Issued April 24, 1996.

AGENCY: Federal Energy Regulatory

Commission, DOE.

ACTION: Final rule.

SUMMARY: The Federal Energy

Regulatory Commission (Commission) is

issuing a Final Rule requiring all public

utilities that own, control or operate

facilities used for transmitting electric

energy in interstate commerce to have

on file open access non-discriminatory

transmission tariffs that contain

minimum terms and conditions of nondiscriminatory service. The Final Rule

also permits public utilities and

transmitting utilities to seek recovery of

legitimate, prudent and verifiable

stranded costs associated with

providing open access and Federal

Power Act section 211 transmission

services. The Commission’s goal is to

remove impediments to competition in

the wholesale bulk power marketplace

and to bring more efficient, lower cost

power to the Nation’s electricity

consumers.

EFFECTIVE DATE: This Final Rule will

become effective on July 9, 1996.

FOR FURTHER INFORMATION CONTACT:

David D. Withnell (Legal Information—

Docket No. RM95–8–000), Office of

the General Counsel, Federal Energy

Regulatory Commission, 888 First

Street NE., Washington, DC 20426,

(202) 208–2063

Deborah B. Leahy (Legal Information—

Docket No. RM94–7–001), Office of

the General Counsel, Federal Energy

Regulatory Commission, 888 First

Street NE., Washington, DC 20426,

(202) 208–2039

Michael A. Coleman (Technical

Information), Office of Electric Power

Regulation, Federal Energy Regulatory

Commission, 888 First Street NE.,

Washington, DC 20426, (202) 208–

1236.

SUPPLEMENTARY INFORMATION: In

addition to publishing the full text of

this document in the Federal Register,

the Commission also provides all

interested persons an opportunity to

inspect or copy the contents of this

document during normal business hours

in the Public Reference Room at 888

First Street, NE., Washington, DC 20426.

The Commission Issuance Posting

System (CIPS), an electronic bulletin

board service, provides access to the

texts of formal documents issued by the

Commission. CIPS is available at no

charge to the user and may be accessed

using a personal computer with a

modem by dialing 202–208–1397 if

dialing locally, or 1–800–856–3920 if

dialing long distance. CIPS is also

available through the Fed World system

(by modem or Internet). To access CIPS,

set your communications software to

19200, 14400, 12000, 9600, 7200, 4800,

2400, or 1200 bps, full duplex, no

parity, 8 data bits and 1 stop bit. The

full text of this order will be available

on CIPS indefinitely in ASCII and

WordPerfect 5.1 format. The complete

text on diskette in Wordperfect format

may also be purchased from the

Commission’s copy contractor, La Dorn

Systems Corporation, also located in the

Public Reference Room at 888 First

Street NE., Washington, DC 20426.

Table of Contents

I. Introduction/Summary

II. Public Reporting Burden

III. Background

IV. Discussion

A. Scope of the Rule

1. Introduction

2. Functional Unbundling

3. Market-based Rates

4. Merger Policy

5. Contract Reform

6. Flow-based Contracting and Pricing

B. Legal Authority

1. Bases for Legal Authority

2. Response to Commenters Opposing our

Legal Authority

C. Comparability

1. Eligibility to Receive Non-discriminatory

Open Access Transmission

2. Service that Must be Provided by

Transmission Provider

3. Who Must Provide Non-discriminatory

Open Access Transmission

4. Reservation of Transmission Capacity by

Transmission Customers

5. Reservation of Transmission Capacity for

Future Use by Utility

6. Capacity Reassignment

7. Information Provided to Transmission

Customers

8. Consequences of Functional Unbundling

D. Ancillary Services

1. Definitions and Descriptions

2. Obligations of Transmission Providers

and Transmission Customers with

Respect to Ancillary Services

3. Unbundling and Bundling Ancillary

Services

4. Reassignment of Ancillary Services

5. Pricing of Ancillary Services

6. Accounting for Ancillary Services

E. Real-Time Information Networks

F. Coordination Arrangements: Power

Pools, Public Utility Holding Companies,

Bilateral Coordination Arrangements,

and Independent System Operators

1. Tight Power Pools

2. Loose Pools

3. Public Utility Holding Companies

4. Bilateral Coordination Arrangements

G. Pro Forma Tariff

1. Tariff Provisions That Affect The Pricing

Mechanism

2. Priority for Obtaining Service

3. Curtailment Provisions

4. Specific Tariff Provisions

H. Implementation

I. Federal and State Jurisdiction:

Transmission/Local Distribution

J. Stranded Costs

1. Justification for Allowing Recovery of

Stranded Costs

2. Cajun Electric Power Cooperative, Inc. v.

FERC

3. Responsibility for Wholesale Stranded

Costs (Whether to Adopt Direct

Assignment to Departing Customers)

4. Recovery of Stranded Costs Associated

with New Wholesale Requirements

Contracts

5. Recovery of Stranded Costs Associated

with Existing Wholesale Requirements

Contracts

6. Recovery of Stranded Costs Caused by

Retail-Turned-Wholesale Customers

7. Recovery of Stranded Costs Caused by

Retail Wheeling

8. Evidentiary Demonstration Necessary—

Reasonable Expectation Standard

9. Calculation of Recoverable Stranded

Costs

10. Stranded Costs in the Context of

Voluntary Restructuring

11. Accounting Treatment for Stranded

Costs

12. Definitions, Application, and Summary

K. Other

1. Information Reporting Requirements for

Public Utilities

2. Small Utilities

3. Regional Transmission Groups

4. Pacific Northwest

5. Power Marketing Agencies

6. Tennessee Valley Authority

7. Hydroelectric Power

8. Residential Customers

V. Environmental Statement

VI. Regulatory Flexibility Act Certification

VII. Information Collection Statement

VIII. Effective Date

Regulatory Text

Appendices (These Appendices will not

appear in the Code of Federal

Regulations)

A. List of Section 211 Applications

B. List of Commenters in Docket Nos.

RM95–8–000 and RM94–7–001

C. Allegations of Public Utilities Exercising

Transmission Dominance

D. Pro Forma Open Access Transmission

Tariff

E. List of Group 1 Public Utilities

F. List of Group 2 Public Utilities

G. Legal Analysis of Commission

Jurisdiction Over the Rates, Terms and

Conditions of Unbundled Retail

Transmission In Interstate Commerce

H. U.S. NOX Emissions
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21541

1These rules are the rules on open access and

stranded costs in the above dockets (FERC Stats. &

Regs. ¶ 31,036), and an accompanying rule on Open

Access Same-Time Information System and

Standards of Conduct (OASIS Final Rule) (FERC

Stats. & Regs. ¶ 31,037) being issued

contemporaneously. The Commission also is

issuing contemporaneously a notice of proposed

rulemaking on capacity reservation open access

transmission tariffs in Docket No. RM96–11–000,

FERC Stats. & Regs. ¶32,517. These final rules and

proposed rule are being published concurrently in

the Federal Register.

2On March 29, 1995, the Commission issued two

notices of proposed rulemaking concerning open

access transmission and stranded cost recovery.

Promoting Wholesale Competition Through OpenAccess Non-Discriminatory Transmission Service

by Public Utilities and Recovery of Stranded Costs

by Public Utilities and Transmitting Utilities,

Notice of Proposed Rulemaking and Supplemental

Notice of Proposed Rulemaking, 60 FR 17662 (April

7, 1995), FERC Stats. & Regs. ¶ 32,514 (1995). On

December 13, 1995, the Commission issued a notice

of proposed rulemaking on information systems.

Real-Time Information Networks and Standards of

Conduct, Notice of Proposed Rulemaking, 60 FR

66182 (December 21, 1995), FERC Stats. & Regs.

¶ 32,516 (1995).

3The Commission’s notice of proposed

rulemaking in the above dockets proposed to apply

the proposed requirements to public utilities that

own and/or control facilities used for the

transmission of electric energy in interstate

commerce. ‘‘Own and/or control’’ is intended to

include public utilities that ‘‘operate’’ facilities

used for the transmission of electric energy in

interstate commerce. However, we have modified

the Final Rule regulatory text to remove any

ambiguity.

Statement of Commissioner Hoecker

Statement of Commissioner Massey

I. Introduction/Summary

Today the Commission issues three

final, interrelated rules designed to

remove impediments to competition in

the wholesale bulk power marketplace

and to bring more efficient, lower cost

power to the Nation’s electricity

consumers.1 The legal and policy

cornerstone of these rules is to remedy

undue discrimination in access to the

monopoly owned transmission wires

that control whether and to whom

electricity can be transported in

interstate commerce. A second critical

aspect of the rules is to address recovery

of the transition costs of moving from a

monopoly-regulated regime to one in

which all sellers can compete on a fair

basis and in which electricity is more

competitively priced.

In the year since the proposed rules

were issued,2 the pace of competitive

changes in the electric utility industry

has accelerated. By March of last year,

38 public utilities had filed wholesale

open access transmission tariffs with the

Commission. Today, prodded by such

competitive changes and encouraged by

our proposed rules, 106 of the

approximately 166 public utilities that

own, control, or operate 3 transmission

facilities used in interstate commerce

have filed some form of wholesale open

access tariff. In addition, since the time

the proposed rules were issued,

numerous state regulatory commissions

have adopted or are actively evaluating

retail customer choice programs or other

utility restructuring alternatives. These

events have been spurred by continuing

pressures in the marketplace for changes

in the way electricity is bought, sold,

and transported. Increasingly, customers

are demanding the benefits of

competition in the growing electricity

commodity market.

The Commission estimates the

potential quantitative benefits from the

Final Rule will be approximately $3.8 to

$5.4 billion per year of cost savings, in

addition to the non-quantifiable benefits

that include better use of existing assets

and institutions, new market

mechanisms, technical innovation, and

less rate distortion. The continuing

competitive changes in the industry and

the prospect of these benefits to

customers make it imperative that this

Commission take the necessary steps

within its jurisdiction to ensure that all

wholesale buyers and sellers of electric

energy can obtain non-discriminatory

transmission access, that the transition

to competition is orderly and fair, and

that the integrity and reliability of our

electricity infrastructure is maintained.

In this Rule, the Commission seeks to

remedy both existing and future undue

discrimination in the industry and

realize the significant customer benefits

that will come with open access.

Indeed, it is our statutory obligation

under sections 205 and 206 of the

Federal Power Act (FPA) to remedy

undue discrimination.

To do so, we must eliminate the

remaining patchwork of closed and

open jurisdictional transmission

systems and ensure that all these

systems, including those that already

provide some form of open access,

cannot use monopoly power over

transmission to unduly discriminate

against others. If we do not take this

step now, the result will be benefits to

some customers at the expense of

others. We have learned from our

experience in the natural gas area the

importance of addressing competitive

transition issues early and with as much

certainty to market participants as

possible.

Accordingly, in this proceeding and

in the accompanying proceeding on

OASIS, the Commission, pursuant to its

authorities under sections 205 and 206

of the FPA:

• Requires all public utilities that

own, control or operate facilities used

for transmitting electric energy in

interstate commerce

• To file open access nondiscriminatory transmission tariffs that

contain minimum terms and conditions

of non-discriminatory service;

• To take transmission service

(including ancillary services) for their

own new wholesale sales and purchases

of electric energy under the open access

tariffs;

• To develop and maintain a sametime information system that will give

existing and potential transmission

users the same access to transmission

information that the public utility

enjoys, and further requires public

utilities to separate transmission from

generation marketing functions and

communications;

• Clarifies Federal/state jurisdiction

over transmission in interstate

commerce and local distribution and

provides for deference to certain state

recommendations; and

• Permits public utilities and

transmitting utilities to seek recovery of

legitimate, prudent and verifiable

stranded costs associated with

providing open access and FPA section

211 transmission services.

Open Access

The Final Rule requires public

utilities to file a single open access tariff

that offers both network, load-based

service and point-to-point, contractbased service. The Rule contains a pro

forma tariff that reflects modifications to

the NOPR’s proposed terms and

conditions and also permits variations

for regional practices. All public

utilities subject to the Rule, including

those that already have tariffs on file,

will be required to make section 206

compliance filings to meet the new pro

forma tariff non-price minimum terms

and conditions of non-discriminatory

transmission. Utilities may propose

their own rates in a section 205

compliance filing.

The Rule provides that public utilities

may seek a waiver of some or all of the

requirements of the Final Rule. In

addition, non-public utilities may seek

a waiver of the tariff reciprocity

provisions.

The Final Rule does not generically

abrogate existing requirements

contracts, but will permit customers and

public utilities to seek modification, or

termination, of certain existing

requirements contracts on a case-by-case

basis. As to coordination arrangements

and contracts, the Rule finds that these

arrangements and contracts may need to

be modified to remove unduly

discriminatory transmission access and/

or pricing provisions. Such

arrangements and agreements include

power pool agreements, public utility
21542 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

4 42 U.S.C. 7401, et seq.

5 42 U.S.C.A. 7651b–e.

holding company agreements, and

certain bilateral coordination

agreements. The Rule provides guidance

and timelines for modifying unduly

discriminatory coordination

arrangements and contracts, and

specifies when the members of such

arrangements must begin to conduct

trade with each other using the same

open access tariff offered to others. The

Rule also provides guidance regarding

the formation of independent system

operators (ISOs).

The Rule does not require any form of

corporate restructuring, but will

accommodate voluntary restructuring

that is consistent with the Rule’s open

access and comparability policies.

As discussed in the NOPR, not all

owners or controllers of interstate

transmission facilities are subject to the

Commission’s jurisdiction under

sections 205 and 206 of the FPA and

therefore are not subject to this Rule’s

open access requirements. Therefore,

the Final Rule retains the proposed

reciprocity provision in the pro forma

tariff. Without such a provision, nonopen access utilities could take

advantage of the competitive

opportunities of open access, while at

the same time offering inferior access, or

no access at all, over their own facilities.

Thus, open access utilities would be

unfairly burdened. We note that some

non-jurisdictional utilities have

expressed an interest in a mechanism

for obtaining a Commission

determination that their transmission

tariffs satisfy the reciprocity provisions

in the pro forma tariffs, and we provide

such a mechanism in the Rule.

The Final Rule does not generically

provide for market-based generation

rates. Although the Rule codifies the

Commission’s prior decision that there

is no generation dominance in new

generating capacity, intervenors in cases

may raise generation dominance issues

related to new capacity. In addition, to

obtain market-based rates for existing

generation, we will continue to require

public utilities to show, on a case-bycase basis, that there is no generation

dominance in existing capacity. Further,

in all market-based rate cases, we will

continue to look at whether an applicant

and its affiliates could erect other

barriers to entry and whether there may

be problems due to affiliate abuse or

reciprocal dealing.

Finally, contemporaneously with this

Rule the Commission issues an NOPR

on capacity reservation tariffs as an

alternative, and perhaps superior,

means of remedying undue

discrimination.

Transmission/Local Distribution

The Rule clarifies the Commission’s

interpretation of the Federal/state

jurisdictional boundaries over

transmission and local distribution.

While we reaffirm our conclusion that

this Commission has exclusive

jurisdiction over the rates, terms, and

conditions of unbundled retail

transmission in interstate commerce by

public utilities, we nevertheless

recognize the very legitimate concerns

of state regulatory authorities as they

contemplate direct retail access or other

state restructuring programs.

Accordingly, we specify circumstances

under which we will give deference to

state recommendations. Although

jurisdictional boundaries may shift as a

result of restructuring programs in

wholesale and retail markets, we do not

believe this will change fundamental

state regulatory authorities, including

authority to regulate the vast majority of

generation asset costs, the siting of

generation and transmission facilities,

and decisions regarding retail service

territories. We intend to be respectful of

state objectives so long as they do not

balkanize interstate transmission of

power or conflict with our interstate

open access policies.

Stranded Costs

With regard to stranded costs, the

Final Rule adopts the Commission’s

supplemental proposal. It will permit

utilities to seek extra-contractual

recovery of stranded costs associated

with a limited set of existing (executed

on or before July 11, 1994) wholesale

requirements contracts and provides

that the Commission will be the primary

forum for utilities to seek recovery of

stranded costs associated with retailturned-wholesale transmission

customers. It also will allow utilities to

seek recovery of stranded costs caused

by retail wheeling only in circumstances

in which the state regulatory authority

does not have authority to address retail

stranded costs at the time the retail

wheeling is required. The Rule retains

the revenues lost approach for

calculating stranded costs and provides

a formula for calculating such costs.

Environmental Issues

The Commission has prepared a Final

Environmental Impact Statement (FEIS)

evaluating the possible environmental

consequences of changes in the bulk

power marketplace expected to occur as

a result of the open access requirements

of this Final Rule. The FEIS focuses, as

do most commenters, on possible

increases in emissions of nitrogen

oxides (NOX) from certain fossil-fuel

fired generators, which could affect air

quality in the producing region and in

areas to which these emissions may be

carried.

In response to comments on the Draft

EIS, the Commission performed

numerous additional studies. The FEIS

finds that the relative future

competitiveness of coal and natural gas

generation is the key variable affecting

the impact of the Final Rule. If

competitive conditions favor natural

gas, the Rule is likely to lead to

environmental benefits. Both EPA and

the Commission staff believe this

projected scenario is the more likely

one. If competitive conditions favor

coal, the Rule may lead to small

negative environmental impacts.

However, even using the most extreme,

unlikely assumptions about the future of

the industry, the negative consequences

are not likely to occur until after the

turn of the century. Because the impacts

will remain modest at least until 2010,

there is no need for an interim

mitigation program. In addition, even if

the data showed more significant

negative consequences requiring

mitigation, the Commission does not

have the statutory authority under the

Federal Power Act or the expertise to

address this possible far-term problem.

The Commission believes, however, that

there is time for federal and state air

quality authorities to address any

potential adverse impact as part of a

comprehensive NOX regulatory program

under the Clean Air Act.4

Despite our conclusions regarding the

lack of environmental impacts expected

to result from the Rule, the Commission

has examined a wide variety of

proposals for mitigating possible

adverse effects. We share the view of

most commenters that the preferred

approach for mitigating increased NOX

emissions generally is a NOX cap and

trading regulatory program comparable

to that developed by Congress to

address sulfur dioxide emissions in the

Clean Air Act Amendments of 1990.5

The Commission has examined various

means of establishing such a program,

including use of existing federal

authorities under the Clean Air Act,

cooperative efforts by state and federal

air quality regulators, and development

of a new emissions regulatory program

administered by the Commission under

the Federal Power Act. The Commission

has concluded that a NOX regulatory

program could best be developed and

administered under the Clean Air Act,

in cooperation with interested states,

and offers to lend Commission support
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21543

6Paul L. Joskow, Inflation and Environmental

Concern: Structural Change in the Process of Public

Utility Regulation, 17 J. Law & Econ. 291, 312

(1974); see also Charles F. Phillips, Jr., The

Regulation of Public Utilities 11 (1988).

7See Joskow, supra at 312; see also Phillips,

supra at 12.

8See Joskow, supra at 312; see also Phillips,

supra at 12–13.

9See Joskow, supra at 312–13; see also Phillips,

supra at 13. The Arab oil embargo resulted in

significantly higher oil prices through the 1970s.

See Richard J. Pierce, Jr., The Regulatory Treatment

of Mistakes in Retrospect: Canceled Plants and

Excess Capacity, 132 U. Pa. L. Rev. 497, 501 (1984).

10See Joskow, supra at 313; see also Phillips,

supra at 13.

11See generally Jersey Central Power & Light

Company v. FERC, 810 F.2d 1168, 1171 (D.C. Cir.

1987).

12 Id.

13See Pierce, supra at 503. By 1983, the

Department of Energy had estimated that the sunk

costs for canceled nuclear plants alone amounted to

$10 billion. Id. at 498.

14 Id.

to that effort should it become

necessary.

Conclusion

The Commission believes that the

Final Rule will remedy undue

discrimination in transmission services

in interstate commerce and provide an

orderly and fair transition to

competitive bulk power markets.

II. Public Reporting Burden

The Open Access Final Rule and the

Stranded Cost Final Rule specify filing

requirements to be followed by public

utilities that own, control or operate

transmission facilities in interstate

commerce in making nondiscriminatory open access tariff filings

and filings to recover legitimate,

prudent and verifiable stranded costs.

The information collection requirements

of the final rules are attributable to

FERC–516 ‘‘Electric Rate Filings.’’ The

current total annual reporting burden

for FERC–516 is 828,300 hours.

A. Docket No. RM95–8–000 (Open

Access Final Rule)

The Open Access Final Rule requires

public utilities filing non-discriminatory

open access tariffs to provide certain

information to the Commission. The

Commission estimated that the public

reporting burden for the information

collection would average 300 hours per

response. This estimate included time

for reviewing the requirements of the

Commission’s regulations, searching

existing data sources, gathering and

maintaining the necessary data,

completing and reviewing the collection

of information, and filing the revised

information. No comments on the

burden estimate were received. Because

the Final Rule adopts essentially the

same information requirements that are

contained in the proposed rule, we

believe that the average filing burden is

same for the Final Rule.

In the proposed rule, the Commission

noted that there are approximately 328

public utilities, including marketers and

wholesale generation entities. We

initially estimated that 137 public

utilities own, control or operate

facilities used for the transmission of

electric energy in interstate commerce,

and would be subject to the filing

requirements of the proposed rule.

Upon further review, the Commission

believes that approximately 166 public

utilities will respond to the information

collection. Accordingly, the public

reporting burden is estimated to be

49,800 hours.

B. Docket No. RM94–7–001 (Stranded

Cost Final Rule)

In the supplemental notice of

proposed rulemaking, the Commission

estimated that the information

requirements of the proposed rule

would not differ substantially from

those contained in the initial proposed

rule. In that notice, the Commission

estimated that the public reporting

burden for the information requirements

contained in the proposed rule would

be 50 hours per response with 10

responses annually. No comments on

this filing burden were received. The

information requirements adopted in

the Stranded Cost Final Rule are not

substantially different from those in the

proposed rule. Therefore, the

Commission concludes that there will

be no additional public filing burden

associated with the Stranded Cost Final

Rule.

III. Background

In the NOPR, we set out a detailed

statement of the events leading up to

this rulemaking. We repeat that

background here, updated to reflect

what has happened since March 1995,

and discuss why it is necessary to

undertake regulatory reform in the

electric industry at this time. We do so

to provide the necessary backdrop to

our action in adopting this Rule.

A. Structure of the Electric Industry at

Enactment of Federal Power Act

The Federal Power Act was enacted in

an age of mostly self-sufficient,

vertically integrated electric utilities, in

which generation, transmission, and

distribution facilities were owned by a

single entity and sold as part of a

bundled service (delivered electric

energy) to wholesale and retail

customers. Most electric utilities built

their own power plants and

transmission systems, entered into

interconnection and coordination

arrangements with neighboring utilities,

and entered into long-term contracts to

make wholesale requirements sales

(bundled sales of generation and

transmission) to municipal, cooperative,

and other investor-owned utilities

(IOUs) connected to each utility’s

transmission system. Each system

covered limited service areas. This

structure of separate systems arose

naturally due primarily to the cost and

technological limitations on the

distance over which electricity could be

transmitted.

Through much of the 1960s, utilities

were able to avoid price increases, but

still achieve increased profits, because

of substantial increases in scale

economies, technological

improvements, and only moderate

increases in input prices.6 Thus, there

was no pressure on regulatory

commissions to use regulation to affect

the structure of the industry.7

B. Significant Changes in the Electric

Industry

In the late 1960s and throughout the

1970s, a number of significant events

occurred in the electric industry that

changed the perceptions of utilities and

began a shift to a more competitive

marketplace for wholesale power.8 This

was the beginning of periods of rapid

inflation, higher nominal interest rates,

and higher electricity rates.9 During this

time, consumers became concerned

about higher electricity rates and

questioned any price increases filed by

utilities.10

During this same time frame, the

construction of nuclear and other

capital-intensive baseload facilities—

actively encouraged by federal and some

state governments—contributed to the

continuing cost increases and

uncertainties in the industry.11 These

investments were made based on the

assumptions that there would be steady

increases in the demand for electricity

and continued large increases in the

price of oil.12 However, due to

conservation and economic downturns,

the expected demand increases did not

materialize. Load growth virtually

disappeared in some areas, and many

utilities unexpectedly found themselves

with excess capacity.13 In addition, by

the 1980s, the oil cartel collapsed, with

a resulting glut of low-priced oil.14 At

the same time, inflation substantially

increased the costs of these large
21544 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

15See Bernard S. Black & Richard J. Pierce, Jr.,

The Choice Between Markets and Central Planning

in Regulating the U.S. Electricity Industry, 93 Col.

L. Rev. 1339, 1346 (1993) (‘‘Actual costs of nuclear

power plants vastly exceeded estimates, sometimes

by as much as 1000%.’’).

16See Phillips, supra at 13. Fossil fuel-fired

plants became subject to increased regulation as a

result of the Clean Air Act of 1970, and its 1977

amendments. 42 U.S.C. 7401–7642. In 1971, nuclear

plant licensing became subject to the environmental

impact statement requirements of the National

Environmental Policy Act of 1969. 42 U.S.C. 4332.

Following the 1979 accident at the Three Mile

Island nuclear plant, nuclear plants also became

subject to additional safety regulations, resulting in

higher costs. See Energy Information

Administration, The Changing Structure of the

Electric Power Industry 1970–1991 (March 1993) 35.

Between 1976 and 1980, most states and many

localities instituted laws governing power plant

siting.

17Based on retail prices reported in Energy

Information Administration (EIA), Monthly Energy

Review, January 1995, Table 9.9 (Prices adjusted for

inflation using the GDP Deflator (1987 = 100)).

18 Id.

19See Black & Pierce, supra at 1346 (These

writeoffs were ‘‘about 17% of the book value of total

1992 utility investment.’’).

20 Id.

21 Id. (‘‘The high perceived risk of future

disallowances reversed utilities’ incentives to

overinvest, and made utilities extremely reluctant

to build new power plants.’’).

22See Preston Michie, Billing Credits for

Conservation, Renewable, and Other Electric Power

Resources: an Alternative to Marginal-Cost-Based

Power Rates in the Pacific Northwest, 13

Environmental Law 963, 964–65 (1983).

23 Id. at 965.

24Energy Information Administration, The

Changing Structure of the Electric Power Industry

1970–1991 (March 1993) 37 (‘‘As larger units were

constructed, however, utilities discovered that

downtime was as much as 5 times greater for units

larger than 600 megawatts than for units in the 100-

megawatt range.’’)

25 Id.; see also George A. Perrault, Downsizing

Generation: Utility Plans for the 1990s, Pub. Util.

Fort. 15–16 (Sept. 27, 1990) (‘‘The large base-load

generating units that form the backbone of utility

systems are almost totally absent from capacity

plans for the 1990s.’’).

26 ‘‘From 1982 through 1991, the average capacity

of fluidized-bed units increased rapidly to 72

megawatts for 4 units in 1991. The average capacity

for the 19 units planned to begin operating in 1992

through 1995 increases to 83 megawatts.’’ Energy

Information Administration, The Changing

Structure of the Electric Power Industry 1970–1991

(March 1993) 38.

27See Charles E. Bayless, Less is More: Why Gas

Turbines Will Transform Electric Utilities, Pub.

Util. Fort. (Dec. 1, 1994) 21.

28 Id. at 24. See also Wallace E. Brand, Is Bigger

Better? Market Power in Bulk Power Supply: From

FDR to NOPR, Pub. Util. Fort. (Feb. 15, 1996) 23

at 25 (while the optimal baseload unit size is about

500 MW for coal-fired steam turbines, the optimal

size for gas fired combined-cycle units is about 150

to 200 MW).

29FERC staff calculations based in part on

combined-cycle plant cost data reported in 1994

FERC Form No. 1 for a sample of units placed in

service during 1990–94. Costs vary with regional

fuel and construction costs, among other reasons.

30Coal and Nuclear plant cost data reported in

1994 FERC Form No. 1 and the EIA report, Electric

Plant Cost and Power Production Expenses 1991,

1993 DOE/EIA–0455(91), for plants placed in

service during 1986–94; see also The 1994 Electric

Executives’ Forum, Bakke (President and CEO of

the AES Corporation), Pub. Util. Fort. (June 1, 1994)

45 (‘‘New generation can be built at about 3 cents

per kilowatt-hour (U.S. average). Old generation

costs about twice that * * *’’).

31See Black & Pierce, supra at 1345 (In the late

1960s and 1970s, improved transmission efficiency

and development of regional transmission networks

‘‘made it possible to build power plants up to 1000

miles from power users.’’).

baseload generating plants.15 Surging

interest rates further increased the cost

of the capital needed to finance and

capitalize these projects and completion

schedules were significantly extended

by, in part, more stringent safety and

environmental requirements.16

As a result, expensive large baseload

plants for which there was little or no

demand, came onto the market or were

in the process of being constructed.

Accordingly, between 1970 and 1985,

average residential electricity prices

more than tripled in nominal terms, and

increased by 25% after adjusting for

general inflation.17 Moreover, average

electricity prices for industrial

customers more than quadrupled in

nominal terms over the same period and

increased 86% after adjusting for

inflation.18 The rapidly increasing rates

for electric power during this period,

together with the opportunities

provided by the Public Utility

Regulatory Policies Act of 1978

(PURPA) (discussed infra), also

prompted some industrial customers to

bypass utilities by constructing their

own generation facilities. This further

exacerbated rate increases for remaining

customers—primarily residential and

commercial customers.

Consumers responded to these ‘‘rate

shocks’’ by exerting pressure on

regulatory bodies to investigate the

prudence of management decisions to

build generating plants, especially when

construction resulted in cost overruns,

excess capacity, or both. Between 1985

and 1992, writeoffs of nuclear power

plants totalled $22.4 billion.19 These

writeoffs significantly reduced the

earnings of the affected utilities.20

Delays in obtaining rate increases to

reflect the effects of inflation further

reduced investor returns. Thus, many

utilities became reluctant to commit

capital to long-term construction

decisions involving large scale

generating plants.21

In addition to economic changes in

the industry, significant technological

changes in both generation and

transmission have occurred since 1935.

Through the 1960s, bigger was cheaper

in the generation sector and the industry

was able to capitalize on economies of

scale to produce power at lower per-unit

costs from larger and larger plants.22 As

a result, large utility companies that

could finance and manage construction

projects of larger scale had a price

advantage over smaller utility

companies and customers who might

otherwise have considered building

their own generating units. Scale

economies encouraged power

generation by large vertically-integrated

utility companies that also transmitted

and distributed power. Beginning in the

1970s, however, additional economies

of scale in generation were no longer

being achieved.23 A significant factor

was that larger generation units were

found to need relatively greater

maintenance and experience longer

downtimes.24 The electric industry

faced the situation ‘‘where the price of

each incremental unit of electric power

exceeded the average cost.’’ 25 Bigger

was no longer better.

Further dictating against larger

generation units were advances in

technologies that allowed scale

economies to be exploited by smaller

size units, thereby allowing smaller new

plants to be brought on line at costs

below those of the large plants of the

1970s and earlier. Such new

technologies include combined cycle

units and conventional steam units that

use circulating fluidized bed boilers.26

The combined cycle generating plants

generally use natural gas as their

primary fuel. This technology has been

made possible by the development of

more efficient gas turbines, shorter

construction lead times, lower capital

costs, increased reliability, and

relatively minimal environmental

impacts.27 Similarly, the circulating

fluidized bed combustion boilers, fueled

by coal and other conventional fuels,

provide a more efficient and less

polluting resource.

Today, ‘‘the optimum size (of

generation plants) has shifted from

(more than 500 MW) (10-year lead time)

to smaller units (one-year lead time) (in

the 50- to 150–MW range).’’ 28 Indeed,

smaller and more efficient gas-fired

combined-cycle generation facilities can

produce power on the grid at a cost

ranging from 5 cents per kWh to less

than 3 cents per kWh.29 This is

significantly less than the costs for large

plants constructed and installed by

utilities over the last decade, which

were typically in the range of 4 to 7

cents per kWh for coal plants and 9 to

15 cents for nuclear plants.30 Significant

changes have also occurred in the

transmission sector of the industry.

Technological advances in transmission

have made possible the economic

transmission of electric power over long

distances at higher voltages.31 This has
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21545

32Coordination transactions are voluntary sales or

exchanges of specialized electricity services that

allow buyers to realize cost savings or reliability

gains that are not attainable if they rely solely on

their own resources. For sellers, these transactions

provide opportunities to earn additional revenue,

and to lower customer rates, from capacity that is

temporarily excess to native load capacity

requirements.

33Pub. L. No. 95–617, 92 Stat. 3117 (codified in

U.S.C. sections 15, 16, 26, 30, 42, and 43).

34See generally FERC v. Mississippi, 456 U.S.

742, 745–46 (1982).

35The Power Plant and Industrial Fuel Use Act

of 1978. Pub. L. No. 95–617, 92 Stat. 3117 (codified

in U.S.C. sections 15, 16, 26, 30, 42, and 43).

36QFs include certain cogenerators and small

power producers. PURPA also added sections 210,

211, and 212 to the FPA, providing the Commission

with authority to approve applications for

interconnections and, in limited circumstances,

wheeling. However, under section 211, as enacted

in PURPA, the Commission could approve an

application for wheeling only if it found, inter alia,

that the order ‘‘would reasonably preserve existing

competitive relationships.’’ Because of this and

other limitations in sections 211 and 212 as

originally enacted, the provision was virtually

ineffective. Only one section 211 order was ever

issued pursuant to the original provision, and it was

pursuant to a settlement. See Public Service

Company of Oklahoma, 38 FERC ¶ 61,050 (1987).

As discussed infra, section 211 was subsequently

revised by the Energy Policy Act of 1992.

37 456 U.S. at 750. Congress recognized that

encouragement was needed in part because utilities

had been reluctant to purchase electric power from,

and sell power to, nonutility generators. Id. at 750–

51.

38For example, PURPA provided that a

cogeneration facility or small power production

facility could not be owned by a person primarily

engaged in the generation or sale of electric power

(other than from cogeneration or small power

production facilities). See 16 U.S.C.

39Energy Information Administration, Electric

Power Annual 1993 (December 1994) 124 (Table

77).

40 Id. EIA data for 1989 through 1991 was for

facilities of 5 megawatts or more and for 1992 and

1993 was for facilities of 1 megawatt or more. A

comparison with Table 74 on page 121 for the years

1992 and 1993 reveals that this mixing of data bases

is likely of minimal effect.

41 Generally, the law has imposed an 80 MW cap

on small power producers. A limited exception

enacted in 1990 permitted small power facilities

that could exceed 80 MW and still qualify as QFs

under PURPA. This exception was limited to

certain solar, wind, waste, and geothermal small

power production facilities and only covered

applications for certification of facilities as

qualifying small power production facilities that

were submitted no later than December 31, 1994

and for which construction commences no later

than December 31, 1999. See Solar, Wind, Waste,

and Geothermal Power Production Incentives Act of

1990, Pub. L. No. 101–575, 104 Stat. 2834 (1990),

amended, Pub. L. No. 102–46, 105 Stat. 249 (1991).

42The first power marketer in the electric

industry was Citizens Energy Corporation. See

Citizens Energy Corporation, 35 FERC ¶ 61,198

(1986). Power marketers take title to electric energy.

Power brokers, on the other hand, do not take title

and are limited to a matchmaking role.

43 15 U.S.C. 79 et seq.

44As discussed infra, Congress eventually

provided a means to avoid the PUHCA restrictions

by creating exempt wholesale generators (EWGs) in

the Energy Policy Act.

45The industry was successful to some extent in

developing ownership structures that permitted

such investment. See, e.g., Commonwealth Atlantic

Limited Partnership, 51 FERC ¶ 61,368 at 62,240

and n.20 (1990).

46Energy Information Administration, Electric

Power Annual 1993 (December 1994) 124 (Table

77).

47Black & Pierce, supra at 1349 n.25.

made it technically feasible for utilities

with lower cost generation sources to

reach previously isolated systems where

customers had been captive to higher

cost generation. In addition, the nature

and magnitude of coordination

transactions 32 have changed

dramatically since enactment of the

FPA, allowing increased coordinated

operations and reduced reserve margins.

Substantial amounts of electricity now

move between regions, as well as

between utilities in the same region.

Physically isolated systems have

become a thing of the past.

C. The Public Utility Regulatory Policies

Act and the Growth of Competition

In enacting PURPA,33 Congress

recognized that the rising costs and

decreasing efficiencies of utility-owned

generating facilities were increasing

rates and harming the economy as a

whole.34 To lessen dependence on

expensive foreign oil, avoid repetition of

the 1977 natural gas shortage, and

control consumer costs, Congress sought

to encourage electric utilities to

conserve oil and natural gas.35 In

particular, Congress sanctioned the

development of alternative generation

sources designated as ‘‘qualifying

facilities’’ (QFs) as a means of reducing

the demand for traditional fossil fuels.36

PURPA required utilities to purchase

power from QFs at a price not to exceed

the utility’s avoided costs and to sell

backup power to QFs.37

PURPA specifically set forth

limitations on who, and what, could

qualify as QFs. In addition to

technological and size criteria, PURPA

set limits on who could own QFs.38

Notwithstanding these limitations, QFs

proliferated. In 1989, there were 576 QF

facilities. By 1993, there were more than

1,200 such facilities.39 For the same

time period, installed QF capacity

increased from 27,429 megawatts to

47,774 megawatts.40 The rapid

expansion and performance of the QF

industry demonstrated that traditional,

vertically integrated public utilities

need not be the only sources of reliable

power.

During this period, the profile of

generation investment began to change,

and a market for non-traditional power

supply beyond the purchases required

by PURPA began to emerge. QFs were

limited to cogenerators and small power

producers.41

However, other non-traditional power

producers who could not meet the QF

criteria began to build new capacity to

compete in bulk power markets, without

such PURPA benefits as the mandatory

purchase requirements. These

producers, known as independent

power producers (IPPs), were

predominantly single-asset generation

companies that did not own any

transmission or distribution facilities.

While traditional utilities were

generally reluctant at that time to invest

in new generating facilities under cost

of service regulation, utilities

increasingly became interested in

participating in this new generation

sector. They organized affiliated power

producers (APPs), with assets not

included in utility rate base, and sought

to sell power in their own service

territories and the territories of other

utilities. At the same time, power

marketers arose. These entities—owning

no transmission or generation—buy and

sell power.42

There were two major impediments to

the development of IPPs and APPs.

First, the ownership restrictions of the

Public Utility Holding Company Act

(PUHCA) 43 severely inhibited these new

entities from entering the generation

business.44 Second, these entities

needed transmission service in order to

compete in electricity markets.

While the Commission had no

authority to remove PUHCA

restrictions,45 it encouraged the

development of IPPs and APPs, as well

as emerging power marketers, by

authorizing market-based rates for their

power sales on a case-by-case basis and

by encouraging more widely available

transmission access. From 1989 through

1993, facilities owned by IPPs and other

non-traditional generators (other than

QFs) increased from 249 to 634 and

their installed capacity increased from

9,216 megawatts to 13,004 megawatts.46

Indeed, ‘‘[i]n 1992, for the first time,

generating capacity added by

independent producers exceeded

capacity added by utilities.’’ 47

Market-based rates helped to develop

competitive bulk power markets. A

generating utility allowed to sell its

power at market-based rates could move

more quickly to take advantage of shortterm or even long-term market

opportunities than those laboring under

traditional cost-of-service tariffs, which

entail procedural delays in achieving

tariff approvals and changes.

In approving these market-based rates,

the Commission required, inter alia, that

the seller and any of its affiliates lack

market power or mitigate any market
21546 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

48See, e.g., Ocean State Power, 44 FERC ¶ 61,261

(1988); Commonwealth Atlantic Limited

Partnership, 51 FERC ¶ 61,368 (1990); Citizens

Power & Light Company, 48 FERC ¶ 61,210 (1989);

Orange and Rockland Utilities, Inc., 42 FERC

¶ 61,012 (1988); Doswell Limited Partnership, 50

FERC ¶ 61,251 (1990) (Doswel); and Dartmouth

Power Associates Limited Partnership, 53 FERC

¶ 61,117 (1990).

49See, e.g., Doswell, 50 FERC at 61,757.

50Citizens Power & Light Corporation, 48 FERC

¶ 61,210 at 61,777 (1989) (emphasis in original); see

also Utah Power & Light Company, PacifiCorp and

PC/UP&L Merging Corporation, 45 FERC ¶ 61,095 at

61,287–89 (1988), order on reh’g, 47 FERC ¶ 61,209,

order on reh’g, 48 FERC ¶ 61,035 (1989), remanded

in part sub nom. Environmental Action, Inc. v.

FERC, 939 F.2d 1057 (D.C. Cir. 1991), order on

remand, 57 FERC ¶ 61,363 (1991).

51 In earlier years, a few customers were able to

obtain access as a result of litigation, beginning

with the Supreme Court’s decision in Otter Tail

Power Company v. United States, 410 U.S. 366

(1973). Additionally, some customers gained access

by virtue of Nuclear Regulatory Commission license

conditions and voluntary preference power

transmission arrangements associated with federal

power marketing agencies. See, e.g., Consumers

Power Company, 6 NRC 887, 1036–44 (1977) and

The Toledo Edison Company and Cleveland

Electric Illuminating Company, 10 NRC 265, 327–

34 (1979). See Florida Municipal Power Agency v.

Florida Power and Light Company, 839 F. Supp.

1563 (M.D. Fla. 1993). See also Electricity

Transmission: Realities, Theory and Policy

Alternatives, The Transmission Task Force Report

to the Commission, October 1989, 197.

52See, e.g., Public Service Company of Colorado,

59 FERC ¶ 61,311 (1992), reh’g denied, 62 FERC

¶ 61,013 (1993); Utah Power & Light Company, et

al., Opinion No. 318, 45 FERC ¶ 61,095 (1988),

order on reh’g, Opinion No. 318–A, 47 FERC

¶ 61,209 (1989), order on reh’g, Opinion No. 318–

B, 48 FERC ¶ 61,035 (1989), aff’d in relevant part

sub nom. Environmental Action Inc. v. FERC, 939

F.2d 1057 (D.C. Cir. 1991); Northeast Utilities

Service Company (Public Service Company of New

Hampshire), Opinion No. 364–A, 58 FERC ¶ 61,070,

reh’g denied, Opinion No. 364–B, 59 FERC

¶ 61,042, order granting motion to vacate and

dismissing request for rehearing, 59 FERC ¶ 61,089

(1992), affirmed in relevant part sub nom. Northeast

Utilities Service Company v. FERC, 993 F.2d 937

(1st Cir. 1993).

53See, e.g., Public Service of Indiana, Inc., 51

FERC ¶ 61,367 (1990), reh’g denied, 52 FERC

¶ 61,260 (1990), appeal dismissed sub nom.

Northern Indiana Public Service Company v. FERC,

954 F.2d 736 (D.C.Cir. 1992).

54Pub. L. No. 102–486, 106 Stat. 2776 (1992),

codified at, among other places, 15 U.S.C. 79z–5a

and 16 U.S.C. 796 (22–25), 824j–l.

55See El Paso Electric Company and Central and

South West Services Inc., 68 FERC ¶ 61,181 at

61,914 (1994) (CSW); see also Paul Kemezis, FERC’s

Competitive Muscle: The Comparability Standard,

Electrical World 45 (Jan. 1995) (‘‘In EPAct, Congress

made it clear that the electric-power industry was

to move toward a fully competitive market system,

but left most of the implementation to FERC.’’).

56 15 U.S.C. 79z–5a.

57 15 U.S.C. 79z–5a(e).

58See supra note 36.

power that they may have possessed.48

The major concern of the Commission

was whether the seller or its affiliates

could limit competition and thereby

drive up prices. A key inquiry became

whether the seller or its affiliates owned

or controlled transmission facilities in

the relevant service area and therefore,

by denying access or imposing

discriminatory terms or conditions on

transmission service, could foreclose

other generators from competing.49 As

we have previously explained:

The most likely route to market power in

today’s electric utility industry lies through

ownership or control of transmission

facilities. Usually, the source of market

power is dominant or exclusive ownership of

the facilities. However, market power also

may be gained without ownership. Contracts

can confer the same rights of control. Entities

with contractual control over transmission

facilities can withhold supply and extract

monopoly prices just as effectively as those

who control facilities through ownership.50

As entry into wholesale power

generation markets increased, the ability

of customers to gain access to the

transmission services necessary to reach

competing suppliers became

increasingly important.51 In addition,

beginning in the late 1980s, in order to

mitigate their market power to meet

Commission conditions, public utilities

seeking Commission approval of

mergers or consolidations under section

203 of the FPA or Commission

authorization for blanket approval of

market-based rates for generation

services under section 205 of the FPA,

filed ‘‘open access’’ transmission tariffs

of general applicability.52 The

Commission applied its market rate

analysis to IOUs, as well as IPPs, APPs,

and marketers, and allowed IOUs to sell

at market-based rates only if they

opened their transmission systems to

competitors.53 The Commission also

approved proposed mergers on the

condition that the merging companies

remedy anticompetitive effects

potentially caused by the merger by

filing ‘‘open access’’ tariffs. These early

‘‘open access’’ tariffs required only that

the companies provide point-to-point

transmission services, which is a much

narrower requirement than that being

imposed in this Rule and did not

require transmission owners to provide

to others the same quality of service that

they themselves enjoyed.

Following PURPA, the economic and

technological changes in the

transmission and generation sectors

helped give impetus to the many new

entrants in the generating markets who

could sell electric energy profitably with

smaller scale technology at a lower price

than many utilities selling from their

existing generation facilities at rates

reflecting cost. However, it became

increasingly clear that the potential

consumer benefits that could be derived

from these technological advances could

be realized only if more efficient

generating plants could obtain access to

the regional transmission grids. Because

many traditional vertically integrated

utilities still did not provide open

access to third parties and still favored

their own generation if and when they

provided transmission access to third

parties, barriers continued to exist to

cheaper, more efficient generation

sources.

D. The Energy Policy Act

In response to the competitive

developments following PURPA, and

the fact that PUHCA and lack of

transmission access remained major

barriers to new generators, Congress

enacted Title VII of the Energy Policy

Act of 1992 (Energy Policy Act).54 A

goal of the Energy Policy Act was to

promote greater competition in bulk

power markets by encouraging new

generation entrants, known as exempt

wholesale generators (EWGs), and by

expanding the Commission’s authority

under sections 211 and 212 of the FPA

to approve applications for transmission

services.55

An EWG is defined as

Any person determined by the Federal

Energy Regulatory Commission to be engaged

directly, or indirectly through one or more

affiliates as defined in [PUHCA] section

2(a)(11)(B), and exclusively in the business of

owning or operating, or both owning and

operating, all or part of one or more eligible

facilities and selling electric energy at

wholesale.56

If the Commission, upon an

application, determines that a person is

an EWG, that person will be exempt

from PUHCA.57 This provision removed

a significant impediment to the

development of IPPs and APPs by

allowing them to develop projects as

EWGs free from the strictures of PUHCA

or the QF PURPA limitations.

While sections 211 and 212, as

enacted by PURPA, were intended to

provide greater access to the

transmission grid, the limitations placed

on these sections made them unusable

in virtually all circumstances.58

However, as amended by the Energy

Policy Act, these sections now give the

Commission broader authority to order

transmitting utilities to provide

wholesale transmission services, upon

application, to any electric utility,

Federal power marketing agency, or any

other person generating electric energy

for sale for resale.

The Energy Policy Act also added

section 213 to the FPA. Section 213(a)

requires a transmitting utility that does

not agree to provide wholesale

transmission service in accordance with

a good faith request to provide a written

explanation of its proposed rates, terms,

and conditions and its analysis of any
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21547

59See Policy Statement Regarding Good Faith

Requests for Transmission Services and Responses

by Transmitting Utilities Under Sections 211(a) and

213(a) of the Federal Power Act, as Amended and

Added by the Energy Policy Act of 1992, 58 FR

38964 (July 21, 1993), FERC Stats. & Regs.,

Regulations Preambles ¶ 30,975 (1993) (Policy

Statement Regarding Good Faith Requests for

Transmission Services).

60See New Reporting Requirements

Implementing Section 213(b) of the Federal Power

Act and Supporting Expanded Regulatory

Responsibilities Under the Energy Policy Act of

1992, and Conforming and Other Changes to Form

No. FERC–714, 58 FR 52420 (October 8, 1993),

FERC Stats. & Regs., Regulations Preambles ¶ 30,980

(Order No. 558), reh’g denied, Order No. 558–A, 65

FERC ¶ 61,324 (1993), regulations modified, 59 FR

15333 (April 1, 1994), FERC Stats. & Regs.,

Regulations Preambles ¶ 30,993.

61See Order No. 550, Filing Requirements and

Ministerial Procedures for Persons Seeking Exempt

Wholesale Generator Status, 58 FR 8897 (February

18, 1993), FERC Stats. & Regs., Regulations

Preambles ¶ 30,964, order on reh’g, Order No. 550–

A, 58 FR 21250 (April 20, 1993), FERC Stats. &

Regs., Regulations Preambles ¶ 30,969 (1993). As

recognized by Congress and the Commission,

availability of transmission information is critical in

developing competitive markets. See supra notes 59

and 60. This opened the ‘‘black box’’ of information

that previously was available only to transmission

owners.

62See Recovery of Stranded Costs by Public

Utilities and Transmitting Utilities, Notice of

Proposed Rulemaking, 59 FR 35274 (July 11, 1994),

FERC Stats. & Regs., Proposed Regulations ¶ 32,507

at 32,866 (Stranded Cost NOPR); American Electric

Power Service Corporation, 67 FERC ¶ 61,168,

clarified, 67 FERC ¶ 61,317 (1994).

63 16 U.S.C.A. 824j–824k (West 1985 and Supp.

1994).

64See, e.g., final orders issued in City of Bedford,

68 FERC ¶ 61,003 (1994), reh’g denied, 73 FERC

¶ 61,322 (1995); Florida Municipal Power Agency v.

Florida Power & Light Company, 67 FERC ¶ 61,167

(1994), order on reh’g, 74 FERC ¶ 61,006 (1996);

Minnesota Municipal Power Agency, 68 FERC

¶ 61,060 (1994); and Tex-La Electric Cooperative of

Texas, 69 FERC ¶ 61,269 (1994); see also Appendix

A.

65See Florida Municipal Power Agency v. Florida

Power & Light Company, 65 FERC ¶ 61,125, reh’g

dismissed, 65 FERC ¶ 61,372 (1993), final order, 67

FERC ¶ 61,167 (1994), order on reh’g, 74 FERC

¶ 61,006 (1996). The Commission has

‘‘characterized point-to-point service as involving

designated points of entry into and exit from the

transmitting utility’s system, with a designated

amount of transfer capability at each point.’’ El Paso

Electric Company v. Southwestern Public Service

Company, 68 FERC ¶61,182 at 61,926 n.9 (1994)

(citing Entergy Services, Inc., 58 FERC ¶ 61,234 at

61,768 (1993), reh’g dismissed, 68 FERC ¶ 61,399

(1994)). Network service allows more flexibility by

allowing a transmission customer to use the entire

transmission network to provide generation service

for specified resources and specified loads without

having to pay multiple charges for each resourceload pairing.

66 Florida Municipal, 67 FERC at 61,477.

67 69 FERC ¶ 61,035 at 61,165 (1994), reh’g

denied, 72 FERC ¶ 61,071 (1995); see also

Southwest Regional Transmission Association, 69

FERC ¶ 61,100 at 61,398 (1994), order on

compliance filing, 73 FERC ¶ 61,147 (1995)

(SWRTA).

68 64 FERC ¶ 61,279 (1993), reh’g granted, 67

FERC ¶ 61,168, clarified, 67 FERC ¶ 61,317 (1994).

69The Commission explained that AEP could

limit the service it was offering because it was

‘‘providing the service voluntarily under a tariff of

general applicability.’’ 64 FERC at 62,978.

70AEP, 67 FERC at 61,489.

physical or other constraints.59 Section

213(b) required the Commission to enact

a rule requiring transmitting utilities to

submit annual information concerning

potentially available transmission

capacity and known constraints.60

E. The Present Competitive Environment

Following the Energy Policy Act, the

Commission established rules: (1) For

certain generators to obtain EWG status

and thus an exemption from PUHCA; 61

and (2) that required transmission

information availability. The

Commission also pursued a number of

initiatives aimed at fostering the

development of more competitive bulk

power markets, including aggressive

implementation of section 211, a new

look at undue discrimination under the

FPA, easing of market entry for sellers

of generation from new facilities, and

initiation of a number of industry-wide

reforms. As stated by the Commission,

in recognition of the Congressional goal

in the Energy Policy Act of creating

competitive bulk power markets:

Our goal is to facilitate the development of

competitively priced generation supply

options, and to ensure that wholesale

purchasers of electric energy can reach

alternative power suppliers and vice versa. 62

1. Use of Sections 211 and 212 to Obtain

Transmission Access

The Commission has aggressively

implemented sections 211 and 212 of

the FPA, as amended by the Energy

Policy Act, in order to promote

competitive markets.63 When wheeling

requests under sections 211 and 212

have been made, the Commission has

required wheeling in almost all of the

requests it has processed. To date, the

Commission has issued orders

(proposed or final) requiring wheeling

in 12 of the 14 cases it has acted on.64

As a general matter, section 211 has

permitted some inroads to be made by

customers in obtaining transmission

service from public utilities that

historically have declined to provide

access to their systems, or have offered

service only on a discriminatory basis.

Under section 211, the Commission has

granted requests for the broader type of

service that most utilities historically

have refused to provide—network

service. Although transmission owners

have provided limited amounts of

unbundled point-to-point transmission

service, third-party customers have not

been able to obtain the flexibility of

service that transmission owners enjoy.

In Florida Municipal, a section 211

case, the Commission ordered

‘‘network,’’ rather than the narrower

‘‘point-to-point,’’ service.65 Network

service permits the applicant to fully

integrate load and resources on an

instantaneous basis in a manner similar

to the transmission owner’s integration

of its own load and resources. At the

same time, the Commission made the

generic finding that the availability of

transmission service will enhance

competition in the market for power

supplies and lead to lower costs for

consumers. The Commission explained

that as long as the transmitting utility is

fully and fairly compensated and there

is no unreasonable impairment of

reliability, transmission service is in the

public interest.66

As discussed infra, based on the

mounting competitive pressures in the

industry and rapidly evolving markets,

we have concluded that section 211

alone is not enough to eliminate undue

discrimination. The comments received

on the proposed rules, discussed in

detail infra, confirm this conclusion.

The significant time delays involved in

filing an individual service request for

bilateral service under section 211 place

the customer at a severe disadvantage

compared to the transmission owner

and can result in discriminatory

treatment in the use of the transmission

system. It is an inadequate procedural

substitute for readily available service

under a filed non-discriminatory open

access tariff. As the Commission noted

in Hermiston Generating Company,

‘‘[t]he ability to spend time and

resources litigating the rates, terms and

conditions of transmission access is not

equivalent to an enforceable voluntary

offer to provide comparable service

under known rates, terms and

conditions.’’ 67

2. Commission’s Comparability

Standard

In the Spring of 1994, the Commission

began to address the problem of the

disparity in transmission service that

utilities provided to third parties in

comparison to their own uses of the

transmission system. In the seminal case

in this area, American Electric Power

Service Corporation (AEP), the company

voluntarily proposed a tariff of general

applicability that would offer firm,

point-to-point transmission service for a

minimum of one month.68 The

Commission accepted the proposed

transmission tariff for filing and

suspended its effectiveness for one day,

subject to refund.69 Rehearing requests

challenged the Commission’s summary

approval of the restriction of service to

point-to-point as being discriminatory

and anticompetitive.70 The rehearing
21548 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

71With respect to anticompetitive effects, the

Commission explained that it has ‘‘adhered to the

Supreme Court’s determination that the

Commission’s ’important and broad regulatory

power * * * carries with it the responsibility to

consider, in appropriate circumstances, the

anticompetitive effects of regulated aspects of

interstate utility operations pursuant to sections 202

and 203, and under like directives contained in

sections 205, 206 and 207.’ Gulf States Utilities

Company v. FPC, 411 U.S. 747, 758–59 (1972).’’ Id.

at 61,490 (footnote omitted). The Commission

reaffirmed that it would examine how best to fulfill

this responsibility, as well as its responsibility to

prevent undue discrimination, in light of the

changing conditions in the electric utility industry.

Id.

72 Id. at 61,490.

73 Id. at 61,490–91.

74See Kansas City Power & Light Company, 67

FERC ¶ 61,183 (1994), reh’g pending.

75E.g., CSW, supra, 68 FERC at 61,914.

76 Id.

77 Id. at 61,915 (footnote omitted).

78 68 FERC ¶ 61,223 (1994).

79 Id. at 62,060. In InterCoast Power Marketing

Company, 68 FERC ¶ 61,248, clarified, 68 FERC

¶ 61,324 (1994), the Commission rejected an

affiliated marketer’s proposal to sell at market rates

without its affiliate utility offering comparable

transmission services. The Commission stated that

the only way to ensure that InterCoast does not

have transmission market power is to require its

affiliated public utility to offer comparable

transmission services. See also LG&E Power

Marketing Inc., 68 FERC ¶ 61,247 at 62,120–21

(1994). The Commission added that this is

consistent with encouraging competitive bulk

power markets as envisioned by the Energy Policy

Act of 1992. Id. at 62,132.

80See Hermiston Generating Company, 69 FERC

¶ 61,035 at 61,164 (1994), reh’g pending. The

Commission subsequently accepted the rates on a

cost basis. See Letter Order dated November 10,

1994.

81 Id. at 61,165.

82See SWRTA, 69 FERC at 61,397; see also

PacifiCorp, the California Municipal Utilities

Association, and the Independent Energy Producers

(on behalf of Western Regional Transmission

Association), 69 FERC ¶ 61,099, order on reh’g, 69

FERC ¶ 61,352 (1994), order on compliance filing,

71 FERC ¶ 61,158 (1995) (WRTA). An RTG is a

regional transmission group. It is defined as ‘‘a

voluntary organization of transmission owners,

transmission users, and other entities interested in

coordinating transmission planning (and

expansion), operation and use on a regional (and

inter-regional.’’ Policy Statement Regarding

Regional Transmission Groups, 58 FR 41626

(August 5, 1993), FERC Stats. & Regs., Regulations

Preambles ¶ 30,976 at 30,870 n. 4 (RTG Policy

Statement).

83SWRTA, 69 FERC at 61,398.

requests argued that the tariff should be

expanded to include network services

such as those used by the transmission

owner. On rehearing, the Commission

announced a new standard for

evaluating claims of undue

discrimination.

The Commission found that a

voluntarily offered, new open access

transmission tariff that did not provide

for services comparable to those that the

transmission owner provided itself was

unduly discriminatory and

anticompetitive.71 In reaching that

conclusion, the Commission broadened

its undue discrimination analysis

(which traditionally had focused on the

rates, terms, and conditions faced by

similarly situated third-party customers)

to include a focus on the rates, terms,

and conditions of a utility’s own uses of

the transmission system:

(A)n open access tariff that is not unduly

discriminatory or anticompetitive should

offer third parties access on the same or

comparable basis, and under the same or

comparable terms and conditions, as the

transmission provider’s uses of its system.72

Refocusing the analysis was

necessitated by the changing conditions

in the electric utility industry, including

the emergence of non-traditional

suppliers and greater competition in

bulk power markets. Because a

transmission provider may use its

system in different ways (e.g., to

integrate load and resources when

serving retail native load, to make offsystem sales or purchases, or to serve

wholesale requirements customers), the

Commission set for hearing the factual

issues associated with identifying those

uses, as well as any potential

impediments or consequences to

providing comparable services to third

parties.73

After AEP, the Commission applied

this comparability standard to a

proposed open access transmission tariff

that was filed by Kansas City Power &

Light Company (KCP&L) in support of a

proposal to sell generation at marketbased rates.74 The Commission

explained that, in light of AEP, the

utility’s proposed open access

transmission tariff (which provided only

for point-to-point service) did not

adequately mitigate its transmission

market power so as to justify allowing

the requested market-based rates.

KCP&L could charge market-based rates

for sales only if it modified its proposed

transmission tariff to reflect the AEP

comparability standard.

Since then, the Commission has

required comparable service in a variety

of contexts, and has set for hearing the

factual issues associated with

comparable service. For example, the

Commission found that market power

can be adequately mitigated only if a

merged company offers transmission

services in accordance with the AEP

comparability standard.75 The

Commission further held that, even if a

merger does not result in an increase in

market power, the merger would not be

consistent with the public interest

under section 203 of the FPA unless the

merged company offers comparable

transmission services, as defined in

AEP.76 The Commission therefore

announced a transmission

comparability requirement for all new

mergers:

Given the transition of the electric utility

industry as a whole, we conclude that, absent

other compelling public interest

considerations, coordination in the public

interest can best be secured only if merging

utilities offer comparable transmission

services.77

In Heartland Energy Services, Inc.,78

the Commission applied its

comparability standard to an affiliated

electric power marketer seeking blanket

authorization to sell electricity at

market-based rates. The Commission

explained that

For all future cases involving blanket

approval of market-based rates an offer of

comparable transmission services will be

required before the Commission will be able

to find that transmission market power has

been adequately mitigated. In the context of

an affiliated power marketer, this means that

all of its affiliated utilities must have a

comparable transmission tariff on file.79

The Commission also denied a

request by a company affiliated with a

transmission-owning utility seeking

permission to sell power at marketbased rates to a particular customer. The

denial was without prejudice to refiling

such a request in a new section 205

proceeding, but only after the affiliated

transmission-owning utility filed a

comparable transmission service tariff.80

The Commission added that it

Will require comparability in any situation

in which a seller seeking market-based rates

is affiliated with an owner or controller of

transmission facilities.81

The Commission has also stated that

‘‘it will henceforth apply the

transmission comparability standard

announced in the AEP case to all

transmitting utility members of an

RTG.’’ 82

The Commission further declared that

comparable services must be provided

through ‘‘open access’’ tariffs rather

than only on a contract-by-contract

basis:

(T)ariffs are essential to the provision of

comparable services. Tariffs set out the

services that are available and the terms and

conditions under which those services will

be made available * * *. (In contrast), a

negotiation process creates uncertainty and

imposes on customers delay and other

transaction costs that the transmitting utility

members of an RTG do not incur when using

the transmission for their own benefit.

Moreover, the ability to execute separate

transmission agreements with different but

similarly situated customers is the ability to

unduly discriminate among them. A tariff

ensures against such discrimination in the

RTG.83
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21549

84KCP&L, 67 FERC ¶ 61,183 (1994).

85 Id. at 61,557 (citing Entergy Services, Inc., 58

FERC ¶ 61,234 at 61,756 and nn. 63 and 65

(Entergy)).

86 Id. The Commission added that ‘‘after

examining generation dominance in many different

cases over the years, we have yet to find an instance

of generation dominance in long-run bulk power

markets.’’ Id.

87 Id.

88FERC Stats. & Regs. ¶ 32,507 (1994).

89 Inquiry Concerning the Commission’s Pricing

Policy for Transmission Services Provided by

Public Utilities Under the Federal Power Act, 59 FR

55031 (November 3, 1994), FERC Stats. & Regs.,

Regulations Preambles ¶ 31,005 (Transmission

Pricing Policy Statement).

90 Inquiry Concerning Alternative Power Pooling

Institutions Under the Federal Power Act, 59 FR

54851 (October 26, 1994), FERC Stats. & Regs.,

Notices ¶ 35,529 (1995) (Pooling Notice of Inquiry).

91FERC Stats. & Regs. ¶ 30,976 (RTG Policy

Statement).

92FERC Stats. & Regs. ¶ 35,531 (1996).

93FERC Stats. & Regs. ¶ 32,507 at 32,864.

94Most transmission contracts set a single price

for energy flow over a utility’s transmission system.

This single-price policy is called ‘‘postage stamp’’

pricing because the rate does not depend on how

far the power moves within a company’s

transmission system. If power flows through several

companies, traditional industry practice is to

specify that power flows along a ‘‘contract path’’

consisting of the transmission-owning utilities

between the ultimate receipt and delivery points.

See Indiana Michigan Power Company, 64 FERC

¶ 61,184 at 62,545 (1993).

95Unlike with postage stamp pricing, with

distance-sensitive pricing the cost of moving power

through a company depends on how far the power

moves within the company. In contrast to contract

path pricing, flow-based pricing establishes a price

based on the costs of the various parallel paths

actually used when the power flows. Because flowbased pricing can account for all parallel paths used

by the transaction, all transmission owners with

facilities on any of the parallel paths could be

compensated for the transaction.

96FERC Stats. & Regs. ¶ 31,005 at 31,136.

97 Id. at 31,142.

98FERC Stats. & Regs. ¶ 35,529 at 35,715.

99 Id. at 35,714. As explained below, the

Commission held technical conferences on issues

surrounding power pools and competition.

Thus, the Commission required the

RTGs to amend their bylaws to commit

all transmitting utility members to offer

comparable transmission services to

other RTG members pursuant to a

transmission tariff or tariffs.

As discussed below, since the AEP

comparability standard was announced,

the Commission has set for hearing 44

open access tariffs to determine what

constitutes comparable service. This

number includes tariffs filed subsequent

to the Open Access NOPR. All tariffs

have now been made subject to the

outcome of the Final Rule.

3. Lack of Market Power in New

Generation

In 1994 in the KCP&L case, discussed

in the prior section, the Commission

continued to recognize that

transmission remains a natural

monopoly. However, it found that, in

light of the industry and statutory

changes that now allow ease of market

entry, no wholesale seller of generation

has market power in generation from

new facilities.84 In particular, the

Commission explained that it had

previously noted in Entergy Services,

Inc. that

There was significant evidence that nontraditional power project developers,

including qualifying facilities and

independent power projects, are becoming

viable competitors in long-run markets.85

The Commission further explained

that since Entergy, Congress had enacted

the Energy Policy Act, which had

lowered barriers to the entry of new

suppliers by creating a new class of

power suppliers—EWGs—that are

exempt from the provisions of

PUHCA.86 The Commission concluded

that, in considering market-based rate

proposals for generation sales, it need

only focus on market power in

transmission, generation market power

in short-run markets, and other barriers

to entry.87

4. Further Commission Action

Addressing a More Competitive Electric

Industry

To address the fact that the electric

industry is becoming more competitive,

and to remove barriers that might

inhibit a more competitive industry, the

Commission has initiated a number of

proceedings: (1) Stranded Cost NOPR,88

(2) Transmission Pricing Policy

Statement,89 (3) Pooling Notice of

Inquiry,90 (4) Regional Transmission

Group (RTG) Policy Statement,91 and (5)

Notice of Inquiry on Merger Policy.92

In the Stranded Cost NOPR the

Commission recognized that the trend

toward greater transmission access and

the transition to a fully competitive bulk

power market could cause some utilities

to incur stranded costs as wholesale

requirements customers (or retail

customers) use their supplier’s

transmission to purchase power

elsewhere. As the Commission noted, a

utility may have built facilities or

entered into long-term fuel or purchased

power supply contracts with the

reasonable expectation that its

customers would renew their contracts

and would pay their share of long-term

investments and other incurred costs. If

the customer obtains another power

supplier, the utility may have stranded

costs. If the utility cannot locate an

alternative buyer or somehow mitigate

the stranded costs, the Commission

explained that ‘‘the costs must be

recovered from either the departing

customer or the remaining customers or

borne by the utility’s shareholders.’’ 93

Accordingly, the Commission proposed

to establish provisions concerning the

recovery of wholesale and retail

stranded costs by public utilities and

transmitting utilities.

In the Transmission Pricing Policy

Statement, the Commission announced

a new policy providing greater

flexibility in the pricing of transmission

services provided by public utilities and

transmitting utilities. The Commission

traditionally had allowed only postagestamp, contract-path pricing.94 Under

the new policy, we will permit a variety

of proposals, including distance

sensitive and flow-based pricing, which

may be more suitable for competitive

wholesale power markets.95 The

Commission explained that this

‘‘(g)reater pricing flexibility is

appropriate in light of the significant

competitive changes occurring in

wholesale generation markets, and in

light of our expanded wheeling

authority under the Energy Policy Act of

1992.’’ 96 However, the Commission

explained that any new transmission

pricing proposal must meet the

Commission’s AEP comparability

standard. The Commission further

explained that comparability of service

applies to price as well as to terms and

conditions.97

The Commission issued the Pooling

Notice of Inquiry to receive comments

on traditional power pools and on

alternative power pooling institutions

that are being explored in today’s more

competitive environment. The

Commission expressed concern that

(G)iven the ongoing changes in the

competitive environment of the electric

utility industry—in particular, the potential

for substantially increased access to

transmission—we must consider whether we

are appropriately balancing our dual

objectives of promoting coordination and

competition.98

Accordingly, the Commission

explained that it wished to look at

alternative power pooling institutions

and to re-examine the role of more

traditional power pools in today’s

environment of increased competition.

In particular the Commission expressed

its intent to ensure that its policies ‘‘are

consistent with the development of a

competitive bulk power market.’’ 99

In the RTG Policy Statement, the

Commission announced a policy

encouraging the development of RTGs.

The Commission explained that a

primary purpose of RTGs is to facilitate

transmission access for potential users

and voluntarily resolve disputes over

such service. The Commission has

approved the formation of three
21550 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

100See WRTA and SWRTA, supra, and Northwest

Regional Transmission Association, 71 FERC

¶ 61,397 (1995).

101At least 12 states have retail wheeling

proposals, legislation, or pilot programs

underway—Alabama, California, Connecticut,

Illinois, Massachusetts, Michigan, New Hampshire,

New York, Ohio, Rhode Island, Vermont, and

Wisconsin. At least 14 other states are investigating

retail wheeling. Currently, according

to a report of the NARUC-affiliated National

Council on competition and the Electric Industry,

41 States are actively involved in investigating

whether and how to restructure their respective

electric power markets. Of this total, 29 State

regulatory authorities * * * have initiated

investigations. In addition, five State legislatures

are involved in similar investigations, while seven

other States have joint regulatory/legislative

proceedings underway.

Testimony of the Honorable Cheryl L. Parrino,

Chair of the Wisconsin Public Service Commission,

on behalf of the National Association of Regulatory

Utility Commissioners, before the United States

Senate Committee on Energy and Natural Resources

(March 6, 1996).

102See American Electric Power Service

Corporation, et al., 72 FERC ¶ 61,287 at 61,238

(1995).

103Attached to this Final Rule as Appendix B is

a list of commenters and the abbreviations used to

designate them, including those commenters that

filed late.

104Energy Information Administration,

Performance Issues for a Changing Electric Power

Industry (January 1995) 10 and (Figure 5).

105Current Competition, November 1994, Vol. 5,

No. 8, at 8.

106As discussed above, a significant number of

public utilities still do not have any form of an

‘‘open access’’ tariff on file with the Commission

and no public utility has on file a nondiscriminatory open access tariff as defined by this

Rule.

RTGs.100 One of the conditions is that

each RTG member must offer

comparable transmission services by

tariff to other RTG members.

In the merger NOI, the Commission

indicated that it will review whether its

criteria and policy for evaluating

mergers need to be modified in light of

the changing circumstances occurring in

the electric industry.

In addition to the Commission’s

actions, a number of states have

initiated proceedings concerning retail

wheeling or proposed legislation for

retail wheeling, that is, for ultimate

consumers to choose their supplier of

power, or other restructuring

proposals.101

5. Events Since Issuance of Open Access

NOPR

Since issuance of the Open Access

NOPR, public utilities have filed, in

some form or another, 47 open access

tariffs. In acting on those filings, the

Commission has made all of the nonrate terms and conditions of those

proposed tariffs subject to the outcome

of this Final Rule.102

Over the last year, the Commission

also has received and analyzed more

than 20,000 pages of comments that

were received from over 400

commenters, as well as additional

information provided by industry

participants at a number of

Commission-initiated technical

conferences.103 Those technical

conferences addressed several issues—

ancillary services, pro forma tariffs,

power pools, and ISOs—and provided

significant input to the Commission’s

formulation of this Final Rule.

F. Need for Reform

The many changes discussed above

have converged to create a situation in

which new generating capacity can be

built and operated at prices

substantially lower than many utilities’

embedded costs of generation. As

discussed above, new generation

facilities can produce power on the grid

at a cost of less than 3 cents per kWh

to 5 cents per kWh, yet the costs for

large plants constructed and installed

over the last decade were typically in

the range of 4 to 7 cents per kWh for

coal plants and 9 to 15 cents for nuclear

plants.

Non-traditional generators are taking

advantage of this opportunity to

compete. Indeed, the non-traditional

generators’ share of total U.S. electricity

generation increased from 4 percent in

1985 to 10 percent in 1993.104 Much of

this increased share of generation is the

result of competitive bidding for new

generation resources that has occurred

in 37 states. Since 1984, almost 4,000

projects, representing over 400,000 MW,

have been offered in response to

requests. Over 350 projects have been

selected to supply 20,000 MW, and, of

these, 126 are now online producing

almost 7,800 MW of power.105

In addition, the cost of utilitygenerated electricity differs widely

across the major regions of the United

States. Average utility rates range from

3 to 5 cents in the Northwest to 9 to 11

cents in California. Electricity

consumers are demanding access to

lower cost supplies available in other

regions of the United States, and access

to the newer, lower cost generation

resources. Therefore, it is important that

the non-traditional generators of

cheaper power be able to gain access to

the transmission grid on a nondiscriminatory open access basis.

The Commission’s goal is to ensure

that customers have the benefits of

competitively priced generation.

However, we must do so without

abandoning our traditional obligation to

ensure that utilities have a fair

opportunity to recover prudently

incurred costs and that they maintain

power supply reliability. As well, the

benefits of competition should not come

at the expense of other customers. The

Commission believes that requiring

utilities to provide non-discriminatory

open access transmission tariffs, while

simultaneously resolving the extremely

difficult issue of recovery of transition

costs (discussed infra), is the key to

reconciling these competing demands.

Non-discriminatory open access to

transmission services is critical to the

full development of competitive

wholesale generation markets and the

lower consumer prices achievable

through such competition.106

Transmitting utilities own the

transportation system over which bulk

power competition occurs and

transmission service continues to be a

natural monopoly. Denials of access

(whether they are blatant or subtle), and

the potential for future denials of access,

require the Commission to revisit and

reform its regulation of transmission in

interstate commerce. As discussed in

detail in Section IV.B., such action is

required by the FPA’s mandate that the

Commission remedy undue

discrimination.

Since the time the NOPR issued, the

Commission staff has completed an

FEIS that provides a quantitative

estimate of some of the cost savings

expected from this Rule: approximately

$3.8 to $5.4 billion per year. Other nonquantifiable benefits are also expected

from this Rule and include: (1) Better

use of existing assets and institutions;

(2) new market mechanisms; (3)

technical innovation; and (4) less rate

distortion. These potential benefits to

the Nation’s electricity consumers and

the economy as a whole confirm the

need to take generic action to remove

barriers to competition. In what follows,

we set out the changes necessary to

remedy undue discrimination and to

ensure a fair transition to a more

competitive regulatory regime.

IV. Discussion

A. Scope of the Rule

1. Introduction

The Commission has determined that

non-discriminatory open access

transmission services (including access

to transmission information) and

stranded cost recovery are the most

critical components of a successful

transition to competitive wholesale

electricity markets. These issues are the

focal point of this Rule, the

accompanying rule on open access

same-time information systems, and the

accompanying proposed rule on

capacity reservation tariffs.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21551

107FERC Stats. & Regs. ¶32,514 at 33,080.

108E.g., Ohio Edison, UtiliCorp, Pennsylvania

P&L, Atlantic City, Montana Power, IL Com, Seattle,

OK Com, TX Industrials, MidAmerican,

Southwestern, Southern, DOD, Public Service Co of

CO, SC Public Service Authority, Florida Power

Corp, DOE, WP&L, Com Ed, SBA, Consumers

Power, CA Com, UT Com, Houston L&P, KCPL, EEI.

109E.g., Florida Power Corp, El Paso, PSNM, and

SC Public Service Authority.

110E.g., Southwestern, PECO, El Paso, Florida

Power Corp, NSP, Public Service E&G,

MidAmerican.

111E.g., NRECA, IN Com, Power Marketing

Association, TDU Systems, NorAm, Turlock,

Texaco, Utility Shareholders, NSP, El Paso, Utility

Investors Analysts, PECO, Florida Power Corp, UT

Com, Sierra, Carolina P&L, SoCal Gas, OK Com, FL

Com, Southern.

112E.g., American Forest & Power, American

National Power, ND Com, IL Com, UAMPS, NIEP,

APPA, Public Power Council, Municipal Energy

Agency Nebraska, Missouri Basin MPA, Texaco,

Direct Services Industries, Calpine, CCEM,

Wisconsin Coalition, VT DPS.

113See also American National Power, ND Com,

Calpine.

114NIEP Initial Comments at 4.

115See also Municipal Energy Agency Nebraska,

Direct Services Industries.

116Others oppose operational unbundling. See,

e.g., Carolina P&L, Salt River.

In undertaking these initiatives,

however, we are mindful that they are

part of a broader picture of evolving

issues affecting the electric industry and

that other Commission policies will

play an important role in ensuring the

full development of competitive

markets. Among the many issues that

are important to competitive bulk power

markets are: independent system

operators (ISOs); regional transmission

groups; generation market power; utility

merger policy; and the development of

innovative transmission pricing

alternatives, such as flow-based,

distance-sensitive transmission pricing

methodologies that reflect incremental

costs. In particular, we believe that ISOs

have great potential to assist us and the

industry to help provide regional

efficiencies, to facilitate economically

efficient pricing, and, especially in the

context of power pools, to remedy

undue discrimination and mitigate

market power. Although we discuss

some of these issues in this Rule, we

will further develop our policies in

other proceedings as well to

accommodate and encourage more

efficient market structures.

We now address the comments

received on the scope of the proposed

rulemaking.

2. Functional Unbundling

In the NOPR, the Commission

preliminarily found that functional

unbundling of wholesale generation and

transmission services is necessary to

implement non-discriminatory open

access transmission.107 At the same

time, the Commission explained that the

proposed rule would accommodate, but

not require, corporate unbundling

(which could include selling generation

or transmission assets to a non-affiliate

(divestiture) or the less aggressive step

of establishing separate corporate

affiliates to manage a utility’s

transmission and generation assets).

However, we invited comments on

functional unbundling and asked

whether it is a strong enough measure

to ensure non-discriminatory open

access transmission without some form

of corporate restructuring.

Comments

Commenters take both sides on

whether functional unbundling is

sufficient to assure non-discriminatory

open access transmission or whether a

stronger measure, such as corporate

unbundling, is needed.

Supporting Functional Unbundling

Various commenters, including

utilities and state commissions,

generally support functional

unbundling as sufficient to assure nondiscriminatory open access transmission

and oppose requiring corporate

unbundling or divestiture.108 Several

commenters state that functional

unbundling will remedy discrimination

without creating the inefficiencies and

additional costs that corporate

restructuring would create.109

A number of other commenters argue

that the Commission has no authority

under the FPA to require divestiture of

transmission assets.110 Several of these

commenters assert that, even if the

Commission has the authority, the

electric industry, unlike the natural gas

industry, is not ready for mandated

corporate unbundling because electric

utilities still serve a high percentage of

retail customers and own large amounts

of the generating capacity. They assert

that transmission system operation

requires the operator to have control

over much of the generating capacity.

Various other commenters also

support functional unbundling, but

believe that safeguards are needed to

make it work.111 Power Marketing

Association, for example, suggests a

number of safeguards: adoption of cost

allocation mechanisms to ensure that

utilities do not shift costs from

generation to transmission; random

audits of utility books; a requirement

that each utility file a code of conduct

that provides for maximum separation

of generation and transmission

functions; and active oversight and

complaint procedures with strong

penalties for abuse. OK Com and GA

Com believe that functional unbundling

along with the safeguard of the

Commission’s complaint process will

provide sufficient incentive for nondiscriminatory open access

transmission.

Supporting Corporate Unbundling

A number of commenters see

weaknesses in functional unbundling

and argue that some form of corporate

unbundling is necessary to assure nondiscriminatory open access

transmission.112 American Forest &

Paper says that there is affiliate abuse in

the gas industry and argues that the

electric industry presents even more

serious potential for abuse because it is

still dominated by vertically integrated

utilities.113 UAMPS asserts that

functional unbundling is insufficient

because the utility will still favor itself

on issues related to transmission

planning, capital investment, and

operation and maintenance and

replacement costs.

NIEP argues that divestiture of

generation assets from transmission and

distribution is the preferred mechanism

for mitigating market power. It further

suggests that if corporate divestiture is

not feasible the Commission should

Seek to achieve ‘‘virtual divestiture’’ by

requiring that the utility generation function

be separated from transmission and

distribution functions in a separate corporate

affiliate, or business unit, and that affiliate

transaction rules be established to guard

against possible abuses. 114

It maintains that the Commission has

broad authority to protect against undue

discrimination and anticompetitive

behavior and can order divestiture if

such action is required to remedy such

behavior.115

FTC and DOJ argue that operational

unbundling, an example of which is the

formation of an independent system

operator (ISO), likely would be more

effective than functional unbundling

and less costly than industry-wide

divestiture.116 FTC describes operational

unbundling as ‘‘structural institutional

arrangements, short of divestiture, that

would separate operation of the

transmission grid and access to it from

economic interests in generation.’’ It

gives as an example the California

proposal under which utilities would

continue to own transmission lines, but

an independent system operator would

have operational control. DOJ also

suggests ‘‘a separate authority’’ to
21552 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

117When and how functional unbundling is to be

achieved for requirements transactions and for

various types of coordination arrangements,

including power pools, is discussed at Sections

IV.A.5 and IV.F. Functional unbundling of ancillary

services is discussed in Section IV.D.

118Real-Time Information Networks and

Standards of Conduct, Notice of Proposed

Rulemaking, 60 FR 66182 (December 21, 1995),

FERC Stats. & Regs., Proposed Regulations ¶ 32,516

at 33,170 (1995).

119The final rule on information systems no

longer uses the terminology RINs. The new

terminology used is OASIS—Open Access Sametime Information System—which we will use in

this Final Rule.

120 67 FERC ¶ 61,183 at 61,557 (1994), reh’g

pending (KCP&L).

manage the grid and access to the grid,

joint ventures, and voluntary pooling

arrangements. These commenters argue

that operational unbundling would be

easier to enforce than functional

unbundling.

DOE states that separation of the

control of transmission from verticallyintegrated companies does not

necessarily require a poolco or any

particular market mechanism. It

suggests the possibility of an ISO that is

functionally separate from any buyer or

seller of generation, but would not

perform all the functions of a poolco.

United Illuminating supports

‘‘operational unbundling’’ that would

either (1) eliminate vertical integration

and divestiture of transmission assets,

leading to the formation of a regional

transmission company, or (2) develop a

regional contractual approach to

transmission services that eliminates the

transmission owner’s market power and

fairly allocates support of the

transmission facilities between native

load and third-party users of the system.

Commission Conclusion

We conclude that functional

unbundling of wholesale services is

necessary to implement nondiscriminatory open access transmission

and that corporate unbundling should

not now be required. As we explained

in the NOPR, functional unbundling

means three things:

(1) A public utility must take

transmission services (including

ancillary services) for all of its new

wholesale sales and purchases of energy

under the same tariff of general

applicability as do others;

(2) A public utility must state separate

rates for wholesale generation,

transmission, and ancillary services;

(3) A public utility must 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.

We believe that these requirements

are necessary to ensure that public

utilities provide non-discriminatory

service.117 These requirements also will

give public utilities an incentive to file

fair and efficient rates, terms, and

conditions, since they will be subject to

those same rates, terms, and conditions.

However, we recognize that

additional safeguards are necessary to

protect against market power abuses.

Functional unbundling will work only if

a strong code of conduct (including a

requirement to separate employees

involved in transmission functions from

those involved in wholesale power

merchant functions) is in place. In the

RINs NOPR, the Commission proposed

a code of conduct that would apply to

all public utility transmission providers.

As the Commission explained,

[T]his code of conduct would require,

among other matters, a separation of the

utilities’ transmission system operations and

wholesale marketing functions, and would

define permissible and impermissible

contacts between employees that conduct

wholesale generation marketing functions

and employees that handle transmission

system operations and reliability in the

system control center or at other facilities or

locations.118

Adoption of this code of conduct,

discussed in detail in the accompanying

final rule on OASIS,119 is needed to

ensure that the transmission owner’s

wholesale marketing personnel and the

transmission customer’s marketing

personnel have comparable access to

information about the transmission

system.

As noted by OK Com and GA Com, a

further safeguard—section 206—is

available if a public utility seeks to

circumvent the functional unbundling

requirements. Under section 206, any

person is free to file a complaint with

the Commission detailing any alleged

misbehavior on the part of the public

utility or its affiliates concerning

matters subject to our jurisdiction under

the FPA. Similarly, the Commission

may, on its own motion, initiate a

proceeding to investigate the practices

of the public utility and its affiliates.

We believe that functional

unbundling, coupled with these

safeguards, is a reasonable and workable

means of assuring that nondiscriminatory open access transmission

occurs. In the absence of evidence that

functional unbundling will not work,

we are not prepared to adopt a more

intrusive and potentially more costly

mechanism—corporate unbundling—at

this time.

Several commenters discuss the need

to encourage or even to require ISOs in

the context of functional unbundling.

We believe that ISOs have the potential

to provide significant benefits (e.g., to

help provide regional efficiencies, to

facilitate economically efficient pricing,

and, especially in the context of power

pools, to remedy undue discrimination

and mitigate market power) and will

further our goal of achieving a workably

competitive market. As we learned at

our technical conference on power

pools, many utilities are examining ISOs

and corporate unbundling in various

shapes and forms, particularly in the

context of power pools. We discuss ISOs

extensively in our section on power

pools where we believe they will have

an important role to play. However, in

the context of individual utility

transactions, we believe that the less

intrusive functional unbundling

approach outlined above is all that we

must require at this time. Nevertheless,

we 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 nondiscriminatory open access

transmission, we will reevaluate our

position and decide whether other

mechanisms, such as ISOs, should be

required.

Finally, while we are not now

requiring any form of corporate

unbundling, we again encourage

utilities to explore whether corporate

unbundling or other restructuring

mechanisms may be appropriate in

particular circumstances. Thus, we

intend to accommodate other

mechanisms that public utilities may

submit, including voluntary corporate

restructurings (e.g., ISOs, separate

corporate divisions, divestiture,

poolcos), to ensure that open access

transmission occurs on a nondiscriminatory basis. We also will

continue to monitor—and stand ready to

work with parties engaging in—

innovative restructuring proposals

occurring around the country.

3. Market-Based Rates

a. Market-Based Rates for New

Generation

In the NOPR, the Commission

proposed to codify its determination in

Kansas City Power & Light Company 120
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21553

121FERC Stats. & Regs. ¶ 32,514 at 33,050.

122 Id. at 33,154.

123 67 FERC at 61,557.

124E.g., Entergy, EEI, Atlantic City, Duke

Centerior, Houston L&P, Montana-Dakota Utilities,

Canadian Petroleum Producers, DOE, Florida Power

Corp, PSNM.

125E.g., EEI, Centerior, Houston L&P, NYSEG.

126E.g., TDU Systems, ELCON, NRECA,

Environmental Action, NIEP, APPA, Power

Marketing Association, EGA.

127See, e.g., MidAmerican Energy Company, 74

FERC ¶ 61,211 (1996).

128KCP&L, 67 FERC at 61,557. See also discussion

in proposed rule, FERC Stats. & Regs. at 33,067–68.

129 Id.

130The NOPR’s proposed language that a public

utility would not have to demonstrate a lack of

market power in generation for sales from capacity

first placed in service on or after the date 30 days

after the final rule is published in the Federal

Register does not properly reflect the finding in

KCP&L. Because KCP&L addressed new or unbuilt

generation, the proposed language is being revised

as indicated above and as set forth in the regulatory

text included with this Final Rule.

131Cf. Wisconsin Electric Power Company, et al.,

74 FERC ¶ 61,069 at 61,193 (1996).

that the generation dominance standard

for market-based sales from new

capacity be dropped.121 The proposed

new section 35.27 would provide:

Notwithstanding any other requirements,

any public utility seeking authorization to

engage in sales for resale of electric energy

at market-based rates shall not be required to

demonstrate any lack of market power in

generation with respect to sales from capacity

first placed in service on or after June 10,

1996.122

However, this proposal would not

affect the Commission’s continuing

authority to look at whether an

applicant and its affiliates could erect

other barriers to entry and whether there

may be affiliate abuse or reciprocal

dealing.123

Comments

A number of commenters support the

Commission’s determination in

KCP&L 124 and several of them explicitly

support the Commission’s proposed

codification.125 EEI asserts that more

than 50 percent of new generation is

from non-utility sources and that recent

competitive solicitations for new

capacity have been greatly oversubscribed. Entergy argues that there is

no evidence in any proceeding thus far

of a market power problem in long-run

markets.

Other commenters, however, oppose

codifying KCP&L.126 They believe that

market power in long-run markets exists

for both new and old generation due to,

for example, constraints on interface

capabilities and unduly long notice

periods for replacement of purchases.

They argue that there is not enough of

a distinction between new and old

generation to treat them differently.

TDU Systems also notes that the

Commission in KCP&L did not take into

account the differences between firm

and non-firm bulk power. NIEP and

ELCON conclude that the Commission

erroneously found in KCP&L that no

wholesale seller of generation has

market power in generation from new

facilities. NIEP asserts that in each

service area there is usually only one

wholesale buyer—the utility—who also

is virtually always a wholesale seller of

generation. Under these circumstances,

NIEP argues that there cannot be arm’slength bargaining. Environmental

Action complains that the Commission’s

proposal to codify KCP&L ignores

significant factors that impede entry to

generation markets, such as utility

resistance to purchased power, state

government-created barriers to nonutility generation, pancaking of rates

under the contract path approach, sunk

investment, and scale economies.

Commission Conclusion

In reviewing applications to sell at

market-based rates, whether from new

(unbuilt) capacity or existing capacity,

we require that the seller (and each of

its affiliates) must not have, or must

have mitigated, market power in

generation and transmission and not

control other barriers to entry. In order

to demonstrate the requisite absence or

mitigation of transmission market

power, a transmission-owning public

utility seeking to sell at market-based

rates must have on file with the

Commission an open access

transmission tariff for the provision of

comparable service. In addition, the

Commission considers whether there is

evidence of affiliate abuse or reciprocal

dealing.127

In KCP&L, we stated that ‘‘in light of

industry and statutory changes which

allow ease of market entry, we therefore

will no longer require rate applicants to

submit evidence of generation

dominance in long-run bulk power

markets.’’ 128 We further explained that

we had examined ‘‘generation

dominance in many different cases over

the years’’ and had ‘‘yet to find an

instance of generation dominance in

long-run bulk power markets.’’ 129

Commenters have criticized our

findings in KCP&L, but no commenter

has provided any evidence of generation

dominance in long-run bulk power

markets. Moreover, we have seen no

such evidence in any of the marketbased rate cases we have considered

since KCP&L. Based on the comments

received, we will codify the

Commission’s determination in KCP&L

that the generation dominance standard

for market-based sales from new

capacity should be dropped. Because

the Commission’s findings in KCP&L

applied to long-run markets, we will

revise proposed § 35.27 to apply to sales

from capacity for which construction

has commenced on or after the effective

date of this Rule.130

The Commission wishes to clarify that

dropping the generation dominance

standard for new capacity does not

affect the demonstration that an

applicant must make in order to qualify

for market-based rates for sales from its

existing generating capacity. In other

words, the fact that an applicant need

not demonstrate its lack of generation

dominance with respect to new capacity

cannot be used to ‘‘bootstrap’’ the

authorization of market-based rates for

its existing capacity. Moreover, our

evaluation of market-based rates for

existing capacity will include

consideration of new capacity.

In addition, the fact that we are

codifying KCP&L does not mean that we

will ignore specific evidence presented

by an intervenor that a seller requesting

market-based rates for sales from new

generation nevertheless possesses

generation dominance. For example, if

the evidence indicated that the new

generator, due to its proximity to an

existing transmission constraint, could

significantly influence the ability to

move power across the constraint, we

would consider such evidence in

determining whether to grant the

applicant’s request.131 If such evidence

is presented, the Commission will

evaluate whether the evidence

disproves the premise that the seller

lacks generation dominance with

respect to its new capacity.

If the applicant has existing

generation, the sales from which are

authorized to be made on a market

basis, the Commission would consider

whether the new generation (when

added to the existing generation with

market-based authority) results in the

applicant having generation dominance.

On the other hand, if the applicant has

existing generation, the sales from

which are subject to cost-of-service

regulation, the Commission would not

include this generation in its analysis of

the applicant’s request for market-based

rates for its new generation. The

question of whether or not the applicant

lacks generation dominance with

respect to its existing capacity is

relevant only if, and when, the seller

applies to the Commission for authority

to make wholesale sales for its existing

capacity at market-based rates.

If evidence regarding an applicant’s

generation dominance with respect to
21554 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

132FERC Stats. & Regs. ¶ 32,514 at 33,093–94.

133E.g., EEI, CINergy, Central Illinois Public

Service, Citizens Utilities, Com Ed, Ohio Edison,

Allegheny, Southern, Portland, NRRI, Pennsylvania

P&L, PECO, Dayton P&L, Utilities For Improved

Transition, Centerior, Houston L&P, Duke, ConEd,

IPALCO, Salt River, PJM, NU, NYSEG, Oklahoma

G&E, PA Com, OK Com, CT DPUC, CA Com, MT

Com.

134E.g., Consumers Power, Portland, Dayton P&L,

CSW.

135See also Citizens Utilities.

136See also CSW, Industrial Energy Applications,

Public Service Co of CO, Coalition for Economic

Competition.

137E.g., NRECA, TDU Systems, MT Com, SMUD,

NEPCO, Orange & Rockland, El Paso, American

Forest & Paper, NIPSCO, AEC & SMEPA, OH Com,

IL Com, IN Com, Legal Environmental Assistance,

LG&E, Cajun, Industrial Energy Applications, LEPA,

MA DPU, MI Com, FTC, Minnesota P&L, SC Public

Service Authority, WP&L, NARUC, Canadian

Petroleum Producers, DOD, CCEM, Environmental

Action, American Wind, Cajun, NIEP, EGA, TAPS,

ELCON, Consolidated Natural Gas.

138See also NIEP, Pacificorp, CA Energy Com.

139See also MT Com, TDU Systems, Soyland.

140See also AEC & SMEPA, NIPSCO, El Paso

(discusses a particular transmission constraint that

it states limits its access to suppliers).

NRECA is also concerned that mergers may create

a handful of ‘‘mega-public utilities’’ that may affect

a regional generation market and that the

Commission should apply more traditional antitrust

principles in analyzing the impacts of mergers.

141LEPA Initial Comments Affidavit of William G.

Shepherd at 4.

its new capacity is submitted, the

applicant would be required to provide

a satisfactory rebuttal.

b. Market-Based Rates for Existing

Generation

In the NOPR, the Commission

explained that increased competition

resulting from open access transmission

may reduce or even eliminate

generation-related market power in the

short-run market (sales from existing

capacity).132 Because market power has

been the primary concern of the

Commission in analyzing requests for

market-based rates for such sales, we

sought comments on the effect of

industry-wide non-discriminatory open

access on our criteria for authorizing

power sales at market-based rates. The

Commission also sought comments on

whether the generation dominance

standard should be dropped for marketbased sales from existing capacity.

Comments

Many commenters support, but many

also oppose, market-based rates for

existing generation without a casespecific analysis of generation

dominance.

Supporting Market-Based Rates for

Existing Generation

Many commenters (primarily IOUs

and a number of state commissions)

assert that existing generators will not

possess market power after

implementation of non-discriminatory

open access transmission and that

market-based rates should be permitted

generically for sales from existing

generation.133

EEI asserts that market power

concerns generally would be transitory,

limited to the time needed to build new

facilities. Thus, it recommends that all

markets be declared competitive by a

date certain and that market-based rates

then be allowed, with customers

permitted to file complaints. Florida

Power Corp believes that existing

procedures under sections 205 and 206

will adequately protect consumers.

Other commenters also urge the

Commission to eliminate its generation

dominance standard, but assert that the

Commission should allow a showing of

market dominance in a complaint or

show cause proceeding.134 CT DPUC

notes that the Commission should be

able to rely on rules of conduct, market

mechanisms, and monitoring to curb

any market power that may exist.

Utilities For Improved Transition

argues that if utilities cannot get marketbased rates, the new players in the

market will have an unfair advantage,

since they do not have to carry the

traditional utilities’ burden of older, less

efficient plants.

Entergy proposes a screening test that

would permit the Commission to

‘‘deregulate’’ wholesale sales to certain

short-run markets. CINergy recommends

that after industry-wide open access

tariffs become effective, the Commission

adopt a rebuttable presumption that all

markets are workably competitive; that

presumption could be rebutted in a

section 206 proceeding.135

UtiliCorp, while it believes that

market power will probably be fully

mitigated by open access, also argues

that the Commission should examine

generation dominance on a region-byregion basis.136 Montana-Dakota

Utilities argues that the Commission

should allow all suppliers in a power

pool or RTG to have market-based rates

after a Commission finding that there is

sufficient generation competition within

the region.

Duke states that it would be highly

inconsistent for the Commission to

require open access, but not allow

utilities to compete in the market. It

further states that the relevant market

should be determined using standard

antitrust techniques; the Commission

should examine the options available to

customers and determine whether the

utility possesses monopoly power in a

relevant market.

Opposing Market-Based Rates for

Existing Generation

Many commenters are concerned that

even with open access tariffs certain

generators will be able to exercise

market dominance.137 For example,

NARUC argues that utilities retain

market power through their ownership

of existing generation and transmission

facilities, favorable long-term contracts

for fuel and other inputs, and access to

superior generation sites.138 NRECA

believes that the universe of generation

providers is still too narrow to assume

a competitive market and that other

factors, such as transmission constraints

and pancaking of rates, will inhibit the

development of competitive markets.139

FTC says that, although comparable

transmission access could broaden the

relevant geographic market for

generation, the Commission should not

assume that there will be no market

power. It says that the Commission must

continue to evaluate each case.140 TDU

Systems argues that the Commission

cannot move to market-based rates

without a Congressional determination

that deregulation of wholesale electric

rates should be implemented. It further

asserts that the Commission does not

have a factual basis for a reasoned

conclusion that regulated utilities do

not have market dominance—full open

access is only a goal at this time, and the

success of open access will depend

upon the transmission rate structures

the Commission approves.

LEPA raises concerns that the small

bulk power suppliers, QFs, cogenerators, EWGs, IPPs, and marketers

(who provide non-requirements power)

may not be able to bring competition to

the wholesale market. LEPA concludes

that ‘‘barriers will exist unless buyers

have full access to requirements power

itself, rather than just to the chance to

acquire the individual components of

requirements power.’’ 141 TDU Systems

raises concerns about the limited

number of generation providers and the

effect of possible future mergers. It also

argues that pancaked rates raise the cost

of transmission to third parties, thereby

restricting the geographic scope of

markets. As a result, TDU Systems

asserts that individual generators in

highly concentrated regions will still be

able to exert market power. OH Com

expresses concerns that restrictions on

siting of generation and transmission

will favor nearby generators. SC Public

Service Authority argues that if the

Commission allows utilities to recover

stranded costs their market power will

not be mitigated, since customers will
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21555

142See also DOD and WP&L. IL Com suggests that

the Commission allow market-based rates to a

utility on the condition that the utility forego

stranded cost recovery.

143NEPOOL Review Committee Initial Comments

at 28.

144See, e.g., Southwestern Public Service

Company, 72 FERC ¶ 61,208 at 61,996 (1995).

145The Commission’s practice is to define the

relevant markets as those utilities directly

interconnected to the applicant (first-tier markets).

For each first-tier market, we consider all utilities

interconnected to the first-tier utility and all

utilities interconnected to the applicant as

competitors in that relevant market. Thus, the

competitors include the second-tier utilities directly

interconnected to the relevant market and those

other first-tier utilities that can reach the market by

virtue of the applicant’s open access transmission

tariff. See, e.g., Kansas City Power & Light

Company, 67 FERC ¶ 61,183 at 61,556; and

Heartland Energy Services, Inc., 68 FERC ¶ 61,223

at 62,061.

146See Wisconsin Public Service Corporation, 75

FERC ¶ 61, lll, slip op. at 6–7 (1996).

147E.g., NRECA, TAPS, Wisconsin Coalition,

APPA.

148E.g., Wisconsin, Rosebud, NRECA, IN Com,

Wisconsin Coalition, NIEP, Minnesota P&L, APPA.

149See also APPA.

150E.g., Wisconsin Coalition, MMWEC.

151E.g., APPA, Wisconsin Coalition, Minnesota

P&L, IN Com.

have to pay exit fees to switch

suppliers.142

CCEM notes that in Order No. 636 gas

pipelines were not allowed marketbased rates for merchant sales until after

transmission had been completely

unbundled and non-discriminatory

open access had been fully

implemented.

DOE and DOJ assert that open access

should not be assumed to mitigate

market power sufficiently to justify

deregulation of existing generation—

structural changes, such as control of

the regional grid by an independent

entity, are required. DOE requests that

the Commission continue to look for

affiliate abuse when reviewing marketbased rates for new generation.

Similarly, EPA is concerned that even

with open access, individual generators

may still exert market power by their

domination of a particular geographic

market. It is also concerned that lowcost plants that are subject to weaker

environmental standards could have a

market advantage. NEPOOL Review

Committee requests that the

Commission not approve any market

prices ‘‘where the market into which the

seller proposes to sell is not effectively

competitive due to the absence of

regional transmission products and

prices.’’143

Commission Conclusion

While the Commission expects this

Rule to facilitate the development of

competitive bulk power markets, we

find that there is not enough evidence

on the record to make a generic

determination about whether market

power may exist for sales from existing

generation. We continue to have

concerns about how to define the

relevant markets and believe that a more

rigorous analysis is needed than can be

achieved with the limited market data

that is now available. We will continue

our case-by-case approach that allows

market-based rates based on an analysis

of generation market power in first tier

and second tier markets.144 In particular

cases, however, the effect of the

mandatory open access prescribed by

this Final Rule may lead to the

consideration of geographic markets for

the applicant’s generation products that

are broader in scope than the first-tier

and second-tier markets currently

considered.145 By the same token, in

some cases, evidence of the effects of

transmission constraints may

circumscribe the scope of the relevant

geographic market for the applicant’s

generation products.

While we will continue to apply the

first-tier/second-tier analysis, we will

allow applicants and intervenors to

challenge the presumption implicit in

the Commission’s practice that the

relevant geographic market is bounded

by the second-tier utilities. Thus, for

instance, applicants may present

evidence that the relevant market is in

fact broader than the first or second tier.

In support of such a contention, an

applicant would need to show more

than the existence of open access. For

example, an applicant might attempt to

demonstrate the lack of significant

transmission constraints in the more

broadly defined market and that

cumulative transmission rates would

not significantly affect the ability of

more distant suppliers to compete in the

relevant market. Similarly, an

intervenor may present evidence that,

due to the existence of significant

transmission constraints within the

first- and second-tier markets, the

relevant market is in fact more limited

in scope.146

Finally, we will maintain our current

practice of allowing market-based rates

for existing generation to go into effect

subject to refund. To the extent that

either the applicant or intervenors in

individual cases offer specific evidence

that the relevant geographic market

ought to be defined differently than

under the existing test, we will examine

such arguments through formal or paper

hearings.

Because our goal is to develop more

competitive bulk power markets, we

will continue to monitor markets to

assess the competitiveness of the market

in existing generation, and we will

modify our market rate criteria if and

when appropriate. However, any

changes we might make to our analysis

for authorizing market-based rates in the

future will not upset transactions

entered into pursuant to existing

market-based rate authority. The

policies we put in place today to

develop a smoothly functioning

transmission access regime will provide

useful experience and information for

assessing the effects of generation

concentration.

4. Merger Policy

In the NOPR, the Commission did not

address possible ramifications of the

NOPR with regard to its existing merger

policy.

Comments

A number of commenters suggest that

the Commission should reevaluate its

merger policy in light of the NOPR.147

They further suggest a number of

changes that they believe need to be

made to the Commission’s existing

merger policy.

Most commenters raising this issue

express concerns that mergers will

lessen competition and hinder

achievement of competitive bulk power

markets.148 For example, NRECA

indicates that the Commission’s merger

policy is at a crossroads. It believes that

it is essential for the Commission to

reevaluate its merger policy in concert

with the proposed rulemakings.149

Similarly, TAPS recommends that the

Commission reevaluate its merger

criteria to ensure that in a more

competitive era, mergers are found to be

consistent with the public interest only

if they are pro-competitive. Several

commenters argue that the Commission

should continue to conduct a case-bycase investigation of the product and

geographic markets that will be affected

by a proposed merger.150

A number of commenters also suggest

certain changes that they would like to

see in the Commission’s merger

policy.151 APPA recommends that, at a

minimum, all merger approvals

considered by the Commission should

be conditioned on: (1) Filing an open

access transmission tariff, (2)

demonstrating no market power in

generation or ancillary services, and (3)

granting all existing requirements

customers of the merged entity the right

to convert existing contracts to rights to

equivalent transmission capacity.

Several commenters suggest adopting

the U.S. Department of Justice Merger
21556 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

152E.g., Wisconsin Coalition.

153E.g., TAPS, Wisconsin Coalition.

154E.g., NIEP, Wisconsin Coalition, TAPS,

Environmental Action.

155FERC Stats. & Regs. ¶ 35,531 (1996).

156Our decision to review our merger policy in

a separate NOI proceeding is not intended to affect

a utility’s business decision of whether a merger

may be in the economic interest of its ratepayers

and stockholders. The NOI proceeding will not

prevent us from reviewing merger applications in

as timely a manner as possible.

157FERC Stats. & Regs. ¶ 32,514 at 33,093.

158E.g., Dayton P&L, NSP, Montaup,

Southwestern, Ohio Edison, Consumers Power,

Allegheny, Public Generating Pool, NEPCO,

Pennsylvania P&L, Southwest TDU Group, Arizona,

DOD, El Paso, Florida Power Corp, AEC & SMEPA,

Atlantic City, Texaco, Tampa, CSW, Central Illinois

Public Service, CA Cogen, ConEd, GA Com,

Consolidated Natural Gas, Ohio Valley, Pacific

Northwest Coop, Salt River, Oglethorpe, Minnesota

P&L, NYSEG, Brazos, Southern, Washington Water

Power, CINergy, SoCal Edison, Hoosier EC.

159E.g., AEC & SMEPA, Cajun, Carolina P&L,

NSP, Pennsylvania P&L, UNITIL, Southwestern,

CSW.

160See also Dairyland, DE Muni, Arkansas Cities,

Ohio Valley.

161E.g., AEP, Associated EC, DOD, El Paso,

NEPCO, Ohio Edison, PSNM, Southwest TDU

Group, Utilities For Improved Transition, NYSEG,

Citizens Utilities, NM Com, EGA. See also NRECA,

TDU Systems, Blue Ridge, CCEM, Industrial Energy

Applications, APPA, Cajun, Springfield, DE Muni,

Missouri Basin MPA, TANC, Wolverine Coop

Members, FL Com, Citizens Utilities, Soyland

(support contract abrogation on a case-by-case

basis).

162E.g., Utilities For Improved Transition, NSP,

Southwestern, DE Muni.

163E.g., NRECA, CCEM, ELCON, DE Muni,

Oglethorpe. Portland maintains that it would be in

the public interest to abrogate existing contracts

completely, but recommends that such action be

taken only on a case-by-case basis.

164See also VT DPS, NYMEX.

165See also VT DPS, Portland.

166CCEM Initial Comments at 26. See also

ELCON, VT DPS, Blue Ridge, NYMEX, OK Com,

Missouri Basin MPA, Texas-New Mexico, TDU

Systems.

167See also TDU Systems, Texas-New Mexico,

TAPS, Wisconsin Municipals.

168See also NorAm. UtiliCorp argues that existing

contracts should not be allowed to extend

indefinitely (as through ‘‘evergreen’’ clauses)

without adopting comparability. See also Texaco,

Wisconsin Municipals, Phelps Dodge.

Guidelines in analyzing merger

proposals.152

Environmental Action and others

contend that merging utilities must be

required to demonstrate real net benefits

to retail and wholesale customers that

could not otherwise be achieved but for

the proposed merger.153

Commenters also argue that the

Commission should use its merger

conditioning authority to order

divestiture of transmission and

generation when required to ensure

competition.154 Environmental Action

and NEPOOL Review Committee

suggest conditioning merger

applications on the existence of regional

transmission pricing arrangements to

mitigate any generation market power

gained by the merging entities.

Commission Conclusion

The Commission appreciates the

concerns and suggestions raised with

respect to our merger policy. However,

since the time the NOPR was issued

(and comments received thereon), we

issued a Notice of Inquiry on the

Commission’s merger policy in Docket

No. RM96–6–000.155 There we indicated

that we will review whether our criteria

and policies for evaluating mergers need

to be modified in light of the changing

circumstances, including this final rule,

that are occurring in the electric

industry. The NOI proceeding will

permit us to consider comments from all

interested participants and, at the same

time, allow us to review our merger

criteria and policies in light of this final

rule. We are committed to reviewing our

merger policy in a timely manner in the

ongoing NOI proceeding.156

5. Contract Reform

In the NOPR, the Commission

explained that it believed that it could

remedy unduly discriminatory practices

and achieve more competitive bulk

power markets without abrogating

existing wholesale power supply

contracts that bundle generation and

transmission services and existing

wholesale transmission contracts.157

Thus, we proposed to apply the

functional unbundling requirement only

to transmission services under new

requirements contracts, new

coordination contracts, and new

transactions under existing coordination

contracts. However, the Commission did

invite comment on whether it would be

contrary to the public interest to allow

all or some of the above types of existing

contracts to remain in effect.

Comments

Requirements and Transmission

Contracts

Many of the commenters (including

utility customers and third-party power

suppliers) addressing this issue oppose

abrogating existing contracts on a

generic basis.158 A number of the

commenters contend that existing

contracts should be retained because

they are the result of mutually beneficial

bargaining.159 SMUD and TANC are

concerned that existing contracts

providing for transmission service that

is superior to the pro forma tariffs not

be abrogated.160 Ohio Edison argues that

existing contracts have contributed to

the emergence of competition, meet the

specific needs of the parties, have been

approved by the Commission, and have

not been found to be unduly

discriminatory or violative of the public

interest, and that their preservation is

consistent with the Energy Policy Act,

most notably amended section 211 of

the FPA. PacifiCorp and AEP express

concern that contract abrogation would

create competitive instability. American

Forest & Paper argues that the

Commission cannot refuse to honor

existing contracts if it expects a

competitive bulk power market to

emerge.

Numerous commenters further argue

that contract abrogation requires a factbased, contract-specific evaluation, and

they oppose any generic declaration that

existing contracts are contrary to the

public interest.161 Some suggest that

generic contract abrogation cannot be

justified under the public interest

standard.162

Missouri Basin MPA argues that the

Commission should allow abrogation of

existing wholesale power and

transmission arrangements if the

customer can demonstrate the undue

competitive disadvantage caused by the

arrangement.

A few commenters support some form

of generic contract abrogation.163 CCEM

asserts that existing wholesale

requirements customers must be given

the right to convert to transmission

service under non-discriminatory open

access tariffs.164 CCEM notes that this is

the same relief from undue

discrimination that the Commission

afforded to pipeline customers in Order

Nos. 436 and 500.165 CCEM emphasizes

that here, in contrast to what occurred

in the gas industry, ‘‘[c]onversion rights

should be understood as the logical quid

pro quo for introducing extracontractual stranded-cost recovery

rights into the wholesale requirements

contracts of electric utilities.’’ 166

NRECA asserts that it would be unduly

discriminatory to allow new

transmission customers to use the open

access transmission tariffs, but not allow

existing customers the same access.167

TAPS says that if those who now have

discriminatory contracts are forced to

live with those contracts, a fully

competitive market will be delayed

considerably.168 Moreover, TAPS

argues, the Commission has a statutory

duty to remedy the undue

discrimination that it is only now

recognizing. Even if the Commission

will not abrogate these contracts across

the board, TAPS asserts that we should

use our section 206 authority to do so

on a contract-by-contract basis.

San Francisco requests that the

Commission clarify that a holder of

capacity rights under an existing
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21557

169See also Industrial Energy Applications.

170E.g., Con Ed, Detroit Edison, IL Com.

171See also Utility Workers Union, VEPCO.

172See Pierce, Richard J., Reconstituting the

Natural Gas Industry from Wellhead to Burnertip,

9 Energy L.J. 1 (1988).

173 In addition, we do not believe that unfavorable

requirements contracts will derail the attainment of

competitive wholesale power markets. Indeed,

many of the commenters support this position and

seek to retain their existing requirements contracts.

174This is consistent with the definition of

existing requirements contracts we have used for

purposes of stranded cost recovery.

175See Section IV.J.5.

contract can extend contractual rights to

transmission access at least coterminous

with the life of the project and under a

roll-over or renewal contract on the

same basis as provided in the existing

contract. Anoka EC proposes that when

a wholesale purchaser’s contract

expires, it should have a right of first

refusal to contract for the transmission

capacity to which it previously had a

right. Knoxville urges the Commission

to require renegotiation of the notice

and/or term of all existing contracts for

which the voluntary termination period

exceeds the time frame for

implementation of the final rule.

NEPCO suggests that we require

existing power contracts that allow rate

changes to be separated into their

generation and transmission

components, without otherwise

disturbing their terms; this would allow

comparisons between the transmission

service the utility provides to its power

customers and the service it offers to

others.169

Coordination Agreements

CINergy argues that coordination

agreements should not be excluded from

the comparability standard and that the

Commission should use its authority

under section 206 to require

amendments to such agreements, just as

it did in Order 636 in requiring

unbundling of pipeline supply

contracts. CINergy suggests that public

utilities should be given up to three

years to file the amendments to avoid

hardship on the industry and the

Commission’s staff. CINergy further

asserts that future transactions

conducted under coordination

agreements should be unbundled and

the transmission component subjected

to the comparable transmission service

requirement.

Others argue that purchases under

existing coordination agreements made

on behalf of retail native load should

not be unbundled.170 NY Com and IL

Com recommend that proposed

§ 35.28(c) be modified to state that the

functional unbundling requirement

‘‘exclude(s) those wholesale purchases

made by the utility to serve existing or

expected native retail load.’’

Utilities For Improved Transition

disagrees with the idea that new

transactions under existing coordination

agreements should be subject to the

rule.171 It argues that the sanctity of

coordination contracts should be the

same as for other contracts.

Coordination contracts are not simply

agreements to agree in the future,

according to Utilities For Improved

Transition; they set forth terms and rates

and merely leave the timing of

transactions to be resolved in the future.

Moreover, it argues that the Commission

has given no reason to abandon its

practice of encouraging coordination

sales by allowing price flexibility.

Commission Conclusion

Requirements and Transmission

Contracts

We do not believe it is appropriate to

order generic abrogation of existing

requirements and transmission

contracts. While the Commission did

generically find it appropriate to modify

natural gas contracts to complete the

move to a competitive commodity

market in natural gas, we face a different

situation here. At the time the

Commission addressed this situation in

the natural gas industry, it was faced

with shrinking natural gas markets,

statutory escalations in natural gas

ceiling prices under the Natural Gas

Policy Act, and increased production of

gas.172 In other words, there was a

market failure in the industry that

required the extraordinary measure of

generically allowing all customers to

break their contracts with pipelines.

In contrast, there is no such market

failure in the electric industry. Although

changes in the industry have been and

continue to be dramatic, we do not

believe they compel generic abrogation

of requirements and transmission

contracts.173

While we have concluded that current

conditions in the wholesale power

market do not warrant the generic

modification of requirements contracts,

we conclude nonetheless that the

modification of certain requirements

contracts on a case-by-case basis may be

appropriate. We conclude further that,

even if customers under such contracts

are bound by so-called Mobile-Sierra

clauses, they nonetheless ought to have

the opportunity to demonstrate that

their contracts no longer are just and

reasonable.

The Commission finds that it would

be against the public interest to permit

a Mobile-Sierra clause in an existing

wholesale requirements contract to

preclude the parties to such a contract

from the opportunity to realize the

benefits of the competitive wholesale

power markets. For purposes of this

finding, the Commission defines

existing requirements contracts as

contracts executed on or before July 11,

1994.174 By operation of this finding, a

party to a requirements contract

containing a Mobile-Sierra clause no

longer will have the burden of

establishing independently that it is in

the public interest to permit the

modification of such contract. The

party, however, still will have the

burden of establishing that such

contract no longer is just and reasonable

and therefore ought to be modified.

This finding complements the

Commission’s finding that,

notwithstanding a Mobile-Sierra clause

in an existing requirements contract, it

is in the public interest to permit

amendments to add stranded cost

provisions to such contracts if the

public utility proposing the amendment

can meet the evidentiary requirements

of this Rule.175 The Commission’s

complementary Mobile-Sierra findings

are not mutually exclusive. Any

contract modification approved under

this Section shall provide for the

utility’s recovery of any costs stranded

consistent with the contract

modification. The stranded costs must

be prudently incurred, legitimate and

verifiable, as provided in Section IV.J.

Further, the Commission has concluded

that if a customer is permitted to argue

for modification of existing contracts

that are less favorable to it than other

generation alternatives, then the utility

should be able to seek modification of

contracts that may be beneficial to the

customer.

The Commission believes that the

most productive way to analyze contract

modification issues is to consider

simultaneously both the selling public

utility’s claims, if any, that it had a

reasonable expectation of continuing to

serve the customer beyond the term of

the contract and the customer’s claim, if

any, that the contract no longer is just

and reasonable and therefore ought to be

modified. Thus, if the selling public

utility intends to claim stranded costs,

it must present that claim in any section

206 proceeding brought by the customer

to shorten or terminate the contract.

Similarly, if the customer intends to

claim that the notice or termination

provision of its existing requirements

contract is unjust and unreasonable, it

must present that claim in any

proceeding brought by the selling public

utility to seek recovery of stranded
21558 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

176This right of first refusal exists whether or not

the customer buys power from the historical utility

supplier or another power supplier. If the customer

chooses a new power supplier and this

substantially changes the location or direction of its

power flows, the customer’s right to continue taking

transmission service from its existing transmission

provider may be affected by transmission

constraints associated with the change.

177The above discussion on a right of first refusal

addresses firm contract customers. However, the

same logic applies to retail customers.

178For purposes of this discussion, we define

coordination agreements as all power sales

agreements, except requirements service

agreements. In addition, for purposes of

implementing the non-discriminatory, open access

requirements of the Final Rule, we are dividing

bilateral coordination agreements into two general

categories: (1) Economy energy coordination

agreements are contracts and service schedules

thereunder that provide for trading of electric

energy on an ‘‘if, as, and when available’’ basis, but

do not require either the seller or buyer to engage

in a particular transaction; and (2) non-economy

energy coordination agreements are any nonrequirements service agreements, except economy

energy coordination agreements.

179The requirements for power pools and other

multilateral arrangements are discussed in detail in

Section IV.F.

180Those executed prior to 60 days after

publication of the Open Access Rule in the Federal

Register.

181The requirement to unbundle future

transactions under existing economy energy

coordination agreements means that if the

transmission owner uses its transmission system to

make economy energy coordination sales or

purchases, it must take service for these

transactions under its own transmission tariff after

December 31, 1996.

182Those executed 60 days after publication of

the Open Access Rule in the Federal Register.

183Accordingly, transmission service needed for

sales or purchases under all new economy energy

coordination agreements will be pursuant to the

Final Rule pro forma tariff.

costs. This will promote administrative

efficiency and will permit the

Commission to consider how the

contracting parties’ claims bear on one

another.

The Commission does not take

contract modification lightly. Whether a

utility is seeking a contract amendment

to permit stranded cost recovery based

on expectations beyond the stated term

of the contract, or a customer is seeking

to shorten or eliminate the term of an

existing contract, we believe that each

has a heavy burden in demonstrating

that the contract ought to be modified.

Still, we believe that given the industry

circumstances now facing us, both

selling utilities and their customers

ought to have an opportunity to make

the case that their existing requirements

contracts ought to be modified. By

providing both buyers and sellers this

opportunity, the Commission attempts

to strike a reasonable balance of the

interests of all market participants. The

Commission expects that many of the

arguments presented by buyers and

sellers in such proceedings will be fact

specific.

We note that because we are not

abrogating existing requirements and

transmission contracts generically and

because the functional unbundling

requirement of the Final Rule applies

only to new wholesale services, the

terms and conditions of the Final Rule

pro forma tariff do not apply to service

under existing requirements contracts.

However, if a customer’s existing

bundled service (transmission and

generation) contract or transmissiononly contract expires, and the customer

takes any new transmission service from

its former supplier, the terms and

conditions of the Final Rule tariff would

then apply to the transmission service

that the customer receives.

A further issue concerning firm

contract customers is their right to

transmission capacity (and the rate for

such capacity) when their contracts

expire by their own terms or become

subject to renewal or rollover. We have

concluded that all firm transmission

customers (requirements and

transmission-only), upon the expiration

of their contracts or at the time their

contracts become subject to renewal or

rollover, should have the right to

continue to take transmission service

from their existing transmission

provider. The limitations are that the

underlying contract must have been for

a term of one-year or more and the

existing customer must agree to match

the rate offered by another potential

customer, up to the transmission

provider’s maximum filed transmission

rate at that time, and to accept a contract

term at least as long as that offered by

the potential customer.176 This means

that there is no right to grandfather the

historical price of the transmission

service. Thus, if not enough capacity is

available to meet all requests for service,

the right of first refusal gives the

capacity to the existing customer who

had contractually been using the

capacity on a long-term, firm basis,

assuming that it meets the conditions

set forth above. Moreover, this limited

right of first refusal is not a one-time

right of first refusal for contracts

existing as of the date of the final rule,

but is an ongoing right that may be

exercised at the end of all firm contract

(including all future unbundled

transmission contracts) terms. A

customer converting existing bundled

service to the Final Rule pro forma tariff

would not have a reservation priority for

capacity expansions, unless the existing

contract provides for future

transmission to the customer that

requires capacity expansion.177

Finally, with respect to all existing

requirements contracts and tariffs that

provide for bundled rates, we will

require all public utilities to make

informational filings setting forth the

unbundled power and transmission

rates reflected in those contracts and

tariffs. These informational rates must

be submitted to the Commission within

60 days of publication of the Final Rule

in the Federal Register and must also be

included as a line item on all bills

submitted to wholesale customers in the

third month following the effective date

of this final rule. The unbundled

informational rates will permit

wholesale customers to compare rates in

anticipation of their contracts expiring

so that they can evaluate alternative

contracts.

Coordination Agreements

The situation as to coordination

agreements requires a slightly different

approach.178 While we also believe that

as a general matter it is important not to

generically abrogate any coordination

agreements, this is particularly true for

non-economy energy coordination

agreements that may reflect

complementary long-term obligations

among the parties. This type of

agreement presents special problems

and, as discussed below, we will not

generically require this type of

coordination agreement to be

modified.179

Hundreds of coordination agreements

exist in the industry today. Many are

open-ended agreements that permit new

transactions to occur well into the

future. Because these contracts may not

expire of their own terms in a

reasonable time, they may present a

larger and more enduring obstacle to

non-discriminatory open access and

more competitive bulk power markets.

Thus, to assure that non-discriminatory

open access becomes a reality in the

relatively near future, we will partially

modify existing economy energy

coordination agreements. We will

condition future sales and purchase

transactions under existing economy

energy coordination agreements 180 to

require that the transmission service

associated with those transactions be

provided pursuant to this Rule’s

requirements of non-discriminatory

open access, no later than December 31,

1996.181 We also will require that for

new economy energy coordination

agreements 182 where the transmission

owner uses its transmission system to

make economy energy sales or

purchases, the transmission owner must

take such service under its own

transmission tariff as of the date trading

begins under the agreement.183
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21559

184A contract path is simply a path that can be

designated to form a single continuous electrical

path between the parties to an agreement. Because

of the laws of physics, it is unlikely that the actual

power flow will follow that contract path.

185Flow-based pricing or contracting would be

designed to account for the actual power flows on

a transmission system. It would take into account

the ‘‘unscheduled flows’’ that occur under a

contract path regime.

186E.g., APPA, TAPS, NY Energy Buyers, Arcadia,

Brownsville, Detroit Edison Customers, AMP-Ohio,

Michigan Systems.

187E.g., AMP-Ohio, NRECA, APPA, Detroit

Edison Wholesale Customers, MMWEC, Missouri

Basin MPA, Air Liquide, American Wind Energy,

Associated Power, CCEM.

188Some commenters propose the development of

a regional rate on a postage stamp basis, without

regard to distance travelled or the actual path of

power flows. E.g., Air Liquide, American National

Power, CA Energy Co. Several commenters do,

however, propose ways to account for unscheduled

flows. E.g., American Forest & Paper, DE Muni,

Lower Colorado River Authority.

189E.g., CSW, EDS Utilities, Dominion, CINergy,

KS Com, CT DPUC, Com Ed, Hogan.

190NYMEX favors contract path pricing because

of its familiarity and believes that the issue should

primarily be resolved by the transmitting utilities.

AEP believes that the primary responsibility lies

with industry to develop alternative pricing

structures.

191E.g., NU, NEPCO, BECO, Florida Power Corp. 192See FERC Stats. & Regs. ¶ 31,005.

Finally, we will treat non-economy

energy coordination agreements

differently. We will not require their

modification. However, this does not

insulate such agreements from

complaints that transmission service

provided under such agreements be

provided pursuant to the Final Rule pro

forma tariff.

With respect to coordination pricing

practices, we conclude that nondiscriminatory open access consistent

with the requirements of this Rule is

necessary if we are to allow utilities to

continue to use market-driven pricing,

such as split-the-savings pricing, for

coordination sales. Absent such nondiscriminatory open access, a utility

would be able to deny access to others

so as to obtain a higher price for its own

power sales.

6. Flow-Based Contracting and Pricing

In the NOPR, the Commission

discussed the procedures to be used in

establishing Stage One rates. These

Stage One rates were proposed as an

administrative convenience. The

proposal merely followed the longestablished practice of establishing rates

on the basis of contract path pricing.184

The Commission made no

determination with respect to the

appropriateness of flow-based pricing or

contracting for other purposes.185

Comments

Most of the commenters addressing

this issue recommend that industry or

the Commission—either in this rule or

ultimately—dispense with the

traditional contract path basis for

pricing and contracting. Most

commenters also recommend that the

Commission adopt or encourage a

regional approach to the solution of

transmission pricing problems, though

they differ markedly in how to account

for flows.186

Transmission customers generally

seek to rid themselves of ‘‘pancaked’’

transmission rates that are associated

with the traditional approach to

transmission pricing.187 They propose

the development of regionwide

transmission rates, perhaps determined

on a pool or RTG basis. Most, however,

do not discuss how to account for

unscheduled flows.188

Many transmission providers, some

regulatory authorities, and some

individuals strongly support flow-based

pricing. Most of these commenters

recognize a need for a regional approach

to resolve transmission pricing

concerns.189 However, many of them

also appear to accept contract pricing in

the near term because of the need to

implement open access quickly.190

NERC recommends that the Commission

maintain an open position on the

transfer scheduling process and

supports changes in the process to

reflect actual power flows. EEI suggests

that the Commission should be willing

to deviate from a contract path

approach, since competition may be

accompanied by greater unscheduled

flows and contract pricing is not well

equipped to deal with such flows.

However, EEI concludes that a single

approach to pricing will not be

appropriate for all systems.

Other commenters, however, do raise

concerns with respect to flow-based

pricing. AEC & SMEPA considers flowbased pricing to be flawed because that

method makes an individual customer

responsible for load flow effects caused

by a third party’s development of the

third-party’s transmission system over

which the customer and its transmission

provider had no control. Dayton P&L

fears that competition would be

lessened under flow-based pricing

because utilities with large transmission

systems would dominate the market.

Several commenters oppose

Southern’s and United Illuminating’s

flow-based proposals, arguing that the

methodologies are based on estimates of

actual flows or a set of conditions with

limited applicability. Various

commenters also believe that a single

rate is flawed and could cause just as

many problems as contract path

pricing.191

Most commenters appear to believe

that the Commission endorsed contract

path pricing in the NOPR. Hogan

expresses concern that many industry

participants’ understanding of the pro

forma tariffs is based on the fiction of

the contract path. The MT Dept of

Environmental Quality believes that

despite the Commission’s pledge to

consider innovative pricing

proposals,192 such proposals will

receive heavy scrutiny, while

conventional contract path pricing

proposals will receive nearly automatic

approval. Dominion is concerned that

relying on the initiative of individual

transmission owners to develop flowbased pricing will yield slow and

patchy results.

Commission Conclusion

We will not, at this time, require that

flow-based pricing and contracting be

used in the electric industry. In reaching

this conclusion, we recognize that there

may be difficulties in using a traditional

contract path approach in a nondiscriminatory open access transmission

environment, as described by Hogan

and others. At the same time, however,

contract path pricing and contracting is

the longstanding approach used in the

electric industry and it is the approach

familiar to all participants in the

industry. To require now a dramatic

overhaul of the traditional approach—

such as a shift to some form of flowbased pricing and contracting—could

severely slow, if not derailed for some

time, the move to open access and more

competitive wholesale bulk power

markets. In addition, we believe it is

premature for the Commission to

impose generically a new pricing regime

without the benefit of any experience

with such pricing. We welcome new

and innovative proposals, but we will

not impose them in this Rule.

While we are not requiring the use of

any form of flow-based pricing, we

recognize that some versions of flowbased pricing could have benefits. For

example, some versions of flow-based

pricing could more accurately reflect

and price the actual power flows on

transmission systems and thus could

produce efficiency gains, better

generation siting decisions, and benefits

for customers and utilities alike. Other

versions could more accurately assign

capacity rights in accordance with a

party’s contribution to capacity costs.

These potential benefits, however,

will not simply come about in the

abstract. Flow-based pricing

methodologies that will achieve the

benefits sought by most of the
21560 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

193Associated Gas Distributors v. FERC, 824 F.2d

981, 998 (D.C. Cir. 1987), cert. denied, 485 U.S.

1006 (1988) (AGD).

194We use the term ‘‘open access’’ to refer to a

public utility’s obligation to put a tariff on file

offering service to eligible customers. Access is not

open to all. Specifically, the tariff is not an offer to

serve retail customers if state law does not permit

retail wheeling.

195 Gulf States Utilities Company v. FPC, 411 U.S.

747, 758–59 (1973).

196 In most situations, discrimination that

precludes transmission access or gives inferior

access will have at least potential anticompetitive

effects because it limits access to generation

markets and thereby limits competition in

generation. Similarly, it is probable that any

transmission provision that has anticompetitive

effects would also be found to be unduly

discriminatory or preferential because the

anticompetitive provision would most likely favor

the transmission owner vis-a-vis others.

197Order No. 436, Regulation of Natural Gas

Pipelines After Partial Wellhead Decontrol, FERC

Stats. & Regs., Regulations Preambles ¶ 30,665

(1985).

198AGD, supra, 824 F.2d at 997.

participants in the industry are in a

development stage and require further

work and refinement to address some of

the difficulties associated with flowbased approaches. Concurrent work on

OASIS and resolving available

transmission capability issues may help

resolve flow-based issues. However, as

demonstrated by the paucity of possible

methodologies presented in the

comments, developing workable

methodologies will be difficult. As we

explained in our Transmission Pricing

Policy Statement, we are receptive to

proposals for alternative rate

methodologies, such as distancesensitive and flow-based pricing, as long

as the proposals are well supported.

However, we have yet to receive a

formal rate application for a flow-based

pricing methodology that has been

tested enough that it can be required on

a generic basis. Thus, we have decided

to go forward to achieve open access

and more competitive wholesale bulk

power markets without waiting for the

development of a generic flow-based

pricing methodology.

We wish to emphasize further that in

taking this approach we are not

endorsing the traditional contract path

approach as the only available

approach. We continue to approve

contract path pricing because it is the

long-established pricing method that

comes to us in rate filings by the electric

industry, is administratively convenient

and feasible, and thus is a practical way

to move forward now. We remain open

to alternative methodologies, but need

to see better developed approaches from

the industry before we can consider

generic adoption of alternative pricing.

We also believe the adoption of flowbased pricing will be more practical on

a regional, instead of individual utility,

basis. Some forms of flow-based pricing

may even require a regional approach.

To this extent, regional ISOs could be a

valuable mechanism for implementing

such pricing reforms.

B. Legal Authority

The Commission reaffirms its

conclusion in the NOPR that we have

the authority under the FPA to order

wholesale transmission services in

interstate commerce to remedy undue

discrimination by public utilities. We

analyze below the relevant cases

examining our wheeling authority, then

discuss and respond to the legal

arguments raised by the commenters.

1. Bases for Legal Authority

a. Undue Discrimination/

Anticompetitive Effects

In upholding the Commission’s order

requiring non-discriminatory open

access in the natural gas industry, the

court in Associated Gas Distributors v.

FERC stated that the Natural Gas Act

‘‘fairly bristles’’ with concern for undue

discrimination.193 The same is true of

the FPA. The Commission has a

mandate under sections 205 and 206 of

the FPA to ensure that, with respect to

any transmission in interstate commerce

or any sale of electric energy for resale

in interstate commerce by a public

utility, no person is subject to any

undue prejudice or disadvantage. We

must determine whether any rule,

regulation, practice or contract affecting

rates for such transmission or sale for

resale is unduly discriminatory or

preferential, and must prevent those

contracts and practices that do not meet

this standard. As discussed below, AGD

demonstrates that our remedial power is

very broad and includes the ability to

order industry-wide non-discriminatory

open access 194 as a remedy for undue

discrimination. The AGD court reached

this decision even in the face of prior

cases that acknowledged that Congress

did not mandate common carriage or

explicitly empower the Commission to

order direct access for either gas

transporters or electric utilities.

Moreover, the Commission’s power

under the FPA ‘‘clearly carries with it

the responsibility to consider, in

appropriate circumstances, the

anticompetitive effects of regulated

aspects of interstate utility operations

pursuant to (FPA) sections 202 and 203,

and under like directives contained in

sections 205, 206, and 207.’’ 195

Therefore, based on the mandates of

sections 205 and 206 of the FPA and the

case law interpreting the Commission’s

authority over transmission in interstate

commerce, we conclude that we have

ample legal authority—indeed, a

responsibility—under section 206 of the

FPA to order the filing of nondiscriminatory open access transmission

tariffs if we find such order necessary as

a remedy for undue discrimination or

anticompetitive effects.196 We discuss

below the primary court decisions that

touch on our wheeling authority under

sections 205 and 206.

The Commission’s authority to order

access as a remedy for undue

discrimination under the Natural Gas

Act (NGA) was upheld and discussed in

detail in AGD. In AGD, the court upheld

in relevant part the Commission’s Order

No. 436.197 That order found the

prevailing natural gas company

practices to be ‘‘unduly discriminatory’’

within the meaning of section 5 of the

NGA (the parallel to section 206 of the

FPA) and held that if pipelines wanted

blanket certification for their

transportation services, they must

commit to transport gas for others on a

non-discriminatory basis; in other

words, they must provide nondiscriminatory open access.

In upholding the Commission’s

authority to require open access, the

court first noted that the opponents’

arguments against such authority must

proceed ‘‘uphill.’’ The statute contains

no language forbidding the Commission

to impose common carrier status on

pipelines, let alone forbidding the

Commission to impose ‘‘a specific duty

that happens to be a typical or even core

component of such status.’’ The court

found that the legislative history cited

by the opponents came nowhere near

overcoming this statutory silence.

Rather, the legislative history supported

only the proposition that Congress itself

declined to impose common carrier

status.198 Emphasizing Congress’ deep

concern with undue discrimination, the

court found that the Commission had

ample authority to ‘‘stamp out’’ such

discrimination:

The issue seems to come down to this:

Although Congress explicitly gave the

Commission the power and the duty to

achieve one of the prime goals of common

carriage regulation (the eradication of undue

discrimination), the Commission’s attempted

exercise of that power is invalid because

Congress in 1906 and 1914 and 1935 and

1938 itself refrained from affixing common

carrier status directly onto the pipelines and

from authorizing the Commission to do so.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21561

199 Id. at 998.

200 410 U.S. 366 (1974).

201 410 U.S. at 375–76.

202 Id. at 374–76.

203See AGD, 824 F.2d at 998.

204 574 F.2d 610 (D.C. Cir. 1978).

205 Id. at 620.

206 Id. at 623, nn.53 and 57.

207 606 F.2d 1156 (D.C. Cir. 1979).

208While Central Iowa was pending, certain of the

functions of the FPC were transferred to the FERC

under the DOE Organization Act. Accordingly, the

FERC was substituted for the FPC as the respondent

in the case.

209 606 F.2d at 1168.

210 Id. at 1169; see also Municipalities of Groton

v. FERC, 587 F.2d 1296 (D.C. Cir. 1978).

And this proposition is said to control no

matter how sound the Order may be as a

response to the facts before the Commission.

We think this turns statutory construction

upside down, letting the failure to grant a

general power prevail over the affirmative

grant of a specific one.199

The AGD court found that court

decisions under the FPA did not

support the view that the Commission’s

authority to ‘‘stamp out’’ undue

discrimination is hamstrung by an

inability to require non-discriminatory

open access as a remedy. These

decisions are discussed below.

One of the earliest cases on wheeling

is Otter Tail Power Company v. United

States (Otter Tail).200 In that case, the

Supreme Court rejected the argument

that the District Court, in a civil

antitrust suit, could not order wheeling

because to do so would conflict with the

FPC’s purported wheeling authority.201

The Court explained that Congress had

decided not to impose a common carrier

obligation on the electric power

industry and noted that the Commission

was not at that time expressly granted

power to order wheeling.202 In effect, it

concluded that because Congress did

not include common carrier provisions

in the FPA, the Commission must not

have any express authority to order

wheeling that would preclude the

District Court from imposing a wheeling

remedy. Nowhere, however, did the

Court say that the Commission lacked

authority under section 206 to remedy

undue discrimination. Indeed, that was

simply not a matter before the Court or

of any consequence to its decision.

In the FPA, while Congress elected

not to impose common carrier status on

the electric power industry, it tempered

that determination by explicitly

providing the Commission with the

authority to eradicate undue

discrimination—one of the goals of

common carriage regulation.203 By

providing this broad authority to the

Commission, it assured itself that in

preserving ‘‘the voluntary action of the

utilities’’ it was not allowing this

voluntary action to be unfettered. It

would be far-reaching indeed to

conclude that Otter Tail, which was a

civil antitrust suit that raised issues

entirely unrelated to our authority

under section 206, is an impediment to

our achieving one of the primary goals

of the FPA—eradicating undue

discrimination in transmission in

interstate commerce in the electric

power industry.

In Richmond Power & Light Company

v. FERC (Richmond),204 the FPC, in

reaction to the 1973 oil embargo, was

attempting to reduce dependence on oil.

The FPC requested that utilities with

excess capacity wheel power to the New

England Power Pool (NEPOOL). In

response, several suppliers and

transmission owners filed rate

schedules with the FPC that provided

for voluntary wheeling. Richmond

Power & Light Company (Richmond)

objected to these filings, claiming that

they were unreasonable because they

did not guarantee transmission access.

The FPC refused to compel the utilities

to wheel Richmond’s power, stating that

it did not have the authority to order a

public utility to act as a common carrier.

The D.C. Circuit upheld the

Commission. It acknowledged that

Richmond’s argument was persuasive in

some respects, but stated that any

conditions the Commission might

impose could not contravene the FPA.

The court examined the legislative

history of the FPA and stated that ‘‘[i]f

Congress had intended that utilities

could inadvertently bootstrap

themselves into common-carrier status

by filing rates for voluntary service, it

would not have bothered to reject

mandatory wheeling * * *.’’ 205

However, the D.C. Circuit in no way

indicated that the Commission was

foreclosed from ordering transmission

as a remedy for undue discrimination.

Richmond also had argued that the

alleged refusal of the American Electric

Power Company (AEP) and its affiliate,

Indiana & Michigan Electric Company

(Indiana), to wheel Richmond’s excess

energy was unlawful discrimination

because AEP and Indiana wheeled

higher-priced electricity from other AEP

affiliates. The court acknowledged that

Richmond’s claim of unlawful

discrimination was theoretically valid,

but found that Richmond had failed to

prove its case. It noted that if Richmond

had argued that the rates were

unjustifiably discriminatory, or that

Indiana’s failure to use its transmission

capability fully or to purchase less

expensive electricity for wheeling

resulted in unnecessarily high rates, a

different case would be before the

court.206 The case thus does not in any

way limit the Commission’s authority to

remedy undue discrimination.

In Central Iowa Power Cooperative v.

FERC,207 the FPC208 reviewed the terms

of the Mid-Continent Area Power Pool

(MAPP) Agreement under its section

205 and 206 authority. The agreement

contained two membership limitations.

First, the agreement established two

classes of membership, with one class

being entitled to more privileges than

the other. Second, the agreement

excluded non-generating distribution

systems from pool services. The FPC

found the first limitation on

membership—the two-class system—to

be unduly discriminatory and not

reasonably related to MAPP’s objectives.

The FPC conditioned approval of the

agreement under section 206 on the

removal of the unduly discriminatory

provision. The FPC found that the

second limitation, the exclusion of nongenerating distribution systems, was not

anticompetitive and did not render the

agreement inconsistent with the public

interest.

On appeal, the D.C. Circuit affirmed

the FPC’s decision. The court found that

the FPC did have authority to order

changes in the scope of the MAPP

agreement, if the agreement was unjust,

unreasonable, unduly discriminatory or

preferential under section 206 of the

FPA. The court stated:

The Commission had authority, * * *

under section 206 of the Act, * * * to order

changes in the limited scope of the

Agreement, including the addition of pool

services, if, in the absence of such

modifications, the Agreement presented ‘‘any

rule, regulation, practice or contract (that

was) unjust, unreasonable, unduly

discriminatory or preferential.’’ 209

However, the court agreed with the

FPC’s conclusion that the limited scope

of MAPP was not unjust, unreasonable,

or unduly discriminatory. The court

recognized that a pool was not invalid

under section 206 merely because a

more comprehensive arrangement was

possible.

The D.C. Circuit upheld the

Commission’s refusal to eliminate the

second limitation on membership by

ordering MAPP participants to wheel to

non-generating electric systems.210

However, neither the Commission nor

the court was presented with the

argument that wheeling was necessary

as a remedy for undue discrimination.
21562 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

211 660 F.2d 668 (5th Cir. 1981), cert. denied sub

nom. Fort Pierce Utilities Authority v. FERC, 459

U.S. 1156 (1983).

212FP&L provided transmission service when four

conditions were met: (1) The specific potential

seller and buyer were contractually identified; (2)

the magnitude, time and duration of the transaction

were specified prior to the commencement of the

transmission; (3) it could be determined that the

transmission capacity would be available for the

term of the contract; and (4) the rate was sufficient

to cover FP&L’s costs.

213All utilities requesting wheeling services,

subject to availability, would be entitled to receive

transmission service under the filed terms. Any

changes to a filed rate must be filed with the

Commission. This is the so-called ‘‘filed rate

doctrine.’’ See Northwestern Public Service

Company v. Montana-Dakota Utilities Company,

181 F.2d 19, 22 (8th Cir. 1980), aff’d, 341 U.S. 246

(1951).

214Under the filed rate doctrine, a refusal to

wheel would be unduly discriminatory under

section 206 of the FPA. As the court acknowledged,

a customer refused service could petition the

Commission to find that FP&L’s policy of

availability was unduly discriminatory under

section 206(a) of the FPA. The court said that in the

absence of a tariff on file, a utility refused wheeling

services would be unable to claim discrimination

under section 206(a) of the FPA. 660 F.2d at 675

(expressing ‘‘serious doubts that such a petition

would be successful in the absence of a tariff’’).

215 Id. at 676.

216 Id. at 678.

217The AGD court did not address New York

State Electric & Gas Corporation v. FERC, 638 F.2d

388 (2d Cir. 1980), cert. denied, 454 U.S. 821 (1981)

(NYSEG), presumably because that case did not

concern whether the Commission could order

wheeling as a remedy for undue discrimination.

218 824 F.2d at 999.

219 Id. at 999.

220 Id. at 1006.

221See, e.g., FPC v. Sierra Pacific Power

Company, 350 U.S. 348, 353 (1956); Arkansas

Louisiana Gas Company v. Hall, 453 U.S. 571, 577

n.7 (1981); and Kentucky Utilities Company v.

FERC, 760 F.2d 1321, 1325 n.6 (D.C. Cir. 1985).

Section 206 of the FPA was recently revised and

now differs from section 5 of the NGA, but not in

a manner significant to our discussion here. See 16

U.S.C. 824e (b) and (c).

In Florida Power & Light Company v.

FERC (Florida),211 the Commission

ordered Florida Power & Light Company

(FP&L) to file a tariff setting forth

FP&L’s policy relating to the availability

of transmission service.212 FP&L

objected to including such a policy

statement in its tariff and argued that

the filing of such a policy would convert

FP&L into a common carrier by

obligating it to offer service to all

customers.213 There was no finding that

the action ordered was necessary to

remedy undue discrimination.

The Fifth Circuit Court of Appeals

agreed with FP&L that the mandatory

filing of the policy statement would

require FP&L to provide transmission

service beyond its voluntary

commitment because such a

requirement would change its duties

and liabilities.214 The Commission order

would impose common carrier status on

FP&L, the court found.215 The court

noted that the Commission did not rely

on a finding of anticompetitive behavior

and therefore the court did not address

the Commission’s power to remedy

antitrust violations.216

The AGD court explicitly rejected the

claim that the above line of cases

establishes that the Commission lacks

authority to require non-discriminatory

open access.217 Opponents of the

Commission’s order argued in AGD that

Richmond and Florida, supra, stand for

the proposition that the Commission

cannot indirectly do what it allegedly

cannot do directly, that is, impose

common carriage. The AGD court

rejected these arguments, stating that

the petitioners read the electric cases far

too broadly:

(n)either Richmond nor Florida comes

anywhere near stating that the Commission is

barred from imposing an open-access

condition in all circumstances.218

The court noted that the Florida case

had expressly left open the question of

whether the Commission would be

entitled to use an open access condition

as a remedy for anticompetitive

conduct, and that in Richmond the D.C.

Circuit had said little more than that

unwillingness to transmit for all could

not be automatically deemed undue

discrimination. The court also noted the

Central Iowa case, supra, in which it

had upheld a Commission order that

found a power pooling agreement

discriminatory on its face because the

agreement gave one class of membership

privileged status over another. The court

stated that the Central Iowa case

‘‘upholds the power of the Commission

to subject approval of a set of voluntary

transactions to a condition that

providers open up the class of

permissible users.’’ 219 The court added

that it refused to ‘‘turn statutory

construction upside down’’ by letting

Congress’ failure to grant a general

power of common carriage prevail over

the affirmative grant of the specific

power to eradicate undue

discrimination.220

We conclude that AGD’s analysis of

undue discrimination under sections 4

and 5 of the Natural Gas Act is equally

applicable to an undue discrimination

analysis under sections 205 and 206 of

the FPA. The Commission and courts

have long recognized that the NGA was

patterned after the FPA and that the two

statutes should be interpreted in the

same manner.221 Thus, we conclude that

we have the authority to remedy undue

discrimination and anticompetitive

effects by requiring all public utilities

that own, control or operate

transmission facilities to file nondiscriminatory open access transmission

tariffs.

b. Section 211 of the Federal Power Act

In concluding that we must invoke

our section 206 authority to remedy

undue discrimination and

anticompetitive effects in the electric

industry, we have carefully considered

the goals of Title VII of the Energy

Policy Act, and whether section 211 of

the FPA, by itself, is sufficient to

remedy undue discrimination in public

utility transmission services. Title VII of

the Energy Policy Act, which amended

section 211 of the FPA to give the

Commission broader authority to order

wheeling in the public interest on a

case-by-case basis, reflects the intent of

Congress to encourage competitive

wholesale electric markets. Section 211

provides a means for wholesale power

sellers and buyers to obtain

transmission services necessary to

compete in, or to reach, competitive

markets, and is a valuable tool to

encourage competitive markets.

However, in amending section 211,

Congress left unaltered the authorities

and obligations of the Commission

under sections 205 and 206 (similar to

our authorities and obligations under

sections 4 and 5 of the NGA) to remedy

undue discrimination. In addition, as

discussed below, reliance on section

211 alone in some circumstances can

result in the perpetuation of, rather than

the elimination of, undue

discrimination and anticompetitive

effects.

First, there are inherent delays in the

procedures for obtaining service under

section 211. However, for competitive

reasons, many transactions must be

negotiated relatively quickly. Many

competitive opportunities will be lost

by the time the Commission can issue

a final order under section 211. Case-bycase section 211 proceedings are not a

substitute for tariffs of general

applicability that permit timely, nondiscriminatory access on request.

Second, discrimination is inherent in

the current industry environment in

which some customers and sellers are

served by open access systems, and

others have to rely on negotiated

bilateral arrangements or the mandatory

section 211 process. The end result is

discrimination in the ability to obtain

transmission services, as well as in the

quality and prices of the services. This

national patchwork of open and closed

transmission systems, with disparate

terms and conditions of service, cannot

be cured effectively through section 211.

The Commission believes that its

actions under sections 205 and 206 will

complement the section 211 procedures
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21563

222NIEP, ELCON, CINergy, UtiliCorp, TAPS, SBA,

Entergy, NY Energy Buyers, Sierra.

223E.g., EEI, Atlantic City, Allegheny, VA Com,

PA Com, Ohio Edison, Southern, Utilities For

Improved Transition, Dayton P&L, SCE&G,

Centerior, BG&E, Central Hudson, NY Com, Salt

River, Carolina P&L, Union Electric, VEPCO, Utility

Workers Union.

224EEI, VA Com, Union Electric.

225E.g., EEI, VA Com, NY Com, PA Com, Salt

River, Southern, Dayton P&L, Detroit Edison, BG&E.

226See also NY Com (NGA has no parallel

provision to section 211 of the FPA), Salt River. 227NIEP Reply Comments at 8.

to achieve both the Energy Policy Act’s

goals of creating more competitive bulk

power markets and lower rates for

consumers and the Federal Power Act’s

explicit direction in section 205(b) that

no public utility shall, with respect to

any transmission in interstate

commerce, grant any undue preference

or advantage to any person or subject

any person to any undue prejudice or

disadvantage.

2. Response to Commenters Opposing

Our Legal Authority

a. Authority to Order Open Access

Tariffs

Comments

Initial Comments Supporting

Commission Authority

A number of commenters support or

state that they do not oppose the

Commission’s authority to order open

access tariffs.222 NIEP and CCEM

explain that the AGD decision supports

the Commission’s action in this

proceeding. ELCON asserts that the

Commission’s ‘‘extensive treatment of

the relevant case law demonstrating

FERC’s authority to remedy this

discrimination is legally sound.’’

UtiliCorp argues that section 211

supports, rather than undermines, the

Commission’s authority for the NOPR

because it reflects Congress’s intention

to encourage more competitive bulk

power markets.

Initial Comments Opposing Commission

Authority

Other commenters assert that the

Commission has improperly relied on

sections 205 and 206 of the FPA to

require open access.223 They argue, for

instance, that Otter Tail should be read

as a broad constraint on the

Commission’s authority to order

wheeling for any purpose and that the

AGD decision does not undermine that

holding or the cases following Otter

Tail.224 In support, some of these

commenters discuss Richmond Power &

Light, New York State Electric & Gas

Corporation, and Florida Power & Light

Company, the same cases discussed by

the Commission in the NOPR.225

For example, EEI highlights the AGD

court’s discussion noting the difference

between the legislative history of the

NGA and that of the FPA, which the

court stated was not as strong as that of

the NGA. Moreover, EEI argues that the

court found that section 7 of the NGA

provided support for the Commission’s

actions in Order No. 436 and that such

section 7 conditioning authority is

lacking under the FPA. Allegheny notes

that AGD did not overrule Otter Tail.

Dayton P&L states that, in the gas case,

the Commission was responding to

voluntary filings by pipelines. It also

says that before the NOPR, the

Commission itself saw its authority as

more limited. SCE&G points to

differences between Commission

jurisdiction over public utilities and gas

pipelines and criticizes the

Commission’s alleged assumption that

the circumstances involved in the gas

and electric industries are virtually

identical.

PA Com argues that the attempt to

analogize to the NGA and the cases that

refer to that Act is inconsistent with the

technical and engineering realities of

the electric transmission grid and that

extensive comparisons between the

natural gas industry and the electric

industry are misleading.226

FL Com argues that, in relying on

sections 205 and 206 to establish

generic open access transmission tariffs

for all public utilities, the Commission

violates the court’s decision in Cajun

Electric Power Cooperative v. FERC, 28

F.3d 173 at 179 (D.C. Cir. 1994), where,

FL Com argues, the court refused to

allow the Commission to use a nonevidentiary ruling when there were

material facts at issue.

Reply Comments

CCEM responds that EEI and others

confuse the obligations of a common

carrier with the duty of public utilities

not to unduly discriminate. It says that

AGD supports the Commission’s

authority because the legislative history

of the FPA and the NGA are similar

with respect to common carriage.

According to CCEM, early versions of

both statutes would have made the

regulated industries operate as common

carriers (citing Otter Tail, the legislative

history of the FPA, the legislative

history of the Public Utility Holding

Company Act, and the legislative

history of the Mineral Leasing Act), but

that Congress chose not to impose the

common carrier obligations.

CCEM also says that the duties the

Commission imposed on the gas

industry and those in the NOPR are not

common carriage in any event.

According to CCEM, a common carrier

must carry all goods offered (citing Am.

Trucking Assoc. v. Atchison, T. & S.F.

Ry. Co., 387 U.S. 397, 406 (1967)).

Finally, CCEM cites Stephenson v.

Binford, 287 U.S. 251, 265–66 (1932),

where the Supreme Court held that

obligations that are typical of common

carriers can be imposed on contract

motor carriers.

CCEM further disagrees with EEI’s

argument that the enactment of section

211 was a disavowal of any other

Commission authority to order

transmission.

ELCON also disagrees with EEI’s

claim that the Energy Policy Act

undermines the Commission’s preexisting section 205 and 206 authority.

It states that the savings clause in

section 212(e) of the FPA, as amended,

explicitly expresses Congress’ intention

not to undermine the Commission’s preexisting authority and that the

legislative history contains nothing to

suggest otherwise.

Similarly, in response to those who

argue that section 211 is the only source

of authority for the Commission to order

transmission, NIEP argues that sections

211 and 212 serve purposes different

from section 206. It says that the

Commission’s authority to order

transmission in the ‘‘public interest’’

under sections 211 and 212 is not

synonymous with its authority to order

transmission as a remedy for undue

discrimination under section 206; the

two standards are complementary but

distinct:

Although broadly applicable, the

Commission’s ability to order wheeling

under sections 211 and 212 is carefully

limited by a number of procedural

provisions. Foremost among these is the

requirement that the wheeling may be

ordered only upon a specific application for

transmission services. FERC’s authority to act

in the public interest is thus confined to the

individual case.

By contrast, FERC’s remedial powers under

Section 206 can be exercised upon a finding

of unjust, unreasonable or unduly

discriminatory or preferential practices. Once

that finding has been made, however, the

form and substance of the remedy is left

entirely to the FERC’s discretion. If FERC

deems it necessary, FERC may adopt

generally applicable rules or practices as a

countermeasure to discriminatory acts,

including ordering utilities to file generally

applicable transmission tariffs.227

NIEP also points out that the

legislative history does not address the

Commission’s authority to order

transmission as a remedy for undue

discrimination. It challenges the
21564 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

228NIEP explains that

(W)hile much has been made of the Senate report

accompanying S.2114, which subsequently became

part of PURPA in 1978, that report does not

illustrate an intent to limit FERC’s authority to

remedy undue discrimination under section 206.

That report characterizes the Supreme Court’s

decision in Otter Tail as holding that ‘‘the Federal

Power Act leaves open a gap in its failure to assign

the FPC general authority to order wheeling in this

situation * * *.’’ The ‘‘situation’’ to which the

Report refers is not discrimination, however.

Instead, the statement appears to make reference to

circumstances in which general public interest

concerns, such as reliability, efficiency and

competition, are at stake. Thus, Senate Report 2114

is simply not a limitation on the Commission’s

remedial powers under Sections 206.

NIEP Reply Comments at 8–9 (citations omitted).

229See also Entergy.

230ELCON Initial Comments at 7 (quoting NYSEG

at 403).

231See, e.g.,- Niagara Mohawk Power Corporation

v. FPC, 379 F.2d 153, 159 (D.C. Cir. 1967).

232AGD, 824 F.2d at 997.

233 Id. (quoting IBEW, Local No. 474 v. NLRB, 814

F.2d 697, 712 (D.C. Cir. 1987) (emphasis deleted by

court from original)).

234 Id. (emphasis added).

235 Id. at 998–99.

interpretation of the legislative history

advanced by some commenters.228

Next, NIEP defends the Commission’s

proposed findings that there is generally

undue discrimination in the provision

of transmission service. It notes that

when an agency acts on an industrywide basis, the agency does not have to

make a finding as to each particular

case.

Finally, NIEP responds to those who

argue that AGD is not on point. It notes

that the AGD court discussed electric

cases and emphasizes the court’s

statement that the NGA ‘‘fairly bristles

with concern for undue

discrimination’’—a statement that is

equally true of the FPA.

TDU Systems responds to the

argument that Otter Tail is a broad

constraint on the Commission’s

authority to order transmission.229 At

issue in that case, it argues, was the

reach of the Sherman Act, not of FPA

sections 205 and 206. Similarly, it

argues, the Florida Power case is not on

point, and the court there specifically

said that it was not deciding whether

the Commission could have ordered

wheeling as a remedy for

anticompetitive activities. Moreover,

TDU Systems asserts that EEI’s use of a

quote from a single Senator should carry

no weight, since it is a well-established

principle of statutory construction that

such statements have little value.

Finally, it points out that the AGD court

itself did not view Otter Tail or other

electric precedent as forbidding the

Commission to order wheeling as a

remedy for undue discrimination.

Entergy asserts that Congress’s refusal

to require utilities to provide

transmission as common carriers or

whenever it is in the public interest was

merely a decision not to give the

Commission general authority to order

wheeling, without regard to undue

discrimination. Thus, the Otter Tail

language concerning the absence of a

common carrier requirement does not

demonstrate that Congress meant to

limit the Commission’s authority to

remedy undue discrimination.

ELCON disputes EEI’s reading of

NYSEG, noting that the NYSEG court

explicitly stated:

Nor do we suggest that the Commission is

powerless to review a wheeling agreement

under section 206 without following the

requirements of sections 211 and 212.230)

TAPS discusses numerous cases,

including the primary cases relied upon

by the Commission, and disposes of

NYSEG by stating that it is no longer

good law, if it ever was.

Commission Conclusion

There can be no question that the

Commission has the authority to remedy

undue discrimination. Sections 205 and

206 of the FPA mandate that we ensure

that, with respect to any transmission in

interstate commerce or any sale of

electric energy for resale in interstate

commerce by a public utility, no person

is subject to any undue prejudice or

disadvantage. Under these sections, we

must determine whether any rule,

regulation, practice, or contract affecting

rates for such transmission or sale for

resale is unduly discriminatory or

preferential, and we must disapprove

those contracts and practices that do not

meet this standard. Our discretion is at

its zenith in fashioning remedies for

undue discrimination.231

Some commenters, however,

challenge our authority to order

industry-wide non-discriminatory open

access as a remedy for the undue

discrimination we have found in the

industry. As summarized above, they

essentially assert that we are prohibited

by court precedent, the legislative

history of the FPA, and sections 211 and

212 of the FPA from ordering wheeling

as a remedy for undue discrimination.

We disagree and conclude that we have

the authority—indeed, a

responsibility—to require nondiscriminatory open access transmission

as a remedy for undue discrimination.

AGD and Legislative History

The court decision in Associated Gas

Distributors v. FERC provides powerful

support for our ability to order industrywide non-discriminatory open access

transmission in the electric industry as

a remedy for undue discrimination. As

discussed in detail above, AGD, which

is the only decision to have addressed

the Commission’s authority to remedy

undue discrimination by requiring open

access, upheld our authority under

section 5 of the NGA (the parallel to

section 206 of the FPA) to require open

access in the natural gas industry. The

rationale supplied by the AGD court

applies equally to the FPA and our

responsibility to eliminate undue

discrimination in the electric industry.

Those who challenge the

Commission’s legal authority to remedy

undue discrimination face the same

difficulty that parties faced in seeking to

overturn open access in the natural gas

industry—they ‘‘can point to no

language in the (FPA) barring the

Commission from imposing common

carrier status on (public utilities), and

certainly none barring it from imposing

upon the (public utilities) a specific

duty that happens to be a typical or

even core component of such status.’’ 232

Instead, as was unsuccessfully

attempted in the AGD proceeding, they

seek to overcome the statutory silence

primarily by means of legislative

history. However, as the AGD court

explained, legislative history is not even

relevant, because

courts have no authority to enforce principles

gleaned solely from legislative history that

has no statutory reference point.233

Here, as the court found with respect to

the NGA, the legislative history of the

FPA ‘‘provides strong support only for

the point that Congress declined itself to

impose common carrier status on

(public utilities) * * * It affords weak—

almost invisible—support for the idea

that the Commission could under no

circumstances whatsoever impose

obligations encompassing the core of a

common carriage duty.’’ 234

Commenters focus on the following

statement in the AGD decision to

support the argument that, because

Congress did not expressly reject

common carriage under the NGA, but

did reject it under the FPA, a different

outcome in this proceeding is required:

we note that the legislative history of the two

acts is, on this point, materially different. In

its deliberations on the bill that ultimately

emerged as the Federal Power Act, Congress

considered and rejected a provision that

would have ‘‘empowered the Federal Power

Commission to order wheeling if it found

such action to be ‘necessary or desirable in

the public interest.’ ’’ (citing Otter Tail)

(quoting S. 1725, 74th Cong., 1st Sess.). The

evidence as to the NGA (surveyed above) is

less direct: it consists exclusively of various

occasions on which Congress did not adopt

proposals actually making the natural gas

pipelines into common carriers.235
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21565

236 Id. at 997. We also note that the contract

carriage obligation we are imposing is easily

distinguished from the common carrier obligation

Congress chose not to adopt. As discussed infra, the

common carrier provisions rejected by Congress

would have required transmission for ‘‘any person’’

upon reasonable request. This would have included

retail purchasers.

237Otter Tail, 410 U.S. at 374.

238H.R. 5423, 74th Cong., 1st Sess., 32 (emphasis

added).

239 Id. at 44.

240 In the debate on the subsequent bill to regulate

natural gas, Congressman Cole explained:

Mr. Chairman, the House should realize that the

measure we are dealing with today is of extreme

importance, more so than the attendance and the

time taken in the discussion would seem to

indicate. It is the culmination of one of the most

far-reaching, intensive studies of the Federal Trade

Commission I assume that that Commission ever

conducted, and last year found a place in not

identical language but very similar in the Rayburn

bill, the famous holding-company bill, as part 3

thereof. Our committee eliminated part 3, as

members will recall, and saved it for a separate

measure reported out as it was last year, which was

not considered by the House, but is here today in

improved form.

81 Cong. Rec. H6724 (daily ed. July 1, 1937).

241AGD, 824 F.2d at 998.

242 Id.

The above statement, however, does

not preclude the AGD court’s decision

on our broad authority to remedy undue

discrimination in the gas industry from

applying equally in the electric

industry. Clearly, the court did not say

that. As discussed below, we believe the

statement focuses on a distinction in the

legislative histories that is not

meaningful.

First, whether or not a material

difference exists in the respective

legislative histories of the NGA and

FPA, the fact remains that the crucial

findings of the AGD court were that: (1)

‘‘Congress declined itself to impose

common carrier status’’ (emphasis

added) and (2) there is no ‘‘support for

the idea that the Commission could

under no circumstances whatsoever

impose obligations encompassing the

core of a common carriage duty.’’ 236

These findings apply equally to the

FPA. Simply stated, statutory silence

cannot be overcome by means of

legislative history—even if the

legislative history in fact indicated that

Congress ‘‘rejected’’ legislative

imposition of common carrier status

under the FPA, but ‘‘did not adopt’’ it

under the NGA. In either event, nothing

in the statute or legislative history

suggests that Congress concluded that

the Commission could under no

circumstances impose open access as a

remedy to undue discrimination.

Moreover, the legislative history of

the bills containing the FPA and the

NGA, taken as a whole, suggests that the

distinction drawn in AGD between the

legislative histories of the NGA and the

FPA is not meaningful. The legislation

that was to become the FPA originally

included provisions regulating both

electric power and natural gas. As

originally proposed, the legislation

contained identical common carriage

language for both public utilities and

natural gas pipelines.

With respect to the FPA, the Supreme

Court explained in Otter Tail that

(a)s originally conceived, Part II would have

included a ‘‘common carrier’’ provision

making it ‘‘the duty of every public utility to

* * * transmit energy for any person upon

reasonable request * * *.’’ In addition, it

would have empowered the Federal Power

Commission to order wheeling if it found

such action to be ‘‘necessary or desirable in

the public interest.’’ H.R. 5423, 74th Cong.,

1st Sess.; S. 1725, 74th Cong. 1st Sess. These

provisions were eliminated to preserve ‘‘the

voluntary action of the utilities.’’ S.Rep. No.

621, 74th Cong., 1st Sess., 19.237

The language paraphrased by the

Supreme Court was from Title II of the

initial bill proposing the Public Utility

Holding Company Act. The entire

sections from which the paraphrased

language came are as follows:

SEC. 202. (a) It shall be the duty of every

public utility to furnish energy to, exchange

energy with, and transmit energy for any

person upon reasonable request therefor; and

to furnish and maintain such services and

facilities as shall promote the safety, comfort,

and convenience of all its customers,

employees, and the public, and shall be in all

respects adequate, efficient, and reasonable.

* * *

SEC. 203. (b) Whenever the Commission

after notice and opportunity for hearing finds

such action necessary or desirable in the

public interest, it may by order direct a

public utility to make additions, extensions,

repairs, or improvements to or changes in its

facilities, to establish physical connection

with the facilities of one or more other

persons, to permit the use of its facilities by

one or more other persons, or to utilize the

facilities of, sell energy to, purchase energy

from, transmit energy for, or exchange energy

with, one or more other persons. Where any

such order affects two or more persons, the

Commission may prescribe the terms and

conditions of the arrangement to be made

between such persons, including the

apportionment of cost between them and the

compensation or reimbursement reasonably

due to any of them.238

This initial bill proposing the Public

Utility Holding Company Act also

included a Title III that was intended to

regulate the transmission and sale of

natural gas. Sections 303(a) and 304 of

Title III included the identical common

carrier language paraphrased by the

Supreme Court and included in sections

202(a) and 203(b) of Title II.239 After

further deliberations, Congress rejected

the above-quoted language in Title II

and eventually adopted a Title II that

did not include any common carrier

language. On the other hand, Title III

(addressing regulation of natural gas)

was not reported out of committee, but

reemerged in the next year.240 The bill

that reemerged did not contain the

common carrier language that was in the

original Title III. However, as Congress

had just debated the common carrier

issue in enacting electric power

regulation, it is not surprising that

Congress did not engage in debating the

very same issue in enacting natural gas

regulation.

Because of the timing of the

legislation involving the FPA and the

NGA and the logical nexus between the

two acts, we conclude that there is in

fact no material difference as to this

issue in the legislative histories of the

two acts. Both initially included

identical common carrier language, and

the language was removed from both. As

to both acts, Congress chose not to

impose common carrier obligations on

the electric or natural gas industries, but

gave the Commission the authority and

responsibility to eliminate undue

discrimination in both industries.

Consequently, as open access was found

to be a proper remedy for undue

discrimination in the natural gas

industry, it is also a proper remedy for

undue discrimination in the electric

industry.

As the AGD court noted with respect

to the Commission’s powers and duties

under the NGA, Congress explicitly gave

the Commission the authority to

eradicate undue discrimination under

the FPA. That explicit power and duty

provided by Congress cannot be

invalidated solely on the ground that

Congress chose not to impose statutory

common carrier status on public

utilities or did not explicitly authorize

the Commission to do so.241 As the AGD

court explained, this would ‘‘turn []

statutory construction upside down,

letting the failure to grant a general

power prevail over the affirmative grant

of a specific one.’’ 242

Other Case Law

A number of commenters argue that

the Commission misinterpreted the

other cases discussed in the NOPR with

respect to our authority to order nondiscriminatory open access

transmission. We disagree. As

demonstrated above, not one of the

cases put forth by commenters holds

that we cannot remedy undue

discrimination by requiring public
21566 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

243See FERC Stats. & Regs. at 33,053–56. We

further note that the AGD court did not discuss the

NYSEG decision at all. Indeed, the NYSEG case did

not involve any allegations of undue discrimination

and any discussion of section 206 by the court was

dictum.

244See, e.g., NLRB v. Bell Aerospace Company,

416 U.S. 267, 293 (1974) (citing SEC v. Chenery

Corporation, 332 U.S. 194, 202–03 (1947). See also

Heckler v. Campbell, 461 U.S. 458, 467 (1983) (even

where enabling statute requires a hearing to be held,

agency may rely on its rulemaking authority);

Panhandle Eastern Pipeline Company v. FERC, 907

F.2d 185, 187–88 (D.C. Cir. 1990). Under section

403 of the DOE Act, 42 U.S.C. 7173, the

Commission is authorized at its discretion to

initiate rulemaking proceedings.

245AGD, 824 F.2d at 1008.

246E.g., EEI, Ohio Edison, PA Com, BG&E, NY

Com, Minnesota P&L, Carolina P&L.

247E.g., EEI, BG&E.

248See also Ohio Edison.

249See also SCE&G.

250Salt River Initial Comments at 5–6 (referencing

an attached legal memorandum of Donald A.

Kaplan).

251Salt River Initial Comments at 6.

252NY Com Initial Comments at 16–18

(discussing FPL and Cajun).

253See also Southern.

254See also Southern.

255We note that CP&L raised legal objections to

our authority to implement this rule.

utilities to provide non-discriminatory

open access transmission.243

AGD is the only case in which a court

specifically addressed our authority to

order open access transmission as a

remedy for undue discrimination. Its

favorable finding with respect to our

action under section 5 of the NGA

directly supports our ordering nondiscriminatory open access transmission

under section 206 of the FPA.

Authority to Act by Rule

We disagree with those commenters

that assert that we may find and remedy

undue discrimination only through

case-by-case adjudications and are

prohibited from making a generic

determination of undue discrimination

through a rulemaking. First, there is no

question that it is within our discretion

whether we act through rule or through

case-by-case adjudications.244 The AGD

court specifically rejected a similar

argument that the Commission erred in

requiring open access transportation

tariffs without first finding that each

individual pipeline’s rates were

unlawful. The AGD court held that

‘‘(t)he Commission is not required to

make individual findings if it exercises

its § 5 authority by means of a generic

rule.’’ 245

We have identified a fundamental

generic problem in the electric industry:

owners, controllers and operators of

monopoly transmission facilities that

also own power generation facilities

have the incentive to engage, and have

engaged, in unduly discriminatory

practices in the provision of

transmission services by denying to

third parties transmission services that

are comparable to the transmission

services that they are providing, or are

capable of providing, for their own

power sales and purchases. These

practices drive up the price of electricity

and hurt consumers. Furthermore, the

incentive to engage in such practices is

increasing significantly as competitive

pressures grow in the industry. It is

within our discretion to conclude that a

generic rulemaking, not case-by-case

adjudications, is the most efficient

approach to take to resolve the industrywide problem facing us.

b. Undue Discrimination/

Anticompetitive Effects

Initial Comments

A number of commenters allege that

the Commission has failed to meet its

burden of proving industry-wide

discrimination.246 They assert that the

Commission has provided only a few

unsubstantiated allegations of

discrimination, which do not represent

the current conditions in the electric

industry, or that the Commission has

not shown that all electric utilities have

unduly discriminated. Some attack the

NOPR’s incorporation by reference of

the unsubstantiated allegations of

discrimination set forth in a petition for

rulemaking filed on February 16, 1995

by the Coalition for a Competitive

Electric Market (CCEM).247

EEI argues that the allegations of

discrimination in the NOPR must be

considered in light of the fact that: (1)

All tariffs currently on file have been

found by the Commission not to be

discriminatory; (2) more than 30

utilities have voluntarily filed open

access tariffs, which belies any assertion

of widespread discrimination in the

industry; and (3) transmission disputes

are rare, with only 19 section 211

proceedings having been filed in the last

three years.248 EEI concludes that the

Commission’s allegations of

discrimination do not rise to the level of

‘‘extreme circumstances’’ found by the

court in the natural gas industry in

AGD.

EEI adds that the Commission’s

proposal to act under section 206 is

itself discriminatory because it applies

only to public utilities and does not

reach all transmission-owning

utilities.249 If reciprocity is designed to

resolve this problem, EEI believes that

reciprocity should also be ‘‘effective for

public utilities.’’ Furthermore, EEI

argues that the failure of a public utility

to provide to others a service that it does

not provide itself is not evidence of

discrimination, and that inclusion of

such a provision actually results in

preferential treatment for transmission

users.

NE Public Power District alleges that

the NOPR does not contain a single

reference to any actual discrimination or

anticompetitive conduct by any publicly

owned utility.

Salt River asserts that the Commission

is required to consider all elements of

an antitrust analysis before reaching a

conclusion that market power exists in

the transmission system and that we

have failed to do so.250 It concludes that

the NOPR ‘‘constitutes an attempt to

legislate a remedy for an evil that has

not been, and cannot be, lawfully found

to exist on a wholesale basis among

utilities that own and operate integrated

generation and transmission

systems.’’ 251

PA Com argues that the Commission’s

request for examples of discriminatory

behavior is a ‘‘tacit admission as to the

paucity of evidence of discriminatory

practices by transmission owning

utilities.’’ NY Com argues that the

‘‘Commission’s lack of a record basis for

its proposed findings is legally suspect

because courts in two cases have held

that the Commission cannot proceed

with open access transmission tariffs

absent record findings of specific

anticompetitive conduct.’’ 252

Finally, EEI claims that even if the

Commission has proven its allegations

of discrimination, we have failed to

meet the requirements of section 206 of

the FPA.253 According to EEI, the

Commission cannot find, without an

adjudicatory hearing, that the rates on

file are unlawful and order replacement

rates.254 The Commission’s proposed

procedure would unlawfully place the

burden of justifying existing rates on the

utilities.

Reply Comments

A number of commenters provide

instances of discriminatory behavior

they have faced over the years. NCMPA

describes difficulties it has faced in

dealing with CP&L, including a

situation where CP&L allegedly

impeded NCMPA’s use of transmission

access through CP&L’s control of

dispatching.255

AMP-Ohio alleges that Toledo Edison

refused to transmit emergency power on

a buy-sell basis to certain AMP-Ohio

members even though Toledo Edison’s

system was not constrained. Instead,

AMP-Ohio alleges, Toledo Edison

bought the power and resold it to AMPOhio at a higher rate.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21567

256Brownsville Reply Comments at 2–3 (emphasis

in original).

257While many public utilities have filed some

form of open access tariff (often in response to our

proposed rule), we believe that many of the

remaining utilities will not voluntarily open their

systems absent a final rule. See also note 266.

258AGD, 824 F.2d at 1008.

APPA challenges EEI’s claim that

there is no substantial evidence of

undue discrimination in transmission. It

suggests that nineteen instances of

transmission disputes being filed since

the Energy Policy Act was enacted is

ample evidence of undue

discrimination. Moreover, according to

APPA, reported abuses are only the tip

of the iceberg.

CCEM responds to the argument

raised by EEI and others that there is no

showing of extreme circumstances of

discrimination in the electric industry

such as the AGD court noted in the gas

industry. It says that these

circumstances are present and gives

numerous examples; it does not identify

the specific utilities because ‘‘it is the

experience of * * * (our) members that

nearly all transmission owners retaliate

* * *’’ against anyone who complains.

Moreover, in answer to EEI’s statement

that transmission disputes are rare,

CCEM states that since most of the

competition is in the short-term market,

it has not been worthwhile to file

complaints. The examples provided by

CCEM include: (1) Refusal by a

California public utility to offer firm

service; (2) refusal by control area

utilities in Texas to offer ancillary

services to a power marketer, with the

result that one of the utilities won the

bid, even though it did not have the

lowest price; (3) non-utilities in ERCOT

being unable to compete to meet shortterm requests for economy energy

because they were required to schedule

by noon of the preceding day, while

utilities did not subject themselves to

such a scheduling requirement; (4)

power pool or control area information

requirements, particularly in the

northwest part of WSPP, that force nonutilities to reveal commercially sensitive

information; the transportation operator

has then revealed the information to its

own or its affiliate’s sales arm, which

‘‘steals’’ the deal; (5) a northeast power

pool that refused to wheel out even

though capacity was available on the

grounds that sending power out of the

pool would drive up prices in the pool

(hoarding); (6) a power marketer that

asked a utility to provide transmission,

whereupon the utility bought up certain

transmission capacity necessary for the

marketer to reach its buyer, thus

blocking the path—this was possible

because the utility was able to locate the

purchaser based on commercially

sensitive information the marketer had

to give the utility when the marketer

asked for transmission; (7) a common

contracting practice among utilities

restricting the use of interconnections to

themselves, particularly in the

Southwest Power Pool, MAPP, and

MAIN; (8) utilities overstating the cost

of improvements (gold-plating) and thus

discouraging service. CCEM also

responds to each of EEI’s criticisms of

CCEM’s examples of undue

discrimination submitted in its February

16, 1995 petition and argues that its

examples of undue discrimination are

unrebutted.

Brownsville asserts that

while PUB [Brownsville] must pay multiple

distance-based and pancaked transmission

rates to engage in transactions with the nonERCOT universe, El Paso Electric would have

received transmission payments from its

merger partners while gaining free

transmission access to buy and sell within

ERCOT. CSW presently walls other ERCOT

utilities off from participation in the Western

Systems Power Pool, while its ERCOT

subsidiaries, CPL and WTU, share in the

benefits of their non-ERCOT affiliates’ WSPP

memberships via the preferential terms of the

CSW Operating Agreement. CSW treats its

own inter-affiliate central dispatch as having

a higher priority than third-party economy

energy transactions, with the result that CPL

not infrequently crowds PUB out of the

economy market. 256

Wisconsin Municipals states that its

members have been fighting

transmission battles for years and sets

forth five examples of the sort of

difficulties it has experienced in

attempting to obtain transmission rights.

For example, it explains that Wisconsin

public utilities have resisted an effort by

the state commission to achieve

comparability of use of transmission.

Wisconsin Municipals also explains a

situation where ‘‘if WPPI continued to

purchase its power from WPSC, it

would pay WPSC $843,840 annually for

transmission service: if it purchases

power off system from WP&L (one of

WPSC’s competitors), WPPI would pay

WPSC $1,774,224 for transmission

service to the exact same load.’’

TAPS sets forth additional examples

of undue discrimination, including

refusals to wheel even in the face of

Nuclear Regulatory Commission (NRC)

nuclear license conditions requiring

wheeling, and Northeast Utilities’

refusal to provide transmission to a QF

even though it had indicated to the

Commission that it would provide such

transmission in order to obtain

Commission approval of its proposed

merger with Public Service Company of

New Hampshire.

NIEP sets forth ten examples of undue

discrimination that its members have

experienced in seeking access to

transmission service at reasonable terms

and conditions.

Some commenters challenge these

claims of undue discrimination. For

example, Carolina P&L responds to

NCMPA #1’s example of obstruction by

Duke in accommodating energy sales

from the jointly owned Catawba Plant.

Carolina P&L explains that NCMPA #1’s

proposal ‘‘would require Duke to

provide its own generation resources on

behalf of NCMPA #1 in order to support

a bulk power sale when NCMPA #1’s

own resource capacity and energy are

not sufficient for the sale.’’ Carolina P&L

argues that this is backstanding that

goes beyond the scope of any ancillary

service the Commission has proposed

and would be entirely inappropriate ‘‘to

compel the Transmission Provider to

sell power to its Transmission Customer

for resale on the bulk power market.’’

Duke also responds to NCMPA #1’s

claim of discrimination and asserts that

NCMPA #1’s claim is not relevant to the

NOPR proceeding, but is a specific

contractual claim that should be

pursued pursuant to the terms of its

contract.

Commission Conclusion

We conclude that unduly

discriminatory and anticompetitive

practices exist today in the electric

industry and, more importantly, that

such practices will increase as

competitive pressures continue to grow

in the industry, unless the Commission

acts now to prevent such practices.257 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. As the AGD court stated:

‘‘Agencies do not need to conduct

experiments in order to rely on the

prediction that an unsupported stone

will fall.’’ 258

We set forth examples in the NOPR of

undue discrimination that we believe

are occurring in the electric industry

and invited commenters to identify any

discrimination that they may have

experienced. In response, commenters
21568 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

259CCEM Initial Comments at 18–19. See also

NIEP Reply Comments at 13 n.31.

260FERC Stats. & Regs. at 33,072.

261See Pacific Gas and Electric Company, 65

FERC ¶ 61,312 at 62,428–30 and n.22, remanded on

other grounds, Pacific Gas & Electric Company v.

FERC, No. 94–70037 (9th Cir. June 23,

1994)(unpublished opinion), order on remand, 69

FERC 61,006 (1994).

262A list of section 211 applications and the

status of each is attached as Appendix A.

263American Municipal Power-Ohio, Inc. v. Ohio

Edison Company, 74 FERC ¶ 61,086 (1996).

264See, e.g., Gulf States Utilities Company v. FPC,

411 U.S. 747, 758–60 (1973); FPC v. Conway

Corporation, 426 U.S. 271, 279 (1976); Northern

Natural Gas Company v. FPC, 399 F.2d 953, 960

(D.C. Cir. 1968).

presented numerous additional

examples of undue discrimination,

which are summarized above, and we

set forth below further examples of

undue discrimination that have been

raised in cases before the Commission.

Many of the examples of

discriminatory behavior that have been

brought to our attention do not name the

specific utilities involved, and many are

allegations that are not proven.

However, we do not believe that this

undermines our finding of unduly

discriminatory practices by

transmission owners and controllers.

We believe that it is only natural that

potential transmission customers with

an interest in participating in electric

markets will be reluctant to name names

for fear of being shut out of those

markets. CCEM, which identified a wide

array of discriminatory behavior its

members have experienced, explained

that

(w)e do not identify the specific utilities in

each example because it is the experience of

CCEM members that nearly all transmission

owners retaliate by cutting off all

communications with anyone that challenges

or complains about the rates, terms or

conditions at which the owner offers access

to its system. Inasmuch as most of the

competitive commerce in electric power

today is in short-term markets, it is typically

not worth the effort of CCEM members or

other transmission-dependent entities to file

a complaint with the Commission’s

enforcement staff or in the courts in

connection with a transmission owner’s

discriminatory practices. The deal is lost well

before a complaint can be processed and

ruled upon.259

Other examples of discriminatory

behavior have also been raised in

proceedings before the Commission. As

we explained in detail in the NOPR,

transmission-owning utilities have

discriminated against others seeking

transmission access in a variety of ways,

most often subtly and indirectly.260 For

example, delaying tactics have been

used to frustrate access. The history of

Pacific Gas and Electric Company’s

(PG&E) attempt to avoid its

commitments made to the California

owners of the California-Oregon

Transmission Project (COTP) is a prime

example. The owners had originally

planned the COTP to have its southern

terminus at the Midway station with

Southern California Edison. PG&E

convinced them to terminate the project

instead at PG&E’s Tesla station and

indicated that PG&E would provide

transmission service the rest of the way

south to Midway. PG&E promised this

service in 1989 (in Principles). PG&E

spent the next four years filing

substitute provisions for what it had

promised in the Principles.261

Additional allegations of discriminatory

behavior are set forth in Appendix C,

which includes allegations made under

oath in proceedings at the Commission

and allegations made in pleadings and

other documents before the

Commission.

In addition, to date, the Commission

has received 28 section 211

transmission requests.262 Applicants

submit section 211 transmission

requests when the transmission

provider refuses to provide the

requested transmission service. For

example, American Municipal PowerOhio, Inc. (AMP-Ohio) requested Ohio

Edison Company (Ohio Edison) to

establish additional delivery points to

certain of AMP-Ohio’s members and to

permit the addition of delivery points in

the future upon AMP-Ohio’s request.

Ohio Edison refused AMP-Ohio’s

request, claiming that it was not a

proper request under section 211

because it already provided wholesale

transmission to the municipal utilities

at issue. In a proposed order, the

Commission disagreed with Ohio

Edison and ordered Ohio Edison to

provide the requested additional

delivery points and to entertain future

requests by AMP-Ohio for specific

delivery points.263

Many of the examples of

discriminatory actions we are seeing in

the electric industry are similar to those

we saw in the gas industry. Given our

experience, we find that these examples

of discriminatory actions are credible

and well-founded. Thus, we conclude

that there is more than sufficient reason

to believe that transmission monopolists

currently engage in unduly

discriminatory practices, and that they

will continue to engage in unduly

discriminatory practices, unless we

fashion a remedy to eliminate their

ability and incentive to do so. In light

of the competitive changes occurring in

today’s electric industry, we believe that

the only effective remedy is nondiscriminatory open access

transmission, including functional

unbundling and OASIS requirements,

and that it is within our statutory

authority to order that remedy.

Further, we disagree with the

argument that we are limited to

applying a traditional antitrust analysis

in determining whether market power

exists in the transmission system. While

we must take antitrust concerns into

consideration in exercising our

responsibilities under the FPA, we are

not an antitrust court, and our

responsibilities are not those of the

Department of Justice.264 We have

analyzed the incentives and practices of

monopoly transmission owners and

controllers in light of the statutory

standards and directives of the FPA and,

based on our findings, have properly

concluded that there is a generic

problem that must be remedied.

The Commission also recognizes, as

some commenters suggest, that we have,

in the past, permitted utilities to file

tariffs containing restrictions on

transmission service that we are now

finding to be unduly discriminatory in

this rule and that we found unduly

discriminatory in cases since our

decision in AEP. However, it is entirely

appropriate, and indeed necessary, that

our application of the FPA’s undue

discrimination standard evolve over

time and adapt to the changing

circumstances in the industry. Our prior

willingness to tolerate the use of

monopoly power over transmission to

maintain and aggregate the utility’s

market power over generation occurred

in the context of an industry structured

largely as vertically integrated regulated

monopolies that supplied all facets of

utility service—power supply,

transmission, and distribution—as a

single monopoly service. Competition

generally was not meaningfully

available as a means to discipline prices

and consumer interests were best served

by improving efficiencies of the

integrated utilities, subject to cost-based

regulation.

Today, the circumstances of the

industry are radically different. As

explained in detail in Section III, a

series of significant economic,

regulatory, and technical changes in the

power industry has introduced the

promise of competitively priced power

supplies. The profile of electric power

suppliers has expanded to include not

just the power supply arms of

traditional utilities, but also

independent power suppliers, affiliated

utility power suppliers selling into

territories of other franchise utilities,
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21569

265We note that there are now 14 power

marketers that are affiliated with public utilities.

266We take note of EEI’s comments that, at the

time of the comments, 30 utilities had filed open

access tariffs. They argue, therefore, that the rule is

unnecessary. Since their comment was filed, the

number of utilities filing some form of an open

access tariff has risen to 106. However, while some

of these tariffs are based on the NOPR pro forma

tariffs, many of these tariffs fall significantly short

of the tariff requirements of both the NOPR and this

Rule. Even if the tariffs met these requirements, the

Rule is still needed to complete the task of

eliminating undue discrimination by all public

utilities and assuring, to the extent possible, a

nationwide open access transmission grid. Indeed,

a number of these tariffs were filed for the purposes

of securing authority to market power

competitively. This underscores markedly our

fundamental conclusion that prior practices of

using monopoly power over transmission to

preserve market power over electricity sales has no

place in today’s industry and must be eliminated

to get the benefits of competition to the customers

we are required to protect under the FPA.

267E.g., EEI, VA Com, Ohio Edison Southern,

Utilities For Improved Transition, BG&E.

268See also NM Com.

269See also Salt River. Moreover, FL Com states

that the Commission should modify its hearing

process to better accommodate state PUC

participation by: (1) Holding hearings in the

affected state; (2) teleconferencing; (3) making free

transcripts available to states; and (4) substantially

deferring to a state when the state commission has

held a hearing on an issue in the case.

270EEI quoted the following language from

NYSEG:

Nor do we suggest that the Commission is

powerless to review a wheeling agreement under

section 206 without following the requirements of

sections 211 and 212. If, after a hearing as required

by section 206, the Commission determines that a

particular rate, charge or condition is unreasonable,

it can order a modification. But where, as here, the

modification amounts to an order requiring

wheeling, it must be preceded also by

determination in accordance with sections 211 and

212. Simply put, we will not allow the Commission

to do indirectly without compliance with the

statutory prerequisites, what it could not do directly

without such compliance. (citing Richmond Power

& Light).

271See also VA Com.

272See also Carolina P&L.

273This argument is puzzling. First, section 211

does not control to whom access must be provided

under sections 205 and 206. However, even if it did,

Associated EC appears to misconstrue eligibility

under section 211. An electric utility as defined in

the FPA is any person or State agency (including

any municipality) which sells electric energy. The

definition does not say that electric energy must be

re-sold at wholesale. Thus, an electric utility could

be a wholesale buyer of transmission used to

transmit energy for sale at either wholesale or retail.

274See also Allegheny.

and power marketers.265 This offers the

promise of an increasingly competitive

commodity market in electric power, in

which significant benefits to consumers

can be achieved. In the context of an

emerging competitive market in

generation, discriminatory practices that

once did not constitute undue

discrimination must be reviewed to

determine whether they are being used

to prevent the benefits of competition in

generation from being achieved. Here

we find conclusively that they are, and

use our remedial authority to ensure

that they can no longer occur.266

c. Section 211

Comments

Various commenters contend that the

enactment of section 211 in essence

either removed any authority the

Commission might have had under

sections 205 and 206 or demonstrates

that Congress did not believe the

Commission could order wheeling

under those provisions.

These commenters assert that the

legislative history of the FPA indicates

that Congress specifically rejected

giving the Commission authority to

order wheeling under any

circumstances.267 They further contend

that the legislative history of section 211

demonstrates that Congress viewed the

authority it granted in section 211 as a

strictly limited and entirely new

authority for the Commission.268

Specifically, EEI states that the

legislative history of the Energy Policy

Act confirms that the expanded

authority provided under section 211

was not intended to grant the

Commission blanket authority to order

wheeling, even as a remedy for

anticompetitive conduct. Similarly,

Utilities For Improved Transition argues

that the legislative history shows that

Congress specifically intended to

preclude the Commission from ordering

tariffs of general applicability under any

circumstances. In addition, EEI points to

testimony provided by a Commission

staff witness before the Subcommittee

on Energy and Power of the House

Committee on Energy and Commerce in

which EEI claims that ‘‘she suggested

that an affirmative statement that the

Commission had the power to require

wheeling on its own motion should be

included, possibly in section 211.’’ EEI

maintains that such suggestion was

rejected by Congress in favor of allowing

the Commission to order wheeling only

upon application.

Detroit Edison, asserting that Cajun

stands for the proposition that the

agency must follow Congressionally

mandated procedures, claims that the

Commission can order transmission

only after going through the procedures

of section 211. Detroit Edison also

argues that the Commission should

incorporate into the final rule the

various safeguards of section 211, such

as the requirement that the utility

receive prior notice, the requirement

that transmission service be in the

public interest, and the requirement that

existing service not be displaced. FL

Com further asserts that it was

Congressional intent in the Energy

Policy Act for wheeling to be ordered on

a case-by-case basis pursuant to section

211.269

EEI argues that the enactment of

section 211 eliminated any authority the

Commission had under sections 205 and

206 to order wheeling as a remedy for

undue discrimination. It alleges that the

Commission failed to discuss the

NYSEG case concerning the relationship

between section 211 and sections 205

and 206 in any meaningful way.

According to EEI, the NYSEG court

concluded that section 211 ‘‘was the

only appropriate vehicle under which

the Commission could order NYSEG to

wheel power for the municipality.’’ 270

EEI further resorts to canons of statutory

construction to conclude that ‘‘section

211 must be given effect as the more

specific provision and must be

interpreted to limit the scope of sections

205 and 206.’’ 271 In addition, EEI asserts

that ‘‘Congress had an opportunity to

reject the NYSEG court’s interpretation

of the scope of sections 205, 206 and

211, but instead amended section 211 in

a manner that is consistent with the

view that mandatory wheeling is to be

governed exclusively by section 211.’’

Dayton P&L raises similar arguments. It

notes the savings provision in section

212(e), but says that Congress ‘‘would

have been more specific if it understood

that the Commission already had the

authority to order wheeling under FPA

sections 205 and 206. * * *’’ 272

Associated EC argues that the NOPR

appears to exceed the Commission’s

authority in that it proposes that

‘‘wholesale buyers and sellers have

’equal access to the transmission grid.’ ’’

It asserts that ‘‘Section 211(a), however,

makes mandatory transmission service

available only to ’[a]ny electric utility,

Federal power marketing agency or any

other person generating electric energy

for sale for resale.’ ’’ 273

NE Public Power District argues that

sections 211 and 212 of the FPA appear

clearly to contemplate a case-by-case

approach.274 NE Public Power District

adds that if the Commission believes

sections 211 and 212 are inconsistent

with the public interest, it can ask

Congress to modify those provisions.

Allegheny adds that the Commission

can order wheeling only under sections

211 and 212 on a company-specific

basis and can use sections 205 and 206

only to evaluate the reasonableness of

terms and conditions of voluntarily filed

agreements or tariffs by public utilities.

Utilities For Improved Transition also

claims that sections 211 and 212

override any authority the Commission

might have had under sections 205 and
21570 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

275 It states that

Section 212(e), however, provides that Sections

211 and 212 limit or impair the Commission’s

authority under ‘‘other provisions of law’’ (a phrase

including, obviously, Sections 205 and 206). On the

face of the statute—we say again for emphasis: on

the face of the statute—the Commission therefore

does not have the authority to order transmission

service outside the provisions of Sections 211 and

212.

Utilities For Improved Transition Initial

Comments at 51 (emphasis in original).

276 16 U.S.C 824k (emphasis added).

277 In discussing the electricity provisions of the

Energy Policy Act, Senator Wallop declared:

It would be a mistake to take the presence of

transmission access provisions in the Conference

Report as a sign of change in position on my part

or that of the Senate. I would have strongly

preferred PUHCA reform without any transmission

access provisions, as was the Senate position.

However, in order to obtain the very significant

benefits of PUHCA reform contained in the Senate

bill, it was necessary to accept some of the House

transmission access provisions.

138 Cong. Rec. S17615 (daily ed. October 8,

1992).

278See, e.g., Shell Oil Company v. Iowa

Department of Revenue, 488 U.S. 19, 29 (1988)

(Shell). In Shell, the Court declared:

This Court does not usually accord much weight

to the statements of a bill’s opponents. ‘‘[T]he fears

and doubts of the opposition are no authoritative

guide to the construction of legislation.’’ Gulf

Offshore Co. v. Mobil Oil Corp., 453 U.S. 473, 483

(1981) (quoting Schwegmann Bros. v. Calvert

Distillers Corp., 341 U.S. 384, 394 (1951).

See also Sutherland Statutory Construction

§ 48.16 at 366.

279Hearings on H.R. 1301, H.R. 1543, and H.R.

2224 before the Subcommittee on Energy and Power

of the House Committee on Energy and Commerce,

102d Cong., 1st Sess. (May 1,2 and June 26, 1991),

Statement of Cynthia A. Marlette, Associate General

Counsel, Federal Energy Regulatory Commission,

Report No. 102–60 at 60 and 61–70. See also id. at

106 (‘‘I believe that we have substantial authority

under the existing case law to mandate access

where necessary to remedy anticompetitive

effects.’’).

280At the time Congress enacted amendments to

FPA section 211, it was well aware that the

Commission had unexplored authorities under

sections 205 and 206 of the FPA to compel

wheeling. The only explicit limitations it chose to

impose on the Commission’s wheeling authorities

were those contained in sections 212(g) and (h),

which provide that no order ‘‘under this Act’’ may

be inconsistent with any State law governing retail

marketing areas of electric utilities (section 212(g)),

or be conditioned upon or require the transmission

of electric energy directly to an ultimate consumer

(section 212(h)).

281FERC Stats. & Regs. ¶ 32,514 at 33,083

(footnote omitted).

282 Id. at 33,083 n.195.

206 to order industry-wide open access.

It cites the savings clause in section

212(e) of the FPA as limiting the

Commission’s authority to order

transmission.275 Utilities For Improved

Transition argues at some length that

the NOPR does not meet the procedural

and substantive standards of sections

211 and 212. It goes on to cite various

passages from the legislative history of

the Energy Policy Act as supporting the

view that Congress intended to

eliminate the Commission’s authority to

order industry-wide open access as a

remedy for undue discrimination.

According to Utilities For Improved

Transition, these passages

‘‘unmistakably show a clear legislative

intent to preclude the mandatory

transmission that the Commission

attempts here * * *.’’

Commission Conclusion

We disagree with those commenters

that argue that the Energy Policy Act

either eliminates our authority under

section 206 to remedy undue

discrimination by requiring nondiscriminatory open access transmission

or demonstrates that we never had any

such authority. Nothing in sections 211

and 212 or in the legislative history of

these sections indicates that Congress

intended to eliminate the Commission’s

other, broader authorities under the

FPA. Indeed, section 212(e) specifically

provides:

SAVINGS PROVISIONS.—(1) No provision

of section 210, 211, 214, or this section shall

be treated as requiring any person to utilize

the authority of any such section in lieu of

any other authority of law. Except as

provided in section 210, 211, 214, or this

section, such sections shall not be construed

as limiting or impairing any authority of the

Commission under any other provision of

law.276

Utilities For Improved Transition’s

argument that the ‘‘Except as provided’’

clause limits or impairs the

Commission’s authority to order

transmission service under sections 205

and 206 would make the savings

provision meaningless. Moreover, such

a reading would be entirely at odds with

the underlying purposes of the Energy

Policy Act. It would be ironic indeed to

interpret the Energy Policy Act as

eliminating our long-standing, broad

authority to remedy undue

discrimination, given the procompetitive purpose of the statute.

The legislative history also provides

no support for the arguments that

sections 211 and 212 remove or prove

the non-existence of the Commission’s

authority to remedy undue

discrimination by requiring nondiscriminatory open access

transmission. In fact, virtually every bit

of legislative history raised by

commenters opposing the NOPR

consists of various statements by

Senator Wallop, an opponent of

expanding transmission access under

sections 211 and 212.277 Such legislative

history provides no insight into the

meaning of a statute and is given little

or no weight by the courts.278

The only other legislative history that

commenters put forth is the testimony

of a Commission staff witness, in 1992

hearings before the Subcommittee on

Energy and Power of the House

Committee on Energy and Commerce.

According to EEI, the witness indicated

that an affirmative statement that the

Commission could require wheeling on

its own motion ‘‘would be needed [in

the Energy Policy Act] if Congress

intends for the Commission to be able

to deal with transmission on its own

motion and thereby go further than

simply dealing with industry

proposals.’’ EEI claims that this

statement demonstrates that the

expanded authority in the Energy Policy

Act ‘‘was not intended to grant the

Commission blanket authority to order

wheeling, even as a remedy for

anticompetitive conduct.’’

EEI’s argument is misleading and

disingenuous. It takes the witness’s

statements out of context, ignoring

attendant testimony that ‘‘there are

strong legal arguments that the

Commission’s obligation to protect

against undue discrimination carries

with it the authority to impose

transmission requirements as a remedy

for undue preference or

discrimination,’’ and the extensive legal

argument, included in her testimony, in

favor of that position—an argument that

closely parallels the legal argument the

Commission is relying on in this

proceeding.279 Indeed, in the face of

such explicit testimony from the staff of

the agency required to implement the

statute, had Congress intended to limit

the Commission’s remedial authority

under section 206 when it amended

section 211, we believe it would have

explicitly done so in the language of the

statute itself, or at least have indicated

its intent to do so in the Conference

Report on the Energy Policy Act.280

C. Comparability

1. Eligibility to Receive NonDiscriminatory Open Access

Transmission

In the NOPR, the Commission

proposed to define who is eligible to

receive service under a nondiscriminatory open access tariff as

follows:

A non-discriminatory open-access tariff

must be available to any entity that can

request transmission services under section

211.281

The Commission further explained that

‘‘[u]nder section 211, any electric

utility, Federal power marketing agency,

or any other person generating electric

energy for sale for resale may request

transmission services under section

211.’’ 282
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21571

283Section 212(h) (Prohibition on Mandatory

Retail Wheeling and Sham Wholesale

Transactions).

284We emphasize that any transmission customer

must follow prudent utility practices so as to assure

reliability.

285New Reporting Requirement Implementing

Section 213(b) of the Federal Power Act and

Supporting Expanded Regulatory Responsibility

Under the Energy Policy Act of 1992, and

conforming and Other Changes to Form No. FERC–

714, Order No. 558–A, 65 FERC ¶ 61,324 at 62,451

n.12 (1993).

286Order No. 558, FERC Stats. & Regs. ¶ 30,980 at

30,895–96, reh’g denied, 65 FERC ¶ 61,324 (1993)

(cooperatives are electric utilities); AES Power, Inc.,

69 FERC ¶ 61,345 at 62,297 (1995) (power marketer

is an electric utility, i.e., a person ‘‘which sells

electric energy’’).

287See, e.g., Citizens Energy Corporation, 35

FERC ¶ 61,198 at 61,452–53 (1986).

288 In making this determination, we are not

deciding whether these entities are eligible entities

under section 211(a) of the FPA.

289See Section IV.I.

Comments

PSNM believes that the NOPR

properly defined customer eligibility.

NIEP, on the other hand, believes that

the proposed definition is too limited. It

argues that the Commission should

require public utilities to make

transmission service available to all

entities engaged in wholesale purchases

or sales of power, not just to those

‘‘generating’’ power. Utility Working

Group requests that the Commission

clarify that eligibility is dependent not

only on being the type of entity set forth

in section 211, but on meeting the

requirements of section 212(h)

(Prohibition on Mandatory Retail

Wheeling and Sham Wholesale

Transactions) as well.283

We also received several comments

related to the applicability of the rule to

foreign entities. Canada states that the

requirements for comparability and

reciprocity should be implemented in a

flexible manner to permit Canadian

utilities to have fair and competitive

access in the U.S. electricity market.

Maritime requests that the Commission

require Canadian utilities who wish to

participate in the U.S. market to offer

other utilities the same privileges they

receive in the United States.

Southwestern argues that transmission

to a foreign country is in interstate

commerce and that a utility should

therefore accommodate this type of

transmission request under its open

access tariff. El Paso argues that the

Commission does not have the authority

to condition access to foreign countries,

but states that if the Commission

nevertheless exercises such authority it

should do so on a case-by-case basis.

Destec asserts that

the posturing of Ontario Hydro before U.S.

regulators pleading for open access and nondiscriminatory transmission treatment—even

for extra-territorial entities, should be met

with a strong reply that such provisions

should also be afforded transmission

dependent entities on the Canadian side of

the border. Ontario Hydro’s aggressive

pursuit of U.S. market opportunities while

simultaneously blocking competitors through

the control of their transmission assets can

not be ignored.

Commission Conclusion

In the Final Rule pro forma tariff the

Commission has modified the definition

of ‘‘eligible customer’’ to address

concerns that in some respects the

NOPR definition was too limited and in

other respects it was too broad. This

includes amended language to clarify

that any entity engaged in wholesale

purchases or sales of energy, not just

those ‘‘generating’’ electric power, is

eligible. It also includes clarification

that entities that would violate section

212(h) of the FPA (prohibition on

Commission-mandated wheeling

directly to an ultimate consumer and

sham wholesale transactions) are not

eligible. The language also has been

modified to provide that foreign entities

that otherwise meet the eligibility

criteria may obtain transmission

services. Further, it has been modified

to provide for service to retail customers

in circumstances that do not violate

FPA section 212(h).284

Persons that would be eligible section

211 applicants also would be eligible

under the open access tariffs. Section

211 applicants may be any electric

utility, Federal power marketing agency,

or any other person generating electric

energy for sale for resale.

Section 3(22) of the FPA, as amended

by the Energy Policy Act, defines

‘‘electric utility’’ to mean

any person or State agency (including any

municipality) which sells electric energy;

such term includes the Tennessee Valley

Authority, but does not include any Federal

power marketing agency.

Thus, as we have previously noted,

municipal utilities are electric utilities

simply by the terms of the statute.285 In

addition, we have also found that

cooperatives and marketers are electric

utilities as defined in the FPA.286 Other

entities that fall within the definition

include IOUs, IPPs, APPs, and QFs that

sell electric energy.

We do not believe that entities that

engage solely in brokering should be

eligible. Such brokers do not take title

to electricity and therefore do not

engage in the sale of electric energy; nor

do they generate electric energy for sale

for resale.287 Although such brokers are

not eligible under the tariffs, they will

be able to arrange deals because they

will have access to the OASIS of all

public utilities and will be able to solicit

information from the relevant

transmission service providers under

the terms of the applicable tariffs.

We clarify that foreign entities that

otherwise meet the eligibility criteria

must be eligible to receive service under

the non-discriminatory open access

transmission tariffs.288 We are making

this determination pursuant to our

authority under section 206 of the FPA

to remedy undue discrimination. As we

explained in the NOPR, market power

through the control of transmission can

be used discriminatorily to block

competition. Customers in the United

States should not be denied access to

cheaper supplies of electric energy,

whether such electric energy is from a

domestic source or a foreign source. By

making non-discriminatory access

available to foreign entities that

otherwise meet the eligibility criteria,

we are assuring that customers in the

United States have access to as many

potential suppliers as possible. This

should result in increased competition

and lead to customers paying the lowest

possible prices for their electric energy

needs. To the extent that such an entity

obtains access, however, we emphasize

that it would be subject to all of the

terms and conditions of the applicable

open access tariff, including the

requirement that it provide reciprocal

service.

Finally, we have reconsidered our

NOPR position that would have limited

eligibility to wholesale transmission

customers. As we explained in the

NOPR, the Commission’s jurisdiction

extends to all unbundled transmission

in interstate commerce by public

utilities. It is irrelevant to the

Commission’s jurisdiction whether the

customer receiving the unbundled

transmission service in interstate

commerce is a wholesale or retail

customer. Thus, if a public utility

voluntarily offers unbundled retail

access in interstate commerce or a state

retail access program results in

unbundled retail access in interstate

commerce by a public utility, the

affected retail customer must obtain its

unbundled transmission service under a

non-discriminatory transmission tariff

on file with the Commission. Though

the Commission may approve a separate

retail transmission tariff when some

variation is necessary or appropriate to

meet local concerns,289 we generally see

no reason why retail transmission tariffs

necessarily must be different from

wholesale transmission tariffs. For that

reason, we anticipate that in many
21572 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

290The Commission has no authority to order

retail transmission directly to an ultimate consumer

or to order ‘‘sham’’ wholesale transmission. See

FPA section 212(h). However, if such access occurs

voluntarily or as a result of a state program, the

rates, terms, and conditions of the access are within

our exclusive jurisdiction if the service is provided

by a public utility.

291FERC Stats. & Regs. ¶ 32,514 at 33,079.

292Requirements for ancillary services are

discussed in Section IV.D.

293FERC Stats. & Regs. ¶ 32,514 at 33,049.

294E.g., Minnesota P&L, Power Marketing

Association.

295E.g., Springfield.

circumstances the same open access

tariff that serves wholesale customers

will be equally appropriate for retail

transmission customers. Therefore,

unless the Commission has specifically

permitted a separate retail tariff, eligible

customers under the Final Rule pro

forma tariff must include unbundled

retail customers.290 We discuss this

further in Section IV.I.

While the rates, terms, and conditions

of all unbundled transmission service

will be subject to a Commissionauthorized tariff, we will, in appropriate

circumstances, give deference to state

recommendations regarding rates, terms,

and conditions for retail transmission

service or regarding the proper

transmission cost allocation to be used

between retail and wholesale customers

when state recommendations are

consistent with our open access

policies. This is also discussed further

in Section IV.I.

Moreover, we are mindful of the fact

that we are precluded under section

212(h) from ordering or conditioning an

order on a requirement to provide

wheeling directly to an ultimate

consumer or sham wholesale wheeling.

We therefore clarify that our decision to

eliminate the wholesale customer

eligibility requirement does not

constitute a requirement that a utility

provide retail transmission service.

Rather, we make clear that if a utility

chooses, or a state lawfully requires,

unbundled retail transmission service,

such service should occur under this

tariff unless we specifically approve

other terms.

2. Service That Must be Provided by

Transmission Provider

In the NOPR, the Commission

proposed that a public utility must offer

to provide any point-to-point or network

transmission service whether or not the

utility provides itself that service:

The Commission therefore proposes that

all public utilities must offer both firm and

non-firm point-to-point transmission service

and firm network transmission service on a

non-discriminatory open access basis in

accord with the proposed rule and the

attached appendix tariffs. The Commission

believes that a utility’s tariff must offer to

provide any point-to-point transmission

service and network transmission service that

customers need, even though the utility may

not provide itself the specific service

requested.291

Comments

EGA and SMUD agree that a

transmission owner should offer any

transmission service it is able to

provide, even if it does not use the

service itself.

Public Generating Pool, an association

of consumer-owned electric utilities,

appears concerned that the Commission

may interpret comparability broadly to

require a utility to offer the same service

provided by another utility or to offer

service generally available in a region.

Thus, it recommends that a third party

seeking more service than a utility

provides itself be required to resort to

the section 211 process.

Commission Conclusion

Initially, we note that, with the

possible exception of small utilities

(which may qualify for a waiver, see

infra), we have seen no evidence that

public utilities are incapable of

reasonably providing the services

required in the Final Rule pro forma

tariff. Nor have we seen evidence that

utilities able to provide these services to

themselves are choosing to forego such

services. In short, we are not convinced

that there is an appreciable difference,

if any, among the services required in

the pro forma tariff, the services utilities

are able to provide, and the services

they actually provide themselves.

To the extent these services do differ,

however, we explicitly adopt the

proposal set forth in the NOPR. Thus, a

public utility must offer transmission

services that it is reasonably capable of

providing, not just those services that it

is currently providing to itself or others.

Because a public utility that is

reasonably capable of providing

transmission services may provide itself

such services at any time it finds those

services desirable, it is irrelevant that it

may not be using or providing that

service today. Moreover, a public utility

must offer these transmission services

whether or not other utilities may be

able to offer the same services and

whether or not such services are

generally available in the region (waiver

of these requirements for small utilities

is discussed in Section IV.K.2.).292

However, if a customer seeks a

customized service not offered in an

open access tariff, a customer may,

barring successful negotiation for such

service, file a section 211 application.

3. Who Must Provide NonDiscriminatory Open Access

Transmission

In the NOPR, the Commission

proposed to require all ‘‘public utilities’’

owning and/or controlling facilities

used for transmitting electric energy in

interstate commerce to file open access

transmission tariffs.293 We explained

that we could not require all

‘‘transmitting utilities’’ to file open

access tariffs under sections 205 and

206 because we do not have jurisdiction

over non-public utilities under these

sections.

Comments

Several commenters argue that the

open access requirement must be

applied to non-jurisdictional utilities

that own interstate transmission

facilities.294 Power Marketing

Association recognizes that this raises

difficult legal issues and suggests that

the Commission support legislation to

expand the Commission’s authority over

non-jurisdictional utilities. Minnesota

P&L argues that if the requirement is not

applied to all entities that own

transmission, jurisdictional and nonjurisdictional entities owning joint

transmission facilities will be

competitively disadvantaged due to

unequal pricing. Union Electric argues

that unless the requirement is extended

to the 56 non-jurisdictional entities

operating control areas, discrimination

in the wholesale power markets will

increase.

A number of municipal commenters

assert that the NOPR overlooks

transmission assets jointly owned by

jurisdictional and non-jurisdictional

utilities.295 They argue that agreements

regarding use of these assets often

contain provisions prohibiting thirdparty power transfers. They further

argue that such provisions should be

nullified, and the joint owners should

be required to develop equitable

methodologies to allocate wheeling

revenues among themselves.

Several cooperatives urge the

Commission to clarify that contracts

among their constituent cooperatives are

not subject to any unbundling of

existing contracts.

Commission Conclusion

Our authority under sections 205 and

206 of the FPA permits us to require

only public utilities to file open access

tariffs as a remedy for undue

discrimination. We have no authority
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21573

296FERC Stats. & Regs. ¶ 32,514 at 33,050 and

33,092–93.

297As discussed in the NOPR, sections 211 and

212 require that applicants specify only rates,

terms, and conditions of service, not specify

transactions. Thus, applicants can file requests for

tariffs to accommodate future, currently unspecified

transactions, similar to the open access tariffs

required by this Rule.

298FERC Stats. & Regs. ¶ 32,514 at 33,089.

299 Id. at 33,095. 300 Id. at 33,090.

301E.g., Consumers Power, Northern States Power,

PacifiCorp, Oklahoma G&E, Allegheny Power,

ELCON, Public Service Co of CO.

302E.g., Northern States Power, VEPCO, Utilities

For Improved Transition, PacifiCorp, Arizona

Public Service, Dairyland, Montaup, Illinois Power,

South Carolina E&G, Florida Power Corp, KU.

303See also NRECA.

304Wisconsin P&L notes, however, that a possible

exception exists where a user could block the

efficient transfer of power and then market its own

power at a premium price.

under those sections of the FPA to

require non-public utilities to file tariffs

with the Commission.

However, we are concerned that if

non-public utilities do not provide

access, there will remain a patchwork of

‘‘open’’ and ‘‘closed’’ transmission

systems and the potential for distortions

in wholesale bulk power markets. We

believe that certain mechanisms exist

that will help to alleviate these

problems.

First, as we explained in the NOPR,

broad application of section 211 will

provide wider access to bulk power

markets.296 Under section 211, eligible

entities may seek transmission service

from ‘‘transmitting utilities,’’ which

section 3(23) of the FPA defines as ‘‘any

electric utility, qualifying cogeneration

facility, qualifying small power

production facility, or Federal power

marketing agency which owns or

operates electric power transmission

facilities which are used for the sale of

electric energy at wholesale.’’ We

believe that section 211 provides us

with authority to require the same

quality of transmission service as

sections 205 and 206, though the

procedural path is more cumbersome.

Thus, section 211 provides access to

transmission systems owned or operated

by non-public utilities.297

Second, as we explained in the NOPR,

our reciprocity requirement is designed

to provide the widest possible use of the

nationwide transmission grid:

The purpose of this provision is to ensure

that a public utility offering transmission

access to others can obtain similar service

from its transmission customers. It is

important that public utilities that are

required to have on file tariffs be able to

obtain service from transmitting utilities that

are not public utilities, such as municipal

power authorities or the federal power

marketing administrations that receive

transmission service under a public utility’s

tariff.298

Finally, again as we explained in the

NOPR, the formation of RTGs should

speed the development of competitive

markets and involve more non-public

utilities in the provision of nondiscriminatory open access

transmission.299 In approving RTGs, our

policy has been to require all members,

whether or not they are public utilities,

to offer comparable transmission

services at least to other members.

We recognize that these solutions are

not perfect. However, given the

difficulties inherent in the statutory

scheme, we believe they will go a long

way toward effectuating transmission

access by non-public utilities.

One further issue involving nonpublic utilities concerns jointly owned

transmission facilities. We will not

allow public utilities that jointly own

interstate transmission facilities with

non-jurisdictional entities to escape the

requirements of open access. We will

require each public utility that owns

interstate transmission facilities jointly

with a non-jurisdictional entity to offer

service over its share of the joint

facilities, even if the joint ownership

contract prohibits service to third

parties. We urge such public utilities to

seek mutually agreeable revisions to

their agreements to permit third-party

access over all, or at least their share, of

the facilities. For those joint ownership

arrangements that include restrictions

on the usage of jointly owned

transmission facilities by third parties,

we will require the public utilities, in a

section 206 compliance filing, to file

with the Commission, by December 31,

1996, a proposed revision (mutually

agreeable or unilateral) to its contract

with the non-jurisdictional owner(s).

This revision must be designed at a

minimum to permit third parties to use

the public utility’s share of the joint

facilities in accordance with this Rule

and must provide for any needed cost

allocation procedures between the

public utility and the non-jurisdictional

owner(s).

4. Reservation of Transmission Capacity

by Transmission Customers

In the NOPR, the Commission set

forth the information that a requester of

transmission service would have to

submit with a service request. We

recognized that there may have to be a

limit, for competitive reasons, on the

information required, but also

recognized the need to assure that no

customer would reserve scarce capacity

and then hold it without using it.300 To

avoid forcing transmission customers to

reveal unnecessary details of their

purchase or sales transactions, the

Commission discussed several less

restrictive options: (1) Allow the

transmission provider to use or sell the

capacity while it is unused, (2) have a

pool that clears the short-term market,

and (3) require the customer to begin

using the capacity within some

specified period or lose its reservation

rights. The Commission requested

comments on these and other possible

approaches.

Comments

Unused or Unneeded Transmission

Capacity

Many commenters recommend a useit-or-lose-it rule (i.e., a transmission

customer must use its reserved

transmission capacity or lose its rights

to that capacity).301 Several commenters

also recommend a number of

restrictions on capacity reservations to

reduce incentives to hoard or to cherrypick (request to reserve firm capacity

only during peak hours of peak seasons)

existing transmission capacity. These

include: (1) Allow requesters to reserve

a place in the queue with a right of first

refusal over later competing requests; (2)

impose a take-or-pay charge on

reservations and deny reservation

holders the right to revenue sharing if

they do not schedule or assign their

rights; (3) limit the time period for

reservations; (4) limit how far in

advance reservations may be made for

both non-firm and firm services; (5)

maintain a price cap on the resale of

transmission; (6) require multi-year

reservations to be for sequential periods;

and (7) require a nonrefundable fee for

advance reservations of service.302

Southwestern suggests that transmission

tariffs include a provision that prevents

transmission customers and the

transmission provider from reserving

and tying up firm transmission capacity

for speculative wholesale

transactions.303

On the other hand, PSNM believes

that a use-it-or-lose-it approach is

inappropriate because any prudent

utility that has reserved capacity would

seek to sell the service it is not using so

as to recover some portion of its fixed

costs. Wisconsin P&L argues that a useit-or-lose-it approach would not work,

would be difficult to administer, and

may be anticompetitive.304 Central

Illinois Public Service asserts that a

reservation holder has little incentive to

hoard capacity because other customers

can use the capacity on a non-firm basis

during times when a reservation holder

does not schedule power. It warns that
21574 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

305A reservation charge would assure that the

utility fully recovers its fixed costs associated with

the transmission customer’s reserved transmission

capacity.

306See Section IV.C.6.

307E.g., NYPP, Public Service E&G, Sierra Pacific

Power, Ohio Edison. Sierra Pacific Power asserts

that a utility should be permitted to retain capacity

for native load use over the pertinent planning

period. El Paso adds that the Commission should

allow utilities the opportunity to reserve capacity

for anticipated uses that, although not firm, are

necessary to maintain reliability.

308E.g., NIEP, CCEM, Conservation Law

Foundation.

giving the transmission operator the

ability to schedule unused capacity may

result in undue influence and the

exercise of market power. CA Energy

Com maintains that, while reassignment

would help prevent hoarding, it would

not assure efficient use of the full

transmission network.

Use of Pooling Arrangements To Prevent

Improper Reservations

Allegheny Power contends that a

pooling arrangement could provide an

incentive to hoarders to release capacity

during a shortage. It suggests that

capacity could be auctioned within a

pool of available capacity. However, it

acknowledges that an auction would be

tantamount to allowing the network

owner to sell transmission service at

unregulated rates.

PacifiCorp does not believe that a

pooling arrangement would prevent

capacity hoarding unless nonsequential

reservations are prohibited. ELCON

contends that a use-it-or-lose-it rule

would be fairer and more effective than

pooling.

Commission Conclusion

Upon further consideration, we

conclude that firm transmission

customers, including network

customers, should not lose their rights

to firm capacity simply because they do

not use that capacity for certain periods

of time. Firm transmission customers

that have reserved capacity and paid a

reservation charge generally do not use

the entire amount of reserved capacity

at all times. This does not mean,

however, that they must permanently

return the unused amount to the utility.

In the absence of evidence of hoarding

or other anticompetitive practices, we

will not limit the amount of

transmission capacity that a customer

may reserve. Firm transmission

customers are in the best position to

know the levels of electric energy they

will be transmitting and the level of

flexibility they need in carrying out

their transmission activities. Indeed,

when they are not using their reserved

capacity, firm transmission customers

remain obligated to pay the utility a

reservation charge that covers all of the

utility’s fixed costs associated with the

reserved capacity.305

Moreover, the possibility that a

customer will reserve capacity and then

hold it without using or reassigning it is

mitigated because the utility is free to

schedule and sell any unscheduled firm

point-to-point transmission capacity on

a non-firm basis to any entity eligible to

receive such service under the utility’s

tariff. We also note that it is in the

economic self interest of reservation

holders to make available unused

capacity to the market.306

We recognize that situations could

arise in which a customer unlawfully

withholds capacity. That is, a

transmission customer could retain

capacity in a way that could have an

anticompetitive effect. For example, a

transmission customer may reserve

certain capacity simply to prevent

everyone else from using it and to make

its own generation the only alternative

available to the market. However, as

described above, we believe that the

incentives are such that parties are more

likely to release unneeded capacity and

that a generic remedy is therefore

unnecessary. Any substantial allegations

that indicate that a transmission

customer is withholding scarce capacity

in a way that has an anticompetitive

effect would be addressed under section

206. If we found such allegations to be

true, we could order the customer to

return the capacity reservation right to

the transmission operator. This

approach should allay concerns that a

customer may reserve scarce capacity

and not use it, without forcing

customers to demonstrate need or to

reveal details of individual transactions.

5. Reservation of Transmission Capacity

for Future Use by Utility

Comments

EEI and many IOUs argue that native

load and network transmission

customers should have first priority to

existing capacity for their reasonably

forecasted load requirements because

that capacity was constructed to provide

service to them and was paid for by

them.307 EEI contends that such priority

ensures equity and comparability based

on past and future cost responsibility for

the system. Similarly, Florida Power

Corp and PECO contend that third-party

customers should not be allowed to use

transmission capacity that native load

customers would grow into within a

reasonable planning horizon.

Other commenters disagree, asserting

that available transmission capacity

must be determined in the same manner

for all customers and that utilities

should not be permitted to reserve

capacity for their own uses.308 NIEP

argues that utilities should not be

permitted to lock up available

transmission capacity over valuable

transmission paths and then require

transmission requesters to pay for the

cost of incremental transmission

upgrades. This would let the utility

avoid incremental transmission charges

on its system. Oklahoma G&E argues

that existing available transmission

capacity should be made available until

it is needed for native load growth.

Utilicorp states that transmission

owners should not be permitted to set

aside capacity for sales or purchases of

economy energy. CCEM argues that the

centerpiece of comparability is that all

transmission customers, including the

merchant operations of the transmission

owner, take service from available

capacity pursuant to the same tariffs.

CCEM adds that allowing utilities to

reserve capacity based on forecasted

retail and network loads creates an

incentive for them to over-forecast their

load to the detriment of all others.

NRECA suggests that the need to

maintain reliability should not

perpetuate transmission providers’

preferential treatment of their own

transactions. It also recommends that,

during periods when facilities are

constrained, access be allocated based

on a combination of past actual use and

planned future use.

Commission Conclusion

We conclude that public utilities may

reserve existing transmission capacity

needed for native load growth and

network transmission customer load

growth reasonably forecasted within the

utility’s current planning horizon.

However, any capacity that a public

utility reserves for future growth, but is

not currently needed, must be posted on

the OASIS and made available to others

through the capacity reassignment

requirements, until such time as it is

actually needed and used.

In response to arguments raised by

several commenters that existing

requirements customers should have

future rights to existing capacity beyond

the terms of their contracts because of

their historical use, as discussed

previously, we believe existing

customers should have a right of first

refusal to capacity they previously used,

if they are willing to match the rate

offered by another potential customer,

up to the transmission provider’s

maximum filed transmission rate at that

time, and to accept a contract term at
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21575

309See Section IV.A.5.

310FERC Stats. & Regs. ¶ 32,514 at 33,088.

311E.g., PacifiCorp, DOJ, NIEP, ELCON, United

Illuminating, DOD, WP&L, FTC. OK Com and FL

Com favor reassignment of capacity, but express

concerns that reliability not be affected.

312E.g., Northern States Power.

313E.g., NEPCO, Nebraska Public Power District.

314E.g., NRECA, Montana Power, PacifiCorp,

NYSEG, PA Com, Idaho, Public Service Co of CO,

FPC, Entergy, TDU Systems, Duke, Cajun, CVPSC,

Oglethorpe, Minnesota DPS. FL Com argues that the

price of reassignment should be capped at the

contract selling price. WP&L argues that the price

cap should be raised to the maximum rate allowed

in the tariff under which the user purchased the

original service.

315See also Minnesota DPS.

316See also Midwest Commissions, SMUD,

CCEM.

317E.g., IL Com, NEPCO, Consumers, American

Wind.

318 If the market is not competitive, however, Con

Ed maintains that the cap should be retained for all

entities.

319E.g., PacifiCorp, NYSEG, Oglethorpe.

320E.g., Oglethorpe, NSP.

321E.g., NYSEG, Entergy, TDU Systems, Turlock,

American Wind.

least as long as that offered by another

potential customer.309

6. Capacity Reassignment

In the NOPR, the Commission

proposed that a tariff must explicitly

permit reassignment of firm service

entitlements.310 We explained that

reassignment of capacity rights could

have a number of benefits: (1) Helping

transmission users manage financial

risk, (2) reducing transmission

providers’ market power by enabling

transmission customers to compete with

them, and (3) improving capacity

allocation when capacity is constrained

and some market participants value

capacity more than current capacity

holders. We requested comments on

whether the current price cap on resale

should be modified or eliminated and

whether the transmission services

described in the NOPR are suitable for

reassignment.

Comments

General

Many commenters favor capacity

reassignment and the development of

secondary markets.311 However, WP&L

notes that reassignments should not be

permitted over constrained interfaces if

the source or destination of power

changes, and LA DWP opposes

unrestricted reassignment because it

could cause tax-exempt financing

problems for many public power

utilities.

Many IOUs argue that the same terms

and conditions of service applied to

IOUs should be applied to resellers of

transmission services.312 Arizona Public

Service, however, asserts that all unused

transmission rights should not be

assignable, but should be made

available to others in a manner

consistent with the contract supporting

the rights. It argues that a network user

experiencing an off-system network

shutdown should be required during the

outage to make available to others the

path from the point that the power

enters the system to its load. It also

contends that firm transmission

customers should be required to post

their unused rights on an EBB or RIN.

Several commenters oppose

mandatory reassignment of firm

capacity rights.313 NEPCO declares that

if a customer is willing to pay for its

reserved capacity, it should not be

forced to reassign unused capacity.

Nebraska Public Power District believes

that mandatory reassignment could

cause problems for publicly-owned

utilities. It further asserts that in the gas

industry the Commission did not allow

the unregulated reassignment regime it

proposes for the electric industry.

SoCal Edison argues that when a

transmission customer resells

transmission capacity, it should not be

released from its contractual obligation

to the transmission provider. It notes

that under traditional contract law, a

party to a contract cannot escape its

obligations by delegating them to

another.

Price Caps

Most commenters addressing this

issue support retaining the existing

price cap on reassignments or resales.314

Generally, these commenters believe

that the price cap is necessary to

prevent customers from speculating or

hoarding capacity in anticipation of its

value increasing. Public Service Co of

CO believes that allowing assignments

of capacity at prices greater than cost

could prevent a transmission provider

from offering firm capacity for

legitimate long-term transactions. TDU

Systems states that a cap should remain

until the secondary market in the

relevant geographic market has been

shown to be competitive. PA Com states

that turning available capacity into a

spot market would tie up capacity that

might otherwise be used on a day-to-day

basis and for emergencies. Still other

commenters argue that customers

should not be allowed to sell the

capacity for more than the transmitting

utility could charge.315 Allegheny argues

that any rule that allows resale of

transmission capacity at a higher price

than the transmission provider can

achieve is ‘‘patently illogical and

probably illegal.’’ Several utilities,

including Allegheny and CSW, contend

that if resellers can market transmission

services at market rates, then

transmission owners must be given the

same opportunity.

Duquesne and United Illuminating

argue that the price cap should be

modified so that third parties are

allowed to resell capacity at the higher

of embedded costs or opportunity

costs.316 Duquesne notes that such a

provision would be comparable to the

option transmitting utilities now have

and would be economically efficient

because it would encourage the firm

capacity owner with the lowest

opportunity cost to resell its capacity.

A few commenters argue that the

price cap should be eliminated.317 IL

Com claims that capacity will be made

available to the entity that values it most

and that an uncapped resale market

cannot lead to more market power

because an efficient secondary market

cannot be monopolized. Con Ed agrees

that if the secondary market is

competitive, all entities should be

allowed to sell at market-based rates.318

CT DPUC argues that there should not

be a price cap; instead, it would prefer

that those holding transmission rights

not be allowed to withhold use of any

portion of their reserved transmission

capacity in the actual moment-bymoment operation of the grid.

Creditworthiness Standards

Of those commenting on the

appropriate creditworthiness standards

for replacement customers (assignees),

all favor allowing the transmission

provider to use reasonable credit

procedures to assure that the

replacement customer is financially

sound.319 NYSEG suggests that, at a

minimum, the same creditworthiness

criteria should be applied to the

replacement customer as are applied to

the original customer. Oglethorpe

recommends that the assignee be

required to commit to comply with all

customer obligations and to pay for any

additional costs resulting from the

assignment.

Liability for Payment

Commenters split on whether the

original customer or the replacement

customer should be liable to the

transmitting utility for payment for the

service. One group of commenters

believes that the original customer

should remain liable for all costs and for

the performance of all obligations.320

Another group of commenters believes

that the original customer should be

relieved of financial responsibility, at

least under certain circumstances.321 For
21576 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

322The transmission provider has the same rights

as any other potential assignee to obtain capacity

that is posted on an OASIS or to negotiate with the

assignor for any capacity the assignor seeks to

assign.

323The public utility’s tariff shall not preclude an

assignor from including a right of recall in its

agreement with an assignee.

324The assignor may also request the transmission

provider to provide the billing and payment

services for the reassignment. The parties would

negotiate terms for such an arrangement, including

a fee for the transmission provider. If an assignor

is a public utility, it will have to have on file with

the Commission a rate schedule governing

reassigned capacity.

325Any expenses that the public utility incurs in

carrying out the capacity assignment program

would simply be included in its cost of service.

326Similar arguments with respect to the

information that public utilities must provide to the

Commission in standard reports (e.g., Form No. 1)

are addressed later in this Final Rule.

327E.g., PacifiCorp, NYSEG, NSP.

328See also PA Com.

example, NYSEG asserts that the

original customer should be relieved of

its obligations upon the execution of a

new service agreement between the new

customer and the provider. TDU

Systems contends that the original

customer should be relieved of future

liability where the replacement

customer meets the transmission

provider’s creditworthiness standards.

Entergy argues that the original

customer should remain liable until all

obligations are fulfilled.

Commission Conclusion

After reviewing the comments, we

conclude that a public utility’s tariff

must explicitly permit the voluntary

reassignment of all or part of a holder’s

firm transmission capacity rights 322 to

any eligible customer.323 Reassignment

may be on a temporary or permanent

basis, and must be subject to the

conditions and requirements discussed

below.

Allowing holders of firm transmission

capacity rights to reassign capacity will:

(1) Help them manage the financial risks

associated with their long-term

transmission commitments, (2) reduce

the market power of transmission

providers by enabling customers to

compete, and (3) foster efficient capacity

allocation. We offer below a number of

clarifications and further explanations

in response to concerns raised by

commenters.

(1) Reassignable Transmission Services

We conclude that point-to-point

transmission service, because it sets

forth clearly defined capacity rights,

should be reassignable. As for network

transmission service, we conclude that

there are no specific capacity rights

associated with such service, and thus,

network transmission service is not

reassignable.

(2) Terms and Conditions of

Reassignments

a. General

In effecting a reassignment, the

assignor does not have to return its

capacity entitlement to the original

transmission provider, but may deal

directly with an assignee without

involvement of the transmission

provider. However, an assignee must

meet the eligibility standard established

by this Rule and must comply with the

reliability criteria of the original

transmission provider. Any such

transaction must be posted on the

transmission provider’s OASIS within a

reasonable time after its effective date.

Alternatively, the assignor may, if it

wishes, request the transmission

provider to effect a reassignment on its

behalf.324 In such a situation, the

transmission provider must

immediately post the available capacity

on its OASIS. The transmission provider

must assure that any revenues

associated with the reassignment are

credited to the assignor.325

b. Contractual Obligations

Assignors and assignees may contract

directly with each other, but the

assignor will remain obligated to the

transmission provider. This obligation

extends to any penalties or other

charges incurred by the assignee in its

use of the reassigned capacity. The

assignee will be liable solely to the

assignor, and should it not meet its

obligations, the assignor may cancel the

assignment under their contract.

If the transmission provider and the

original customer mutually agree, we

will permit alternatives to the above

approach. For example, the

transmission provider could agree to

relieve the original customer of payment

liability for the term of the reassignment

and permit the assignee to pay the

provider directly.

In the case of a permanent

reassignment, the transmission provider

should not unreasonably refuse to

release the assignor from liability if the

assignee meets the transmission

provider’s creditworthiness

requirements as set forth in its tariff and

agrees to pay the price the assignor is

obligated to pay the transmission

provider.

c. Price Cap

We conclude that the rate for any

capacity reassignment must be capped

by the highest of: (1) The original

transmission rate charged to the

purchaser (assignor), (2) the

transmission provider’s maximum

stated firm transmission rate in effect at

the time of the reassignment, or (3) the

assignor’s own opportunity costs

capped at the cost of expansion (Price

Cap). We remain convinced that we

cannot lift the Price Cap and permit

reassignments at market-based rates.

Based upon the information available in

this proceeding, we are unable to

determine that the market for reassigned

capacity is sufficiently competitive so

that assignors will not be able to exert

market power. Thus, we will not permit

an assignor to reassign capacity at a rate

in excess of the Price Cap. Assignees

must agree, in contracting with the

assignor, that the firm transmission

capacity they will use is subject to the

Price Cap.

7. Information Provided to Transmission

Customers Comments

Many commenters argue that in an

open access, competitive environment,

confidential and proprietary

information should not be made

publicly available through a RIN.326

Several utilities assert that the

existing reporting requirements are

sufficient to support the comparability

requirements of the proposed rule, with

some modifications.327 They note that

the Commission’s audit authority and

complaint process will help enforce

comparability requirements.328 Central

Illinois Public Service states that, with

the availability of pricing and

transaction information through the

RIN, no further reporting requirements

are necessary. IL Com states that

additional reporting should be required

only if clear evidence emerges of

discriminatory use of the transmission

system. Dominion Resources adds that

users have no need for utility planning

information and data on generator status

and that disclosure of such information

would place owners at a competitive

disadvantage. VEPCO opposes the

disclosure of any commercially

sensitive information to marketers,

including the utility’s power marketing

employees.

On the other hand, several

commenters argue that the information

submitted by public utilities may not be

adequate. For example, APPA argues

that the Commission should scrutinize

closely cost functionalization by

utilities to assure that plant in service is

properly booked. Others recommend

that the Commission put in place a

monthly pass-through of transmissionrelated operating income for all classes

of customers receiving firm

transmission service, rather than rely on

the current practice of reducing test year
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21577

329The prices of some ancillary services, which

are posted on the OASIS, are based on generation

costs, however.

330Because the Commission establishes many

generation and all transmission rates on a cost

basis, the Commission also will continue to need

the information that it collects in Form No. 1 and

other standard forms from public utilities to assure

that the rates are just and reasonable. As we explain

later in this Final Rule, the information provided

in those forms is public information that is

available to any transmission customer. However,

because of the competitive changes occurring in the

electric industry, we recognize that there may be a

need to reexamine the information we collect from

public utilities through the Form No. 1.

331See also Environmental Action, Missouri

Basin MPA, Texaco, EGA, AEC & SMEPA.

332See also TDU Systems, Public Service Co. of

CO.

333E.g., NARUC, AZ Com, CT DPUC, OK Com, FL

Com, NC Com, NM Com.

334E.g., Com Ed, Citizens Utilities, PacifiCorp.

335E,g,, Allegheny Power, PacifiCorp,

MidAmerican, PECO, Public Service Co. of CO,

Com Ed, NARUC, NRRI, MN DPS, ND Com, FL

Com.

336E.g., Allegheny Power.

337E.g., CCEM, ABATE.

cost of service by revenues booked to

Accounts 456 and 447. Industrial

Energy Applications recommends that

utilities be required to file quarterly

reports with the Commission that detail

the transmission services and the

pricing of their off-system power supply

transactions, as an incentive to comply

with the Commission’s rule.

Commission Conclusion

We conclude that all necessary

transmission information, as detailed in

the OASIS final rule, must be posted on

an OASIS. With respect to generation

information, we will require, consistent

with the OASIS final rule, that

information needed to verify

opportunity/redispatch costs be

provided, on request, to the

transmission customer charged. We will

not require this information, or any

other generation information,329 to be

posted on an OASIS.330

8. Consequences of Functional

Unbundling

a. Distribution Function

The NOPR proposed functional

unbundling of wholesale generation and

wholesale transmission so that the

public utility as a wholesale seller could

not gain an undue advantage from its

transmission ownership. We did not

propose to further unbundle the retail

transmission and distribution functions

from the wholesale transmission

function.

Comments

A number of commenters assert that

utilities should be required to

unbundle—either functionally or

corporately—the distribution function

from the transmission function. ELCON

argues that unbundling distribution

would help delineate state and Federal

jurisdiction, facilitate the establishment

of transmission pricing, avoid crosssubsidization, and prepare for the

customer choice (retail wheeling)

programs that will be implemented by

states in the future. It contends that

functional distinctions between

wholesale and retail service should be

minimized.331

Other commenters, however, oppose

establishing a separate distribution

function. DOD asserts that the

Commission can address any problems

that arise by enforcing the terms of open

access tariffs and that the Commission

should not intrude into state

ratemaking.332

Various state commissions question

the workability and desirability of a

functional test to determine the dividing

line between retail transmission and

local distribution.333 CA Com

recommends that, to avoid jurisdictional

uncertainty surrounding functional

unbundling, the Commission adopt a

functional test for local distribution.

Under this test, vertically integrated

utilities that chose to unbundle into

separate operating companies, including

a local distribution company that sells

only at retail, could establish a workable

bright line between state and Federal

authority without engaging in the

arduous task of differentiating

transmission from distribution.

Certain IOUs echo the jurisdictional

concerns raised by the state

commissions.334 They believe that the

unbundling of the distribution function

would create significant jurisdictional

problems. Pacificorp also argues that

unbundling of the distribution function

would create significant jurisdictional

conflict with respect to cost allocation.

Commission Conclusion

We conclude that the additional step

of functionally unbundling the

distribution function from the

transmission function is not necessary

at this time to ensure nondiscriminatory open access

transmission. Our approach to assuring

such open access has two broad

requirements: (1) Functional

unbundling of transmission and

generation (which includes separately

stated rates for generation, transmission,

and ancillary services, and a

requirement that a transmission

provider take service under its own

tariff), except for bundled retail service

and (2) an OASIS with standards of

conduct. We believe that additional

requirements are not needed now. We

further address in Section IV.I the

concerns raised regarding our proposed

tests to distinguish transmission and

local distribution.

b. Retail Transmission Service

Comments

The majority of commenters

addressing this issue believe that

unbundling retail service is unnecessary

to establish a competitive market and to

achieve non-discriminatory open access

transmission.335 For example, PSNM

argues that the Commission is not as

well situated as are state regulators to

oversee and supervise local reliability

issues for retail customers. Central

Illinois Public Service argues that due to

the nature of transmission facilities and

operations, it is not possible for the

transmission provider to discriminate

between the provision of wholesale and

retail firm service. Several IOUs further

contend that because the Commission is

specifically precluded from mandating

retail wheeling and has no authority

over bundled retail service, the

Commission cannot require retail

service to be provided.336

In contrast, some commenters argue

that functional unbundling must apply

to all transmission service in interstate

commerce provided by public utilities,

including the transmission component

of bundled retail sales.337 They believe

that this is necessary to achieve

comparability. For example, CCEM

asserts that if the distribution function

is not unbundled, the result will be

service under two separate

arrangements—an explicit wholesale

transmission tariff filed at the

Commission and an implicit retail

transmission tariff governed by a state

regulatory body. According to CCEM,

failure to unbundle retail transmission

will allow transmitting utilities to

manipulate how they characterize and

account for their own uses of

transmission. ABATE contends that the

Commission, for efficiency reasons,

should encourage states to permit retail

access. It asserts that the Commission

must adopt a policy that signals to states

how rates, terms, and conditions of

retail service will be established; once a

state sets such parameters, the

Commission should review them.

Commission Conclusion

Although the unbundling of retail

transmission and generation, as well as

wholesale transmission and generation,

would be helpful in achieving

comparability, we do not believe it is

necessary. In addition, it raises

numerous difficult jurisdictional issues
21578 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

338But see discussion of buy/sell transactions in

Section IV.I.

339FERC Stats. & Regs. ¶ 32,514 at 33,080.

340E.g., Michigan Systems, Cleveland, Municipal

Energy Agency Nebraska, Missouri Basin MPA,

TAPS, Wisconsin Municipals, LG&E, NIEP, CCEM.

341With the exception of certain contracts and

agreements executed on or before 60 days after

publication of the Final Rule in the Federal

Register, the regulation we are adopting requires

that public utilities take service under their open

access tariff for wholesale sales or purchases of

electric energy and unbundled retail sales of

electric energy, effective on the date the public

utility engages in such transactions.

342As discussed in Section IV.F., the Commission

will not impose this requirement on existing

bilateral non-economy coordination agreements, but

persons may file complaints that such agreements

need to be modified.

343E.g., EEI, Con Ed, VEPCO.

344See also NEPCO.

345See also Florida Power Corp.

that we believe are more appropriately

considered when the Commission

reviews unbundled retail transmission

tariffs that may come before us in the

context of a state retail wheeling

program. The Commission therefore

reaffirms its decision to require the

unbundling only of wholesale

transmission from generation.338

c. Transmission Provider

1. Taking Service Under the Tariff

In the NOPR, we explained that a

public utility must take transmission

services for all of its new wholesale

sales and purchases of energy under the

same tariff of general applicability

under which others take service.339

Comments

A number of commenters argue that

utilities should be required to take all of

the transmission for their own use

under their tariff.340 CCEM asserts that

a transmission owner should have to

schedule, at arm’s length, its retail

transmission uses and pay posted rates

into a separate account; otherwise the

capacity might be overforecast at no

cost.

PECO requests that the Commission

clarify that the requirement that a

transmission provider take service

under its own transmission tariffs does

not apply to: (1) Retail service, (2)

existing wholesale contracts, and (3)

pooling arrangements. UNITIL claims

that the requirement for a transmission

provider to take service under its own

tariff and to post its own tariff rate

should not apply to pool transactions

where a single pool-wide rate is applied.

A number of IOUs contend that it is

not necessary for the transmission

provider to take service under the

network tariff because both the

transmission provider and the network

customers cannot use the tariff to make

off-system sales. LILCO states that it is

appropriate to distinguish between a

transmission owner’s use of its

transmission system to make: (1)

Wholesale bulk power sales; and (2) offsystem purchases to serve its native load

retail customers. LILCO contends that in

the second situation it should not be

required to take transmission service

under its own open access tariffs.

EGA argues that transmission owners

should be required to take transmission

service under open access tariffs for

both wholesale off-system sales and

purchases. It maintains that, as retail

competition increases, utilities will

eventually have to take retail service

under their own tariffs. Power

Marketing Association believes that

comparability can be achieved only if

transmission service provided in

connection with coordination

transactions is unbundled and the

transmission provider takes such

transmission service under its tariff.

Consumers Power also claims that

there is an inconsistency between the

NOPR text, the tariffs, and the proposed

regulatory language regarding whether

the requirement for a utility to take

service under its own tariff applies only

to new wholesale transactions.

Commission Conclusion

We conclude that public utilities must

take all transmission services for

wholesale sales under new requirements

contracts and new coordination

contracts under the same tariff used by

others (eligible customers).341 For sales

and purchases under existing bilateral

economy energy coordination

agreements, we will give an extension

until December 31, 1996, for public

utilities to take transmission service

under the same tariff used by others.342

As further discussed in Section IV.F.,

we will also give an extension of time

to December 31, 1996, for certain

existing power pooling and other multilateral coordination agreements to

comply with this requirement. This will

ensure that utilities live by their own

rules for wholesale transactions and that

we can achieve non-discriminatory

open access transmission. In the case of

a public utility buying or selling at

wholesale, the public utility must take

service under the same tariff under

which other wholesale sellers and

buyers take service.

2. Accounting Treatment

In the NOPR, we did not address any

accounting aspects of our proposed rule.

Comments

IOUs generally object to a requirement

that they pay themselves for their use of

the transmission system.343 NEPCO

claims that it is a general principle of

accounting that an enterprise cannot

recognize and record revenues to itself.

NEPCO suggests that, to ensure that

utilities’ financial statements are not

misleading, this aspect of functional

unbundling can and should be

accomplished through the ratemaking

process, rather than by requiring

utilities to actually charge themselves

revenues for taking transmission

services.344

Atlantic City Electric states that the

added costs of properly administering

and accounting for these transactions

separately will increase prices to

ultimate consumers. It contends that

ensuring that operators do not give

undue preference to transactions of the

transmission provider makes it

unnecessary for a utility to charge itself.

CSW argues that some of the

provisions of the tariffs were

specifically designed for third parties

and do not make sense as applied to the

transmission provider (e.g., signing

service agreements and running credit

checks).345

Most IOUs suggest that a revenue

credit mechanism be used to account for

a transmission provider’s use of its

system. Florida Power Corp states that

revenue credits should be equal to the

utility’s posted rates for transmission

service multiplied by the amount of

capacity reserved and/or energy

transmitted by the utility.

Otter Tail proposes a revenue credit

that allocates revenues based on use

under the tariff of the utility’s

transmission investment and credits

these revenues against the firm load

customers’ accounts.

Duke asserts that the transmission

provider should maintain records

reflecting transmission for its own

transactions under the tariff and

develop appropriate revenue credits for

transmission rates. It also believes that

all firm users of the transmission system

should receive credits for all non-firm

uses.

Allegheny Power states that the

crediting of non-firm revenues to

network customers would have to be

done on an after-the-fact basis when

their loads would be known. However,

it believes that revenue crediting should

occur only if the firm service customer

has retained the utility to remarket the

customer’s unused capacity.

Cajun proposes that all transmission

revenues in excess of those implicitly

included in the development of the

transmission rates, including those that

the utility has charged itself, be credited
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21579

346 If the utility is not required to file a Form No.

1, PacifiCorp states that it should be required to file

similar information annually.

347E.g., Consumers Power, Northern States Power,

PacifiCorp, Allegheny Power.

348Additional guidance on this subject is in

Section IV.G.4.g.(2)(a).

back to the network service

transmission customers on a load ratio

share basis. If transmission service rates

are formula rates that are recalculated

annually, Cajun proposes that excess

transmission revenues be used to offset

the recalculated revenue requirement. If

the rates are not formula rates, Cajun

states that an explicit tracker with

monthly crediting to the network

customer must be used.

To avoid cross-subsidization between

affiliates and third parties, NRECA

suggests that transmission revenues

‘‘paid’’ by a utility’s generation function

to its transmission function be credited

back to the utility’s nonaffiliated

customers, and that any rate discounts

extended to the generation function by

the transmission function be filed with

the Commission with a full explanation

of why the discount was extended

together with a showing that the

discount was made available to all other

similarly situated customers.

APPA contends that the

Commission’s current system of revenue

crediting could give transmission

owners an unfair competitive advantage

by allowing them to use the revenue

credit to subsidize the price at which

they sell power. It argues that

transmission owners should pay the

actual price of transmission rather than

booking a revenue credit as an offset to

the cost of transmission service.

TAPS and Wisconsin Municipals

argue that an essential element of true

comparability is the ongoing passthrough to network customers of a load

ratio share of transmission revenues

generated by third-party and the

transmission provider’s off-system uses

of the transmission system.

Houston L&P suggests that the

revenue crediting mechanism proposed

in the NOPR could be established to

recognize the utility’s transmission

service revenue and expenses in nonthird-party wheeling transactions by

reclassifying a portion of its revenue

equal to the cost of transmission

services provided to itself during such

transactions. This mechanism would

not reclassify expense accounts, but

would distinguish that transmission

portion of the total transaction’s revenue

that was associated with covering the

cost of transmission service, using the

rates charged in similar third-party

transactions.

PacifiCorp contends that the

Commission should enforce the

requirement that utilities account for

revenues they pay themselves through

the commission’s audit powers and

through complaint proceedings. It

specifically recommends that each

transmitting utility be required to

indicate, in its Form No. 1 under

Account 456, the megawatts and

revenues associated with its firm and

non-firm off-system sales.346

MT Com states that the embedded

costs that the Commission

functionalizes for jurisdictional

purposes should be carefully reconciled

with plant balances used to calculate

other costs of service.

CCEM wants each transmission

provider to charge and book revenues

into separate accounts for (1) service

provided to itself and off-system sales

and third-party sales under the tariffs,

(2) impact study costs that the provider

performs for itself or an affiliate, and (3)

ancillary service revenues, net of out-ofpocket expenses the transmission owner

provides itself or an affiliate.

Arizona Public Service recommends

that any revenue crediting or booking be

prospective only and that enforcement

occur through the Commission’s

periodic audits and a utility’s rate cases.

Many IOUs argue that there should be

no obligation to credit non-firm

transmission revenues to customers who

are not using their firm capacity.347

PacifiCorp contends that all non-firm

revenues should be credited against

total annual revenue requirements,

resulting in lower rates to all customers.

Wisconsin P&L maintains that non-firm

sales revenue should be shared with all

network customers.

Otter Tail argues that non-firm

transactions between existing utilities to

support and achieve real-time system

optimization should be permitted

without charge to the transmission

owner. CSW asserts that no credits

should be made for the non-firm

secondary service under the point-topoint tariff and that off-system

purchases for native load should not

result in a revenue credit.

Southwestern suggests that the

Commission not require the crediting of

a transmission component associated

with off-system purchases by the public

utility. Southwestern argues that a

credit would interfere with a utility’s

ability to buy the most economic energy

for its native load customers. It also

argues that requiring a credit is not

comparable to what network customers

pay. NEPCO points out that crediting

transmission associated with purchases

would require native load customers to

pay the costs of the utility’s purchasing

off-system power while network

customers do not have to pay a separate

point-to-point charge for their offsystem purchases. Southwestern claims

that the crediting requirement would

double-charge the transmitting utility

and its native load customers because a

utility’s off-system purchases directly

relate to the load it serves, and that load

already is reflected in the transmission

rate calculation. Southwestern also

claims that it is unclear from the NOPR

whether the Commission considers sales

from the renewal of existing wholesale

requirements contracts as being subject

to crediting. It argues that transmission

related to these sales should not be

subject to the crediting requirement

because this is service to native load

customers.

Brazos opposes imputing revenues

associated with a utility’s own use of its

transmission system because this will

artificially increase the cost of power

and deny consumers the benefits of

economy energy sales made at marketbased prices.

Commission Conclusion

While we used the word ‘‘accounting’’

in the NOPR, the real issue is assuring

that utilities bear the costs associated

with their own uses of the system in a

manner comparable to how they charge

others. Accordingly, this is a rate issue,

not an accounting issue. However, we

direct utilities to account for all uses of

the transmission system and to

demonstrate that all customers

(including the transmission provider’s

native load) bear the cost responsibility

associated with their respective uses.348

D. Ancillary Services

In the NOPR, the Commission stated

that several ancillary services are

needed to provide basic transmission

service to a customer. These services

range from actions taken to effect the

transaction (such as scheduling and

dispatching services) to services that are

necessary to maintain the integrity of

the transmission system during a

transaction (such as load following and

reactive power support). Other ancillary

services are needed to correct for the

effects associated with undertaking a

transaction (such as energy imbalance

service).

We proposed six ancillary services to

be offered in an open access

transmission tariff, which we called (1)

scheduling and dispatching services, (2)

load following service, (3) energy

imbalance service, (4) system protection

service, (5) reactive power/voltage

control service, and (6) loss

compensation service. We requested
21580 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

349Of course, public utilities would have to have

a rate schedule on file to provide other

jurisdictional interconnected operations services.

350A control area is part of an interconnected

power system with a common generation control

system. It may contain one or several utilities. The

operator of the control area is responsible for

balancing generation and load and for maintaining

reliable system operation.

351E.g., Oak Ridge, Houston L&P, Carolina P&L,

NYPP.

352Oak Ridge originally identified nineteen

ancillary services, which included a recommended

separation of the six NOPR ancillary services into

twelve services and seven additional new services.

comments on all aspects of ancillary

services, including whether the

identified ancillary services are

appropriately defined, whether other

services should be included, and how

these services should be supplied.

Commenters identified a number of

other services that may be provided as

part of interconnected operations. After

considering the comments, we conclude

that the following six ancillary services

must be included in an open access

transmission tariff:

(1) Scheduling, System Control and

Dispatch Service;

(2) Reactive Supply and Voltage

Control from Generation Sources

Service;

(3) Regulation and Frequency

Response Service;

(4) Energy Imbalance Service;

(5) Operating Reserve—Spinning

Reserve Service; and

(6) Operating Reserve—Supplemental

Reserve Service.

A description of these services and

our reasons for designating them as

ancillary services are included in

section 1 below. We also discuss in that

section our rationale for excluding other

services from the list of ancillary

services that must be included in an

open access transmission tariff. In

section 2 below, we discuss which of

the six ancillary services the

transmission provider must provide or

offer to provide to transmission

customers, and which the transmission

customer must purchase from the

transmission provider. These

requirements are summarized as

follows:

(1) Scheduling, System Control and

Dispatch Service (Transmission

Provider must provide and

Transmission Customer must purchase

from Transmission Provider);

(2) Reactive Supply and Voltage

Control from Generation Sources

Service (Transmission Provider must

provide and Transmission Customer

must purchase from Transmission

Provider);

(3) Regulation and Frequency

Response Service (Transmission

Provider must offer to provide only to

Transmission Customer serving load in

Transmission Provider’s control area

and Transmission Customer must

acquire, but may do so from

Transmission Provider, a third party or

self supply);

(4) Energy Imbalance Service

(Transmission Provider must offer to

provide only to Transmission Customer

serving load in Transmission Provider’s

control area and Transmission Customer

must acquire, but may do so from

Transmission Provider, a third party or

self supply);

(5) Operating Reserve—Spinning

Reserve Service (Transmission Provider

must offer to provide only to

Transmission Customer serving load in

Transmission Provider’s control area

and Transmission Customer must

acquire, but may do so from

Transmission Provider, a third party or

self supply); and

(6) Operating Reserve—Supplemental

Reserve Service (Transmission Provider

must offer to provide only to

Transmission Customer serving load in

Transmission Provider’s control area

and Transmission Customer must

acquire, but may do so from

Transmission Provider, a third party or

self supply).

Our requirement that these six

ancillary services be included in an

open access transmission tariff does not

preclude the transmission provider from

offering voluntarily to provide other

interconnected operations services to

the transmission customer along with

the supply of basic transmission service

and ancillary services.349

1. Definitions and Descriptions

Comments

Commenters generally agree that some

ancillary services are needed for

transmission of power. Some

commenters, however, argue for a

different name or description for the

ancillary services we proposed in the

NOPR. Others argue for a more

extensive list of services.

EEI believes that the term ‘‘ancillary’’

is a confusing description because the

services are integral to providing

transmission service. NERC, PSE&G,

and others claim that ancillary services

are not, as the term ‘‘ancillary’’ implies,

subordinate or auxiliary to the

transmission of power; rather such

services are conjunctive and required to

allow reliable operation of an electric

system. BG&E and others contend that

ancillary services should be defined as

services for control area operation,350

and not as services provided by an

individual, noncontrol area utility.

NERC proposes, and many IOU

commenters support, an alternative

name for these services, ‘‘Interconnected

Operations Services.’’ NERC contends

that the alternative name better reflects

the fact that the services are needed in

the broader context of allowing control

areas, transmission customers, and other

operating entities to operate reliably and

equitably.

Some commenters propose a greater

number of ancillary services. They argue

that the services we proposed can be

broken down into more discrete

functions. A number of commenters

provide rather lengthy lists of possible

ancillary services to supplement those

identified in the NOPR.351

NERC identifies twelve services,

which it groups into three broad

categories: interchange scheduling

services, generation services, and

transmission services. NERC’s proposed

interconnected operations services are:

(a) interchange scheduling services:

(1) System control and dispatch

services; and

(2) Accounting;

(b) generation services:

(1) Regulation service;

(2) Energy imbalance service;

(3) Frequency response service;

(4) Backup supply service;

(5) Operating reserve service:

spinning reserve and supplemental

reserve services;

(6) Real power loss service;

(7) Reactive supply (from generation

resources) and voltage control service;

and

(8) Restoration service; and

(c) Transmission services:

(1) Facilities use; and

(2) Reactive supply (from

transmission resources).

NERC also identifies dynamic

scheduling as a unique type of dispatch

service that control areas must have

responsibility over to ensure reliability.

Houston L&P proposes a substitute

list of twenty services. NYPP proposes

a substitute list of thirty-eight

‘‘unbundled components for

transmission service,’’ which include

twelve generation-related services and

twenty-six operations-related services.

Oak Ridge recommends that the

Commission consider using seven

ancillary services, which closely

conform to the six services described in

the NOPR.352 Although Oak Ridge

identifies several additional ancillary

services, it recommends that these

services not be included in the list of

services to be required because they

cannot be measured or because the cost
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21581

353NERC indicates that the list of services is a

work in progress and therefore may not be a

complete list. NERC has formed an independent

Interconnected Operations Services Working Group

(Working Group). The Working Group includes

representatives with a broad range of industry

interests (transmission-dependent, partial

requirements, IPP, transmission-owning, public

power). We encourage this effort and will consider

future changes to the list of ancillary services or

their descriptions to reflect the further development

of concepts in this area.

354See, e.g., APPA.

355E.g., EEI, NERC, NYSEG, FPL, NSP.

356See also APPA.

of metering and billing outweighs the

cost of these services.

Commission Conclusion

We will adopt NERC’s

recommendations for definitions and

descriptions with modifications.

Starting with NERC’s Interconnected

Operations Services, we identify some

of these as ancillary services that must

be offered with basic transmission

service under an open access

transmission tariff.353 The definitions

developed by NERC for the individual

services reflect the current position of a

broad spectrum of experts on the subject

of interconnected operations. Adoption

of NERC’s terminology will provide a

more universally accepted set of

definitions of services. We will retain

the term ‘‘ancillary services,’’ which

will refer to those interconnected

operations services that we will require

transmission providers to include in an

open access transmission tariff.

The interconnected operations

services identified by NERC incorporate

all of the ancillary services proposed in

the NOPR. We believe, however, that

several of the individual services

identified by NERC do not warrant

classification as unbundled ancillary

services due to the small cost involved

(e.g., accounting). NERC also has

identified services that, while capable of

being provided in the context of

integrated operations, are more

appropriately provided for in a separate

service agreement or other contractual

arrangement (e.g., dynamic scheduling,

loss compensation service). NERC and

others have attempted to identify all

interconnected operation services that

could be provided by a control area. The

thoroughness of the comments received

on this issue has been invaluable to the

Commission’s deliberations.

We will require that an open access

transmission tariff include the six

ancillary services that we have

identified as necessary for the

transmission provider to offer to

transmission customers. These are

needed to accomplish transmission

service while maintaining reliability

within and among control areas affected

by the transmission service. Other

interconnected operations services, such

as loss compensation service, may be

provided by the transmission provider

or third parties to facilitate a particular

transaction or operating arrangement.

We will not require other

interconnected operations services as

part of an open access transmission

tariff. If a transmission provider

supplies such services voluntarily, they

may be added to a customer’s service

agreement with the transmission

provider.

As mentioned, we will adopt NERC’s

definitions with modifications, and we

name and describe the six ancillary

services below. After each service name,

we list in parenthesis the service name

in the NOPR that most closely

corresponds to the service defined. In

the discussion, we explain whether and

how we modified NERC’s term.

a. The Six Ancillary Services

(1) Scheduling, System Control and

Dispatch Service (in the NOPR:

Scheduling and Dispatching Service)

Comments

NERC proposes a System Control and

Dispatch Service, which provides for (i)

interchange schedule confirmation and

implementation with other control

areas, including intermediary control

areas that are providing transmission

service, and (ii) actions to ensure

operational security during the

interchange transaction. A transmission

customer may schedule interchange

with another control area operator or

with another entity inside another

control area; however, the control area

operators are responsible for confirming

and implementing the interchange into

or out of their respective areas on behalf

of the transmission customer.

NERC also proposes a separate

Accounting Service, which provides for

energy accounting and billing services

associated with interchange. Accounting

Service would be provided by the

operator of the control area in which the

transmission service takes place.

Commission Conclusion

We adopt ‘‘Scheduling, System

Control and Dispatch’’ as the name for

an ancillary service. It substitutes for the

NOPR’s Scheduling and Dispatching

Service.

The name is NERC’s recommendation

with two modifications. First, we

include the term ‘‘scheduling’’ in the

name of this service because a control

area operator/transmission provider

must take on the function of scheduling

on behalf of customers. Second, we will

not require Accounting as a separate

ancillary service. The purpose of

separating accounting as a stand-alone

service would be to allow customers to

take it separately from scheduling and

system control. However, we believe

that accounting for scheduling, system

control and dispatch is not separable

from these other functions and that

accounting costs are likely to be small.

Therefore, accounting does not warrant

separate service status. The cost of

accounting for these services should be

included in the cost of Scheduling,

System Control and Dispatch Service.

(2) Reactive Supply and Voltage Control

From Generation Sources Service

(Formerly Reactive Power/Voltage

Control Service)

Comments

A number of commenters explain that

reactive power and voltage control

service is integrally related to the

reliable operation of the transmission

system. These commenters also note

that reactive power and voltage support

must be supplied at the location where

it is needed.354 It cannot be provided by

a distant supplier.355

NERC indicates that reactive supply is

necessary to maintain the proper

transmission line voltage for the

transaction. NERC states that reactive

supply is provided from both generation

resources and transmission facilities

(e.g., capacitors), and lists its provision

as two services, distinguished by the

facilities that supply them.356 NERC

further distinguishes reactive supply

service based on the source of the need

for the service: (1) Reactive supply

needed to support the voltage of the

transmission system and (2) reactive

supply needed to correct for the reactive

portion of the customer’s load at the

delivery point.

Commission Conclusion

We adopt ‘‘Reactive Supply and

Voltage Control from Generation

Sources’’ as the name for an ancillary

service. It substitutes for the NOPR’s

Reactive Power/Voltage Control Service.

We accept NERC’s identification of

two ways of supplying reactive power

and controlling voltage. One is to install

facilities, usually capacitors, as part of

the transmission system. We will

consider the cost of these facilities as

part of the cost of basic transmission

service. Providing reactive power and

voltage control in this way is not a

separate ancillary service.

The second is to use generating

facilities to supply reactive power and

voltage control. This use is the service
21582 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

357The ability to reduce reactive power

requirements will be affected by the location and

operating capabilities of the generator. Any

arrangement for the customer to self-supply a

portion of reactive supply should be specified in

the transmission customer’s service agreement with

the transmission provider.

358Transmission providers may propose delivery

point power factor standards, including additional

(penalty) charges for failure to maintain specified

power factors, in service agreements with

customers. We will evaluate the reasonableness of

any such proposals by public utilities to determine

whether they conform to prudent utility practices

and are comparable to requirements imposed by the

utility on other customers, including the utility’s

own requirements customers, and are otherwise just

and reasonable.

359Separation of reactive supply and voltage

control from basic transmission service also may

contribute to the development of a competitive

market for such service if technology or industry

changes result in improved ability to measure the

reactive power needs of individual transmission

customers or the ability to supply reactive supply

from more distant sources. We recognize that these

capabilities may not be fully developed at present

and the ability to distinguish the reactive power

needs of individual customers may be limited at

first to generator control and power factor

correction.

360E.g., NERC, EEI, Florida Power Corp.

361E.g., NERC, EEI.

362E.g., EEI, Florida Power Corp, TVA,

Wollenberg.

named here, which must be unbundled

from basic transmission service.

We note, however, that customers

have the ability to reduce (but not

eliminate completely) the reactive

supply and voltage control needs and

costs that their transactions impose on

the transmission provider’s system. For

example, customers who control

generating units equipped with

automatic voltage control equipment

can use those units to respond to local

voltage requirements and thereby

reduce a portion of the reactive power

requirements associated with their

transaction.357

In addition, transmission customers

that serve loads can minimize the

reactive power demands that they

impose on the transmission system by

maintaining a high power factor at their

delivery points. A poor power factor at

a customer’s delivery point creates a

need for either transmission reactive

facilities (i.e., capacitors) or local

generator-supplied voltage support.358

However, these transmission

customer actions do not eliminate

entirely the need for generator-supplied

reactive power. The transmission

provider must provide at least some

reactive power from generation sources.

For this reason, and because a

transmission customer has the ability to

affect the amount of reactive supply

required, we will require that reactive

supply and voltage control service be

offered as a discrete service, and to the

extent feasible, charged for on the basis

of the amount required.359

(3) Regulation and Frequency Response

Service (in the NOPR: Load Following

Service)

Comments

Someone must supply extra

generating capacity, called regulating

margin, to follow the moment-tomoment variations in the load located in

a control area. Following load variations

is necessary to maintain scheduled

interconnection frequency at sixty

cycles per second (60 Hz).

NERC and others support the need for

someone to provide load following

service to have generation follow a

transmission customer’s load changes;

someone must supply power to meet

any difference between a customer’s

actual and scheduled generation.

Usually, the control area operator

provides this service, but it is possible

for a customer to arrange for someone

else to follow its variations in load.

Many commenters indicate that the

industry commonly refers to this service

as ‘‘Regulation Service.’’ 360

Also, NERC proposes that Frequency

Response Service be identified as a

related but distinct service. NERC

indicates that all control areas are

expected to have generation and control

equipment to respond automatically to

frequency deviations in their networks.

Commission Conclusion

We adopt ‘‘Regulation and Frequency

Response’’ as the name of an ancillary

service. It substitutes for the NOPR’s

Load Following Service. This name

conforms to the terminology

recommended by NERC.

We conclude that Regulation Service

and Frequency Response Service are the

same services that make up the Load

Following Service referenced in the

NOPR. While the services provided by

Regulation Service and Frequency

Response Service are different, they are

complementary services that are made

available using the same equipment. For

this reason, we believe that Frequency

Response Service and Regulation

Service should not be offered separately,

but should be offered as part of one

service.

(4) Energy Imbalance Service (the Same

in the NOPR)

Comments

Many commenters explain that

Energy Imbalance Service, as proposed

in the NOPR, is necessary when

transmission service is provided in a

control area that contains the load being

served.361 Energy Imbalance Service

supplies any hourly mismatch between

a transmission customer’s energy supply

and the load being serving in the control

area. That is, this service makes up for

any net mismatch over an hour between

the scheduled delivery of energy and

the actual load that the energy serves in

the control area. In contrast, Regulation

and Frequency Response Service

corrects for instantaneous variations

between the customer’s resources and

load, even if over an hour these

variations even out and require no net

energy to be supplied.

Commission Conclusion

We will adopt ‘‘Energy Imbalance’’ as

the name for an ancillary service. This

is the same name proposed in the

NOPR. NERC’s description is the same

as the service proposed in the NOPR.

(5) Operating Reserve—Spinning

Reserve Service and

(6) Operating Reserve—Supplemental

Reserve Service (in the NOPR These

Two Were Formerly System Protection

Service)

Comments

Many commenters express confusion

regarding the NOPR term ‘‘system

protection.’’ They indicate that the term

‘‘system protection,’’ is described in the

NOPR as furnishing operating reserve,

but has another meaning in the

industry.362

Operating reserve is extra generation

available to serve load in case there is

an unplanned event such as loss of

generation. Generation held for

operating reserve should be located near

the load, typically in the same control

area. Operating reserve amounts are set

by the region, subregion, or a reserve

sharing group in which the transmission

customer’s load is electrically located.

NERC and other commenters

recommend the commonly-used name,

‘‘operating reserve,’’ for this service.

NERC also indicates that there are two

types of operating reserve: spinning

reserve and supplemental reserve.

Spinning reserve is provided by

generating units that are on-line and

loaded at less than maximum output.

They are available to serve load

immediately in an unexpected

contingency, such as an unplanned

outage of a generating unit.

Supplemental reserve is also

generating capacity that can be used to

respond to contingency situations.

Supplemental reserve, however, is not

available instantaneously, but rather

within a short period (usually ten
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21583

363 In addition, NERC designates ‘‘facilities use

service’’ as an interconnected operations service.

We note that the facilities use service described by

NERC is simply basic transmission service, which

must be provided under an open access tariff. We

do not consider facilities use service to be an

ancillary service.

364See, e.g., Portland, APPA, PacifiCorp, EEI.

365 If a transmission provider does not charge for

transmission used to supply losses for its own

wholesale power sales and purchases, it may not

charge others. If it charges others, it must charge for

its own uses.

366E.g., Detroit Edison, El Paso, FPL, Minnesota

P&L, NIPSCO.

minutes). Supplemental operating

reserve is provided by generating units

that are on-line but unloaded, by quickstart generation, and by customerinterrupted load, i.e., curtailing load by

negotiated agreement with a customer to

correct an imbalance between

generation and load rather than

increasing generation output.

Commission Conclusion

We adopt Operating Reserve—

Spinning Reserve Service and Operating

Reserve—Supplemental Reserve Service

as the names of two related, but distinct,

ancillary services. They substitute for a

single ancillary service in the NOPR,

System Protection Service. The names

conform to the terminology

recommended by NERC. We distinguish

them because these services may be

subject to different reliability

requirements; the resources that supply

each service may not be the same; and

the two services may be provided by

different suppliers.

b. Other Services Discussed in the

NOPR

Commenters discussed whether two

other services that were discussed in the

NOPR should be designated as ancillary

services.363 Although we do not

designate these as ancillary services for

purposes of this Rule, we discuss the

names and descriptions here so that we

can discuss our policy regarding these

services.

(1) Real Power Loss Service (in the

NOPR: Loss Compensation Service)

In the NOPR, we proposed that Loss

Compensation be an ancillary service.

Comments

NERC recommends the term, ‘‘Real

Power Loss,’’ to refer to energy

consumed in transmission, much of it

by resistance heating of the lines and

transformers. Many parties, including

NERC, comment that there are a number

of ways to compensate the transmission

provider for the losses that occur in

providing transmission service. They

indicate that real power loss service can

be obtained from a variety of sources,

such as the power supplier, the

customer, a third-party, the

transmission provider, or another

control area. Also, the loss is commonly

accounted for by a transmission

customer receiving less energy at the

point of delivery than it provides to the

transmission provider at the point of

receipt. The difference between

delivered and received energy can be set

equal to the energy lost in transmission.

Commission Conclusion

We adopt the term ‘‘Real Power Loss’’

as the name of this interconnected

operations service. It substitutes for the

Loss Compensation service described in

the NOPR. This name conforms to the

terminology recommended by NERC.

Although proposed as an ancillary

service in the NOPR, we will not require

that Real Power Loss be included as an

ancillary service in an open access

transmission tariff. It is not necessary to

require the transmission provider to

supply energy losses to the transmission

to ensure comparable transmission

access. Real Power Loss is more

appropriately an interconnected

operations service that transmission

providers may offer voluntarily to

provide to transmission customers.

It is not necessary for the transmission

provider to supply Real Power Loss to

effect a transmission service transaction.

The transmission provider is not

uniquely situated to provide Real Power

Loss service to its customers, nor does

it have a comparative advantage over

anyone in providing such a service.

Indeed, to require the transmission

provider to provide this service would

effectively obligate the transmission

provider to engage in a sale of power

when such a sale is not needed to effect

the transmission service transaction.

As noted in the comments, customers

have several options to cover losses that

occur when electricity moves across

transmission facilities.364 The

availability of open access permits the

customer to obtain energy losses from

many regional suppliers.

Although we will not require the

transmission provider to supply Real

Power Loss to the transmission

customer nor require the customer to

purchase it from the transmission

provider, the customer must make

provision for Real Power Loss. It cannot

take basic transmission service without

such a provision. A customer seeking

transmission service must bring to the

transaction sufficient energy and

capacity to replace the losses associated

with its intended transaction.365

Consequently, we will require that the

transmission customer’s service

agreement with the transmission

provider identify the party responsible

for supplying real power loss. In

addition, we will require that the

transmission provider indicate, either in

its tariff or on its OASIS, what the

energy and capacity loss factors would

be for any transmission service it may

provide so that potential customers will

know the amount of losses to replace.

(2) Dynamic Scheduling (the Same in

the NOPR)

In the NOPR’s discussion of

Scheduling and Dispatch Service, we

pointed out that dynamic scheduling is

possible in some regions. We asked for

comments on whether we should

require dynamic scheduling as an

ancillary service, given the complexity

of the service.

Comments

Most commenters would not have us

require Dynamic Scheduling as an

ancillary service.366 Dynamic

scheduling provides the metering,

telemetering, computer software,

hardware, communications,

engineering, and administration

required to allow remote generators to

follow closely the moment-to-moment

variations of a local load. In effect,

dynamic scheduling electronically

moves load out of the control area in

which it is physically located and into

another control area.

Commission Conclusion

We adopt the name Dynamic

Scheduling Service, but we will not

designate it as an ancillary service that

must be included in an open access

transmission tariff.

In the NOPR, we noted that Dynamic

Scheduling could be used in a

transmission transaction if it is

technically feasible to do so without

adversely affecting reliability. We did

not propose in the NOPR that Dynamic

Scheduling be named an ancillary

service. Although Dynamic Scheduling

is closely related to Scheduling, System

Control and Dispatch Service, it is a

special service that is used only

infrequently in the industry. It uses

advanced technology and requires a

great level of coordination. Each

Dynamic Scheduling application has

unique costs for special telemetry and

control equipment, making it difficult to

post a standard price for the service.

Consequently, we will not require that

the transmission provider offer Dynamic

Scheduling Service to a transmission

customer, although it may do so

voluntarily. If the customer wants to
21584 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

367E.g., NERC, Carolina P&L, Oak Ridge, Houston

L&P. 368E.g., Atlantic City, Oak Ridge.

purchase this service from a third party,

the transmission provider should make

a good faith effort to accommodate the

necessary arrangements between the

customer and the third party for

metering and communication facilities.

c. Other Services Not Discussed in the

NOPR

Comments

Some commenters identified several

other services that were not discussed in

the NOPR, which they recommend we

require to be provided as ancillary

services.367 Examples are emergency

power, supplemental power, and

inadvertent power.

Commission Conclusion

We believe that these other services

generally refer to either (1) generation

services that are not related to providing

transmission or (2) a subpart of a service

discussed above, the cost of which is

not easily separable from the other

service. Consequently, we will not name

any of these services as an ancillary

service that a transmission provider will

be required to offer separately under an

open access transmission tariff.

However, generation-related services

may be offered voluntarily to the

transmission customer.

We discuss below two of these

proposed generation-related ancillary

services, which NERC included among

its proposed interconnected operations

services.

(i) Backup Supply Service

Comments

NERC explains that Backup Supply is

electric generating capacity and energy

that is provided to the transmission

customer as needed (1) to replace the

loss of its generation sources and (2) to

cover that portion of the customer’s load

that exceeds its generation supply for

more than a short time. NERC notes that

Backup Supply Service is a long-term

service, which distinguishes it from

Operating Reserve Service and Energy

Imbalance Service. Backup Supply

service replaces temporary use of

operating reserves; it serves load after

operating reserves are returned to

standby mode to maintain operating

reserves at required levels. Backup

Supply may last for hours, weeks, or

longer. NERC indicates that a

transmission customer could reduce its

need for backup supply service by using

interruptible load control or active

demand-side management control, or

both.

Commission Conclusion

We accept the term ‘‘Backup Supply’’

as the name for this interconnected

operations service, but we will not

require this service as an ancillary

service under an open access

transmission tariff. Backup Supply

Service is not required for comparable

open access transmission service.

Backup Supply Service is an

alternative source of generation that a

customer can use in the event its

primary generation source becomes

unavailable for more than a few

minutes. Although we believe that the

two short-term operating reserve

services (spinning and supplemental)

are necessary to support transmission,

we conclude that long-term service is

not necessary. Backup Supply is a

generation service that may reasonably

be viewed as the responsibility of the

transmission customer, who may

contract for backup service or curtail

load.

We will impose no obligation on the

transmission provider to provide power

to the customer for a time longer than

specified in the tariff for the customer’s

own backup power supply to be made

available. The transmission provider is

obligated to protect against emergencies

for a short time; it has no obligation to

furnish replacement power on a longterm basis if the customer loses its

source of supply. The transmission

provider has no obligation to provide

power for the weeks necessary for unit

maintenance, for example.

The transmission provider is not

uniquely situated to provide Backup

Supply Service to its transmission

customers, nor does it have a

comparative advantage over others in

providing such service. Moreover, as

Backup Supply Service may require

substantial amounts of generation

capability, it is inappropriate to require

the transmission provider to assume

significant generation responsibilities as

we functionally unbundle transmission

from generation.

Although the transmission provider

will not be required to offer this service

to transmission customers, it may offer

voluntarily to provide Backup Supply

Service to its transmission customers.

Any arrangements for the supply of

such service by the transmission

provider should be specified in the

customer’s service agreement.

(ii) Restoration Service

Comments

NERC states that Restoration Service

provides facilities and procedures to

enable (1) a transmission provider to

restore its system and (2) a transmission

customer to start its generating units or

restore its loads if local power is

unavailable. Other commenters refer to

Restoration Service as Blackstart

Service, which may be provided by the

operator of the host control area,

another control area operator, or another

generation supplier.368

According to NERC, close

coordination with the host control area

operator is absolutely necessary during

system restoration operations. Under

current industry practice, each control

area operator is responsible for

implementing a restoration plan in

coordination with non-control area

utilities as well other power producers.

Many large generating units require

startup power to restart after being out

of service. Startup power may be

provided, for example, by self-contained

diesel engine generator sets located at a

generating plant. If electric power is not

available from the grid, some and

perhaps many plants must obtain the

necessary power from their auxiliary

generators to restart plants and return

the grid voltage to the proper level.

Other generators without blackstart

capability may rely on power from the

grid to restart, once the grid is energized

by others. NERC notes, however, that it

may be inappropriate to rely completely

on power from the grid for restart power

because power from the grid may be

unavailable or insufficient.

Consequently, at least some power

plants must have internal auxiliary

power sources.

Commission Conclusion

We accept the term ‘‘Restoration’’ as

the name for this interconnected

operations service. We will not require

the transmission provider to offer

Restoration Service as a separate

ancillary service in an open access

transmission tariff.

Comments on Restoration Service

appear to describe two services,

blackstart service and planning for

system restoration. Presumably, each

utility and power producer will do its

part through voluntary coordination and

self-interest to ensure a reliable and

adequate source of startup power for its

generating units. We will not require a

transmission provider to provide

blackstart capability to transmission

customers. Generators without

blackstart capability can instead

purchase blackstart power from any

power supplier connected to the grid at

an appropriate power price, if such

service is available after a contingency

is corrected.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21585

369Some commenters suggest that transmission

providers be required to provide, or transmission

customers be required to purchase or self-supply,

certain services other than the six ancillary services

that we will require to be included in an open

access transmission tariff. Because we will not

require the transmission provider to offer any

services other than basic transmission service and

the six ancillary services, comments on

requirements to provide or take other services are

not included in the summary.

370E.g., NERC, Tallahassee, IL Com.

371E.g., BG&E, Minnesota P&L, Florida Power

Corp.

372See also Florida Power Corp and Montana

Power.

373E.g., Carolina P&L, Texas Utilities, NERC,

PSE&G.

374E.g., SCE&G, Montana Power, NIPSCO, EEI,

PacifiCorp. EEI and PacifiCorp indicate that

dynamic scheduling of load following service is an

exception to the general practice of the control area

operator providing load following service.

375E.g., Montana Power, TDU Systems.

376E.g., Tallahassee, Wisconsin Municipals, IL

Com.

377E.g., OVEC, OG&E, Memphis, Nebraska Public

Power, TDU Systems, TANC, San Francisco, Brazos.

The obligation to plan for restoration

capability is a system control area

function that rests with the transmission

provider and the operator of the control

area in which the transmission provider

is located. The transmission provider (or

its associated control area operator)

generally makes arrangements with

enough generators to provide the system

with this capability at strategic locations

on the transmission system. Thus,

restoration planning is intrinsic to the

transmission provider’s basic

transmission service and included in its

cost.

2. Obligations of Transmission

Providers and Transmission Customers

With Respect to Ancillary Services

In the NOPR, the Commission

proposed that public utilities required

to file open access transmission tariffs

also be required to provide unbundled

ancillary services to transmission

customers. Although the NOPR

included a list of ancillary services to be

offered by transmission providers, the

NOPR did not indicate whether a

customer must take basic transmission

service from the transmission provider

to be eligible to require the transmission

provider to supply ancillary services.

Comments on these issues are

summarized below.369

Comments

Several commenters 370 distinguish

generation-related ancillary services

from others. Generation-related services

are those that require the provider to

have extra generating capacity or to

provide electric energy. The remaining

ancillary services are called

transmission-related services or control

area services. Transmission-related

services would involve, for example,

voltage support from transmission

facilities. An example of a control area

service is system control and dispatch.

Commenters do not agree on how each

service should be classified.

Many commenters state that only

control area operators should be

allowed to offer certain ancillary

services, such as scheduling, system

control and dispatch.371 They believe

that otherwise reliability might suffer.

Minnesota P&L states that certain

ancillary services (e.g. reactive power

from generators, load following,

frequency control) should be provided

exclusively by the operator of the

control area where the load resides.372

Minnesota P&L indicates that obtaining

these services externally could

jeopardize reliability. Several

commenters claim that a control area

operator must provide the scheduling,

system control and dispatch service and

reactive power supply service (except in

cases where the customer’s load is very

close to the generating source).373

Numerous commenters indicate that

load following (now called Regulation

and Frequency Response Service)

generally is provided only by a control

area operator.374

EEI and other commenters state that

energy imbalance service must be

provided by either the control area

operator or some other entity that is in

the control area where the customer’s

load is located and has real-time

response capability.375 NYSEG points

out that transmission providers

generally are also control area operators

and thus automatically provide energy

imbalance service to maintain

interchange flows and control area

reliability. For this reason, NYSEG

believes it is important that this service

remain a responsibility of the

transmission provider.

SC Public Service Authority contends

that ancillary services can be provided

only by an entity large enough to

operate at a NERC regional scale. It

states that ancillary services protocols

must be established regionally to

support regional transmission services.

Other commenters disagree. They

argue that all the generation-related

ancillary services identified in the

NOPR can be obtained from sources

other than the transmission provider.376

American Wind believes the ability of a

transmission customer to self-supply

ancillary services or purchase them

from a third party will help to curb

inflated prices for such services.

Southwest TDU Group also claims that

permitting entities outside the

transmission provider’s control area to

provide ancillary services will enhance

competition and reduce the need for

Commission oversight of charges for

ancillary services.

A majority of commenters support the

view that the transmission-providing

public utility should provide ancillary

services. Many commenters do not

discuss the services individually but

present their views generally on the

provision of ancillary services.

Missouri-Kansas Industrials and CCEM

support a requirement that utilities

make ancillary services available

through a tariff. They argue that, from a

customer’s point-of-view, it is extremely

critical that a transmission provider be

required to furnish these services under

a regulated, nondiscriminatory, costbased tariff format. NIEP argues that,

until a fully competitive market for

ancillary services develops, transmitting

utilities should be obligated to provide

or arrange for any and all of the NOPR

ancillary services, to the extent that the

transmission customer desires such

services. Direct Service Industries

emphasizes that a transmission provider

should be required to provide any

ancillary service that it is capable of

supplying. Direct Service Industries and

Utilities For Improved Transition claim

that open access tariffs should state

clearly that the transmission provider

must secure ancillary services for a

transmission customer if the

transmission provider is not able to

provide these services itself. Large

Public Power Council contends that,

during the transition to a competitive

market for generation-related ancillary

services, transmission providers should

be required to provide all ancillary

services related to generation that

existing customers now take on a

bundled basis. OH Com notes that

transmission owners, by virtue of their

position as transmission owners, are

necessarily the providers of last resort

for certain ancillary services. OH Com

therefore believes that only transmission

providers should provide ancillary

services.

Several non-IOU, transmissionowning commenters, however, urge that

the Commission not require

transmission providers to provide

ancillary services that they cannot

physically supply, i.e., if they lack

sufficient generation, lack control area

facilities, or have slow-responding

generating units.377 NRECA and TDU

Systems also state that many

cooperatives and transmission
21586 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

378E.g., PSNM, Atlantic City, Centerior, UWG,

Texas Utilities, Entergy, LG&E, Montana Power,

FPL, United Illuminating, Large Public Power

Council, Christensen.

379E.g., NIPSCO, PacifiCorp, Orange & Rockland,

Allegheny, NYSEG, EEI.

380E.g., BG&E.

381E.g., CSW, BG&E, ConEd, United Illuminating,

Ohio Edison, Atlantic City, Centerior, SoCal Edison,

Duke, EEI.

382E.g., RUS, TDU Systems, DE Muni.

383See also NYSEG, Ohio Edison.

dependent systems presently obtain

ancillary services from control area

utilities under specific contract terms.

Consequently, if their member systems

are asked to provide transmission

service, they may not be able to take on

the obligation to secure ancillary

services under their existing contracts

for transmission customers. Soyland

and Pacific Northwest Coop argue that

a transmission provider should not be

required to supply services that it does

not provide to its native load.

Most IOU commenters and others

oppose a requirement that the

transmission provider be obligated to

provide generation-related ancillary

services. They offer the following

reasons: (1) The need for such services

differs from one transaction to the next;

(2) a transmission provider is neither

uniquely qualified to provide these

services, nor is it essential that such

provider be the one providing these

services in order to effect a transaction;

(3) until it is demonstrated that these

services cannot be obtained from a

source other than the transmission

provider, it is inappropriate to require

transmission providers to supply such

services; and (4) a transmission provider

should have no residual obligation as a

provider of last resort to plan its system

to have generating resources available

for the supply of ancillary services.378 IL

Com also contends that utilities should

not be required to provide generationrelated ancillary services under general

transmission service tariffs if such

services can be obtained from the bulk

power market.

Other IOU commenters argue that

there is a fundamental inconsistency

between an obligation to provide or

obtain ancillary services for customers

and the NOPR’s unbundling

requirement. For example, BG&E claims

that it is inconsistent to require the

traditional vertically integrated utility to

functionally unbundle and also to

remain responsible for providing at costbased rates what should be

competitively-priced generation

services. Florida P&L and other IOU

commenters argue that providing

generation-related ancillary services

effectively imposes the load-serving

obligation of the transmission customer

on the transmission provider.

However, some IOU commenters

contend that the transmission provider

or its agent should be required to

provide certain ancillary services.379

NIPSCO and PacifiCorp believe that

load following (now called Regulation

and Frequency Response Service)

should be provided only by the

transmitting utility, especially if the

customer’s load and resources are

located in the control area operated by

the transmitting utility. EEI contends

that a third-party generator should have

the opportunity to provide regulation

service if it resides in the transmission

provider’s control area and coordinates

its actions with the control area

operator.

IN Com and NY Com recommend that

the Commission provide flexibility in

assessing responsibility for the supply

of ancillary services. MN DPS

recommends that an individual

transmission provider should not be

required to file an individual tariff for

ancillary services if it is a member of an

RTG whose tariffs adequately cover the

same services.

EEI contends that a control area utility

should not be required to provide

ancillary services to a third party

outside its control area. EEI also argues

that, if the transmission provider is not

a control area, it should not be required

to procure ancillary services from a

control area on behalf of a third party

seeking service over its system. Rather,

the third party should be responsible for

procuring the ancillary services it needs.

Other IOU commenters argue that the

responsibility to acquire ancillary

services belongs to the transmission

customer, not the transmission

provider.380

Many IOU commenters express

concern that ancillary services be

offered and taken on a symmetrical

basis, i.e., if transmission providers are

uniquely situated to provide the service,

customers should likewise be required

to take and pay for the service from such

transmission providers.381 BG&E claims

that it is patently unfair to give thirdparty users the option not to purchase

ancillary services that the transmission

provider must offer. BG&E argues that,

if transmission providers have an

obligation to provide ancillary services,

equity dictates that transmission

customers have a corresponding

obligation to take those services or

compensate transmission providers for

the costs associated with the unused

capabilities. United Illuminating argues

that the requirement to provide service

without a corresponding obligation to

purchase service unfairly burdens the

transmission provider and skews

competition in favor of transmission

customers.

Other non-IOU commenters oppose a

symmetric obligation to provide and

purchase particular ancillary

services.382 Ontario Hydro and others

claim that the customer should decide

on a case-by-case basis which ancillary

services it needs to purchase.

BPA and BG&E assert that

transmission providers should be able to

require that the party receiving the

power, which may not be the

transmission customer, be responsible

for acquiring ancillary services. This

would allow the transmission provider

to establish the appropriate contractual

arrangements with the party that is

actually receiving the energy and avoid

shifting responsibility to a party that is

merely arranging the transmission

service.

A number of IOU commenters express

concern that customers may ‘‘lean’’ on

a transmission provider’s system for

ancillary services. That is, they worry

that the transmission customer may not

purchase an ancillary service but

nevertheless rely on the transmission

provider to provide it. Commenters

propose various remedies to address

this concern. NIEP, Dayton P&L and

others argue that the Commission

should require that, as a prerequisite to

basic transmission service, the

transmission customer has either

arranged to obtain ancillary services

from the transmission provider or has

demonstrated it has an arrangement

with an alternative supplier that is

reliable and sufficient to satisfy the

ancillary service needs associated with

the transmission service transaction.

NYPP believes that, if the customer’s

method of providing ancillary services

does not meet the standards of the

transmission provider, the transmission

provider should be able to require that

the transmission customer find another

ancillary service supplier or purchase

the service directly from the

transmission provider at its tariff

rates.383 EEI proposes that penalties be

permitted as a backstop if the market

cannot resolve the ‘‘leaning’’ problem.

VEPCO suggests that utilities should

have the option to require customers to

maintain backup supply reserves.

Commission Conclusion

The NOPR proposed that six ancillary

services be included in an open access

transmission tariff. Some commenters

interpret the NOPR to require that

transmission providers make a

‘‘universal’’ offer of unbundled ancillary
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21587

384E.g., PSNM, Atlantic City, Centerior, Texas

Utilities, Entergy, FPL, Utility Working Group.

385The requirement to offer to act as agent is in

lieu of the requirement for the transmission

provider to supply the ancillary service to the

transmission customer. Many commenters asked

that we not require the transmission provider to

acquire the capacity to provide ancillary services

that it does not provide for itself but acquires from

its control area operator. E.g., EEI, NRECA, BPA,

TDU Systems.

386 If the transmission provider is a control area

operator but not a public utility, we can order

transmission services only upon application,

pursuant to section 211 and 212 of the FPA.

However, the provision of transmission services by

non-public utilities would be necessary to satisfy

the reciprocity condition in public utilities’ open

access transmission tariffs.

387E.g., Carolina P&L, Texas Utilities, PSE&G.

services, i.e., an offer to any

transmission customer regardless of

location and whether the transmission

customer would also be taking basic

transmission service from the supplier

of ancillary services.384 Such

interpretation is incorrect; it goes

beyond what is required for

comparability. These services are

required to be provided only to

customers taking basic transmission

service. However, transmission

providers may offer these services on a

voluntary basis to other customers if

technology permits.

Transmission through or out of a

control area requires fewer ancillary

services from the operator of the control

area than transmission within or into a

control area to serve loads in the control

area. If the requested transmission

service transaction involves more than

one control area, i.e., the receipt point

and delivery point of transmission

service are located in different control

areas, certain ancillary services will be

needed only in the control area where

the transmission customer’s load is

located.

We will distinguish two groups or

categories of ancillary services: (1)

Services that we will require the

transmission provider to provide to all

its basic transmission customers, and (2)

services that we will require the

transmission provider to offer to provide

only to transmission customers serving

load in the provider’s control area. The

first group is comprised of (i)

Scheduling, System Control and

Dispatch and (ii) Reactive Supply and

Voltage Control from Generation

Services. The second group is

comprised of (i) Regulation and

Frequency Response, (ii) Energy

Imbalance, (iii) Operating Reserve—

Spinning, and (iv) Operating Reserve—

Supplemental.

With respect to the first group of

ancillary services, we conclude that the

transmission provider that operates a

control area is uniquely positioned to

provide these services. Thus, as stated

above, we will require the transmission

provider that operates a control area to

provide these ancillary services. We will

also require that the transmission

customer purchase these services from

the transmission provider, as explained

in the next section.

With respect to the second group of

ancillary services, we conclude that the

transmission provider is not always

uniquely positioned to provide these

services, although in many cases it may

be the only practical source. Thus, we

will require the transmission provider to

offer to provide the ancillary services in

the second group to transmission

customers serving load in the

transmission provider’s control area. We

also will require the transmission

customer serving load in the

transmission provider’s area to acquire

these services, but it may do so from the

transmission provider, a third party or

self-supply. These ancillary services

must be provided by someone if the

system is to be operated reliably; the

customer may not decline the

transmission provider’s offer of

ancillary services unless it demonstrates

that it has acquired the services from

another source. The transmission

provider may require the customer to

decide which of these ancillary services

it will purchase from the transmission

provider when it applies for basic

transmission service.

If the transmission provider is a

public utility providing basic

transmission service but is not a control

area operator, it may be unable to

provide some or all of the ancillary

services we require without substantial

investment. In this case, we will allow

the transmission provider to fulfill its

obligation to provide, or offer to

provide, ancillary services by acting as

the customer’s agent. We will require

the transmission provider to offer to act

as agent for the transmission customer

to secure these services from the control

area operator.385 The customer may have

the transmission provider act as agent or

may secure the ancillary services

directly from the control area operator.

As stated above, the customer may also

secure the second group of ancillary

service from a third party or by selfsupply.

If the transmission provider is a

public utility that is not a control area

operator, but its control area operator is

a public utility, the control area operator

must offer to provide all ancillary

services to any transmission customer

that takes transmission service over

facilities in its control area whether or

not the control area operator owns or

controls the facilities used to provide

the basic transmission service.386

We discuss the requirement to supply

and purchase each ancillary service

individually below.

a. Ancillary Services Required To Be

Provided by Transmission Provider for

All of Its Transmission Customers

(1) Scheduling, System Control and

Dispatch Service

We conclude that this service is

necessary to the provision of basic

transmission service within every

control area. As NERC and other

commenters point out, Scheduling,

System Control and Dispatch Service

can be provided only by the operator of

the control area in which the

transmission facilities used are

located.387 This is because the service is

to schedule the movement of power

through, out of, within, or into the

control area.

(2) Reactive Supply and Voltage Control

Service From Generation Sources

We conclude that this service is

necessary to the provision of basic

transmission service within every

control area. Because reactive power

cannot be transmitted for significant

distances, the local transmission

provider has to supply reactive power

from generation sources. It is often

uniquely situated to supply reactive

power. The transmission provider or the

operator of the control area in which the

provider is located cannot avoid

supplying it to the transmission

customer, and the transmission

customer cannot avoid taking at least

some of this service from the

transmission provider. Although a

customer is required to take this

ancillary service from the transmission

provider or control area operator, it may

reduce the charge for this service to the

extent it can reduce its requirement for

reactive power supply.

b. Ancillary Services Required To Be

Offered Only to Transmission

Customers Serving Loads in the

Transmission Provider’s Control Area

(1) Regulation and Frequency Response

Regulation and Frequency Response

Service is not required for transmission

out of or through the transmission

provider’s control area. We conclude

that this service must be offered only for

transmission within or into the

transmission provider’s control area to

serve load in the area. Customers may

be able to satisfy the regulation service

obligation by providing generation with
21588 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

388Some of these options (e.g., establishing a

separate control area), while technically feasible,

may be too costly or otherwise inadvisable.

389E.g., Carolina P&L, NYSEG, FPL, NSP, WP&L,

Orange & Rockland, Arizona, Salt River, SC Public

Service Authority, Brazos, NY Com.

390See, e.g., Carolina P&L Initial Comments at 56.

391See, e.g., CCEM, Carolina P&L, NYSEG,

CINergy.

392E.g., UT Com, Washington and Oregon Energy

Offices, WA Com.

393E.g., Direct Service Industries, Mt. Hope

Hydro.

automatic generation control

capabilities to the control area in which

the load resides. Dynamic scheduling

may also be used to electronically

‘‘move’’ a remote generating unit into

the appropriate control area. For

customers to take advantage of these

developments, a transmission provider

is required to identify the regulating

margin requirements for transmission

customers serving loads in its control

area and develop procedures by which

customers can avoid or reduce such

requirements.

(2) Energy Imbalance

We conclude that Energy Imbalance

service must be offered for transmission

within and into the transmission

provider’s control area to serve load in

the area.

Energy imbalance represents the

deviation between the scheduled and

actual delivery of energy to a load in the

local control area over a single hour. A

transmission customer can reduce or

eliminate the need for energy imbalance

service in several ways. A customer can

avoid taking energy imbalance service if

it controls generation with loadfollowing capabilities located in the

control area. The Final Rule pro forma

tariff allows unlimited changes before

the hour at no additional charge to a

customer’s hourly schedule of energy

deliveries to the control area. By

changing its schedule more frequently

(based on updated load information, for

example), a customer can reduce or

avoid energy imbalance charges. Other

customer options to reduce or avoid

energy imbalance charges include (i)

establishing the load as a separate

control area island within the

transmission provider’s control area

with its own generation and load and

(ii) removing the customer’s load from

the transmission provider’s control area

through dynamic scheduling.388

(3) Operating Reserve—Spinning

(4) Operating Reserve—Supplemental

We conclude that Operating

Reserve—Spinning and Operating

Reserve—Supplemental must be offered

for transmission within and into the

transmission provider’s control area to

serve load in the control area. Reserves

should be located near load in case of

unplanned unavailability of generating

units serving load in the control area.

We will permit transmission providers

to rely upon prevailing regional

practices to set reserve criteria.

Transmission providers are required to

facilitate efforts by customers to meet

Operating Reserve obligations with their

own generating resources or from thirdparty sources if they can satisfy the

regional criteria.

If a customer uses either type of

operating reserve, it must expeditiously

replace the reserve with backup power

to reestablish required minimum reserve

levels.

3. Unbundling and Bundling Ancillary

Services

a. Services That Can Be Bundled With

Transmission Service

In the NOPR, the Commission

proposed that transmission providers

should be required to offer ancillary

services as discrete services, unbundled

from basic transmission service.

Comments

While most commenters support the

approach to unbundling the ancillary

services proposed in the NOPR, a

number of commenters argue that, for

technical and administrative reasons,

certain services should be bundled with

basic transmission service. For example,

some commenters assert that Reactive

Supply and Voltage Support service

should be bundled with basic

transmission service.389 They argue that

this service is integrally related to the

operation of the transmission system,

that it must be provided at or near the

point of need, and that its costs are

difficult to isolate and account for.390

Other commenters argue that scheduling

and dispatch service, for similar

reasons, should be bundled with basic

transmission service.391

A few commenters suggest that other

services could be bundled with the

basic transmission service. For example,

NYSEG identifies energy imbalance

service as a candidate for bundling. EEI

identifies frequency regulation and

NYMEX identifies frequency control as

services that could be bundled with

basic transmission service.

Some commenters believe that the

Commission should allow utilities to

file transmission tariffs that bundle all

necessary transmission and ancillary

services, at least as an interim

measure.392

On the other hand, other commenters

believe that a greater level of

unbundling of transmission and

ancillary services is necessary to

facilitate the development of

competitive markets and to ensure that

transmission customers are able to

purchase only the services they

require.393 Dayton P&L believes that all

ancillary services should be offered as

discrete services with separate prices.

Texas Utilities asserts that generationrelated ancillary services should be

unbundled and separately priced.

Commission Conclusion

Although commenters raise valid

concerns, they do not provide a

compelling reason to require that our six

ancillary services be bundled with basic

transmission service. We have, however,

changed the proposal in the NOPR to

clarify that reactive supply and voltage

support from transmission resources is

part of basic transmission service.

Unbundling ancillary services will

promote competition and efficiency in

their supply. Because most generationbased ancillary services potentially can

be provided by many of the generators

connected to the transmission system,

some customers may be able to provide

or procure such services more

economically than the transmission

provider can. Once they are unbundled,

a more competitive market may emerge

to supply such services.

Also, unbundling makes possible a

more equitable distribution of costs.

Because customers that take similar

amounts of transmission service may

require different amounts of some

ancillary services, bundling these

services with basic transmission service

would result in some customers having

to take and pay for more or less of an

ancillary service than they use. For

these reasons, the Commission

concludes that the six required ancillary

services should not be bundled with

basic transmission service.

With respect to the specific question

of whether Reactive Supply and Voltage

Control from Generation Sources should

be bundled with basic transmission

service, we believe that this service

should remain unbundled because, as

explained above, transmission

customers have some ability to effect

how much of this service they need and

a third party may be able to supply

some portion of a customer’s reactive

power requirements.

b. Services That May Be Offered and

Sold as a Package

The NOPR indicated that ancillary

services must be offered separately from

one another but did not indicate if the
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21589

394E.g., Direct Service Industries, Mt. Hope

Hydro, ELCON, PA Com.

395EEI Initial Comments at V–4; ELCON Initial

Comments at 21.

396E.g., WP&L, NYSEG.

397E.g., Consumers, PacifiCorp, Carolina P&L,

PSNM, Salt River, PA Com, TDU Systems.

398TDU Systems Initial Comments at 87.

399Mt. Hope Hydro Initial Comments at 17.

400E.g., Utilities For Improved Transition, Idaho,

CINergy, Direct Service Industries, Mt. Hope Hydro,

ABATE, TDU Systems, Missouri-Kansas Industrials,

Washington and Oregon Energy Offices, IN Com.

401E.g., PJM, Texas Utilities, Entergy, Carolina

P&L.

transmission provider may also offer a

package of ancillary services.

Comments

Several commenters support giving

customers the option either to purchase

ancillary services as separate and

distinct services or to purchase a

package of services from the

transmission provider.394 Others, such

as Tallahassee, recommend that utilities

be prohibited from bundling the

purchase of one service with another so

that a transmission customer cannot rely

on the transmission provider for just

one or a few of the ancillary services.

EEI and ELCON argue that the

Commission should permit customers

the option to request that transmission

providers offer packages of selected

ancillary services.395 They and other

commenters express a concern that

efficiencies can be lost under a policy

that precludes combining ancillary

services.

Commission Conclusion

We conclude that a transmission

provider must offer and price the

individual ancillary services separately.

It may not tie the purchase of one to the

purchase of another.

However, we will allow a

transmission provider to assemble

packages of ancillary services (not

bundled with basic transmission

service) that can be offered at rates that

are less than the total of individual

charges for the services if purchased

separately. It may also offer rate

discounts on any ancillary service. If a

rate discount is offered to the

transmission owner itself or to an

affiliate of the transmission owner, the

same discount must be offered to nonaffiliates, as well. In addition, discounts

offered to non-affiliates must be on a

basis that is not unduly discriminatory.

All discounts must be posted on the

transmission provider’s OASIS.

4. Reassignment of Ancillary Services

In the NOPR, the Commission noted

that ancillary services may not be

suitable for reassignment and requested

comments on this issue.

Comments

Commenters express divided views

on the reassignment issue. Some IOU

commenters believe that, subject to

technical limitations, ancillary services

could be reassigned.396 Other

commenters, including many IOUs,

oppose reassignment because they

believe it is impractical.397 In particular,

PacifiCorp claims that the customerspecific nature of generation-related

ancillary services prevents such services

from being reassigned.

TDU Systems argue that transmission

customers that must pay for ancillary

services they do not need should be able

to resell them to someone else.398 Mt.

Hope Hydro claims that, if a bulk power

transaction and the associated

transmission service can be reassigned,

it is reasonable that the ancillary

services used to support the transaction

also should be reassigned, particularly if

the same facilities and contract path are

used.399

Commission Conclusion

We conclude that transmission

customers will be allowed to reassign

ancillary services along with the

reassignment of basic transmission

service. The Commission believes that a

policy of transmission capacity

reassignment may not be possible unless

the ancillary services used to support

the transmission are also reassignable.

5. Pricing of Ancillary Services

In the NOPR, we asked for comments

on ancillary service pricing and

proposed specific ancillary services

prices in the Stage One implementation

rates. Many commenters commented on

the Stage One rates. There is no Stage

One in the Final Rule.

Comments

Many commenters state that ancillary

services are difficult to price. They

suggest diverse pricing approaches. IN

Com notes that, because utilities and

regulatory commissions have no

experience with pricing unbundled

ancillary services, the process needs to

evolve but the goal should be to

encourage market pricing in competitive

markets. Air Liquide believes the best

pricing policy should be negotiated

bilateral agreements, provided market

power is mitigated.

Other commenters express concern

about how pricing proposed in the

NOPR would affect the development

and operation of competitive ancillary

services markets. Industrial Energy

Applications notes that low price caps

on generation-related services, such as

supplying losses, imbalance energy,

operating reserve and backup power,

which can be provided from many

sources, inhibit competitive market

development. There is little incentive

for other providers to invest in facilities

to provide these services. Dayton P&L

and others contend that the Commission

should not require transmission

providers to provide generation-based

ancillary services at cost-based rates and

then allow third parties to resell such

services at market-based rates.

PacifiCorp expresses concern that the

NOPR’s pricing proposal would be

overly restrictive in the emerging

competitive market for generationrelated ancillary services.

Many commenters argue that costbased price caps are appropriate for

ancillary services if there are no

alternative suppliers or until

competitive markets develop.400 CAMU

suggests that the comparability standard

is not met if market rates exceed the

costs of providing ancillary services.

Allegheny, Ohio Edison and Atlantic

City support cost-based pricing for

Reactive Power/Voltage Control. Ohio

Edison recommends cost-based pricing

for frequency regulation, and Atlantic

City recommends it for scheduling and

dispatch.

Several commenters suggest that the

Commission require cost-based rates for

ancillary services where no source other

than the transmission provider exists

and market-based rates for generationrelated ancillary services if competition

exists.401 Washington and Oregon

Energy Offices recommend that, before

permitting market-based rates, at least

two other non-affiliated parties should

be able to offer a nearly identical

ancillary service and that the

Commission should use the same

standards for allowing market-based

rates for ancillary services that it has

used for wholesale power sales. Mt.

Hope Hydro argues that vertically

integrated utilities should be permitted

to charge cost-based rates that are

limited to no more than the market price

for ancillary services. It also contends

that companies whose generation

facilities are not supported by captive

retail or transmission customers should

be authorized to sell at market-based

prices.

The vast majority of commenters from

all interest groups who address marketbased pricing for ancillary services agree

that market-based pricing is appropriate

for ancillary services where competitive

market conditions exist. However,

commenters disagree over whether a
21590 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

402Many commenters were particularly

concerned that rates for energy losses, a NOPR

ancillary service, should be market-based. We need

not address this concern in this Rule, however,

because we will not require Real Power Losses to

be offered as an ancillary service.

competitive market for ancillary

services currently exists.

In determining the extent of

competition, many commenters

distinguish between ancillary services

that are (1) generation-related and (2)

transmission-related. Commenters

disagree over whether the Commission

can declare generation-related ancillary

services to be competitive on a generic

basis. Many commenters contend that

transmission-related ancillary services

are not available in a competitive

market; consequently, they agree that

prices for such services should be costbased.

Commission Conclusion

We will consider ancillary services

rate proposals on a case-by-case basis.

In response to comments,402 we offer

here some general guidance on ancillary

services pricing principles.

(1) Ancillary service rates should be

unbundled from the transmission

provider’s rates for basic transmission

service, even though such services are a

necessary adjunct to basic transmission

service.

(2) The fact that we have authorized

a utility to sell wholesale power at

market-based rates does not mean we

have authorized the utility to sell

ancillary services at market-based rates.

(3) In the absence of a demonstration

that the seller does not have market

power in such services, rates for

ancillary services should be cost-based

and established as price caps, from

which transmission providers may offer

a discount to reflect cost variations or to

match rates available from any third

party. If a rate discount is offered to the

transmission owner itself or to an

affiliate of the transmission owner, the

same discounted rate must be offered to

non-affiliates, as well. In addition,

discounts offered to non-affiliates must

be on a basis that is not unduly

discriminatory. All discounts must be

posted on the transmission provider’s

OASIS.

(4) The amount of each ancillary

service that the customer must

purchase, self-supply, or otherwise

procure must be readily determined

from the transmission provider’s tariff

and comparable to the obligations to

which the transmission provider itself is

subject. The provider must take

ancillary services for its own wholesale

transmission under its own tariff.

(5) The location and characteristics of

a customer’s loads and generation

resources may affect significantly the

level of ancillary service costs incurred

by the transmission provider. Ancillary

service rates and billing units should

reflect these customer characteristics to

the extent practicable.

6. Accounting for Ancillary Services

Comments

Some commenters suggest that there

may be a need for revising the Uniform

System of Accounts to track better the

costs of providing discrete ancillary

services. Other commenters believe that

ancillary services are transmission-type

services and suggested that the costs of

generation-provided ancillary services

be refunctionalized from power

production expense to transmission

expense.

Oak Ridge asserts that a primary goal

of those interested in restructuring the

electricity industry should be to identify

clearly the different functions that are

today buried within the vertically

integrated utility and bundled into one

price. Oak Ridge, however, indicates

that achieving this ideal of identifying

unbundled services at appropriate

prices will be difficult because of utility

accounting practices.

EEI asserts that since the current

Uniform System of Accounts was

designed to track costs incurred to

provide bundled wholesale service, it

does not track the discrete costs

incurred to provide ancillary services.

Therefore, according to EEI, a major

update is needed to support the pricing

of discrete ancillary services.

ConEd states that ancillary services

are integral and essential elements of

providing transmission services. It notes

that, historically, due to the vertical

integration of utilities, those services

have been bundled with the other

services provided and the costs

associated with providing ancillary

services have not been specifically

defined. ConEd claims that to a large

degree, this is due to the fact that utility

accounting mechanisms were not

established with the intention of

identifying the costs for ancillary

services.

UI asserts that if transmission

customers are to be charged for certain

ancillary services, it may be necessary to

refunctionalize certain specific costs

items from generation to transmission.

UI points out that some of the reactive

power to support system voltages and to

provide transmission services, for

example, is supplied from the variable

reactive output of the generators. It

states that these costs, to the extent they

can be identified with the provision of

transmission service, should be

refunctionalized to the transmission

account. However, UI states it may not

be possible to develop a unit cost for

specific transactions. Thus, UI states it

may be more appropriate to roll these

costs into the embedded transmission

rate and allocate them among the

various users of the transmission

system.

Commission Conclusion

To ensure comparable transmission

access a Transmission Provider is

obligated to offer or arrange to provide

certain ancillary services to the

Transmission Customer. Also, the

Transmission Provider may offer to

provide other ancillary services to the

Transmission Customer. A

Transmission Customer is obligated to

purchase certain ancillary services from

the Transmission Provider.

Generation resources provide certain

ancillary services, while transmission

resources provide other ancillary

services. Consequently, the costs of

providing certain ancillary services are

recorded in the utility’s power

production expense accounts, while

others are recorded in the utility’s

transmission expense accounts.

Currently, the Uniform System of

Accounts requires that costs incurred in

providing ancillary services be recorded

as power production or transmission

expense depending upon which

resource the utility uses to supply the

service. At this time, we are not

convinced that the amounts involved or

the difficulty associated with measuring

the cost of ancillary services warrants a

departure from our present accounting

requirements. We will specify, however,

that revenues a Transmission Provider

receives from providing ancillary

services must be recorded by type of

service in Account 447, Sales for Resale,

or Account 456, Other Electric

Revenues, as appropriate.

E. Real-Time Information Networks

In the Open Access NOPR, the

Commission determined that in order to

remedy undue discrimination, a utility

must functionally unbundle its

wholesale services, and that among the

things required by functional

unbundling is that the utility, when

buying or selling power, rely upon the

same electronic network that its

transmission customers rely upon to

obtain transmission information.

Accordingly, the Commission

accompanied its issuance of the Open

Access NOPR with issuance of a notice

of technical conference that initiated a

proceeding in Docket No. RM95–9–000
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21591

403See Real-Time Information Networks, Notice

of Technical Conference and Request for

Comments, 60 FR 17726 (April 7, 1995).

404 In Phase II, we will continue to develop the

requirements for fully functional OASIS. We expect

to issue a final rule on Phase II OASIS requirements

sometime in 1997. 405E.g., DE Com, DC Com, NJ Com, MD Com.

to consider whether Real-Time

Information Networks (RINS) or some

other option would be the best means to

ensure that potential customers of

transmission services have access to the

information necessary to obtain open

access transmission service on a nondiscriminatory basis.403

The Commission affirms its

conclusion that in order to remedy

undue discrimination in the provision

of transmission services it is necessary

to have non-discriminatory access to

transmission information, and that an

electronic information system and

standards of conduct are necessary to

meet this objective. Therefore, we issue,

in conjunction with this Final Rule, a

final rule adding a new Part 37 that

requires the creation of a basic OASIS

and standards of conduct.404

The Phase I OASIS rules require each

public utility (or its agent), as defined in

section 201(e) of the Federal Power Act,

16 U.S.C. 824(e), that owns, controls, or

operates facilities used for the

transmission of electric energy in

interstate commerce to develop and/or

participate in an OASIS. The Phase I

OASIS rules describe what information

must be provided on the OASIS during

Phase I and how OASIS must be

implemented.

In addition, the new Part 37 contains

a code of conduct applicable to all

transmission providing public utilities.

The code of conduct is designed to

ensure that preferential access to

information about wholesale

transmission prices and availability is

not available to employees of the public

utility engaged in wholesale marketing

functions or to employees of certain of

the public utility’s affiliates.

F. Coordination Arrangements: Power

Pools, Public Utility Holding

Companies, Bilateral Coordination

Arrangements, and Independent System

Operators

Comments

Timing of Reformation

Many marketers, IPPs, and other

nonmembers of pools request that the

Commission immediately apply

unbundling and transmission tariff

requirements to all new transactions

under existing pooling agreements.

APPA states that the Commission

should not deal with power pools as a

‘‘follow-on activity’’ because treatment

of pools is an integral step in achieving

transmission comparability. AEC

contends that until pools publish open

access tariffs, the Commission should

permit applications for section 211

transmission orders from one or more

applicants directed to multiple

respondents.

Existing pools generally urge the

Commission to allow time for the pools

to propose alternative structures or

agreements which would meet the

objectives of the final rule. EEI states

that the rule may create problems for

power pools that will not be examined

or understood by the Commission and

the public until the Commission’s

pooling inquiry is completed; it requests

that the pooling inquiry be completed

before a final rule is issued. Duke

recommends that implementation of

open access transmission services by

power pools be addressed in a separate

proceeding because implementation of

open access for power pools raises

complex issues.

EGA, among others, argues that new

transactions under existing pooling

agreements should not be grandfathered,

but rather should be required to meet

the functional unbundling requirements

of the final rule. Some pool members

argue that pool transactions are largely

not wholesale transactions. For

example, PECO (a member of PJM)

requests the Commission to clarify that

the delivery of pooled generation to

pool members’ native load is not a

‘‘wholesale purchase’’ of power and

thus would not require taking

transmission service under one’s own

open access transmission tariff. Another

member of PJM, BG&E, interprets the

proposed rule to require all PJM

economy trades to be firm point-to-point

services; it claims that such a

requirement ‘‘jeopardizes the continued

viability of the pool.’’

System-Wide Tariffs

Virtually all commenters on power

pool issues state that the tariff

requirements should not be applied

directly to individual utilities who are

members of ‘‘tight’’ power pools.

ELCON, CCEM, and others argue that

the pro forma tariff requirement should

be applied directly to ‘‘tight’’ or ‘‘single

system’’ power pools to avoid

discriminatory ‘‘pancaking’’ of

transmission rates. However, Duke

argues that where there are both

multiple owners and operators, as in

‘‘loose’’ pools, it is appropriate to have

individual tariffs unless the pool

members agree otherwise. DOE

recommends a power pool file a single

pool-wide tariff to offset problems

associated with joint ownership or

control of transmission. CT DPUC

recommends that the Commission

provide guidance for transmission

access and pricing (so as to avoid

needless disruption of present

methods).

Flexible Treatment

Most commenters on power pools

support recognizing regional differences

among power pools and urge flexibility.

PSE&G (a member of PJM) states that

open access tariffs must be specially

crafted to deal with power pool

members. NYPP and PJM state that they

are considering innovations and urge

that their efforts not be stifled by any

final rule. CSW proposes a region-wide

pricing model based on power flows.

NPPD, a member of the Mid-Continent

Area Power Pool (MAPP), says MAPP is

considering adopting the megawatt-mile

approach to transmission pricing. SoCal

Edison states that California utilities are

developing a market-based power pool

and that it is crucial for the final rule

to be flexible to permit innovations

throughout the country.

ELCON and power marketers,

however, argue for uniformity and point

out the difficulties of moving power

from system to system where each

system has varying standards or ‘‘pool

rules.’’ These commenters support

uniform application of the terms and

conditions in the pro forma tariffs to

create a national standard.

NEPOOL emphasizes that since pools

remain voluntary, the imposition of

rules that are not acceptable to pool

members simply increases the

likelihood that members will withdraw

and pools will disintegrate. For this

reason, NEPOOL states that solutions to

enhance competition (within a tight

pool setting) are best identified through

the consensus of pool members, which

requires both time and flexibility on the

part of the Commission.

DE, DC, NJ and MD Coms emphasizes

its concern that a one-size-fits-all openaccess policy, while perhaps benefiting

subsets of individual suppliers and

purchasers, may not be the best solution

for the millions of retail customers who

currently rely on power pools.405 It

wants the Commission to be aware that

the individual commissions have begun

a formal dialog among each other and

with the PJM utilities to discuss

possible regional solutions to

transitional competitive issues.

Open Membership

NIEP and CCEM argue that the

competitive playing field cannot be

level unless nonmembers receive certain
21592 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

406E.g., Central Louisiana, Dayton P&L, LPPC,

MEAG, Missouri Basin Group, Montana-Dakota

Utilities, Nebraska Public Power District, Ohio

Edison, PSNM.

407E.g., Arizona, Ohio Edison.

408E.g., Soyland, NRECA.

409E.g., APPA.

410E.g., APPA, CCEM, EGA.

411E.g., APPA, CCEM, LG&E, EGA.

power pool services on terms

comparable to those for pool members.

Members of pools state that ‘‘return in

kind’’ transactions are efficient, but that

such transactions are not appropriate for

those entities that are not similarly

situated to vertically integrated utilities.

EEI maintains that those seeking the

benefits of pool membership must

accept the burdens imposed on existing

pool members (otherwise, they would

have an advantage, not comparability).

EEI believes that new pool participants

can negotiate and ‘‘buy into’’ the pool

resources. Many commenters claim that

unbundling certain power pool services

to accommodate open access will solve

the problem.

MidAmerican states that if the

Commission grants nonmembers access

to pool transmission service, the

Commission should allow a period of at

least four years for pools to restructure

and refile rate schedules to avoid the

inequitable results which the

Commission’s requirements will impose

on pool members.

MidAmerican contends that the

Commission should authorize pool

members to unilaterally withdraw from

their pools if any restructuring or

revision of rate schedules is

unacceptable to the member.

Holding Companies

Allegheny, Southern, and other

holding companies argue that

coordination agreements among

subsidiaries of a utility holding

company system do not constitute a

power pool and should not be subject to

any obligations the Commission may

place on power pools.

Bilateral Coordination Agreements

Ohio Edison requests clarification that

the Commission is not requiring new

wholesale coordination transactions to

be under the open access tariffs; they

may be continued under existing

coordination agreements. It stresses the

importance of such agreements in

making economy and emergency

transactions.

A number of commenters agree that

existing coordination contracts should

not be abrogated or modified, and that

transactions under these existing

contracts should not be governed by the

provisions of the pro forma tariffs.406

These commenters generally argue that

existing coordination agreements should

not be abrogated or amended by the

final rule because: (1) They were not

negotiated in the environment

envisioned by the NOPR; (2)

coordination sales are beneficial to

consumers and ratepayers (and thus it

would not be in the public interest to

curtail them); and (3) the termination of

coordination agreements, which in some

cases have been in place for years and

are tailored to parties’ peculiar

circumstances, could cause severe

hardships in certain regions (especially

with regard to scheduling and

curtailment).

PSNM contends that such agreements

are the result of mutually beneficial

bargaining. LPPC and MEAG argue that

current contracts negotiated among

parties provide cost savings to

consumers, which may be foregone if

existing contracts are modified. Central

Louisiana suggests that the pro forma

tariff provisions should be flexible

enough to achieve comparability if

applied to both existing and new

coordination agreements.

Some commenters argue that there

may be cases where it is inappropriate

to modify existing coordination

agreements to satisfy the requirements

of the rule. They assert that

coordination agreements providing for

emergency transactions,407 reliability,408

and resource efficiency gains 409 need

special attention. However, Soyland

believes that existing agreements need

to be reviewed if there is substantial

increase in wholesale power market

transactions, at the customer’s option.

TDU Systems argues that coordination

contracts supporting system reliability

should be honored and given

scheduling and curtailment preference.

TDU Systems contends that any

amendments should be at the parties’

discretion rather than by Commission

mandate.

Several commenters suggest that the

proposed rule is unclear about whether

only existing transactions under

agreements already approved by the

Commission will be exempt from

functional unbundling, or whether the

proposed rule also would exempt (or

grandfather) new transactions entered

into pursuant to existing approved

contracts.410 Other commenters

recommend that the Commission clarify

that its policy on unbundling applies to

all new transactions, whether pursuant

to new or existing agreements.411 ConEd

and KCPL request clarification that

purchases made to satisfy retail service

are not subject to the requirements of

the pro forma tariffs.

CCEM argues that all coordination

transactions, including new transactions

under existing agreements, should be

unbundled to ensure that transmission

providers are implementing the posted

transmission rate. CINergy contends that

the comparability standard should be

applied to existing coordination

agreements, including buy-resell

agreements, to mitigate any unfair bulk

power market advantages. Functional

unbundling would ensure that a utility

includes an EBB-posted transmission

rate in the transaction charge. CINergy

and Power Marketing Association

recommend that the Commission use its

authority under section 206 to require

all utilities to file amendments to their

existing coordination agreements

providing for transmission service to be

taken pursuant to the parties’ open

access transmission tariffs. Power

Marketing Association further

recommends that the Commission

establish expedited procedures to

address the situation arising from

conflicting pro forma tariffs and existing

coordination provisions.

Tallahassee also believes that the

comparability standard should be

applied to existing coordination

agreements, but Tallahassee

recommends that the Commission

establish a transition period to allow for

renegotiation among parties rather than

imposing modifications to existing

agreements. Renegotiation would

provide an opportunity to retain

previously bargained-for benefits.

Detroit Edison also contends that many

of the existing coordination agreements

do not provide for the services required

under the pro forma tariffs. Like

Tallahassee, Detroit Edison recommends

that the Commission allow sufficient

time for parties to renegotiate existing

agreements. CINergy suggests a threeyear transition period.

Coordination Pricing Practices

EEI and PJM disagree with the

Commission’s assertion that current

coordination pricing is no longer just

and reasonable in the absence of an

open access tariff. Ohio Edison and PA

Com question the basis of the

Commission’s preliminary conclusion

that current coordination pricing is no

longer justified in the absence of a

seller’s tariff offer of non-discriminatory

open access transmission services. PA

Com asserts that the Commission’s

underlying assumption of general lack

of transmission access by wholesale

customers has not been established as

fact in the proposed rule.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21593

412E.g., Arizona, CINergy, Consumers Power, EEI,

PJM.

413For example, a 30-year contract to supply 50

MW of power can be considered to be a

coordination arrangement because it is not a

contract to meet all of the buyer’s power

requirements.

414Agreements dealing with joint ownership or

operation of transmission facilities are discussed at

Section IV.C.3.

415The Commission did not define what it meant

by ‘‘power pools’’ in the NOPR discussion. We use

the term power pool in a very broad context here

and have generally characterized three broad types

of arrangements that represent some form of

pooling: ‘‘tight pools’’, ‘‘loose’’ pools and other

multilateral coordination arrangements, and

holding companies. Even between the categories of

tight and loose pools, however, there is no bright

dividing line.

416A technical conference on pro forma tariffs

was held on October 27, 1995. A technical

conference on power pools was held on December

5 and 6, 1995 and a follow-up technical conference

on ISOs and power pools was held on January 24,

1996.

MN DPS supports current

coordination pricing methods provided

that utilities have executed open-access

tariffs. Missouri Basin Group argues

that, if increased market competition

materializes through open access,

utilities will decreasingly rely on

current coordination pricing if it no

longer produces the most beneficial

outcome. Missouri Basin Group

recommends the Commission simply

allow utilities to choose a pricing

method even if a utility opts for a less

beneficial outcome. Nebraska Public

Power District also urges the

Commission to avoid mandating

coordination pricing methods. Nebraska

Public Power District is concerned that

this may impede establishing RTGs

where such pricing is by mutual

agreement and subject to ADR

procedures.

Several commenters agree that current

coordination pricing may no longer be

appropriate in an open access regime.412

FL Com believes that current

coordination pricing should be replaced

by market-based rates if open access

transmission service is imposed by the

Commission.

Commission Conclusion

The term ‘‘coordination’’ is applied to

a wide variety of wholesale power sales

agreements within the industry,

including interchange, interconnection,

pooling, and other agreements. Broadly

speaking, any non-requirements power

sales agreement can be considered to be

a coordination agreement.413

The Final Rule’s general requirement

for non-discriminatory transmission

access and pricing by public utilities,

and its specific requirement that public

utilities unbundle their transmission

rates and take transmission service

under their own tariffs, apply to all

public utilities’ wholesale sales and

purchases of electric energy, including

coordination transactions. The

Commission has determined that certain

existing wholesale coordination

arrangements and agreements must be

modified to ensure that necessary

transmission services for such

arrangements and agreements are taken

under open access transmission tariffs

and thus that such arrangements and

agreements are not unduly

discriminatory. Below we discuss how

and when various types of coordination

agreements will need to be modified,

and when public utility parties to

coordination agreements must begin to

trade power under those agreements

using transmission service obtained

under the same open access

transmission tariff available to nonparties.

Coordination arrangements, and the

agreements governing them, vary

widely. They range from relatively

simple bilateral arrangements to

complex tight power pools. Our

discussion addresses four broad

categories of arrangements and

accompanying agreements: ‘‘tight’’

power pools, ‘‘loose’’ power pools,

public utility holding company

arrangements, and bilateral coordination

arrangements. For purposes of

implementing the non-discriminatory,

open access requirements of the Final

Rule, we are dividing bilateral

coordination agreements into two

general categories: bilateral economy

energy agreements and other bilateral

coordination agreements. Economy

energy agreements typically provide for

short-term economy trading ‘‘if, as, and

when available’’ and are generally

driven by the buyer and seller’s

generation costs. They do not require

either the seller or the buyer to engage

in a particular transaction. Other

coordination agreements are typically

longer term or open-ended. Some may

involve joint ownership or joint

planning of generation.414 Others may

provide joint operation of facilities so

that the parties can coordinate their

maintenance schedules or provide one

another with emergency service. These

longer-term coordination agreements are

distinguished from short-term economy

trading agreements in that the parties

have undertaken a contractual

obligation to operate their facilities so as

to support one another under the

conditions specified in the

arrangements.

As noted in the NOPR, power pools,

in contrast to most bilateral

arrangements, present complex issues

that may require special implementation

requirements.415 This is because these

arrangements may involve agreements

containing an intricate set of rights,

obligations, and considerations among

the members of a pool. We provide for

implementation requirements herein

that vary depending upon the type of

‘‘pooling’’ arrangement involved.

The Commission has concluded that

in order to adequately remedy the

undue discrimination in transmission

access and pricing by public utilities

that are members of power pools or

other coordination arrangements, such

public utilities must remove preferential

transmission access and pricing

provisions from agreements governing

their transactions. The filing of open

access tariffs by the public utility

members of a power pool is not enough

to cure undue discrimination in

transmission if those public utilities can

continue to trade with a selective group

within a power pool that

discriminatorily excludes others from

becoming a member and that provides

preferential intra-pool transmission

rights and rates. The same holds true of

certain bilateral arrangements that allow

preferential transmission pricing or

access. These arrangements and

agreements need to be changed. We

expect such arrangements and

agreements to be modified by the dates

indicated in this Rule. However, if

necessary, we will institute section 206

proceedings against public utilities that

do not make such filings.

The Commission’s technical

conferences on power pools, ISOs, and

pro forma tariffs made clear to us the

need to articulate guidance in this Rule

on the restructuring or modification of

unduly discriminatory coordination

arrangements—particularly tight power

pools.416 They also made clear that

members of tight power pools, in

particular, need time to make the

necessary modifications to these

arrangements. We recognize that

members of some power pools are

already in the process of formulating

voluntary modifications to pooling

agreements to be filed with the

Commission (e.g., PJM, NYPP,

NEPOOL). Therefore, we will provide

adequate time for these filings as well as

guidance to changes that need to be

made.

In addition, although we do not at this

time find it necessary to require power

pools to form an independent system

operator in order to remedy undue

discrimination, we believe ISOs may

prove to be an effective means for
21594 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

417The DOJ and DOE suggested that the

Commission examine operational unbundling as a

way of enforcing comparability in transmission

service. DOJ and DOE believe that functional

unbundling may not be adequate to ensure

comparability and so have recommended that some

form of operational unbundling be required. While

we believe that requiring this is premature, we note

that an ISO is one way to achieve operational

unbundling and we encourage the voluntary

development of ISOs.

accomplishing comparable access.417

We recognize that several utilities are

exploring the possibility of forming

ISOs. For example, discussions are

ongoing in California, PJM, NYPP, and

the Midwest. Therefore, because of the

industry’s interest (which we share) in

the concept of an ISO and the potential

for an ISO to provide nondiscriminatory transmission services to

all market participants, we will provide

guidance in this section on minimum

ISO characteristics.

1. Tight Power Pools

For purposes of this Rule, the tight

power pools are: New York Power Pool

(NYPP), New England Power Pool

(NEPOOL), Pennsylvania-New JerseyMaryland Interconnection (PJM), and

the Michigan Electric Coordinated

Systems (MECS).

Public utilities who are members of a

tight pool must file, within 60 days of

publication of the Final Rule in the

Federal Register, either: (1) An

individual Final Rule pro forma tariff; or

(2) a joint pool-wide Final Rule pro

forma tariff. They are not required to

take service for pool transactions under

the tariff that is filed within 60 days.

However, they will be required to file a

joint pool-wide Final Rule pro forma

tariff no later than December 31, 1996,

and must begin to take service under

that tariff for all pool transactions no

later than December 31, 1996. The

purpose of this extension is to allow

sufficient time for tight pools to amend

their pooling agreements and to

restructure their operations to conform

to the requirements of the Final Rule.

We also believe that the additional time

is necessary to preserve efficient trading

arrangements during the restructuring

period.

The Commission therefore will

require that the public utility members

of tight pools file reformed power

pooling agreements no later than

December 31, 1996. The reformed power

pool agreements should establish open,

non-discriminatory membership

provisions (including establishment of

an ISO, if that is a pool’s preferred

method of remedying undue

discrimination) and modify any

provisions that are unduly

discriminatory or preferential. The

membership provision must allow any

bulk power market participant to join,

regardless of the type of entity,

affiliation, or geographic location.

If the reformed agreement allows

members to make transmission

commitments or contributions in

exchange for the discounted

transmission rates, the pool may file a

transmission tariff that contains an

access fee for non-transmission owning

members or non-members, justified

solely on the basis of transmissionrelated costs. Alternatively, the pool

could make available a transmission rate

that is structured the same as the

discounted rate (e.g., non-pancaked) but

with a higher rate that is justified on the

basis of transmission-related costs borne

(or contributed) by the pool members.

However, any such access fee or higher

rate must be justified solely on the basis

of transmission costs and cannot be tied

to the costs of any other agreement

among the pool members (e.g.,

generation reserve sharing).

2. Loose Pools

For purposes of the Final Rule, a loose

pool is any multi-lateral (more than 2

public utilities) arrangement, many of

which contain discounted and/or

special transmission arrangements.

Examples are MAPP, Inland Power Pool,

and the MOKAN pool. Other entities

may qualify to be treated as a loose pool

if they can show that they meet the

definition above.

Public utilities within a loose pool

must file, within 60 days of publication

of the Final Rule in the Federal

Register, either: (1) An individual Final

Rule pro forma tariff; or (2) a pool-wide

Final Rule pro forma tariff. They are not

required to take service for pool

transactions under the tariff that is filed

within 60 days. However, they will be

required to file a joint pool-wide Final

Rule pro forma tariff no later than

December 31, 1996, and must begin to

take service under that tariff for all pool

transactions no later than December 31,

1996. The purpose of this extension is

to allow sufficient time for loose pools

to amend their agreements and to

restructure their operations to conform

to the requirements of the Final Rule.

We also believe that the additional time

is necessary to preserve efficient trading

arrangements during the restructuring

period.

The Commission therefore will

require that the public utility members

of loose pools file reformed power

pooling agreements no later than

December 31, 1996. They also must file

a joint pool-wide tariff no later than

December 31, 1996. The reformed power

pool agreements should establish open,

non-discriminatory membership

provisions and modify any provisions

that are unduly discriminatory or

preferential. The membership provision

must allow any bulk power market

participant to join, regardless of the type

of entity, affiliation, or geographic

location.

The Commission recognizes that loose

pools typically do not operate as a

single control area and that operational

unbundling, perhaps through an ISO,

might not be readily attainable at this

time. Nonetheless, we encourage the

members of loose pools to explore the

advantages of the ISO concept.

If the reformed agreement allows

members to make transmission

commitments or contributions in

exchange for discounted transmission

rates, the pool may file a transmission

tariff that contains an access fee for nontransmission owning members or nonmembers, justified solely on the basis of

transmission-related costs.

Alternatively, the pool could make

available a transmission rate that is

structured the same as the discounted

rate (e.g., non-pancaked) but with a

higher rate that is justified on the basis

of transmission-related costs borne (or

contributed) by the pool members.

However, any such access fee or higher

rate must be justified solely on the basis

of transmission costs and cannot be tied

to the costs of any other agreement

among the pool members (e.g.,

generation reserve sharing).

3. Public Utility Holding Companies

Public utility members of registered

and exempt holding companies that are

also members of tight or loose pools are

subject to the tight and loose pool

requirements set forth above. The

remaining holding company public

utility members, with the exception of

the Central and South West (CSW)

System, are required to file a single

system-wide Final Rule pro forma tariff

permitting transmission service across

the entire holding company system at a

single price within 60 days of

publication of the Final Rule in the

Federal Register (service companies

may, of course, file on behalf of their

public utility affiliates). As discussed

below, CSW presents special

circumstances.

The CSW System is comprised of four

operating public utilities. Two of those

utilities, Southwestern Electric Power

Company (SWEPCO) and Public Service

Company of Oklahoma (PSO) operate in

the Southwest Power Pool (SPP). The

other two, West Texas Utilities

Company (West Texas) and Central

Power and Light Company (CP&L),

operate in the Electric Reliability
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21595

418The North and East Interconnections were

ordered by the Commission pursuant to sections

210, 211 and 212 of the Federal Power Act. See

Central Power and Light Company, et al., 17 FERC

¶ 61,078 (1981), order on reh’g, 18 FERC ¶ 61,100

(1982); 40 FERC ¶ 61,077 (1987).

419Houston Lighting and Power Company (HL&P)

and Texas Utilities Electric Company (TU) also

have on file ‘‘to or from and over tariffs’’ pursuant

to the Commission orders.

420See, e.g., CP&L and West Texas Interpool

Transmission Service Tariff, § 4.1.

421Compare 21 TEX REG 1397, LEXIS, mimeo at

18 (adopting hybrid pricing scheme with 70% of

transmission rate based on regional postage stamp

method and 30% based on the vector-absolute

megawatt-mile method) with Id. at Article III.

We note that the Texas Commission concluded

that the ERCOT portion of the costs of the North

and East Interconnections ‘‘should be included in

the cost of service, when the owners of the

(Interconnections) amend the FERC tariffs for the

use of the (Interconnections) to provide equal

access to other utilities. 21 TEX REG, LEXIS, mimeo

at 24.

422 It may be appropriate to have different rates for

transmission service wholly within ERCOT or the

SPP, and for service between the reliability

councils. However, the same rates, terms, and

conditions applicable for third parties should also

be applicable to the CSW System’s wholesale

transmission requirements.

423We recognize that this action may require

amendment to the Commission’s orders under FPA

sections 210, 211, and 212, ordering the North and

East Interconnections. In this regard, it should be

clearly understood that the Commission’s action in

requiring comparable service by the CSW System is

not in any way intended to result in public utility

status to any ERCOT participants that are not public

utilities—e.g., HL&P and TU. See 16 U.S.C.

824(b)(2).

424All discounts must be posted on the

transmission provider’s OASIS.

Council of Texas (ERCOT). SWEPCO

and PSO exchange power with West

Texas and CP&L through two high

voltage, direct current interconnections

(the North and East Interconnections).418

Pursuant to the Commission orders

concerning the North and East

Interconnections, CP&L, West Texas,

SWEPCO, and PSO have on file what

are referred to as the ‘‘to or from and

over tariffs.’’ 419 Those tariffs apply only

to transmission service that involves the

delivery of power and energy to or from

and over the North and East

Interconnections.420 The tariffs do not

apply to the transmission of power for

CSW subsidiaries other than the

operating companies. The tariffs in

many respects are different from the

Final Rule pro forma tariff and do not

provide comparable services. Moreover,

the pricing provided in the ‘‘to or from

and over’’ tariffs is different from the

pricing set forth in the Texas

Commission’s final open access rule.421

Given these special circumstances, we

believe it appropriate to give CSW the

opportunity to propose a solution to

achieving comparability for the CSW

system. Accordingly, we direct the

public utility subsidiaries of CSW to

consult with the Texas, Arkansas,

Oklahoma and Louisiana Commissions

and to file not later than December 31,

1996 a system tariff that will provide

comparable service to all wholesale

users on the CSW System,422 regardless

of whether they take transmission

service wholly within ERCOT or the

SPP, or take transmission service

between the reliability councils over the

North and East Interconnections.423

The Commission will give public

utilities that are members of holding

companies an extension of the

requirement to take service under the

system tariff for wholesale trades

between and among the public utility

operating companies within the holding

company system. This extension is until

December 31, 1996—the same extension

we are granting to power pools. At that

point, the public utility operating

companies will be required to take

service under the Final Rule pro forma

tariff for wholesale trades among

themselves. In addition, it may be

necessary for registered holding

companies to reform their holding

company equalization agreement to

recognize the non-discriminatory terms

and conditions of transmission service

required under the Final Rule pro forma

tariff.

4. Bilateral Coordination Arrangements

Any bilateral wholesale coordination

agreement executed after the effective

date of this Rule will be subject to the

functional unbundling and open access

requirements set forth in this Rule. With

regard to existing bilateral agreements,

however, the diversity of the types of

agreements currently on file presents

special implementation problems. The

Commission is particularly concerned

with future economy energy

transactions that may occur pursuant to

existing umbrella-type coordination

agreements. Accordingly, we shall

require all bilateral economy energy

coordination contracts executed before

the effective date of this Rule to be

modified to require unbundling of any

economy energy transaction occurring

after December 31, 1996. All noneconomy energy bilateral coordination

contracts executed before the effective

date of this Rule will be permitted to

continue in effect, but will be subject to

complaints filed under section 206 of

the FPA. Under those procedures, the

rates, terms, and conditions of

individual coordination contracts may

be challenged as unduly discriminatory

or otherwise unlawful.

To compute the unbundled

coordination compliance rate, the utility

must subtract the corresponding

transmission unit charge in its open

access tariff from the existing

coordination rate ceiling. For example,

if a utility has a coordination rate

ceiling for hourly service of incremental

cost plus 15 mills/kWh and a

transmission tariff rate for hourly

service of 3 mills/kWh, it shall revise

the coordination rate ceiling to

incremental cost plus 12 mills/kWh.

The Commission cautions that the

compliance filing will be strictly limited

to removing the current transmission

tariff price from the coordination price

and will not be a medium for otherwise

revising the residual coordination sales

price.

The transmission rate for the

coordination transactions may be at or

below the tariff rate. However, if a

utility’s transmission operator offers a

discounted transmission rate to the

utility’s wholesale marketing

department or an affiliate for the

purposes of coordination transactions,

the same discounted rate must be

offered to others for trades with any

party to the coordination agreement. In

addition, discounts offered to nonaffiliates must be on a basis that is not

unduly discriminatory.424 This may

require parties to file modifications of

the coordination arrangements.

ISO Principles

The Commission recognizes that some

utilities are exploring the concept of an

Independent System Operator and that

the tight power pools are considering

restructuring proposals that involve an

ISO. While the Commission is not

requiring any utility to form an ISO at

this time, we wish to encourage the

formation of properly-structured ISOs.

To this end, we believe it is important

to give the industry some guidance on

ISOs at this time. Accordingly, we here

set out certain principles that will be

used in assessing ISO proposals that

may be submitted to the Commission in

the future.

These principles are applicable only

to ISOs that would be control area

operators, including any ISO established

in the restructuring of power pools. We

recognize that some utilities are

exploring concepts that do not involve

full operational control of the grid.

Without in any way prejudging the

merits of such arrangements, the

following principles do not apply to

independent administrators or

coordinators that lack operational

control. We do not have enough

information at this time to offer

guidance about such entities, but
21596 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

425A public utility is any person that owns or

operates facilities used for the transmission of

electric energy in interstate commerce or the sale

of electric energy at wholesale in interstate

commerce. An ISO will operate facilities used for

the transmission of electric energy in interstate

commerce and thus will be subject to the Open

Access and OASIS rules.

recognize that they could perform a

useful role in a restructured industry.

Because an ISO will be a public utility

subject to our jurisdiction,425 the ISO’s

operating standards and procedures

must be approved by the Commission.

In addition, a properly constituted ISO

is a means by which public utilities can

comply with the Commission’s nondiscriminatory transmission tariff

requirements. The principles for ISOs

are:

1. The ISO’s governance should be

structured in a fair and nondiscriminatory manner. The primary

purpose of an ISO is to ensure fair and

non-discriminatory access to

transmission services and ancillary

services for all users of the system. As

such, an ISO should be independent of

any individual market participant or

any one class of participants (e.g.,

transmission owners or end-users). A

governance structure that includes fair

representation of all types of users of the

system would help ensure that the ISO

formulates policies, operates the system,

and resolves disputes in a fair and nondiscriminatory manner. The ISO’s rules

of governance, however, should prevent

control, and appearance of control, of

decision-making by any class of

participants.

2. An ISO and its employees should

have no financial interest in the

economic performance of any power

market participant. An ISO should

adopt and enforce strict conflict of

interest standards. To be truly

independent, an ISO cannot be owned

by any market participant. We recognize

that transmission owners need to be

able to hold the ISO accountable in its

fiduciary role, but should not be able to

dictate day-to-day operational matters.

Employees of the ISO should also be

financially independent of market

participants. We recognize, however,

that a short transition period (we believe

6 months would be adequate) will be

needed for employees of a newly formed

ISO to sever all ties with former

transmission owners and to make

appropriate arrangements for pension

plans, health programs and so on. In

addition, an ISO should not undertake

any contractual arrangement with

generation or transmission owners or

transmission users that is not at arm’s

length. In order to ensure independence,

a strict conflict of interest standard

should be adopted and enforced.

3. An ISO should provide open access

to the transmission system and all

services under its control at nonpancaked rates pursuant to a single,

unbundled, grid-wide tariff that applies

to all eligible users in a nondiscriminatory manner. An ISO should

be responsible for ensuring that all users

have non-discriminatory access to the

transmission system and all services

under ISO control. The portion of the

transmission grid operated by a single

ISO should be as large as possible,

consistent with the agreement of market

participants, and the ISO should

schedule all transmission on the portion

of the grid it controls. An ISO should

have clear tariffs for services that

neither favor nor disfavor any user or

class of users.

4. An ISO should have the primary

responsibility in ensuring short-term

reliability of grid operations. Its role in

this responsibility should be welldefined and comply with applicable

standards set by NERC and the regional

reliability council. Reliability and

security of the transmission system are

critical functions for a system operator.

As part of this responsibility an ISO

should oversee all maintenance of the

transmission facilities under its control,

including any day-to-day maintenance

contracted to be performed by others.

An ISO may also have a role with

respect to reliability planning. In any

case, the ISO should be responsible for

ensuring that services (for all users,

including new users) can be provided

reliably, and for developing and

implementing policies related to

curtailment to ensure the on-going

reliability and security of the system.

5. An ISO should have control over

the operation of interconnected

transmission facilities within its region.

An ISO is an operator of a designated set

of transmission facilities.

6. An ISO should identify constraints

on the system and be able to take

operational actions to relieve those

constraints within the trading rules

established by the governing body.

These rules should promote efficient

trading. A key function of an ISO will

be to accommodate transactions made in

a free and competitive market while

remaining at arm’s length from those

transactions. The ISO may need to

exercise some level of operational

control over generation facilities in

order to regulate and balance the power

system, especially when transmission

constraints limit trading over interfaces

in some circumstances. It is important

that the ISO’s operational control be

exercised in accordance with the trading

rules established by the governing body.

The trading rules should promote

efficiency in the marketplace. In

addition, we would expect that an ISO

would provide, or cause to be provided,

the ancillary services described in this

Rule.

7. The ISO should have appropriate

incentives for efficient management and

administration and should procure the

services needed for such management

and administration in an open

competitive market. Management and

administration of the ISO should be

carried out in an efficient manner. In

addition to personnel and

administrative functions, an ISO could

perform certain operational functions,

such as: determination of appropriate

system expansions, transmission

maintenance, administering

transmission contracts, operation of a

settlements system, and operation of an

energy auction. The ISO should use

competitive procurement, to the extent

possible, for all services provided by the

ISO that are needed to operate the

system. All procedures and protocols

should be publicly available.

8. An ISO’s transmission and

ancillary services pricing policies

should promote the efficient use of and

investment in generation, transmission,

and consumption. An ISO or an RTG of

which the ISO is a member should

conduct such studies as may be

necessary to identify operational

problems or appropriate expansions.

Appropriate price signals are essential

to achieve efficient investment in

generation and transmission and

consumption of energy. The pricing

policies pursued by the ISO should

reflect a number of attributes, including

affording non-discriminatory access to

services, ensuring cost recovery for

transmission owners and those

providing ancillary services, ensuring

reliability and stability of the system

and providing efficient price signals of

the costs of using the transmission grid.

In particular, the Commission would

consider transmission pricing proposals

for addressing network congestion that

are consistent with our Transmission

Pricing Policy Statement. In addition, an

ISO should conduct such studies and

coordinate with market participants

including RTGs, as may be necessary to

identify transmission constraints on its

system, loop flow impacts between its

system and neighboring systems, and

other factors that might affect system

operation or expansion.

9. An ISO should make transmission

system information publicly available

on a timely basis via an electronic

information network consistent with the

Commission’s requirements. A free-flow
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21597

426FERC Stats. & Regs. ¶ 32,514 at 33,079.

427 Id. at 33,092.

428On October 27, 1995, the Commission’s staff

sponsored a technical conference on the pro forma

tariffs.

429American Electric Power Service Corporation,

et al., 71 FERC ¶ 61,393, modified, 72 FERC ¶

61,287 (1995).

430The Final Rule pro forma tariff is attached as

Appendix D.

431Additional comments concerning transition to

flow-based pricing are summarized in Section

IV.A.6.

of information between the ISO and

market participants is required for an

ISO to perform its functions and for

market participants to efficiently

participate in the market. At a

minimum, information on system

operation, conditions, available capacity

and constraints, and all contracts or

other service arrangements of the ISO

should be made publicly available. This

information should be made available

on an OASIS operated by the ISO.

10. An ISO should develop

mechanisms to coordinate with

neighboring control areas. An ISO will

be required to coordinate power

scheduling with other entities operating

transmission systems. Such

coordination is necessary to ensure

provision of transmission services that

cross system boundaries and to ensure

reliability and stability of the systems.

The mechanisms by which ISOs and

other transmission operators coordinate

can be left to those parties to determine.

11. An ISO should establish an ADR

process to resolve disputes in the first

instance. An ISO should provide for a

voluntary dispute resolution process

that allows parties to resolve technical,

financial, and other issues without

resort to filing complaints at the

Commission. We would encourage the

ISO to establish rules and procedures to

implement alternative dispute

resolution processes.

G. Pro Forma Tariff

In the NOPR, the Commission stated

that—

all utilities use their own systems in two

basic ways: to provide themselves point-topoint transmission service that supports

coordination sales, and to provide

themselves network transmission service that

supports the economic dispatch of their own

generation units and purchased power

resources (integrating their resources to meet

their internal loads). 426

Accordingly, the Commission

proposed two pro forma tariffs in

Appendices B and C of the NOPR: One

for point-to-point service and one for

network service. Our goal was to

encourage the development of

competitive bulk power markets by

ensuring that all participants would be

able to secure transmission services on

a non-discriminatory basis. We

attempted in the NOPR pro forma tariffs

to articulate the minimally acceptable

terms and conditions of service for

point-to-point and network transmission

service that were required to ensure

non-discriminatory transmission

service.427 We explained that, for the

most part, specific pricing provisions

were omitted. We asked for comments

on whether these tariffs provided a good

basis for defining the minimum

acceptable non-price terms and

conditions of service.428

Subsequently, in a June 28, 1995

order, we encouraged public utilities to

file open access transmission tariffs as

soon as possible.429 Tariffs with terms

and conditions of service substantively

similar to the NOPR pro forma tariffs

would become effective without a

refund condition, assuming there were

no other concerns, e.g., rate issues. We

also indicated that these tariffs would be

subject to revision based on the Final

Rule.

Unified Pro Forma Tariff

The Commission received many

comments on both the point-to-point

and network tariffs. Many commenters

suggested improvements to the

proposed tariffs. Others took issue with

how to reconcile various aspects of

service under the two tariffs (e.g., cost

allocation, service priority, customer

rights and obligations). As discussed

below, the Commission has attempted to

address these concerns in developing

tariff requirements for the Final Rule.

Importantly, while the Commission has

retained point-to-point transmission

service and network transmission

service as distinct services, the

requirements for the two services are

now in a single pro forma tariff.430 The

Final Rule pro forma tariff eliminates

many of the differences between the two

NOPR pro forma tariffs, provides a

unified set of definitions, and

consolidates certain common

requirements such as the obligation to

provide ancillary services. The general

terms and conditions of transmission

service specified in the Final Rule pro

forma tariff should be familiar to all

utilities, particularly those that have

voluntarily filed open access tariffs

based on the NOPR pro forma tariffs.

The Commission believes that the

modified, single pro forma tariff, in

conjunction with the other

requirements, is sufficient to remedy

undue discrimination in the provision

of transmission services. However, we

note that in an accompanying notice of

proposed rulemaking in Docket No.

RM96–11–000, we are seeking

comments on whether a different form

of open access tariff—one based solely

on a capacity reservation system—might

better accommodate competitive

changes occurring in the industry while

ensuring that all wholesale transmission

service is provided in a fair and nondiscriminatory manner.

We address below the comments

received on the NOPR tariff and the

specific modifications we have made in

the Final Rule pro forma tariff.

1. Tariff Provisions That Affect The

Pricing Mechanism

a. Non-Price Terms and Conditions

Comments

Utilities For Improved Transition

argues that any generic imposition of

detailed tariffs on the electric industry

will stifle the evolution of the industry.

Rather, it asserts, utilities that supply

transmission service should be

permitted to apply general principles of

comparability in their company-specific

tariffs, using terms and conditions of

service based on their own particular

circumstances and those of their

customers.

Utility Working Group wants the final

rule to allow utilities to depart from the

pricing method implicitly contained in

the NOPR pro forma tariffs. It argues

that the final rule should recognize that

some terms and conditions may not

make sense in the context of innovative

pricing proposals.

DOE thinks that it is proper to base

the tariffs on a familiar and simple

pricing method. However, DOE suggests

that, in the future, the Commission

carefully assess the workability of the

contract path model in a competitive

bulk power market. DOE suggests that

spot or real-time pricing should be

considered.

Numerous commenters contend that

the NOPR pro forma tariffs are based

upon the contract path, embedded cost

methodology. According to EEI and

other IOU commenters, conforming

changes may be needed to various terms

and conditions of the tariffs to

implement pricing methodologies that

are not based upon contract path. These

commenters argue that any flow-based

model would necessitate different nonprice terms and conditions. The

commenters generally recognize the

technical difficulties of implementing a

flow-based model.431 These commenters

assert that the NOPR pro forma tariffs,

as written, are not independent of

pricing.

EGA criticizes the assumption

underlying the contract path approach,
21598 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

432E.g., BPA, Utilities For Improved Transition,

PG&E, Duke.

433We further clarify that, contrary to some

commenters’ interpretation, the Final Rule pro

forma tariff is in no way a rejection of opportunity

or incremental cost pricing.

434As noted in Section IV.H., public utilities may

propose variations that are consistent with or

superior to the terms and conditions in the Final

Rule pro forma tariff.

435E.g., PSNM, WP&L.

436Florida Power Corp’s contract demand

proposal would allow a network customer to

nominate less than its full load for transmission

service. 437E.g., Cajun, NRECA.

i.e., that the capacities of individual

transmission paths can be determined

independently and made available to

third parties. EGA notes that, in light of

the competitive implications associated

with transmission pricing, some utilities

may propose other non-price terms and

conditions suitable for other pricing

methods, including power-flow-based

tariffs. EGA expresses concern that the

pro forma tariffs will be the only type

of tariff allowed. EGA believes that the

Commission should follow its

transmission pricing policy guidelines

and not impose a special burden on

parties proposing tariffs that differ from

the final rule pro forma tariffs, including

non-price terms that support alternative

pricing methods.

Some commenters also interpret the

lack of reference to opportunity cost and

incremental cost in the NOPR pro forma

tariffs as a rejection of their use.432

Commission Conclusion

We agree that non-price terms and

conditions cannot be designed

independent of pricing and cost

recovery. As discussed in detail below,

the Final Rule pro forma tariff is

intended to initiate open access, with

non-price terms and conditions based

on the contract path model of power

flows and embedded cost ratemaking. It

is designed based on the practices and

procedures currently used by virtually

all public utilities and complements the

large number of tariffs already filed with

the Commission. The Final Rule pro

forma tariff is not intended to signal a

preference for contract path/embedded

cost pricing for the future. We recognize

that the industry, in response to changes

in institutions, competitive pressure,

and technological innovations, is

evolving rapidly. For example, various

forms of flow-based pricing are

beginning to be considered in

conjunction with electronic

transmission information systems. We

seek to encourage this process and will

in the future entertain nondiscriminatory tariff innovations to

accommodate new pricing proposals.433

In response to various comments, we

are revising certain non-price terms and

conditions where suggested changes

either improve the tariff services or

reconcile tariff inconsistencies. The

nature of these tariff revisions does not

appear to have serious cost

consequences. The mandated changes

are generally compatible with the rate

proposals already filed by many public

utilities. As discussed in Section IV.H.,

those utilities will not be required to file

corresponding rate changes due to our

mandated tariff changes to non-price

terms and conditions, although they

will be permitted to do so.

The Final Rule pro forma tariff

includes specific terms and conditions

rather than general principles. By

initially requiring a standardized

tariff,434 we intend to foster broad access

across multiple systems under

standardized terms and conditions.

However, in response to concerns raised

by certain commenters, the tariff

provides for certain deviations where it

can be demonstrated that unique

practices in a geographic region require

modifications to the Final Rule pro

forma tariff provisions. Accordingly,

where applicable, the tariff permits the

use of alternative non-price terms or

conditions that are reasonable, generally

accepted in the region, and consistently

adhered to by the transmission provider.

Finally, we will allow utilities to

propose a single cost allocation method

for network and point-to-point

transmission services. These principles,

as well as other modifications and

clarifications to the NOPR pro forma

tariffs, are discussed in detail below.

b. Load Ratio Sharing Allocation

Mechanism for Network Service

Comments

Some commenters believe that load

ratio cost allocation is appropriate for

network service.435 Other commenters

argue that load ratio cost allocation is

inappropriate, but disagree on the

alternative. They offer a variety of other

cost allocation and pricing methods.

The most frequent comment is that

network and point-to-point services

should be priced on the same basis.

Florida Power Corp wants network

contract demand to be offered and

priced on a 12 CP basis.436 ConEd and

Duke argue that their systems are built

and designed to meet a single peak;

therefore, they contend that network

service costs should be allocated with a

load ratio calculation based on annual

system peak rather than 12 CP. PSE&G

claims that load ratio cost allocation

works only if the customer has its own

generation. Many commenters propose

that ‘‘behind the meter’’ generation and

load be eliminated from the network

load ratio calculation.437

CINergy notes that the transmission

provider’s monthly load ratio

calculation includes its long-term offsystem firm service. It proposes that offsystem sales be eliminated from the load

ratio calculation to enable the

transmission provider to offer discounts

on long-term service. Alternatively,

CINergy proposes that the revenues

from these long-term off-system sales be

shared with network customers based

on their load ratio.

Atlantic City and Allegheny contend

that cost allocation for network service

should also reflect customers’ relative

energy use (i.e., not just customers’

coincident demand). Consequently,

these commenters propose that cost

allocation consider the network

customer’s actual load factor. Allegheny

also proposes adding a minimum

revenue provision to the load ratio

method to recognize cost responsibility

for non-peak use. Allegheny further

proposes to include an increasing return

on equity as available transmission

capacity decreases. EEI proposes that

cost allocation be based on a customer’s

non-coincident peak demand.

Lower Colorado River Authority

proposes using load flow studies to

determine planned use during the

system peak with MW-mile billing

units. It believes that this pricing

method should be used for all

transmission service to ensure

comparable transmission pricing.

Oklahoma G&E wants cost allocation to

be based on the impacted MW-mile

method, or alternatively, to determine

embedded cost by voltage level.

Centerior proposes the use of actual

transfer capability instead of contract

path capability in determining cost

responsibility.

Orange & Rockland recommends some

form of a ‘‘poolco’’ approach using

locational marginal cost pricing. DOE

also recommends using location-specific

spot pricing (a form of marginal cost) for

operating and congestion costs.

Public Generating Pool believes that

load ratio share pricing is unworkable in

the Pacific Northwest, in part because

generation is generally located outside

of the control area directly served by

parties in the Northwest, and in part

because BPA, which does not have a

typical service territory, dominates the

regional transmission market. Seattle

states that cost allocation based solely

on demand is inappropriate for systems
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21599

438Additional comments concerning the Pacific

Northwest are summarized in Section IV.K.

439E.g., OH Coops, Municipal Energy Agency

Nebraska, UT Com.

440Florida Municipal Power Agency v. Florida

Power & Light Company, 74 FERC ¶ 61,006 (1996),

reh’g pending.

441Under the annual system peak method, system

costs are allocated on the basis of each customer’s

contribution to the utility’s annual system peak.

Under the 12 CP method, system costs are allocated

based on the average of the customer’s usage at the

time of the utility’s 12 monthly system peaks.

442A ratchet is a billing provision that imposes

minimum payment obligations on utility customers.

443See also Centerior, SCE&G, Detroit Edison.

that consist predominantly of hydro

generation.438

AEC & SMEPA and NRECA are

concerned about pancaked rates for

network service that is provided to load

served by more than one network tariff.

Other commenters advocate use of some

form of regional pricing.439 American

Wind proposes the use of a complex

seasonal calculation, which appears to

benefit wind energy. NY Com and

Missouri-Kansas Industrials also express

a preference for seasonal pricing

models.

Commission Conclusion

We conclude that the load ratio

allocation method of pricing network

service continues to be reasonable for

purposes of initiating open access

transmission. Network service permits a

transmission customer to integrate and

economically dispatch its resources to

serve its load in a manner comparable

to the way that the transmission

provider uses the transmission system

to integrate its generating resources to

serve its native load. Because network

service is load based, it is reasonable to

allocate costs on the basis of load for

purposes of pricing network service.

This method is familiar to all utilities,

is based on readily available data, and

will quickly advance the industry on the

path to non-discrimination. We are

reaffirming the use of a twelve monthly

coincident peak (12 CP) allocation

method because we believe the majority

of utilities plan their systems to meet

their twelve monthly peaks. Utilities

that plan their systems to meet an

annual system peak (e.g., ConEd and

Duke) are free to file another method if

they demonstrate that it reflects their

transmission system planning.

Moreover, we recognize that alternative

allocation proposals may have merit and

welcome their submittal by utilities in

future rate applications. They will be

evaluated on a case-by-case basis and

decided on their merits.

As to the concerns raised by AEC &

SMEPA and NRECA about pancaked

rates for network service provided to

load served by more than one network

service provider, we have stated that if

a customer wishes to exclude a

particular load at discrete points of

delivery from its load ratio share of the

allocated cost of the transmission

provider’s integrated system, it may do

so.440 Customers that elect to do so,

however, must seek alternative

transmission service for any such load

that has not been designated as network

load for network service. This option is

also available to customers with load

served by ‘‘behind the meter’’

generation that seek to eliminate the

load from their network load ratio

calculation.

As noted, the most frequent comment

is that the network and point-to-point

services should be priced on a similar

basis. This concern is addressed in the

next section.

c. Annual System Peak Pricing for

Flexible Point-to-Point Service

Comments

Commenters express concern that, if

annual system peak capability is used to

determine rates for point-to-point

service and 12 CP is used to allocate

costs for network service, point-to-point

service may be underpriced relative to

network service.441 Therefore, many

commenters propose pricing both

services on the same basis.

EEI argues that flexible point-to-point

service provides a premium service at a

discount price. Therefore, EEI would

increase the price unless the

Commission either (1) eliminates the

flexibility or (2) allows network

customers to make non-firm sales at no

additional charge. It recommends use of

12 CP for pricing both network and

point-to-point service, but would credit

point-to-point revenues to the cost of

service for network and native load to

avoid over-collection from contract

demand point-to-point users.

Alternatively, EEI contends that pointto-point service could use annual

system peak capability pricing with a

ratchet,442 although EEI believes that 12

CP reflects the premium nature of longterm transmission. Under this

alternative method, EEI notes that longterm non-flexible point-to-point service

would use annual system peak pricing,

while short-term service should be

based on ‘‘up to’’ (ceiling) rates. In

essence, EEI proposes a two-tier pointto-point service, with the first tier

(flexible service) of equal priority in all

respects to network service.443 Ohio

Edison also claims that, as proposed,

flexible point-to-point service is a more

valuable service than network service

because it would be priced lower than

network service. To correct for this

difference, Ohio Edison would impose a

separate rate for point-to-point non-firm

use.

According to NRECA, unless the same

measure of demand is included in the

calculation of network and point-topoint charges, actual revenue from these

two firm services will be greater than

the actual cost of service. FL Com

believes that flexible point-to-point

service allows a transmission customer

to engage in network economy

transactions without incurring a full

network charge, thus gaining an

advantage over the transmission

provider. Atlantic City recommends that

the Commission either (1) eliminate the

flexibility of point-to-point service or (2)

price such service on a 12 CP basis. It

claims that the use of an annual system

peak capability creates a higher value

service at a lower cost than network

service. Based on its 1994 system data,

Atlantic City claims that there is a 33

percent difference in rates between

network and point-to-point services.

Atlantic City also opposes the

requirement to offer point-to-point

service on an hourly basis, claiming

that, unlike the point-to-point service

customer, native load and network

service customers are responsible for

system investment year-round. Atlantic

City also argues that point-to-point

customers should pay for all non-firm

use, i.e., the Commission should

eliminate the flexible nature of firm

point-to-point service. PSE&G argues

that point-to-point service should be

used only for through-flow or out-flow

transactions with all other transactions

treated as network service. Thus,

according to PSE&G, point-to-point

service would not need flexibility.

If an annual system peak capability is

used, Oklahoma G&E would redefine

point-to-point service to eliminate the

flexibility. FPL recommends either

eliminating the flexibility to nominate

secondary receipt and delivery points

and receive non-firm service between

them or pricing point-to-point service as

premium service (i.e., at a higher price

than network service). Florida Power

Corp claims that flexibility should be

associated with network service, not

point-to-point service. It also argues that

revenues from point-to-point service

should be credited against total

transmission costs. It would similarly

exclude point-to-point demands from

the derivation of the network rate.

Utility Working Group claims that if

flexible point-to-point service is

retained, such service should be priced

at a higher (unspecified) rate or the nonfirm secondary use should be separately

priced. It believes that all users should
21600 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

444 In this context, diversity occurs when a

customer’s peak demand is not coincident with the

transmission provider’s system peak demand.

445The use of this rate design is particularly

applicable where customers who were taking

bundled service convert to transmission-only

service under the point-to-point tariff and ensures

that transmission costs are allocated to point-topoint customers and network customers in a

consistent manner. 446FERC Stats. & Regs. ¶ 31,005 (1994).

pay for non-firm use, or if there is no

additional charge under the point-topoint tariff, network customers and the

transmission provider should be treated

equally. SMUD argues that a user who

does not want flexibility should have an

option to elect a lower-priced nonflexible point-to-point service.

Commission Conclusion

We agree that pricing both services on

a consistent basis may be appropriate.

Consequently, we will allow a

transmission provider to propose a

formula rate that assigns costs

consistently to firm point-to-point and

network services. While not requiring

the use of any particular rate

methodology, we will no longer

summarily reject a firm point-to-point

transmission rate developed by using

the average of the 12 monthly system

peaks.

Our previous rationale for not using

the average of the twelve-monthly peaks

as a denominator in the development of

non-customer specific transmission

rates was enunciated in Southern

Company Services, Inc., 61 FERC

¶ 61,339 (1992) (Southern). In Southern,

the Commission was concerned that

establishing a system-wide, noncustomer specific transmission service

rate that did not appropriately account

for diversity 444 among various

transmission customers might result in

the over-recovery of revenues for pointto-point service. Inherent in our ruling

in Southern was the understanding that

once a sufficient pattern of customer

usage under the tariff was established,

the company was free to file a customerspecific rate using the average of the 12

monthly system peaks for cost

allocation. We still believe that it is

appropriate for utilities to use a

customer-specific allocated cost of

service 445 to account for diversity, but

based on the changed circumstances

since Southern (which we discuss

below) we will now permit an

alternative.

We also note that the circumstances

in Southern are distinguishable from

those now present in the industry.

Southern proposed a rigid, inflexible

firm point-to-point transmission service

where the customer paid separately for

each delivery and receipt point

combination. The only flexibility

permitted was to use alternative receipt

and delivery points on a non-firm basis

at no additional charge. As the name

implies, the flexible nature of the pointto-point transmission service proposed

in the NOPR is more akin to the service

provided to native load and network

service customers. Contrary to what was

proposed in Southern, point-to-point

service does not require separate

charges for each firm service receipt and

delivery point combination. Rather,

customers pay on the basis of the higher

of the total delivery points or total

receipt point combination. Flexible

point-to-point transmission customers

continue to be able to access alternative

receipt and delivery points on a nonfirm basis without additional charges (as

long as they remain within their

capacity reservation). In addition, firm

point-to-point customers can reassign

and resell unused portions of their

reserved firm capacity to third parties.

With flexible firm and non-firm pointto-point transmission service, the

transmission provider must make firm

point-to-point transmission capacity

available to the customer regardless of

its load characteristics or use.

For these reasons, we will allow all

firm transmission rates, including those

for flexible point-to-point service, to be

based on adjusted system monthly peak

loads. The adjusted system monthly

peak loads consist of the transmission

provider’s total monthly firm peak load

minus the monthly coincident peaks

associated with all firm point-to-point

service customers plus the monthly

contract demand reservations for all

firm point-to-point service.

The flexibility and reassignment

rights of this transmission service

require the transmission provider to

hold the firm contract capacity available

regardless of the customer’s own load

characteristics or its actual use. In other

words, a transmission provider’s

obligation to plan for, and its ability to

use, a transmission customer’s reserved

capacity is clearly defined by that

customer’s contract reservation. For

these reasons, it is appropriate to

consider a firm reservation as the

equivalent of a load for cost allocation

and planning purposes.

In order to prevent over-recovery of

costs for those who use this approach,

we will require transmission providers

to include firm point-to-point capacity

reservations in the derivation of their

load ratio calculations for billings under

network service. In addition, revenue

from non-firm services should continue

to be reflected as a revenue credit in the

derivation of firm transmission tariff

rates. The combination of allocating

costs to firm point-to-point service and

the use of a revenue credit for non-firm

service will satisfy the requirements of

a conforming rate proposal enunciated

in our Transmission Pricing Policy

Statement.446

d. Opportunity Cost Pricing

(1) Recovery of Opportunity Costs

Comments

EEI and IOUs generally support the

notion that transmission customers

should pay some form of opportunity

cost when transmission is constrained

and request that the final rule clearly

define redispatch and opportunity costs.

These commenters generally agree that

the final rule should codify these terms

consistent with recent Commission

orders addressing opportunity costs.

Duke requests that the final rule

clarify that the transmission customer

should pay all the opportunity costs

associated with modified dispatch.

Centerior argues that redispatch costs

include consideration of parallel flows

and scheduled deliveries, which,

according to Centerior, cause redispatch

costs to be incurred.

Florida Power Corp and NYSEG state

that redispatch costs should be either

rolled in or charged on an incremental

basis, consistent with the Commission’s

‘‘or’’ pricing policy. Florida Power Corp

recommends that an opportunity cost

recovery provision be added to the

‘‘Rates and Charges’’ sections of the

tariffs. NYSEG recommends that the

tariffs implement the Commission’s

recent ruling in Florida Power & Light

Company, 66 FERC ¶ 61,227 (1994),

allowing lost opportunity costs to be

recalculated annually. NYSEG believes

that: (1) Redispatch costs should be

collected for any period in which the

transmission customer causes a

constraint, including the period of time

it takes to construct incremental

facilities necessary to alleviate the

constraint; (2) network customers

should be responsible for any

opportunity costs incurred as a result of

their non-firm use of the system if such

costs rise to a level above their load

ratio share of system costs; and (3)

point-to-point customers should be

responsible for any opportunity costs

incurred as a result of their non-firm use

of the transmission provider’s system up

to their reserved firm entitlement.

Ohio Edison believes that, given the

unique nature of network service, it is

inappropriate to require network service

customers to incur redispatch costs in

order to create additional capacity.

PECO requests that the final rule clearly

indicate (1) from whose perspective
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21601

447Northeast Utilities Service Company

(Northeast Utilities), 56 FERC ¶ 61,269 (1991), order

on reh’g, 58 FERC ¶ 61,070, reh’g denied, 59 FERC

¶ 61,042 (1992), order granting motion to vacate

and dismissing request for rehearing, 59 FERC ¶

61,089 (1992), aff’d in relevant part and remanded

in part, Northeast Utilities Service Company v.

FERC, 993 F.2d 937 (1st Cir. 1993); Pennsylvania

Electric Company (Penelec), 58 FERC ¶ 61,278 at

62,871–75, reh’g denied, 60 FERC ¶ 61,034 (1992),

affd, Pennsylvania Electric Company v. FERC, 11

F.3d 207 (D.C. Cir. 1993).

448Penelec, 58 FERC at 61,872; 60 FERC ¶ 61,034

at 61,126 (1992).

449FERC Stats. & Regs. ¶ 31,005 at 31,138.

‘‘least cost’’ redispatch is judged and (2)

that the ‘‘least cost’’ redispatch

obligation is subordinate to reliability.

Concerned that transmission

providers could manipulate the

calculation of redispatch charges to

increase profits, NRECA proposes that

transmission providers develop formal

redispatch protocols that would be

provided to all customers. NRECA

argues that all information necessary to

calculate redispatch costs should be

made available on the RIN. Customers

assessed redispatch charges should be

provided with all the necessary

information to evaluate such charges,

including full audit rights. NRECA,

Cajun, and PacifiCorp object to the

inclusion of ‘‘lost opportunity’’ costs in

redispatch charges. NRECA proposes

that only actual non-firm sales or

purchases should be included in the

calculation of opportunity costs.

United Illuminating and Seattle state

that all opportunity costs should be

assessed to short-term and non-firm

transmission service customers that

cause the transmission provider to

redispatch its generation to unload a

constrained transmission line.

According to United Illuminating, it is

not appropriate to roll opportunity costs

into the rates charged other

transmission users because existing

users do not have the choice to pay the

opportunity costs or to allow their

transaction to be curtailed.

UtiliCorp, on the other hand, states

that all ‘‘out of rate’’ uneconomic

dispatch costs should be rolled in and

recovered from all users of the

transmission system. UtiliCorp argues

that directly assessing these costs to a

particular customer would unfairly

penalize a customer who could not gain

access to a system until after the tariffs

take effect.

CCEM argues that only lost

opportunity costs associated with the

loss of firm purchases or sales should be

recoverable. CCEM also believes that the

transmission provider should calculate

the redispatch costs in advance and

transmission customers should be able

to opt out of redispatch if costs rise

above a certain level.

Commission Conclusion

We will retain redispatch provisions

in the Final Rule pro forma tariff, but

clarify that redispatch is required only

if it can be achieved while maintaining

reliable operation of the transmission

system in accordance with prudent

utility practice.

We find that the recovery of

redispatch cost requires that: (1) A

formal redispatch protocol must be

developed and made available to all

customers; and (2) all information

necessary to calculate redispatch costs

should be made available to the

customer for audit.

As discussed in the Section IV.H., the

Commission is according substantial

flexibility to public utilities to propose

appropriate pricing terms, including

opportunity cost pricing, in their

compliance tariff. However, as with any

compliance filing, the rates proposed

must meet the standards for conforming

proposals in the Transmission Pricing

Policy Statement.

In Northeast Utilities and Penelec, we

fully explained our rationale for

allowing utilities to charge opportunity

costs.447 We concluded that a public

utility is entitled to full compensation

for all ‘‘legitimate’’ and ‘‘verifiable’’

costs it incurs to provide firm

transmission service.448 We explained

that where a utility can demonstrate that

additional opportunity costs are

incurred as a direct result of providing

transmission service, our pricing

principles would permit recovery of

those costs. The Commission further

explained in the Transmission Pricing

Policy Statement that when

transmission capacity is constrained

and a utility does not expand capacity,

we have allowed the utility to charge

transmission customers the higher of

embedded costs or legitimate and

verifiable opportunity costs, but not the

sum of the two (i.e., ‘‘or’’ pricing is

permitted; ‘‘and’’ pricing is not). The

opportunity costs are capped by

incremental expansion costs.449

Transmission providers proposing to

recover opportunity costs must adhere

to the following requirements:

(1) A fully developed formula

describing the derivation of opportunity

costs must be attached as an appendix

to their proposed tariff.

(2) Proposals must address how they

will be consistent with comparability.

(3) All information necessary to

calculate and verify opportunity costs

must be made available to the

transmission customer.

(2) Fuel Adjustment Clause Treatment

for Redispatch Costs

If the transmission provider proposes

to separately collect redispatch costs on

a direct assignment basis from a specific

transmission customer, we will require

that the transmission provider credit

these revenues to the cost of fuel and

purchased power expense included in

its wholesale fuel adjustment clause.

e. Expansion Costs

Comments

ELCON argues that direct assignment

of 100% of the costs of expanding a

constrained transmission system to a

particular customer is unfair. NY Energy

Buyers believes that the costs of

expanding the transmission system

should be shared among all customers

seeking transmission service.

Alternatively, NY Energy Buyers states

that if direct assignment of system

expansions is adopted, such costs

should be payable both by new

wholesale customers and by new retail

load. According to NY Energy Buyers, it

would be preferable for the utility to

treat all requesters during a given period

as making one request for a large

increment of capacity, with all

requesters paying the same average

incremental cost. New native load also

should be considered to be a requester

of transmission capacity and allocated

an appropriate share of any expansion

costs.

CA Energy Co believes that

incremental pricing will discriminate

against all later competitors by charging

higher rates. It advocates rolled-in

pricing with the requirement that all

users requesting system expansion

commit to service for a term that will

cover their proportionate expansion cost

assignments.

FPL proposes that costs associated

with normal load growth and the repair

and/or replacement of older facilities be

rolled in with the other embedded

transmission costs and shared on a load

ratio basis. However, it believes that

transmission expansions associated

with the addition of a new resource

should be separately assigned.

On the other hand, Orange &

Rockland maintains that unless

expansion costs are directly assigned, an

unfair subsidization will occur.

According to PECO, transmission

customers should be assigned costs for

system upgrades under both the

network and point-to-point tariffs.

Consumers Power claims that the

network tariff is unclear about which

facilities are directly assignable, and

proposes that all costs that exceed the
21602 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

450E.g., EEI, Consumers Power.

embedded average cost qualify for direct

assignment.

SMUD requests that the final rule

clarify that if a transmission customer

invests in incremental facilities, it will

be entitled to ownership-like rights to

the capacity addition.

In order to avoid possible argument

over the necessity and cost of system

expansions for a particular transmission

request, NIEP requests that the final rule

require utilities to use a ‘‘least-cost’’

approach to transmission expansion that

includes comparable transmission

expansion practices for all wholesale

customers.

According to Duke, the concern that

the transmission provider’s retail

customers will retain an advantage by

having expansion costs placed on third

parties is misplaced. Duke argues that,

under ‘‘or’’ pricing, the issue of who is

responsible for expansion costs would

still arise. It contends that the

Commission will have to decide on a

case-by-case basis whether expansion

costs are incurred for the benefit of a

specific party or are part of overall

network costs. Duke generally supports

the current ‘‘or’’ pricing policy.

Citing the Commission’s

Transmission Pricing Policy Statement,

FL Com supports the flexibility of

charging both embedded cost and

incremental cost transmission rates, i.e.,

‘‘and’’ pricing. It argues that, because of

the dynamic and interconnected nature

of the transmission system, tariff

customers causing expansion costs

should be held responsible for both the

incremental cost of the addition and

some portion of the existing

transmission system needed to support

the addition. FL Com states that the

comparability standard is at odds with

the Commission’s non-conforming

transmission pricing policy, particularly

with respect to ‘‘and’’ pricing.

Commission Conclusion

Under the Final Rule pro forma tariff,

we will allow transmission providers to

propose any method of collecting

expansion costs that is consistent with

our transmission pricing policy. We

disagree with ELCON’s assertion that

directly assigning the costs for

expanding a constrained transmission

system is necessarily unfair. As we

stated in Northeast Utilities, if the cost

of expansion is directly attributable to a

customer’s request for transmission

service and the expansion would not be

undertaken ‘‘but for’’ that customer’s

request, then it is reasonable to assign

the cost of expansion to that customer.

If we were not to allow the direct

assignment of expansion costs to the

customer causing the expansion, then

other customers would subsidize the

new customer’s use of the transmission

system. We continue to believe that ‘‘or’’

pricing sends the proper price signal to

customers and promotes efficiency.

Under the tariff, any assignment of

future expansion costs must meet the

standards for conforming proposals in

the Transmission Pricing Policy

Statement. Recovering expansion cost

based upon ‘‘and’’ pricing will not be

allowed.

Any request to recover future

expansion costs will require a separate

section 205 filing. The Commission will

evaluate, on a case-by-case basis, who is

responsible for expansion costs in those

filings and whether direct assignment of

those costs is appropriate.

f. Credit for Customers’ Transmission

Facilities

Comments

Most commenters agree that the

Commission must clearly define when a

network customer’s transmission

facilities warrant a credit from the

transmission provider. Several

commenters state that customers must

bear the burden of demonstrating that

their facilities are used by and useful to

the transmission provider, provide

direct benefits, and support the

operation of the transmission system.450

EEI cautions against providing a credit

for facilities that may be integrated with,

but of no effective benefit to, the

operation of the bulk power system.

The costs associated with customerowned facilities that are used by the

transmission provider should, in

PECO’s opinion, be recovered from the

transmission provider under the

customer’s own transmission tariff.

FPL cautions that the position of

certain parties that transmission

facilities warrant a credit if they would

have been included in the transmission

provider’s rates could produce absurd

results. It claims that it could actually

end up paying a network customer with

substantial transmission investment for

the right to provide that customer

service. FPL contends that it will

receive absolutely no service from its

network customers because FPL would

not need, nor could it use, any of the

customers’ transmission facilities to

integrate FPL’s loads and resources. FPL

argues that crediting under the so called

‘‘rate base’’ test obligates the

transmission provider to purchase a

load-ratio share of the customer’s

transmission facilities. FPL states that,

under network service, the transmission

provider and the network customer will

not create a single system.

AEP recommends that a network

customer receive a credit if its

transmission facilities meet the

following criteria: (1) At points of

interconnection, there must be a

through-flow of power from the network

customer’s system to the transmission

provider’s system under normal

operating conditions; and (2) the

customer’s facilities must: (a) Increase

the transfer capability of an interface on

the transmission provider’s system; (b)

provide an alternative path for power

flows during transmission facility

outages, thus increasing the reliability

or stability of the combined system; or

(c) otherwise satisfy the transmission

provider’s planning criteria for the

installation of network facilities.

WP&L argues for a broader standard

and states that a transmission customer

should be entitled to a credit if the

transmission owner would have

installed similar facilities to provide

service for its own native load under

similar circumstances. Florida Power

Corp states that the credit for each

facility should be determined on a caseby-case basis.

PacifiCorp argues that a utility may

take advantage of the transmission

credit and shift major transmission

investment onto another transmitting

utility and its transmission customers

by simply becoming a network

customer. PacifiCorp claims that such a

situation may, for example, exist for

BPA as a transmitting utility. According

to PacifiCorp, preliminary studies

indicate at least one potential network

customer may be entitled to a

transmission credit which would exceed

that customer’s charges for BPA’s

network integration service.

APPA, Blue Ridge, and Cajun

maintain that a customer’s facilities

should be evaluated on a basis

comparable to the facilities included in

the rates of transmission providers in a

region. APPA argues that a claim that

the transmission customer’s facilities do

not benefit the transmission system

must be weighed against the fact that

some facilities included in the

transmission provider’s rate base may

not directly benefit the transmission

customer. Cajun advocates setting clear

standards for the identification of

customer-owned transmission facilities

eligible for crediting and clear

guidelines for determining the amount

of the credit.

SMUD not only supports the credit

under the network tariff, but also would

extend the credit to facilities used to

complete a transaction under the

transmission provider’s point-to-point

tariff.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21603

451 74 FERC ¶ 61,006 at 61,010 (1996), reh’g

pending.

452We caution all transmission providers that

while our discussion here addresses the

requirements necessary for a customer’s

transmission facilities to become eligible for a

credit, the principles of comparability compel us to

apply the same standard to the transmission

provider’s facilities for rate determination purposes. 453E.g., Duke, SCE&G, AEP, FPL.

454The same requirements will apply to discounts

from firm transmission service. Similarly, if a

transmission provider offers an affiliate a discount

for ancillary services, or attributes a discounted

ancillary service rate to its own transactions, it must

offer at the same time the same discounted rate to

all eligible customers. Discounted ancillary services

rates must be posted on the OASIS pursuant to new

Part 37 of the Commission’s regulations.

Commission Conclusion

Because of the diverse concerns raised

by the commenters, we are unable to

resolve on the basis of this record the

extent to which, or under what

circumstances, cost credits related to

customer-owned facilities would be

appropriate under an open-access

transmission tariff. We conclude that

such credits are more appropriately

addressed on a case-by-case basis,

where individual claims for credits may

be evaluated against a specific set of

facts.

We stress that while certain facilities

may warrant some form of cost credit,

the mere fact that transmission

customers may own transmission

facilities is not a guaranteed entitlement

to such a credit. The presumption of

many commenters that a customer’s

subscription to transmission service

somehow transforms the provider’s and

customer’s systems into an expanded

integrated whole to the mutual benefit

of both is not a valid one. As we ruled

in Florida Municipal Power Agency v.

Florida Power & Light Company

(FMPA), it must be demonstrated that a

transmission customer’s transmission

facilities are integrated with the

transmission system of the transmission

provider. Specifically, we stated that:

The integration of facilities into the plans

or operations of a transmitting utility is the

proper test for cost recognition in such cases.

The mere fact that a section 211 requestor has

previously constructed facilities is not

sufficient to establish a right to credits.451

The fact that a transmission customer’s

facilities may be interconnected with a

transmission provider’s system does not

prove that the two systems comprise an

integrated whole such that the

transmission provider is able to provide

transmission service to itself or other

transmission customers over those

facilities—a key requirement of

integration.452 We also note that

consistent with our ruling in FMPA, if

a customer wishes not to integrate

certain loads and resources, and thereby

exclude them from their load ratio share

of the allocated cost of the integrated

system, it may do so. Customers that

elect to do so, however, should

recognize that they may need to secure

alternative transmission arrangements

such as point-to-point transmission

service on an as-available basis in order

to utilize those resources for reserves.

Where disputes over credits for

customer-owned transmission facilities

arise, we encourage all parties to first

pursue alternative means to resolve

their differences rather than seek formal

resolution at the Commission. In any

event, the Commission anticipates that

disputes over the appropriate level of

transmission facility credits should not

preclude transmission customers from

initiating service under the tariff. Where

the parties are unable to reach

agreement on the appropriate credit for

customer-owned transmission facilities,

the parties may make an appropriate

filing with the Commission.

g. Ceiling Rate for Non-Firm Point-toPoint Service

Comments

Commenters generally support a

ceiling rate for non-firm transmission

service, capped at the firm rate.453

Others request clarification as to

whether the point-to-point tariff rates

are fixed or are ceiling rates. Central

Illinois Public Service’s major concern

is that, if the rates are fixed, the tariffs

may result in higher prices for capacity

and energy than those currently allowed

for bundled service.

NYSEG argues that unequal pricing is

a natural phenomenon of the open

marketplace and requests assurance that

offering transmission service at prices

below a cost-based ceiling rate will not

expose a transmission provider to

claims of undue discrimination.

AEC & SMEPA opposes using the firm

rate as the cap for non-firm transmission

service. It states that, given the

substantially lower quality of non-firm

service (with no obligation to plan for

such service), no cost-of-service

principle justifies charging rates for

non-firm service as high as the rate for

firm service.

EGA and NRECA state that any

discounts from the maximum firm rate

must be uniform, transparent, readily

understood, and posted on a RIN.

According to CCEM and NRECA, the

transmitting utility must have

nondiscriminatory discount practices

and must contemporaneously offer

discounts to transmission customers at

the same time and on the same basis as

discounts for internal sales operations

or affiliates.

Commission Conclusion

We believe that it is important to

continue to allow pricing flexibility. In

accordance with the Commission’s

current policies, the rate for non-firm

point-to-point transmission service may

reflect opportunity costs. Any

provisions for opportunity cost pricing

for non-firm service must meet the

requirements already discussed. If a

utility chooses to adopt opportunity cost

pricing, the non-firm rate is effectively

capped by the availability of firm

service and is not subject to a

separately-stated price cap. If a utility

chooses not to adopt opportunity cost

pricing, the non-firm rate is capped at

the firm rate. We also wish to ensure

that non-firm transmission service is

priced in a nondiscriminatory fashion.

Accordingly, if a transmission provider

offers a rate discount to its affiliate, or

if the transmission provider attributes a

discounted rate to its own transactions,

the same discounted rate must also be

offered at the same time to non-affiliates

on the same transmission path and on

all unconstrained transmission paths.

We will further require that any affiliate

discounts from the maximum firm rate

must be transparent, readily

understandable, and posted on the

transmission provider’s OASIS in

advance so that all eligible customers

have an equal opportunity to purchase

non-firm transmission at the discounted

rate.454 In addition, discounts offered to

non-affiliates must be on a basis that is

not unduly discriminatory and must be

reported on the OASIS within 24 hours

of when available transmission

capability (ATC) is adjusted in response

to the transaction. As discussed in the

RIN section, information, including the

price for all non-firm transaction

discounts, must be posted on the OASIS

to ensure comparability.

2. Priority for Obtaining Service

Comments

The term ‘‘priority’’ is used in the

comments in several senses. The intent

of the comment depends on which kind

of ‘‘priority’’ is intended. In general,

there are comments about the order in

which parties can obtain new service,

which we call ‘‘reservation priority,’’

and there are comments about the order

in which parties lose service they

already have, which we call

‘‘curtailment priority.’’ Commenters

may establish different reservation

priorities for various services, such as

network, off-system sales, firm, ability

to reserve a portion of new transmission
21604 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

455See also American Forest & Paper, AMP-Ohio.

456See discussion in Section IV.A.5.

capacity to be constructed, and so on.

Curtailment priorities also differ with

the type of service. However, many

commenters assert that certain parties

should or should not have ‘‘priority’’

without distinguishing the kind of

priority or type of service for which

priority is intended.

a. Reservation Priority for Existing Firm

Service Customers

Comments

Many IOUs, state commissions, and

cooperatives strongly believe that native

load should have priority to reserve

transmission capacity under the tariffs.

EEI suggests that existing and future

allocations of transmission capacity

must be based on proper transmission

pricing or, in its absence, priority of

service. According to EEI, retail and

existing wholesale requirements service

should have the highest priority for use

of transmission capacity, followed by

long-term point-to-point service. Dayton

P&L supports a continued preference for

native load growth because native load

customers have borne the majority of

the costs of the transmission system.

Detroit Edison, EEI, and Florida Power

Corp claim that, because native load and

network customers pay higher rates

during all hours, such customers should

have higher priority for service requests

than others requesting transmission

service. These commenters also claim

that the transmission provider should be

able to reserve firm capacity for native

load and network service customers.

Similarly, NARUC wants wholesale

and retail native load customers to be

held harmless from functional

unbundling of wholesale transmission

services. Because these customers have

borne the vast majority of the costs of

the utility’s transmission facilities,

NARUC argues that priority of service,

quality of service, and allocation of joint

and common costs to native load

customers should not be affected by the

transition to an open access

transmission regime.

PA Com does not share the

Commission’s concern that a

transmission provider may discriminate

against a third party transmission

customer vis-a-vis native load. It finds

nothing impermissible in this sort of

discrimination, arguing that the

interconnected system was financed by,

designed for, and built to serve native

load.

NRECA explains that most

transmission customers that seek

network service will already be

receiving similar service (albeit in a

bundled form) from their transmission

providers. It argues that these customers

should receive the same priority of

service as the transmission provider’s

native load customers for as long as they

continue to take network service,

whether under a current bundled

wholesale supply contract, a private

transmission contract, or a network

tariff.455

East Kentucky requests that the final

rule clarify that member distribution

cooperatives of G&Ts will have priority

over third parties in the use of the G&T’s

existing transmission facilities. TVA

comments that native load customers

and emergency service to neighboring

systems should have a higher service

priority than transmission services sold

to third parties (where an alternative

power supply is available to the third

party).

Commission Conclusion

We reiterate that we are not requiring

the transmission provider to unbundle

transmission service to its retail native

load nor are we requiring that bundled

retail service be taken under the terms

of the Final Rule pro forma tariff.

However, the amount of transmission

capacity available to wholesale and

unbundled retail customers under the

Final Rule pro forma tariff is clearly

affected by the amount of transmission

capacity that the transmission provider

reserves for the use of its native load

customers and the future load growth of

those customers. The transmission

provider may reserve in its calculation

of ATC transmission capacity necessary

to accommodate native load growth

reasonably forecasted in its planning

horizon. However, the transmission

provider is obligated to provide

transmission service to others under the

Final Rule pro forma tariff out of

capacity reserved for native load growth

up to the time the capacity is actually

needed for such future needs.

Furthermore, as we explained

previously, while existing wholesale

customers do not have any ownershiplike rights to the capacity they used

during the term of their contract, they

will have a right of first refusal to that

capacity after the expiration of their

contracts or when their contracts

become subject to renewal or rollover.456

b. Reservation Priority for Firm Point-toPoint and Network Service

Comments

A number of commenters argue that

all firm service should not be treated

equally. These commenters argue that

the price of the service should

determine the priority that the service

receives. A large number of IOUs and

potential network customers (existing

requirements customers) argue that in

light of the pricing implicit in the

NOPR, (i.e., 12 CP for network versus

annual system peak for point-to-point)

network service should have priority

over point-to-point service (because, all

other things being equal, the price for

network service will be higher).

BG&E believes that a customer

receiving service priority equal to native

load and network customers should pay

comparable rates. Thus, BG&E argues

that either flexible firm point-to point

service should be priced the same as

network service, or point-to-point

service should have a lesser priority

than native load and network service

customers if point-to-point service is

priced lower than network service.

DE Muni believes that native load and

network customers must have priority

access to interfaces (particularly where

they are constrained) after system

reliability concerns have been satisfied.

The same argument is advanced by

commenters concerning long-term

service versus short-term service. Public

Generating Pool argues that long-term

service should always have priority over

short-term service because long-term

customers contribute more towards

fixed-cost recovery than do short-term

customers.

Cajun objects to having its service and

service to its customers, which it

characterizes as network service, receive

the same priority as firm point-to-point

service customers who take service for

periods as short as one hour. Cajun

points out that it, as well as other

network and native load customers,

have been paying and will be paying for

the transmission facilities in place to

serve their needs for many years.

According to Cajun, the transient firm

point-to-point customer should not have

equal standing. Cajun suggests,

however, that a long-term firm point-topoint customer taking service for ten

years or more should have service

priority equal to native load and

network service customers.

SC Public Service Authority argues

that the availability of short-term firm

service with a priority equal to longterm service would provide a means for

short-term customers to obtain the

advantages of long-term firm service at

a much lower total cost. As a result, it

argues that a few point-to-point

customers would opt for long-term firm

service, and the burden of the residual

costs of the transmission system would

fall on network customers.

EEI claims that priority for point-topoint service should be on a continuum

of firmness, with reservation (as well as
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21605

457The service itself, as opposed to reservations,

is subject to the curtailment provisions discussed

below.

curtailment) priority based upon

duration of service and specific

negotiated terms. EEI proposes that the

point-to-point tariff be modified to

provide a first-tier category of flexible

point-to-point transmission service that

is comparable in priority, price, length,

and terms of service to network service.

EEI believes that this modification will

resolve the problems that are associated

with establishing priorities between

network service and point-to-point

service if the Commission retains

different CP cost allocation methods for

each service.

On the other hand, CCEM, a group of

power marketers, supports the concept

that all firm service should be treated

equally, regardless of the term or the

nature of service.

Commission Conclusion

An essential element of nondiscriminatory transmission access is

the right of transmission customers to

reserve and purchase transmission

service that is of the same quality as that

used by the transmission provider in

serving its wholesale requirements

customers and retail load. Thus, we

reject the proposal of some commenters

that transmission providers need not

provide firm point-to-point service that

is of the same ‘‘firmness’’ as the

transmission provider’s service to native

load. However, the fact that both

network service and point-to-point

service are provided on an equally firm

basis does not mean that both types of

service must be priced or reserved in the

same manner.

The comments about reservation

priorities for firm services boil down to

two concerns. First, due to the

differences in pricing firm point-topoint service and network service

implicit in the NOPR (i.e., twelvemonthly CP pricing for network versus

annual system peak for point-to-point),

some commenters believe that network

service should have priority over pointto-point service. Second, some

commenters maintain that according

firm, short-term point-to-point service a

priority equal to long-term service

provides a means for short-term

customers to avoid making a fair

contribution to the long-term costs of

the system.

With respect to the first concern, we

have eliminated the differences in

pricing by permitting utilities to adopt

point-to-point reservations as the

customer load. As discussed above, for

purposes of the Final Rule pro forma

tariff, utilities are free to propose a

single cost allocation method for the

two services.

The second area of concern arises

because of the first-come first-served

reservation priority in the NOPR pointto-point tariff. The Commission

recognizes that the tariffs, as proposed

in the NOPR, provide the opportunity

for a customer to reserve certain

valuable rights (e.g., the right to shortterm firm service during peak periods)

while avoiding in part the long-term

costs of the system (perhaps by relying

on non-firm service during lengthy offpeak periods when there is a

substantially reduced chance of

interruption). However, the Commission

has a countervailing concern that the

transmission provider should not be

able to withhold valuable transmission

capacity from potential customers if that

capacity is not being used by those who

are paying for the long-term costs of the

system.

Accordingly, the Final Rule pro forma

tariff provides a mechanism to address

this concern while safeguarding the

rights of potential customers to obtain

access to unused capacity. The tariff

provides that reservations for short-term

firm point-to-point service (less than

one year) will be conditional until one

day before the commencement of daily

service, one week before the

commencement of weekly service, and

one month before the commencement of

monthly service. These conditional

reservations may be displaced by

competing requests for longer-term firm

point-to-point service. For example, a

reservation for daily firm point-to-point

service could be displaced by a request

for weekly firm point-to-point service

during an overlapping period. Before

the applicable reservation deadline, a

holder of a conditional firm point-topoint reservation would have the right

of first refusal to match any longer-term

firm point-to-point reservation before

being displaced. After the deadline, the

reservation becomes unconditional, and

the service would be entitled to the

same priorities as any long-term pointto-point or network firm service.457

The Final Rule pro forma tariff does

not propose point-to-point or network

service with various degrees of firmness

beyond the simple categories of firm

and non-firm. When a customer requests

firm transmission service, reservation

priorities are established based first on

availability, and in the event the system

is constrained, based on duration of the

underlying firm service request;

customers may choose the ‘‘firmness’’ of

service they want by electing to take

non-firm service, or by reserving and

paying for firm service. We have not

included any degrees of firmness in the

Final Rule pro forma tariff because

having intermediate categories of

firmness under point-to-point or

network service would, we believe,

unnecessarily complicate the priority

system. However, utilities are free to

propose and fully support different

reservation priority provisions for firm

service in subsequent rate filings as long

as those provisions are not unduly

discriminatory, fully comply with the

principles of comparability, and are

priced appropriately.

c. Reservation Priorities for Non-Firm

Service

Comments

IOUs, state commissions, and

potential network customers tend to

support the service reservation priorities

for non-firm service set forth in the

NOPR pro forma tariffs (i.e.,

transmission service by network

customers for economy purchases to

serve network load has a higher priority

than non-firm point-to-point service,

which has a higher priority than a firm

point-to-point customer using

transmission service at secondary points

of receipt and delivery). However,

because network customers pay a higher

rate than point-to-point customers, these

commenters argue that network

customers should be permitted to use

their off-peak load ratio share of the

transmission system to make off-system

sales. Many commenters argue that

point-to-point customers can use their

secondary service for both purchases

and sales; thus, they believe it is

discriminatory to limit network

customers to purchases at secondary

points.

Commenters that are opposed to the

service reservation priority scheme in

the NOPR pro forma tariffs argue that

transmission providers will

discriminate against third party users in

favor of their native load economy

purchases. These commenters argue that

all non-firm service should have equal

priority.

Other commenters, such as CINergy,

would base priority on the duration of

service. CINergy claims that this method

would eliminate what it claims is an

advantage (over network) given in the

NOPR to point-to-point service in

making short-term purchases. TVA

notes that it establishes priority for nonfirm service based on duration of service

requested, with customers in each

service category receiving priorities

based on the rate they wish to pay.

Some commenters believe that the

transmission price should affect the
21606 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

458E.g., Duke, Orange & Rockland.

459E.g., TANC, Turlock, SMUD.

460E.g., PSNM and Nebraska Public Power

District.

461Proposed Pro Forma Network tariff section

9.7—System Reliability.

462The Final Rule pro forma tariff contains

language allowing the transmission provider the

discretion to interrupt firm transmission service in

an emergency or other unforeseen condition in a

manner suggested by these commenters. Section

11.6, Curtailment of Firm Service, of the Final Rule

pro forma tariff provides:

However, the Transmission Provider reserves the

right to interrupt, in whole or in part, firm

Transmission Service provided under this Tariff

when, in the Transmission Provider’s sole

discretion, an emergency or other unforeseen

condition impairs or degrades the reliability of its

transmission system.

The reference to curtailments being allocated on

a proportional (pro rata) basis addresses situations

where multiple transactions could be curtailed to

relieve a constraint.

priority of customers to obtain non-firm

transmission capacity.458 However,

other commenters argue that this seems

to be precluded by the NOPR pro forma

tariffs’ service priority provisions.

Although PSE&G believes that the

NOPR pro forma tariffs suggest a firstcome, first-served allocation method for

capacity in excess of that needed for

firm transmission service, it proposes a

fixed period of time for all potential

users to submit bids for service (e.g., one

week prior for monthly service),

allowing the bid price to determine

priority (i.e., the higher bid prices

receive service priority over lower bid

prices). According to PSE&G, customers

could bid an ‘‘up to’’ rate subject to a

price floor, with all revenues flowed

back to firm service customers. TVA

also advocates departing from the firstcome, first-served approach for

allocating some uses of the transmission

system, claiming that price is an

effective means to establish priority for

non-firm and short-term firm services.

Utility Wind Interest Group requests

that non-firm service used for

transmitting renewable resources be

given a higher priority than non-firm

service used for transmitting

conventional resources because

renewable resources cannot store their

fuel supply.

Commission Conclusion

We continue to believe that network

economy purchases should have a

reservation priority over non-firm pointto-point and secondary point-to-point

uses of the transmission system.

Network transmission customers are

obliged to pay all of the costs of the

transmission system without regard to

the resources from which energy is

scheduled. Therefore, it is appropriate

that the transmission associated with a

network customer’s economy purchases

(i.e., transmission that is used to

substitute one resource for another on

an as-available basis) enjoys a higher

priority than non-firm point-to-point

transmission service.

Regarding the reservation priority for

non-firm service under point-to-point

service, we will adopt a reservation

priority based upon duration of nonfirm service, with price acting as a tiebreaker for competing service requests

of an equal duration. If there is

insufficient transmission capacity to

accommodate all non-firm transmission

requests, the reservation of longer

duration should displace the shorter.

For example, a reservation for a month

of non-firm service will displace a

reservation for a week of non-firm

service. Also, a reservation for a week

will displace a reservation for a day,

which will displace a reservation for an

hour of non-firm service. If a customer

requests non-firm and later another

customer requests longer-term non-firm

service before either term of service

begins, the first customer to request

service has the right of first refusal to

change its request to the longer term of

service. A firm point-to-point

customer’s use of transmission service

at secondary points of receipt and

delivery will continue to have the

lowest reservation priority.

3. Curtailment Provisions

a. Pro-Rata Curtailment Provisions

Comments

A large number of IOUs that are

control area operators argue for

discretion to curtail the transaction that

most effectively relieves the constraint,

in lieu of mandatory pro-rata

curtailments, which they argue are

inappropriate and not cost effective.

Other commenters that do not support

pro-rata curtailment argue that

preference should be given to native

load or existing customers because these

customers have paid the majority of the

costs of the transmission system. A large

number of customers note that their

existing contracts contain ‘‘enhanced’’

curtailment priorities (i.e., service to

others will be curtailed before service to

customers with such curtailment

priority) due to the large capital outlays

made by them in connection with their

service.459

Public Generating Pool believes that

the proposed curtailment provisions

may not be flexible enough for

transactions in the Northwest. It argues

that hydro spill should be avoided, and

suggests that transactions from federal

and/or non-federal hydroelectric

generation facilities should not be

curtailed pro rata with other

transactions that do not rely on such

facilities. Public Generating Pool urges

that regional agreements (e.g., regional

transmission group agreements) that

would achieve this goal should be given

deference.

Other commenters support pro-rata

curtailments for firm service.460 PSNM

states that this has been its operating

practice in the past, and PSNM expects

to continue such an approach in the

future.

Power marketer commenters generally

support the pro-rata curtailment adding

that a standardized curtailment priority

applied nationally would provide

greater open access and eliminate

discriminatory curtailments.

Commenting on a related subject, EEI

maintains that the network tariff

provision for termination of service in

the event a customer fails to curtail

load 461 may not be realistic for service

to a Transmission Dependent Utility.

EEI suggests that the Commission

supplement this provision with a

substantial penalty provision, coupled

with an indemnification requirement.

Commission Conclusion

It was not our intent in the NOPR to

require all transactions to be curtailed

on a pro-rata basis regardless of whether

the transaction relieves a constraint. We

intended to permit curtailments of

transactions that substantially relieve a

constraint.462 We intended and continue

to believe that curtailment on a pro-rata

basis is appropriate for curtailing the

transactions that substantially relieve

the constraint. In order to allay the

concerns of the commenters addressing

this issue, we are clarifying the

curtailment provision of the tariff to

explicitly allow the transmission

provider discretion to curtail the

services, whether firm or non-firm, that

substantially relieve the constraint. Of

course, any curtailment must be made

on a non-discriminatory basis, including

curtailment of the transmission

provider’s own use of the transmission

system. Customers that believe the

curtailment policy is administered

unfairly may file a section 206

complaint at the Commission.

Concerning the request of certain

Pacific Northwest commenters, we

would consider granting deference to an

alternative curtailment method to avoid

hydro spill if such a regional practice is

generally accepted and adhered to

across the region, as discussed further in

Section IV.K.

Finally, we agree with EEI’s

observation that terminating network
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21607

463E.g., Florida Power & Light Company,

Southern California Edison Company.

464 69 FERC ¶ 61,145 at 62,300 (1994) (proposed

order), 74 FERC ¶61,220 (1996) (final order).

465E.g., EEI, Utility Working Group, SoCal Edison.

466E.g., Arkansas Cities, NRECA.

service under the tariff to a transmission

dependent utility that fails to curtail

load as required may not be appropriate.

As a result, we clarify that under

network and point-to-point service, the

transmission provider may propose a

rate treatment (penalty provision) to

apply in the event a customer fails to

curtail load as required under the Final

Rule pro forma tariff. Such proposals

will be evaluated on a case-by-case basis

on compliance.

b. Curtailment Provisions for Non-Firm

Service

Comments

A number of commenters seek

clarification of the curtailment

provision for non-firm service under the

two tariffs. They note that economy

purchases by the network customer are

accorded a higher curtailment priority

than non-firm service under the pointto-point tariff. However, under the

point-to-point tariff there is no

acknowledgement of this higher priority

for network service. Curtailments for

non-firm transmission service under the

point-to-point tariff are simply based

upon duration of service, without

reference to a higher priority for

network economy purchases.

A number of commenters, including

Industrial Energy Applications, suggest

that a price-based curtailment queue for

non-firm transmission will facilitate

economy energy deals in highly

competitive wholesale power supply

markets and allow the parties to directly

address delivery risk through the

pricing mechanism.

Blue Ridge argues that the final rule

should provide equal curtailment

priority for all types of non-firm

transmission service. Utilities For

Improved Transition argues that

network customers should be able to

transmit non-firm power imports under

the network tariff with the same

curtailment priority that is assigned to

all other firm network uses of the

transmission system.

A number of commenters note that

the tariffs allow non-firm service to be

interrupted only for emergency or

reliability reasons or to provide firm

service. These commenters contend

that, under this requirement,

curtailment of non-firm service is

unlikely.463 As a result, they believe that

non-firm service is elevated to firm

service. To remedy this situation, these

commenters argue that transmission

providers should have the ability to

curtail non-firm service for any

economic reason.

Commission Conclusion

We have clarified in the Final Rule

pro forma tariff that a network

customer’s economy purchases have a

higher curtailment priority than nonfirm point-to-point transmission service.

A higher curtailment priority should

be provided to network economy energy

purchases for the reasons stated in AES

Power, Inc..464 In that case, we

recognized that the network

transmission customer has already

‘‘paid’’ for the transmission of its

economy purchases (i.e., transmission

that is used to substitute one resource

for another on an as available basis)

through its payment of a load ratio share

of the system.

Many commenters oppose the pointto-point service provision allowing nonfirm service to be interrupted only for

emergency or reliability reasons or to

provide firm service. Upon further

consideration, we agree that this

provision is too narrow. Accordingly,

the Final Rule pro forma tariff is revised

to allow the transmission provider to

curtail non-firm service for reliability

reasons or economic reasons (i.e., in

order to accommodate (1) a request for

firm transmission service, (2) a request

for non-firm service of greater duration,

(3) a request for non-firm transmission

service of equal duration with a higher

price, or (4) transmission service for

economy purchases by network

customers from non-designated

resources.). However, all curtailments

must continue to be made on a nondiscriminatory basis including

curtailments of the transmission

provider’s own non-firm uses of the

transmission system under the tariff. A

firm point-to-point customer’s use of

transmission service at secondary points

of receipt and delivery will continue to

have the lowest curtailment priority.

4. Specific Tariff Provisions

a. Network and Point-to-Point

Customers’ Uses of the System

Comments

Generally, transmission providers

argue that the tariffs give too much

flexibility to customers, while

transmission customers argue that even

more flexibility is required. The

arguments are generally tied to pricing

rather than technical problems with

providing any level of service.

A common transmission provider

argument is that the proposed firm

point-to-point tariff provides a premium

service comparable to network service,

but at a lower rate. It has been suggested

that either the flexibility to use non-firm

service at secondary points of receipt

and/or delivery at no additional charge

under the point-to-point tariff be

eliminated or that point-to-point

customers should pay a premium price

for such flexibility.465 Transmission

providers generally argue that flexible

point-to-point service puts the

transmission owner and the network

customer at a competitive disadvantage.

They assert that the point-to-point

customer is able to use non-firm

transmission to reach secondary receipt

and delivery points for both sales and

purchases, but the network customer

may use only non-firm transmission to

reach secondary points for purchases.

Thus, they argue, the flexible point-topoint users can sell non-firm power

with a small or even no transmission

component (because the underlying

transmission is effectively free). Electric

Consumers Alliance and Cajun believe

that the owner and network customer

competing for that sale should not be

charged for the identical transaction.

Absent a change to the point-to-point

tariff, a number of transmission

providers and state commissions

(including Midwest Commissions) argue

that to provide balance to the tariffs, the

network tariff should permit the

network customers to have non-firm

transmission to secondary receipt and

delivery points at no additional charge

for both purchases and sales within its

load-ratio transmission entitlement.

Utilities For Improved Transition refers

to this proposed network tariff

modification as ‘‘headroom.’’

CCEM opposes the headroom concept,

arguing that ‘‘free’’ use of capacity will

give transmission providers an unfair

competitive advantage. CCEM also cites

Order No. 636 in support of its position.

Conversely, a number of customer

groups believe the point-to-point tariff

should be made more flexible by

broadly defining the concept of points

of receipt and delivery. They argue that

all points of connection between the

transmitting utility and the purchasing

utility should be treated as a single

point of delivery (POD) or point of

receipt (POR).466 In this manner, a

customer would not have to pay for

every point of receipt or point of

delivery, but could select a contract

demand level of service. The customer

could then use the service at multiple
21608 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

467E.g., Public Power Council, Washington Water

Power, NWRTA.

468See Florida Municipal Power Agency v.

Florida Power & Light Company, 74 FERC ¶ 61,006

at 61,013 and n.70 (1996).

469See also VEPCO, CSW, NYSEG, WP&L.

points without incurring separate

reservation charges for each point.

A number of commenters contend

that the Commission should not force

specific tariffs on public utilities in the

Pacific Northwest due to their unique

status.467 In particular, NWRTA

recommends that the final rule

recognize that the Pacific Northwest’s

integrated transmission system,

including large components owned by

non-public utilities, was constructed to

support a unique region-wide

hydroelectric-dependent generating

system. NWRTA recommends that the

final rule be sufficiently flexible to

accommodate these unique

characteristics without prejudicing the

interests of users or providers of

transmission services.

Similarly, Public Generating Pool

states that the NOPR pro forma network

tariff departs from the status quo

arrangements in the Northwest and is

generally unworkable because

generation is usually remote from the

control area serving the network load

and because BPA, which does not have

a typical service territory, dominates the

regional transmission market. Public

Generating Pool suggests that the

Commission require, and the region

develop, a ‘‘generation integration’’

transmission tariff that would offer

network-type service to a source or

sources of generation unbundled from

the ‘‘network services’’ designed to

integrate load. Similar contract demand

network tariffs have already been

proposed by some IOUs.

Commission Conclusion

We will not allow network customers

to make off-system sales within the

load-ratio transmission entitlement at

no additional charge. Commenters have

raised no new arguments to persuade us

to do so. The primary purpose of

network service is to integrate resources

to serve loads. Use of transmission by

network customers for non-firm

economy purchases, which are used to

displace firm network resources, must

be accorded a higher priority than nonfirm point-to-point service and

secondary point-to-point service under

the tariff. Off-system sales transactions,

which are sales other than those to serve

a network customer’s native load, must

be made using point-to-point service.

They can be made on either a firm or

non-firm basis.

A large number of transmission

providers support the ‘‘headroom’’

concept, arguing that without it the

flexible point-to-point service puts them

at a competitive disadvantage. This

would be true if a utility serving load

were required to use network service

exclusively. However, we do not require

any utility to take network service to

integrate resources and loads. If any

transmission user (including the public

utility) prefers to take flexible point-topoint service,468 they are free to do so.

Any point-to-point customer may take

advantage of the secondary, non-firm

flexibility provided under point-to-point

service equally, on an as-available basis.

b. Minimum and Maximum Service

Periods

Comments

Commenters raise issues regarding the

minimum term of one hour for firm

point-to-point service. Their concerns

center on price and priority.

Transmission providers point out that

their native load customers pay the

fixed cost of the transmission system

every hour of the year. They argue that

comparability is not achieved by

permitting others to have service for one

hour with equal priority to native load

and other long-term customers. Others

worry that the one-hour minimum term

will: (1) Promote the selective use of the

transmission system; (2) impair the

ability of a utility to plan its system; and

(3) adversely impact longer term

transactions.

Tallahassee and KY Com are

concerned that one-hour firm service

may encourage speculative advance

requests for service during the system

peak day (Cajun refers to this as cream

skimming). These commenters express

concern that such requests could

displace other valid transactions or

constrain a corridor or interface to the

detriment of network service or native

load customers. Tallahassee proposes a

one-day minimum term for firm

service.469

East Kentucky is concerned that users

of the transmission system could, under

the Commission’s proposed open-access

rule, purchase short-term firm service

during peak months in lieu of annual

firm service to reduce expenses

associated with the purchase of firm

transmission service. By buying shortterm firm service only during the peak

months, an entity can significantly

reduce its transmission expenses by

purchasing non-firm service during offpeak months when the available

transmission capacity far exceeds the

demand on the transmission system. For

this reason, some commenters request

that short-term firm service be priced to

generate revenues over the peak months

equal to the charge for annual firm

service.

Duke argues that, because all

curtailments are equal, the addition of

each one hour firm transaction will

lower the reliability profile of native

load customers and other customers

with long-term commitments. It suggests

that different classes of services be

established that offer transmission

customers the flexibility to obtain an

intermediate level of transmission

service (between native load firm and

non-firm) for transactions of shorter

duration.

On the other hand, some TDUs and

power marketers support the one-hour

minimum term. TAPS argues that

transmission providers should not be

permitted to restrict the availability of

hourly, daily or weekly transmission

service at reasonable prices, as some

transmission providers have proposed

in open access cases. Brazos supports a

minimum duration of service equal to

the minimum scheduling period of the

transmission owner. Turning to the

maximum term of service, Chugach

objects to the imprecise requirement

that transmission service be offered for

a term equal to the life of a particular

generation resource. Chugach, joined by

VEPCO, suggests that the Commission

require transmitting utilities to offer

five-year terms (with longer contract

terms by negotiated agreement).

Although BPA supports eliminating

arbitrary term limitations and

facilitating long-term resource

commitments, it is concerned that the

Commission’s failure to specify a

maximum term for firm transmission

service (particularly where no specific

resource is being wheeled) requires

transmitting utilities to effectively sell

off their transmission capacity to third

parties. In BPA’s view, such a

requirement goes well beyond the intent

of the Energy Policy Act.

PSE&G argues that the term limit for

firm transmission service should be

consistent with the transmission

provider’s planning horizon (e.g., for

PSE&G, 10 years), which will ensure

comparability of firm third party

customers with native load. According

to ConEd, failure to specify a maximum

term for service creates uncertainty for

planning purposes. PECO believes that

utilities should have the right to limit

the term of service to either: (1) The

expected useful life of facilities used in

providing service; or (2) the term of

permits and land rights needed for those

facilities.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21609

470E.g., El Paso, Southern, NSP.

Commission Conclusion

We will adopt a one-day minimum

term for firm point-to-point service. The

one-day minimum term for firm pointto-point service, along with

modifications to the procedures for

requesting firm point-to-point service,

will moot a number of reliability

concerns and allegations about possible

‘‘cream-skimming.’’ As discussed supra,

firm service requests with longer

durations of service will have bumping

rights over shorter term firm service

requests. Also, the one-day minimum

will not disadvantage anyone because

the transmission provider will be

subject to the same one-day term for its

firm point-to-point uses of the

transmission system. Because of the

longer-term nature of network service, it

will be subject to a one-year minimum

term.

We will not specify a maximum term

for either point-to-point or network

transmission service. However, we

recognize the concerns raised by

commenters that a commitment of

uncertain duration makes planning

difficult. Therefore, we will modify the

tariff to require that an application for

transmission service specify the length

of service being requested. This will

provide the transmission provider with

the certainty it needs for planning and

the transmission customer with the

flexibility to request the service it needs.

c. Amount of Designated Network

Resources

Comments

The NOPR pro forma network tariff

specifies that a customer may designate

only those resources that the customer

owns or has committed to purchase

pursuant to an executed contract.

Transmission providers argue that there

is a need for some limitation on the

resources that network customers can

designate to serve their loads.

Otherwise, they assert, a utility would

be required to incur costs (planning,

constructing, and operating its

transmission system) that are out of

proportion to the customer’s load and

its share of the utility’s cost of service.

However, EEI, VEPCO, and Utilities For

Improved Transition believe that the

Commission’s proposal to use a

purchase obligation standard is too

narrow, inflexible, and susceptible to

manipulation. These IOU commenters

argue that it could include very shortterm obligations and contingent

obligations to purchase. EEI suggests

that the Commission should establish a

minimum term so that a customer could

not designate resources for which it has

only a one-month contract. The

principal problem VEPCO sees is that

purchase obligations may not be clear.

According to VEPCO, a transmission

customer may claim an obligation when

it has no substantial payment obligation

and thus no economic deterrent to

designating that purchase obligation as

a potential resource to serve its loads. It

alleges that the result is that the

transmitting utility can be forced to tie

up transmission capacity for service

from a resource that may have little

probability of being used; consequently,

less capacity will be available for other

uses. VEPCO further argues that, since

upgrade costs are typically rolled in, the

customer may not have a strong

incentive to minimize transmission

construction. EEI argues for systemspecific limits based on capacity needs

to serve the network loads reliably.

Alternatively, if the ‘‘own’’ or

‘‘purchase’’ provision is to be used, EEI

contends that the customer should be

required to have a significant and

ongoing obligation to purchase power

(e.g., minimum one-year contracts that

impose obligations on a first-call basis).

These IOUs also recommend that the

Commission not decide on a single way

to limit network resources. They note

that proposals based on percentage

limits (e.g., 125%) subject to exceptions

for reliability concerns may be a

reasonable approach. According to these

IOUs, the Commission should permit

flexibility to develop not unduly

discriminatory provisions until

experience suggests which are the best

ways to satisfy the objective. To prevent

over-designating network resources,

Missouri-Kansas Industrials suggest

placing a limit of 200% of the

subscriber’s load.

Arkansas Cities supports limiting the

definition of network resources to those

that the customer owns or contracts for.

It argues that this reasonably

accommodates the planning process.

Arkansas Cities argues that any type of

percentage adder would unreasonably

restrict the process.

ELCON states that virtually any issue

regarding the nature of network service

can be resolved by reference to the price

of such service. According to ELCON, if

a transmission customer seeks to

incorporate unlimited (i.e., unspecified)

generation sources into its network load,

the customer should pay a higher rate

than a network customer that can

identify a need for service to/from

specified generating units.

A related issue is how interface

capacity should be allocated between

network customers and the transmission

provider. IOUs generally argue that

interface capacity should be allocated

based upon the load ratio of the

customers. Tariff customers generally

argue that there should be no restriction

on the amount of interface capacity that

they may designate.

Commission Conclusion

We do not believe that a superior

alternative has been suggested to our

purchase obligation for limiting network

resources. Accordingly, we will not

change the limitation on the amount of

resources a network customer may

designate. A transmission provider

taking network service to serve network

load under the tariff also is required to

designate its resources and is subject to

the same limitations required of any

other network customer.

Limiting the amount of resources to

those that the customer owns or

commits to purchase will protect a

utility from having to incur costs that

are out of proportion to the customer’s

load. The transmission provider’s

concern that the purchase limitation

will result in excessive network

resources is unfounded. A transmission

customer, like a transmission provider,

has an incentive not to oversubscribe its

capacity requirements because the cost

of excessive reserve margins will be

prohibitive. Requiring a strict

percentage limitation could distort the

planning process by limiting the size of

resource additions a transmission

customer may undertake. Allowing

discretionary exceptions to the

percentage limit will inevitably lead to

disputes and claims of discrimination.

With respect to the allocation of

interface capacity under network

service, we clarify that a customer is not

limited to a load ratio percentage of

available transmission capacity at every

interface. A customer may designate a

single interface or any combination of

interface capacity to serve its entire

load, provided that the designation does

not exceed its total load.

d. Eligibility Requirements

Under the NOPR pro forma tariffs, the

transmission provider and anyone who

can file a section 211 request is eligible

to request service.

Comments

In general, most commenters agree

with the eligibility requirements.

However, several IOUs argue that the

tariffs should be modified specifically to

preclude the use of the tariffs for retail

wheeling.470

NIEP believes the eligibility provision

should include all entities that not only

generate power themselves, but also

purchase power generated by others for
21610 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

471See discussion in Section IV.C.1.

472E.g., IL Com, KY Com, VT DPS, GA Com.

473E.g., CCEM, CA Energy Co.

474E.g., Sierra, MidAmerican, Tucson Power.

475E.g., Puget, Sierra, NSP.

476E.g., NRECA, Omaha Public Power District,

Dairyland, AEC & SMEPA, PA Com, IL Com, TDU

Systems.

477E.g., NRECA, SC Public Service Authority,

Seminole EC, TDU Systems.

resale, including municipalities, federal

entities with rights to purchase, and

other entities with load but no

generation resources.

Power Marketing Association and

others argue that the network tariff

should be modified to specifically allow

service to marketers.

PacifiCorp argues that independent

owners of generation resources should

not be allowed to acquire network

integration service directly. It suggests

that, if the eligible utility does not have

a load in the control area, the service

sought is to accommodate off-system

sales, which is a point-to-point service.

Commission Conclusion

As we previously explained, a nondiscriminatory open access transmission

tariff must be made available, at a

minimum, to any entity that can request

transmission services under section 211

and to foreign entities.471 Eligibility to

take service is further discussed in

Section IV.C.1.

e. Two-Year Notice of Termination

Provision

Comments

Ohio Edison, Utilities For Improved

Transition, LA DWP, and VEPCO

believe that point-to-point transmission

customers should not be allowed to

terminate transmission service prior to

the end of their contract term, especially

in light of their reassignment rights. For

network service, VEPCO, Florida Power

Corp, Utilities For Improved Transition,

and Duke believe that the notice of

termination period should be at least

five years, to coincide with the utility’s

construction horizon. In particular,

VEPCO wants transmission customers

terminating service prior to the end of

the contract term to pay for network

upgrades constructed for their benefit

that would be stranded due to early

termination of service.

CCEM supports a six-month notice of

termination as appropriate for a term of

service of one year or greater; any longer

notice period would unduly limit a

transmission customer’s purchasing

options.

NYSEG and EEI want the flexibility to

negotiate a reasonable, mutually

agreeable notice of termination period to

recognize such things as the term of the

contract and the amount of service at

issue.

LEPA, VT DPS, and NorAm believe

that written notice of termination

should not be required for transactions

of two years or less.

Commission Conclusion

We will delete the notice of

termination provision from the tariff.

We believe that commenters have raised

a number of valid concerns about

including the notice of termination

provision. In particular, the notice of

termination will have no effect on shortterm service of less than two years. In

addition, the two-year notice provision

does not coincide with either a

transmission provider’s planning or

construction horizon. Because we are

eliminating the notice of termination

provision from the tariff, transmission

service will have to be reserved and

paid for over the length of the contract

term. Of course, by eliminating this

tariff provision, we are not precluding

parties from negotiating mutually

agreeable terms for early termination on

a case-specific basis. However, we note

that point-to-point customers are able,

under the reassignment provision, to

resell unused transmission capacity.

f. Reciprocity Provision

In the NOPR, the Commission

explained that it was requiring a

reciprocity provision in the nondiscriminatory open access transmission

tariffs so that public utilities offering

transmission access to others would be

able to receive service from transmitting

utilities that are not public utilities (e.g.,

municipal power authorities and federal

power marketing administrations that

receive service under a public utility’s

tariff).

Comments

Reciprocity Requirement

The vast majority of the jurisdictional

IOUs commenting on this issue favor a

reciprocity requirement. In contrast, the

non-jurisdictional transmission

customers (primarily publicly-owned

entities and cooperatives) generally

oppose such a requirement. The few

state commissions commenting on this

issue generally support the stated goal

of the reciprocity requirement, but

question our legal authority to require

it.472 The few IPP and power marketer

commenters that address this issue do

not object to reciprocity if it does not

apply to non-transmission owners.473

Several commenters believe that all

transmission-owning utilities, whether

public or investor-owned, must be

required to provide open access service

for a truly competitive wholesale power

market to be realized.474 Sierra states

that specific legislation by Congress

and/or state lawmakers may be

necessary to ensure that currently nonpublic utilities comply with the

Commission’s open access

requirements.

A number of commenters maintain

that the Commission should enforce

reciprocity by allowing public utilities

to deny transmission service to nonpublic utility transmitting entities when

reciprocal transmission service is not

offered.475

Phelps Dodge and Otter Tail believe

that non-public utility transmitting

entities will continue their existing

bundled service contracts indefinitely to

avoid complying with the reciprocity

requirement. Therefore, to promote

transmission access through reciprocity,

Phelps Dodge and Otter Tail suggest

requiring the unbundling of existing

contracts by a date certain to convert

such contracts to transmission service

agreements under the transmission

provider’s open access tariff.

A number of commenters argue that

the Commission’s only legal authority to

impose a reciprocity requirement on

non-public utilities is that provided by

section 211 of the FPA.476 Large Public

Power and others suggest that

mandating reciprocity is not necessary

because the stated goals of the

reciprocity requirement can be met by

voluntary transmission access and

through section 211 filings.

Many commenters do not oppose

reciprocity if it is modified to

incorporate the protections present in

sections 211 and 212 and the benefits

available under sections 205 and 206.477

TDU Systems explains that section 211

contains a number of protections, e.g.,

transmitting utilities cannot be required

to provide transmission service if such

service impairs their ability to provide

reliable service, disrupts existing

contracts with entities seeking service,

or is inconsistent with state law

regarding retail marketing areas. It also

notes that section 212 contains rate

provisions that protect a non-public

utility transmission provider from being

forced to provide electric service at a

non-compensatory rate. Seminole EC

argues that, without section 205/206

rights, non-public utilities cannot adjust

their tariffs or challenge tariff provisions

that they believe should not apply to

them.

Several commenters also suggest that,

without sections 211, 212, and 205

rights and protections, reciprocity
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21611

478E.g., EEI, Consumers Power, Montana-Dakota

Utilities, CSW, Duke, BPA.

479E.g., Blue Ridge, SMUD, LPPC, Salt River,

Oglethorpe.

480See also Omaha PPD, Salt River, MEAG,

TAPS.

481See also Omaha PPD.

482See also Heartland.

483See also Wisconsin Municipals, Omaha PPD,

Salt River, MEAG, MMEWC, NE Public Power

District.

484See also TAPS.

provisions allow the transmission

provider to deny transmission based on

its own determination of the

transmission customer’s attempt to

comply with reciprocity, which SC

Public Service Authority contends is

letting the ‘‘fox guard the henhouse.’’

TAPS states that in no event should the

claimed lack of reciprocity constitute

grounds for refusal to offer a service

agreement, or unilateral denial, delay or

termination of service. TAPS, and other

cooperative, municipal, and public

power commenters suggest that some

procedure must be developed to bring

reciprocity disputes before the

Commission. Wisconsin Municipals

argues that this provision should be

modified, claiming that a customer’s

receipt of a revenue credit for

transmission facilities it contributes to

the transmission provider’s system

should satisfy the reciprocity

requirement.

Rather than filing tariffs with the

Commission, Dairyland suggests

allowing cooperatives that are not

public utilities to file a compliance

transmission tariff with the Rural

Utilities Service (RUS) as it relates to

the issue of reciprocity, thereby

affording non-jurisdictional cooperative

utilities rights and privileges similar to

those afforded jurisdictional utilities.

Application of Reciprocity Requirement

Several commenters argue that

reciprocity should apply to both the

seller and purchaser engaged in a

transaction under an open access tariff

to ensure that: (1) Transmission

customers cannot avoid their reciprocity

obligation by requesting service through

an agent that owns no transmission

facilities; (2) a generator cannot take

transmission service in order to sell

power to a non-jurisdictional entity,

thereby allowing the non-jurisdictional

entity to escape the reciprocity

provision, and (3) a buyer cannot take

service in order to purchase power from

a non-jurisdictional entity, thereby

allowing the entity to escape the

reciprocity requirement. 478

Entergy also is concerned that

reciprocity can be evaded through the

use of power marketers. Therefore,

Entergy proposes that, if the

transmission customer is neither the

producer, transmitter, nor distributor of

the power and energy to be transmitted,

but instead acts as a marketer, the

marketer must designate an electric

utility that either produces, transmits, or

distributes such power and energy as

being subject to the requirement to

provide comparable service.

CCEM and NIEP support the

reciprocity provision because they

apply only to transmission owners.

CCEM and NIEP contend that nontransmission-owning customers should

not be required to procure transmission

capacity or hire a proxy solely to meet

a reciprocity requirement.

In contrast, CA Energy Co insists that

the reciprocity provisions of the

proposed tariffs must be amended to

clarify that IPPs can obtain access even

if the IPPs own no transmission assets.

CA Energy Co argues that the

Commission must exempt IPPs from the

reciprocity requirement if IPPs are to be

assured equal access and thus remain

effective competitors.

Publicly-Owned Entities

Publicly-owned entities argue that

they differ from IOUs and cannot

provide completely reciprocal

services. 479 LPPC identifies a number of

differences between publicly-owned

utilities and IOUs, such as: the publiclyowned utilities’ use of tax-exempt debt,

which could be jeopardized if they are

required to make their transmission

systems available for private use;

restrictions on the rate-setting methods

publicly-owned utilities can use; and

statutory restrictions on the services

publicly-owned utilities can offer. 480

LPPC asks that the reciprocity provision

be dropped or changed to recognize

these differences. 481 It argues that the

purposes of the NOPR are met by

transmission tariffs voluntarily offered

by its members that generally meet the

standard of open access.

NE Public Power District notes that to

the extent that the Commission requires

cost-based rates, the Commission must

recognize that publicly-owned utilities

do not establish rates in the same

manner as IOUs; for example, NE Public

Power District does not include

depreciation or return on equity as costs

in its rates, nor does it pay federal

income taxes. It suggests that the

Commission should not apply a onesize-fits-all approach to pricing

transmission service, should consider

the special circumstances of publiclyowned utilities in exercising its

authority under section 212, and should

give publicly-owned utilities the

opportunity for an evidentiary hearing

before requiring them to adopt ratesetting conventions that are appropriate

for public utilities.482

CAMU asserts that the tax-exempt

financing of government bodies may be

jeopardized due to limitations on the

private use of facilities that are financed

through tax exempt bonds.483 It suggests

that a solution may be to impute the

cost of capital based on the average cost

of all area utilities. Wisconsin

Municipals says that the Commission

should seek an opinion from the IRS

regarding whether reciprocal use would

jeopardize tax-exempt status; if it is

determined it would, the owner of the

transmission facilities should be

allowed to recover any increased costs

associated with the loss of tax-exempt

status.484

DE Muni is concerned that a utility

may ‘‘impose’’ the open access tariffs on

a non-public utility customer such as a

municipal system and then demand

reciprocal access to that customer’s

transmission facilities to serve the

municipal’s retail customers.

San Francisco argues that there is no

legal authority in the FPA or case law

to impose the open access requirement

on non-public utility entities. Moreover,

San Francisco is concerned that the

reciprocity requirement may impair its

ability to deliver its own power

pursuant to the requirements of the

Raker Act.

Salt River opposes the reciprocity

provision because it could

‘‘administratively vest discriminatory

market power in FERC jurisdictional

public utilities.’’ Salt River further

argues that ‘‘duly adopted open access

transmission tariffs or rate schedules of

publicly-owned utilities should be

presumed to satisfy FERC’s reciprocity

requirement, and the legislative action

of the publicly-owned utility’s

ratemaking body should be given

deference in a dispute brought before

FERC relating to the tariff or rate

schedule.’’

Public Generating Pool argues that a

non-public utility transmission

customer should not have to provide the

same service a public utility provides. It

argues that a publicly-owned entity may

lack the resources to provide the high

level of service a public utility can

provide.

Tallahassee seeks clarification that

reciprocity does not mean that investorowned utilities can require municipal

utilities to offer services that are

identical to those offered by the
21612 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

485We note that the application in Docket No.

TX95–3–000 by Municipal Energy Agency of

Nebraska was withdrawn on November 16, 1995.

486Salt River Reply Comments at 2. See also

NCMPA.

487 37 FPC 12, 37 FPC 495 (1967), aff’d sub nom.

Salt River Project v. FPC, 391 F.2d 470 (D.C. Cir.),

cert. denied, 393 U.S. 857 (1968).

488See also Basin EC, Big Rivers EC (citing

Golden Spread, 39 FERC ¶ 61,322, reh’g denied, 40

FERC ¶ 61,348 (1987)), RUS (asserting that RUS has

exclusive authority over rural power cooperatives

that have RUS loans).

489See also McKenzie EC, NW Iowa Cooperative,

TDU Systems, RUS (asserting that if cooperative

voluntarily gives up its tax exempt status, the

Commission should allow the related tax expense

to be included in the rates charged to the nonmember customers only), Brazos, Tri-State G&T,

TAPS.

investor-owned utilities. It argues that it

is not practical to require small utilities

to provide all of the services bigger

utilities provide and that legal

obligations imposed on municipal

utilities may interfere with their ability

to provide certain types of open access

provisions. Tallahassee concludes that

reciprocity should be equated with

comparability (the transmission user

must offer service that is comparable to

the service it offers to itself).

TANC asks for clarification and

suggests various changes to the

reciprocity provision. It asks whether

the reciprocity requirement will apply

to it, since it is part owner of a

transmission facility (the California

Oregon Transmission Project (COTP))

but has contractually dedicated its

entitlement to use of this facility to its

members. It argues that if the

requirement does apply, its obligation

should be limited to the member’s share

of TANC’s entitlement. TANC also asks

whether when it receives transmission

service on behalf of a member, that

member’s non-COTP transmission

facilities must be made available to the

transmission provider. If that is the case,

TANC asks what voltage level of

facilities must TANC and its members

make available? TANC believes that if a

TANC member independently requests

transmission service from a utility, that

member would be obligated to make

reciprocal service available to the utility

on the share of the COTP that member

‘‘controls’’ through TANC’s entitlement.

TANC argues that neither TANC and its

members nor TANC and its COTP coowners should be treated as ‘‘affiliates’’

under the proposed reciprocity

provision. It argues that the comparable

service tariff it must provide as a

member of the Western Regional

Transmission Association should satisfy

the reciprocity requirement.

TANC also asks for clarification as to

how the reciprocity provision would be

administered. A non-public utility

cannot file a tariff with the Commission,

so presumably it and the public utility

from which it wants transmission

service would negotiate; if, however, the

public utility does not agree that

reciprocal service is being offered, it

will deny access to its transmission

facilities, and the non-public utility

would have to come to the Commission

to resolve the dispute. SC Public Service

Authority expresses a similar concern. It

argues that the reciprocity provision

will prevent non-public utilities from

obtaining comparable access. The public

utility from which the non-public utility

wants access will be able to delay access

by claiming that the reciprocity

provision is not satisfied. Even the

possibility of such a delay may

discourage customers from contracting

with non-public utilities. SC Public

Service Authority suggests that this

problem can be fixed by allowing nonpublic utilities to file comparable access

tariffs with the Commission.

NE Public Power District asserts that

while government-owned utilities are

subject to limited regulation under

sections 211–213 of the FPA, ‘‘that

limited grant of jurisdiction cannot be

transmuted into amenability of stateand municipally owned utilities to the

sort of detailed regulation that the

NOPR would impose through requiring

insertion of so-called ’reciprocity’

clauses in the transmission tariffs of

jurisdictional public utilities, by

inviting the filing of ’class’ § 211

applications, or by making adherence to

the rules emerging from the NOPR

proceeding an automatic requirement

for utilities that are subject to a section

211 application.’’

NE Public Power District explains that

it has pending before the Commission a

proceeding in which it has taken the

position that it is not subject to the

Commission’s jurisdiction. (citing

Docket No. TX95–3–000).485 NE Public

Power District also argues that it would

be unconstitutional under the Tenth

Amendment and the Guarantee Clause

of the United States Constitution for the

Commission to assert jurisdiction. It

further argues that the proposed

regulations would constitute an

unfunded Federal mandate within the

meaning of the Unfunded Mandates

Reform Act of 1995 and that the

Commission has not followed the

requirements of that Act.

NE Public Power District explains that

under Nebraska law it is prohibited

from granting or conveying to any

private entity any interest or control of

any of its property or facilities, and

section 211 does not authorize the

Commission to order wheeling for an

end-user or to replace a contractual

wholesale sale. Thus, it argues that the

Commission does not have authority to

use mandatory reciprocity clauses to

obtain compliance with a policy it has

no right to impose directly. (citing

Sunray and AGD). NE Public Power

District also questions whether the

Commission may lawfully declare

exclusive-use provisions invalid under

the Sierra-Mobile doctrine without

conducting a proceeding under section

206 with regard to each specific facility

and making the necessary findings.

Salt River responds to complaints that

public power entities have a

competitive advantage, due to subsidies

and preferences, over investor-owned

utilities:

This Commission is not the appropriate

forum and this proceeding is not the

appropriate proceeding to consider the

investor-owned utilities’ ‘‘level playing field’’

complaint as it relates to public power, and

the Commission should reject any suggestion

that it do so.486

Cleveland urges the Commission not

to address in the NOPR proceeding

either congressional policy as reflected

in the tax laws or the propriety of other

long-standing federal statutes in

considering complaints that publiclyowned entities receive subsidies from

the government that IOUs do not. It

points to three tax breaks available to

IOUs: (1) Investment tax credits; (2)

deferred taxes resulting from different

book and tax depreciation; and (3) use

of tax-exempt financing in certain

circumstances.

NRECA/APPA argues that the

Commission should not, as requested by

EEI, address alleged ‘‘undue’’ subsidies

received by consumer-owned utilities

and delve into such subsidy issues as

municipal financing policy, rural

electrification and development

policies, and the merits of privatizing

the federal power marketing

administration. NRECA/APPA alleges

that these are complex issues that are

within the domain of other federal

agencies.

G&T and Distribution Cooperatives

NRECA explains that under Dairyland

Power Cooperative,487 the Commission

does not have jurisdiction over

cooperatives that have REA/RUS

loans.488 NRECA further explains that

rural electric cooperatives are exempt

from federal taxation only if 85 percent

of their revenues are derived from their

members and open access could

jeopardize their tax relief.489 RUS notes

that while the Energy Policy Act

expanded the Commission’s authority to

order transmission access, it did not
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21613

490Brazos Initial Comments at 6.

491E.g., NW Iowa Cooperative, TDU Systems, Big

Rivers EC, Mor-Gran-Sou EC, San Luis Valley REC,

Tri-County EC; see also RUS, MEAG, Brazos.

492E.g., NRECA, Cajun, AEC & SMEPA, Seminole

EC, TDU Systems. 493FERC Stat. & Regs. at 33,050.

amend the Rural Electrification Act (RE

Act) so as to curtail the plenary powers

of RUS to carry out a program of rural

electrification.

Citing various cases, Brazos says that

the Commission must be mindful of the

purposes of the RE Act and, if available

transmission on Brazos is taken for use

by third parties, ‘‘a question remains as

to the capacity of the remaining portions

of the system to function with ‘decent

service and at decent rates.’ ’’ 490

Various rural electric cooperatives

state that the Commission must

recognize that consumer-owned electric

utilities are very different from investorowned utilities.491 Mor-Gran-Sou EC is

concerned that the final rule will have

a detrimental impact on rural areas, just

as it believes deregulation of the

banking industry, airline industry and

telecommunications industry has had.

Many cooperatives request that the

term ‘‘affiliates’’ be defined: (1) To

apply only to corporate ‘‘affiliates’’ over

which the transmission customer

exercises legal control; and (2) to

exclude the distribution cooperative

members of a generation and

transmission (G&T) cooperative.492

Seminole EC explains that a G&T is a

cooperative formed by a group of

distribution cooperatives; therefore, a

G&T has no legal powers to require

action by its member cooperatives. In

fact, according to Seminole EC, the

distribution cooperatives govern the

G&T.

Similarly, TDU Systems notes that the

term ‘‘affiliates’’ could be construed to

apply to a joint action agency and its

municipal and cooperative members.

TDU Systems point out that a joint

action agency, itself a creature of statute,

may not have the power to require its

members to provide transmission

service.

AEC & SMEPA contends that

including the transmission customer’s

affiliates in the reciprocity obligation is

broader than the obligation of the

transmission provider, which does not

include transmission service by the

provider’s affiliates. AEC & SMEPA

suggests that either: (1) The

transmission provider’s affiliates should

be included in the basic obligation to

provide transmission service; or (2) the

reciprocity provision should delete the

reference to affiliates of the transmission

customer.

NRECA comments that it is unclear

whether ‘‘facilities owned or controlled

by the transmission customer’’ include

transmission contracts. NRECA believes

that transmission contracts cannot be

included in this definition, at least as

applied to ‘‘transmitting utilities’’ under

sections 211 and 212.

Transmission Provider

Seminole EC questions whether the

requirement to offer ‘‘open access’’

service requires reciprocal service to be

provided solely to the transmission

provider or an open access tariff

available to any and all qualified

applicants. Seminole EC and NRECA

request that the Commission adopt the

former interpretation in the final rule.

In contrast, Tucson Power and Phelps

Dodge believe that, if a non-public

utility transmitting entity chooses to

take service under any open access

tariff, such access should be

conditioned on its own agreement to

provide comparable service to all

eligible customers under an open access

tariff.

Tucson Power believes that, without

such access to all eligible customers,

reciprocity will fail to achieve true

‘‘comparability.’’ Tucson Power

explains that reciprocal transmission

service would appear to be limited by

the terms of the specific original request

for transmission. For example, Tucson

Power fears that a non-jurisdictional

entity requesting 25 MW of point-topoint firm service could argue that its

reciprocal transmission obligation is

limited to the same 25 MW of point-topoint firm service for an equivalent

duration. Tucson Power argues that

such a limitation on providing

reciprocal service would prove useless.

Further, Tucson Power believes that

reciprocity should be interpreted to

require a non-public utility entity to

expand or upgrade facilities to meet the

transmission requests of all eligible

entities and should contain the same

pricing provisions as applied in this

proceeding for jurisdictional utilities.

Seminole EC questions whether the

reciprocity requirement to provide

‘‘comparable’’ service to the

transmission provider simply means

offering the same kind of service to the

transmission provider that the

transmission customer receives (i.e.,

network, firm point-to-point, or nonfirm).

NRECA claims that the reciprocity

requirement should not be construed to

impose on non-public utilities an

unreasonable obligation to build.

Seminole EC adds that an unreasonable

obligation to build could effectively

preclude requests for tariff service; the

transmission customer could be better

off litigating a section 211 request rather

than accepting the obligation to

undertake a massive construction

program.

Commission Conclusion

We conclude that it is appropriate to

require a reciprocity provision in the

Final Rule pro forma tariff. This

provision would be applicable to all

customers, including non-public utility

entities such as municipally-owned

entities and RUS cooperatives, that own,

control or operate interstate

transmission facilities and that take

service under the open access tariff, and

any affiliates of the customer that own,

control or operate interstate

transmission facilities. Any public

utility that offers non-discriminatory

open access transmission for the benefit

of customers should be able to obtain

the same non-discriminatory access in

return.

In the NOPR, we explained that the

reciprocity provision would ‘‘requir(e)

any user or agent of the user of the tariff

that owns and/or controls transmission

facilities to provide non-discriminatory

access to the tariff provider.’’ 493 We

wish to clarify that, in stating that a user

must provide non-discriminatory access

to the tariff provider, we intend that

reciprocal service be limited to the

transmission provider. However, in

situations in which a non-public utility

is a member of an RTG or a power pool,

it also would have to provide service to

the other members of the RTG or power

pool. We do not believe it is appropriate

to expand the reciprocity condition

beyond these situations at this time

because, as discussed further below, the

IRS currently is evaluating its taxexempt financing regulations in light of

competitive changes in the industry.

We are aware that many non-public

utilities are very willing to offer

reciprocal access, and that some are

willing to provide access to all eligible

customers through an open access tariff.

However, they are fearful that a public

utility may deny service based simply

on a claim that the open access tariff

offered by a non-public utility is not

satisfactory. To assist these non-public

utilities, we have developed a voluntary

safe harbor procedure that should

alleviate these concerns. Under this

procedure, non-public utilities would be

allowed to submit to the Commission a

transmission tariff and a request for

declaratory order that the tariff meets

the Commission’s comparability (nondiscrimination) standards. We would

post these requests on the Commission

Issuance Posting System (CIPS) and

would provide them with an NJ (non-
21614 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

494Public utilities would also be required to

provide service during the pendency of any request

for declaratory order. Otherwise, public utilities

could continue to delay providing service.

495See, e.g., Southwest Regional Transmission

Association, 73 FERC ¶ 61,147 at 61,414 (1995).

496See 26 U.S.C. 141.

497See 26 U.S.C. 142.

498 Definition of Private Activity Bonds, 59 FR

67658 (December 30, 1994), Proposed Rules (to be

codified at 26 CFR pt. 1).

499The same would be true in the case of a G&T

cooperative that is a tax-exempt entity under

section 501(c)(12) of the Internal Revenue Code (26

U.S.C. 501(c)(12)) that would risk loss of tax-exempt

status if more than 15 percent of its revenues are

derived from business with non-members. We

clarify that reciprocal service will not be required

if providing such service would jeopardize the G&T

cooperative’s tax-exempt status.

500A tariff offered by a non-public utility

transmission provider to satisfy the reciprocity

requirement may include a provision permitting the

transmission provider to refuse service if providing

such service would jeopardize its tax-exempt status

or the tax-exempt status of its bonds. The nonpublic utility could file a declaration to this effect

in an NJ docket.

501 26 U.S.C. 142(f)(2)(A).

jurisdictional) docket designation. If we

find that a tariff contains terms and

conditions that substantially conform or

are superior to those in the Final Rule

pro forma tariff, we would deem it an

acceptable reciprocity tariff and would

require public utilities to provide open

access service to that particular nonpublic utility.494 In order to find that a

non-public utility’s tariff is consistent

with our comparability standards, we

would need sufficient information to

conclude that the non-public utility’s

rate is comparable to the rate it charges

others. In addition, once we find that a

tariff is an acceptable reciprocity tariff,

an applicant in a section 211 case

against a non-public utility would have

the burden of proof to show why service

to the applicant under the same terms

as the reciprocity tariff is not sufficient

and why a section 211 order should be

granted.

The safe harbor procedures that we

have outlined above would be purely

voluntary for non-public utilities. The

procedures are intended to provide nonpublic utilities an opportunity to

confirm that they are willing to provide

comparable transmission service. If,

however, a non-public utility chooses

not to seek a Commission determination

that its tariff meets the Commission’s

comparability standards, a public utility

could refuse to provide open access

transmission service only if such denial

is based on a good faith assertion that

the non-public utility has not met the

Commission’s reciprocity requirements.

In addition to the safe harbor

procedures, we note that a non-public

utility that is a member of an RTG can

meet our comparability standards

through the RTG, and can provide an

open access tariff that meets our

comparability standards by filing a tariff

with the administrator of the RTG.495

Similarly, a non-public utility that is a

member of a power pool could meet our

comparability standard if the power

pool adopts a joint pool-wide open

access tariff.

Some commenters have challenged

the Commission’s jurisdiction to require

any non-public utility that takes

jurisdictional service to provide

reciprocal non-discriminatory

transmission services and to unbundle

its rates. We are not requiring nonpublic utilities to provide transmission

access. Instead, we are conditioning the

use of open access services on an

agreement to offer open access services

in return. Non-public utilities can

choose not to take service under public

utility open access tariffs and can

instead seek voluntary service from the

public utility on a bilateral basis.

In response to arguments raised by

publicly-owned utilities and

cooperatives, we are not prepared to

revise or eliminate the reciprocity

condition. Our reason is simple and

compelling. We are undertaking this

Rule and imposing significant

responsibilities on public utilities to

ensure the Nation’s transmission grid is

open and available to customers seeking

access to the increasingly competitive

commodity market for electricity. While

we do not have the authority to require

non-public utilities to make their

systems generally available, we do have

the ability, and the obligation, to ensure

that open access transmission is as

widely available as possible and that

this Rule does not result in a

competitive disadvantage to public

utilities. Non-public utilities, whether

they are selling power from their own

generation facilities or reselling

purchased power, have the ability to

foreclose their customers’ access to

alternative power sources, and to take

advantage of new markets in the

traditional service territories of other

utilities. While we do not take issue

with the rights these non-public utilities

may have under other laws, we will not

permit them open access to

jurisdictional transmission without

offering comparable service in return.

We believe the reciprocity requirement

strikes an appropriate balance by

limiting its application to circumstances

in which the non-public utility seeks to

take advantage of open access on a

public utility’s system. However, we

recognize that Congress has determined

that certain entities in the bulk power

market can utilize tax-exempt financing

by issuing bonds that do not constitute

‘‘private activity bonds’’ 496 or by

financing facilities with ‘‘local

furnishing’’ bonds.497 In both

circumstances, Congress has entrusted

the Internal Revenue Service (IRS) with

the responsibility for implementation

and for determining what uses of the

facilities are consistent with

maintaining tax-exempt status for bonds

used to finance such facilities. It is not

our purpose to disturb Congress’s and

the IRS’s determinations with respect to

tax-exempt financing.

We are encouraged that the IRS is

presently reconsidering its private

activity bond regulations in light of,

among other things, the changing

circumstances in the electric industry,

including this proceeding.498 We are

hopeful that the IRS in its rulemaking

will, to the maximum extent possible,

remove regulatory impediments that

limit the ability of industry participants

to provide reciprocal open access

service. Until that occurs, however, we

believe we must ensure that the

reciprocity requirement will not be used

to defeat tax-exempt financing

authorized by the Congress. Therefore,

we clarify that reciprocal service will

not be required if providing such service

would jeopardize the tax-exempt status

of the transmission customer’s (or its

corporate affiliates’) bonds used to

finance such transmission facilities.499 If

a non-public utility has sought a

declaratory order on a voluntarily-filed

tariff, we request that it identify the

services, if any, that it cannot provide

without jeopardizing the tax-exempt

status of its financing.500

We believe, given the fact that the IRS

is currently examining these issues, that

our policy in this regard is appropriate

for the time being. After the IRS acts, we

will reexamine our policy to ensure that

the reciprocity requirement is applied

broadly to achieve open access without

jeopardizing tax-exempt financing.

With respect to local furnishing

bonds, which are available to a handful

of public utilities, we note that

Congress, in section 1919 of the Energy

Policy Act, amended section 142(f) of

the Internal Revenue Code to provide

that a facility shall not be treated as

failing to meet the local furnishing

requirement by reason of transmission

services ordered by the Commission

under section 211 of the FPA if ‘‘the

portion of the cost of the facility

financed with tax-exempt bonds is not

greater than the portion of the cost of

the facility which is allocable to the

local furnishing of electric energy.’’ 501

San Diego G&E has included in its

existing transmission tariff a provision
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21615

502See San Diego Gas & Electric Company, Docket

No. ER96–43–000, Pro-Forma Point-to-Point

Transmission Service Tariff, section 4.6(d); Network

Transmission Service Tariff, section 4.7(d).

503See Appendix D, Pro Form Open Access

Transmission Tariff, Section 5.

that provides that, if it appears that the

provision of transmission service would

jeopardize the tax-exempt status of any

local furnishing bonds used to finance

its facilities, San Diego G&E will not

contest the issuance of an order under

section 211 of the FPA requiring the

provision of such service, and will,

within 10 days of receiving a written

request by the applicant, file with the

Commission a written waiver of its

rights to a request for service under

section 213(a) of the FPA and to the

issuance of a proposed order under

section 212(c).502 We believe such a

provision is necessary and appropriate

so that any local furnishing bonds that

may exist do not interfere with the

effective operation of an open access

transmission regime. Accordingly, we

will require any public utility that is

subject to the Open Access Rule that has

financed transmission facilities with

local furnishing bonds to include in its

tariff a similar provision.503

In addition, in response to arguments

raised by cooperatives and joint action

agencies, we agree to limit the

reciprocity requirement to corporate

affiliates. If a G&T cooperative seeks

open access transmission service from

the transmission provider, then only the

G&T cooperative, and not its member

distribution cooperatives, would be

required to offer transmission service.

However, if a member distribution

cooperative itself receives transmission

service from the transmission provider,

then it (but not its G&T cooperative)

must offer reciprocal transmission

service over its interstate transmission

facilities.

Finally, a non-public utility, for good

cause shown, may file a request for

waiver of all or part of the reciprocity

requirement. We would apply the same

criteria we will use to determine

whether to grant a waiver of all or part

of the Final Rule’s requirements for

public utilities that request waiver.

The reciprocity requirement will also

apply to any entity that owns, controls

or operates transmission facilities that

uses a marketer or other intermediary to

obtain access. For example, if a

municipal purchases power from a

marketer that also arranges for the

transmission of the power through a

public utility open access tariff to the

municipal, the municipal would need to

meet our reciprocity requirements. We

point out here that we have established

a procedure, set out in Section IV.K.2.,

for small public utilities to request a

waiver from some or all of the

requirements of the Rule. We would

apply the same criteria to waive the

reciprocity condition for small nonpublic utilities.

g. Miscellaneous Tariff Modifications

(1) Ancillary Services

The pro forma tariff, attached as

Appendix D, incorporates conforming

revisions consistent with the

determinations discussed in Section

IV.D.

(2) Clarification of Accounting Issues

Comments

A number of commenters generally

assert that, as presently configured, the

Commission’s Uniform System of

Accounts does not support the proposed

stranded cost and open access policies

set forth in the NOPR. They urge the

Commission to open a separate docket

to address these accounting issues and

bring together all parties to properly

resolve them. More specifically,

commenters ask whether certain of the

requirements outlined in the NOPR pro

forma tariffs would require changes to

the Uniform System of Accounts. In

particular, commenters are concerned

that the recording of costs and revenues

related to ancillary services, facilities

studies, and system impact studies

would require the creation of new

accounts under the Uniform System of

Accounts. In addition, commenters raise

questions about the procedures

transmission providers would have to

follow for recording the costs for their

own use of the system. Commenters also

indicate that the Commission’s

accounting requirements may not be

adequate to provide fully for the

recognition of stranded costs as

contemplated in the NOPR.

Commission Conclusion

The Final Rule will result in

significant changes in the way public

utilities conduct business. This will

create needs for financial information

that are different from those that the

Commission and others found necessary

in the past. The Commission believes

that the accounting guidance discussed

infra will be sufficient to provide the

financial information needed for

regulatory purposes in light of this Rule.

Therefore, we will not institute a

separate proceeding to propose changes

to our Uniform System of Accounts at

the present time. We recognize,

however, that the industry is in an early

stage of transition to an environment in

which truly comparable transmission

services will be provided to all

wholesale users. If, after gaining

additional experience, it becomes

apparent that more guidance is needed,

additional guidance can be provided at

that time through issuance of

accounting interpretations, guidance

letters, or a notice of proposed

rulemaking to change our accounting

regulations.

Many of the accounting concerns

expressed by commenters were

addressed in the Chief Accountant’s

January 26, 1996 guidance letter. We

offer the following additional

clarifications on the Final Rule pro

forma tariff requirements and certain

other accounting issues related to the

Final Rule.

(a) Transmission Provider’s Use of Its

System (Charging Yourself)

The purpose of functional unbundling

is to separate the transmission

component of all new transactions

occurring under the Final Rule pro

forma tariff, thereby assisting in the

verification of a transmission provider’s

compliance with the comparability

requirement. For example, if a

transmission provider makes an offsystem power sale, functional

unbundling requires that the revenues

received from that third-party customer

be unbundled into specific transmission

and production components. The

transmission component of the revenues

would be the product of the amount of

transmission capacity used in making

the sale and the applicable rate. With

respect to off-system sales, the

transmission provider would look to

operating revenue accounts those

revenues received from the customer to

whom it made the off-system sale. We

will require that the transmission

service component and energy

component of those revenues be

recorded in separate subaccounts of

Account 447, Sales for Resale.

(b) Facilities and System Impact Studies

Comparability mandates that to the

extent a transmission provider charges

transmission customers for the costs of

performing specific facilities or system

impact studies related to a service

request, the transmission provider also

must separately record the costs

associated with specific studies

undertaken on behalf of its own native

load customers, or, for example, for

making an off-system sale. Utilities

choosing this method of recovering the

cost of specific studies must keep

detailed expense records pertaining to

each specific study. We will require

utilities to record the cost of such

studies that are properly includable in

the determination of net income for the
21616 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

504This discussion applies to vertically integrated

transmission providers. It may not apply, for

example, to a transmission-only company or an

independent system operator.

period in a separate subaccount of

Account 566, Miscellaneous

Transmission Expenses. We note,

however, that not all studies performed

by a transmission provider will benefit

only a single customer. To the extent a

transmission provider performs a

system impact study that is useful in

providing service to all transmission

customers, the costs should be allocated

to all customers.

(c) Ancillary Services

To ensure comparable transmission

access a transmission provider is

obligated to provide, or offer to provide,

certain ancillary services to the

transmission customer. Also, the

transmission provider may offer to

provide other ancillary services to the

transmission customer, as discussed in

Section IV.D. A transmission customer

is obligated to purchase certain ancillary

services from the transmission provider.

Generation resources provide certain

ancillary services, while transmission

resources provide other ancillary

services. Consequently, the costs of

providing certain ancillary services are

recorded in the transmission provider’s

power production expense accounts,504

while others are recorded in the

transmission provider’s transmission

expense accounts.

Some commenters suggest that there

may be a need for revising the Uniform

System of Accounts to better track the

costs of providing discrete ancillary

services. Other commenters believe that

ancillary services are transmission-type

services and suggested that the costs of

generation-provided ancillary services

be refunctionalized from power

production expense to transmission

expense.

Currently, the Uniform System of

Accounts requires that costs incurred in

providing ancillary services are

recorded as power production or

transmission expense depending upon

which resource the transmission

provider uses to supply the service. At

this time, we are not convinced that the

amounts involved or the difficulty

associated with measuring the cost of

ancillary services warrants a departure

from our present accounting

requirements. However, in calculating

separate rates for specific ancillary

services utilities must maintain

sufficient records and cost support for

the derivation of the rates. Additionally,

we will specify that the revenues a

Transmission Provider receives from

providing ancillary services must be

recorded by type of service in Account

447, Sales for Resale, or Account 456,

Other Electric Revenues, as appropriate.

(3) Liability and Indemnification

Comments

A number of commenters addressed

the liability and indemnification

provisions of the proposed pro forma

tariffs. Duke argues that the proposed

language confuses and conflates the

limitation on the Transmission

Provider’s and Customer’s rights against

each other if a force majeure event

occurs, and the requirement of

indemnification against claims by third

parties.

EEI argues that the proposed

indemnification provision is

inappropriate because it applies both

ways, that is, the Transmission Provider

and Customer indemnify each other

against third party claims arising on

their own systems. EEI suggests that the

provision, as written, could result in the

utility being required to indemnify the

customer against damages incurred if,

for example, an individual pried open a

transformer to steal materials and in the

process was electrocuted. This concern

was also voiced by Consolidated Edison,

NYSEG, and Virginia Electric and Power

Company. Consumer Power suggests

that the best answer to this issue may be

to leave the issue of allocation of risk to

the contracting parties, to be resolved by

negotiation when a Service Agreement

is drawn up.

The Coalition for a Competitive

Market, on the other hand, argues that

the indemnification provision, as

proposed, provides too much of a

limitation of the Transmission

Provider’s liability, requiring gross

negligence rather than simple

negligence before the Transmission

Provider can be held liable for damages

to third parties arising from the

Transmission Provider’s actions.

Commission Conclusion

We agree with the commenters that

these risk allocation provisions must be

carefully drafted so that transmission

providers and customers can accurately

assess and account for their respective

risks. The indemnification provision has

now been broken into two parts. The

first part is a force majeure provision

which provides that neither the

transmission provider nor the customer

will be in default if a force majeure

event occurs, but also provides that both

the transmission provider and customer

will take all reasonable steps to comply

with the tariff despite the occurrence of

a force majeure event. This protection

against unexpected and unpredictable

events is appropriately made available

to both the transmission provider and

transmission customer.

The second portion of the provision

provides for indemnification against

third party claims arising from the

performance of obligations under the

tariff. We have limited the

indemnification portion of the provision

so that it is now only the transmission

customer who indemnifies the

transmission provider from the claims

of third parties. The customer is taking

service from the transmission provider

and may appropriately be asked to bear

the risks of third-party suits arising from

the provision of service to the customer

under the tariff. We find that this new

indemnification provision would be too

strict if it required customers to

indemnify transmission providers even

in cases where the transmission

provider is negligent. See Pacific

Interstate Offshore Company, 62 FERC

¶ 61,260 at 62,733–34 (requiring

amendment of indemnification

provisions that required

indemnification except in cases of

‘‘gross negligence’’). Accordingly, the

revised provision provides that the

customer will not be required to

indemnify the transmission provider in

the case of negligence or intentional

wrongdoing by the transmission

provider.

(4) Miscellaneous Clarifications

(a) Electronic Format

In the NOPR, we proposed that public

utilities making Stage Two filings be

required, in addition to the

requirements specified in Part 35, to file

copies of such filings on a diskette in

ASCII format. We will now require that

public utilities, in addition to

complying with the requirements of Part

35, submit a complete electronic version

of all transmission tariffs and service

agreements in a word processor format,

with the diskette labeled as to the

format (including version) used,

initially and each time changes are filed.

After the initial compliance filing,

utilities proposing changes to the Final

Rule pro forma tariff terms and

conditions must provide a detailed list

of changes and, to the extent

practicable, provide an electronic

version that reflects changes in redline/

strikeout format.

(b) Administrative Changes

A number of commenters request

tariff modifications of an administrative

nature. We have adopted many of these

recommendations. Due to the nature of

these changes, we feel that no further
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21617

505E.g., ABATE, CO Com, DOE, Florida Power

Corp, IBM, IL Com, MN DPS, Industrial Energy

Applications, Missouri-Kansas Industrials, NIEP,

ND Com, PG&E, PSNM, SBA, SC Public Service

Authority, TDU Systems.

506E.g., SC Public Service Authority.

507E.g., Dayton, Carolina P&L, Citizens Utilities,

Montana Power, Oglethorpe, OK Com, Seattle,

Seminole EC, St. Joseph, Turlock, WA Com.

508E.g., Christensen, Seminole EC.

explanation is necessary. The tariff

modifications include the following:

Part I—Common Service Provisions

Description

• Added definition for Curtailment.

• Modified definition for Good Utility

Practice.

• Added definition for Interruption.

• Added definition for Load

Shedding

• Added definition for Long-Term

Firm Point-to-Point Transmission

Service.

• Added definition for Third-Party

Sale.

• Modified provision for Interest on

Unpaid Balances to include amounts

placed in escrow.

• Modified provision for Customer

Default to not require termination of

service.

• Deleted contradictory language

from the provision for Rights Under the

Federal Power Act.

• Deleted references to Valid Request

throughout the tariff.

Part II—Point-To-Point Transmission

Service

Description

• Added language that multiple

generating units at one site are

considered one point of receipt.

• Changed the time to file an

unexecuted service agreement from 10

days to 30 days.

• Changed the time to execute a

service agreement from 30 days to 15

days.

• Deleted charge for scheduling

changes.

• Deleted redundant language on

study agreements.

• Changed standards for estimates

from binding to good faith.

• Clarified that schedules of energy

submitted to the delivering party will

equal the schedules of energy submitted

by the receiving party unless reduced

for losses.

• Clarified that the term of non-firm

point-to-point transmission service need

not expire before the customer may

submit another application for service.

• Added language for rate treatment

in the instance when a customer uses

more non-firm point-to-point

transmission service than it has

reserved.

• Clarified Deposit provision to

permit return of deposit at expiration of

service agreement rather than crediting

the deposit against unspecified

customer obligations under the tariff.

• Clarified provision for Yearly

Extensions for Commencement of

Service.

• Clarified provision for Reservation

of Non-Firm Point-to-Point

Transmission Service.

• Modified provision for customer

Power Factor to permit mutually

agreeable alternatives to maintaining a

specified power factor.

Part III—Network Integration

Transmission Service

Description

• Deleted redundant Direct

Assignment provision.

• Added language to clarify that a

transmission customer does not have to

use the transmission provider’s point-topoint transmission service if the sales to

non-designated loads do not use the

transmission provider’s system.

• Modified Transmission Customer

Redispatch Obligation to limit the

redispatch obligation to reliability

reasons.

• Deleted Member System

requirement from network service.

• Deleted redundant General

Conditions.

• Added provision to return

application if customer does not remedy

deficiency.

• Deleted redundant language for

designating new network resources.

• Deleted redundant language for

connecting new member systems.

• Deleted redundant language for new

interconnection points.

• Added a 60 day period for initial

applications consistent with the pointto-point service provision. (If

applications during this period exceed

available capacity, they are considered

simultaneous requests and service will

be decided based on a lottery.)

• Modified System Impact Study

provision.

• Added 30 day turnaround for

Facilities Study Agreement and changed

estimates from binding to good faith.

• Deleted redundant language for

adding new network resources.

• Added language for rate treatment

in the instance when a customer fails to

curtail or shed load.

• Deleted redundant language from

Network Operating Committee.

H. Implementation

The Commission proposed in the

NOPR a two-stage implementation

process that would apply to all

transmission-owning public utilities

that do not have non-discriminatory

open access transmission tariffs on file

on the effective date of the final rule. As

proposed in the NOPR, public utilities

already in compliance with the rule

would not be subject to the two-stage

process.

In Stage One, the Commission

proposed to put into effect tariffs for

network and point-to-point services,

which include ancillary transmission

services. These tariffs would specify the

minimum terms and conditions of

service needed to eliminate undue

discrimination, and were proposed to be

effective 60 days after the effective date

of the final rule. Because the proposed

pro forma tariffs did not contain specific

rates, the Commission proposed to itself

establish, for each affected public

utility, just and reasonable rates for

network service, point-to-point service,

and six identified ancillary services.

These rates were to be incorporated into

each utility’s tariffs.

In Stage Two, which was to begin 61

days after the effective date of the final

rule, parties would have been allowed

to propose changes to the rates, terms,

and conditions for service under

utilities’ transmission tariffs pursuant to

sections 205 and 206 of the FPA.

Comments

The commenters are split on the twostage implementation procedure

proposed in the NOPR. Commenters in

favor of the proposed procedure believe

that a two-stage process is necessary to

put basic open access tariffs in place

without delay.505 Florida Power Corp

and NIEP state that a longer

implementation procedure would create

a discriminatory situation for utilities

that have filed open access tariffs versus

those that have not. Other commenters,

however, contend that the proposed

Stage One rates would be just and

reasonable only as an interim measure;

therefore, the period during which such

rates are effective should be limited.506

Those commenters that oppose the

two-stage implementation process do so

for a variety of reasons.507 Many

transmission customers believe that

Stage One rates will be much higher

than the rates they pay now. Several

commenters warn that the

implementation plan may not be

practical if the Commission is

inundated with filings at the beginning

of Stage Two.508 Some commenters

expressing concerns about transmission

pricing policy believe that in the NOPR

the Commission intended to establish

the Stage One rate method as its own
21618 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

509As described in the Transmission Pricing

Policy Statement, a ‘‘conforming’’ proposal is one

that meets the traditional revenue requirement and

reflects comparability. FERC Stats. & Regs. ¶ 31,005

at 31,141.

510 Given the brief comment period on the

compliance filings, we will require public utilities

to serve copies of their compliance filings (via

overnight delivery) on: all participants in their

current open access rate proceedings (if applicable);

all customers that have taken wholesale

transmission service from the utility after the date

of issuance of the Open Access NOPR; and the state

agencies that regulate public utilities in the states

of those participants and customers.

511The Commission retains the right to reject

such rates or to set them for hearing.

official pricing policy, while other

commenters argue that the Stage One

rates demonstrate that broad pricing

policy reform is needed as part of an

open access rule.

Some commenters express concern

about the timing of Stage One. Carolina

P&L complains that the proposed

implementation date is far too

aggressive and proposes a one-year

delay between the final rule and its

implementation. Montana Power states

that Stage One tariffs cannot be

implemented in 60 days if any sort of

functional unbundling is required. It

insists that utilities should be given, at

a minimum, 180 days in which to hire

and train new employees and to install

new equipment. Dayton P&L believes

that Stage One tariffs should not be

imposed until experience is gained with

voluntarily-filed open access tariffs, but

recommends further development of the

tariffs for guidance purposes. It also

requests that the Commission delay

implementation of mandatory open

access transmission until meaningful

appellate review has taken place. Seattle

suggests that the rate determination

methods be phased in, so that the forced

filing of transmission tariffs does not

cause immediate and major shifts in

cost allocation between old and new

customers.

A few commenters express concern

about the applicability of the

implementation process. EEI and

Consumers Power state that utilities that

have already filed open access tariffs

should have the option to use the twostage implementation procedure so that

they can obtain the terms and

conditions of the NOPR tariffs without

having to make a full-blown rate case

filing.

Citizens Utilities asks that small

distribution public utilities be exempt

from Stage One if such entities can

demonstrate that they do not use their

own transmission systems to provide

network service. Alternatively, it asks

that application of Stage One to small

public utilities be deferred until 60 days

after they receive a section 211 request.

Oglethorpe states that the proposed

method of Stage One pricing is not

appropriate for electric cooperatives that

receive financing from the Rural

Utilities Service (formerly the Rural

Electrification Administration).

Commission Conclusion

In light of the many concerns raised

regarding the proposed implementation

process, the need to have adequate open

access tariffs on file for all public

utilities as soon as possible, the large

number of utilities that have already

filed some form of open access tariffs,

and the desire to give public utilities

flexibility to propose their own rates to

be used in conjunction with the

minimum non-rate terms and conditions

necessary to ensure comparable service,

we have decided to modify our

proposed procedures. The details of the

revised procedures are discussed below.

In addition, special implementation

requirements for coordination

arrangements (power pools, public

utility holding companies, and bilateral

coordination arrangements) are

discussed in Section IV.F.

The Revised Procedures

Implementation of the Rule will vary

slightly for those public utilities that

tendered for filing open access tariffs

before the date of issuance of this Rule

(including newly-tendered applications

that have not been accepted for filing

before the issuance of this rule) and

those public utilities that did not tender

open access tariffs before the issuance of

this Rule. The former group is

hereinafter referred to as Group 1 public

utilities, while the latter group is

referred to as Group 2 public utilities.

1. Group 1 Public Utilities

Group 1 public utilities will be

required, within 60 days following

publication of the Final Rule in the

Federal Register, to make section 206

compliance filings that contain the nonrate terms and conditions set forth in

the Final Rule pro forma tariff and

identify any terms and conditions that

reflect regional practices, as discussed

below. Attached as Appendix E to this

Rule is a list of Group 1 public utilities.

As to rates, we note that a

transmission tariff rate is already in

effect for all Group 1 public utilities,

except for the few with recentlytendered applications that have not yet

been accepted for filing. Most of these

rates have been suspended, accepted for

filing, set for hearing, and made subject

to refund. Some have been accepted

outright. Still others are the product of

rate settlements.

We anticipate that our mandated

changes in non-rate terms and

conditions are compatible with the rate

proposals already filed by Group 1

public utilities. Consequently, we are

not going to divert the industry’s

resources by mandating any rate

changes to fine-tune these interim

tariffs. Should, however, a Group 1

public utility determine that certain rate

changes are necessitated by the revised

non-rate terms and conditions, it may

file a new rate proposal under FPA

section 205. Such filings must be

‘‘conforming’’ 509 under the

Transmission Pricing Policy Statement

and must be made no later than 60 days

after publication of the Final Rule in the

Federal Register. Intervenors may raise

any concerns with the filings within 15

days after such filings.510 We hereby

impose a blanket suspension for any

filings by Group 1 public utilities

proposing rate changes necessitated by

the new non-rate terms and conditions.

These rates will go into effect, subject to

refund, 60 days after publication of this

Rule in the Federal Register (the same

day on which the non-rate terms and

conditions of the Final Rule pro forma

tariff go into effect).511

If the Final Rule tariff’s non-rate terms

and conditions do not in the opinion of

the utility necessitate a change in

current rates, then the current rates will

continue in effect under whatever

refund conditions, if any, now apply to

those rates.

2. Group 2 Public Utilities

Group 2 public utilities will be treated

the same as Group 1 public utilities

with regard to non-rate terms and

conditions, but will be treated slightly

differently from Group 1 as to rates,

since Group 2 utilities have not filed

any proposed rates. We will require

these utilities to either: (i) Within 60

days following publication of the Final

Rule in the Federal Register, make

section 206 compliance filings that

contain the non-rate terms and

conditions set forth in the Final Rule

pro forma tariff and identify any terms

and conditions that reflect regional

practices, as discussed below; and (ii)

within 60 days following publication of

the Final Rule in the Federal Register,

make section 205 filings to propose rates

for the services provided for in the tariff,

including ancillary services; or (iii)

make a ‘‘good faith’’ request for waiver.

The rates must meet the standards for

conforming proposals in the

Commission’s Transmission Pricing

Policy Statement and comply with the

guidance concerning ancillary services

set forth in this order. Attached to this
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21619

512 Group 2 public utilities must serve a copy of

their filings (via overnight delivery) on all

customers that have taken wholesale transmission

service from them since March 29, 1995 (the date

of issuance of the Open Access NOPR) and on the

state agencies that regulate public utilities in the

states where those customers are located.

513But see note 510, supra.

514As we stated in our ‘‘Further Guidance Order,’’

American Electric Power Service Corp., 71 FERC

¶ 61,393, 62,539–40, order on rehearing, 72 FERC

¶ 61,287, order on rehearing, 74 FERC ¶ 61,013

(1995), all tariffs need not be ‘‘cookie-cutter’’ copies

of the Final Rule tariff. Thus, under our new

procedure, ultimately a tariff may go beyond the

minimum elements in the Final Rule pro forma

tariff or may account for regional, local, or systemspecific factors. The tariffs that go into effect 60

days after publication of this Rule in the Federal

Register will be identical to the Final Rule pro

forma tariff; however, public utilities then will be

free to file under section 205 to revise the tariffs,

and customers will be free to pursue changes under

section 206.

515That determination included the situation in

which a former bundled retail customer may need

unbundled wheeling services from its previous

public utility generation supplier, as well as

unbundled wheeling from one or more intervening

public utilities, in order to reach a distant

generation supplier. In that scenario, the

Commission would have jurisdiction over all of the

transmission facilities used for the unbundled

wheeling provided by the intervening public

utilities. The NOPR also noted that the Commission

would not have jurisdiction over the rates for the

sale of generation by the distant supplier because

the transaction would be a retail sale. FERC Stats.

& Regs. ¶ 32,514 at 33,144.

516The term ‘‘wheeling’’ is intended to cover any

delivery of electric energy from a supplier to a

purchaser, i.e., transmission, distribution, and/or

local distribution. The Commission also has

jurisdiction to order wholesale transmission

services in either interstate or intrastate commerce

by transmitting utilities that are not also public

utilities. See Tex-La Electric Cooperative of Texas,

Inc., 67 FERC ¶61,019 (1994), reh’g pending.

Rule as Appendix F is a list of Group

2 public utilities.

Intervenors may raise any concerns

with these filings within 15 days after

the filing.512 We hereby impose a

blanket suspension for all such rate

filings; they will go into effect, subject

to refund, 60 days after the publication

of this Rule in the Federal Register (the

same day on which the terms and

conditions of the compliance tariffs go

into effect).513

3. Clarification Regarding Terms and

Conditions Reflecting Regional Practices

We have built a degree of flexibility

into the tariffs to accommodate regional

and other differences. Certain non-rate

Final Rule pro forma tariff provisions

specifically allow utilities either to

follow the terms of the provision or to

use alternatives that are reasonable,

generally accepted in the region, and

consistently adhered to by the

transmission provider (e.g., time

deadlines for scheduling changes, time

deadlines for determining available

capacity). In addition, other tariff

provisions require utilities to follow

Good Utility Practice. The definition of

‘‘Good Utility Practice,’’ contained in

Section 1.14 of the Final Rule pro forma

tariff, states that it ‘‘is not intended to

be limited to the optimum practice,

method, or act to the exclusion of all

others, but rather to be acceptable

practices, methods or acts generally

accepted in the region.’’ Thus, where

public utilities are permitted to follow

regional practices, and elect to do so

within 60 days of the date of publication

of the Final Rule in the Federal

Register, they should identify the

regional practices in their compliance

tariff filings.

4. Future Filings

We recognize that there may be

circumstances in which a public utility

believes that the Final Rule pro forma

tariff does not provide sufficient

flexibility or that the utility can propose

superior non-rate terms and conditions.

Thus, once the compliance tariff and

conforming rates go into effect, which

will be 60 days after publication of this

Rule in the Federal Register, a public

utility (either Group 1 or Group 2) may

file pursuant to section 205 a tariff with

terms and conditions that differ from

those set forth in this Rule, provided

that it: (1) Serves a copy of its filing on

all wholesale customers for whom it has

provided transmission service since

March 29, 1995 (the date of the Open

Access NOPR) and on the state agencies

that regulate public utilities in the states

where those customers are located; (2)

identifies all deviations from its

compliance tariff in its letter of

transmittal; (3) provides, to the extent

practical, a redlined version of the tariff;

and (4) demonstrates that such terms

and conditions are consistent with, or

superior to, those in the compliance

tariff. However, it may not seek to

litigate fundamental terms and

conditions set forth in the Final Rule.514

In addition, the public utility may file

whatever rates it believes are

appropriate, consistent with the

Transmission Pricing Policy Statement.

5. Waiver

Finally, as noted above, several

commenters propose that public utilities

that own few transmission facilities be

granted waiver, or that application of

the Rule to such utilities be deferred

until 60 days after they receive a section

211 request. As discussed more fully in

Section IV.K.2., we find that it is

reasonable to permit certain public

utilities for good cause shown to file,

within 60 days after this Rule is

published in the Federal Register,

requests for waiver from some or all of

the requirements of this Rule. The filing

of a request in good faith for a waiver

from the requirement to file an open

access tariff will eliminate the

requirement that such public utility

make a compliance filing unless

thereafter ordered by the Commission to

do so. It will not, however, exempt such

public utility from providing, upon

request, transmission services consistent

with the requirements of the Final Rule.

I. Federal and State Jurisdiction:

Transmission/Local Distribution. In the

original Stranded Cost NOPR, the

Commission clarified that it has

exclusive jurisdiction over unbundled

retail transmission in interstate

commerce by public utilities: it found

that the Commission has exclusive

jurisdiction over the rates, terms, and

conditions of unbundled retail

transmission in interstate commerce by

public utilities, up to the point of local

distribution. In the Open Access NOPR,

the Commission reaffirmed this

jurisdictional determination 515 and also

addressed the distinction between

transmission and local distribution. The

Commission stated three reasons for

expressing its views on the distinction

between Commission-jurisdictional

transmission in interstate commerce and

state-jurisdictional local distribution, in

the context of unbundled retail

wheeling by public utilities.516 First,

facilities that can be used for wholesale

transmission in interstate commerce by

a public utility would be subject to the

Commission’s open access

requirements. Second, states have

authority to address retail stranded costs

and stranded benefits through their

jurisdiction over facilities used in local

distribution. Third, as the structure of

the industry continues to change

dramatically, utilities need to know

which regulator has jurisdiction over

which facilities and services in order to

meet state and federal filing

requirements. Accordingly, the NOPR

set forth our jurisdictional analysis and

several technical factors, for

determining what constitutes ‘‘facilities

used in local distribution.’’

For unbundled wholesale wheeling,

the NOPR proposed to apply a

functional test, i.e., whether the entity to

whom the power is delivered is a lawful

reseller. For unbundled retail wheeling,

the NOPR proposed to apply a

combination functional-technical test

that would take into account technical

characteristics of the facilities used for

the wheeling. The Commission

proposed seven indicators of local

distribution to be evaluated on a caseby-case basis:
21620 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

517FERC Stats. & Regs. ¶32,514 at 33,145.

518 Id. at 33, 144–45.

519As discussed infra, there also would be a

component of local distribution in such a

transaction that would be subject to state

jurisdiction.

520E.g., PG&E, Wisconsin Coalition, Com Ed.

521E.g., NM Com, NC Com, AZ Com.

522Oklahoma G&E Initial Comments at 16.

(1) Local distribution facilities are

normally in close proximity to retail

customers.

(2) Local distribution facilities are

primarily radial in character.

(3) Power flows into local distribution

systems; it rarely, if ever, flows out.

(4) When power enters a local

distribution system, it is not

reconsigned or transported on to some

other market.

(5) Power entering a local distribution

system is consumed in a comparatively

restricted geographical area.

(6) Meters are based at the

transmission/local distribution interface

to measure flows into the local

distribution system.

(7) Local distribution systems will be

of reduced voltage.517

The NOPR concluded that the

application of these tests will enable

states to address stranded costs by

imposing an exit fee on departing retail

customers, or including an adder in the

retail customers’ local distribution

rates.518

In the NOPR, the Commission also

addressed buy-sell transactions in

which an end user arranges for the

purchase of generation from a thirdparty supplier and a public utility

transmits that energy in interstate

commerce and re-sells it as part of a

‘‘nominal’’ bundled retail sale to the end

user. We explained that the retail sale is

actually the functional equivalent of two

unbundled sales (one transmission and

the other the sale of power) and that we

have exclusive jurisdiction over the

voluntary sale by public utilities of

unbundled transmission at retail in

interstate commerce.519

Comments

Several commenters support the

Commission’s proposed jurisdictional

demarcation.520 San Diego G&E states

that the Commission correctly proposed

to look at both functional factors (such

as whether the service is retail or

wholesale) and technical factors (such

as voltage). PG&E states that the NOPR’s

functional/technical test is preferable to

a bright line voltage test.

Consumers Power states that the

Commission has exclusive jurisdiction

over all wheeling on an interconnected

interstate transmission grid. It suggests

that the Commission and the states act

through a joint board or hearing to

resolve jurisdictional differences and

develop a bright line test.

PSE&G and PG&E express concern

that if retail wheeling is implemented,

there may be loopholes that would

enable customers to evade state

jurisdiction and thus avoid paying

stranded costs. For example, PSE&G is

concerned that a retail customer may

request transmission service only and a

state commission will be unable to

attach a retail stranded cost surcharge to

that customer. PG&E proposes adding

another indicator to the functional/

technical test—a final tap to a retail

customer—to ensure that ‘‘high-voltage’’

retail customers do not evade the state’s

reach. Moreover, to ensure that retail

customers cannot escape state

jurisdiction, PG&E recommends that the

Commission state, as a matter of policy,

that ‘‘all retail customers taking retail

transmission service from their host

utility by definition take service over

local distribution facilities.’’

CINergy agrees with the Commission

that a distinction between transmission

and local distribution is important, but

emphasizes the practical need for clarity

on a timely basis. To achieve certainty,

CINergy proposes that the Commission

allow public utilities to file, under

section 205, classifications of their

facilities as transmission or local

distribution. CCEM endorses CINergy’s

proposal. Although NARUC disagrees

that the Commission has jurisdiction

over unbundled retail transmission, if

the Commission reaffirms the NOPR

regarding its jurisdiction, then NARUC

supports CINergy’s proposal.

PSE&G strongly supports the

Commission’s proposed case-by-case

methodology for determining whether

facilities should be classified as

transmission or local distribution. SoCal

Edison argues that since a utility may

have difficulty determining which of its

facilities are transmission and which are

local distribution, utilities and states

should be able to ask the Commission to

classify a particular facility. Portland

and Orange & Rockland suggest that the

Commission provide a forum to resolve

disputes over the correct classification

of particular facilities.

Ohio Edison states that the

Commission should assume jurisdiction

over unbundled retail transmission, but

only where a state has required this

unbundling. It also believes that the

Commission should assert jurisdiction

over the ancillary services necessary to

provide this jurisdictional service.

NYSEG argues that the Commission

lacks jurisdiction over the transmission

component of bundled retail service. On

the other hand, NYSEG argues that the

statute, legislative history, and case law

reveal that the Commission has

jurisdiction over unbundled retail

wheeling from source to load, since it is

transmission in interstate commerce.

NYSEG argues that the ‘‘local

distribution’’ exception to the

Commission’s jurisdiction applies only

to bundled sales of power at retail.

Several state commissions assert that

states have rate authority over all

facilities used to provide retail

service.521 IL Com argues that states

have rate authority over all facilities

used to provide retail service, regardless

of whether the NOPR would classify

these facilities as transmission or local

distribution.

MI Com, citing Connecticut Light &

Power Company v. Federal Power

Commission, 324 U.S. 515 (1945)

(CL&P), and Arkansas Electric

Cooperative v. Arkansas Public Service

Commission, 461 U.S. 375, 393–94

(1983), contends that states have

plenary jurisdiction over all aspects of

retail service, including retail access

and unbundled retail transmission

service. It asserts that the Commission’s

effort to expand federal jurisdiction into

transmission in connection with retail

sales is without statutory justification.

Legal Environmental Assistance

argues that the NOPR creates confusion

about, and may intrude onto, state

jurisdiction. NYMEX argues that when a

state orders retail wheeling, the state

should have jurisdiction over that

transmission-only service.

Oklahoma G&E, citing CL&P and

United States v. California Public

Utilities Commission, 345 U.S. 295, 316

(1953), asserts that the Commission

failed to explain that the term

‘‘transmission in interstate commerce’’

could have different meanings

depending on the factual context in

which the term is applied. It argues that

‘‘transmission in interstate commerce’’

means the movement, in bulk, of

electric energy flowing in interstate

commerce, as opposed to the movement

of electric energy that has been

subdivided for delivery to consumers.

Oklahoma G&E further argues that

‘‘[t]he distinction between

interconnected operation and radial

operation corresponds precisely to this

distinction between activities that have

potential interstate effects and those that

might have interstate effects but are a

matter of primarily local concern.’’ 522

Oklahoma G&E also disagrees that the

transportation of electric energy sold at

wholesale necessarily constitutes

transmission in interstate commerce. It

argues that the Commission has
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21621

523See also OH Com.

524E.g., DOD, NM Com, KY Com, ABATE.

525See Public Utilities Commission v. Attleboro

Steam & Electric Company, 273 U.S. 83 (1927). 526 IA Com Initial Comments at 4.

misapplied case precedent and, by

focusing on the level of the associated

power sale, the Commission has

misunderstood what constitutes a

functional distinction between

transmission in interstate commerce and

local distribution.

NY Com asserts that the grant of

jurisdiction to the Commission over

wholesale power transactions in

interstate commerce under section 201

of the FPA does not reduce the states’

authority over local distribution (citing

CL&P and Federal Power Commission v.

Florida Power & Light Company, 404

U.S. 453, 467 (1972)). NY Com argues

that the NOPR’s assertion of exclusive

jurisdiction over all facilities used to

deliver electricity for resale, even those

traditionally regarded as local

distribution, violates Congress’

assignment of local electric distribution

to the states. It takes issue with the

Commission’s list of factors and says

that states and the Commission should

agree on a definition that preserves the

traditional classification of local

distribution facilities. According to NY

Com, such definition should focus on

the functional characteristics of local

electric systems—i.e., electricity flows

into a comparatively restricted

geographic area and does not flow back

out of that area, and the power is

consumed in that area.

NY IOUs argue that the Commission

has jurisdiction over unbundled, but not

bundled retail wheeling. It says that

other factors, including the indicators

listed in the NOPR, are irrelevant, and

that even long-distance interstate

transmission is under state jurisdiction

as long as it is bundled with a retail sale.

According to NY IOUs, this is the plain

meaning of the FPA; resort to legislative

history is unnecessary. NY IOUs bases

this view on section 201(a), which says

that federal regulation extends only to

matters not subject to state regulation.

NY IOUs says that the only matters

subject to state regulation were bundled

retail sales, and that since transmission

was part of the bundle, Congress

intended transmission to stay under

state authority as long as it is part of that

bundle. It also cites section 201(b),

which sets forth exceptions from

Commission jurisdiction, and section

201(c), which defines ‘‘transmission in

interstate commerce’’ and thus also

controls the definition of transmission

in intrastate commerce. Finally, NY

IOUs argues that the legislative history

supports its view, as does the case law.

Central Louisiana believes that the

costs of requiring a transmission

provider to take unbundled

transmission service for both wholesale

and retail purposes would far exceed

any benefits. In this regard, Central

Louisiana says that states clearly have

jurisdiction over bundled retail

transmission charges and that the

proposed approach could not be

implemented without states giving up

jurisdiction or the passage of new

federal legislation.

MN DPS disagrees on legal and policy

grounds with the Commission’s

assertion of jurisdiction over unbundled

retail transmission services.523 It

maintains that the Commission’s

arguments do not negate the language of

the FPA specifying that regulation of

retail sales of electric energy is reserved

to the states. MN DPS argues that the

Commission’s arguments in support of

its position are not on point because the

issue is state authority to set rates for

retail sales, not interstate commerce.

Further, it declares that jurisdiction over

a service does not change simply

because it is priced differently.

Several commenters argue that

unbundled pricing should not expand

the Commission’s jurisdiction.524

NARUC argues that the NOPR did not

explain why the Commission’s authority

attaches only to unbundled retail

transmission service, why unbundling is

jurisdictionally significant, and how

transmission of electricity to end users

differs from unbundled interstate

transmission of natural gas by local

distribution companies, which is subject

to state regulation. Thus, NARUC urges

the Commission not to claim

jurisdiction over unbundled retail

transmission services.

NARUC also argues that the

Commission’s test for distinguishing

between transmission and local

distribution is not a bright line as

discussed in Federal Power Commission

v. Southern California Edison Company,

376 U.S. 205 (1964) (Colton). NARUC

concludes that when a state determines

to enable a retail customer to purchase

power from a third-party provider, that

state retains the authority to regulate the

delivery service provided by the utility.

IL Com asserts that the test should be

whether the utility function over which

the Commission seeks to exercise

jurisdiction is one which falls within

the Attleboro gap.525 It argues that the

Commission has no legal authority to

prescribe conditions under which a

public utility may provide transmission

service within its own service territory

to its own retail customers. IL Com

concedes that the court cases cited by

the Commission can be interpreted to

support widely disparate legal and

policy positions, but argues that those

cases resolved questions of Commission

jurisdiction in circumstances where

wholesale sales of electric power were

being examined and not circumstances

where retail sales are being considered.

It contends that the question of whether

the Commission should exercise

jurisdiction over all transmission in

retail wheeling has never been

addressed before and requires a careful

examination of the underlying purposes

of Congress in enacting the FPA. IL Com

explains that transmission by an Illinois

utility of power to a retail consumer

within its own service territory is not

subject to Commission jurisdiction

because that transmission was never

within the Attleboro gap and has always

been regulated by states.

OK Com recommends that the

Commission apply to the electric

industry the same policy that it has

adopted concerning its regulation of the

gas industry and leave unbundled retail

service regulation to state authorities.

WI Com argues that if a utility offers

unbundled retail access, jurisdiction

over transmission services should

continue to be based upon the historical

demarcation between wholesale and

retail transactions. KY Com argues that

Congress did not intend, by authorizing

wholesale wheeling in the Energy Policy

Act, to change the longstanding division

of jurisdiction between the Commission

and the states. It claims that the NOPR

ignores the limitation in the FPA that

the Commission has no jurisdiction over

retail sales service. NV Com cites

several cases noting the states’ historical

authority to regulate retail rates.

IA Com proposes a definition of local

distribution and transmission that

would preserve the jurisdictional status

quo and does not put a state

commission in the position of losing

authority over certain elements of a

retail transaction should it allow retail

wheeling. IA Com’s proposed definition

is as follows:

Distribution—Service provided by a utility

directly connected to an ultimate consumer

of electricity is a distribution service with

respect to electric energy delivered to that

consumer.

Transmission—Service provided by a

utility with respect to electric energy to be

delivered to an ultimate consumer through

another utility is a transmission service.526

Montana Power states that a

reasonable way to give effect to the

‘‘local distribution’’ exemption is to

define ‘‘local distribution’’ as a bundled

retail sale, even if interstate facilities are

used.
21622 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

527Natural Resources Defense Initial Comments at

3. 528NV Com Reply Comments at 3.

Several commenters criticized the

NOPR’s functional/physical indicators.

PA Com disagrees with the

Commission’s discussion of the FPA’s

legislative history and asserts that the

FPA does not address the issue of what

constitutes local distribution. PA Com

contends that the issue was resolved by

the Supreme Court in CL&P in a manner

contrary to the Commission’s technicalfunctional test and that the NOPR

minimized CL&P. NM Com asserts that

the proposed engineering and functional

elements for determining the status of

local distribution facilities fail to

account for the governmental or

legalistic test requirement of the FPA as

identified in CL&P.

KY Com concludes that a physical

definition of distribution facilities,

based on objective criteria, is consistent

with the FPA and is necessary to

provide a clean line of demarcation.

CO Com argues that Congress used a

transactional test rather than a

functional test and that Congress

intended all retail transactions to be

under state jurisdiction. According to

CO Com, there is concurrent jurisdiction

over unbundled transmission in

interstate commerce to an end-user.

Moreover, CO Com asserts that

unbundled intrastate transmission to a

wholesale purchaser is under state

jurisdiction (citing section 201(b)(1)).

Finally, CO Com argues that the state

has authority over unbundled

transmission in intrastate commerce to

an end-user when the transmissionproviding utility, end-user, and

generator are all within the same state.

Other commenters prefer a functional

test. Natural Resources Defense, DOE,

and Sustainable Energy Policy generally

agree that a line needs to be drawn

between transmission and local

distribution but believe that the

Commission’s test is unnecessarily

cumbersome or may lead to legal

uncertainty, at least within the context

of stranded benefits. Instead, Natural

Resources Defense proposes the

following functional test, which is based

on end-use service:

The Federal Power Act does not affect state

regulators’ jurisdiction to apply distribution

charges—either volume-based or fixed—to

electricity that is used by any utility

customer to provide end-use services (as

distinguished from electricity that is

purchased for resale to end-use

customers).527

Sustainable Energy Policy endorses

Natural Resources Defense’s position.

DOE suggests that a functional

definition of local distribution (i.e.,

electricity provided for end-use service)

may be the best way to avoid legal

uncertainty.

EPA argues that the Commission’s

proposed physical definition may

encourage gaming to avoid stranded

costs and costs associated with public

policy goals such as energy efficiency,

renewable energy development and R&D

funding, and a physical definition

assumes that power flows into, and not

out of, distribution systems, which

would not allow for distributed

generation (e.g., fuel cells). Thus, EPA

urges the Commission to adopt a

functional definition that ‘‘local

distribution occurs whenever electricity

is provided by a utility for end-use

service.’’ Alternatively, EPA suggests

that the Commission add a provision to

its approach that ‘‘the provision of

electricity for end-use service generally

involves local distribution.’’ Sustainable

Energy Policy suggests a non-bypassable

charge levied on all users of the

distribution system. It endorses the

policy formulation set forth by Natural

Resources Defense in its initial

comments. Reynolds wants to ensure

that there is always at least concurrent

state jurisdiction over lines used to

serve end-use customers, since only

states can order retail wheeling.

Detroit Edison argues that state/

federal jurisdictional issues should be

resolved by focusing on the use of the

facilities. It says that facilities that are

used to distribute a utility’s own power

to its own local customers should be

subject to state regulation, while the use

of facilities for wholesale power

transactions or wholesale or retail

transmission in interstate commerce

should be under federal regulation.

Mountain States Petroleum Assoc

argues that the Commission should use

a functional test based on state

boundaries: if a line is in more than one

state, there is Commission jurisdiction;

if a line is entirely within one state,

there is state jurisdiction.

MD Com states that it believes that the

Commission’s proposed indicators for

determining where to draw the line are

adequate, but adds that it does not

concede the Commission’s assertion of

jurisdiction over unbundled retail

transmission.

Some commenters suggest that

implementation of the NOPR’s tests

could have adverse consequences. NH

Com objects to the NOPR’s specific

tests; for example, if the Commission

asserts jurisdiction over facilities

because they are not radial, New

Hampshire’s policy of encouraging

looping rather than radial lines would

have the ironic effect of destroying state

jurisdiction. NJ BPU states that there

may be situations when the NOPR

factors would not produce the proper

result. It requests that the final rule

recognize the need for case-by-case

flexibility in determining where federal

jurisdiction ends, so that the

Commission and the states can work

cooperatively.

NRRI argues that the NOPR’s test

could make siting of new transmission

lines more difficult because states have

in the past required native load

customers to pay that part of the

transmission-related revenue

requirement that is not covered by

unbundled transmission service. NRRI

contends that, if the Commission asserts

jurisdiction over all unbundled

transmission service and if there is a

firm point-to-point service capacity

right that has value and is reassignable,

then state commissions might eliminate

portions of the transmission systems

subject to capacity rights from rate base.

NRRI is also concerned that the NOPR’s

transmission/local distribution test

could create a price squeeze between

bundled and unbundled retail

transmission rates.

IN Com argues that the NOPR’s view

of jurisdiction would discourage retail

wheeling. It says that states will be

reluctant to order wheeling if the result

is that they lose jurisdiction over the

previously rolled-in transmission aspect

of the service. It suggests that the

Commission use negotiated rulemaking

to address jurisdictional issues.

Several commenters suggest

alternative approaches to jurisdictional

line-drawing. NV Com suggests that the

Commission consider federal and state

jurisdiction over transmission by using

‘‘network’’ and ‘‘non-network’’

concepts:

The ‘‘network’’ concept for regulation

recognizes that there is an interstate network

of electric facilities used to link generation

with loads. The operation of that network is

indifferent to whether the electrical flows are

retail or wholesale flows. Conceptually,

events on the network could fall under

federal jurisdiction. Where facilities provide

essential service for the delivery of power,

but do not substantially affect the electrical

flows on the network, the facilities fall

outside the network and would remain

within the traditional domain of the state

commission. As a consequence the

delineation of federal and state jurisdiction

evolves from the recognition of the events

and where they occur as opposed to a rigid

consideration of the physical properties of

the facilities involved.528

NV Com further explains that the

determination of what is a network

event would require a case-by-case

examination.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21623

529Sections 212(g) and 212(h) of the FPA.

530We note that since OH Com filed its

comments, it approved an interruptible buy-through

plan. See Interruptible Electric Service Guidelines,

Case No. 95–866–EL–UNC, l PUR 4th l (Ohio

PUC Feb. 15, 1996). See also Central Illinois Light

Company, Docket No. ER96–1075–000, 75 FERC ¶

lll (1996) (accepting amendment to open access

transmission tariffs that expands service eligibility

to accommodate participation in experimental retail

wheeling pilot program approved by the Illinois

Commerce Commission); Illinois Power Company,

Docket No. ER96–1285–000, 75 FERC ¶ lll

(1996); cf. Illinois Power Company, l PUR4th l,

No. 95–0494 (Illinois Commerce Commission Mar.

13, 1996) (offering retail direct access service

providing transmission and ancillary services using

the rates, terms, and conditions of Illinois Power’s

open access tariff on file with the Commission);

recently introduced legislation in Rhode Island,

H.B. 8124, the Utility Restructuring Act of 1996. 531SBA Initial Comments at 36.

532NC Com Initial Comments at 7.

533NARUC Reply Comments at 15–16.

534FERC Stats. & Regs. ¶ 32,514 at 33,080–83.

OH Com asserts that Congress intends

there to be a bright line between state

and federal jurisdiction and that the

Commission has failed to provide such

a bright line. OH Com proposes the use

of retail marketing areas to provide the

bright line—the jurisdictional line

would be at the point at which power

enters the retail marketing area of the

entity delivering the power to the retail

customer. OH Com cites section 212(g)

of the FPA, as amended by the Energy

Policy Act, which provides that the

Commission cannot issue any order

under the FPA inconsistent with state

law governing retail marketing areas.

Under OH Com’s proposal, the

Commission would have jurisdiction

over the wheeling-out and wheelingthrough components of retail wheeling

and the state would have jurisdiction

over the wheeling-in component due to

its local nature. OH Com concludes that

the Commission’s approach ‘‘fails to

meet the legal standard FERC must

consider, and is inconsistent with the

‘savings clause’ and legitimacy of ‘retail

marketing areas’ as discussed in the

amended FPA.’’ 529 OH Com also

explains that the Commission’s

approach ‘‘is wreaking havoc on the

state’s ability to develop an interruptible

buy-through arrangement to provide an

increased competitive option for its

retail customers.’’ 530 OH Com further

encourages the use of mutual deference

to promote Congress’ intent in

mandating a system of federal/state

cooperation. In support, OH Com cites

federal and state enforcement of

telecommunications laws. NRRI also

suggests that the jurisdictional line be

drawn at the retail marketing area.

DC Com argues that the NOPR test is

too difficult to administer and will

create problems in determining the rate

base at the state level. It suggests that

the Commission should have

jurisdiction over transmission from the

source to the boundary of the ‘‘home’’

utility that delivers the power to the

customer, with state jurisdiction over all

aspects of the transmission service

within that utility’s franchise territory.

AZ Com also expresses doubts that the

NOPR’s test is workable.

Several commenters propose that the

Commission and state authorities

address the jurisdictional issue jointly.

SBA characterizes the Commission’s

proposed demarcation line as ‘‘laudable

but misguided.’’ 531 SBA recommends

that a federal/state board be established

to resolve the transmission/local

distribution dilemma, similar to what

Congress did for allocating costs

between interstate and intrastate

communications. SBA explains that the

problem in the communications

industry was the impossibility of

allocating a portion of a single copper

wire to interstate or intrastate service.

AZ Com notes that even if the

Commission is correct, the FPA clearly

does not preempt a state from

concluding that retail transmission or

other direct access programs should be

implemented in that state. AZ Com

suggests that there may be concurrent

jurisdiction and that mutually agreedupon principles should be implemented

to determine which jurisdiction should

be given deference.

MD Com states that in determining

the status of particular facilities, the

Commission should give substantial

weight to determinations made by

states. ABATE states that the

Commission could initially defer to

states with respect to the determination

of rates, terms, and conditions, while

maintaining the right to review and

overturn the state determination.

If the Commission maintains its

position concerning jurisdiction,

NARUC argues that the Commission

should not implement its multi-factor

test, but should enter into discussions

with state commissions to develop

workable alternatives. NH Com argues

that pricing the retail part of a

transaction, even if it involves use of the

transmission system, should be subject

only to state jurisdiction. NH Com

wants to create a mechanism by which

state and federal regulators combine

their efforts in cooperative regulation; it

suggests several alternatives such as

state/federal agreements for shared

jurisdiction.

KY Com and NRRI object to the

statement in the NOPR that retail buythrough service is really transmission

service (subject to the Commission’s

jurisdiction) plus a sale of generation at

retail (subject to state jurisdiction).

From a policy standpoint, KY Com

argues that the Commission’s approach

creates a powerful disincentive for a

state to embark on changes that

otherwise might foster a more

competitive environment. NRRI argues

that the Commission’s approach may

violate sections 212(g) and 212(h).

IL Com is concerned that industrial

customers who get direct access may

attempt to evade state jurisdiction, and

thus avoid retail stranded cost charges,

by bypassing facilities such as radial

lines. It contends that retail wheeling

rate surcharges would be a more

effective means of recovering retail

stranded costs if states were allowed to

apply them to unbundled transmission

and local distribution rates, not just the

local distribution component of such

rates.

NC Com asserts that ‘‘[a] significant

cottage industry may well arise solely to

convert retail customers into wholesale

customers, thereby subverting the intent

of Congress as expressly set forth in

EPACT.’’ 532 If the Commission does not

adopt NARUC’s proposal, NARUC

asserts that the Commission’s functional

test should not permit an end user to

bypass the distribution service provided

by the utility. It urges the Commission

to assure that there will be some facility

involved in the transaction that will be

defined as providing a local distribution

service.

NARUC also requests that the

following sentence be added to

proposed 18 CFR 35.27:

Nothing in this part limits the authority of

a State commission in accordance with State

law (1) to allow or disallow the inclusion of

the costs of electric energy purchased at

wholesale in retail rates subject to such State

commission’s jurisdiction, (2) to establish

competitive procedures for the acquisition of

such electric energy, or (3) to establish nondiscriminatory fees for the delivery of such

electric energy to retail consumers for

purposes established in accordance with

State law.(533)

Duke is concerned about the potential

for regulatory gaps, which could lead to

costs not being recovered from either

federal or state jurisdiction. Duke is also

concerned that where facilities are used

for both wholesale and retail

transactions, costs might not be

recovered if federal and state regulators

use different methods of cost allocation.

In response to the NOPR’s proposal

for functional unbundling,534 CA Com

agrees that it is important to draw a

distinction between transmission and

local distribution and that a bright line

is not possible, but suggests that

corporate or functional unbundling
21624 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

535See id. at 33,082.

536UT Com Initial Comments at 4–5.

537NYSEG Initial Comments at 48 (footnote

omitted). 538NYSEG Initial Comments at 50.

might provide a means to establish a

workable bright line without relying on

the more qualitative approach proposed

in the NOPR. Arizona argues that rather

than unbundling transmission for retail

purposes, each utility should establish a

distribution function that would obtain

transmission on behalf of retail

customers, taking service under the

utility’s tariff. Arizona states that this

would simplify the allocation of

transmission costs, since all

transmission costs would be under the

Commission’s jurisdiction. Arizona

argues that the Commission should

permit the utility to recover the

distribution rate approved by the state.

According to Arizona, this would create

a bright line between state and federal

jurisdiction.

TX Com argues that the proposed test

would not be applicable to intrastate

utilities in Texas because they do not

operate in interstate commerce. Thus, it

asserts that it should continue to

regulate Electric Reliability Council of

Texas (ERCOT) transmission and

distribution service and deal with

stranded cost issues that arise in

connection with any retail wheeling

initiatives.

Several commenters object to the

Commission’s proposal to assert

jurisdiction over transactions that are

buy-sell transactions in name only.535

AEP argues that the Commission should

avoid an unnecessary conflict over

state/federal jurisdiction that may be

caused by the NOPR’s statement that

buy-sell transactions are in fact

transmission subject to Commission

jurisdiction. It suggests that the

Commission attempt to reach agreement

with the states on this matter or ask

Congress for any necessary statutory

change. Citizens Utilities also argues

that the Commission should not

unbundle the interstate transmission

aspect of buy-sell transactions. It says

that, unlike the analogous gas contracts,

buy-sell arrangements on the electric

side are not an end run around clear

federal jurisdiction. Further, it argues

that it would be very difficult to define

those buy-sell transactions that truly

belong under federal jurisdiction.

IL Com also objects to the NOPR’s

characterization of buy-sell transactions.

It argues that the fact that a transaction

becomes unbundled does not suddenly

make part of it under federal

jurisdiction. Nucor argues that there is

no need for the Commission to resolve

this issue now; it suggests that the buysell arrangement is only tangentially

related to open access. It argues that

each buy-sell transaction will have to be

addressed individually.

UT Com seeks clarification as to what

the Commission means by buy-sell

arrangements:

we currently authorize interruptible ‘‘buythrough’’ contracts, through which a retail

customer, taking service subject to

interruption for either economic or technical

reasons, can opt to ‘‘buy-through’’ an

interruption. The public utility purchases

energy on behalf of the customer and sells it

at cost to the customer. In our opinion, such

transactions are not an example of a buy-sell

transaction within the meaning of the

proposed rule.536

DOD objects to the statement in the

NOPR that ‘‘buy-sell’’ transactions are

not really bundled retail service. It says

that this view will discourage the

development of innovative state

programs, such as direct access

programs. NYSEG also argues that buysell transactions are not under the

Commission’s jurisdiction. It argues that

these transactions are unlike buy-sell

transactions on the gas side, where the

Commission asserted jurisdiction to

prevent LDCs from circumventing the

nondiscrimination standard it imposed

on the release of capacity. NYSEG says:

In contrast to its regulation of gas buy-sells,

if the Commission regulates electric buy-sell

transactions it would forego regulation of a

transaction in which the Commission has a

significant interest (i.e., access to the

upstream seller’s transmission), to regulate a

transaction in which the Commission has

virtually no interest (i.e., access to the

distributing utility’s system). Electric utilities

must serve each retail customer irrespective

of whether the customer takes traditional

bundled service or retail buy-sell service.

Unlike excess upstream gas pipeline

capacity, the capacity on the local utility’s

electric system would not be allocated to

another customer in a FERC jurisdictional

transaction absent the electric buy-sell

transaction. Electric buy-sell transactions are

not designed so as to manipulate the

assignment of upstream transmission

capacity. Consequently, the impetus for

FERC to reclassify gas buy-sell transactions

as capacity assignments is not present in the

electric context.537

NYSEG argues that there are only two

possible grounds for the Commission’s

assertion of jurisdiction over electric

buy-sell transactions: either (1) the sale

for resale by the supplier is really a sale

at retail to the end user, and the resale

by the local utility is really unbundled

retail wheeling; or (2) the Commission

has jurisdiction over transmission

service that is part of bundled retail

service. It claims that the second ground

is invalid because the transmission

aspect of bundled retail service is

distribution. It also claims that the first

ground is invalid because it assumes

that the sale by the supplier to the local

utility is not a sale for resale even

though the contract says that it is.

NYSEG states:

The logical outcome would be that FERC

would not have jurisdiction over the sale by

the supplier to the utility, including

transmission by that supplier because it

would be a bundled retail sale. This is

because, if the commission holds the resale

to be a retail wheel, then it would have to

find that the sale by the supplier is a retail

sale to the end user. The Commission cannot

at once regulate the sale for resale and the

‘‘retail transmission service.’’ The

Commission would regulate the transmission

rates of the local franchise utility, although

it would not regulate the access to such

transmission service—a matter FERC leaves

to state regulators. In the process, FERC

would abandon the ability to regulate access

to the supplier’s bundled ‘‘retail power sale

and transmission service,’’ a transaction that

FERC arguably has an interest in

regulating.538

Finally, NYSEG argues that if the

Commission insists on asserting

jurisdiction, it should at least

grandfather existing contracts.

UT Industrials state that where there

is a state barrier to a buy-sell

transaction, the Commission should

allow the utility to file a tariff with the

Commission that would permit the

utility to complete a voluntary buy-sell

transaction as the NOPR proposes.

However, it contends that when a state

regulatory authority is authorized to,

and has approved buy-sell transactions,

it is not necessary for the Commission

to become involved. It urges the

Commission to allow such transactions

to take place free of Commission

regulation.

Commission Conclusion

In the discussion below, the

Commission addresses the following

jurisdictional issues raised in the prior

NOPRs:

a. Does the Commission have jurisdiction

over unbundled transmission in interstate

commerce by a public utility when such

transmission is used to transport electric

energy that is sold to an end user?

b. If so, what facilities are jurisdictional to

the Commission in a situation involving the

unbundled delivery in interstate commerce

by a public utility of electric energy from a

third-party supplier to an end user?

c. What facilities are jurisdictional to the

Commission in a situation involving the

unbundled delivery in interstate commerce

by a public utility of electric energy from a

third-party supplier to a purchaser who will

then re-sell the energy to an end user?
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21625

539Not only do we conclude that our

determinations are legally supportable under the

case law, but we believe it is imperative to provide

guidance to public utilities and state regulators as

to our position on where the jurisdictional

boundaries lie.

540The Commission’s complete legal analysis on

this issue, and on the related issue of what facilities

are Commission-jurisdictional transmission

facilities, and what are state jurisdictional local

distribution facilities, are contained in Appendix G

to this Rule.

541Section 201(b)(1) specifically exempts from

Commission jurisdiction facilities used for

transmission in intrastate commerce and

transmission of electric energy consumed wholly by

the transmitter. As a result, we have no jurisdiction

over retail wheeling that occurs in Alaska, Hawaii

and the Electric Reliability Council (ERCOT)

portion of Texas since transactions in those areas

are intrastate.

542The legislative history of FPA section 212(g)

and its predecessor, former section 211(c)(3),

indicates that the provision was focused on not

interfering with state laws governing retail service

territories and not permitting Commission wheeling

orders ‘‘for purposes of sale by a utility to an

ultimate consumer who is within the service

territory of another utility (other than the applicant)

where such territory is established by or under State

law, rule, or decision.’’ See H.R. Conf. Rep. No.

1750, 95th Cong., 2d Sess. 92 (1978), reprinted in

Continued

d. What procedures are appropriate for

making jurisdictional determinations?

In addition, the Commission

addresses concerns raised by state

regulators which indicate that

competition and open access are

perceived as threatening the traditional

regulatory functions of state

commissions. The Federal Power Act

differentiates between state and federal

regulation of electric power. As we

discuss below, the Commission believes

that any change in state or federal

jurisdiction over physical transmission

assets and related costs will not affect

the traditional tasks of state and federal

regulators.

The wide range of jurisdictional

interpretations and proposals in the

comments reflects the fact that the

legislative history of the FPA and case

law interpreting federal/state

jurisdiction under that Act and the

Natural Gas Act grew out of a market

structure in which electricity and

transmission generally were bought and

sold on a bundled basis. As a result,

most transactions included either a

retail or wholesale sale of electric

energy and jurisdictional lines were

drawn on the basis of this sale. Thus,

the cases simply do not resolve

dispositively these jurisdictional issues

when they arise in the context of the

market structures and unbundled

transactions being contemplated in

today’s electric industry. However, after

reviewing the extensive analysis of the

FPA, legislative history, and case law

contained in both our initial Stranded

Cost NOPR and in our Open Access

NOPR, and the comments received on

that analysis, we continue to believe

that we were correct in asserting

jurisdiction over the transmission

component of an unbundled interstate

retail wheeling transaction. We

therefore reaffirm our conclusion. We

also reaffirm and clarify our

determinations regarding the tests to be

used to determine what constitute

Commission-jurisdictional transmission

facilities and what constitute statejurisdictional local distribution facilities

in situations involving unbundled

wholesale wheeling and unbundled

retail wheeling.539

At the same time, the Commission

strongly supports the efforts of states to

pursue pro-competitive policies. We

recognize that jurisdictional issues raise

overlapping Federal and state policy

concerns that call for heightened

cooperation among federal and state

regulators. As discussed below, where

states unbundle retail sales, we will give

deference to their determinations as to

which facilities are transmission and

which are local distribution, provided

that the states, in making such

determinations, apply the seven criteria

discussed in the NOPR and reaffirmed

below. In addition, we clarify our view

that there is an element of local

distribution service in any unbundled

retail transaction, and further clarify

other aspects of our jurisdictional ruling

to preserve state jurisdiction over

matters that are of local concern and

will remain subject to state jurisdiction

if retail unbundling occurs.

We first address our legal

determination that if unbundled retail

transmission in interstate commerce

occurs voluntarily by a public utility or

as a result of a state retail access

program, this Commission has exclusive

jurisdiction over the rates, terms, and

conditions of such transmission. No

commenter has raised cases or

legislative history not previously

considered in our prior NOPRs, and we

will not repeat here our full legal

analysis of this issue.540 However, we

find compelling the fact that section 201

of the FPA, on its face, gives the

Commission jurisdiction over

transmission in interstate commerce (by

public utilities) without qualification.541

Unlike our jurisdiction over sales of

electric energy, which section 201 of the

FPA specifically limits to sales at

wholesale, the statute does not limit our

transmission jurisdiction over public

utilities to wholesale transmission.

In response to those commenters

(including NARUC) who argue that the

Commission did not explain why its

authority attaches only to unbundled,

but not bundled, retail transmission in

interstate commerce by public utilities,

we believe that when transmission is

sold at retail as part and parcel of the

delivered product called electric energy,

the transaction is a sale of electric

energy at retail. Under the FPA, the

Commission’s jurisdiction over sales of

electric energy extends only to

wholesale sales. However, when a retail

transaction is broken into two products

that are sold separately (perhaps by two

different suppliers: an electric energy

supplier and a transmission supplier),

we believe the jurisdictional lines

change. In this situation, the state

clearly retains jurisdiction over the sale

of the power. However, the unbundled

transmission service involves only the

provision of ‘‘transmission in interstate

commerce’’ which, under the FPA, is

exclusively within the jurisdiction of

the Commission. Therefore, when a

bundled retail sale is unbundled and

becomes separate transmission and

power sales transactions, the resulting

transmission transaction falls within the

Federal sphere of regulation.

In asserting jurisdiction over

unbundled retail transmission in

interstate commerce by public utilities,

the Commission in no way is asserting

jurisdiction to order retail transmission

directly to an ultimate consumer.

Section 212(h) of the FPA clearly

prohibits us from doing so. In addition,

as stated in both the initial Stranded

Cost NOPR and the Open Access NOPR,

we do not address whether states have

authority to order retail wheeling in

interstate commerce. The Commission’s

assertion of jurisdiction is that if retail

transmission in interstate commerce by

a public utility occurs voluntarily or as

a result of a state retail wheeling

program, the Commission has exclusive

jurisdiction over the rates, terms, and

conditions of such transmission and

public utilities offering such

transmission must comply with the FPA

by filing proposed rate schedules under

section 205.

The Commission clarifies that nothing

in this jurisdictional determination

changes historical state franchise areas

or interferes with state laws governing

retail marketing areas of electric

utilities. Section 212(g) of the FPA

prohibits Commission orders that would

be inconsistent with such laws.

However, we reject arguments made by

some of the commenters that section

212(g) could somehow be construed to

give states authority over the rates,

terms, and conditions of unbundled

interstate transmission within retail

marketing areas.542 While our
21626 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

1978 U.S. Code Cong. & Ad. News 7797, 7826.

Nothing on the face of section 212(g) or the

legislative history of either the Energy Policy Act

or PURPA indicates that the provision in any way

affects the Commission’s authority over rates, terms,

and conditions of transmission in interstate

commerce by public utilities.

543Among other things, Congress left to the States

authority to regulate generation and transmission

siting. See FPA sections 201(b) and 211(d)(1);

section 731 of the Energy Policy Act.

544This Final Rule will not affect or encroach

upon state authority in such traditional areas as the

authority over local service issues, including

reliability of local service; administration of

integrated resource planning and utility buy-side

and demand-side decisions, including DSM;

authority over utility generation and resource

portfolios; and authority to impose non-bypassable

distribution or retail stranded cost charges.

545Section 35.27 of the proposed rules provided

that any public utility seeking authorization to

engage in sales for resale at market-based rates shall

not be required to demonstrate any lack of market

power in generation with respect to sales from

capacity first placed in service on or after 30 days

from the date of publication of the Final Rule in the

Federal Register. FERC Stats. & Regs. ¶ 32,514 at

33,154.

546As noted, the Commission’s detailed legal

analysis is contained in Appendix G. We are

particularly persuaded by the Supreme Court’s

statement that whether facilities are used in local

distribution is a question of fact to be decided by

the Commission as an original matter. See CL&P,

515 U.S. at 534–35.

547As noted above, states retain authority over

state integrated resource planning, utility resource

portfolios, and utility buy-side and demand-side

decisions.

jurisdiction cannot affect whether and

to whom a retail electric service

territory (marketing area) is to be

granted by the state, and whether such

grant is exclusive or non-exclusive,

neither can state jurisdiction affect this

Commission’s exclusivejurisdiction over

transmission in interstate commerce by

public utilities.

In response to several of the

commenters, we further clarify that the

Commission’s jurisdiction over the

rates, terms, and conditions of

unbundled retail transmission is no

broader than our authority over

transmission used for wholesale

transactions, and will not affect matters

otherwise left to the states by

Congress.543 The Federal Power Act

recognizes that retail marketing areas

are governed by state law. Moreover, we

believe that states have authority over

the service of delivering electric energy

to end users. In exercising this

authority, state regulatory commissions

and state legislatures have traditionally

developed social and environmental

programs suited to the circumstances of

their states. State regulation of most

power production and virtually all

distribution and consumption of electric

energy is clearly distinguishable from

this Commission’s responsibility to

ensure open and non-discriminatory

interstate transmission service. Nothing

adopted by the Commission today,

including its interpretation of its

authority over retail transmission or

how the separate distribution and

transmission functions and assets are

discerned when retail service is

unbundled, is inconsistent with

traditional state regulatory authority in

this area.

The Commission reiterates its strong

interest in preventing any balkanization

of the interstate power market. Although

the Commission believes its Final Rule

will accommodate retail competition, if

it is offered voluntarily by a utility or

ordered by a state, our policies relate

only to the bulk power market and not

traditional state regulation of the retail

market.544

NARUC has requested that the

Commission specifically clarify in

§ 35.27 of its proposed rules 545 that

nothing in our final rule limits the

authority of a state commission ‘‘to

allow or disallow the inclusion of the

costs of electric energy purchased at

wholesale in retail rates subject to such

State commission jurisdiction.’’ We will

adopt NARUC’s proposal with

modification, but add it as a separate

subsection. The Final Rule adopts a new

§ 35.27(b) as follows:

Nothing in this part (i) shall be construed

as preempting or affecting any jurisdiction a

state commission or other state authority may

have under applicable state and federal law,

or (ii) limits the authority of a state

commission in accordance with state and

federal law to establish (a) competitive

procedures for the acquisition of electric

energy, including demand-side management,

purchased at wholesale, or (b) nondiscriminatory fees for the distribution of

such electric energy to retail consumers for

purposes established in accordance with

state law.

With respect to the Commission’s

adoption of the Open Access NOPR’s

functional/technical tests for

determining what facilities are

Commission-jurisdictional facilities

used for transmission in interstate

commerce and what facilities are statejurisdictional local distribution

facilities, the case law supports a bright

line for unbundled wholesale

transmission, i.e., transmission of

electric energy that is being sold for

resale. This is consistent with the bright

line drawn by Congress to fill the

Attleboro gap for regulating wholesale

sales of electric energy. The case law

also supports a bright line with respect

to retail transmission by intervening

utilities, i.e., transmission by those

utilities between the new retail

generation supplier and the public

utility that previously provided bundled

retail service to the end user. However,

despite many commenters’ arguments to

the contrary, we cannot divine such a

bright line for unbundled retail

transmission by the public utility that

previously provided bundled retail

service to the end user. In fact, the

limited case law, including CL&P and

Colton, supports a case-by-case

determination.546 Accordingly, we

believe our technical test, with its seven

indicators, will permit reasoned factual

determinations in individual cases.

Although we are unable to draw the

bright line for local distribution

facilities that many commenters would

like, we believe it is important to make

two clarifications regarding local

distribution in the context of retail

wheeling. First, even when our

technical test for local distribution

facilities identifies no local distribution

facilities for a specific transaction, we

believe that states have authority over

the service of delivering electric energy

to end users. Second, through their

jurisdiction over retail delivery services,

states have authority not only to assess

stranded costs but also to assess charges

for stranded benefits, such as lowincome assistance and demand-side

management. Because their authority is

over services, not just the facilities,

states can assign stranded costs and

benefits based on usage (kWh), demand

(kW), or any combination or method

they find appropriate. They do not have

to assign them to specific facilities.547

Thus, while we believe in most cases

there will be identifiable local

distribution facilities subject to state

jurisdiction, we also believe that even

where there are no identifiable local

distribution facilities, states

nevertheless have jurisdiction in all

circumstances over the service of

delivering energy to end users. Under

this interpretation of state/federal

jurisdiction, customers have no

incentive to structure a purchase so as

to avoid using identifiable local

distribution facilities in order to bypass

state jurisdiction and thus avoid being

assessed charges for stranded costs and

benefits.

Based on concerns raised by state

commissions as well as some utilities,

we have further determined that it is

appropriate to provide deference to state

commission recommendations regarding

certain transmission/local distribution

matters that arise when retail wheeling

occurs. We also believe it is important

to develop mechanisms to avoid

regulatory conflict and to help provide

certainty to utilities as to which

regulator has jurisdiction over which

facilities. These are discussed below.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21627

548 In order to give such deference, we expect

state regulators to specifically evaluate the seven

indicators and any other relevant facts and to make

recommendations consistent with the essential

elements of the Rule.

549This should also alleviate some concerns about

the potential for costs not being accounted for if the

Commission and a state commission use different

methods of allocating costs.

550As discussed above, even if there were

instances where no local distribution facilities are

used, we believe states have authority over the

service of delivering electric energy to end users.

551 I.e., the tariff would be different from the tariff

that applies to wholesale customers. Such tariff

would still be filed with the Commission under

FPA section 205.

552 In applying the principles of the Final Rule to

retail transmission tariffs, the Commission clearly

cannot order retail wheeling directly to an ultimate

consumer. See FPA section 212(h).

Determining where to draw the

jurisdictional line for facilities used in

unbundled retail wheeling transactions

will involve case-specific

determinations that evaluate the seven

local distribution indicators that we are

adopting. We believe that the

Commission should take advantage of

state regulatory authorities’ knowledge

and expertise concerning the facilities of

the utilities that they regulate.

Therefore, in instances of unbundled

retail wheeling that occurs as a result of

a state retail access program, we will

defer to recommendations by state

regulatory authorities concerning where

to draw the jurisdictional line under the

Commission’s technical test for local

distribution facilities, and how to

allocate costs for such facilities to be

included in rates, provided that such

recommendations are consistent with

the essential elements of the Final

Rule.548 Moreover, we recognize that in

some cases the Commission’s seven

technical factors may not be fully

dispositive and that states may find

other technical factors that may be

relevant. We will consider jurisdictional

recommendations by states that take

into account other technical factors that

the state believes are appropriate in

light of historical uses of particular

facilities.

Some commenters have asked the

Commission to provide a forum to

prevent or resolve disputes over the

correct classification of facilities as

transmission or local distribution. As a

means of facilitating jurisdictional linedrawing, we will entertain proposals by

public utilities, filed under section 205

of the FPA, containing classifications

and/or cost allocations for transmission

and local distribution facilities.

However, as a prerequisite to filing

transmission/local distribution facility

classifications and/or cost allocations

with the Commission, utilities must

consult with their state regulatory

authorities. If the utility’s classifications

and/or cost allocations are supported by

the state regulatory authorities and are

consistent with the principles

established in the Final Rule, the

Commission will defer to such

classifications and/or cost allocations.549

We encourage public utilities and their

state regulatory authorities to attempt to

agree to utility-specific classifications

and allocations that the utility may file

at the Commission.

A number of commenters have asked

the Commission to defer to state

commission recommendations or

decisions regarding rates, terms and

conditions of unbundled retail

transmission in interstate commerce by

public utilities. Some have suggested

that we set broad guidelines for such

rates, terms, and conditions, and then

allow states to actually implement the

guidelines. While the Commission

cannot simply turn over its jurisdiction

for the states to implement, we

understand the concerns raised by many

state regulators and believe that

deference to state commissions with

regard to rates, terms, and conditions

may be appropriate in some

circumstances, as discussed below.

As we determined in the NOPR, when

unbundled retail wheeling in interstate

commerce occurs, the transaction has

two components for jurisdictional

purposes—a transmission component

and a local distribution component. The

Commission has jurisdiction over

facilities used for the transmission

component of the transaction, and the

state has jurisdiction over facilities used

for the local distribution component.550

Thus, the rates, terms and conditions of

unbundled retail transmission by a

public utility must be filed at the

Commission. When this occurs, we will

generally expect unbundled retail

wheeling customers to take service

under the same FERC tariff that applies

to wholesale customers. However, if the

unbundled retail wheeling occurs as

part of a state retail access program, it

may be appropriate to have a separate

retail transmission tariff 551 to

accommodate the design and special

needs of such programs. In such

situations, the Commission will defer to

state requests for variations from the

FERC wholesale tariff to meet these

local concerns, so long as the separate

retail tariff is consistent with the

Commission’s open access policies and

comparability principles reflected in the

tariff prescribed by this Final Rule. In

addition, rates must be consistent with

our Transmission Pricing Policy

Statement, and the guidance herein

concerning ancillary services.552

A final jurisdictional issue raised in

the Open Access NOPR concerns buysell transactions. We remain concerned,

just as we were with buy-sell

arrangements in the gas industry, that

buy-sell arrangements can be used by

parties to obfuscate the true transactions

taking place and thereby allow parties to

circumvent Commission regulation of

transmission in interstate commerce.

Thus, we reaffirm our conclusion that

we have jurisdiction over the interstate

transmission component of transactions

in which an end user arranges for the

purchase of generation from a thirdparty. However, we recognize that there

is a wide range of programs and

transactions that might or might not fall

within this category. We will address

these on a case-by-case basis.

In summary, the Commission

reaffirms and clarifies its prior

jurisdictional conclusions and tests for

determining the demarcation between

federal and state jurisdiction over

transmission in interstate commerce and

local distribution. We have attempted to

address these issues in a way that

provides for flexibility and recognition

of legitimate state concerns. With regard

to retail services, we recognize the

states’ concerns that the unbundling of

retail transactions would result in

changes from what historically has been

regulated by the states (principally, the

rates of transmission assets previously

included in retail rate base). However,

the decision to provide unbundled retail

wheeling is not the Commission’s to

make because we have no authority to

order transmission directly to an

ultimate consumer. In addition, even if

a retail access program occurs, we do

not believe the unbundling of retail

transactions will radically change

fundamental state authorities, including

authority to regulate the vast majority of

generation asset costs, the siting and

maintenance of generation facilities and

transmission lines, and decisions

regarding retail service territories.

Further, the Commission intends to be

respectful of state objectives so long as

they do not balkanize interstate

transmission of power or conflict with

our interstate open access policies. As

the electric industry and state regulatory

authorities continue to develop new

competitive market structures and

consider retail wheeling programs, we

believe that the tests and mechanisms

we have provided in this Rule will

accommodate both Federal and state

interests and will help provide

jurisdictional certainty to market

participants.
21628 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

553FERC Stats. & Regs. ¶ 32,514 at 33,095.

554The Supplemental Stranded Cost NOPR

described such an obligation as explicit at retail and

arguably implicit at wholesale. FERC Stats. & Regs.

¶ 32,514 at 33,101.

555 Id. at 33,095–96, 33,101.

556See, e.g., EEI, Atlantic City, Arizona, Carolina

P&L, Centerior, Central Hudson, Detroit Edison,

Duke, Duquesne, Entergy, Florida Power Corp, El

Paso, Houston, NIPSCO, NU, Oklahoma G&E, Otter

Tail, PG&E, Puget, Southern, San Diego G&E,

SCE&G, SoCal Edison, Montana, Montana-Dakota

Utilities, NSP, Utilities For Improved Transition,

NC Com, PA Com, Electric Consumers Alliance,

American National Power, NE Public Power

District, MEAG, OH Coops, Seattle, NY Energy

Buyers, SBA, TVA, Utility Workers Union, Big

Rivers EC, Central EC, Citizens Lehman, NGSA,

AGA, Montaup, NIEP.

557See, e.g., EEI, Coalition for Economic

Competition, EGA, CINergy, Electric Consumers

Alliance, Atlantic City, Com Ed, Consumers Power,

Dayton P&L, Dominion, Duke, El Paso, NEPCO,

NIMO, NIPSCO, Ohio Edison, Florida Power Corp,

PECO, Pennsylvania P&L, PSNM, Public Service Co

of CO, Southern, SCE&G, VEPCO, Texas Utilities,

DOE, CA Energy Com, CO Com, PA Com, NE Public

Power District, SMUD, Brazos, Sunflower, PJM,

Utility Workers Union, Utility Investors Analysts,

Nuclear Energy Institute, SoCal Gas, AGA, Utility

Shareholders, LPPC. Although DOD agrees that

addressing stranded costs is a critical part of the

transition to a more competitive industry, it submits

that there is nothing in the Open Access NOPR that

should affect the treatment of stranded costs

because the Open Access NOPR would not change

the contracts that govern existing wholesale

transactions. It argues that the Commission will

have ample opportunity to decide these matters

before the present wholesale long-term contracts

expire.

558E.g., Utilities For Improved Transition, PECO,

Utility Workers Union, Dayton P&L.

559Utility Investors Analysts, Utility

Shareholders.

560See, e.g., EEI, SCE&G, Montana, Com Ed.

561E.g., TAPS, IN Industrials, Air Liquide, Texas

Industrials, Detroit Edison Customers, AMP-Ohio.

562E.g., TDU Systems, Competitive Enterprise.

563See, e.g., Missouri Joint Commission, Omaha

PPD, American Forest & Paper, TAPS, AMP-Ohio,

Kansas Commission, VA Com, Nucor, Torco,

IPALCO, DE Muni, Municipal Energy Agency

Nebraska, Air Liquide, Arkansas Cities, Detroit

Edison Customers, Cleveland, Texas-New Mexico,

Blue Ridge, Suffolk County, NM Industrials, PA

Munis, Caparo, ABATE, NRRI, Building Owners,

Alma, WEPCO, Total Petroleum. SC Public Service

Authority asserts that the Commission has not

adequately addressed the anticompetitive potential

of exit fees and the potential shifting of losses from

high-cost to low-cost producers. It says that the

Commission should renotice any further proposal

that it develops to permit a reasoned analysis of

anticompetitive concerns.

564E.g., TAPS, AMP-Ohio, IPALCO, Suffolk

County, Competitive Enterprise, NY Energy Buyers,

Supervised Housing, Central Illinois Light, WP&L,

SC Public Service Authority, KS Com.

565E.g., Alma, IPALCO, Suffolk County, CO

Consumers Counsel, Arkansas Cities, Central

Illinois Light, NY AG, NASUCA, VA Com, NY

Energy Buyers, UT Industrials, NM Industrials, NJ

Ratepayer Advocate, WEPCO, IN Industrials,

ABATE, AZ Com.

566E.g., ELCON, TDU Systems, Texas-New

Mexico, Central Illinois Light.

567However, Utilities for Improved Transition

refers to a report by Moody’s Investor Service

estimating that the stranded costs of the Nation’s

114 largest electric utilities under open access

transmission will be $135 billion in the next ten

years (13 to 14 times greater than the costs stranded

by the introduction of open access transportation of

J. Stranded Costs

1. Justification for Allowing Recovery of

Stranded Costs

In the Supplemental Stranded Cost

NOPR, the Commission noted that the

Open Access Rule would give a utility’s

historical wholesale customers greatly

enhanced opportunities to reach new

suppliers.553 This would affect the way

in which utilities have recovered costs

under the traditional regulatory system

that, on the one hand, imposed an

obligation to serve,554 and, on the other

hand, permitted recovery of all

prudently incurred costs. We noted that

if customers leave their utilities’

generation systems without paying a

share of these costs, the costs will

become stranded unless they can be

recovered from other customers. The

Commission stated in the NOPR that we

must address the costs of the transition

to a competitive industry by allowing

utilities to recover their legitimate,

prudent and verifiable stranded costs

simultaneously with any final rule we

adopt requiring open access

transmission.555

Comments

Virtually all of the investor-owned

utility commenters as well as

commenters representing state

commissions and other constituencies

support the NOPR’s premise that

stranded costs can be created when a

customer switches suppliers. They

endorse the proposal to allow the

recovery of legitimate and verifiable

stranded costs.556 Numerous

commenters also support the

Commission’s proposal to link stranded

cost recovery with open access tariffs.

These commenters agree that the

recovery of stranded costs is critical to

the successful transition of the industry

to an open transmission access,

competitive industry.557 Commenters

such as EEI and NU submit that open

access and stranded cost recovery

should be implemented simultaneously;

that unbundled transmission service

should not be required until a stranded

cost recovery mechanism is in place.

Some commenters propose that if the

full recovery of stranded costs is

disallowed as a result of rehearing or

judicial review, utilities that have filed

open access transmission tariffs should

be permitted to withdraw them, or the

Commission should otherwise

reconsider its rule on open access

transmission in light of such a

reversal.558

Commenters representing the

financial community reiterate their

strong support for the full recovery of

stranded costs, noting that the prospect

of not recovering stranded costs could

erode a utility’s ability to attract capital

which, in turn, could impede the longterm goal of achieving competitive

wholesale markets.559 Several

commenters also argue that stranded

cost recovery is economically efficient

and is necessary to ensure parity among

competitors and to avoid uneconomic

bypass.560

The commenters that oppose allowing

utilities to recover legitimate and

verifiable stranded costs repeat many of

the arguments that were raised in

response to the initial Stranded Cost

NOPR. For example, a number of

commenters argue that the risk that a

utility could lose customers (and

thereby incur stranded costs) is not a

new phenomenon created by regulatory

and statutory initiatives that utilities

could not have anticipated.561 Some

commenters argue that there was never

an implied obligation to serve at

wholesale.562 According to TDU

Systems, monopoly power, not

regulatory obligation, has kept

wholesale customers captive over the

years.

Other commenters argue that allowing

the recovery of stranded costs would

make it uneconomic for customers to

seek alternative sources of power and

that the prospect of liability for and

protracted litigation over stranded cost

claims would create paralyzing

uncertainty for customers, uncertainty

that may dissuade them from taking

advantage of new opportunities in the

wholesale power market.563 Some

commenters also argue that stranded

cost recovery would be a disincentive to

efficient operation by affording the

greatest protection to utilities that made

the worst investment decisions.564

Commenters also argue that the scope

of the proposed rule is overbroad; that

stranded cost recovery should be

allowed, if at all, on a case-by-case

basis; that there should be no

presumption that every utility will

experience stranded costs; and that

utilities should not be allowed to

recover 100 percent of prudently

incurred stranded costs.565

Several commenters suggest that there

is no factual basis for the stranded cost

rule, citing a lack of evidence of a

wholesale stranded cost problem.566

TDU Systems refers to a Resource Data

International study that shows that, of

$114 billion in potential investor-owned

utility stranded investment, only $10.4

billion is associated with wholesale

transactions.567 Others submit that the
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21629

natural gas). It notes that this estimate covers costs

stranded by transmission in interstate commerce of

both wholesale and retail power, and submits that

both types of costs are relevant to this proceeding

because of the Commission’s jurisdiction over the

transmission rates for wheeling to both wholesale

and retail customers.

568E.g., Central Illinois Light, Utility Workers

Union, Alcoa.

569See FERC Stats. & Regs. ¶ 32,514 at 33,105.

570According to NRRI, the Commission did not

‘‘berate’’ electric utility management to sign

uneconomic contracts in the manner that NRRI

contends the Commission and Congress ‘‘berated’’

pipeline management. NRRI Initial Comments at 6.

NRRI also objects that the proposed rule is a

departure from what occurred in other deregulated

industries (where no stranded cost recovery was

allowed) and that the Commission should provide

a fuller explanation as to why it believes allowing

utilities full recovery of legitimate and verifiable

stranded costs is the correct course of action.

571E.g., Legal Environmental Assistance,

Conservation Law Foundation.

572E.g., TDU Systems.

573E.g., EGA, LG&E. EGA and LG&E further argue

that if a utility is able to abrogate a QF contract, a

QF should be entitled to recover its costs based

upon the same equities of reliance upon

governmental approvals, changed regulatory

regimes, and reasonable expectation.

574 VT DPS argues that under Order No. 636, the

Commission allowed recovery of costs that would

be rendered ‘‘unrecoverable’’ because the costs

would not be incurred to provide transportation

service and because there would be no wholesale

load from which to recover the costs. It suggests

that when a utility loses wholesale load or a

municipality establishes a new distribution system,

the utility’s costs are not necessarily rendered

unrecoverable.

575E.g., PA Munis, Missouri Joint Commission,

TAPS, Municipal Energy Agency Nebraska.

576But see FPA section 212(a), 16 U.S.C. 824k(a).

577RUS objects that, at the same time, an RUSfinanced cooperative that is a transmitting utility

would be required to provide reciprocal open

access to its public utility supplier, which is also

its customer and its competitor.

578 761 F.2d 768 (D.C. Cir. 1985).

579E.g., VA Com, DE Muni, LG&E, Mountain

States Petroleum Assoc.

580ELCON July 25, 1995 Comments at 6.

581Hereafter referred to collectively as the ‘‘new

open access’’ or ‘‘open access transmission.’’

582FERC Stats. & Regs. ¶ 32,514 at 33,101–02.

583Contrary to NRRI’s claim, and as explained in

the NOPR (see, e.g., FERC Stats. & Regs. ¶ 32,514

at 33,063–68), the electric industry’s transition to a

more competitive market is driven in large part by

statutory and regulatory changes beyond the

utilities’ control.

Commission should obtain more current

data concerning the magnitude of

potential stranded cost recovery before

issuing the final rule.568 In reference to

the statement in the Supplemental

NOPR that the Commission will

continue to gather information on the

magnitude of potential stranded

costs,569 DE Muni states that the

Commission must commit to making

public all the data it obtains so that all

can evaluate the impact of the recovery

of stranded costs on an ongoing basis.

NRRI submits that the Commission

has drawn the wrong conclusion from

its natural gas industry experience.

According to NRRI, pipelines were

‘‘caught in an unusual transition’’ by

changes caused by Congress and the

Commission. In the case of the electric

industry, NRRI submits that although

there are uneconomic wholesale power

contracts, the Commission is not

responsible for this situation.570

Several commenters suggest that the

Commission condition a utility’s ability

to recover stranded costs upon the

utility agreeing to take certain actions

(such as reducing environmental effects

571 or ensuring the payment of costs that

are stranded if the utility commences

direct service to an end-use customer

that was previously a wholesale

customer of a transmission dependent

utility 572 ), or agreeing to refrain from

certain actions (such as seeking

unilaterally to terminate or modify IPP

contracts).573 CCEM proposes that open

access, conversion rights, and

divestiture should each be a

precondition to a utility’s eligibility for

any stranded cost recovery. VT DPS

submits that, if the Commission adopts

a stranded cost rule, it should limit

utility stranded cost claims to those

cases where the utility can demonstrate

that its costs have been rendered

unrecoverable as a direct result of the

final rule.574

A number of commenters object that

the proposed rule contains no

provisions for non-transmission-owning

utilities to collect stranded costs.575

Illinois Municipal Electric Agency asks

the Commission to consider providing a

forum for municipals to recover

stranded costs from their customers

under the same guidelines as investorowned utilities. Recognizing that the

FPA gives the Commission no general

jurisdiction over municipalities for

purposes of rate regulation,576 Illinois

Municipal Electric Agency argues that

the FPA nevertheless does not prevent

the Commission from providing a forum

for municipalities that may experience

stranded costs as a result of new federal

regulations. NE Public Power District,

RUS, and rural electric cooperative

commenters object that the NOPR gives

public utilities a greater chance than

other transmitting utilities to recover

stranded costs from departing customers

by offering public utilities two avenues

of recovery (an exit fee under a power

sales contract or a transmission

surcharge) but offering other

transmitting utilities only one avenue (a

transmission surcharge).577

PA Munis objects that the

Commission’s proposal to impose

stranded costs only on wholesale

requirements customers (and not on

other wholesale customers) is unduly

discriminatory and counter to the goals

of the Open Access NOPR. It submits

that the Commission’s proposal, by

subjecting a wholesale requirements

customer to increased transmission rates

for stranded costs not levied on other

wholesale customers, is

indistinguishable in substance from the

pre-Order 436 plan held to be

discriminatory in Maryland People’s

Counsel v. FERC.578

ELCON and others 579 urge the

Commission to clarify that stranded

costs do not arise when a customer

leaves a system because its plant

becomes uneconomic or the customer

wishes to co-generate or self-generate.

They note that ‘‘[t]hese alternatives have

always existed and do not arise from

new opportunities for wholesale and

retail wheeling.’’ 580

Commission Conclusion

We reaffirm our preliminary

determination that the recovery of

legitimate, prudent and verifiable

stranded costs should be allowed.

Having considered the arguments raised

by the commenters that oppose stranded

cost recovery, we continue to believe

that utilities that entered into contracts

to make wholesale requirements sales

under an entirely different regulatory

regime should have an opportunity to

recover stranded costs that occur as a

result of customers leaving the utilities’

generation systems through

Commission-jurisdictional open access

tariffs or FPA section 211 orders,581 in

order to reach other power suppliers. As

we indicated in the Supplemental

Stranded Cost NOPR, we do not believe

that utilities that made large capital

expenditures or long-term contractual

commitments to buy power years ago

should now be held responsible for

failing to foresee the actions this

Commission would take to alter the use

of their transmission systems in

response to the fundamental changes

that are taking place in the industry.582

We will not ignore the effects of recent

significant statutory and regulatory

changes on the past investment

decisions of utilities.583 While, as some

commenters point out, there has always

been some risk that a utility would lose

a particular customer, in the past that

risk was smaller. It was not

unreasonable for the utility to plan to

continue serving the needs of its

wholesale requirements customers and

retail customers, and for those

customers to expect the utility to plan

to meet future customer needs. With the

new open access, the risk of losing a
21630 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

584As a result, the opportunity for wholesale

stranded cost recovery under this Rule is limited to

utilities that provided sales of generation and

transmission under wholesale requirements

contracts, and to utilities that provided service to

retail customers that convert to wholesale customer

status, and that face the potential inability to

recover costs when their customers are able to reach

new suppliers through open access transmission.

585 15 U.S.C. 3301 et seq.

586AGD, 824 F.2d at 1021.

587 Id. at 1027.

588Pipeline Service Obligations and Revisions to

Regulations Governing Self-Implementing

Transportation Under Part 284 of the Commission’s

Regulations; and Regulation of Natural Gas

Pipelines After Partial Wellhead Decontrol, Order

No. 636, 57 FR 13267 (April 16, 1992), FERC Stats.

& Regs. ¶ 30,939 (1992), order on reh’g, Order No.

636–A, 57 FR 36128 (August 12, 1992), FERC Stats.

& Regs. ¶ 30,950 (1992); order on reh’g, Order No.

636–B, 57 FR 57911 (December 8, 1992), 61 FERC

¶ 61,272 (1993), reh’g denied, 62 FERC ¶ 61,007

(1993), appeal pending United Distribution

Companies, et al., v. FERC, No. 92–1485, et al.,

(D.C. Cir. Oral Argument Held Feb. 21, 1996).

589See, e.g., Public Utilities Commission of the

State of California v. FERC, 988 F.2d 154, 166 (D.C.

Cir. 1993) (‘‘FERC, with the backing of this court,

has been at pains to permit pipelines to recover

these (take-or-pay) costs, which have accumulated

less through mismanagement or miscalculation by

the pipelines than through an otherwise beneficial

transition to competitive gas markets.’’); Western

Resources, Inc. v. FERC, 72 F.3d 147 (D.C. Cir.

1995).

customer is radically increased. If a

former wholesale requirements

customer or a former retail customer

uses the new open access to reach a new

supplier, we believe that the utility is

entitled to recover legitimate, prudent

and verifiable costs that it incurred

under the prior regulatory regime to

serve that customer.584

We learned from our experience with

natural gas that, as both a legal and a

policy matter, we cannot ignore these

costs. During the 1980s and early 1990s,

the Commission undertook a series of

actions that contributed to the impetus

for restructuring of the gas pipeline

industry. The introduction of

competitive forces in the natural gas

supply market as a result of the Natural

Gas Policy Act of 1978 585 and the

subsequent restructuring of the natural

gas industry left many pipelines holding

uneconomic take-or-pay contracts with

gas producers. When the Commission

initially declined to take direct action to

alleviate that burden, the U.S. Court of

Appeals for the District of Columbia

Circuit faulted the Commission for

failing to do so.586 The court noted that

pipelines were ‘‘caught in an unusual

transition’’ as a result of regulatory

changes beyond their control.587

As we stated in the Supplemental

NOPR, the court’s reasoning in the gas

context applies to the current move to

a competitive bulk power industry.

Indeed, because the Commission failed

to deal with the take-or-pay situation in

the gas context, the court invalidated

the Commission’s first open access rule

for gas pipelines. Once again, we are

faced with an industry transition in

which there is the possibility that

certain utilities will be left with large

unrecoverable costs or that those costs

will be unfairly shifted to other

(remaining) customers. That is why we

must directly and timely address the

costs of the transition by allowing

utilities to seek recovery of legitimate,

prudent and verifiable stranded costs.

At the same time, however, this Rule

will not insulate a utility from the

normal risks of competition, such as

self-generation, cogeneration, or

industrial plant closure, that do not

arise from the new availability of nondiscriminatory open access

transmission. Any such costs would not

constitute stranded costs for purposes of

this Rule.

We are issuing the Stranded Cost

Final Rule simultaneously with the

Open Access Final Rule because we

believe that the recovery of legitimate,

prudent and verifiable stranded costs is

critical to the successful transition of

the electric industry to a competitive,

open access environment. We believe

that our decision today will be upheld

by the courts. While the D.C. Circuit is

still considering the various appeals of

Order No. 636,588 it has already upheld,

in at least two instances, our ultimate

decision to allow the recovery of costs

stranded in the transition to a

competitive natural gas industry.589 As

a result, we reject the suggestions of

some commenters that a utility’s

obligation to comply with the

provisions of the Open Access Final

Rule should be conditioned upon final

court approval of the Stranded Cost

Final Rule. We also decline otherwise to

condition a utility’s ability to recover its

stranded costs. As described in greater

detail in Section IV.J.8, if a utility can

make the necessary evidentiary

showings, it will be eligible for stranded

cost recovery.

With regard to the magnitude of

potential wholesale stranded costs, as

the Supplemental Stranded Cost NOPR

recognizes, the level may be small

relative to that of retail stranded costs.

Nevertheless, wholesale costs may be

stranded as a result of open access

transmission. Because the significance

of such costs to the utilities that would

face them may be great (and the

prospect of not recovering such costs

could erode utilities’ ability to attract

capital and be very detrimental to a

diverse array of utility shareholders), we

believe that we have a responsibility to

allow for the recovery of such costs.

We disagree with the commenters

who contend that this Rule would

discriminate against certain segments of

the industry, such as non-transmissionowning utilities (who would not be

allowed to collect stranded costs) or

wholesale requirements customers (who

would be subject to stranded cost

charges while other wholesale

customers would not). These

commenters misconstrue the purpose of

this Rule and the nature of the stranded

costs for which this Rule would allow

recovery. This rule is designed to

address a new and specific problem:

The fact that a utility that historically

has supplied bundled generation and

transmission services to a wholesale

requirements customer and incurred

costs to meet reasonably expected

customer demand may experience

stranded costs when its customer is able

to reach a new generation supplier due

to the availability of open access

transmission. This rule proposes a

solution to that problem by allowing the

recovery of legitimate, prudent and

verifiable costs incurred by a utility to

provide service to a wholesale

requirements customer that

subsequently becomes, in whole or in

part, an unbundled wholesale

transmission services customer of the

utility. The opportunity for extracontractual wholesale stranded cost

recovery is allowed for only a discrete

set of requirements contracts for which

the utility can demonstrate that it had

a reasonable expectation of continuing

service, as well as for retail-turnedwholesale situations in which the utility

satisfies the necessary evidentiary

criteria. Thus, the fundamental premise

of this rule—namely, that a utility

should have an opportunity to recover

reasonably-incurred costs that arise

because open access use of the utility’s

transmission system enables a

generation customer to shop for

power—would not apply to a nontransmission-owning utility that, by

definition, has no transmission by

which its generation customer can

escape to another supplier.

The same historical relationship

discussed above, including the

expectation of continued service,

justifies imposing the stranded costs

covered by this rule on wholesale

requirements customers only (not on

non-requirements customers that

contract separately for transmission

services to deliver their purchased

power). Requirements customers

historically were long-term customers

who typically did not expect to take

service from other suppliers. Utilities

thus assumed they would continue
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21631

590 28 F.3d 173 (D.C. Cir. 1994) (Cajun).

591FERC Stats. & Regs. ¶ 32,514 at 33,105–06.

592E.g., APPA, ABATE, ELCON, Central Illinois

Light, IL Com, VT DPS.

593See, e.g., ELCON, American Forest & Paper,

MMWEC, Cajun, IL Com, PA Com, VT DPS,

Education, DE Muni, IN Industrials, Texas-New

Mexico, Las Cruces, Blue Ridge, Suffolk County,

Total Petroleum, NM Industrials, PA Munis.

594E.g., Arkansas Cities, PA Munis, NM

Industrials.

595See Cajun, 28 F.3d at 179.

596See, e.g., Suffolk County, Arkansas Cities,

Education.

597E.g., PA Com, NY Com, RUS.

598Cajun, 28 F.3d at 179 (emphasis in original).

599SC Public Service Authority notes this

distinction as well (Initial Comments at 78): ‘‘In

Cajun, the court was not criticizing the recovery of

stranded assets as an abstract matter, but

specifically as an integral part of a set of tariffs

designed to justify market-based rates on the basis

that the open access tariff adequately mitigated

market power despite the provision permitting

recovery of stranded assets.’’ It suggests that if the

Commission decides to allow utilities to recover

stranded costs from departing customers, any utility

recovering such costs should not be allowed to

charge market-based rates.

600See, e.g., EEI, NEPCO, Centerior, Electric

Consumers Alliance, Southern.

601E.g., Omaha PPD, Com Ed, Florida Power

Corp. Com Ed also submits that the argument by the

petitioners in Cajun that ‘‘there really is no such

thing as stranded investment, only a failure to

compete’’ ignored the circumstances under which

the investments were made. It states that electric

utilities did not incur the costs of generation

facilities (and long-term fuel and power supply

contracts) because they were less efficient

competitors, but to satisfy their obligation in a fullyregulated market to provide service to all who

request it.

serving these customers and may have

made significant investments based on

that long-term expectation. In contrast,

utilities did not (and do not today)

generally make investments for shortterm economy-type transactions. Rather,

such transactions were entered into only

when the utility temporarily had

available capacity or energy that could

be provided to the buyer at a price lower

than the buyer’s decremental cost. The

utility was not obligated in any way—

either explicitly or implicitly—to

provide for the needs of nonrequirements customers. Because

coordination transactions were not the

cause of stranded investment decisions,

it would be inappropriate to allocate

such costs to non-requirements

customers.

Further, although some commenters

object that the Rule would give public

utilities a greater opportunity than other

transmitting utilities to recover stranded

costs, our jurisdiction over transmitting

utilities that are not also public utilities

is limited. If the selling utility under an

existing contract is a transmitting utility

that is not also a public utility, its

wholesale requirements contracts are

not subject to this Commission’s

jurisdiction. Thus, we can allow such a

transmitting utility to recover stranded

costs only through Commissionjurisdictional transmission rates under

sections 211 and 212 of the FPA.

Nevertheless, in the context of a specific

section 211 case, we would expect to

apply similar principles to the extent

possible to assure full stranded cost

recovery. We also encourage such

transmitting utilities to negotiate

mutually agreeable stranded cost

provisions with their customers.

2. Cajun Electric Power Cooperative,

Inc. v. FERC590

In the Supplemental Stranded Cost

NOPR, the Commission made a

preliminary finding that the Cajun court

decision does not bar the recovery of

stranded costs as proposed in the NOPR

and set forth our reasoning in support

of that finding.591

Comments

Various commenters contend that the

proposal to permit recovery of stranded

costs at all, or particularly through

transmission rates of departing

customers, fails to address the Cajun

court’s concerns.592 These commenters

repeat many of the same arguments

previously raised in this proceeding,

which we have already addressed. Some

commenters argue that including

generation-based stranded costs in

transmission rates is an anticompetitive

tying arrangement and that Cajun

compels the Commission to abandon

this aspect of its stranded cost proposal

or, at a minimum, to explain how the

chosen method of recovery differs from

that remanded in Cajun.593

Several commenters 594 question

whether the NOPR’s stranded cost

provisions would undermine the

‘‘meaningful’’ access to alternative

suppliers referenced by the Cajun

court.595 For example, Arkansas Cities

asserts that the Commission has failed

to address whether a transmitting utility

retains market power over transmission

even after imposition of an open access

tariff. It contends that this question is

vital to determining whether imposition

of stranded costs would interfere with a

wholesale transmission customer’s

meaningful access to other power

suppliers.

Some commenters also submit that

the proposed procedures for a customer

to obtain an estimate of its stranded cost

liability are inadequate because they do

not ameliorate the uncertainty

confronting the customer, which was a

concern of the court in Cajun. They

suggest that a customer would still face

the prospect of litigation concerning

whether a proposed stranded cost

charge is appropriate.596

Other commenters argue that Cajun

requires a trial-type evidentiary hearing

before stranded costs may be recovered.

They question whether the

Commission’s generic proposals on

open access and the Commission’s

statements about the need to recover

stranded costs are adequate.597 ELCON

references the Cajun court’s statement

that ‘‘if the Commission is wrong at the

outset concerning the possibility of

legitimate stranded investment cost, it is

not fair or reasonable to create such a

mechanism for recovery.’’ 598 ELCON

submits that the factual record does not

demonstrate any significant wholesale

stranded cost problem and, as a result,

a final rule allowing recovery of such

costs would not be ‘‘fair or reasonable.’’

Many other commenters, in contrast,

believe that the NOPR is distinguishable

from the case that was before the court

in Cajun and that the Commission has

fully addressed the Cajun court’s

concerns. According to the Coalition for

Economic Competition, this proceeding

is very different from the Cajun

proceeding because the proposed rule

would not automatically permit utilities

to charge market-based rates. The

Coalition for Economic Competition

states that in the absence of generic

market-based rate authorization, there is

no basis in Cajun for barring the

recovery of stranded investment in

transmission tariffs.599

A number of commenters agree with

the Commission that the Cajun court

was concerned with the need for a more

complete explanation of the basis for

stranded cost recovery and the

mechanism selected for such recovery.

These commenters believe that the

NOPR provides both the evidentiary

record for addressing these concerns on

a generic basis and the opportunity for

all participants to present evidence and

arguments.600

Noting the Cajun court’s concern as to

whether the wholesale customer in that

case had ‘‘meaningful’’ access to

alternative suppliers, a number of

commenters agree that the Commission,

through the open access provisions of

the NOPR, is in fact providing

wholesale customers meaningful,

reasonable access to alternative

suppliers.601

As evidence that the Cajun court was

concerned with inadequate explanation

and procedures and did not find that

stranded costs could never be justified,

several commenters point out that the

Cajun court did not mention the D.C.

Circuit’s landmark decision in AGD,

which strongly supports stranded cost
21632 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

602See, e.g., Com Ed, Coalition for Economic

Competition, NYSEG, Entergy.

603See, e.g., K N Energy, Inc., 968 F.2d 1295 at

1301 (D.C. Cir. 1992), Elizabethtown Gas Co. v.

FERC, 10 F.3d 866, 874 (D.C. Cir. 1993).

604E.g., EEI, Com Ed, Consumers Power, SoCal

Edison, Salt River, Entergy.

605See State of Illinois ex rel. Burris v. Panhandle

Eastern Pipe Line Co., 935 F.2d 1469, 1483 (7th Cir.

1991), cert. denied, 502 U.S. 1094 (1992) (pipeline’s

refusal to transport gas that an LDC customer

purchased from another supplier was ‘‘genuinely

and reasonably motivated by the need to limit its

potential take-or-pay liability, not by a desire to

maintain its monopoly position by excluding

competition in the sale of natural gas’’); City of

Chanute v. Williams Natural Gas Company, 743 F.

Supp. 1437 (D. Kan.), aff’d, 955 F.2d 641 (7th Cir.

1990) (pipeline’s refusal to transport third-party gas

was motivated by legitimate business concerns,

including desire to prevent take-or-pay liability, not

by an anticompetitive motive).

606 72 F.3d 147 (D.C. Cir. 1995).

607 Id. at 152.

608As we noted in the Supplemental NOPR, the

same court had earlier instructed the Commission

in the AGD case that the Commission must consider

the transition costs borne by regulated utilities

when the Commission changes the regulatory rules

of the game. FERC Stats. & Regs. ¶ 32,514 at 33,106.

609 Id. at 33,065–67.

610 In contrast to the tariff under review in Cajun,

the Final Rule pro forma tariff provides that

available transmission capability (ATC) must be

calculated and posted on the transmission

provider’s Open Access Same-time Information

System (OASIS) pursuant to new Part 37—OPEN

ACCESS SAME-TIME INFORMATION SYSTEM

AND STANDARDS OF CONDUCT FOR PUBLIC

UTILITIES of the Commission’s regulations. Section

37.6 provides in pertinent part that along with

posting its ATC on its OASIS node, a public utility

must make all data used in the calculation publicly

available, on request. Section 37.4 provides that

employees of the public utility and any affiliate that

are engaged in merchant functions are prohibited

from having preferential access to any transmissionrelated information. Additionally, the regulations

provide auditing and monitoring procedures to

safeguard against discriminatory practices.

611 In contrast to the tariff under review in Cajun,

the Final Rule pro forma tariff requires the

provision of point-to-point and network service.

612 In contrast to the tariff under review in Cajun,

the Final Rule pro forma tariff requires reasonable

time limits for responses to transmission requests.

Specifically, Section 17.5 provides that a

transmission provider must respond to a request for

firm service as soon as practicable, but not later

than thirty days after the date of receipt of a

completed application.

613 In contrast to the tariff under review in Cajun,

the Final Rule pro forma tariff does not allow firm

transmission service to be cancelled after the

service has been commenced. However, Section 7.3

of the Final Rule pro forma tariff does provide that

in the event of a customer default, the transmission

provider may, in accordance with Commission

policy, file and initiate a proceeding with the

Commission to terminate service.

614Cajun, 28 F.3d at 179–80.

recovery.602 For example, Coalition for

Economic Competition suggests that

construing Cajun to hold that stranded

cost recovery is always anticompetitive

would be at odds with AGD and other

decisions that have upheld the

Commission’s policy of allowing

recovery of the costs of the transition to

competitive markets.603

Numerous commenters also support

the Commission’s conclusion that

stranded cost recovery through

transmission rates is not a tying

arrangement.604 Among other things,

these commenters argue that a tying

claim requires that the defendant force

the sale of a separate product with the

sale of a product over which it has

market power, and that here there is no

second product being tied to

transmission. Several commenters also

suggest that, in any event, stranded cost

recovery as proposed in the NOPR

would be considered a legitimate

business justification under the antitrust

laws.605 Com Ed explains that the

Commission, as part of its effort to

enhance competition in generation by

opening up the transmission network, is

avoiding placing on utilities the entire

burden of the stranded costs resulting

from their past regulatory obligations; it

is not permitting utilities to maintain a

monopoly of power sales.

Commission Conclusion

We reaffirm that we do not interpret

the Cajun court decision as barring the

recovery of stranded costs. The court in

that case did not bar stranded cost

recovery, as some commenters suggest;

it instead found that the Commission

had not provided adequate proceedings

and had not fully explained its decision.

The Commission had failed to hold an

evidentiary hearing concerning whether

the inclusion of a stranded cost recovery

provision in a particular utility’s

transmission tariff, along with other

provisions in the tariff, resulted in the

adequate mitigation of Entergy’s market

power so as to justify market-based

rates. The court also found that the

Commission had failed to explain

adequately its approval of the stranded

cost provision, among other provisions.

In contrast, as discussed below, we have

addressed in this consolidated

proceeding (the Stranded Cost NOPR,

the Supplemental Stranded Cost NOPR,

the Open Access NOPR, and the Open

Access/Stranded Cost Final Rule) all of

the Cajun court’s concerns.

Our interpretation of Cajun is

bolstered by a recent opinion of the

Court of Appeals for the D.C. Circuit

(the same circuit that decided Cajun)

that confirms the validity of

Commission imposed stranded cost

recovery mechanisms in the transition

to competitive markets. In Western

Resources, Inc. v. FERC,606 the court

affirmed the Commission’s decision to

allow the recovery of costs stranded in

the transition of the natural gas industry

to a competitive market.607 We believe

that, by this decision, the court has

again affirmed the Commission’s ability

to allow stranded cost recovery, as long

as we follow adequate procedures and

explain our decision.608

We are providing in this proceeding

the evidentiary record to support our

decision to allow the recovery of

legitimate, prudent and verifiable

stranded costs on a generic basis. We

also are ensuring the ‘‘meaningful’’

access to alternative suppliers that was

identified as a concern of the Cajun

court. The Open Access Final Rule is

designed to attack one essential element

of market power—namely, control over

transmission access. The standard we

are adopting for transmission service is

far stricter than the standard we used at

the time Cajun was decided; we now

require non-discriminatory open access

transmission, as well as a code of

conduct and non-discriminatory sharing

of transmission information (OASIS).

The collective effect of these actions is

that public utilities that own, control or

operate interstate transmission facilities

will not be able to favor their own

generation and will have to compete on

an equal basis with other suppliers.609

All public utilities that own, control or

operate facilities used for transmitting

electric energy in interstate commerce

will have tariffs on file that offer to any

eligible customer any transmission

services that the public utility could

provide to itself, and under comparable

terms and conditions.

We note that the Cajun court

identified several provisions in

Entergy’s proposed tariff as potentially

restraining competition: Entergy’s

retention of sole discretion to determine

the amount of transmission capability

available for its competitors’ use; 610 the

point-to-point service limitation; 611 the

failure to impose reasonable time limits

on Entergy’s response to requests for

transmission service; 612 and Entergy’s

reservation of the right to cancel service

in certain instances,613 even where a

customer had paid for transmission

system modifications.614 These types of

provisions, which have the potential to

restrain competition, will not be

allowed under the Open Access Rule.

On the contrary, the Final Rule pro

forma tariff contains terms and

conditions to ensure the provision of

non-discriminatory transmission

service. In addition, the requirements

that a public utility take service under

its own tariff, adopt a nondiscriminatory transmission information

network, and separate power marketing

and transmission functions further

ensure non-discrimination and remove

constraints to fair competition. Thus,

the nondiscriminatory open access
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21633

615Notably, the court stated: ‘‘This is, in essence,

a tying arrangement, (citation omitted), and it might

be fine if the purpose of the arrangement were not

to cabin Entergy’s market power.’’ Id. at 177–78

(emphasis added).

616FERC Stats. & Regs. ¶32,514 at 33,108.

617See, e.g., EEI, Atlantic City, Arizona, Carolina

P&L, Centerior, Com Ed, Duke, HP&L, Duquesne,

Florida Power Corp, Omaha PPD, Alcoa, AEC &

SMEPA, BG&E, Central Electric, Detroit Edison, El

Paso, Montana-Dakota Utilities, Ohio Edison, PECO,

PSNM, Southern, Sierra, SoCal Edison, Tucson

Power, Utilities For Improved Transition, Cajun,

NRECA, EGA, Electric Consumers Alliance, FL

Com, PA Com, Knoxville, Salt River, KY Com, ND

Com, California DWR, LA DWP, TVA, Utility

Investors Analysts, Texas Utilities, LG&E, Utility

Shareholders.

618E.g., NC Com, UT Com, NJ Ratepayer

Advocate.

619E.g., SCE&G, Com Ed, Ky Com, NC Com.

SCE&G states that the Commission misinterpreted

its previous comments by suggesting in the

Supplemental NOPR that SCE&G believed

shareholders should bear part of the costs.

620E.g., Texas Utilities, DOJ.

transmission that is the hallmark of this

Rule is designed to ensure meaningful

access to alternative suppliers and goes

far beyond that which was offered in the

transmission tariff that was under

review in Cajun.

We also have addressed the Cajun

court’s concern over the method of

recovery. In that case, Entergy proposed

to include a charge in the departing

customer’s transmission rate to recover

its stranded investment costs. The court

said that this might constitute an

anticompetitive tying arrangement.615

As we explained in the Supplemental

NOPR, the stranded cost recovery

procedure we prescribe in this Rule is

a transitional mechanism only that is

intended to enable utilities to recover

costs prudently incurred under a

different regulatory regime. The purpose

and effect of the stranded cost recovery

mechanism that we approve in this Rule

is to facilitate the transition to

competitive wholesale power markets.

Although we recognized in the

Supplemental NOPR that stranded cost

recovery may delay some of the benefits

of competitive bulk power markets for

some customers, such transition costs

must nevertheless be addressed at an

early stage if we are to fulfill our

regulatory responsibilities in moving to

competitive markets. The stranded cost

recovery mechanism that we direct here

is a necessary step to achieve procompetitive results. In the long term, the

Commission’s rule will result in more

competitive prices and lower rates for

consumers.

The Commission’s approach also is

consistent with the traditional

regulatory concept of cost causation. We

do not believe it is an illegal tying

arrangement to hold a customer

accountable for the consequences of

leaving an incumbent supplier if, under

our rules, the incumbent supplier must

show a reasonable expectation of

continuing service before it can recover

stranded costs from the customer.

Further, in response to the Cajun

court’s concern that the Commission

had failed in that case to explain

adequately its approval of the stranded

cost provision and other provisions, we

have provided in this proceeding a

detailed explanation of the fundamental

industry and regulatory changes that

have given rise to the potential for

stranded costs; the transitional nature of

stranded costs; the critical need to deal

with these costs in order to reach more

competitive wholesale markets; and the

consumer benefits that will result from

competitive generation markets. We also

have provided a detailed explanation of

the terms and conditions in the Final

Rule pro forma tariff that will meet the

non-discriminatory open access service

requirement.

Several commenters (and the Cajun

court) express concern for the need to

provide as much certainty as possible

for departing customers concerning

their potential stranded cost obligation.

Without some certainty, customers may

be unable to shop for alternative

suppliers. In response to these concerns,

we have modified the stranded cost

recovery mechanism to include a

formula for calculating a departing

customer’s potential stranded cost

obligation. As discussed in greater detail

in Section IV.J.9, the revenues lost

formula is designed to provide certainty

for departing customers and to create

incentives for the parties to address

stranded cost claims between

themselves without resort to litigation.

We conclude that we have fully

explained our decision to allow the

recovery of legitimate, prudent and

verifiable costs that are stranded in the

transition to competitive wholesale bulk

power markets. We also have provided

ample opportunity for all concerned to

present arguments and evidence on the

issue. Further, we have significantly

strengthened our open access

requirements to ensure mitigation of

transmission market power. Thus, we

have fully addressed the concerns of the

Cajun court.

3. Responsibility for Wholesale

Stranded Costs (Whether To Adopt

Direct Assignment to Departing

Customers)

In the Supplemental Stranded Cost

NOPR, the Commission made a

preliminary finding that direct

assignment of stranded costs to the

departing wholesale generation

customer is the appropriate method for

recovery of such costs.616

Comments

Numerous parties representing all

constituencies support direct

assignment of stranded costs to the

departing generation customer.617 These

commenters argue, among other things,

that direct assignment is consistent with

the cost causation principle and

preferable to increasing the delivered

price of electricity to a whole region

through the imposition of a wires

charge, and that recovery of stranded

costs from remaining customers would

not be in the public interest. Several

state commenters seek assurance from

the Commission that native load

customers will be held harmless from

stranded costs resulting from other

customers leaving the system.618 KY

Com submits that the possible results of

a broader assessment of stranded costs,

with the related uncertainty of its

impact on the utilities’ cost of capital,

is more problematic in the long run than

the possibility that the direct

assignment of stranded costs would

deter customers from shopping for

power.

Although TAPS opposes stranded cost

recovery in general, it submits that, if

the Commission decides to allow

recovery, the Commission should

directly assign stranded costs and not

spread them across the board to all

transmission users.

Several commenters also oppose any

allocation of stranded cost liability to

shareholders.619

Some commenters state that direct

assignment of stranded costs sends the

correct pricing signals during the

transition to a competitive regime. For

example, Electric Consumers Alliance

states that a wholesale customer should

be able to obtain power elsewhere, but

that the motive to do so should not be

to escape responsibility for sunk

investments made on its behalf. El Paso

submits that failure to make the

departing generation customer liable for

stranded cost recovery would create a

‘‘first-off’’ incentive; the customers that

leave the system first would not suffer

from higher future rates designed to

recover prudently incurred costs from

the reduced base of remaining

customers.

Some commenters support direct

assignment but oppose recovery of

stranded costs through transmission

rates. These commenters prefer an exit

fee or lump-sum approach that would

reflect cost causation in an unbundled

fashion.620 DOJ maintains that a
21634 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

621 In its reply comments, Utility Working Group

disputes DOJ’s arguments that a transmission adder

is analogous to an excise tax and would distort

competition. It argues that DOJ’s claim of price

distortion ignores the fact that the costs that would

be associated with a transmission adder consist of

a portion of the previous wholesale power price—

the markup above the utility’s marginal cost that

had regulatory approval. Utility Working Group

says that because the utility’s price and its

competitor’s price will contain this same charge for

the utility’s sunk and regulatory costs (the

difference between the utility’s regulated rate and

its incremental cost), they will compete on the basis

of their respective incremental costs. It also suggests

that transmission adders can be designed on a

lump-sum basis so that they are not tied to the

amount of electricity purchased.

622E.g., ELCON, NYMEX, IL Industrials, MissouriKansas Industrials, Philip Morris, Fertilizer

Institute, Coalition on Federal-State Issues.

623Some commenters also oppose the

Commission’s proposal to allow the recovery of

generation-related costs through transmission rates

as being in contravention of cost-causation

principles (e.g., VT DPS) or in violation of section

212(a) of the FPA, which they contend limits cost

recovery to transmission-related costs (e.g., IL

Industrials, Las Cruces).

624E.g., ELCON, IL Industrials, NY Energy Buyers,

TX Industrials, Missouri-Kansas Industrials,

Caparo, IBM, PA Munis, Education. For example,

Caparo submits that business decisions by

incumbent utilities are the cause of stranded costs.

625 In support of this proposition, the VT DPS

cites Transwestern Pipeline Co., 44 FERC ¶61,164

at 61,536 (1988); El Paso Natural Gas Co., 47 FERC

¶61,108 at 61,314 (1989); El Paso Natural Gas Co.,

72 FERC ¶61,083 (1995). It also contends that the

Commission recently treated a notice provision in

an El Paso contract as a conclusive, rather than a

rebuttable, presumption. VT DPS cites other

differences between the Commission’s treatment of

the natural gas and the electric utility industries. It

notes that the Commission has not proposed to

allow existing wholesale electric customers to get

out of their contracts early, as it did in the gas area.

626E.g., ELCON, IN Industrials, Reynolds, Philip

Morris, ABATE, Missouri-Kansas Industrials,

Aluminum.

627See, e.g., American National Power, NIEP,

NSP, SBA, Coalition on Federal-State Issues,

Pennsylvania P&L, Consolidated Natural Gas,

Nordhaus, PA Munis. Consumers Power states that

it does not oppose direct assignment, but asks that

the final rule not preclude utilities from proposing

alternative recovery mechanisms, including those

that assess stranded costs on all transmission

customers as part of the transmission rate. It

suggests that utilities should not be precluded from

showing that there may be countervailing reasons

to assess stranded costs broadly among all

transmission customers (e.g., where the costs

assignable to a particular customer or group of

customers may be so high as to create a dispute as

to the propriety of direct assignment).

628See, e.g., American Forest & Paper, Torco,

Philip Morris, DE Muni, MT Com, IL Com, KS Com,

Fertilizer Institute, Caparo, Las Cruces, IN Com, PA

Munis, San Francisco, NRRI, Competitive

Enterprise, ELCON, IN Industrials, UT Industrials,

NY Energy Buyers, ABATE, CA Energy Co, Caparo,

Education, Reynolds.

629See, e.g., Fertilizer Institute, Caparo, DE Muni,

PA Munis, MT Com, San Francisco, ELCON, IN

Industrials, NY Energy Buyers.

630As used in this Rule, ‘‘exit fee’’ refers to the

charge that will be payable by a departing

generation customer upon the termination of its

requirements contract with a utility (if the utility is

able to demonstrate that it reasonably expected to

continue serving the customer beyond the term of

the contract), whether payable in a lump-sum

payment or an amortization of a lump-sum

payment. (The same charge also can be paid as a

surcharge on the customer’s transmission rate.)

transmission adder is analogous to an

excise tax and that the excise tax

approach would distort pricing signals

and customers’ decisions on the use of

electric power. It submits that the lumpsum approach, on the other hand,

would establish a fixed, sunk liability

that would not depend upon how much

transmission service the departing

customer takes in the future.621

Other commenters oppose direct

assignment as being inconsistent with

wholesale competition.622 They argue

that placing all of the responsibility for

stranded costs on departing generation

customers would discourage customers

from switching to other generation

providers and would thereby inhibit

competition.623 Some commenters also

assert that departing generation

customers are not the sole ‘‘cause’’ of

stranded costs.624 VT DPS contends that

direct assignment cannot be reconciled

with the Commission’s refusal to allow

the imposition of exit fees by gas

pipelines when their wholesale

customers depart.625

Some commenters support spreading

the burden of stranded costs broadly

among departing customers,

shareholders, and remaining wholesale

customers on the basis that it would be

equitable for all industry stakeholders to

share both the benefits and the costs of

the transition to competition.626

Others support spreading the costs to

all customers through, for example, a

meter charge to all utilities (to be passed

on to customers), a one-time charge

across the total market base, an access

fee on the transmission system, or a

component of transmission rates.627

Nordhaus proposes a uniform national

tax on all customers, at a rate that

declines over time in a predetermined

manner. He submits that this approach

would remove ‘‘gaming’’ between

utilities and potential exiters, would

ensure that the stranded costs are not

disproportionately loaded on pricesensitive demanders (that is, exiting

customers), and would gradually

disappear over time in a predictable

fashion, thereby increasing the

predictability of the new market.

PA Munis disputes the Commission’s

assertion in the Supplemental Stranded

Cost NOPR that there is no compelling

reason to assess costs broadly. It argues

that a broad-based recovery mechanism

that distributes uneconomic stranded

costs to all power users would minimize

the competition-inhibiting aspects of the

Commission’s proposed surcharge on

departing generation customers. In a

similar fashion, NSP states that acrossthe-board recovery from all users of the

grid would recognize the societal

benefits to be achieved from the

transition to a competitive bulk power

market and would reflect precedent set

during the move to competition in the

natural gas and telephone industries. It

submits that the cost per service unit

would be lower than exit fees assigned

to particular customers and would

eliminate the need for detailing

stranded cost exposure for each

customer contemplating leaving the

system.

FTC submits that some investments

that now appear as stranded costs may

have been intended to benefit customers

over a wider area than a single utility.

It suggests that national regional

assessment methods could recover

stranded costs undertaken to benefit

these wider groups of customers.

We also received comments

suggesting that less than full recovery of

stranded costs should be allowed. A

number of commenters urge the

Commission to require some

shareholder liability for stranded cost

recovery to give utilities an incentive to

mitigate.628 Several of these commenters

assert that utility shareholders should

be required to pay a portion of any

stranded costs (such as 25–50 percent)

because at least some of the

responsibility for stranded costs lies

with poor business decisions by utility

management.629 Occidental Chemical

proposes that the Commission grant

utilities a ‘‘presumption of prudence’’ in

return for requiring them to absorb a

minimum of 25 percent (up to 50

percent) of stranded costs, citing as

support the Commission’s precedent in

the natural gas industry.

Commission Conclusion

We reaffirm our decision that direct

assignment of stranded costs to the

departing wholesale generation

customer through either an exit fee 630 or

a surcharge on transmission is the

appropriate method for recovery of such

costs. We believe it is appropriate that

the departing generation customer, and

not the remaining generation or

transmission customers (or

shareholders), bear its fair share of the

legitimate and prudent obligations that

the utility undertook on that customer’s

behalf.

In reaching this decision, we have

carefully weighed the arguments

supporting direct assignment of

stranded costs against those supporting

a more broad-based approach, such as

spreading stranded costs to all

transmission users of a utility’s system.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21635

Recognizing that each approach has

advantages and disadvantages, we

conclude that, on balance, direct

assignment is the preferable approach

for both legal and policy reasons.

One of the main reasons to adopt

direct assignment of stranded costs is

that direct assignment is consistent with

the well-established principle of cost

causation, namely, that the party who

has caused a cost to be incurred should

pay it. Direct assignment of stranded

costs to departing generation customers

is particularly appropriate given the

nature of the stranded cost recovery

mechanism contained in this Rule,

which links the incurrence of stranded

costs to the decision of a particular

generation customer to use open access

transmission to leave the utility’s

generation system and shop for power,

and which bases the prospect of

stranded cost recovery on the utility’s

ability to demonstrate that it incurred

costs with the reasonable expectation

that the customer would remain on its

generation system.

A broad-based approach, in contrast,

would violate the cost causation

principle by shifting costs to customers

(such as transmission users of the

utility’s system) that had no

responsibility for stranding the costs in

the first place. In addition, if the

Commission were to adopt a broadbased approach, it would have to

determine whether to base the

transmission surcharge on all users of a

utility’s transmission system on a onetime, up-front estimate of stranded costs

(that is, each utility claiming stranded

costs would make a one-time,

comprehensive determination of

stranded costs for the utility as a whole)

or on an as-realized basis (the surcharge

would be based on actual customer

departures and would be adjusted each

time a customer departs). Each option

would have disadvantages that are not

present in the direct cost causation

approach we are adopting.

For example, a major disadvantage of

an up-front, broad-based transmission

surcharge is that it in effect would

charge customers for costs before the

costs are incurred (i.e., before customers

have even decided to leave the utility’s

generation system) and could charge for

costs that may never be incurred (e.g.,

some customers may decide to stay on

the utility’s system as requirements

customers). The other option, a broadbased transmission surcharge that

would be adjusted as customers leave

the utility’s system, also has

disadvantages. While this option might

recover stranded costs that are closer to

the actual amount incurred by the

utility, it could produce variability in

transmission rates every time stranded

costs from a newly-departed customer

are included in the transmission

surcharge and, in turn, could possibly

hamper efficient power supply choices

and efficient generator location

decisions. These disadvantages are not

present in the direct assignment

approach.

Direct assignment will result in a

more accurate determination of a

utility’s stranded costs than would an

up-front, broad-based transmission

surcharge. This is because the stranded

cost for any customer is finally

determined only if that customer

actually leaves a utility. Moreover, there

is no stranded cost unless the thencurrent market price of power for the

period that the utility reasonably

expected to continue serving the

customer is below the utility’s cost.

Thus, because the circumstances of each

departing customer will be known, the

amount of any stranded cost liability

can be determined with reasonable

accuracy. Further, if a customer does

not leave the utility or leaves at some

future time when the utility’s costs are

competitive, the issue need not be

addressed.

On this basis, the direct assignment

approach is more suited to the recovery

of stranded costs as defined in this Rule

(including the reasonable expectation

standard and open access transmission

causation requirement) than is a broadbased approach. We expect that a utility

would have difficulty estimating in

advance all of its stranded costs for

purposes of an up-front, broad-based

transmission surcharge. In the face of

this uncertainty, the utility’s best

strategy likely would be to try to recover

through the broad-based surcharge as

much of its uneconomic assets as

possible by claiming that all of its

wholesale customers are likely to depart

and to leave large stranded costs. In this

regard, the broad-based approach would

provide an incentive for a utility to try

to recover the costs of all of its

uneconomic assets whether or not they

were prudently incurred. This is in

contrast to what this Rule provides,

which is for recovery of only those

legitimate, prudent and verifiable costs

that were incurred on behalf of a

specific customer based on a reasonable

expectation that the utility would

continue to serve the customer and that

are stranded when the customer departs

the utility’s generation system by using

the utility’s open access transmission.

The direct assignment approach also

can be readily applied to both wholesale

and retail-turned-wholesale departing

customers. It also can be adapted for

retail customers. Further, it works for

costs stranded by a section 211 order

requiring either a public utility, or a

transmitting utility that is not also a

public utility, to provide transmission

service. However, this is not the case for

a broad-based approach, particularly an

up-front, broad-based approach.

Assuming that a principal motivation

for an up-front, broad-based approach

would be to recover all of a utility’s

stranded costs as quickly as possible,

retail-turned-wholesale stranded costs

nevertheless are not susceptible of being

collected on an up-front basis. It is not

possible to make a realistic up-front

estimate of costs stranded by

municipalizations that may occur in the

future. Thus, even if we were to adopt

an up-front, broad-based approach for

recovering costs that are stranded when

wholesale requirements customers use

their former supplier’s transmission

system to reach a new supplier, retailturned-wholesale stranded costs would

have to be identified as they occur and

the stranded cost surcharge on

transmission users adjusted accordingly.

Similarly, the broad-based approach is

not easily adaptable to transmitting

utilities that are not also public utilities.

It is doubtful that, in establishing the

rate for a section 211 applicant, the

Commission could also set transmission

surcharges for customers that were not

section 211 applicants; this is what a

broad-based approach, in effect, would

require us to do.

Direct assignment by means of an exit

fee or a transmission surcharge that is

not dependent on any subsequent power

or transmission purchases by the

customer is also an economically

efficient way to collected stranded costs.

The customer may make a lump-sum

stranded cost payment, amortize the

lump-sum payment, or spread the

payment as a surcharge in addition to its

transmission rate. The total amount of

stranded costs that the directly-assigned

customer ultimately pays would not

depend on how much transmission

service it takes and thus would not

influence the customer’s subsequent

transmission purchase decisions.

With a broad-based surcharge (which

could be demand- or usage-based), on

the other hand, the surcharge for

transmission users would depend on

how much transmission service the

users take. A broad-based approach also

would be inefficient as it would raise

the price of transmission service for all

customers, thereby potentially cutting

off some beneficial power trading that

would otherwise occur for all

unbundled transmission customers. The

surcharge also could convert some

profitable existing power purchase

contracts into unprofitable contracts. In
21636 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

631To counteract this potential disadvantage, we

have provided procedures in this Rule, including a

formula that the utility is to use to calculate a

departing generation customer’s stranded cost

obligation, that allow a customer considering

switching power suppliers to request a stranded

cost determination from the utility at any time

before the expiration of the customer’s wholesale

requirements contract. See Section IV.J.9.

632 In addition, because the customer would

already know its stranded cost transmission

surcharge, it presumably would have some certainty

as to the costs of shopping for power. However, the

stranded cost surcharge in its transmission rates

subsequently may be adjusted upward if the utility

providing transmission becomes eligible to recover

retail-turned-wholesale stranded costs. Also, if the

broad-based stranded cost surcharge is adjusted on

an as-realized basis, the potential departing

generation customer’s surcharge may increase as a

result of other customers leaving the utility’s

system.

633As discussed in Section IV.A.5, we are not

providing for a similar conversion right in this Rule.

634FERC Stats. & Regs. ¶32,514 at 33,108.

addition, it could reduce economy

trading because the surcharge would be

added to the price of economy

transmission. In this manner, a broadbased surcharge would constitute a

cross-subsidy that could distort the

market.

We recognize that direct assignment is

not without its potential drawbacks. For

example, when compared to an upfront, broad-based transmission

surcharge approach, direct assignment

may entail a longer stranded cost

recovery period. The transition period

for stranded cost recovery under a direct

assignment approach would depend on

the length of the remaining terms of the

wholesale requirements contracts for

which this Rule provides an

opportunity for recovery (contracts

executed on or before July 11, 1994 that

do not contain an exit fee or explicit

stranded cost provision).

On the other hand, a broad-based

approach could identify and recover

stranded costs earlier than the direct

assignment approach; recovery of

stranded costs for all of a utility’s

wholesale requirements customers

could begin as soon as the utility’s upfront stranded cost amount for departing

wholesale customers is determined

(through litigation or settlement).

However, this potential advantage of a

broad-based approach (the shorter

transition period) is outweighed by

what we believe to be a serious

infirmity, namely, the possibility that

the broad-based transmission surcharge

could end up including costs that have

not yet been incurred and may never be

incurred.

In addition, another potential

drawback to the direct assignment

approach is that the departing

generation customer may see little or no

savings in the short-term by switching

power suppliers once its stranded cost

exit fee is added to its lower power

price from a new supplier. Direct

assignment may leave the customer

uncertain about the benefits of shopping

for power because of the customer’s

potential stranded cost liability and, in

turn, may bias the customer toward

staying with its existing power

supplier.631

In the case of a broad-based approach,

in contrast, much of the customer’s

direct assignment stranded costs are

spread to others through a transmission

surcharge. As a result, the departing

generation customer’s power cost

savings may more than offset the

customer’s stranded cost transmission

surcharge. The customer may therefore

see earlier power cost savings if a broadbased approach were adopted.632 Once

again, however, we believe that this

potential benefit to a broad-based

approach is outweighed by a significant

countervailing disadvantage. In

particular, the potential power cost

savings to the departing generation

customer would be realized only by

shifting costs (that are directly

attributable to the departing generation

customer) to the other users of the

utility’s transmission system. We

believe that this negative aspect of a

broad-based approach—its violation of

the cost causation principle—is too

great a price to pay for allowing a

departing generation customer to realize

power cost savings as early as possible.

Thus, we recognize that under direct

assignment, it is possible that some

customers may not be able to afford to

leave as soon as they would like. This

in turn could mean that lower cost

suppliers would not be able to make

sales to those customers as soon as they

would like. However, this would occur

only during a transition period, and it

would ensure that, consistent with strict

cost causation principles, the burden of

these transition costs is not unfairly

spread to other customers. Once the

existing uneconomic assets and

contracts are behind us, all wholesale

customers will be better able to shop for

power and reap the long-term benefits of

competitive supply markets.

Although this direct assignment

approach is different from the approach

taken in the natural gas industry, we

believe that the difference is justified.

The transition of the electric industry to

an open transmission access,

competitive industry (including our

proposal to allow an opportunity for

extra-contractual recovery of stranded

costs associated with a discrete set of

wholesale requirements contracts) is

different in a number of respects from

the natural gas industry’s transition to

open access transportation service by

interstate natural gas pipelines. The gas

industry underwent a long period of

open access transition, starting with

Order No. 436 in 1985 and culminating

with Order No. 636 in 1992. In the gas

context, prior to addressing potential

stranded costs, the Commission in

Order No. 436 allowed customers

receiving bundled gas sales and

transportation service from a pipeline

the option to convert to transportationonly service, or to reduce their contract

demand for gas service, before the

termination of their contracts with the

pipeline.633 As a result, most of the

former bundled customers of the

pipeline had already departed the

pipeline’s sales service before the

Commission addressed the recovery of

take-or-pay costs in Order Nos. 500 and

528. In addition, by the time that the

Commission addressed the remaining

transition costs in Order No. 636, the

commodity or wellhead natural gas

market was already competitive and the

majority of gas was already being sold

on an unbundled basis.

Thus, changes in the natural gas

industry had progressed to such a point

(i.e., the departure of customers from

bundled sales) that it was not possible

for the Commission to use a strict cost

causation approach. We noted in the

Supplemental Stranded Cost NOPR that

Many natural gas customers had already

left their historical pipeline suppliers’

systems. Others had converted from sales and

transportation customers to transportationonly customers. Others were in a transition

stage having had opportunities to lower their

contract demands or otherwise become

partial service customers. Significant take-orpay and other costs had accumulated.634

Under those circumstances, the

Commission determined that it was

appropriate to spread the majority of the

remaining transition costs associated

with take-or-pay and other supply

contracts to all customers (both existing

and new) using the interstate natural gas

transportation system. Moreover,

because of the changes in contractual

relationships that had already occurred

among pipelines and their customers, it

was no longer possible for the

Commission to follow a strict cost

causation approach to recovering takeor-pay costs. The Commissionprescribed remedy for the recovery of

transition costs in the natural gas

industry thus was tailored to fit the

needs of that industry given the stage of

development at the time.

However, such a broad-based

approach to recovery of natural gas

transition costs was an exception to the
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21637

635 968 F.2d 1295, 1300–01 (D.C. Cir. 1992)

(quoting Alabama Electric Cooperative, Inc. v.

FERC, 684 F.2d 20, 27 (D.C. Cir. 1982) (emphasis

in original).

636 Id. at 1301. See also Public Utilities

Commission of State of California v. FERC, 988 F.2d

154, 169 (D.C. Cir. 1993).

637Moreover, as we explained in the

Supplemental Stranded Cost NOPR, the shifting of

generation costs to transmission rates does not

violate Commission policy where, as here, the

customer that caused the costs to be incurred and

stranded will continue to pay those costs. As we

indicated, the only difference is that in some

instances the customer will pay the costs through

an adder to its transmission rate instead of through

a generation rate. See FERC Stats. & Regs. ¶32,514

at 33,108 n.269.

638See, e.g., Transwestern Pipeline Company, 43

FERC ¶61,240 at 61,654, order on rehearing, 44

FERC ¶61,164 at 61,536 (1988), relevant petitions

for review dismissed as moot, Transwestern

Pipeline Company v. FERC, 897 F.2d 570, 575–76

(D.C. Cir. 1990); El Paso Natural Gas Company, 47

FERC ¶61,108 at 61,314 (1989).

639 72 FERC ¶61,083 (1995). Further, VT DPS

misinterprets the Commission’s reference to the

NOPR in that case. The Commission did not treat

a notice of termination provision in El Paso’s

contract as a conclusive presumption that El Paso

had no reasonable expectation of continuing to

serve certain customers, as VT DPS contends. The

Commission merely stated that ‘‘[e]ven if the rules

proposed in [the Supplemental Stranded Cost]

NOPR were applied here, El Paso would have

difficulty justifying the exit fee proposed in light of

the existence of the notice of termination provision

in the contract.’’ 72 FERC at 61,441.

640See, e.g., Maryland v. Louisiana, 451 U.S. 725,

748 (1981); Office of Consumers’ Counsel v. FERC,

914 F.2d 292 (D.C. 1990); National Fuel Gas Supply

Corporation v. FERC, 900 F.2d 340, 342, 347–51

(D.C. Cir. 1990).

641 In Order No. 500, the Commission provided

that if pipelines absorbed from 25 to 50 percent of

their take-or-pay settlement costs, they could

recover an equal amount from their firm sales

customers in the form of fixed charges. Any balance

could be recovered in the form of a commodity rate

surcharge or a volumetric surcharge on total

pipeline throughput. Order No. 500, FERC Stats. &

Regs. ¶30,761 at 30,787 (1987). See also Order No.

528, 53 FERC ¶61,163 at 61,597 (1990). Moreover,

we offered pipelines an important quid pro quo for

absorbing take-or-pay costs under Order Nos. 500

and 528—a special presumption that they had been

prudent in incurring their take-or-pay liabilities.

642Order No. 636, FERC Stats. & Regs. ¶30,939 at

30,461.

time-honored principle that rates should

reflect cost causation, and because of

this it was necessary for the

Commission to justify its departure from

that principle. As the court said in K N

Energy v. FERC, 635 ‘‘[i]t has been this

Commission’s long standing policy that

rates must be cost supported. Properly

designed rates should produce revenues

from each class of customers which

match, as closely as practicable, the

costs to serve each class or individual

customer.’’ In that case, the court found

the Commission’s departure from costcausation justified ‘‘given the unusual

circumstances surrounding the take-orpay problem, and the limited nature—

both in time and scope—of the

Commission’s departure from the costcausation principle.’’ 636 It continues to

be Commission policy to follow the

cost-causation principle to the extent

possible.

The factors described above are not

present in the electric industry. At this

time, the vast majority of customers

remain on their bundled suppliers’

systems and generation is not yet fully

competitive. Because the situation

facing the electric industry today is

different from that which the natural gas

industry faced, the Commission must

tailor its approach differently. In the

case of the electric industry today, we

have the opportunity to address the

stranded cost recovery issue up front,

before customers leave their suppliers’

systems. We thus are able to use the cost

causation approach that has been

fundamental to our regulation since

1935.637

The Commission disagrees with

commenters’ arguments that we cannot

impose an exit fee to recover stranded

costs because we did not do so in the

gas context. As discussed in Section

IV.J.9, this Rule establishes procedures

for providing a potential departing

generation customer advance notice

(before it leaves its existing supplier) of

the stranded cost charge (whether it is

to be paid as an exit fee or a

transmission surcharge) that will be

applied if the customer decides to buy

power elsewhere. In the natural gas

context, in contrast, the Commission has

prohibited pipelines from developing

and charging an ‘‘exit fee’’ after a

customer had implemented its gas

purchase decision, noting that

otherwise, the customer would not

know in advance the full cost

consequences of its nomination

decision.638 The ‘‘exit fee’’ that the

Commission rejected in El Paso Natural

Gas Company 639 is also factually

distinguishable from the ‘‘exit fee’’

discussed in this rule. In that case, the

Commission rejected a pipeline’s

attempt post-restructuring to impose an

‘‘exit fee’’ on firm transportation-only

customers (that were converted sales

customers) who in the future elect either

to terminate their firm transportation

service upon expiration of the service

agreement, or to reduce their firm

transportation services level by more

than 10 percent pursuant to an existing

contractual reduction right. Such a

scenario is quite different from the

limited opportunity for stranded cost

recovery provided in this Rule, which is

based on a utility’s reasonable

expectation of continuing generation

service to a bundled (sales and

transmission) requirements customer.

We also will decline to require a

utility seeking stranded cost recovery to

shoulder a portion of its stranded costs.

Such a requirement would be a major

deviation from the traditional principle

that a utility should have a reasonable

opportunity to recover its prudently

incurred costs.640 Although the

Commission allowed such an approach

with regard to a natural gas pipeline’s

take-or-pay costs,641 we did so only as

an extraordinary measure given the

nature of the take-or-pay problem and

the prevailing environment at that time.

We returned to traditional principles

when, in issuing Order No. 636, we

authorized pipelines to recover all of

their prudently incurred gas supply

realignment costs (the costs pipelines

incur in realigning, renegotiating, or

terminating their portfolio of gas supply

contracts to adjust to their sales

customers’ decisions to exercise their

unilateral right under the rule to reduce

or end their commodity purchase

obligations to the pipelines). 642 In the

case of the open access transmission

required by this Rule, we believe that a

utility is entitled to an opportunity to

recover all legitimate, prudent and

verifiable costs incurred by the utility

when the availability of open access

transmission enables a requirements

customer to reach a new generation

supplier.

Although the alternatives of either

spreading the stranded costs to all

transmission users or requiring the

utility shareholders to share the costs

with departing customers might enable

a wholesale customer to leave sooner

than would the direct assignment

approach, the departing customer would

be able to do so only at the expense of

others who had no responsibility for

causing the legitimate, prudent and

verifiable costs to be incurred. Although

we departed from strict cost causation

principles in the gas context and

required a broad spreading of the costs

given the particular circumstances

presented by the gas industry’s

transition to open access, we ultimately

returned to the more traditional

approach of allowing utilities to recover

all of their prudently incurred transition

costs in Order No. 636. At this juncture

in the evolution of competition in the

electric industry we need not make such

a departure from cost causation

principles; utilities can identify and

seek to charge the customers who

caused the costs to be incurred in the

first place, before those customers leave

the utility’s generation system.

Accordingly, we believe that a broader

spreading of the costs to entities who

are not responsible for the incurrence of
21638 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

643FERC Stats. & Regs. ¶ 32,514 at 33,110.

644 Id. at 33,118.

645 Id. and nn. 273, 274.

646E.g., PA Com, FL Com, PSNM, Southern, NC

Com, Duke, Public Service Co of CO, SoCal Edison,

PacifiCorp, Carolina P&L, NYSEG.

647E.g., Sunflower, Sierra, Public Service Co of

CO, Duke.

648E.g., EEI, NYSEG, Southern, PA Com, SoCal

Edison, Pacificorp, El Paso.

649E.g., EEI, Public Service Co of CO, PA Com,

Entergy, Florida Power Corp.

650E.g., TDU Systems, NRECA, TAPS, Redding,

Southwest TDU Group. VT DPS sees no urgent need

for elimination of the § 35.15 requirement or for

automatic termination of sales service under a

wholesale contract of more than three years

duration. However, it supports pregranted

authorization of service termination upon

expiration of sales contracts with terms of less than

three years. Among other things, it submits that the

pregranted authority to terminate short-term service

would relieve the utility of a planning uncertainty

and allow it to maximize use of uncommitted

transmission capacity.

651TAPS, TDU Systems, FL Com, MMWEC.

the stranded costs would not be

equitable.

4. Recovery of Stranded Costs

Associated With New Wholesale

Requirements Contracts

In the Supplemental Stranded Cost

NOPR, the Commission preliminarily

concluded that future wholesale

contracts must explicitly address the

obligations of the seller and buyer,

including the seller’s obligation to

continue to serve the buyer, if any, and

the buyer’s obligation, if any, if it

changes suppliers. We stated that

utilities will be allowed stranded cost

recovery associated with ‘‘new’’

wholesale requirements contracts

(executed after July 11, 1994) only if

explicit stranded cost provisions are

contained in the contract. We indicated

that recovery of wholesale stranded

costs associated with any such new

contract will not be allowed unless such

recovery is provided for in the

contract.643 We also stated that a

contract that is extended or renegotiated

for an effective date after July 11, 1994

becomes a ‘‘new’’ contract for which

stranded cost recovery will be allowed

only if explicitly provided for in the

contract.644

We also stated that it is not

appropriate to impose on a wholesale

requirements supplier a regulatory

obligation to continue to serve its

existing requirements customer beyond

the end of the contract term. We

proposed to retain the § 35.15 prior

notice of termination filing requirement

only for: (i) All contracts required to be

filed under sections 205 and 206 of the

FPA that were executed before the

effective date of the Final Rule pro

forma tariffs; and (ii) any unexecuted

contracts that were filed before the

effective date of the Final Rule pro

forma tariffs. With regard to any power

sales contract executed on or after that

date, we proposed to no longer require

prior notice of termination under

§ 35.15, but to require (for

administrative reasons) written

notification of the termination of such

contract within 30 days after

termination takes place. We requested

comments on whether this proposal

should also be applied to transmission

contracts.645

Comments

Numerous commenters support our

preliminary conclusion that new

wholesale requirements contracts

should explicitly address the obligations

of the seller and buyer and that it is not

appropriate to impose on wholesale

requirements suppliers a regulatory

obligation to continue to serve their

existing requirements customers beyond

the end of the contract term.646

However, Arkansas Cities expresses

concern that this could undermine

obligations to serve that have been

included in certain contracts with

utilities. It asks the Commission to state

that, unless a utility has undertaken an

obligation to serve via contract, there is

no obligation to serve beyond the

contract term. Arkansas Cities asks the

Commission to clarify that contracts

establishing an obligation to serve will

be enforced.

Several other commenters argue that

if a wholesale customer elects to switch

suppliers, the previous supplier should

be under no obligation to take the

customer back onto its system at

embedded cost rates.647 Sierra asks the

Commission to endorse a host utility’s

ability to insist on protective contract

provisions before reestablishing service,

including a predetermined period (such

as five years—a commonly-used

planning period) before the customer

could seek to leave the system again.

A number of commenters support the

Commission’s proposal to eliminate the

prior notice of termination requirement

for power sales contracts executed after

the date on which the final rule pro

forma tariffs become effective.648

Southern states that, because of the

opportunities for power purchasers that

will exist after the proposed rules take

effect, the Commission also should

eliminate § 35.15 as it applies to old

contracts.

Several commenters support

eliminating the § 35.15 filing

requirement for transmission contracts

as well.649 This change is needed, some

assert, to provide certainty in

commercial arrangements in the more

competitive environment and as a

matter of fairness. CSW suggests that all

§ 35.15 filing requirements for existing

contracts (wholesale and transmission

contracts) be phased out over three

years and that only contracts that expire

within three years after the final rule

should be subject to the requirement to

file a notice of termination.

Nevertheless, several other

commenters oppose the Commission’s

proposal to no longer require prior

notice of termination for power sales

contracts executed on or after the

effective date of the generic tariffs.650

TDU Systems opposes elimination of

§ 35.15 as tantamount to a finding that

termination of all contracts is just and

reasonable. TDU Systems and NRECA

submit that the market power exercised

by supplying utilities will not disappear

the instant the rule becomes final and

that it may be possible for a utility to

exercise monopoly power even with

regard to ‘‘new’’ contracts. They propose

that if the Commission nevertheless

decides to allow contract termination

under § 35.15, the Commission should

require a public utility to pay ‘‘stranded

benefit’’ costs to former wholesale

power customers if the customers show

that they had a reasonable expectation

that the power sales would continue

past the end of the agreement at the

prior rate.

Several commenters also oppose

eliminating the § 35.15 filing

requirement for transmission

contracts.651 FL Com asserts that

because the Commission has imposed

an obligation to serve for transmission

service, § 35.15 should be retained for

new and existing transmission

contracts.

Commission Conclusion

We reaffirm our preliminary

determination that future wholesale

requirements contracts should explicitly

address the mutual obligations of the

seller and buyer, including the seller’s

obligation to continue to serve the

buyer, if any, and the buyer’s obligation,

if any, if it changes suppliers. As we

indicated in the Supplemental Stranded

Cost NOPR, now that utilities have been

placed on explicit notice that the risk of

losing customers through increased

wholesale competition must be

addressed through contractual means

only, they must address stranded cost

issues when negotiating new contracts

or be held strictly accountable for the

failure to do so.

We accordingly will allow recovery of

wholesale stranded costs associated

with any new requirements contract
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21639

652Although several commenters have asked the

Commission to retain the prior notice of

termination filing requirement due to concern that

a utility nevertheless may be able to exercise

generation market power with regard to a ‘‘new’’

wholesale requirements contract, we do not believe

that retention of that provision is necessary to

address these commenters’ concerns. Instead, any

party claiming to be aggrieved by a utility’s alleged

abuse of generation market power under a

wholesale requirements contract can file a

complaint with the Commission under section 206

of the FPA.

653FERC Stats. & Regs. ¶ 32,514 at 33,113.

654We invited comments on this proposal. Id. at

33,115.

(executed after July 11, 1994) only if

explicit stranded cost provisions are

contained in the contract. By ‘‘explicit

stranded cost provision’’ (for contracts

executed after July 11, 1994) we mean

a provision that identifies the specific

amount of stranded cost liability of the

customer(s) and a specific method for

calculating the stranded cost charge or

rate. For purposes of requirements

contracts executed after July 11, 1994

but before the date on which this Final

Rule is published in the Federal

Register, however, we clarify that a

provision that specifically reserved the

right to seek stranded cost recovery

consistent with what the Commission

permits in this Rule (without identifying

the specific amount of stranded cost

liability of the customer(s) and

calculation method) nevertheless will be

deemed an ‘‘explicit stranded cost

provision.’’ However, a provision in a

requirements contract executed after

July 11, 1994 but before the date on

which this Final Rule is published in

the Federal Register that merely

postpones the issue of stranded cost

recovery without specifically providing

for such recovery will not be considered

an ‘‘explicit stranded cost provision.’’

After the date on which this Final Rule

is published in the Federal Register, a

provision must identify the specific

amount of stranded cost liability of the

customer(s) and a specific method for

calculating the stranded cost charge or

rate in order to constitute an ‘‘explicit

stranded cost provision.’’

We reaffirm that a requirements

contract that is extended or renegotiated

for an effective date after July 11, 1994

becomes a ‘‘new’’ requirements contract

for which stranded cost recovery will be

allowed only if explicitly provided for

in the contract.

We also reaffirm our preliminary

determination not to impose a

regulatory obligation on wholesale

requirements suppliers to continue to

serve their existing requirements

customers beyond the end of the

contract term. The only exception to

this would be if the customer decides to

remain a requirements customer for the

period for which the Commission finds

that the supplying utility reasonably

expected to continue serving the

customer. In such a case, the supplying

utility will be obligated to offer

continuing service to the requirements

customer for the period the utility

reasonably expected to continue serving

the customer.

A requirements customer will be

responsible for planning to meet its

power needs beyond the end of the

contract term by either building its own

generation, signing a new power sales

contract with its existing supplier, or

contracting with new suppliers in

conjunction with obtaining transmission

service under its existing supplier’s

open access transmission tariff or

another utility’s transmission system. In

so holding, it is not our intent to

undermine any obligations specifically

contained in a contract. Thus, if a

contract explicitly establishes an

obligation to serve beyond the end of

the contract term, such a contractuallyimposed obligation to serve (as

distinguished from a regulatory

obligation to serve) would be

enforceable as a term of the contract. If

a wholesale customer that switches

suppliers later seeks to reestablish

service with its former supplier, it will

be up to the parties to negotiate their

respective obligations.

We also reaffirm our preliminary

determination to no longer require prior

notice of termination under § 35.15 for

any power sales contract executed on or

after the effective date of the Final Rule

pro forma tariff (but to require written

notification of the termination of such

contract within 30 days after

termination takes places). This

determination goes hand-in-hand with

our determination (discussed above) not

to impose a regulatory obligation on

wholesale requirements suppliers to

continue to serve their existing

requirements customers beyond the end

of the contract term.652 We clarify,

however, that this decision applies only

to a power sales contract that is to

terminate by its own terms (such as on

the contract’s expiration date). We have

revised § 35.15 accordingly. We will,

however, continue to require prior

notice of cancellation or termination for

any power sales contract that is

proposed to be cancelled or terminated

for a reason other than by the contract’s

own terms (such as a self-help provision

related to, for example, a billing

dispute), regardless of when the contract

was executed. We also will continue to

require prior notice of the proposed

termination of any power sales contract

executed before the effective date of the

Final Rule pro forma tariff (even if the

contract is to terminate by its own

terms) as well as any unexecuted power

sales contract that was filed before that

date.

Further, we will retain the § 35.15

filing requirement for all transmission

contracts. The reason for retaining the

§ 35.15 requirement for transmission

contracts is that transmission will

continue to be provided under

conditions of potential market power,

and the Commission must be assured

that transmission owners are not

exerting market power in termination of

transmission contracts. In addition, this

filing requirement will provide the

customer an opportunity to notify the

Commission if the termination terms are

disputed or if the customer was not

given adequate opportunity to exercise

its limited right of first refusal under the

Final Rule (see Section IV.A.5).

5. Recovery of Stranded Costs

Associated With Existing Wholesale

Requirements Contracts

In the Supplemental Stranded Cost

NOPR, the Commission reaffirmed its

proposal to permit the recovery of

legitimate, prudent and verifiable

stranded costs for a discrete set of

‘‘existing’’ wholesale requirements

contracts (executed on or before July 11,

1994)—those that do not already contain

exit fees or other explicit stranded cost

provisions. We encouraged the parties

to such contracts to renegotiate them to

address stranded costs. In the case of

existing contracts that already contain

an exit fee or explicit stranded cost

provision, however, we proposed to

reject a unilateral stranded cost

amendment; that is, we stated we would

reject an amendment unless the contract

permits renegotiation of the existing

stranded cost provision or the parties to

the contract mutually agree to

renegotiate the contract.653 In so doing,

we proposed to drop the three year

mandatory negotiation period suggested

in the initial Stranded Cost NOPR.654

If an existing requirements contract

does not contain an exit fee or other

explicit stranded cost provision (and is

not renegotiated to add such a

provision), we proposed that before the

expiration of the contract: (1) A public

utility or its customer may file a

proposed stranded cost amendment to

the contract under section 205 or 206;

or (2) a public utility or transmitting

utility may file a proposal to recover

stranded costs associated with any such

existing contract through its

transmission rates for a customer that

uses the utility’s transmission system to

reach another generation supplier.
21640 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

655See United Gas Pipeline Company v. Mobile

Gas Service Corporation, 350 U.S. 332 (1956); FPC

v. Sierra Pacific Power Company, 350 U.S. 348

(1956).

656FERC Stats. & Regs. ¶ 32,514 at 33,113–14. We

noted that under the Mobile-Sierra doctrine, a

customer may waive its right to challenge the

contract and/or the utility may waive its right to

make unilateral rate changes. However, the parties

may not waive the indefeasible right of the

Commission to alter rates that are contrary to the

public interest. Id. at 33,111.

657 Id. at 33,114–15.

658E.g., ELCON, TAPS, Alcoa, Utilicorp.

659E.g., Utilities For Improved Transition,

Atlantic City.

660E.g., Basin, Tri-County EC, NW Iowa

Cooperative, Baker EC, Big Horn EC, Black Hills EC,

Bon Homme Yankton EC, Carbon Power, Central

EC, Douglas EC, East River EC, Ida County REC,

James Valley EC, Lincoln-Union EC, McKenzie EC,

North Dakota RECs, Oahe EC, Oliver-Mercer EC,

Panhandle Coop, Rushmore EC, San Luis Valley EC,

Slope EC, Spink EC, Turner-Hutchinson EC,

Traverse EC, Union County EC, West River EC,

Whetstone Valley EC, Woodbury County REC,

Yellowstone Valley EC.

661Basin indicates that all such contracts for the

sale of more than 1,000 kW and any amendments

thereto must be specifically approved by the RUS.

662E.g., EEI, PSNM, AEP, Consumers Power.

Consumers Power suggests that the language of

proposed § 35.26(c)(1)(iv) be modified to recite the

Commission’s public interest finding.

663E.g., Concord, Chugach, ME Consumer-Owned

Utilities.

664E.g., Utilicorp, AMP-Ohio, Environmental

Action, DE Muni, Arkansas Cities, Direct Service

Industries, PA Munis, ABATE, APPA.

665See, e.g., American Forest & Paper, VT DPS,

PA Munis, ABATE, ELCON, APPA, Environmental

Action.

666 55 F.3d 686 (1st Cir. 1995) (Northeast

Utilities).

667PA Munis argues that Northeast Utilities

provides no support for the Commission’s proposed

Mobile-Sierra finding because Northeast Utilities

involved the effect of disputed contractual terms on

In the Supplemental Stranded Cost

NOPR, we reaffirmed our proposal in

the initial Stranded Cost NOPR that,

even if the contract contains an explicit

Mobile-Sierra 655 provision, it is in the

public interest to permit public utilities

to seek unilateral amendments to add

stranded cost provisions if the contracts

do not in essence forbid such recovery

by containing exit fees or other explicit

stranded cost provisions.656 Under these

circumstances, if neither of the parties

seeks and obtains acceptance or

approval of a stranded cost amendment,

we propose to permit the public utility

to seek recovery of stranded costs

through its wholesale transmission

rates.

We also proposed procedures for

providing an existing wholesale

requirements customer advance notice

of how the utility would propose to

calculate costs that the utility claims

would be stranded by the customer’s

departure.657

Comments

a. July 11, 1994 Cut-Off Date

A number of commenters ask the

Commission to reconsider the July 11,

1994 cut-off date for distinguishing

between ‘‘existing’’ and ‘‘new’’

requirements contracts. Some

commenters 658 support October 24,

1992 (the date of passage of the Energy

Policy Act) as the cut-off date on the

basis that anyone entering into a

wholesale requirements contract after

that date should have recognized the

greatly increased possibility of the

customer terminating or not renewing

the contract.

Other commenters 659 support a later

date for defining ‘‘new’’ requirements

contracts, such as the date on which the

final rule open access tariffs become

effective. Utilities For Improved

Transition argues that the Commission

cannot retroactively adopt the July 11,

1994 cut-off date, but must wait until

the final rule is issued before setting the

date after which requirements contracts

must contain stranded cost provisions

in order for stranded cost recovery to be

allowed.

Commenters representing electric

cooperatives also oppose the July 11,

1994 cut-off date.660 They contend that

RUS borrowers were not free to

negotiate stranded cost amendments to

wholesale power contracts as soon as

the Commission warned them to do so

because their wholesale power contracts

are mandated both as to form and

substance by the RUS.661

PA Munis asks the Commission to

treat certain contracts that were

executed before July 11, 1994 (but not

approved by the Commission until after

that date) as ‘‘new’’ contracts. PA Munis

argues that the utility, after issuance of

the initial NOPR, could have withdrawn

its filing of the contract and sought to

negotiate an exit fee at that time. It

submits that the utility’s failure to do so

would justify a finding by the

Commission that contracts approved

after July 11, 1994 be treated similarly

to contracts executed after that date.

b. Stranded Cost Recovery for Existing

Requirements Contracts

A number of commenters express

support for the Commission’s proposal

to permit modification of existing

requirements contracts that do not

already contain exit fees or other

explicit stranded cost provisions.662

NEPCO states its interpretation that the

NOPR does not consider notice

provisions to be ‘‘explicit stranded cost

provisions;’’ it argues that the presence

of a notice provision in a contract, while

bearing on the supplier’s ability to

demonstrate the duration of its

reasonable expectation of continued

service, should not foreclose the

amendment of a wholesale contract to

add an exit fee or similar payment

provision. Several other commenters ask

the Commission to clarify that contracts

that contain notice provisions and that

preclude recovery for termination or

reduction of service (but that do not

necessarily use the terms ‘‘exit fee’’ or

‘‘stranded cost’’), or that expressly

provide that stranded costs shall not be

charged, cannot be reopened for a

stranded cost claim.663

A number of other commenters

oppose the Commission’s proposal to

permit amendment of wholesale

requirements contracts that do not

address stranded cost recovery, for

reasons previously raised in this

proceeding.664 They argue, among other

things, that contracts should stand on

their own. RUS asserts that the integrity

of its Federal loan program is to a large

extent predicated on honoring the longterm requirements wholesale power

contracts between G&Ts and their

distribution members.

Several commenters also challenge

the Commission’s proposed

determination that it is in the public

interest to permit utilities to seek

unilateral amendments to add stranded

cost provisions to requirements

contracts. These commenters argue that

the NOPR’s assumptions concerning the

financial stability of public utilities are

unsupported and thus do not meet the

burden of proof required for the public

interest finding under the Mobile-Sierra

doctrine. They urge the Commission to

require a utility-specific finding of

imminent financial jeopardy before

overriding a Mobile-Sierra contract.665

ELCON argues that the recent

Northeast Utilities Service Company v.

FERC 666 case reaffirms the traditional

high threshold for overriding MobileSierra clauses in the ‘‘classic MobileSierra situation’’ in which one of the

parties seeks modification of a contract

that has already been reviewed and

approved by the Commission. It submits

that a utility seeking to add a stranded

cost provision to an existing contract

would fall within the ‘‘classic

situation.’’ ELCON also argues that the

First Circuit strongly implied that to

satisfy Mobile-Sierra, the Commission

must identify specifically those aspects

of a contract that are contrary to the

public interest and why. On this basis,

ELCON argues that the case supports its

position that a utility-specific finding of

imminent financial jeopardy is

necessary to override an existing

Mobile-Sierra contract.667
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21641

third parties, not the alleged financial effect on the

utility. It argues that the court found that the

Commission had adequately explained how the

disputed contractual terms may harm third parties

to the contract (which PA Munis says the

Commission has failed to do here). PA Munis also

submits that the court went out of its way to

emphasize the narrow scope of its order affirming

the Commission.

668E.g., ELCON, CCEM, VT DPS, OK Com, TDU

Systems, LG&E, ABATE, Portland, Utilicorp, TAPS.

669E.g., Knoxville, Memphis.

670E.g., EEI, Florida Power Corp, PA Com, WP&L,

Consumers Power, FL Com, TVA, SoCal Edison,

Texas Utilities.

671E.g., TAPS, TDU Systems, DOD, ELCON,

APPA.

672E.g., Sierra, Central Illinois Light, NY Energy

Buyers, American Forest & Paper, WEPCO, EGA.

Education proposes either a transition period that

ends five years after the effective date of the final

rule or a phase-out of the utility’s authority to

recover stranded costs from departing customers by

gradually reducing (for instance, over a ten year

period from the date of the final rule) the

percentage of stranded costs that the utility could

recover.

673E.g., TAPS, Missouri Joint Commission.

674E.g., TDU Systems.

675E.g., DOD, ABATE.

676See UFIT Initial Comments at 34. Moreover,

the cases that UFIT cites, in which the Commission

rejected parties’ efforts to devise rates based on

methods or formulas contained in proposed rules,

are inapposite. By establishing the July 11, 1994

cutoff date, the Commission is not ‘‘fix(ing) rates

under section 206’’ or otherwise making ‘‘a Section

206 ‘determination,’ ’’ as UFIT suggests. Id. at 35,

36. The Commission has not proposed a change in

the way that utilities compute their rates; it has

simply put all parties on notice of the limited

nature and opportunity for extra-contractual

stranded cost recovery.

677 In response to the commenters representing

electric cooperatives that object to the July 11, 1994

cut-off date, we do not believe that the requirement

that RUS borrowers obtain RUS approval of their

contracts necessarily prevents such borrowers from

addressing stranded cost recovery in contracts

executed after July 11, 1994.

678We confirm that a notice of termination

provision by itself (that is, one that does not also

provide for or preclude recovery of stranded costs

by the seller upon termination of the contract) is not

an ‘‘explicit’’ stranded cost provision; however, as

discussed in Section IV.J.8, the presence of a notice

provision creates a rebuttable presumption that the

utility had no reasonable expectation of continuing

to serve the customer.

Some commenters argue that if

utilities are to be granted industry-wide

Mobile-Sierra relief, then the

Commission should give wholesale

customers the reciprocal right to convert

their wholesale power contracts to

transmission-only service.668 However,

EEI contends that the Commission is

barred by section 211(c)(2) of the FPA

from ordering wheeling where a

customer is taking service under a

contract or under a rate tariff on file

with the Commission.

Several commenters ask the

Commission to require renegotiation of

the notice and/or term of all existing

contracts with long lead-time

cancellation provisions in order to allow

all wholesale customers access to the

market at the same time.669 They submit

that customers with short notice

provisions will be the first to enjoy the

benefits of open access and will have an

effective ‘‘first right of refusal’’ of the

most economical transmission paths

and low cost suppliers, putting

customers with long lead-time

cancellations at a competitive

disadvantage.

c. Transition Period

A number of commenters support the

Commission’s proposal not to mandate

a three-year time limit for renegotiation

of existing wholesale requirements

contracts. They note that existing

contracts have unique characteristics

and complexities that affect the time

required to renegotiate the contract

bilaterally, to file a unilateral

amendment with the Commission, or to

file for stranded cost recovery through

transmission rates.670

On the other hand, some commenters

object that the proposal to replace the

previously proposed three-year window

with an opportunity to raise stranded

cost claims throughout the existing

contract term creates a virtually

unlimited transition period.671 For

example, ELCON asserts that because

the NOPR would allow utilities to seek

amendment of an existing contract any

time prior to its expiration, stranded

cost issues could extend through the life

of existing facilities (30 years or more).

Portland suggests that the Commission

set a schedule now for proceedings to

determine transmission costs and

stranded costs for each utility with

wholesale requirements customers.

Commenters propose various limits to

the period within which stranded cost

recovery could be raised, such as: (i)

Three to five years; 672 (ii) the lesser of

three years from the effective date of the

final rule or the remaining term of the

contract; 673 (iii) one year from the

effective date of the final rule; 674 and

(iv) December 31, 1998 (20 years after

PURPA).675

Commission Conclusion

a. July 11, 1994 Contract Cut-Off Date

We reaffirm our proposal to permit

the recovery of legitimate, prudent and

verifiable stranded costs for ‘‘existing’’

wholesale requirements contracts

(executed on or before July 11, 1994)

that do not already contain exit fees or

other explicit stranded cost provisions.

We believe that July 11, 1994—the date

on which the initial Stranded Cost

NOPR was published and, thus, on

which the industry was put on notice of

the proposal to disallow prospectively

extra-contractual recovery of stranded

costs—is the appropriate date for

distinguishing ‘‘existing’’ requirements

contracts from ‘‘new’’ requirements

contracts. Because all parties were put

on notice in the initial Stranded Cost

NOPR that July 11, 1994 would be the

operable date for the ‘‘existing’’/‘‘new’’

contract distinction, utilities that

executed requirements contracts after

that date could have had no reasonable

expectation that they would be

permitted to recover any costs extracontractually.

Moreover, because the costs at issue

are extra-contractual costs, the

Commission’s notice to all parties that

contracts executed after July 11, 1994

will be enforced by their terms as far as

stranded cost recovery is concerned

does not constitute ‘‘retroactive

rulemaking.’’ Contrary to UFIT’s

contention, the Commission is not

‘‘requir[ing]’’ utilities to include

stranded cost recovery provisions in all

contracts executed after July 11, 1994.676

The Commission has merely put all

parties on notice that the opportunity

for extra-contractual stranded cost

recovery (which will be allowed on a

prospective basis upon the effective date

of the Rule) will not be available for any

requirements contracts executed after

July 11, 1994. The parties to

requirements contracts executed after

July 11, 1994 have been free to provide

for stranded cost recovery in the

contract, or not.677 The point is that, for

requirements contracts executed after

the cut-off date, stranded cost recovery

will be governed solely by the terms of

the contract.

b. Stranded Cost Recovery for Existing

Requirements Contracts

We reaffirm that we will permit

utilities to seek recovery of stranded

costs for a limited set of existing

wholesale requirements contracts,

namely, those that do not already

contain exit fees or other explicit

stranded cost provisions.678 If an

existing requirements contract includes

an explicit provision for payment of

stranded costs or an exit fee, we will

assume that the parties intended the

contract to cover the contingency of the

buyer leaving the system. We will reject

a stranded cost amendment to such a

contract, unless the contract permits

renegotiation of the existing stranded

cost provision or the parties to the

contract mutually agree to a new

stranded cost provision. Similarly, we

will reject a stranded cost amendment to

an existing requirements contract if the

contract prohibits stranded cost

recovery (or precludes recovery for

termination or reduction of service) or
21642 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

679 In the case of an existing wholesale

requirements contract that does not contain an exit

fee or other explicit stranded cost provision but

does contain a notice provision, once a customer

gives notice according to the terms of the contract

that it will no longer purchase all or a part of its

requirements from the selling utility, we would not

allow the utility to amend the contract to add a

stranded cost provision. However, in such a case,

the utility could seek to recover stranded costs

through its rates for transmission services to the

customer. As discussed in Section IV.J.8, the utility

would have to rebut the presumption that, based on

the presence of the notice provision, it had no

reasonable expectation of continuing to serve the

customer.

680FERC Stats. & Regs. ¶ 32,507 at 32,870.

681See Utility Investors Analysts, Initial

Comments at 2–3; Utility Shareholders, Initial

Comments at 2–4.

682The court concluded that the Commission

‘‘gave thoughtful consideration to the public

interest.’’ 55 F.3d at 693.

683 Id. at 689.

684 Id. at 690.

685 Id. at 691, citing Northeast Utilities Service

Company v. FERC, 993 F.2d 937, 961 (1st Cir.

1993).

686Northeast Utilities, 55 F.3d at 691. The court

distinguished the facts of that case from other

Mobile-Sierra cases. It noted that ‘‘[t]he issue here

is not whether one party to a rate contract filed with

FERC can effect a rate change unilaterally, but the

standard to be used by FERC in examining electric

power contracts filed with it.’’ Id. at 690–91. It also

noted that the contract provisions under review

were not low-rate issues in the context of Mobile

and Sierra. We recognize that whether a contract

should be modified to add a stranded cost provision

could be viewed as one party to a contract seeking

to effect a unilateral rate change, or as a low-rate

issue (i.e., whether the utility’s rates would be

insufficient without stranded cost recovery).

However, parties are being permitted to make such

unilateral filings only after a generic finding by the

Commission that the public interest likely would be

jeopardized if utilities are not permitted to make a

case-specific showing that recovery should be

allowed. We believe that Northeast Utilities

provides valuable guidance concerning application

of the public interest standard where, as here, a

failure to allow limited contract modification may

harm the public interest by harming third parties.

687The court found that the Commission had met

the public interest standard ‘‘by explaining how the

disputed contractual terms may harm third parties

to the contract. * * * For example, the

Commission found the automatic rate-of-return-onequity adjustment provision unacceptable because

third parties may ultimately bear the burden of a

rate component that does not reflect actual capital

market conditions. Likewise, the ‘blank check’

given owners of the power plant to determine the

decommissioning costs for themselves under New

Hampshire law is impermissible because it may be

cashed at the expense of non-parties to the

contract.’’ Id. at 692 (emphasis in original). The

court rejected the argument that the public interest

standard is ‘‘practically insurmountable’’ in all

circumstances. It noted, among other things, ‘‘that

neither Mobile nor Sierra stated or intimated that

the ‘public interest’ doctrine was ‘practically

insurmountable.’ ’’ Id. at 691.

688 Id. at 692 (emphasis in original).

prohibits renegotiation of an existing

stranded cost or exit fee provision,

unless the parties to the contract

mutually agree to a new stranded cost

provision.679

We reaffirm our desire that utilities

attempt to renegotiate with their

customers existing requirements

contracts that do not contain exit fees or

other explicit stranded cost provisions.

If the parties negotiate a stranded cost

provision and the seller is A public

utility, the utility must file the provision

with the Commission as an amendment

to the existing requirements contract.

If an existing requirements contract

does not contain an exit fee or other

explicit stranded cost provision (and is

not renegotiated to add such a

provision), before the expiration of the

contract: (1) a public utility or its

customer may file a proposed stranded

cost amendment to the contract under

section 205 or 206; or (2) a public utility

in a section 205 proceeding, or a

transmitting utility in a section 211

proceeding, may file a proposal to

recover stranded costs associated with

any such existing contract through its

transmission rates for a customer that

uses the utility’s transmission system to

reach another generation supplier.

We thus reaffirm that if an existing

requirements contract is not

renegotiated, and the contract permits

the seller and/or buyer to seek an

amendment to the contract, the

authorized party may seek an

amendment to add a stranded cost

provision. We also adopt our

preliminary finding that, even if an

existing requirements contract contains

an explicit Mobile-Sierra provision, it is

in the public interest to permit the

public utility to seek a unilateral

amendment to add stranded cost

provisions if the contract does not

already contain exit fees or other

explicit stranded cost provisions. In the

initial Stranded Cost NOPR, we

identified two ways in which a failure

to permit public utilities to address

stranded costs could harm third parties,

and thereby harm the public interest:

First, the inability to seek recovery of

stranded costs could impair the financial

ability of a utility to continue to provide

reliable service. This will depend on the

magnitude of stranded costs and the prospect

or lack thereof for recovering such costs from

ratepayers. The prospect of not recovering

from ratepayers significant amounts of

stranded costs could seriously erode a

utility’s access to capital markets, or could

drive the utility’s cost of capital to

unprecedented levels. This high cost of

capital could precipitate other customers

leaving the system which, in turn, could

cause others to leave. Such a spiral could be

difficult to stop once begun. Second, if some

customers are permitted to leave their

suppliers without paying for stranded costs,

this may cause an excessive burden on the

remaining customers who, for whatever

reason, cannot leave and therefore may have

to bear those costs.680

The financial community commenters

confirm our views in this regard. As

they note, a utility’s access to financial

markets is essential to the continued

provision of safe and reliable electric

service to customers. However, the

prospect of a utility not recovering

stranded costs could erode a utility’s

ability to attract capital and thus imperil

its continued financial stability.681 As

these and other commenters agree, the

recovery of stranded costs is critical to

the successful transition to more

competitive markets.

Moreover, our determination that it is

in the public interest to give public

utilities a limited opportunity to

propose contract changes unilaterally to

address stranded costs if their contracts

do not already explicitly do so satisfies

the public interest standard of the

Mobile-Sierra doctrine as recently

interpreted by the Northeast Utilities

court. In that case, the court affirmed an

order of the Commission on remand

modifying a contract under the MobileSierra public interest standard.682 As the

court explained, the Mobile-Sierra

doctrine ‘‘represents the Supreme

Court’s attempt to strike a balance

between private contractual rights and

the regulatory power to modify

contracts when necessary to protect the

public interest.’’ 683 The court noted that

when the Commission is considering

whether a contract rate is too low,

protective action by the Commission in

the public interest is justified ‘‘where

the rate might impair the financial

ability of the utility to continue to

supply electricity, force electricity

consumers to bear an excessive burden,

or be unduly discriminatory.’’ 684

The court also explained that ‘‘the

most attractive case for affording

additional protection [under the public

interest standard], despite the presence

of a contract, is where the protection is

intended to safeguard the interests of

third parties * * *.’ ’’ 685 It stated that

the Mobile-Sierra doctrine allows the

Commission to modify the terms of a

private contract ‘‘when third parties are

threatened by possible ‘undu[e]

discrimination’ or the imposition of an

‘excessive burden.’ ’’ 686 The court found

that the Commission had met the public

interest standard by showing how the

contract could harm third parties.687

Consistent with the holding in

Northeast Utilities, and contrary to the

positions of some commenters, we have

demonstrated how ‘‘third parties may

ultimately bear the burden’’ 688 if public

utilities with Mobile-Sierra contracts are

not given any opportunity to propose

contract changes to address stranded

costs. If the Commission fails to give a
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21643

689FERC Stats. & Regs. ¶ 32,507 at 32,871.

690This is consistent with the definition of

existing requirements contracts we have used for

purposes of stranded cost recovery.

public utility this opportunity, and the

utility’s financial ability to continue the

provision of safe and reliable service is

impaired, third parties (customers

relying on the public utility for their

electric service) will be placed at risk.

Similarly, if the Commission fails to

give a public utility the opportunity to

directly assign costs to the customers on

whose behalf they were incurred, and

some of the utility’s customers leave the

utility’s generation system for that of

another supplier without paying such

costs, third parties (the utility’s

remaining customers) will be harmed by

having to bear the costs that were not

incurred to serve them and that are

stranded by the other customers’

departures via open access

transmission. Moreover, we believe that

protective action in the public interest

is particularly necessary where, as here,

a utility’s rates could become

insufficient because of fundamental

changes in the industry that largely

result from legislative or regulatory

changes that could not be anticipated.

Further, notwithstanding the

arguments of some commenters

supporting a case-by-case (as opposed to

a generic) public interest finding, we

believe it appropriate that our public

interest finding be made on a generic

basis given the fact that, by this Rule,

we are requiring full open access that

could significantly affect historical

relationships among traditional utilities

and their customers and the ability of

utilities to recover prudently incurred

costs. We also emphasize that we are

not eliminating the need for case-bycase demonstrations that stranded cost

recovery should be allowed. Our public

interest finding is that utilities be

permitted to seek extra-contractual

recovery of stranded costs in certain

defined circumstances. Utilities seeking

recovery of stranded costs will have the

burden, on a case-by-case basis, of

showing they had a reasonable

expectation of continuing to serve the

departing generation customer.

In summary, we emphasize the

limited nature of our Mobile-Sierra

public interest finding. First, our

holding applies only to wholesale

requirements contracts executed on or

before July 11, 1994 that do not contain

an exit fee or other explicit stranded

cost provision. Thus, we will not permit

modification of any contract that

addresses the stranded cost issue

explicitly, unless the contract

specifically permits such modifications.

Instead, we are simply examining

requirements contracts that do not

clearly address the issue in the context

of the traditional regulatory regime

under which they were signed—a

regulatory environment in which it was

assumed as a matter of course that the

great majority of requirements

customers would stay with their original

suppliers and that these suppliers had a

concomitant obligation to plan to

supply these customers’ continuing

needs.

Second, although we have decided on

a generic basis that it is in the public

interest to permit public utilities with

Mobile-Sierra contracts to make

unilateral filings, we are not

automatically approving any

amendment that a particular utility

might file. As we stated in the initial

Stranded Cost NOPR, if a public utility

unilaterally files a proposed stranded

cost amendment under either section

205 or 206 of the FPA, this does not

necessarily mean that the Commission

ultimately will find it appropriate to

allow such amendment.689 In addition,

customers with Mobile-Sierra contracts

that do not explicitly address stranded

costs may also file complaints under

section 206 of the FPA to propose to

address stranded costs in existing

requirements contracts. The

Commission will analyze any proposed

stranded cost amendment to a MobileSierra contract, whether proposed by

the utility or by its customer, based on

the particular circumstances

surrounding that contract. Thus, the

case-by-case findings that some

commenters seek will, in effect, be made

when the Commission determines

whether to approve a proposed stranded

cost amendment to a particular contract.

As discussed in Section IV.A (Scope),

the Commission has concluded that

although current conditions in the

wholesale power market do not warrant

the generic modification of

requirements contracts, nonetheless the

modification of certain requirements

contracts on a case-by-case basis may be

appropriate. We have concluded further

that, even if customers under such

contracts are bound by so-called MobileSierra clauses, they nonetheless ought

to have the opportunity to demonstrate

that their contracts no longer are just

and reasonable.

We have found that it would be

against the public interest to permit a

Mobile-Sierra clause in an existing

wholesale requirements contract to

preclude the parties to such a contract

from the opportunity to realize the

benefits of the competitive wholesale

power markets. For purposes of this

finding, the Commission defines

existing requirements contracts as

contracts executed on or before July 11,

1994.690 By operation of this finding, a

party to a requirements contract

containing a Mobile-Sierra clause no

longer will have the burden of

establishing independently that it is in

the public interest to permit the

modification of such contract. The

party, however, still will have the

burden of establishing that such

contract no longer is just and reasonable

and therefore ought to be modified.

This finding complements the

Commission’s finding that,

notwithstanding a Mobile-Sierra clause

in an existing requirements contract, it

is in the public interest to permit

amendments to add stranded cost

provisions to such contracts if the

public utility proposing the amendment

can meet the evidentiary requirements

of this Rule. The Commission’s

complementary Mobile-Sierra findings

are not mutually exclusive. Any

contract modification approved under

this section shall provide for the

utility’s recovery of any costs stranded

consistent with the contract

modification. The stranded costs must

be prudently incurred, legitimate and

verifiable. Further, the Commission has

concluded that if a customer is

permitted to argue for modification of

existing contracts that are less favorable

to it than other generation alternatives,

then the utility should be able to seek

modification of contracts that may be

beneficial to the customer.

The Commission believes that the

most productive way to analyze contract

modification issues is to consider

simultaneously both the selling public

utility’s claims, if any, that it had a

reasonable expectation of continuing to

serve the customer beyond the term of

the contract and the customer’s claim, if

any, that the contract no longer is just

and reasonable and therefore ought to be

modified. Thus, if the selling public

utility intends to claim stranded costs,

it must present that claim in any section

206 proceeding brought by the customer

to shorten or terminate the contract.

Similarly, if the customer intends to

claim that the notice or termination

provision of its existing requirements

contract is unjust and unreasonable, it

must present that claim in any

proceeding brought by the selling public

utility to seek recovery of stranded

costs. This will promote administrative

efficiency and will permit the

Commission to consider how the

contracting parties’ claims bear on one

another.
21644 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

691The value of its assets could vary over time as

new technologies emerge, fuel costs fluctuate, or

environmental requirements change.

692FERC Stats. & Regs. ¶ 32,514 at 33,127.

693 Id. at 33,128.

694 Id.

695E.g., NARUC, ELCON, TAPS, NASUCA, N.Y.

Mayors, NY Industrials, American Iron & Steel,

Missouri Joint Commission, Omaha PPD, MI Com,

NY Com, NJ BPU, VT DPS, OK Com, IN Com, UT

Com, WA Com, Environmental Action, IN

Industrials, LA DWP, Seattle, CAMU, Las Cruces,

UT Industrials, Suffolk County, NM Industrials, CO

Consumers Counsel.

696ELCON Comments, dated July 25, 1995, at 41.

697E.g., MD Com, MI Com, LA DWP, Las Cruces.

For example, MD Com states that while open access

transmission may make municipalization more

attractive, it ultimately is MD Com’s approval that

makes municipalization possible in Maryland.

698E.g., MD Com, Las Cruces, Caparo, Coalition

on Federal-State Issues, IN Com, MI Com, Iowa

Board.

699E.g., IL Com, CA Com, Midwest Commissions,

CO Consumers Counsel.

700E.g., LA DWP, Ohio Manufacturers, MMWEC,

American Iron & Steel, UT Industrials, MI Com, NY

Industrials, WA Com, Caparo.

The Commission does not take

contract modification lightly. Whether a

utility is seeking a contract amendment

to permit stranded cost recovery based

on expectations beyond the stated term

of the contract, or a customer is seeking

to shorten or eliminate the term of an

existing contract, we believe that each

have a heavy burden in demonstrating

that the contract ought to be modified.

Still, we believe that given the industry

circumstances now facing us, both

selling utilities and their customers

ought to have an opportunity to make

the case that their existing requirements

contracts ought to be modified. By

providing both buyers and sellers this

opportunity, the Commission attempts

to strike a reasonable balance of the

interests of all market participants. The

Commission expects that many of the

arguments presented by buyers and

sellers in such proceedings will be fact

specific.

c. Transition Period

We reaffirm our proposal to allow a

public utility or its customer to file a

proposed stranded cost amendment, or

to allow a public utility or transmitting

utility to file a proposal to recover

stranded costs through a departing

generation customer’s transmission

rates, at any time prior to the expiration

of the contract. There is no uniform time

remaining on requirements contracts

executed on or before July 11, 1994. Any

limitation on the period in which

parties could propose amendments

covering stranded costs (e.g., 3 years)

would thus unequally affect market

participants. Those with long terms

remaining on their contracts could

object that immediately addressing the

issue would not be cost effective. For

example, a utility with a long remaining

term (e.g., 20 years) might not even seek

stranded cost recovery depending on the

competitive value of its assets near the

end of the contract term.691 However,

such a utility would invariably seek to

preserve its option to seek stranded cost

recovery if its failure to do so within a

short period resulted in a waiver of its

right to do so.

6. Recovery of Stranded Costs Caused by

Retail-Turned-Wholesale Customers

In the Supplemental Stranded Cost

NOPR, we stated that both this

Commission and state commissions

have the legal authority to address

stranded costs that result from retail

customers becoming wholesale

customers who then obtain transmission

under the open access tariffs.692 We

proposed that this Commission should

be the primary forum for addressing the

recovery of stranded costs caused by

retail-turned-wholesale customers. We

explained that if a retail customer

becomes a legitimate wholesale

customer (such as through

municipalization), it becomes eligible to

use the non-discriminatory open access

tariffs:

If costs are stranded as a result of this

wholesale transmission access, we believe

that these costs should be viewed as

‘wholesale stranded costs.’ But for the ability

of the new wholesale entity to reach another

generation supplier through the FERC-filed

open access transmission tariff, such costs

would not be stranded.693

We accordingly proposed to define

‘‘wholesale stranded costs’’ to include

stranded costs resulting from unbundled

transmission for newly-created

wholesale customers and sought

comments on this definition.

We proposed to require the same

evidentiary demonstration for recovery

as that required if recovery were sought

from a wholesale requirements

customer. We reaffirmed our proposal in

the initial Stranded Cost NOPR that a

utility will have to show that the

stranded costs are not more than the net

revenues that the retail-turnedwholesale customer would have

contributed to the utility had it

remained a retail customer of the utility,

and that the utility has taken and will

take reasonable steps to mitigate

stranded costs. We further proposed to

deduct any recovery that a state has

permitted from departing retail-turnedwholesale customers from the legitimate

stranded costs of which we will allow

recovery. In addition, we proposed to

apply the same procedures for obtaining

an estimate of maximum stranded cost

exposure without mitigation to retail

customers contemplating becoming

wholesale transmission customers as

those proposed for wholesale

customers.694

Comments

Some commenters contend that

stranded costs that result when a retail

customer becomes a wholesale customer

should be left to the states as a matter

of law and comity.695 These commenters

argue, among other things, that because

the facilities used to provide retail

service to these retail customers were

subject to state jurisdiction and were

included in retail rate base when the

service was rendered, the state is the

appropriate entity to determine the

extent to which those customers should

compensate the utility for the stranding

of these costs. According to ELCON, ‘‘(a)

retail customer’s new found access to

the wholesale market does not provide

FERC with authority over costs that

originated with the local distribution

function.’’ 696

Commenters assert that stranded costs

resulting from the creation of new

wholesale entities will occur as a result

of state or local decisionmaking.697 A

number of commenters contend that in

states where the state commission has

control over municipalization, the

Commission has no authority to provide

for the recovery of stranded costs due to

municipalization.698 IL Com asserts that

the Commission lacks authority over

retail-turned-wholesale stranded costs,

even in the absence of any explicit

statutory authority for state

commissions to address such costs. FL

Com argues that the Commission should

address the recovery of these stranded

costs only upon petition from a state

public utility commission.

According to some commenters, the

availability of open access transmission

tariffs does not convert the character of

the costs of stranded generation that was

built to serve retail customers from

retail to wholesale.699 CA Com argues

that this reasoning could require the

Commission to act as the primary forum

for stranded costs resulting from retail

wheeling if the Commission’s

jurisdiction over retail transmission is

upheld. It argues that in such a case,

there also would be a relationship

between the Commission-jurisdictional

transmission and stranded costs.

Some commenters also submit that

the potential for retail customers to

become wholesale customers has

existed since the beginning of the

industry and that utilities have had

ample opportunity to adjust to this

risk.700 A number of commenters submit
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21645

701E.g., American Iron & Steel, MD Com, LA

DWP, Suffolk County, MI Com, NJ BPU, N.Y.

Mayors. NASUCA cites practical problems posed by

the Commission’s proposal to assume jurisdiction

over stranded costs resulting from

municipalization, such as how the Commission

would transfer the revenues extracted from the

retail-turned-wholesale customer to a nonwholesale, locally-franchised entity.

702NARUC Initial Comments at 18–19.

703E.g., N.Y. Mayors, NIEP, Wing Group, VT DPS,

NY Industrials, American Iron & Steel,

Environmental Action, IN Industrials, Las Cruces,

Caparo, UT Industrials.

704E.g., IN Com.

705E.g., VT DPS, American Iron & Steel. American

Forest & Paper states that allowing stranded cost

recovery in the event of municipalization would be

inconsistent with the Commission’s actions in the

natural gas industry, where the Commission has

encouraged competition at the retail level (through

competitive bypass rather than franchise

competition) and has not imposed transition

charges or exit fees on converting customers.

706 VT DPS Initial Comments at 49; see also

American Iron & Steel, NY Industrials, Caparo.

707 63 FERC ¶ 61,212 (1993), reh’g denied, 64

FERC ¶ 61,087 (1993).

708See Massachusetts Electric Company, 68 FERC

¶ 61,101 (1994); Letter Order dated March 3, 1995,

Docket No. ER94–129–000 (approving settlement).

709E.g., EEI, PSE&G, Centerior, Com Ed,

Consumers Power, Detroit Edison, Duke, El Paso,

Entergy, LILCO, Minnesota Power, Montana-Dakota

Utilities, NYSEG, PECO, PG&E, PSNM, Southern,

Utilities For Improved Transition, Allegheny, OH

Com, Utilicorp, PA Com, WI Com, Coalition for

Economic Competition, Central Louisiana, United

Illuminating, Utility Investors Analysts, Nuclear

Energy Institute, Utility Shareholders.

710E.g., Consumers Power, Coalition for Economic

Competition, Utilities For Improved Transition.

711E.g., Detroit Edison, Minnesota Power, El Paso,

LILCO, Centerior, PG&E. PG&E urges a clarification

in the rule so that the Commission would address

retail-turned-wholesale stranded costs only if the

state commission either lacks jurisdiction over

municipal utilities, or, if it has jurisdiction,

declines to address stranded costs. Where a state

commission possesses jurisdiction over municipal

entities and provides a utility with stranded cost

recovery from former retail customers that have

municipalized, PG&E proposes that such action

should be final and not subject to Commission

review. Other commenters, such as El Paso, ask the

Commission to establish itself as the forum of last

resort when states do not provide for full recovery

of stranded costs.

712E.g., Coalition for Economic Competition, El

Paso.

that state commissions are in a better

position than the Commission to

address the recovery of costs that were

incurred to serve retail customers and to

take into consideration local

concerns.701

NARUC recognizes that a ‘‘practical

regulatory gap may exist that prevents

[state commission] consideration of

recovery of * * * potentially stranded

costs’’ in certain instances ‘‘such as

municipalization and cooperatives,

where retail customers become

wholesale customers under a FERCapproved open access tariff, [and] costs

of the utility which served the customer

at retail may become stranded.’’ 702

NARUC proposes that the affected states

and the Commission collaboratively

develop mechanisms (which may

involve amendments to the FPA, state

statutes, or both) to eliminate these

regulatory gaps.

Some commenters object that the

Commission’s proposal to be the

primary forum for recovery of stranded

costs caused by retail-turned-wholesale

customers would make

municipalization more expensive and

therefore would discourage

municipalities from seeking alternative

sources of electricity.703 Some argue that

different treatment of stranded costs

between federal and state authorities

may lead to forum-shopping as a

primary determinant in the decision to

municipalize.704

A number of commenters also suggest

that the NOPR is inconsistent with prior

Commission treatment of

municipalization because the

Commission has historically promoted

franchise competition between

municipalities and utilities and has

never before suggested that utilities

could ‘‘penalize’’ municipalization

decisions through generation cost addons to transmission rates.705 VT DPS

states: ‘‘By the Commission’s logic,

there would never have been an Otter

Tail case. If Otter Tail could have made

a stranded cost claim against the

municipal utility Elbow Lake planned to

create, Otter Tail would never have

needed to refuse to wheel.’’ 706

Suffolk County states that the

Commission already considered

stranded costs in the context of retailturned-wholesale customers in United

Illuminating Company,707 where the

Commission required United

Illuminating to remove a provision in its

proposed transmission tariff that would

have allowed it to recover stranded

costs associated with former retail loads

served by new municipal systems.

Suffolk County states that the

Commission made clear that stranded

cost matters, including those caused by

municipalization, properly would be

raised before state regulatory

authorities. It objects that the Open

Access NOPR ignores this case. Suffolk

County also submits that the

Commission’s adoption of the

settlement approved by the

Massachusetts DPU in the

Massachusetts Bay Transportation

Authority case should serve as an

example of proper jurisdictional

deference with respect to local issues.708

However, many other commenters

support the Commission’s proposal to

be the primary forum for retail-turnedwholesale stranded costs.709 These

commenters submit, among other

things, that the Commission’s

jurisdiction over such costs is clear.710

Coalition for Economic Competition

states that when a utility’s costs are

stranded through the availability of

Commission-jurisdictional transmission

service, the Commission must address

those costs. It argues that commenters

opposing the Commission’s jurisdiction

fail to analyze the Commission’s duty to

establish just and reasonable rates for

Commission-jurisdictional transmission

service.

A number of commenters support the

Commission’s proposal to address retailturned-wholesale stranded costs on the

basis that many state commissions

either lack authority to address costs

that are stranded because of expanding

or newly-created municipal systems, or

have failed to address such costs.711 El

Paso adds that any protection offered by

state judicial condemnation proceedings

does not obviate the need for the

Commission’s involvement in this issue,

noting that condemnation awards may

not provide full stranded investment

recovery under the Commission’s

standards. In addition, El Paso suggests

that municipalization may occur

through means other than

condemnation of the distribution

systems of electric utilities, such as

when a municipality constructs its own,

duplicative distribution facilities.

Several commenters also indicate that

by forthrightly addressing this issue, the

Commission has removed a cloud of

uncertainty that would have taken years

to resolve through litigation.712 El Paso

states that the proposed rule is needed

because utilities may be subject to

stranded costs resulting from

municipalization in two separate state

jurisdictions.

In response to the argument that

stranded costs are exclusively subject to

state jurisdiction, SoCal Edison asserts

that whether the costs are retail or

wholesale is irrelevant because the issue

is how and where these costs should be

recovered. According to SoCal Edison, if

the Commission finds that these costs

are just and reasonable costs associated

with providing open access

transmission service, the Commission

may allow utilities to recover them in

Commission-regulated rates.

Coalition for Economic Competition

notes that while utilities are aware of

state laws allowing municipalities to

condemn electric facilities and to form

utilities, in recent decades, it has not

happened on most systems. Moreover, it

argues that merely being on notice that

municipalization is a possibility does

not relieve utilities of their stateimposed obligation to serve all
21646 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

713E.g., EEI, Minnesota Power, Centerior, Public

Service Co of CO, SoCal Edison, Coalition for

Economic Competition. PG&E asks that we allow

utilities to seek recovery at the Commission for

stranded costs attributable to former retail

customers that have become customers of existing

public agencies or municipal utilities where such

costs cannot be collected at the state level.

714E.g., Centerior, Coalition for Economic

Competition, PG&E. Coalition for Economic

Competition proposes that the Commission accept

just and reasonable regional stranded cost recovery

mechanisms in such situations to enable regional

transmission associations (whether through pool

and interpool arrangements or regional

transmission groups) to collect through

Commission-filed rate schedules from

interconnected utilities charges equal to the costs

otherwise stranded as a result of Commissionjurisdictional service realignments.

715E.g., SoCal Edison, OH Com, NY Com, MI

Com, Coalition on Federal-State Issues.

716E.g., MI Com, NY Com, Ohio Com.

717PG&E proposes a similar approach, noting that

if there are differences in the stranded cost method

used by the Commission and the states, an

incentive may remain for retail customers to

municipalize merely to take advantage of more

favorable stranded cost treatment at the

Commission.

718Costs that are exposed to nonrecovery when a

retail customer or a newly-created wholesale power

sales customer ceases to purchase power from the

utility and does not use the utility’s transmission

system to reach a new generation supplier (e.g.,

through self-generation or use of another utility’s

transmission system) do not meet the definition of

‘‘wholesale stranded costs’’ for which this rule

provides an opportunity for recovery. Such costs

are outside the scope of this rule because such costs

would not be stranded as a result of the new open

access. See Section IV.J.12.

719We recognize that we took a different approach

to retail-turned-wholesale stranded cost recovery in

United Illuminating, where we suggested that state

and local regulatory authorities or the courts should

be able to provide an adequate forum to address

retail franchise matters, including recovery of

stranded costs caused by municipalization, but said

we would consider revisiting the question if United

Illuminating could demonstrate the lack of a forum.

63 FERC at 62,583–84. Since the issuance of that

decision, however, we have had an opportunity to

re-analyze the nature of the stranded cost problem

in cases where a retail customer becomes a

wholesale customer, including the potential that

there might not be a state regulatory forum for

recovery of such costs. In these circumstances, we

have determined that where such costs are stranded

as a result of wholesale open access transmission,

these costs should be viewed as wholesale stranded

costs and this Commission should be the primary

forum for addressing their recovery.

720The CA Com has asked that, ‘‘(t)o the extent

of FERC’s authority, it should assume jurisdiction

to fulfill a backstop role in case retail customers

evade a state-determined transition charge by

becoming retail customers of an entity not subject

to the state regulatory commission’s jurisdiction. In

assuming jurisdiction, the Commission should defer

to the state commission’s determination and

allocation of stranded costs for the departing retail

customer.’’ CA Com March 18, 1996 Response to

Supplemental Comments of PG&E.

customers in their franchise areas. It

asserts that utilities had to continue to

invest in plant to satisfy their duty to

serve. In addition, it submits that

utilities had a reasonable expectation

that they would continue to serve retail

load because, among other things, state

regulators set long amortization periods

of 30–40 years for depreciation rates.

Some commenters state that the

Commission also should ensure that

stranded costs are recovered when a

municipal utility annexes territory

served by another utility or otherwise

expands its service territory.713 A

number of commenters also urge the

Commission to ensure recovery of costs

that are stranded if a municipal utility

or a newly-formed wholesale or

municipal utility physically

interconnects to another utility or builds

new transmission or distribution

facilities to the municipal system.714

Several commenters believe that close

coordination between the Commission

and state regulators as to the calculation

of stranded costs is important in the

case of municipalization.715 A number

of state commissions suggest that the

Commission allow the states to set the

level of retail-turned-wholesale stranded

costs to be recovered in wholesale

transmission rates set by the

Commission.716 They submit that this

approach would respect state interests

in controlling the rate impact of

stranded costs, while allowing the

Commission to design cost recovery,

and would address the needs of

industrial customers and other

stakeholders by providing a forum

before state regulators who will be more

aware of their particular needs. Further,

they contend that this approach would

prevent relitigation of issues, minimize

forum-shopping, and prevent legitimate

and verifiable costs from falling through

the cracks or being double-recovered.717

NY Industrials asks the Commission to

clarify that utilities will not be allowed

to seek cost recovery at both the

Commission and state commissions.

Commission Conclusion

We reaffirm our preliminary

determination that this Commission

should be the primary forum for

addressing the recovery of stranded

costs caused by retail-turned-wholesale

customers. If such a customer is able to

reach a new generation supplier because

of the new open access (through the use

of a FERC-filed open access

transmission tariff or through

transmission services ordered pursuant

to section 211 of the FPA), we believe

that any costs stranded as a result of this

wholesale transmission access should

be viewed as ‘‘wholesale stranded

costs.’’ Such costs would not be

stranded but for the action of this

Commission (either through a

mandatory FPA section 205–206 open

access tariff or an order under FPA

section 211) in permitting the new

wholesale entity to become an

unbundled transmission services

customer of the utility and thereby to

obtain power from a new supplier.718

There is a clear nexus between the

FERC-jurisdictional transmission access

requirement and the exposure to nonrecovery of prudently incurred costs. In

these circumstances, we believe that

this Commission should be the primary

forum for addressing recovery of such

costs. To avoid forum-shopping and

duplicative litigation of the issue, we

expect parties to raise claims before this

Commission in the first instance.719

Some commenters have asked us also

to be the primary forum for stranded

cost recovery in situations in which an

existing municipal utility annexes

territory served by another utility or

otherwise expands its service territory.

We decline to do so because in these

situations there is no direct nexus

between the FERC-jurisdictional

transmission access requirement and the

exposure to non-recovery of prudently

incurred costs. The risk of an existing

municipal utility expanding its territory

was a risk prior to the Energy Policy Act

and prior to any open access

requirement.

Nevertheless, we are concerned that

there may be circumstances in which

customers and/or utilities could

attempt, through indirect use of open

access transmission, to circumvent the

ability of any regulatory commission—

either this Commission or state

commissions—to address recovery of

stranded costs.720 We reserve the right to

address such situations on a case-bycase basis.

As we indicated in the Supplemental

Stranded Cost NOPR, if the state has

permitted any recovery from departing

retail-turned-wholesale customers (for

example, if it imposed an exit fee prior

to, or as a condition of, creating the

wholesale entity), that amount will not,

in fact, be stranded, and we will deduct

that amount from the legitimate

stranded costs for which we will allow

recovery.

As discussed in Sections IV.J.8–IV.J.9,

we will require the same evidentiary

demonstration for recovery of stranded

costs from a retail-turned-wholesale

customer, and will apply the same

procedures for determining stranded

cost obligation, as that required in the

case of a wholesale requirements

customer.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21647

721As discussed in Section IV.I, the Commission’s

authority to address retail stranded costs derives

from its jurisdiction over the rates, terms and

conditions of unbundled transmission in interstate

commerce used by retail customers that obtain

retail wheeling. The states’ authority derives from

state jurisdiction over local distribution facilities

and over the service of delivering electric energy to

end users, and from the authority to impose, among

other things, retail exit fees and surcharges on local

distribution rates.

722We proposed to require the same evidentiary

demonstration for recovery of stranded costs from

a retail customer that obtains retail wheeling as that

required in the case of a wholesale requirements

customer. We also reaffirmed our proposal in the

initial Stranded Cost NOPR that a utility will have

to show that the stranded costs are not more than

the net revenues that the retail customer would

have contributed to the utility had it remained a

retail customer of the utility, and that the utility has

taken and will take reasonable steps to mitigate

stranded costs. FERC Stats. & Regs. ¶ 32,514 at

33,128.

723As we noted in the Supplemental NOPR, a

state may require payment of an exit fee before a

franchise customer is permitted to obtain

unbundled retail wheeling. If local distribution

facilities are used by a retail wheeling customer, the

state may allow recovery of stranded costs through

rates for use of such local distribution facilities. In

addition, as discussed in Section IV.I, because we

believe that states have authority over the service

of delivering electric energy to end users, not

merely the local distribution facilities themselves,

state authorities can assign stranded costs and

benefits through a local distribution service charge,

and may do so based on usage (kWh), demand (kW),

or any combination or method they find

appropriate. If a state decides not to take any of

these routes, it may consider whether to allow

recovery of stranded costs from remaining retail

customers or whether shareholders should bear all

or part of those costs. Id. at 33,129.

724 Id. at 33,129–30.

725 Id. at 33,098 n. 230.

726E.g., Utilicorp, Houston L&P, PG&E, Freedom

Energy Co, WI Com.

727E.g., EEI, EGA, Coalition for Economic

Competition, Utilities for Improved Transition,

Atlantic City, Arizona, Centerior, Com Ed, Detroit

Edison, El Paso, LILCO, NU, NSP, NYSEG, United

Illuminating, BG&E, Sierra, Southern, UT

Industrials, NRECA. NRECA argues that unless the

Commission addresses stranded costs caused by

retail wheeling where a state commission lacks

authority, or has authority but decides not to

exercise it, there could be a jurisdictional gap into

which many rural electric cooperatives could fall.

728E.g., CSW.

729E.g., EEI, Illinois Power, PSNM, Entergy,

Nuclear Energy Institute, Coalition for Economic

Competition.

730E.g., Coalition for Economic Competition,

Illinois Power, Utilities for Improved Transition,

EEI.

731EEI notes, for example, that as use of electrical

facilities shifts between retail and wholesale,

jurisdiction over the rates to recover the allocated

cost of service shifts between state commissions

and this Commission, and that the regulatory

authority is determined by the nature of the

transactions and the classification of the customer,

not the jurisdiction under which the costs originally

arose.

732E.g., Illinois Power, Utilities For Improved

Transition, EEI, Coalition for Economic

Competition.

733EEI Initial Comments at IV–13; see also

Coalition for Economic Competition Initial

Comments at 23–31.

734See also SoCal Edison.

7. Recovery of Stranded Costs Caused by

Retail Wheeling

In the Supplemental Stranded Cost NOPR,

we stated that both this Commission and

state commissions have the legal authority to

address stranded costs that result from retail

customers who obtain retail wheeling from

public utilities in order to reach a different

generation supplier.721 Because the vast

majority of commenters urged the

Commission not to assume responsibility for

retail stranded costs, except in certain

circumstances, we preliminarily concluded

that it is appropriate to leave it to state

regulatory authorities to deal with any

stranded costs occasioned by retail wheeling.

We proposed to entertain requests to recover

stranded costs caused by retail wheeling only

when the state regulatory authority does not

have authority under state law to address

stranded costs at the time when the retail

wheeling is required.722 In so doing, we

preliminarily accepted the view that stranded

costs caused by retail wheeling are primarily

a matter of local or state concern and thus,

with the limited exception discussed above,

generally must be recovered through retail

charges.

We noted that the states have a

number of mechanisms for addressing

stranded costs caused by retail

wheeling, one of which is a surcharge to

state-jurisdictional rates for local

distribution.723 We encouraged the

states to use the mechanisms available

to them to address stranded costs.724 We

also noted that the states may use their

jurisdiction over local distribution

facilities to address ‘‘stranded benefits,’’

such as environmental benefits

associated with conservation, load

management, and other demand side

management programs.725

Comments

A number of commenters support the

Commission’s proposal for addressing

stranded costs caused by retail

wheeling.726

Other commenters urge the

Commission to take a greater role in

retail stranded cost recovery and to

entertain requests to recover stranded

costs as a backstop where: (1) State

regulatory authorities have the authority

to address stranded costs but either

choose not to exercise that authority or

fail to permit full stranded cost

recovery; 727 or (2) the state

commission’s authority is unclear.728

Commenters that support a greater

Commission backstop role argue, among

other things, that because the

Commission has exclusive ratemaking

jurisdiction over any stranded cost

charges imposed ‘‘for or in connection

with’’ interstate transmission service by

public utilities, the Commission has an

obligation to regulate the recovery of

stranded costs from interstate retail

transmission customers.729 A number of

these commenters argue that the

determining factor is who has the

jurisdiction to review the rates for the

service, not who has the jurisdiction to

order the service.730 They explain that

the Commission has jurisdiction over

generating facilities and associated costs

to the extent appropriate to establish

just and reasonable rates for

jurisdictional services. They disagree

with other commenters who argue that

only the jurisdiction under whose

authority the costs were incurred and

initially recovered should have

authority to order recovery of stranded

costs.731

These commenters contend that the

Commission cannot abdicate its

regulatory responsibilities by either

deferring to the state commissions or

otherwise failing to independently

address the issue.732 EEI and the

Coalition for Economic Competition

refer to ‘‘a long line of cases (where) the

courts have held that where a federal

regulatory agency * * * is charged with

implementing a statutory framework,

that agency is without authority to

deviate from or abdicate its statutory

responsibilities.’’ 733 According to

Coalition for Economic Competition, for

example, the Commission could satisfy

its obligation to address stranded costs

that arise from retail wheeling by

allowing states to determine retail

stranded cost charges in the first

instance; to the extent that the state

allows full recovery, Coalition for

Economic Competition submits that the

Commission’s obligation would be

satisfied.

EEI asserts that it would be unduly

discriminatory and preferential for the

Commission to refuse to address all

stranded costs arising from retail

wheeling. According to EEI, the same

arguments that support the

Commission’s decision to address costs

that are stranded where retail load

municipalizes and where the state

regulatory authority, at the time retail

wheeling is required, lacks authority to

act, apply with equal force to all other

retail stranded costs. EEI submits that

the nexus in these cases is that

Commission-jurisdictional transmission

service is the means by which the costs

are stranded.734

Utility Working Group argues that the

NOPR inappropriately characterizes the

Commission’s jurisdiction over retail

stranded costs and that this could later

be used against the Commission’s

exercise of its full authority. According

to Utility Working Group, the NOPR

depicts the Commission’s jurisdiction as
21648 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

735Opinion 234, 31 FERC ¶ 61,305, on reh’g, 32

FERC ¶ 61,425 (1985).

736 875 F.2d 903 (D.C. Cir. 1989), cert. denied sub

nom. Mississippi v. FERC, 494 U.S. 1078 (1990).

737E.g., NU, Coalition for Economic Competition,

Illinois Power, EEI.

738E.g., NEPCO, EEI, Coalition for Economic

Competition, Entergy.

739E.g., LILCO, Coalition for Economic

Competition.

740E.g., NU, NSP, Illinois Power, Coalition for

Economic competition, PSE&G, Utilities For

Improved Transition, Philip Morris, EEI.

741Freedom Energy Co. rejects this argument on

the basis that state regulation has never been wholly

consistent and yet utilities have not asked for

federal unification of state ratemaking policies or

resolution of differences.

742E.g., PSNM, GA Com, Omaha PPD, Illinois

Power.

743E.g., CA Com, MD Com, VA Com, IN Com, NH

Com, NV Com, NY Com, OH Com, FL Com, AZ

Com, TX Com, ELCON, NY Industrials, NY AG, NY

Consumer Protection, MA DPU, Iowa Board, IN

Industrials, Texas Industrials, NM Industrials,

Reynolds, NYMEX, Legal Environmental

Assistance, CO Consumers Counsel, NJ Ratepayer

Advocate, IBM, ME Industrials, Jay, WEPCO, NH

General Court.

744E.g., NARUC, ELCON, NY Industrials, NM

Industrials, NV Com.

745 16 U.S.C. 824(a).

746See also Freedom Energy Co. Reply

Comments.

747E.g., ELCON, PA Com, NY Industrials, ND

Com, VA Com, NM Com.

being derived from state law (in other

words, the Commission will act where

state regulatory authorities have no

authority over retail stranded costs and

will not act where state regulatory

authorities have such authority). If the

Commission desires to afford substantial

deference to the states regarding retail

stranded costs, Utility Working Group

contends that the final rule should

reflect that policy determination;

however, the rule should not confuse

policy with jurisdiction by purporting to

place limits on, or attempting to waive,

the Commission’s jurisdiction over such

costs.

Entergy asserts that the Commission’s

jurisdiction over multi-state utilities

provides further support for our

jurisdiction over retail stranded costs in

certain contexts. Entergy states that

most of the eleven multi-state registered

holding company systems have some

form of Commission-jurisdictional

agreement that allocates production and

transmission costs among the systems’

affiliated operating companies. It asserts

that these agreements by their very

nature allocate costs among

jurisdictions (that is, between states).

Many of these agreements equalize the

cost of generating reserves among

affiliated operating companies, and such

reserve equalization formulas can shift

retail stranded costs among states unless

the Commission provides a regulatory

forum to address cost-shifting. Citing

Middle South Energy,735 and City of New

Orleans v. FERC,736 Entergy submits that

the Commission cannot sit on the

sidelines when it comes to stranded

retail costs on the Entergy system.

According to Entergy, Commission and

judicial precedent place on the

Commission the responsibility to ensure

that federally-approved costs and cost

allocations are not undermined by state

action.

Commenters also express concern that

it will not be possible to be sure that a

state regulatory authority has authority

over retail stranded costs until after

years of litigation. If the Commission

waits for the resolution of challenges to

state authority and a court holds that the

state regulatory authority is without

authority, these commenters assert that

the bar on retroactive ratemaking could

leave the states and the Commission

without a remedy to compensate

utilities for stranded costs.737 A number

of commenters suggest that while the

states should be allowed to set retail

wheeling stranded cost charges in the

first instance, the Commission should

accept filings to preserve a utility’s

ability to recover retail stranded costs

from the time the customer departs if

the state-authorized charges are not

upheld in court. They submit that this

would put customers on notice of the

potential for Commission action and

thereby avoid the retroactivity

problem.738

Some commenters express concern

that if the Commission does not take

more decisive action on retail wheeling

stranded costs, the result will be

wasteful litigation that will discourage

competition by causing financial

uncertainty and higher financing costs

for investor-owned utilities and higher

rates for consumers.739 Coalition for

Economic Competition also asserts that

stranded cost charges would be greatest

at the start of a retail wheeling program,

thereby making the years during which

the state-authorized charges are subject

to appeal more important for recovery

purposes.

A number of commenters support

Commission-established uniform

standards for, and uniform recovery of,

costs stranded as a result of open access

to the interstate transmission system.740

They argue that disparate state

treatment of stranded costs would be

economically inefficient and

discriminatory and would burden

interstate commerce.741 Several

commenters support state involvement

in the establishment of uniform

standards.742

In contrast to the commenters that

support a greater Commission role in

retail stranded cost recovery, NARUC

and a number of other commenters

oppose any Commission involvement in

retail stranded costs.743 These

commenters contend, among other

things, that the Commission lacks

authority over these costs. Even if the

Commission could assert such

jurisdiction, they argue that as a policy

matter it would be inappropriate for the

Commission to delve into complicated

legal and policy issues governed by

varying state regulatory regimes.

According to some of these

commenters,744 section 201(a) of the

FPA precludes an exercise of federal

jurisdiction over retail stranded cost

recovery because the Commission’s

jurisdiction extends ‘‘only to those

matters which are not subject to

regulation by the States.’’ 745 NM

Industrials argues that a lack of state

commission authority is an affirmative

state determination, either by act or

omission, that stranded costs must be

dealt with in a particular manner. It

submits that the Commission also lacks

authority over retail stranded costs

when states either decide not to address

such costs or, in the Commission’s

opinion, grant insufficient recovery of

stranded costs. NM Industrials asserts

that the language of the FPA and its

legislative history indicate that Congress

wanted to preclude Commission

jurisdiction in those areas where states

could exercise effective control, and that

this limitation covers all matters which

are or can be regulated by the states,

including the recovery of stranded

investment. NM Industrials also

suggests that assertion of Commission

jurisdiction would violate the provision

of section 212 of the FPA that prohibits

the Commission from interfering with

the states’ authority over the

transmission of energy directly to an

ultimate consumer.746

Other commenters argue that the

Commission’s proposed treatment of

retail stranded costs infringes on the

states’ jurisdiction over the allocation of

costs that were under their jurisdiction

when the costs were incurred.

According to these commenters, the

question of whether these costs should

be recovered from other retail

ratepayers, eliminated as excess

capacity, or billed in some fashion to

the customer now receiving wheeling

service are purely questions of state

ratemaking law.747 Some commenters

assert that, as a matter of policy, the

Commission should stay out of retail

stranded costs because only the states

have sufficient knowledge and expertise

regarding utility planning, investment,
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21649

748E.g., OH Com, NY Industrials, NM Com, IN

Com, WA Com, NV Com, NY Com, Suffolk County,

NY AG, Tonko, PA Industrials, NH General Court.

749E.g., OH Com, PA Com, NM Com, CA Com,

Blue Ridge.

750E.g., Nucor, AEC & SMEPA.

751E.g., NY Industrials, EGA, NJ BPU, Coalition

on Federal-State Issues.

752E.g., Iowa Board, Nevada Commission, CCEM;

see also NE Public Power District.

753E.g., IL Com, PG&E, Public Service Co of CO.

754E.g., NRECA, Wisconsin EC, EEI, PECO,

Missouri Basin Group.

755E.g., MT Com, Entergy.

756E.g., NARUC, Entergy Retail Regulators, MS

Com, Al Com.

757E.g., NARUC, MS Com.

758E.g., Homelessness Alliance, Black Mayors,

National Women’s Caucus, Vann, La Raza.

759NARUC and OH Com assert that, in

determining whether a wholesale transmission

transaction is a ‘‘sham,’’ the Commission should

consider a retail customer’s intent to bypass

responsibility for supporting social programs.

760E.g., Natural Resources Defense, NW

Conservation Act Coalition, Seattle, FTC, Northeast

States for Coordinated Air Use Management,

NARUC, OH Com. CO Com agrees that states should

have the option to fund such programs through the

imposition of surcharges on any form of electric

service used to benefit retail customers, including

surcharges on retail transmission rates. Seattle

proposes either a simple fee on kWhs or a

differential fee based on the type of resource and

its environmental affects. DOE urges the

Commission to work with state regulators to ensure

that states have the ability to recover stranded retail

costs and benefits in a way that prevents costshifting, forum-shopping, and uneconomic bypass

(including bypass of stranded benefits).

761CO Com notes that the NOPR proposes to limit

states to funding mechanisms that can be

implemented solely at the local distribution level,

presumably through the use of a surcharge on

distribution facilities or so-called ‘‘fee at the meter’’

or the use of a local distribution system revenue

decoupling mechanism. It suggests that neither of

these options may be legally or practically feasible

in many states for a wide variety of reasons (but

does not expand on these reasons).

762Natural Resources Defense proposes that the

Commission adopt the following language: ‘‘The

FPA does not affect state regulators’ jurisdiction to

apply distribution charges—either volume-based or

fixed—to electricity that is used by any utility

customer to provide end-use services (as

distinguished from electricity that is purchased for

resale to end-use customers).’’ Natural Resources

Defense Initial Comments at 3.

and forecasting to address these costs

adequately.748

Commenters also express concern that

the possibility of Commission

involvement in retail stranded cost

recovery will encourage forum-shopping

whenever state commission action is

unfavorable, even when states have

procedures to deal with stranded costs.

They argue that the result would be

endless litigation over where federal

jurisdiction ends and where state

jurisdiction begins. They suggest that if

a state fails to address retail stranded

cost recovery, the issue should be

addressed in court or in state

legislatures.749 OH Com contends that a

Commission policy that does not

recognize states’ authority over retail

stranded costs would be a disincentive

for states to permit retail wheeling.

A number of commenters argue that

recovery of retail stranded costs is not

directly implicated by any Commission

or Congressional action—that most such

costs would be created by retail

wheeling, which is not the subject of the

Commission’s open access initiatives—

and thus need not be dealt with as part

of the final rule.750

Commenters seek a number of

clarifications concerning the

Commission’s position on, and the

procedures for, retail stranded cost

recovery. A number of commenters ask

the Commission to clarify the states’

role with respect to retail stranded cost

recovery.751 Others address the type of

evidence required to establish that the

state regulatory authority lacks authority

to address stranded costs when retail

wheeling is required.752

Several commenters express concern

that customers receiving retail wheeling

not be able to evade state stranded cost

charges.753 IL Com says that the

Commission’s proposal for determining

whether facilities are state-jurisdictional

‘‘local distribution’’ facilities or

Commission-jurisdictional

‘‘transmission’’ facilities in interstate

commerce may not always provide a

state with the opportunity to recover

retail stranded costs through

distribution rate surcharges. It says that

the Commission does not offer any

assurances that the case-by-case

application of the proposed ‘‘functionaltechnical test’’ will result in a finding

that ‘‘local distribution’’ facilities are

used in all retail wheeling scenarios.

PG&E asks the Commission to provide

that all retail customers that opt for

direct transmission access by definition

take service over local distribution

facilities and therefore may be subjected

to a state-determined distribution rate

that includes stranded cost surcharges.

A number of commenters ask the

Commission to clarify that, in issuing

the final rule, the Commission is not

endorsing (either implicitly or

explicitly) retail wheeling.754

Several commenters express concern

that stranded costs may arise in one

state jurisdiction and be shifted to

another.755 For example, MT Com says

that an analysis confined to a state’s

boundaries may reveal no stranded

costs, but that such costs may indirectly

arise because of common pool revenue

recovery mechanisms, which may be the

largest source of stranded costs for some

utilities. Entergy raises a similar

concern in the context of holding

company or other multi-state situations.

It argues that denial of retail stranded

cost recovery by a state regulatory

authority could harm customers in other

states. Entergy proposes that, while state

regulators should be given the

opportunity in the first instance to

assure that stranded costs are recovered

and are not shifted to other states, the

Commission should allow utilities to

file retail wheeling tariffs with the

Commission to preserve the right to seek

recovery from the Commission.

Several commenters oppose Entergy’s

proposal.756 Among other things, they

argue that the FPA does not authorize

the Commission to act as an appellate

court over retail regulators. They assert

that, in the case of a multi-state holding

company system, it is the Commissionjurisdictional intra-system agreement

(not a state’s decision as to recovery of

retail stranded costs) that determines

the allocation of costs at wholesale

among the affiliates. Several of these

commenters suggest that if the holding

company believes that, as a result of a

state’s disallowance of costs in retail

rate base, the cost allocations under an

intra-system agreement are unduly

discriminatory, the holding company

could propose to amend the

agreement.757

A number of commenters also express

concern that services that investorowned utilities provide to promote

energy efficiency and conservation and

to assist low-income residents and the

elderly be continued.758 NW

Conservation Act Coalition suggests that

the Commission should condition

stranded cost recovery upon a showing

by the utility that allowing recovery will

not strand such social benefits.759

Various commenters endorse the use

by state regulators of a distribution

charge or other fee imposed on

electricity consumption to address

stranded social benefits.760 NARUC and

OH Com express concern that the

Commission, by claiming authority over

unbundled retail transmission services,

may make it difficult for states to use

non-bypassable ‘‘wires charges’’ or

‘‘access fees’’ to require all customer

classes to support such programs.761

NARUC asks the Commission to ensure

that any jurisdiction we exercise over

unbundled transmission services does

not legally or practically foreclose the

ability of individual states to fund such

programs.762 LILCO, as part of its

argument that the Commission should

provide a complete backstop for

stranded cost recovery resulting from

retail wheeling, urges the Commission

to establish retail wheeling rates that

provide for full recovery of any stranded

costs, including stranded social benefits,
21650 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

763 ‘‘State regulatory authority’’ has the same

meaning as provided in section 3(21) of the FPA.

764We reject the arguments of EEI and Coalition

for Economic Competition that the Commission

made findings in the initial stranded cost NOPR

that ‘‘inexorably’’ lead to the conclusion that

Commission action providing full recovery of retail

stranded costs is required. Their reliance on

Williams Natural Gas Company v. FERC, 872 F.2d

438 (D.C. Cir. 1989), appeal after remand, 943 F.2d

1320 (D.C. Cir. 1991) (Williams), is simply

misplaced. Williams involved a rulemaking that

was terminated by the Commission. The court

stated that the Commission, ‘‘having expressed

these tentative views (that the incentive price for

tight formation gas would disserve the public

interest) and having solicited comments on the

issue, was not free to terminate the rulemaking’’

without providing a satisfactory explanation. 872

F.2d at 446, 450. Here, in contrast, we are issuing

a Final Rule that reaffirms in many respects

preliminary findings proposed in both the initial

and Supplemental Stranded Cost NOPRs. Although

the conclusion we reach based on those findings

may be different than that which some commenters

advocate, we have fully explained the basis for our

decision.

765 In these circumstances, the cases cited by

commenters to support the proposition that an

agency is not authorized to abdicate its statutory

responsibilities or to delegate to parties and

intervenors regulatory responsibilities (such as

preparation of an environmental impact statement)

are factually distinguishable and inapposite. See,

e.g., FPC v. Texaco, 417 U.S. 380, 394 (1974)

(Commission cannot exempt small-producer rates

from compliance with just and reasonable

standard); United States v. City of Detroit, 720 F.2d

443, 451 (6th Cir. 1983) (district court

inappropriately implied waiver of EPA statutory

duty under Title II of the Federal Water Pollution

Prevention and Control Act); State of Idaho v. ICC,

35 F.3d 585, 595–96 (D.C. Cir. 1994) (an agency

cannot abdicate its NEPA responsibilities in favor

of the regulated party).

766As discussed in the Supplemental NOPR

(FERC Stats. & Regs. ¶32,514 at 33,129–30), these

mechanisms include requiring an exit fee before a

franchise customer is permitted to obtain

unbundled retail wheeling and imposing a

surcharge on local distribution rates. Commenters

identified several other possible mechanisms in

response to the initial Stranded Cost NOPR.

767As we stated in the Supplemental NOPR, we

do not address whether states have the lawful

authority to order retail wheeling in interstate

commerce. Id. at 33,098 at n.228. In addition, we

are neither endorsing nor discouraging retail

wheeling.

768See id. at 33,098, 33,127–28.

that are unrecovered after state stranded

cost determinations.

Commission Conclusion

We believe that both this Commission

and the states have the legal authority

to address stranded costs that result

when retail customers obtain retail

wheeling in order to reach a different

generation supplier, and that utilities

are entitled, from both a legal and a

policy perspective, to an opportunity to

recover all of their prudently incurred

costs. This Commission’s authority to

address retail stranded costs is based on

our jurisdiction over the rates, terms,

and conditions of unbundled retail

transmission in interstate commerce.

The authority of state commissions to

address retail stranded costs is based on

their jurisdiction over local distribution

facilities and the service of delivering

electric energy to end users. However,

because it is a state decision to permit

or require the retail wheeling that

causes retail stranded costs to occur, we

will leave it to state regulatory

authorities to deal with any stranded

costs occasioned by retail wheeling. The

only circumstance in which we will

entertain requests to recover stranded

costs caused by retail wheeling is when

the state regulatory authority 763 does

not have authority under state law to

address stranded costs when the retail

wheeling is required.

Commenters that describe our action

as an unlawful abdication or delegation

of authority misconstrue the nature of

our decision to leave retail stranded

costs (with a limited exception) to state

regulatory authorities.764 We have not

‘‘abdicated’’ or ‘‘delegated’’ to state

regulatory authorities our jurisdiction

over the rates, terms, and conditions of

retail transmission in interstate

commerce; if retail transmission in

interstate commerce by a public utility

occurs, public utilities offering such

transmission must comply with the FPA

by filing proposed rate schedules under

section 205. Instead, we have made a

policy determination that the recovery

of retail stranded costs—an issue over

which either this Commission or state

commissions could exercise authority

by virtue of their jurisdiction over retail

transmission in interstate commerce and

over local distribution facilities and

services, respectively—is primarily a

matter of local or state concern that

should be left with the state

commissions. However, if the state

regulatory authority does not have

authority under state law to address

stranded costs when the retail wheeling

is required, then we will entertain

requests to recover such costs.765

Because we have accepted the view

that stranded costs caused by retail

wheeling are primarily a matter of local

or state concern, we will not allow the

states to use the interstate transmission

grid as a vehicle for passing through any

retail stranded costs, with the following

limited exception. If the state regulatory

authority does not have authority under

state law when the retail wheeling is

required to resolve the retail stranded

cost issue, we will permit a utility to

seek a customer-specific surcharge to be

added to an unbundled transmission

rate.

We believe that most states have a

number of mechanisms for addressing

stranded costs caused by retail

wheeling.766 In addition, as further

discussed in Section IV.I, we are

defining in this rule ‘‘facilities used in

local distribution’’ under section

201(b)(1) of the FPA. Rates for services

using such facilities to make a retail sale

are state-jurisdictional, and states will

be free to impose stranded costs caused

by retail wheeling on facilities or

services used in local distribution.

States may also use their jurisdiction

over local distribution facilities or

services to recover so-called stranded

benefits. This rule is not intended to

preempt any existing state authority to

assess a stranded cost or stranded

benefits charge on a retail customer that

obtains retail wheeling. Moreover, since

the charge is state jurisdictional, it is of

no moment to our responsibilities under

the FPA as to whether such charges are

volume-based (kWh), demand-based

(kW), or customer-based (fixed).

We believe that our approach to retail

wheeling stranded costs represents an

appropriate balance between federal and

state interests. This approach ensures

that the rates for transmission in

interstate commerce by public utilities

(except in a narrow circumstance) will

not be burdened by retail costs. It also

helps to ensure that one state will not

be able to impose costs stranded by its

ordering of retail wheeling 767 on

customers in another state.768 In a

holding company or other multi-state

situation, we recognize that denial of

retail stranded cost recovery by a state

regulatory authority could, through

operation of the reserve equalization

formula in a Commission-jurisdictional

intra-system agreement, inappropriately

shift the disallowed costs to affiliated

operating companies in other states. The

Commission is concerned about this

potential for cost-shifting. We would not

wish to see an intra-system agreement

used as a means for one jurisdiction to

shift to other jurisdictions retail

stranded costs for which it would

otherwise be responsible under that

agreement. However, we will deal with

such situations if they arise pursuant to

public utility filings under section 205

or complaints under section 206. Thus,

the need to amend a jurisdictional

agreement to prevent retail stranded

costs from being shifted to customers in

other states will be addressed on a caseby-case basis. We encourage the affected

state commissions in such situations to

seek a mutually agreeable approach to

this potential problem. If such a

consensus solution resulted in a filing to

modify a jurisdictional agreement, we

would accord such a proposal

deference, particularly if other

interested parties support the filing. In

the event that the state commissions and
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21651

769See Public Utilities Commission of the State of

California v. FERC, 988 F.2d 154, 163–66 (D.C. Cir.

1993).

770FERC Stats. & Regs. ¶ 32,514 at 33,117.

771 Id. at 33,118.

772 Id. at 33,128.

773E.g., Carolina P&L, CSW, Duke, Utilities for

Improved Transition, Montaup, TVA,

MidAmerican. MidAmerican states that, for years,

utilities have entered into wholesale contracts

containing termination notice provisions and, for

years, customers have renewed and renegotiated

those contracts. Duke agrees that more important

indications of the utility’s reasonable expectation of

continuing to serve the customer can be found

where the service has been included in the IRP

process or the contract has been repeatedly

renewed. Orange & Rockland proposes that there be

a rebuttable presumption of recovery for longstanding (at least 10 years) contracts between utility

affiliates on the basis that the existence of a longstanding relationship is of greater significance than

a notice provision.

774E.g., CSW, IN Com.

775E.g., El Paso, Utilities For Improved

Transition.

other interested parties cannot reach

consensus that would prevent cost

shifting, the Commission would

ultimately have to resolve the

appropriate treatment of such stranded

costs.

Should a situation arise in which a

state regulatory authority concludes that

it has no ability to address retail

stranded costs, or the appropriate state

courts ultimately determine that a state

regulatory authority does not have

authority to impose retail stranded

costs, a utility may seek recovery here

through its Commission-jurisdictional

retail transmission rates of costs

stranded as of the date of the customer’s

departure. Because all parties are put on

notice by this Rule of the potential for

recovery through Commissionjurisdictional retail transmission rates

should state commission-authorized

retail wheeling charges be invalidated,

such recovery (if allowed) would not be

retroactive ratemaking.769

8. Evidentiary Demonstration

Necessary—Reasonable Expectation

Standard

In the Supplemental Stranded Cost

NOPR, the Commission made a

preliminary determination that a public

utility or transmitting utility seeking to

recover stranded costs must

demonstrate that it had a reasonable

expectation of continuing to serve a

customer. We indicated that the

existence of a notice of termination

provision in a wholesale requirements

contract creates a rebuttable

presumption that the utility had no

reasonable expectation of serving the

customer beyond the period provided

for in the notice provision.770 We

proposed not to adopt a minimum

notice period for purposes of applying

the rebuttable presumption. This was

because whether a utility has a

reasonable expectation of continuing to

serve a customer, and for how long,

including whether there is sufficient

evidence to rebut the presumption that

no such expectation existed beyond the

notice provision in the contract, will

depend on the facts of each case.

We sought further comment

concerning whether the reasonable

expectation standard should apply if a

utility has been making wholesale

requirements sales to a customer in a

non-contiguous service territory and

where, in order to make such a sale

possible, transmission service has been

rendered by an intervening utility. We

asked whether the Commission should

take this as conclusive evidence that the

customer had a choice of wholesale

suppliers and, therefore, that the seller

had no reasonable expectation that the

contract would be extended. We further

asked should we choose to provide the

seller with an opportunity to prove that

it had a reasonable expectation, what

weight should be given to the fact that

transmission service was rendered by

the intervening utility. If the seller

establishes that it had a reasonable

expectation, and the former wholesale

customer does not take unbundled

transmission service from the former

seller, we asked what if any means

ought to be available for the collection

of stranded costs.771

We also proposed to require the same

evidentiary demonstration for recovery

of stranded costs from a retail-turnedwholesale customer or a retail customer

that obtains retail wheeling as that

required when a wholesale

requirements customer leaves a utility’s

system. We proposed that the utility

must demonstrate that it incurred

stranded costs based on a reasonable

expectation that the customer would

continue to receive bundled retail

services. We anticipated that the

reasonable expectation test would be

easily met in those instances in which

state law awards exclusive service

territories and imposes a mandatory

obligation to serve. We requested

comments on these proposals.772

Comments

a. Rebuttable Presumption

Some commenters oppose treating a

notice provision as a rebuttable

presumption that the utility had no

reasonable expectation of continuing to

serve a customer. Commenters

representing the financial community

(Utility Shareholders and Utility

Investors Analysts), for example, state

that investment in generation and other

costs incurred in providing utility

service have not been tied to notice

provisions. Based on the use of notice

provisions in the past, and their

infrequent use for termination, they

state that the financial community has

not viewed notice provisions as a

determinant of the financial basis of

investment in the industry.

Other commenters also argue that the

Commission interprets the intent behind

termination notice provisions too

narrowly. These commenters submit

that the Commission should examine on

a case-by-case basis whether a notice

provision demonstrates a sufficient

meeting of the minds between the

parties that there was no reasonable

expectation that the contract would be

extended.773 TVA notes that the

existence of a notice provision in its

contracts in no way implies that

continued service would not be

expected.

A number of commenters 774 note that

some utilities have ‘‘evergreen’’

contracts that remain in effect

indefinitely unless either party gives

notice that it intends to terminate the

contract. They argue that, with no date

certain for termination, the provider of

bundled service must proceed on the

assumption that it will have to meet its

contract obligations on a continued

basis. CSW recommends that the

Commission limit the rebuttable

presumption standard to contracts that

contain a fixed contract termination

date. IN Com suggests that where a

contract contains an evergreen

provision, the Commission should

consider how often the contract has

been automatically renewed and the

length of the notice period.

A number of commenters suggest that

the following factors should be

conclusive proof of a reasonable

expectation (or sufficient to

conclusively rebut the presumption of

no reasonable expectation): (1) An

obligation under statute, certificate of

public convenience and necessity, order

or otherwise, granted to the utility to

provide service to the area that includes

the customer; (2) participation by the

customer in regulatory proceedings that

defer the utility’s complete recovery of

the costs associated with existing

investment to a later period; or (3)

service under a wholesale rate that

averaged the cost of all of a utility’s

generation resources, both long-term

and short-term.775 Utilities For

Improved Transition maintains that a

customer whose rates were based on the

totality of a utility’s resources, including

those with long life expectancies,
21652 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

776See, e.g., ELCON, NRECA, APPA, American

Forest & Paper, Central Montana EC, Municipal

Energy Agency Nebraska, Arkansas Cities, Direct

Service Industries, Atlantic City, TDU Systems,

Fertilizer Institute, LG&E, ABATE, Oglethorpe.

777E.g., TAPS, Missouri Joint Commission,

Detroit Edison Customers, LEPA, APPA, Cleveland.

778According to LEPA, the normal set of NRC

license conditions included an explicit wheeling

commitment and many of the license conditions

clearly referenced the possibility that the wheeling

commitment would lead to the loss of customers to

whom the utility had been selling bulk power

supply as well as retail power. LEPA submits that

acceptance of such license conditions should have

ended any reasonable expectation that a utility

might have had of continuing to serve a full

requirements customer, wholesale or retail, after the

termination of its contract.

779See FERC Stats. & Regs. ¶ 32,514 at 33,117.

780E.g., TAPS, Phelps Dodge. Phelps Dodge

suggests that evidence of past contract renewals, by

itself, should not serve to rebut the presumption

that the utility has no reasonable expectation of

contract renewal in the future.

781 In contrast, EEI believes that lack of access to

alternative suppliers can be evidence that a utility

reasonably expected to continue to serve a

customer.

782 If the investment now alleged to be stranded

was incurred after the most recent amendment or

extension to the contract, TAPS would focus the

reasonable expectation review on such later date.

783E.g., IL Com, Utilicorp, PSG&E, NM

Industrials.

784 453 U.S. 571 (1981).

785E.g., Florida Power Corp, Consumers Power,

FL Com, TDU Systems.

cannot claim that the governing

expectation was that the utility would

serve the customer only for a period of

one to three years.

Other commenters, in contrast, assert

that the rebuttable presumption does

not go far enough. These commenters

submit that a notice of termination

provision should create a conclusive

presumption that a utility had no

reasonable expectation of continuing to

serve a customer beyond the notice

period.776 Some commenters 777 also

support a conclusive presumption of no

reasonable expectation where one or

more of the following grounds are

present: (1) An explicit termination

provision, regardless of the length of the

pre-termination notice period; (2) an

explicit provision for decreasing service

or switching to partial requirements

service; (3) a pre-existing transmission

tariff or transmission service schedule;

(4) NRC license conditions providing for

transmission service or pooling

rights; 778 (5) a municipal joint action

agency or G&T cooperative with

authority to supply the wholesale load

in question; (6) a fixed-term contract; (7)

membership in a power pool that

provides access to regional markets; (8)

a contract entered into after passage of

the Energy Policy Act; or (9) other

evidence of an ability to seek alternative

suppliers. Several of these commenters,

such as TAPS and Detroit Edison

Customers, submit that a conclusive,

irrebuttable presumption would

decrease the number of disputes over

stranded cost issues.

Several comments were submitted

concerning the examples listed in the

NOPR that the Commission suggested,

depending on all of the facts and

circumstances, could establish a

reasonable expectation that a contract

would be extended. These examples

include lack of access to alternative

suppliers, repeated contract renewals,

failure of a customer to object to the

imposition of construction-work-inprogress, or communications between

supplier and customer concerning

including the customer’s load in system

planning.779 Some commenters argue

that evidence of this type should not be

enough to rebut the presumption (or to

overcome a summary judgment motion

based on the presumption) of no

reasonable expectation for contracts

with notice provisions.780 ELCON

objects to using a customer’s lack of

alternative supply as evidence of a

continued service obligation; it submits

that the historic lack of supply

alternatives has been caused by undue

exercise of market power and should

not be rewarded.781 Las Cruces suggests

that if lack of opposition to

construction-work-in-progress

evidences a reasonable expectation of

continued service, continuous

opposition should evidence a

reasonable expectation that the

customer will depart a system at the

earliest possible date. With regard to the

Commission’s suggestion that

communications with the customer on

the customer’s future plans could

establish reasonable expectation, Direct

Service Industries submits that no

claimed reliance should be deemed

reasonable unless the seller obtained

express assurances from the customer

that the customer intended to continue

to purchase power from the seller

beyond its current contract.

We also received comments on the

time at which the reasonable

expectation had to exist. TAPS urges

that the Commission should focus on

whether a utility had a reasonable

expectation of continued service when

it entered into the most recent

execution, renewal or amendment of the

power supply contract.782 PSE&G, on

the other hand, argues that the focus of

the Commission’s review should be

whether, at the time of incurring or

obligating itself to incur the cost of

serving a customer, the utility had a

reasonable expectation of serving that

customer for its planning horizon.

b. Application of Reasonable

Expectation Standard to NonContiguous Service Territory

Some commenters discuss the

situation in which a utility has been

making wholesale requirements sales to

a customer in a non-contiguous service

territory and, in order to make such a

sale possible, transmission service has

been rendered by an intervening utility.

They argue that this situation presents

conclusive evidence that the customer

had a choice of wholesale suppliers and,

therefore, that the seller had no

reasonable expectation that the contract

would be extended.783 Direct Service

Industries submits that if a customer has

power supply options that do not rely

on access to the selling utility’s

transmission system, the selling utility

could have had no reasonable

expectations other than those expressly

created by contract. NM Industrials

submits that allowing recovery of

stranded costs in this situation would

also constitute retroactive ratemaking in

violation of Arkansas Louisiana Gas

Company v. Hall.784 It argues that by

assessing stranded costs at the close of

a contract’s term against customers that

do not even need a generating utility’s

transmission services to leave its

system, the Commission would

retroactively alter the terms and

conditions of the rates for generation

negotiated between the parties and

approved by the Commission.

Other commenters submit that in

these circumstances the Commission

should give the supplier the opportunity

to prove that it had a reasonable

expectation that it would continue to

serve the customer.785 ELCON and

WP&L state that the reasonable

expectation standard should be satisfied

(or not) by reference to the parties’

existing contract, regardless of whether

the customer is in a contiguous service

territory.

Utility Investors Analysts asserts that

a seller will always have a reasonable

expectation that a business relationship

can be continued with a current

customer and that the better

presumption would be that the contract

will be extended unless evidence to the

contrary exists.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21653

786E.g., PA Com, Com Ed, CSW, United

Illuminating, UFIT, PSNM, TDU Systems.

787E.g., Com Ed, Central and Southwest, United

Illuminating, Utilities For Improved Transition,

Utility Investors Analysts, Utility Shareholders.

788E.g., EEI, Minnesota Power, PECO, Puget,

Centerior, Florida Power Corp, FL Com, Southern,

SoCal Edison, NEPCO, Consumers Power, Coalition

for Economic Competition. NEPCO asserts that the

Supplemental Stranded Cost NOPR does not cite

any comments or evidence casting doubt on the

Commission’s initial proposal (in the initial

Stranded Cost NOPR) not to apply the reasonable

expectation test to retail-turned-wholesale or retail

customers that obtain retail wheeling on the basis

that utilities operating under an obligation to serve

at retail necessarily have an entitlement to recover

the costs prudently incurred in fulfillment of that

obligation.

789E.g., EEI, Detroit Edison, Centerior, Consumers

Power, Ohio Edison.

790E.g., Wing Group, Alma, Total Petroleum,

Cleveland, ABATE, N.Y. Mayors, CAMU, Suffolk

County.

791E.g., Wing Group, Total Petroleum, ABATE,

CAMU, NY Mayors. Proposals advanced by

commenters to address non-exclusive franchises

include suggestions that the Commission:

summarily reject claims to recover retail stranded

costs where the utility has a non-exclusive

franchise and historically has been subject to retail

competition (e.g., Cleveland); apply a rebuttable

presumption that a utility had no reasonable

expectation of continued service where a municipal

franchise is expiring and the municipality has put

the retail supplier on notice that the municipality

may seek an alternative source of power supply

(e.g., Las Cruces); or provide that no stranded cost

claim will be entertained absent a showing, by

reference to applicable state law, that the utility had

an exclusive service franchise obligation or was

otherwise subject to an obligation to serve the

customer that is departing its system (e.g., Phelps

Dodge).

792E.g., Utility Working Group, SoCal Edison,

Florida Power Corp, PG&E. Referring to the

Commission’s statement that it expects the

reasonable expectation test to be easily met in those

instances in which state law awards exclusive

territories and imposes a mandatory obligation to

serve, Utility Working Group asks the Commission

to make clear in the final rule that it did not intend

by that example that utilities with non-exclusive

service territories would be presumed to fail the

reasonable expectation test. According to Utility

Working Group, the focus of the test must be on the

utility’s obligation to serve, which may be separate

from any franchise arrangements.

793The examples that the Commission provided

in the Supplemental NOPR of possible ways to

establish reasonable expectation were not intended

to be dispositive of the issue. As we make clear in

this Rule, whether a particular utility had a

reasonable expectation that a contract would be

extended will depend on all of the facts and

circumstances.

794However, if the remote customer does not use

the former supplying utility’s open access tariff to

reach the new supplier, there would be no

‘‘wholesale stranded costs’’ as that term is defined

in this Rule. In this situation, we would not allow

extra-contractual recovery of stranded costs. Thus,

there would be no need to address reasonable

expectation. See Section IV.J.12.

795The same procedures would apply to retail

customers that obtain retail wheeling.

c. Application of Reasonable

Expectation Standard to Retail-TurnedWholesale Customers or To Retail

Wheeling

A number of commenters support the

Commission’s proposal to apply the

reasonable expectation standard in these

cases.786 PA Com submits that the caseby-case analysis contemplated by the

Commission for establishing a utility’s

reasonable expectation of continuing to

serve a wholesale requirements

customer should also apply in the case

of a retail-turned-wholesale customer or

a retail customer that obtains retail

wheeling.

Some commenters believe that the

reasonable expectation test would be

easily met in those instances in which

state law awards exclusive service

territories and imposes an obligation to

serve.787 Some contend that the

reasonable expectation standard should

be presumed met in these circumstances

because state law obligates a utility to

serve all retail customers. A number of

commenters assert that such a

presumption would obviate the need for

case-by-case showings concerning the

expectations of each utility and the

nature of each franchise.788 At a

minimum, several commenters propose

that the Commission adopt a rebuttable

presumption that utilities had an

obligation to serve retail customers and

therefore that the reasonable expectation

test is met in a retail-turned-wholesale

customer scenario or in the case of costs

stranded as a result of retail wheeling.789

On the other hand, a number of

commenters argue that there is no basis

for a utility to reasonably expect that it

will continue to serve a particular

customer in states where franchises are

non-exclusive.790 Several of these

commenters argue that a utility

operating under a non-exclusive

franchise is faced with the ever-present

prospect that the communities it serves

may build their own systems.791

Other commenters oppose the

suggestion that the reasonable

expectation test cannot be met where a

franchise is non-exclusive or has

terminated.792 They argue that a utility’s

obligation to serve retail customers

arises under state laws independent of

the franchise. SoCal Edison explains

that in states such as California, a

franchise is nothing more than the

source of a utility’s right to use the city’s

streets, poles, rights of way, etc., and

that a utility’s duty to serve extends to

all customers within its certificated

service territories and not simply to

those areas in which it has a franchise.

Commission Conclusion

We reaffirm that a utility seeking to

recover stranded costs must

demonstrate that it had a reasonable

expectation of continuing to serve a

customer. Whether a utility had a

reasonable expectation of continuing to

serve a customer, and for how long, will

be determined on a case-by-case basis,

and will depend on all of the facts and

circumstances.793

Further, we will apply the reasonable

expectation standard in those cases

where a utility has been making

wholesale requirements sales to a

customer in a non-contiguous service

territory and, in order to make such a

sale possible, transmission service has

been rendered by an intervening utility.

We believe it is appropriate to give the

utility an opportunity to prove that it

had a reasonable expectation of contract

renewal in circumstances in which the

remote customer becomes an unbundled

transmission services customer of the

former supplier.794

We also reaffirm our determination

that the existence of a notice provision

in a contract creates a rebuttable

presumption that the utility had no

reasonable expectation of serving the

customer beyond the specified period.

Whether or not a contract contains an

‘‘evergreen’’ or other automatic renewal

provision will be a factor to be

considered in determining whether the

presumption of no reasonable

expectation is rebutted in a particular

case.

We will not adopt a minimum notice

period for purposes of applying the

reasonable expectation rebuttable

presumption. Whether a utility had a

reasonable expectation of continuing to

serve a customer, including whether

there is sufficient evidence to rebut the

presumption that no such expectation

existed beyond the notice provisions in

a contract, will depend on the facts of

each case.

In addition, we reaffirm our

preliminary determination to apply the

reasonable expectation standard to

retail-turned-wholesale customers. In

this scenario, before the Commission

will permit a utility to recover stranded

costs, the utility must demonstrate that

it incurred such costs based on a

reasonable expectation that the retailturned-wholesale customer would

continue to receive bundled retail

service. Whether the state law awards

exclusive service territories and imposes

a mandatory obligation to serve would

be among the factors to be considered in

determining whether the reasonable

expectation test is met in a particular

case.795

We further note that we are not

addressing in this Rule who will bear

the stranded costs caused by a departing

generation customer if the Commission

finds that the utility had no reasonable

expectation of continuing to serve that
21654 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

796FERC Stats. & Regs. ¶ 32,507 at 32,872.

797 Id. at 33,121.

798 Id.

799 Id. at 33,123. We also asked how revenues

received as a result of mitigation measures should

be reflected in the determination of the amount of

recoverable stranded costs; what special accounts,

if any, should be created to track revenue liability

for specific customers, revenues from mitigation

measures, and other revenues received by the utility

that offset the stranded cost liability; whether any

adjustment should be permitted to the revenues that

the utility claims will be realized in a competitive

market for its stranded assets, and if so, how often

and under what circumstances. Further, we sought

comments on whether there are special costs that

warrant some special consideration in the

determination of stranded cost liability under a

revenues lost approach, and if so, how they should

be treated. Id. at 33,121–22.

800 Id. at 33,122.

801 Id. at 33,114–15.

802 Id. at 33,115.

803E.g., Centerior, NYSEG, Florida Power Corp,

Houston L&P, NIMO, Orange & Rockland, Com Ed,

PSE&G, EEI, PECO, Texas Utilities, PG&E, SoCal

Edison, Dayton P&L, El Paso, IL Com, United

Illuminating, Nuclear Energy Institute.

804E.g., LG&E, TAPS, TDU Systems, ABATE, Blue

Ridge, NY Energy Buyers, WP&L, PA Com, KY Com,

American National Power, ELCON, Texaco, UT

Com, NARUC, NIEP, DE Muni, Reynolds,

Knoxville, Alma, APPA, NY Industrials, IL

Industrials, SC Public Service Authority, Caparo,

American Forest & Paper.

805E.g., NIEP, DE Muni and TDU Systems.

806E.g., SC Public Service Authority, ABATE, NY

Energy Buyers, NARUC, ELCON, American Forest

and Paper, APPA.

807E.g., NARUC, NYSEG.

808E.g., NRECA, NIEP, TDU Systems.

customer. As we suggested in the initial

Stranded Cost NOPR,796 we anticipate

that, in such a case, a public utility will

seek in subsequent requirements rate

cases to have the costs reallocated

among the remaining customers on its

system. However, we will not prejudge

that issue here.

9. Calculation of Recoverable Stranded

Costs

In the Supplemental Stranded Cost

NOPR, the Commission proposed that

the determination of recoverable

stranded costs be based on a ‘‘revenues

lost’’ approach. Under this approach,

stranded costs are calculated by

subtracting the competitive market

value of the power the customer would

have purchased from the revenues that

the customer would have paid had it

stayed on the utility’s generation

system. We cited several benefits that

we believe a ‘‘revenues lost’’ approach

offers over a hypothetical cost-of-service

approach, including avoidance of an

asset-by-asset review, minimization of

cost allocation procedures, and ease of

application.797

We sought comments on how to

calculate what the utility’s revenue

stream would have been had the

customer continued service. We also

sought comments on how to calculate

the revenues that the utility would

receive in a competitive market for the

stranded assets. This included whether

we should require the utility to track the

actual selling price of the power over

time or require the utility to use an upfront approach (such as an estimate of

the forecasted market value of the power

for the period during which the

customer would have taken service). We

asked whether we should allow prices

in futures markets or forward markets to

be used in an up-front approach,

assuming such financial instruments

become available.798

We suggested that the revenues lost

approach automatically takes account of

mitigation measures because it reduces

the amount of stranded costs

recoverable by a utility by the market

price of the power that the customer no

longer takes. We noted that this is

particularly so if mitigation is reflected

through a one-time, up-front estimate of

the future market value of the power

and is not trued up over time. We

sought comments regarding

implementation of a mitigation

requirement. If mitigation is trued up

over time, we asked how the

Commission should ensure that the

utility takes all reasonable steps to

mitigate its own costs so as to minimize

what the customer would have paid. We

also asked how the Commission should

ensure that the utility does its best to

sell the power at its highest possible

value. In addition, we asked whether

there are other mitigation measures that

should be taken into account (such as

efficiency improvements that a utility

would have undertaken regardless of

whether the particular customer

continued to take power under its

contract, or cost savings resulting from

the buy-out of a fuel contract made

possible by the customer’s departure).799

With regard to determining how long

a utility could have reasonably expected

to keep a generation customer (which

we will call the ‘‘reasonable expectation

period’’), we preliminarily found that a

one-size-fits-all approach is not

appropriate. We sought further

comment with respect to whether the

Commission ought to establish

presumptions or, in the alternative,

absolute limits on a customer’s

maximum liability when a utility

establishes that it had a reasonable

expectation that the contract would be

extended. We inquired whether it

would be appropriate to pick an outer

limit equal to the revenues that the

utility would lose during the length of

one additional contract extension

period, or during the length of the

utility’s planning horizon. We also

asked what other events or criteria

might be used to establish either

presumptions or absolute limits on the

reasonable expectation period.800

In addition, we proposed procedures

for providing a customer advance notice

of how the utility would propose to

calculate costs that the utility claims

would be stranded by the customer’s

departure.801 We invited comments on

these procedures.802

Comments

a. Revenues Lost Approach

Numerous commenters, including

almost all investor-owned utility

commenters, support the revenues lost

approach for calculating stranded

costs.803 Among other things,

commenters maintain that the revenues

lost approach is fair, reliable, and less

complicated than the asset-by-asset

approach. As discussed below, while

some of these commenters support an

‘‘up-front’’ determination of stranded

costs with no subsequent adjustments,

others prefer use of a true-up

mechanism whereby a customer’s

responsibility for stranded costs is

adjusted to the extent that the actual

competitive market value is different

from the estimated market value used to

determine the customer’s up-front

stranded cost charge.

Other commenters, on the other hand,

oppose the revenues lost approach.804

Some commenters state that the

revenues lost approach provides no

incentive to mitigate stranded costs

because, by permitting a utility to

recoup from a departing generation

customer the difference between the

contract price and a power resale price,

the utility receives the same total

revenues regardless of whether the

customer stays or leaves and regardless

of whether the utility effectively

mitigates stranded costs.805 Others

maintain that the revenues lost

approach is imprecise.806 Referencing

the problems associated with avoided

cost projections used in setting QF rates

under PURPA, some of these

commenters submit that the revenues

lost approach also requires significant

assumptions (regarding projected

revenue streams, service levels, and

generic market value forecasts).807

Among the other criticisms of the

revenues lost approach that are raised

by commenters are that it leads to overrecovery of stranded costs,808 is
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21655

809E.g., TDU Systems, Blue Ridge, NY Energy

Buyers.

810E.g., UT Com.

811E.g., Utility Investors Analysts, Public Power

Council, Atlantic City, EEI, PA Com, NYSEG,

Central Montana EC, Nebraska Public Power

District, LG&E ABATE.

812Several commenters (Illinois Power, Oklahoma

G&E, and Utility Investors Analysts) suggest that the

Commission hold a technical conference to discuss

how best to define the calculation of the formula

components.

813Central Montana EC and NY Energy Buyers.

814See EEI, Electronic Data Systems, Knoxville,

NIMO, NYSEG, NY Energy Buyers, Reynolds.

815E.g., Nuclear Energy Institute, EEI, Consumers

Power, PA Com, Oklahoma G&E, Portland,

Knoxville, MidAmerican, Seattle, Salt River,

Washington and Oregon Energy Offices, SMUD,

Caparo.

816Some commenters (e.g., Alma, Freedom

Energy) oppose such flexibility. Alma maintains

that clarity of rules is needed to provide

participants in the competitive market as much

certainty as possible about stranded cost charges

likely to be recovered before they engage in

alternative transactions. Freedom Energy similarly

supports across-the-board or generic standards, as

opposed to a case-by-case approach.

817E.g., Centerior, Com Ed, Duke, Entergy, Florida

Power Corp, Utility Investors Analysts, CA Energy

Co, CSW.

818E.g., Alma, ABATE, DOD, TDU Systems,

ELCON.

819E.g., NRECA, CA Energy Co, ABATE, DOD.

820E.g., EEI and various investor-owned utilities,

Nuclear Energy Institute, NC Com, Legal

Environmental Assistance, EPA, Utilities for

Improved Transition, PA Com.

821E.g., TAPS, WP&L, UT Industrials, UtiliCorp,

American Forest & Paper.

822E.g., DC Com, Sustainable Energy Policy,

Washington and Oregon Energy Offices.

823E.g., AEC & SMEPA, Electronic Data Systems,

Freedom Energy Co, LG&E, American National

Power, EGA, Entergy, AMP Ohio, TDU Systems,

TAPS, Las Cruces.

824TDU Systems proposes that the Commission

allow for the recovery of stranded benefits in one

of two ways: (1) Require direct payment of stranded

benefits to a wholesale purchaser whose contract is

terminated; or (2) allow a party to continue to

receive power at cost-based rates for a period

sufficient for the purchaser to be ‘‘transitioned’’ into

a competitive market.

825E.g., ELCON, NY Energy Buyers, SMUD,

Caparo.

anticompetitive,809 and that it leads to

cost shifting.810 NARUC and TDU

Systems also maintain that it is likely

that assets stranded by a customer’s

departure from the utility’s generation

system will be used to serve new

customers but that the revenues lost

approach offers no method of

accounting for such ‘‘unstranding’’ of

assets.

A number of commenters request

clarification of the stranded cost

formula contained in the NOPR,

including specific instructions regarding

how to calculate the revenues the

customer would have paid the utility

had it remained a customer and the

competitive market value of the power

the customer would have purchased.811

Some of these commenters suggest that

the stranded cost issue will be more

contentious if the final rule does not

provide greater detail.812 Several

commenters request that the

Commission issue a detailed list of

recoverable costs.813 A number of

commenters propose detailed

alternatives to, or variations of, the

revenues lost approach.814

Numerous commenters urge the

Commission to be flexible and not

overly prescriptive regarding the

calculation of the formula

components.815 These commenters

generally recommend that the

Commission judge each stranded cost

proposal on a case-by-case basis.816

Definition and Calculation of Revenue

Stream

Some commenters maintain that the

revenue stream component should be

calculated based on the present rates

paid by the customer.817 These

commenters state that because present

rates have been approved by various

commissions, the costs have been

shown to be legitimate, prudent, and

verifiable.

Other commenters oppose the use of

current rates to calculate the utility’s

revenue stream. WP&L believes that the

use of current rates would be overly

generous and recommends capping the

revenue measure at a regional average

rate rather than a utility-specific rate. A

number of other commenters argue that

the effects of competition should be

factored into the revenue stream by

using the rates for capacity and energy

actually offered or available in the

utility’s marketplace, such as incentive

and special rates, not just the tariff rates

to a particular customer.818 Several

commenters support removal of rate of

return-related revenues associated with

stranded assets, including risk

premiums that are designed to

compensate for potential nonrecovery of

stranded costs.819 EEI, in contrast,

opposes any disallowance of rate of

return-related revenues on the grounds

that such a disallowance would violate

the constitutional bar against the taking

of private property without just

compensation. Electronic Data Systems

recommends calculation of the revenue

stream using projected rates that include

the effects of future rate increases.

The Commission requested comments

on what categories of costs, in addition

to investment costs, should be eligible

for stranded cost recovery. In response,

many commenters support the inclusion

in the revenue stream calculation of

additional costs, termed ‘‘special’’ costs,

that may not be currently reflected in

the rates paid by the departing

customers, but that were incurred to

provide service to these customers.820

‘‘Special’’ costs include: (1) Nuclear

decommissioning costs; (2)

environmental obligations existing at

the time of the customer’s departure; (3)

purchased power contracts; (4) buyouts

and buydowns of purchased power

contracts; and (5) all regulatory assets,

including deferred costs of generating

assets for which regulators have

promised recovery, deferred taxes,

transition costs for post-employment

benefits other than pensions, and

contingent liability.

Other commenters oppose the

inclusion of ‘‘special’’ costs in the

calculation of the revenue stream.821

TAPS questions how a customer can be

held responsible for a cost that, by

definition, it was never under a

contractual obligation to pay. WP&L

states that suppliers’ rates should

already reflect reasonable estimates of

decommissioning costs and, therefore,

no additional recovery is warranted.

Some commenters argue that the

calculation of stranded costs should

include social costs, such as demand

side management, environmental costs,

low income assistance costs, and costs

associated with the management of fish

and wildlife.822

NARUC states that the Commission

should not preempt the ability of states

to establish competitively neutral

programs, such as DSM and energy

efficiency, environmental mitigation,

and R&D.

Various commenters state that any

determination of stranded costs should

take into account all offsetting benefits

realized by the transmission provider

upon a customer’s departure.823 Some

commenters describe these costs as

‘‘stranded benefits.’’ 824

Most commenters favor the removal of

avoided variable costs from the

calculation of stranded costs on the

basis that only fixed costs are truly

stranded.

Some commenters support

prioritizing stranded cost recovery.825

These commenters argue that stranded

costs should be categorized and ranked

by the degree of responsibility that

utilities had for their incurrence.

Utilities would be allowed the greatest

percentage of recovery for those

stranded costs over which they had the

least control.

Definition and Calculation of the

Competitive Market Value

There generally was no consensus

among the commenters concerning how
21656 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

826E.g., Centerior, Duke, Entergy, Com Ed,

Houston L&P, Florida Power Corp, Carolina P&L,

NRRI, WP&L, DOE, CSW, UtiliCorp, LG&E, FL Com.

827E.g., WP&L, DOD, Duke, PSNM, ABATE,

Houston L&P. The Commission notes that the New

York Mercantile Exchange only recently began

trading in electricity futures and that such trading

was limited to two delivery points located within

the Western Interconnection.

828E.g., MI Com, NSP, NY Energy Buyers, KS

Com.

829E.g., KS Com, NY Energy Buyers.

830Commenters that support a one-time, up-front

approach include FL Com, Dayton P&L, Portland,

DE Muni.

831Commenters that support true-ups include

ELCON, NYSEG, MN DPS, Reynolds, TAPS, NIMO,

DOE, Electric Consumers Alliance, Com Ed, United

Illuminating, SoCal Edison.

832 DE Muni urges rejection of true-ups on the

basis that true-ups represent guaranteed recovery of

100 percent of stranded costs.

833E.g., Electronic Data Systems, Alma, American

National Power, CA Energy Co, NARUC, NRECA.

834E.g., Atlantic City Electric, EGA, Conservation

Law Foundation.

835E.g., Utility Investors Analysts, Duke, PSE&G,

Com Ed, United Illuminating, Entergy.

836E.g., NIEP, LG&E, TDU Systems, EGA, NY

Energy Buyers, ELCON, American National Power.

837E.g., LG&E, Allegheny, TDU Systems, EGA,

AMP Ohio, CA Energy Co, WP&L, Torco.

838CA Energy Co maintains that an

anticompetitive intent could be hidden by the

argument that power must be dumped to mitigate

stranded costs. It thus submits that, even without

intending to do so, a utility could cripple

competition by depressing market rates to

artificially low levels.

839E.g., TDU Systems, Arkansas EC.

to determine the revenues a utility

would receive in a competitive market

for the stranded assets, that is, the

competitive market value.826 Proposals

for calculating competitive market value

include using: (1) The marginal cost of

the released capacity; (2) the long-run

marginal cost of the most competitive

incremental generation replacement

technology; (3) the marginal cost of

requirements service; (4) a combination

of the marginal costs of the utility,

alternative suppliers, and others; (5) the

cost of a combined cycle combustion

turbine; (6) the price paid by the

departing generation customer; (7) the

highest price available in the market;

and (8) auctions. In addition, to the

extent that a futures market is

sufficiently well-developed when the

Commission issues a final rule, several

commenters believe that futures market

prices could be used as an estimate of

market value.827

MT Com contrasts the effect of using

short-term nonfirm prices instead of

long-term firm prices as the competitive

market value. It states that if short-term

nonfirm prices are used, the stranded

cost estimate would be higher, because

the market price of short-term nonfirm

power is lower than both the market

price of long-term firm power and the

embedded cost price.

Some commenters express concern

regarding the difficulty of determining

the market value of the displaced

capacity under the revenues lost

approach.828 Among other things,

commenters note that because a

competitive market does not yet exist,

the market price cannot be calculated in

advance. For this reason, several

commenters support an after-the-fact

determination of market value.829

Snapshot Approach vs. True-Ups

Commenters are split on whether the

revenues lost approach should use a

one-time snapshot approach 830 or

whether true-ups should be required or

allowed.831 The primary rationale

offered in support of a snapshot

approach is certainty; 832 the primary

rationale offered in support of true-ups

is accuracy.

Commenters that support true-ups

note the inaccuracy associated with

long-term avoided cost estimates

contained in PURPA-mandated QF

contracts and maintain that the

projections required by the revenues

lost approach will produce similarly

disastrous results if true-ups are not

permitted. As a component of the trueup calculation, some commenters favor

inclusion of revenues associated with

future load growth of remaining

customers.833 According to Electronic

Data Systems, if these revenues are not

included in a true-up calculation, the

utility could over- or under-collect

stranded costs, depending on whether

and what type of load growth is

anticipated. CA Energy Co and

American National Power recommend

consideration of load growth of

remaining customers as a mitigating

factor because the load increases of

these customers allow the sale of the

stranded capacity. CSW, on the other

hand, opposes using the future load

growth of remaining customers as a

mitigation device. CSW states that the

benefits of growth on the former

supplier’s system should flow to the

customers who remain customers of that

system. Ohio Ed agrees, except where

the customer proves that the utility has

deferred or cancelled capacity resource

additions in response to departing

customers.

Other commenters suggest that the

Commission should not prescribe one

method over the other.834 EGA, for

example, states that customers should

have the choice of paying either a

projected fixed amount or a charge that

is periodically trued up.

Mitigation

A number of commenters agree that

the revenues lost approach effectively

encompasses mitigation.835 Others argue

that mitigation should (or could) be

accomplished through divestiture of

assets or capacity auctions.836 LG&E

states that a utility requesting recovery

of stranded costs should be required to

auction that portion of its system to the

highest bidder. The difference between

the auction price and the depreciated

value of the auctioned assets could be

used to determine stranded costs.

However, LG&E does not advocate

complete recovery of this difference;

rather, it argues that this amount could

be used as a starting point.

Several commenters argue that the

revenues lost approach can produce

anticompetitive results if capacity

auctions or divestiture are not

required.837 A number of these

commenters contend that utilities that

recover significant stranded costs (while

still maintaining control over the

stranded capacity) can use the freed

capacity to make sales in the market at

subsidized prices. They maintain that

these utilities do not have to worry

about recovery of fixed costs because

those costs are recovered by the

stranded cost charge. According to these

commenters, utilities can then remarket

(or ‘‘dump’’) stranded capacity at

artificially low prices (made possible by

the subsidy from the stranded cost

recovery) and thereby gain a

competitive advantage in other

transactions.838 If the utilities are

permitted to remarket the displaced

capacity, CA Energy Co states that

market-sensitive floor prices should be

set to prevent utilities from reselling

power from stranded assets at

artificially low prices.

Suggestions as to how to prevent such

anticompetitive consequences include

allowing the customer to own or control

the residual asset or amount of stranded

capacity equivalent to the lost revenues.

According to EGA, the customer could

market the capacity it would have had

to pay for through stranded cost charges

and thus prevent the utility from

remarketing the capacity after it has

been paid stranded costs.

Several commenters take a harder line

and would require suppliers seeking

stranded cost recovery to offer for sale

to the departing customer a ‘‘slice’’ of

their system.839 TDU Systems states that

the purchase of an undivided slice of

the system is superior to divestiture of

a specific asset because the utility

cannot keep the wheat and leave the

purchaser with the chaff. TDU Systems

would also make purchase rights to the

system assignable. According to TDU
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21657

840See, e.g., CA Energy Co.

841See, e.g., PSNM.

842See WP&L.

843E.g., EEI, PA Com, AMP Ohio, TAPS.

844E.g., ABATE, Fertilizer Institute, IL Com, KS

Com, San Francisco, UT Industrials, ELCON, CA

Energy Co, MT Com, Caparo, WA Com, Education,

NRRI, NY Energy Buyers, Reynolds, DOD, DC Com.

845See, e.g., Florida Power Corp, Central and

South West, Com Ed, EEI, Montana, PECO,

Minnesota DPS, NIMO, NSP, SoCal Edison, PA

Com, Central Louisiana, Utility Investors Analysts,

Salt River, Orange & Rockland.

846E.g., Utility Investors Analysts and Utility

Shareholders.

847E.g., NIEP, TAPS, Allegheny, Central Montana,

Municipal Energy Agency Nebraska, PSNM,

ABATE, ELCON, PSE&G, UtiliCorp.

848E.g., PSE&G, PSNM, ELCON, Oklahoma G&E,

Duke. Oklahoma G&E supports use of the utility’s

planning cycle for retail stranded costs and use of

the contract term for wholesale stranded costs.

Duke states that the Commission should permit the

customer and the transmission provider to establish

the compensation period at something less than the

maximum period.

849E.g., UtiliCorp, WP&L, Missouri Joint

Commission, TAPS, Municipal Energy Agency

Nebraska, TDU Systems.

850E.g., Carolina P&L.

851E.g., FL Com.

852E.g., UT Industrials.

853Central Montana describes as ‘‘excessive’’ the

recovery period offered to it by Montana. Central

Montana states that it gave notice under a five-year

notice provision and that Montana responded with

a stranded cost demand extending 14 years after

notice of termination (nine years from the date

service would terminate).

854Allegheny would exempt three types of

stranded costs from such a limit: (1) Those due to

PURPA power purchases (it submits that these were

federally-mandated rather than profit-motivated

business decisions); (2) those due to regulatory

assets (such as deferred taxes); and (3) those due to

municipalization. In addition, it favors establishing

a rebuttable presumption that these special costs are

eligible for stranded cost recovery.

855E.g., EEI, Centerior, PECO, Houston L&P, Salt

River.

Systems, this mitigation scheme is the

only possible way to justify the

revenues lost approach. TDU Systems

argues that this proposal would inflict

no harm on the utility, which would be

fully compensated for the stranded

assets. It also suggests that the ability to

purchase a slice of the supplier’s system

would serve as an important bargaining

tool in stranded cost negotiations,

which would help level the playing

field among the parties.

Other mitigation proposals include: (i)

Requiring each utility to prepare a

mitigation plan under the supervision of

an independent expert that must be

approved by the parties or by the

Commission before stranded cost

recovery is permitted; 840 (ii) requiring a

utility to report annually for a five-year

period its mitigation activities and to

identify its stranded costs yet to be

recovered; 841 and (iii) setting the market

value of the displaced capacity at a high

level (thereby reducing the stranded

cost charge) to provide a mitigation

incentive.842 A number of commenters

support customer-controlled mitigation,

arguing, among other things, that the

entity responsible for paying stranded

costs has the best incentive to mitigate

them.843 Others support some form of

utility sharing of stranded costs to give

utilities an incentive to mitigate

stranded costs.844

b. Reasonable Expectation Period

(Period of Expected Continued Service)

Numerous commenters oppose setting

absolute limits on the period over which

a customer’s liability for stranded costs

would be determined.845 They suggest

instead that the Commission should

apply the facts of each case, including

the facts used to prove a reasonable

expectation of continued service, to its

determination of a reasonable

expectation period. Among the factors

commenters propose for consideration

are: the utility’s planning horizon; the

average remaining life of the utility’s

generating facilities or a specific number

of years that coincides with the duration

of a utility-specific stranded cost

recovery plan; utility projected load

growth; dedicated facility construction

lead times; estimated time to market

stranded assets; the lesser of the utility’s

need date for new generation or the

cross-over date when the market

generation price is expected to equal a

customer’s embedded cost less other

charges and compensation; and the

period for which estimated revenues

exceed market values. Commenters

representing the financial

community 846 oppose limiting cost

recovery from the departing generation

customer based on the term of the

contract. They argue that it was

reasonable for a utility to expect to

continue to serve a customer, or

customers who would take its place,

through the life of the assets; otherwise,

the asset could not have been financed

in the first place.

A number of other commenters urge

the Commission to prescribe limits on a

customer’s maximum liability.847 Some

commenters believe that the utility’s

planning horizon is the reasonable

expectation period.848 PSE&G states that

since utilities invested and incurred

costs to serve customers based on the

planning horizon, the planning horizon

is the only logical period. Other

commenters propose that the reasonable

expectation period be limited to one

contract extension period, or to the

shortest of: (i) One additional contract

renewal period; (ii) the utility’s

planning horizon; (iii) the period it

would/does take for load growth on the

seller’s system to absorb the lost load; or

(iv) the contractual notice period.849

Other suggested limits include the

weighted average remaining life of all

generating assets; 850 the in-service date

of the utility’s next avoidable generating

unit or purchased power contract that is

projected to have a capacity factor

comparable to the departing generation

customer’s load factor minus a one-time

mitigation effort; 851 and a rebuttable

presumption that two years is the

maximum time for a utility reasonably

to expect to receive revenue from tariff

sales or ‘‘open-ended’’ contracts.852

Other commenters propose recovery

periods that range from three to five

years (e.g., Central Montana EC),853 five

years (e.g., Public Power Council), and

eight years (e.g., Allegheny).854

GA Com and AZ Com state that

stranded cost recovery should not go on

indefinitely. GA Com states that

stranded costs should be collected for a

sufficient period of time to ensure full

recovery and indifference on the part of

the utilities’ remaining native load

customers. AZ Com states that a specific

termination period will also create an

incentive for utilities to mitigate

stranded costs.

c. Proposed Stranded Cost Recovery

Procedures

Several commenters 855 urge the

Commission to be flexible in evaluating

proposed mechanisms for recovery of

stranded costs, including the payment

method, noting that an approach

suitable to one utility and its customers

may not be suitable to another. They say

that utilities within a region might find

a mechanism that meets their region’s

unique characteristics.

Some commenters oppose certain

aspects of the procedures proposed in

the NOPR. For example, TAPS objects

that the NOPR procedure aimed at

providing advance notice to the

customer of its potential stranded cost

obligation resembles the procedure

rejected in Cajun. It says that ‘‘the

customer will likely be forced to spend

significant time and resources

‘litigat[ing] to determine the price of a

product(,)’ thereby ‘introduc[ing] dealkilling transactional costs and

uncertainties.’ ’’ (citing Cajun, 28 F.3d at

179). TAPS proposes that the seller be

required to produce a stranded cost

estimate that reflects a good faith,

reasonable estimate of the likely impact

of mitigation and that sellers making

excessive and unsupported stranded

cost claims be penalized. At a

minimum, it argues that the seller

should be held responsible for the costs
21658 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

856E.g., Entergy.

857E.g., Associated Power.

858E.g., Associated Power.

859E.g., Texaco.

860E.g., Heartland.

861E.g., PSNM, ELCON.

862E.g., ELCON.

863 In the case of a retail-turned-wholesale

customer, subtraction of distribution system-related

costs may also be appropriate.

864The formula is not to be used for recovering

stranded costs associated with retail wheeling. We

believe the formula is unworkable in this scenario

because one of its key elements—the option for a

customer to market or broker the utility’s power—

may not be practicable for retail customers.

Therefore, stranded costs associated with retail

wheeling will be determined on a case-by-case

basis.

865The customer may also decide to remain a

requirements customer for L. If the customer elects

to remain a requirements customer, the utility will

be obligated to continue service to the customer for

the duration of L.

reasonably expended by the buyer to

litigate the stranded cost claim.

DE Muni asserts that if filing a

complaint to redress grievances related

to the recovery of stranded costs is to be

a meaningful remedy, the final rule

should set a time limit within which the

complaint must be resolved.

A number of commenters offer

modifications to the recovery

procedures set forth in the NOPR,

including: (1) Extending a utility’s

response time for providing stranded

cost liability estimates from 30 days to

at least 60 days; 856 (2) requiring a utility

to provide to each wholesale customer

within six months of the effective date

of the final rule: (a) The formula that the

utility proposes to use to calculate the

customer’s maximum possible stranded

cost exposure without mitigation; and

(b) an actual calculation of the

customer’s stranded cost exposure

assuming the customer left the utility’s

system six months after the effective

date of the final rule; 857 (3) allowing

customers that desire to litigate their

stranded cost liability to do so in a

forum in which all litigating customers

participate; 858 (4) requiring utilities to

disclose their estimated transition cost

liabilities (and the nature of those

liabilities) before the effective date of

the final rule to permit a realistic

evaluation of the scope of the transition

cost problem and possibly facilitate

resolution of some disputes by

settlement; 859 (5) requiring any utility

seeking stranded cost recovery to

provide a list of the stranded facilities

to the departing generation customer

and offer that customer an equity

position in those facilities in return for

payment of stranded costs, thereby

enabling the departing customer to

recover some of its stranded costs

payment when any of the facilities

becomes useful again; 860 (6) requiring a

‘‘good faith request’’ for an estimate of

stranded costs based on an expected

date of departure from the providing

utility’s system and mitigation efforts

expected to be undertaken by the

utility; 861 and (7) requiring documented

evidence that a utility made a good faith

attempt to settle with a departing

generation customer before the utility is

given the opportunity to recover

stranded costs.862

Commission Conclusion

We reaffirm our proposal that the

determination of recoverable stranded

costs should be based on the ‘‘revenues

lost’’ approach. We find that the

revenues lost approach is the fairest and

most efficient way to balance the

competing interests of those involved.

After careful consideration of the

comments submitted, we have decided

to adopt the following formula for

calculating a departing generation

customer’s stranded cost obligation

(SCO), on a present value basis, under

a revenues lost approach:

SCO=(RSE¥CMVE×L

where:

RSE=Revenue Stream Estimate—average

annual revenues from the departing

generation customer over the three

years prior to the customer’s

departure (with the variable cost

component of the revenues clearly

identified), less the average

transmission-related revenues that

the host utility would have

recovered from the departing

generation customer over the same

three years under its new wholesale

transmission tariff.863

CMVE=Competitive Market Value

Estimate—determined in one of two

ways, at the customer’s option:

Option (1)—the utility’s estimate of

the average annual revenues (over

the reasonable expectation period

‘‘L’’ discussed below) that it can

receive by selling the released

capacity and associated energy,

based on a market analysis

performed by the utility; or Option

(2)—the average annual cost to the

customer of replacement capacity

and associated energy, based on the

customer’s contractual commitment

with its new supplier(s).

L=Length of Obligation (reasonable

expectation period)—refers to the

period of time the utility could have

reasonably expected to continue to

serve the departing generation

customer. We reaffirm that we do

not believe that a one-size-fits-all

approach is appropriate for

determining the length of a

customer’s obligation. If the parties

cannot reach agreement as to the

length of the customer’s obligation,

this period is to be determined

through litigation as a part of the

threshold issue of whether the

utility had a reasonable expectation

of continuing to serve the customer.

Application of the foregoing formula

and collection of the resulting stranded

costs are subject to the following

conditions:

1. Cap on SCO. The quantity (RSE–

CMVE) can be no greater than the

average annual contribution to fixed

power supply costs (defined as RSE less

variable costs) that would have been

made by the departing generation

customer had it remained a customer.

2. Changes in Customer Revenues. If

the customer’s rates (or contract

demand amounts, if relevant) changed

during the three-year period prior to the

termination of its existing requirements

contract, then the RSE should be

calculated using the customer’s most

recent 12 months of revenue.

3. CMVE Option 2 Conditions. Option

2 (a CMVE equal to the average cost to

the customer of replacement capacity

and associated energy) would be

available to a customer whose

alternative purchase(s) runs concurrent

with L, or, if longer than L, contains

rates that do not fluctuate over the

duration of the contract. The customer

would be required to demonstrate (at

the time it chooses this option) that the

replacement capacity contract(s) is for

service equivalent to the released

capacity (that is, firm power for a period

at least equal to L), and must also

clearly identify the rates to be paid for

the replacement service.

4. Payment Options. The method and

term of payment should be negotiated,

but is ultimately left to the customer’s

discretion. Possible payment options

include a lump-sum payment, an

amortization of a lump-sum payment

over a reasonable period of time, or a

surcharge on the customer’s

transmission rate.

5. Applicability. The formula is

designed for determining stranded costs

associated with departing wholesale

generation customers and for retailturned-wholesale customers.864

6. Marketing/Brokering Option. The

Commission will allow the customer, at

its sole discretion, a choice to market

the released capacity and associated

energy (or to contract with a marketer

for such service). Alternatively, the

customer may choose to broker the

released capacity and associated energy

(or to contract with a broker).865
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21659

866This option also addresses the concerns of

commenters that, by failing to require auctions or

divestiture of stranded capacity, the Rule would

allow a utility recovering stranded costs to sell the

freed capacity at subsidized prices, thereby gaining

a competitive advantage in other transactions. If the

customer avails itself of this option, the utility

would no longer control the released capacity.

867The present rates, whether established by

settlement or otherwise, have been found to be just

and reasonable. In other words, they are neither

confiscatory nor exorbitant.

7. Released Capacity and Associated

Energy. A utility requesting stranded

cost recovery must indicate the amount

of system capacity and the amount of

associated energy released by the

departing generation customer and used

in the revenues lost calculation. This

will allow the departing generation

customer to fairly consider exercising a

choice to market or broker the released

capacity and associated energy.

The formula balances a number of

goals, including: (1) Ensuring full

recovery of legitimate, prudent and

verifiable stranded costs; (2) requiring

the utility to mitigate stranded costs; (3)

providing certainty for departing

generation customers; and (4) creating

incentives for the parties to renegotiate

their existing requirements contracts or

otherwise settle stranded cost claims

without resort to litigation.

Contrary to the objections of some

commenters that the revenues lost

approach creates no incentive to

mitigate stranded costs, the formula

automatically encompasses mitigation

by reducing the departing generation

customer’s stranded cost obligation by

the competitive market value of the

released capacity and associated energy.

Further, the option provided in the

formula for a customer to market or

broker the released capacity and

associated energy protects the customer

from a utility trying to overrecover

stranded costs by estimating a low value

for the released capacity and associated

energy and thereby provides the

customer some assurance that stranded

costs will be minimized. Specifically, if

a customer believes the utility’s

competitive market value estimate

(CMVE) is too low, it can market or

broker the released capacity and

associated energy and reduce its

stranded cost obligation.866 We

accordingly will not impose a separate

mitigation obligation on the utility

above that which is already subsumed

in the revenues lost approach. In

addition, a utility will continue to be

subject to an ongoing prudence

obligation to sell excess capacity offsystem and/or to dispose of uneconomic

assets.

We recognize that some commenters

oppose the revenues lost approach as

imprecise. However, any ratemaking

method that relies on estimates will be

subject to forecasting error. Moreover, in

direct response to commenter concerns,

we have gone to great lengths in this

rule to provide specificity with respect

to the calculation of the components of

the formula. We believe that use of the

formula will narrow the scope of

disputes over the calculation of

stranded costs, lend precision to the

stranded cost amount it produces, and

provide certainty to departing

generation customers with respect to

their stranded cost obligations.

Calculation of the Revenue Stream

Estimate (RSE)

The RSE component of the formula is

based on revenues paid by the departing

generation customer during the last

three years of its contract or retail

service. We believe that the use of

‘‘present’’ revenues in the calculation of

the revenue stream has numerous

advantages over other approaches

advocated. The use of present revenues

eliminates disputes over estimates of

future revenues, thereby adding

certainty to the calculation. It also

eliminates the need for a detailed listing

of includable costs, relying instead on

the assumption that present rates

include all of the utility’s costs of

providing service. Further, the rates that

produce present revenues have been

approved by regulators, which strongly

suggests that the costs included in them

are prudent, legitimate and verifiable.867

We reject the suggestion by

commenters that a utility be required to

calculate the revenue stream using any

lower rate being offered by the utility for

service comparable to that being taken

by the customer when the customer

departs the utility’s generation system.

A revenue stream calculated in this

manner could deny a utility the

opportunity to fully recover its stranded

costs or could shift costs to other

customers, a result we find

unacceptable. Similarly, the elimination

of return-related revenues from the

revenue stream effectively would

require shareholders to absorb stranded

costs, which is contrary to our

determination that a utility is entitled to

an opportunity to fully recover

legitimate, prudent and verifiable

stranded costs.

Calculation of the Competitive Market

Value Estimate (CMVE)

We recognize the difficulty associated

with estimating the competitive market

value of the capacity and associated

energy not purchased by the departing

generation customer. However, we

believe that an up-front estimate, which

provides flexibility to the utility and a

measure of certainty to customers, is

superior to other proposals, provided

the right mix of incentives and options

is included in the formula.

A utility requesting stranded cost

recovery must estimate CMVE based on

a market analysis, with all assumptions

and work papers made available to the

departing generation customer. This

provides a utility with the flexibility to

choose the methodology that it feels

produces the best estimate of the

competitive market value of the released

capacity and associated energy. We note

that numerous proposals for calculating

competitive market value were made in

the comments. The Commission

believes that the flexibility provided by

the formula we adopt in this Rule

permits the filing utility to avail itself of

many of these recommendations.

At the same time, a utility may have

an incentive to underestimate CMVE

and thereby increase the stranded costs

charge. To address this issue, the

formula contains several features

designed to create an incentive to

produce a good faith estimate of

stranded costs and to safeguard

customers if a utility fails to do so. For

example, the formula provides a

departing generation customer with the

option to market or broker the released

capacity and associated energy if it

believes the utility’s estimate is too low.

If the marketing option is chosen, the

customer would buy the released

capacity from the utility at the utility’s

market value estimate. The associated

energy would be purchased at the

utility’s average system variable cost.

The customer would then resell the

released capacity and energy and keep

the resulting revenues. If the revenues it

receives are greater than the utility’s

market value estimate, the customer will

have reduced its stranded cost

obligation. If the customer chooses the

brokering option and the released

capacity and associated energy are

purchased by a third-party for more

than the utility’s market value estimate,

the difference between the average

annual revenues produced by the sale

and the utility’s CMVE estimate will be

used to lower the customer’s stranded

cost obligation. The utility may be

required to show in a compliance filing

that it has reduced the customer’s

stranded cost obligation under such

circumstances.

If the customer chooses CMVE Option

2 and meets its conditions, CMVE will

be set at the average price that the

customer pays its new supplier. The

customer will test the market and

choose the best deal available. Hence,
21660 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

868These procedures apply to a potential

departing generation customer who is an existing

wholesale requirements customer of a public utility,

or a retail customer of a public utility who is

contemplating becoming a wholesale transmission

customer (such as through municipalization). They

may be used at the option of the potential departing

generation customer. An existing wholesale

requirements customer may use the procedures in

conjunction with, or in lieu of, a complaint under

section 206 to amend its existing requirements

contract to add an explicit stranded cost provision,

as discussed in Section IV.J.5.

869FERC Stats. & Regs. ¶ 32,514 at 33,114–15;

33,128–29.

870 If the customer is a retail customer

contemplating becoming a wholesale transmission

customer, it may at any time request the public

utility to provide an estimate of its stranded cost

obligation.

871Because the formula reduces a customer’s

stranded cost obligation by the competitive market

value of the capacity and associated energy that

would be released by the customer’s departure, we

will not adopt the proposal in the Supplemental

Stranded Cost NOPR to allow a potential departing

customer to receive an estimate of the customer’s

‘‘maximum possible stranded cost exposure without

mitigation.’’ Requiring the utility to provide an

estimate that reflects the competitive market value

of the capacity and associated energy to be released

will better enable the customer to assess its supply

options.

872 If the customer is a retail customer

contemplating becoming a wholesale transmission

customer, it should specify in its request, to the

extent possible, the date on which the customer is

considering becoming a wholesale transmission

customer of the utility and the amount of

generation, if any, it will continue to purchase from

its existing supplier.

873 If the customer is a retail customer

contemplating becoming a wholesale transmission

customer, the utility should provide a detailed

rationale justifying the basis for its reasonable

expectation of continuing to provide the customer

bundled retail service.

874Subsection (i) above also would apply to a

retail customer contemplating becoming a

wholesale transmission customer if the customer

believes that the utility has failed to establish that

it had a reasonable expectation of continuing to

provide the customer bundled retail service.

the price the customer pays its

alternative supplier is arguably a more

accurate measure of the competitive

market value of the capacity and

associated energy not taken from the

host utility. Whether to exercise Option

2 resides solely with the customer.

We further note that the sale of all or

part of a utility’s generating assets could

be used as a method to determine

competitive market value of such assets.

Under the theory that an asset sale price

reflects the highest value for the utility’s

assets, the Commission would presume

that the competitive market value

established under an open asset sale

(i.e., an offer to sell assets to any taker)

would fully satisfy the utility’s

responsibility to minimize stranded

costs. If a stranded cost claim involves

divestiture of assets, the amount of

stranded costs associated with those

assets would be the book value less the

sale price. The Commission would

determine the appropriate stranded cost

charge based on the facts presented.

Snapshot Approach Versus True-Ups

The revenues lost formula is based on

a one-time snapshot approach. We favor

this approach over the true-up approach

because it creates certainty and will

produce reasonably accurate results.

True-ups, on the other hand, while

theoretically more accurate, require

periodic recalculation of stranded costs,

which creates ongoing uncertainty and

disputes. In addition, true-ups will

result in additional transaction costs.

We believe that an approach that

provides certainty and establishes cost

responsibility up front is best for what

is fundamentally a transition issue.

Implementation Procedures 868

In the Supplemental Stranded Cost

NOPR, we proposed procedures to

provide a potential departing generation

customer with advance notice of how

the utility would propose to calculate

costs that the utility claims would be

stranded by the customer’s departure.869

These procedures are modified as

follows to incorporate the findings made

in this rule:

(1) A customer may, at any time

before the termination date specified in

its existing wholesale requirements

contract,870 request the public utility to

provide an estimate of the customer’s

stranded cost obligation based on the

revenues lost formula contained in this

Rule,871 as of the date set forth in the

customer’s request. The customer

should specify in its request, to the

extent possible, pursuant to its rights

under its power sales requirements

contract with the seller,872 the date on

which the customer is considering

substituting alternative generation for

the requirements purchase and the

amount of the substitute generation.

Any remaining generation requirements

to be purchased from the existing

supplier after this date should be clearly

indicated. The customer may seek

further information on how the stranded

cost charge would vary as a result of

choosing different dates or different

amounts of substitute purchases. The

customer also should indicate its

preferred payment method, such as a

lump-sum payment, an amortization of

a lump-sum payment, or a surcharge

(such as monthly or annual) on the

customer’s transmission rate.

(2) The utility shall, within thirty

days of receipt of the request, or other

mutually agreed-upon period, provide

the customer with an estimate of the

customer’s stranded cost obligation. The

response shall include: (i) Estimates of

RSE, CMVE, and L according to the

revenues lost formula and based on the

information supplied by the customer;

(ii) supporting detail (including the

underlying market analysis that forms

the basis for the CMVE estimate)

indicating how each element in the

formula is derived to enable the

customer to understand the basis for

each element; (iii) a detailed rationale

justifying the basis for the utility’s

reasonable expectation of continuing to

serve the customer beyond the

termination date in the contract; 873 (iv)

an estimate of the amount of released

capacity and the amount of associated

energy that would result from the

customer’s departure, based on the

information supplied by the customer,

including detailed support for the

amount of the released capacity and the

amount of associated energy, and the

market value of each, for each year of

the reasonable expectation period, and

how those amounts are consistent with

the RSE and CMVE estimates; and (v)

the utility’s proposal for any contract

amendment needed to implement the

customer’s payment of stranded costs

(the proposed modification should also

reflect the customer’s chosen payment

method).

(3) If the customer believes that: (i)

The utility has failed to establish that it

had a reasonable expectation of

continuing to serve the customer

beyond the contract term; 874 (ii) the

proposed stranded cost charge (or any of

the elements used to compute it) is

unreasonable; (iii) the amount of

released capacity and the amount of

associated energy assumed to be sold is

unreasonable; or (iv) the utility’s

proposal for any contract amendment

needed to implement the customer’s

payment of stranded costs is

unreasonable, the customer will have

thirty days in which to respond to the

utility explaining why it disagrees. The

Commission expects parties to attempt

to resolve any disputed issues.

(4) If the parties are unable to resolve

the matter using the procedures in (1)–

(3) above, the customer may either: (a)

File a petition for declaratory order, or

a section 206 filing seeking to amend an

existing requirements contract, to seek a

Commission determination as to

whether: (i) The utility has met the

reasonable expectation standard; (ii) the

proposed stranded cost charge satisfies

the other evidentiary standards set forth

in this Rule; (iii) the amount of released

capacity and the amount of associated

energy proposed by the utility is

reasonable; or (iv) the utility’s proposal

for any contract amendment needed to

implement the customer’s payment of
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21661

875As discussed above, retail customers

contemplating becoming wholesale transmission

customers may use the same procedures. As also

discussed above, customers under existing

requirements contracts with public utilities have

the option of making a filing under section 206

seeking to amend the contract to add an explicit

stranded cost provision, without having to go

through these procedures.

876Although estimates by the utility or the

customer may be binding for purposes of litigation,

this does not mean that the parties may not settle

at any time on another amount.

877A customer requesting a section 211 order for

transmission services from a transmitting utility

also may incur a stranded cost obligation. Any

estimate of stranded cost obligation resulting from

the requested transmission services should be

included as part of the utility’s good faith response

to the customer’s request for transmission services.

See 18 CFR 2.20. Because the Commission will

apply the revenues lost formula to any request for

stranded cost recovery as a part of its determination

of the appropriate charge for transmission services

ordered in a section 211 proceeding, we encourage

non-public utilities to use the revenues lost formula

to estimate a customer’s stranded cost obligation.

878Because litigation of stranded costs may

extend beyond the date of the customer’s departure,

the customer may also file a petition for a

declaratory order requesting expedited resolution of

marketing or brokering implementation issues.

879 If the customer can market the released

capacity and associated energy for a higher price

than the customer paid for it, the customer

effectively reduces its stranded cost obligation, i.e.,

the incremental revenue received offsets a portion

of the customer’s stranded cost payment to the

utility.

880For example, if the customer brokers any

released capacity and associated energy for a higher

price than the utility’s estimated competitive

market value of that capacity and energy, the

difference between the utility’s estimate and the

brokered price will be used to increase the utility’s

CMVE component of the stranded cost calculation,

thereby reducing the customer’s stranded cost

obligation.

stranded costs is reasonable; or (b) wait

until the proposed stranded cost charge

is filed by the utility under section 205

of the FPA, and contest it at that time.875

In either case, because estimates of RSE

and CMVE may change over time, any

estimate of stranded costs provided by

a utility to a customer will not be

considered binding prior to any filing by

either party with the Commission.

However, any stranded cost estimate

filed by the utility in a section 205 or

206 proceeding, or in response to a

petition for a declaratory order, shall be

considered to be a binding estimate of

the customer’s maximum stranded cost

obligation for purposes of litigation.

Similarly, any estimate of stranded cost

obligation filed by a customer in a

petition for declaratory order or a

section 205 or 206 proceeding shall be

considered to be a binding estimate of

the customer’s minimum stranded cost

obligation for purposes of litigation.876

Estimates of stranded cost obligation

that are filed by either party with the

Commission shall include the

information, including the supporting

detail, identified in (2) above.

(5) If a utility intends to file for

stranded cost recovery from a customer

through either a stranded cost

amendment to its existing contract or a

surcharge on transmission rates, it must

file its stranded cost estimate no later

than 120 days prior to the end of the

customer’s contract term. The filing

shall include the information, including

the supporting detail, set forth in (2)

above. The customer, of course, may

contest the contents of such a filing.877

Conditions of the Marketing/Brokering

Option

A customer may choose to market or

broker a portion or all of the released

capacity and associated energy

identified by the utility in its stranded

cost estimate (or to contract with a

marketing/brokering agent).

Importantly, by exercising the marketing

or brokering option, the customer does

not relinquish its right to contest any

aspect of the utility’s stranded cost

estimate, including whether the utility

is entitled to recover stranded costs for

the period that the customer has agreed

to market or broker any released

capacity and associated energy. To

implement this option, a customer must

inform the utility in writing of its

decision no later than 30 days after the

utility files its estimate of stranded costs

for the customer with the Commission.

Before marketing or brokering of the

released capacity and associated energy

can begin, the utility and customer must

execute an agreement identifying, at a

minimum, the amount of capacity and

associated energy the customer is

entitled to schedule, the price of

capacity and associated energy, and the

duration of the customer’s marketing/

brokering of the released capacity and

associated energy. Parties are

encouraged to settle disputes over these

and any other marketing/brokering

implementation issues. The negotiations

should be guided by the principle that

the utility must allow the customer to

market or broker the released capacity

and associated energy under terms and

conditions comparable to those for a

utility resale of the capacity and

associated energy to a third party. If

agreement over marketing or brokering

cannot be reached, the parties may seek

to include the issue as a part of a

proceeding initiated at the Commission

with respect to the utility’s stranded

cost estimate for the customer.878 Upon

issuance of an order resolving the

disputed issues, the customer may

reevaluate its decision to exercise the

marketing/brokering option. The

customer also may choose to market or

broker any released capacity and

associated energy not being marketed or

brokered under an earlier agreement

with the utility. A customer must notify

the utility in writing within 30 days of

issuance of the Commission’s order

resolving the disputed issues whether

the customer will market or broker a

portion or all of the capacity and energy

associated with stranded costs allowed

by the Commission.

Payment for Released Capacity and

Associated Energy Under the Marketing

Option

If the customer chooses to market

released capacity and associated energy,

it shall pay the utility’s estimate of the

competitive market value of the

capacity, or, if the marketing option is

exercised after a Commission order, it

shall pay the competitive market value

amount as determined by Commission

order. In addition, for all energy

scheduled to be delivered, the customer

shall pay the utility’s average system

variable costs. The customer may also

choose to market only a portion of the

released capacity and/or for a shorter

period. In this situation, the customer

will also pay the competitive market

value for the released capacity plus the

utility’s average system energy costs.

The customer’s liability for payment of

stranded costs is unaffected by its

decision to market released capacity and

associated energy.879 In addition, to the

extent that the customer chooses to

market a portion or all of the capacity

alleged by the utility to be stranded, a

final determination with respect to the

customer’s stranded cost obligation will

not affect any prior marketing

agreement.

Payment for Stranded Costs Under the

Brokering Option

If the customer chooses to broker a

portion or all of the released capacity

and associated energy, any revenue

received from such brokering activity

shall be used to offset the utility’s

estimate of the competitive market value

of the brokered capacity and associated

energy.880 Once a brokering agreement is

executed between the customer and the

utility, if the customer’s brokering

efforts fail to produce a buyer within 60

days of the date of that agreement, the

customer shall relinquish all rights to

broker the released capacity and

associated energy and will pay stranded

costs as determined by the formula.
21662 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

881FERC Stats. & Regs. ¶32,514 at 33,132.

882See, e.g., EEI, NSP, LILCO, Central Hudson,

Deloitte & Touche, Centerior.

883FERC Stats. & Regs. ¶ 32,514 at 33,115.

884EEI asks the Commission to expand the

definition of stranded costs to account for the case

where the Commission has proposed to address

purely retail stranded costs (that is, where a state

regulatory authority does not have authority to

address stranded costs at the time that retail

wheeling is required). However, the regulations will

contain a definition of ‘‘retail stranded costs’’ to

account for this case. See § 35.26(b)(5) of the Final

Rule.

885E.g., EGA, Direct Service Industries, Memphis.

10. Stranded Costs in the Context of

Voluntary Restructuring

In the Supplemental Stranded Cost

NOPR, we noted that the functional

unbundling of wholesale services does

not require corporate unbundling (such

as disposition of assets to a non-affiliate,

or establishing a separate corporate

affiliate to manage a utility’s

transmission assets). At the same time,

we indicated that some utilities may

ultimately choose some form of

corporate unbundling.881 We reaffirm in

this Final Rule that we are willing to

consider case-specific proposals for

dealing with stranded costs in the

context of any restructuring proceedings

that may be instituted by individual

utilities.

11. Accounting Treatment for Stranded

Costs Comments

A number of commenters ask the

Commission to provide accounting

treatment guidance as part of its

procedures for implementing its policies

on stranded costs and their recovery.882

NSP states that the Commission will

need to provide appropriate accounting

guidance for the final stranded cost

recovery methodology, including

accounting for any portion of stranded

cost recovery representing capital costs,

the effect of any interperiod differences

between the stranded cost calculations

and the authorized recovery period, and

the effects of differences between book

and income implications of the stranded

cost recovery mechanism. NSP also

asserts that, in addressing the

accounting implications of the final

rule, the Commission must consider the

requirements of the Financial

Accounting Standards Board (FASB)

Statement of Financial Accounting

Standards No. 121, ‘‘Impairment of

Long-Lived Assets’’ (SFAS No 121).

NASUCA states that one of the

Commission’s stated goals in providing

stranded cost recovery is to protect

against cost shifting. NASUCA argues

that the Commission should adopt an

accounting rule that assures that any

federal resolution of wholesale stranded

costs does not impose any cost shifting

to captive customers.

EEI and Centerior argue that the

Uniform System of Accounts as

presently configured does not support

the Commission’s proposed policies on

stranded cost recovery. Further, EEI

states that even with the revenues lost

approach, which EEI supports, utilities

will still have to account for their assets

on a class-of-asset by class-of-asset

basis. EEI argues that this is necessary

to ensure that the costs of the assets are

expensed in the proper accounting

period. EEI states that one of the basic

principles of financial accounting is that

expenses should be matched with the

related revenues.

Commission Conclusion

As discussed in Section IV.J.3, this

rule adopts a direct assignment

approach for the recovery of stranded

costs from departing generation

customers. Under the revenues lost

approach, stranded cost recovery is

limited to the departing generation

customer’s contribution to fixed costs

that the utility otherwise would not

recover because of the customer’s

departure.

We recognize that there are certain

similarities between the financial

reporting objectives of SFAS No. 121

and the determination of stranded costs.

However, there are also important

differences between SFAS No. 121 and

our approach to stranded costs. The

revenues lost approach does not attempt

to identify specific uneconomic assets

and is not limited to only long-lived

assets. Instead, it uses a formulary

methodology that encompasses all fixed

costs of providing service.

From a financial accounting

standpoint, our approach to stranded

costs creates the potential for a

mismatch between the periods in which

the stranded costs are charged to

expense and any revenues provided for

their recovery are included in net

income determinations. This is because

the earning process entitling a utility to

the benefits of stranded cost recovery

and thereby requiring the recognition of

revenue may be completed prior to the

time that the stranded costs must be

charged to expense under generally

accepted cost recognition criteria. This

circumstance in a cost-based regulated

environment creates the undesirable

potential for double recovery of the

same cost, cost shifting, and

inappropriate financial reporting.

In order to avoid this potential,

utilities shall not recognize revenues

intended to provide for recovery of

stranded costs from wholesale

requirements customers prior to the

time that the stranded costs are charged

to expense, unless prior Commission

approval to do so has been obtained.

Absent Commission approval, utilities

shall defer such amounts in Account

253, Other Deferred Credits, and

amortize them to Account 456, Other

Electric Revenues, consistent with the

period the related costs are charged to

expense. Also, we will require a utility

to submit its proposed accounting for

stranded costs and related revenues as

part of its rate filing requesting recovery

of stranded costs under section 205 of

the FPA.

12. Definitions, Application, and

Summary

In the Supplemental Stranded Cost

NOPR, the Commission described

proposed amendments to our

regulations to establish filing

requirements for public utilities and

transmitting utilities that seek stranded

cost recovery. We proposed to define

‘‘wholesale stranded cost’’ as ‘‘any

legitimate, prudent and verifiable cost

incurred by a public utility or a

transmitting utility to provide service to:

(i) A wholesale requirements customer

that subsequently becomes, in whole or

in part, an unbundled wholesale

transmission services customer of such

public utility or transmitting utility, or

(ii) a retail customer, or a newly created

wholesale power sales customer, that

subsequently becomes, in whole or in

part, an unbundled wholesale

transmission services customer of such

public utility or transmitting utility.’’

We sought comments on whether this

definition should encompass the

situation where a wholesale

requirements customer ceases to

purchase power from the utility that had

been making wholesale requirements

sales to such customer without

becoming an unbundled transmission

services customer of that utility.883

Comments

We received numerous comments

both supporting and opposing revisions

to the proposed definition of wholesale

stranded costs.884 Several commenters

oppose broadening the definition to

include costs stranded by customers

that do not become unbundled

transmission service customers of the

former supplier.885 For example, EGA

argues that the loss of an industrial

customer that chooses to self-generate or

the loss of a requirements customer as

a result of a newly-created municipal

system that interconnects with a

transmitting utility that is not the

customer’s former supplier could have

happened at any time. EGA states that

revenues lost as a result of either
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21663

886E.g., Atlantic City, Carolina P&L, Consumers

Power, Minnesota Power, Knoxville, Alma, Florida

Power Corp, El Paso, Central Louisiana, Southern,

WP&L, FL Com, Utility Investors Analysts, Florida

Power Corp, El Paso, Central Louisiana, TDU

Systems, NW Conservation Act Coalition, Puget,

NU, EEI.

887Several commenters also ask the Commission

to expand the definition of wholesale stranded cost

to include the situation where a wholesale supplier

loses wholesale load as a result of a requirements

customer’s loss of retail load because of retail

wheeling, municipalization or retail taps from

another utility’s system. E.g., Utilities For Improved

Transition, Montaup, SC Public Service Authority.

In addition, a number of commenters ask the

Commission to treat the members of a single G&T

cooperative system as a single economic unit and

to revise the definition of wholesale stranded costs

to allow a transmitting G&T cooperative (the arm of

the cooperative system that provides the

transmission) to recover the costs stranded when a

retail customer of one of its member distribution

cooperatives takes advantage of the open access

environment by becoming a wholesale entity. E.g.,

Big Rivers EC, NRECA, Tri-County EC, TDU

Systems.

888E.g., Carolina P&L, NU, Florida Power Corp,

PSNM, Southern, Mountain States Petroleum

Assoc, FL Com.

889 In its reply comments, Memphis Light objects

to the proposal that the Commission condition

approval of all new power contracts for those

customers that leave a utility’s system without

using the transmission services of the original

utility upon the inclusion of a provision to recover

the stranded cost for the previous power supplier.

It argues that this proposal could result in

nonrecovery from some customers because

wholesale customers faced with such a provision

would pursue non-jurisdictional contracts and/or

generate within the confines of their own systems.

890E.g., EEI, El Paso, NU, Atlantic City, PG&E,

Coalition for Economic Competition, NW

Conservation Act Coalition, Puget, NRECA, Cajun,

East Kentucky, FL Com, Associated EC, Utilities For

Improved Transition, TDU Systems, TVA.

891E.g., EEI, NSP, Arizona, United Illuminating,

Entergy, SCG&E, PECO, NRECA.

892E.g., EEI, Centerior, NSP, SCG&E, PECO,

Tucson Power, Arizona.

893E.g., PECO, Entergy.

894E.g., EEI, SCG&E, Carolina P&L.

895E.g., Atlantic City. EEI also proposes that at the

time of filing of a stranded cost recovery charge

(whether as an amendment to a contract or a

surcharge to a transmission rate), the Commission

limit its inquiry to the issue of the stranded cost

charge rather than allowing all aspects of a rate or

contract to be opened up. EEI states that this is what

the Commission did in the natural gas context,

where it permitted limited rate filing cases under

section 4 of the NGA.

896E.g., Alcoa, Cleveland.

897E.g., Mountain States Petroleum Assoc,

Caparo, Torco.

898E.g., AMP-Ohio, PA Munis, TAPS.

899For the reasons articulated below, we

accordingly will reject the various revisions to the

definition that were proposed by commenters.

scenario have nothing to do with

regulatory reforms and should not be

considered ‘‘stranded’’ costs.

Other commenters disagree.886 Puget

asserts that permitting departing

generation customers to avoid paying

stranded costs if they do not take

unbundled transmission from their

former suppliers would create an

incentive for departing customers (or

their new electric suppliers) to build

unneeded and uneconomic new

transmission lines. Puget says that it

also could be a disincentive to engage in

regional transmission planning and

coordination because the existence of

new transmission facilities needed to

achieve regional reliability and

efficiency may increase the likelihood

that departing generation customers

could import their power supplies over

those new facilities and avoid paying

the utility’s stranded costs.887

Some of these commenters propose

using an exit fee to collect stranded

costs from a customer that does not take

unbundled transmission from its former

supplier, since a transmission surcharge

is not available in this circumstance.888

Other methods proposed include: (1)

Conditioning Commission approval of

the transmission rates or wholesale

power rates charged by the

transmission-providing utility upon the

inclusion of a surcharge to recover the

former supplier’s stranded costs or upon

the transmission-providing utility

otherwise agreeing to guarantee the

payment of the stranded costs or act as

billing agent for the former supplier; 889

(2) authorizing the former supplier to

levy a stranded cost charge on the

transmission-providing utility (if that

utility is interconnected with and has

transmission contracts with the former

supplier); (3) if a retail customer

becomes annexed to a municipal utility

and does not take unbundled

transmission services from its former

supplier, permitting recovery of

stranded costs from the municipal

utility through its jurisdictional

transmission rates; or (4) requiring a

public utility providing transmission

service for a customer that has left its

former supplier to agree, as a condition

to recovery of its own stranded costs, to

ensure the payment of any stranded

costs incurred by the former supplier.890

Commenters also address the use of

the terms ‘‘legitimate, prudent, and

verifiable’’ in the definitions of

wholesale and retail stranded costs.

Several commenters suggest that the

Commission’s use of the word

‘‘prudent’’ could imply that utilities

have to relitigate the prudence of costs

that the Commission and state

commissions have already approved;

these commenters believe that utilities

should not have to relitigate

prudence.891 Some argue that once a

regulatory agency (state or federal) has

allowed recovery of the costs in rates, or

promised future recovery, utilities

should not have to undergo a second

regulatory review to recover those costs

if they become stranded.892

Commenters recommend that the

Commission address this situation by:

Striking the word ‘‘prudent’’ from the

definition or specifying that the

prudence requirement is satisfied by

previous regulatory authorization; 893

dropping the terms ‘‘legitimate, prudent

and verifiable’’ from the definition and

using instead ‘‘allowed,’’ ‘‘accepted,’’ or

‘‘allowable’’; 894 or adding ‘‘or approved

by state commission’’ after the words

‘‘legitimate, prudent and verifiable’’ in

the definitions of both wholesale and

retail stranded costs.895

Other commenters oppose these

proposals, suggesting that the prudence

analysis for stranded cost purposes may

involve questions of prudence different

from those that arise in a ratemaking

context.896 DE Muni objects that

replacing ‘‘legitimate, prudent and

verifiable’’ with ‘‘allowed, accepted, or

allowable’’ could enable a utility to

recover costs that the utility may not be

able to prove were prudent, legitimate,

and verifiable.

A number of commenters submit that

‘‘legitimate, prudent and verifiable’’

costs should not include the costs of

uneconomic plants or costs resulting

from utilities’ independent business

decisions (as distinguished from costs

the utility was forced by regulation to

incur).897

Several other commenters address the

rule’s application to wholesale

requirements customers.898 AMP-Ohio

asks the Commission to clarify that the

reference to ‘‘wholesale requirements

customer’’ is to a full requirements

customer, not a partial requirements

customer. It says that no transmission

provider should have any reasonable

expectation of continuing to serve loads

of partial requirements customers. TAPS

suggests that references to ‘‘new

wholesale requirements contract’’ in

proposed § 35.26(c)(1) should be

conformed to the defined term ‘‘new

contract’’ in proposed § 35.26(b)(7). In

addition, it suggests that the

Commission clarify the regulations by

clearly foreclosing stranded cost claims

for ‘‘new contracts’’ without express exit

fees, instead of simply failing to provide

for such recovery.

Commission Conclusion

We will retain the definition of

‘‘wholesale stranded cost’’ proposed in

the Supplemental Stranded Cost

NOPR.899 We believe it would be

inappropriate to expand the definition

to include the situation where a
21664 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

900 ‘‘Wholesale requirements contract’’ is defined

as ‘‘a contract under which a public utility or

transmitting utility provides any portion of a

customer’s bundled wholesale power requirements’’

(emphasis added). Thus, a ‘‘wholesale requirements

customer’’ for purposes of the Rule can be either a

full or a partial requirements customer. We reject

AMP-Ohio’s suggestion that the Commission make

a blanket finding that a utility could not have had

a reasonable expectation of continuing to serve a

partial requirements customer. For example, a

partial requirements customer may have met part of

its needs with its own generation but because it

could not build more of its own generation locally

it had to depend on the utility for the remainder

of its needs in the absence of the new open access.

Also, a partial requirements customer may have

been able to reach alternative suppliers for only a

portion of its requirements due to transmission

constraints. If this were the case, the partial

requirements supplier may well have had a

reasonable expectation of continuing to serve the

balance of the customer’s load.

901The definition of ‘‘retail stranded cost’’

contains a similar requirement (i.e., the retail

customer must become, in whole or in part, an

unbundled retail transmission services customer of

the public utility or transmitting utility from which

the customer previously received bundled retail

services). We will retain it for the same reasons

discussed above.

902As we have said, this Rule is not intended to

insulate a utility from the normal risks of

competition.

903As the Commission has previously indicated,

however, in the case of formula rates, approval of

a formula rate constitutes approval of the formula,

and not the underlying costs. See, e.g., New

England Power Company, et al., 72 FERC ¶61,148

at 61,761 (1995); Boston Edison Company, Opinion

No. 376, 61 FERC ¶61,026 at 61,145 (1992).

wholesale requirements customer 900 (or

a retail-turned-wholesale customer)

ceases to purchase power from the

utility without using the transmission

services of that utility.901 Any costs that

the utility might incur as a result of the

loss of the requirements customer in

this scenario would be outside the scope

of this Rule. The premise of this Rule is

that, where a customer uses the new

open access to obtain power from a new

generation supplier, the customer must

pay the costs that were incurred on its

behalf under the prior regulatory

regime. However, if a customer leaves

its utility supplier by exercising power

supply options (such as access to

another utility’s transmission system or

self-generation) that do not rely on

access to the former seller’s

transmission, there is no nexus to the

new open access rules.902 If a customer

is able to obtain power from a new

supplier by using the transmission

system of another utility, it is likely that

the customer could have made these

arrangements in the absence of the new

open access rules. The new

transmission provider would have had

little incentive to deny transmission

services to the customer in order to

protect an existing power supply

arrangement, since it was not the

customer’s power supplier in the first

place. Indeed, it is likely that the

neighboring utility would have a

positive incentive to provide the

transmission service in order to increase

its revenues. This incentive is

unchanged by open access transmission.

Some commenters have asked us to

eliminate the term ‘‘prudent’’ from the

definition of stranded costs. We will not

do so; we will retain the requirement

that stranded costs be ‘‘legitimate,

prudent and verifiable.’’ A

determination that a utility had a

reasonable expectation of continuing to

serve a customer would not, in all

circumstances, mean that costs incurred

by the utility were prudent. Prudence of

costs, depending upon the facts in a

specific case, may include different

things: e.g., prudence in operation and

maintenance of a plant; prudence in

continuing to own a plant when cheaper

alternatives become available; prudence

in entering into purchased power

contracts, or continuing such contracts

when buy-outs or buy-downs of the

contracts would result in savings. The

Commission therefore cannot make a

blanket assumption that all claimed

stranded costs will have been prudently

incurred. However, we clarify that we

do not intend to relitigate the prudence

of costs previously recovered.903

Thus, this Rule will permit a public

utility or transmitting utility to seek

recovery of wholesale stranded costs as

follows. First, for stranded costs

associated with new wholesale

requirements contracts (that is, any

wholesale requirements contract

executed after July 11, 1994), the

regulations will allow recovery of

stranded costs only if the contract

contains an explicit stranded cost

provision that permits recovery. By

‘‘explicit stranded cost provision’’ we

mean a provision that identifies the

specific amount of stranded cost

liability of the customer(s) and a

specific method for calculating the

stranded cost charge or rate.. We clarify

that provisions in requirements

contracts executed after July 11, 1994

but before the date on which this Final

Rule is published in the Federal

Register that explicitly reserved the

right to stranded cost recovery pending

the outcome of this Rule will be deemed

‘‘explicit stranded cost provisions.’’

However, provisions in requirements

contracts executed after July 11, 1994

but before the date on which this Final

Rule is published in the Federal

Register that postpone the issue of

stranded cost recovery without

specifically providing for recovery of

stranded costs will not be considered

‘‘explicit stranded cost provisions.’’

Second, for existing wholesale

requirements contracts (that is, any

wholesale requirements contract

executed on or before July 11, 1994), a

utility may not recover stranded costs if

recovery is explicitly prohibited by the

contract (including associated

settlements) or by any power sales or

transmission tariff on file with the

Commission.

Third, for existing wholesale

requirements contracts that do not

address stranded costs through exit fee

or other explicit stranded cost

provisions, a public utility may seek

recovery of stranded costs only as

follows: (1) If the parties to the existing

contract renegotiate the contract and file

a mutually agreeable amendment

dealing with stranded costs, and the

Commission accepts or approves the

amendment; (2) if either or both parties

seeks an amendment to the existing

contract under sections 205 or 206 of

the FPA, before the contract expires,

and the Commission accepts or

approves an amendment permitting

stranded cost recovery; or (3) if the

public utility files a request, before the

contract expires, to recover stranded

costs through a departing generation

customer’s transmission rates under

FPA sections 205–206 or 211–212.

Fourth, if the selling utility under an

existing wholesale requirements

contract is a transmitting utility but not

also a public utility, and the contract

does not address stranded costs through

an explicit exit fee or other stranded

cost provision, the transmitting utility

may seek to recover stranded costs

through a surcharge to a departing

generation customer’s transmission rates

under FPA sections 211–212. Such

utility may not seek recovery of

stranded costs through a section 211–

212 transmission rate if the existing

requirements contract does contain an

explicit exit fee or other stranded cost

provision.

Fifth, for a retail-turned-wholesale

customer, a public utility or

transmitting utility may file a request to

recover stranded costs from the newlycreated wholesale customer through that

customer’s transmission rates under

FPA sections 205–206 or 211–212.

Sixth, for customers who obtain retail

wheeling, a public utility or

transmitting utility may seek recovery

through Commission-jurisdictional

transmission rates only if the state

regulatory authority had no authority

under state law to address stranded

costs when retail wheeling is required.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21665

904E.g., NIPSCO, Illinois Power, Centerior, Ohio

Edison, EEI.

905E.g., NSP, Ohio Edison.

906See also Minnesota P&L.

907See, e.g., Consolidated Edison Company of

New York, Inc. and Central Hudson Gas & Electric

Corp., 72 FERC ¶ 61,184 at 61,891 (1995) (ConEd).

908 72 FERC at 61,891.

909We note that public utility marketers are

required to file quarterly transaction reports so that

the Commission can monitor the reasonableness of

their charges and their ability to exercise market

power. See Heartland Energy Services, Inc., 68

FERC ¶ 61,223 at 62,065–66 (1994). Unlike

traditional public utilities, marketers do not use

cost-based rates. Approval of the generation rates of

non-jurisdictional transmitting utilities is not

subject to our jurisdiction.

910E.g., Central Hudson, Central Illinois Light,

CVPSC, Citizens Utilities, East Kentucky, IPALCO,

Montana-Dakota Utilities, Seattle, St. Joseph,

Tallahassee, VT DPS.

K. Other

1. Information Reporting Requirements

for Public Utilities

In the NOPR, the Commission did not

propose any changes to its information

filing requirements for public utilities.

Comments

Many IOUs argue that the current

information filing requirements

competitively disadvantage traditional

public utilities and unfairly benefit

sellers, such as power marketers, that

are not required to provide comparable

information.904 They urge the

Commission to eliminate the

requirement for public disclosure of

competitively sensitive, proprietary, or

otherwise confidential Form No. 1 data.

They contend that requiring such

disclosure only from traditional public

utilities harms such public utilities and

compromises the development of

efficient competition. Illinois Power

asks the Commission to review all

information that utilities must file,

including EIA 860, EIA 767, and FERC

Form No. 715.

A number of commenters believe that

some type of information requirement

must also be placed on non-public

utility entities.905 PacifiCorp suggests

that the Commission should require

transmitting utilities that do not file a

Form No. 1 to file similar information

annually with the Commission. Ohio

Edison asserts that the Commission

should extend its use of the reciprocity

concept to require the filing of operating

data with the Commission. Further, if

non-public utility entities are not

required to disclose certain information,

Ohio Edison asserts that all public

utilities that have received approval to

sell power at market-based rates,

including traditional utilities, should

also be free from having to disclose such

information.

Arizona argues that enforcing

comparability vis-a-vis non-public

utility transmitting utilities would seem

to invite jurisdictional challenge. Thus,

it would support legislation to broaden

the Commission’s jurisdiction.906

Commission Conclusion

We will not adopt the suggestion

made by a number of commenters that

we now eliminate the public disclosure

of allegedly competitively sensitive,

proprietary, or otherwise confidential

data submitted to the Commission on

Form No. 1, as well as on other

Commission forms. The information

that we collect from public utilities is

necessary to carry out our jurisdictional

responsibilities and is used, among

other things, to evaluate the

reasonableness of cost-based rates

subject to our jurisdiction and the

operation of power markets.907

Moreover, as we explained in ConEd,

[R]eports required to be submitted by

Commission rule and necessary for the

Commission’s jurisdictional activities are

considered public information. 18 CFR

388.106. In addition, the Commission has

long required jurisdictional utilities to

submit Form 1 data on a form that states on

its cover that the Commission does not

consider the material to be confidential.908

We are sensitive to the lack of

symmetry in the generation information

we require from traditional public

utilities, particularly those that have

market-based rate authority, and the

generation information we require from

other public utilities (e.g., public utility

marketers) authorized to sell at marketbased rates.909 However, the record in

this proceeding is insufficiently

developed for us to make and support

a well-informed decision requiring a

different reporting scheme, particularly

given the industry’s current rapid pace

of change. Also, we are not persuaded

that the burdens borne by traditional

public utilities (primarily annual reports

submitted months after-the-fact) are

impairing the competitiveness of these

utilities so much that we must act

hastily now, instead of deferring a

decision to a more appropriate

proceeding. Moreover, we are required

to regulate the rates of public utilities

and, although we are moving toward

greater reliance on market-based

generation rates, we continue to regulate

generation on a cost basis for most

traditional public utilities, particularly

rates for sales from existing generation.

To assure that these rates are just and

reasonable, we, as well as the customers

of public utilities, need the more

detailed information our regulations

require public utilities to submit.

Accordingly, at this time, we will not

change our information reporting

requirements. As the industry becomes

more competitive, we will monitor our

reporting requirements to make sure

that they are needed, fair to all segments

of the industry, and consistent with the

workings of a competitive environment.

2. Small Utilities

In the NOPR, we did not address

whether special provisions were needed

for small public utilities and small

transmission customers because of the

possible burden of unbundling, open

access tariffs, and the OASIS

requirement.

Comments

A number of commenters assert that

the unbundling requirement poses

significant problems for smaller public

utilities and that small utilities should

not be subject to the same requirements

as larger utilities.910 St. Joseph notes

that in small utilities one system

operator typically runs the system

operations center. Functional

unbundling, it asserts, would require

the addition of another operator for each

shift at great cost to the small utility.

Central Hudson estimates that

unbundling would result in an

approximately 10 percent increase in

the wholesale price, putting small

utilities at a competitive disadvantage.

Several commenters assert that many

small utilities enjoy little or no

transmission market power because

their systems tend to be in parallel with

large systems and are bypassed as a

result. They say that customers prefer to

deal with one large regional utility

rather than pay pancaked transmission

rates for service through two or more

small utilities.

Citizens Utilities argues that some

systems are radial spurs of much larger

systems and merely serve to link points

of interconnection. It claims that a

network tariff is not applicable in such

a case and that it is unlikely that third

parties would request service over such

small or isolated systems. It

recommends that if a utility is basically

a spur system and faces little present or

future demand for third-party service,

the Commission should either relax the

open access requirements or defer them

until a section 211 request is submitted.

East Kentucky proposes that the

Commission exempt not-for-profit

utilities from the requirement to

separate the functions related to

operation and marketing, since small

G&T cooperatives exist solely to serve

the needs of their owner-member

distribution cooperatives.
21666 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

911Non-public utility entities could request that

the Commission find that they can satisfy the

reciprocity condition without meeting all or some

of the requirements that public utilities must meet.

The requests could encompass a wide variety of

circumstances. For example, a non-public utility

could agree to offer comparable transmission

services but not wish to have an OASIS or separate

transmission personnel from wholesale marketing

personnel due to the cost of doing so. The

Commission could find that the entity nevertheless

satisfied the reciprocity condition.

912FERC Stats. & Regs. ¶ 32,514 at 33,095.

913E.g., AMP-Ohio, Missouri Joint Commission,

MT Com, WEPCO, Nebraska Public Power District,

Texas-New Mexico.

914E.g., WEPCO, Portland, WA Com.

VT DPS suggests that waiver of

marketing and transmission personnel

separation requirements may be

appropriate in the case of smaller

utilities that do not operate control

areas. St. Joseph proposes that the

Commission establish a threshold level

based on system demand of 1000 MW,

below which unbundling of wholesale

transmission functions from other

dispatching functions would not be

required. Alternatively, St. Joseph

proposes an exemption from

unbundling where the utility can

demonstrate that it has no market power

and that unbundling would not

materially improve the level of

competition in the generating market.

Central Hudson believes that the

Commission should allow the

development of a short form tariff or

else defer the functional unbundling

requirement for smaller utilities and use

the section 211 process in the interim to

provide flexibility for these utilities.

Oregon Trail EC, a small rural electric,

public utility cooperative, requests that

the Commission revise proposed § 35.28

of its regulations to provide that the

generic open access transmission

requirements apply only to public

utilities that operate facilities used for

the transmission of electric energy in

interstate commerce. It explains that it

owns one transmission line that it leases

to BPA, which operates the line as part

of its integrated transmission network.

Thus, Oregon Trail EC states that it

cannot meet the requirements of the

open access rule. It also points out that

the Commission exempted Oregon Trail

EC and other similarly situated utilities

from the transmission reporting

requirements of Form No. 715 because

they did not engage in transmission

planning.

ALCOA suggests that the default

tariffs for smaller utilities with

transmission systems unlikely to be

used by others should not become

effective automatically. Rather, the

default tariffs should become effective

only when service is requested. Citizens

Utilities suggests that relaxed tariff

requirements be established for small

utilities with insignificant demand for

transmission service.

BG&E believes that a utility using its

system on a network basis for economic

dispatch should not be required to file

a network service tariff if there is no

customer to take the service. It suggests

that if municipalization were to occur,

the Commission could then require the

utility to file, within 60 days, a network

service tariff to serve the new

municipal.

Commission Conclusion

We are sympathetic to the array of

concerns raised by small public utilities

and small transmission customers. The

regulations we are adopting include

waiver provisions under which public

utilities and transmission customers,

and non-public utility entities seeking

exemption from the reciprocity

condition, may file requests for waivers

from all or part of the Commission’s

regulations or for special treatment.911

However, it is difficult to imagine any

circumstance that would justify waiving

the requirements of this Rule for any

public utility that is also a control area

operator.

We recognize, for example, that it

might be a financial burden on small

public utilities to unbundle generation

from transmission, follow standards of

conduct that separate transmission

personnel from wholesale marketing

personnel, and maintain an OASIS.

These requirements may be particularly

burdensome for small public utilities

that own no generation and buy at

wholesale on a radial transmission line

from another utility’s grid. In addition,

if a small public utility’s service

territory is part of another utility’s

control area, the small public utility

should be permitted to make a showing

that it should be exempt from all or

some of the Rule. In this circumstance,

we will consider granting a waiver if the

utility can show that: (1) It does not own

transmission facilities, (2) it has turned

control of its facilities over to someone

else (such as the control area operator)

who complies with the rule as its agent,

or (3) no one is likely to ask to use its

facilities (e.g., because they are radial

lines), and it commits to file an open

access tariff within 60 days of a request

to use its facilities and to comply with

the rule in all other ways.

Because the possible scenarios under

which small entities may seek waivers

from the Final Rule are diverse, they are

not susceptible to resolution on a

generic basis and we will require

applications and fact-specific

determinations in each instance. We

note here that any waivers that we may

grant depend upon the facts presented

in each case. If the circumstances that

give rise to the exemption change, the

waiver may no longer be appropriate.

For example, a radial line today could

very easily become part of a network

tomorrow and a portion of a grid that no

one is interested in using today could

become an important transmission link

tomorrow, especially if retail access is

allowed.

In addition, we will apply the same

standards to any entity seeking a waiver.

This includes public utilities seeking

waiver of some or all of the

requirements of the rule, as well as nonpublic utilities seeking waiver of the

reciprocity provisions contained in the

pro forma open access tariff. Thus, we

would not apply the open access

reciprocity provision to small nonpublic utilities that are not control area

operators and either do not own or

control transmission or have

transmission that no one is likely to ask

to use. They would not have to provide

an open access tariff, establish an

OASIS, or separate operators of

transmission from wholesale purchasers

in order to satisfy the reciprocity

condition for obtaining transmission

service. However, they will have to

apply for this waiver and demonstrate

that they qualify for the waiver.

3. Regional Transmission Groups

In the NOPR, we again expressed our

support for the voluntary formation of

regional transmission groups (RTGs).912

We also explained that the potential

benefits of RTGs would not be

undermined by the rules proposed in

the NOPR.

a. Incentives for RTGs to Form and

Resolve Regional Transmission Issues

Comments

A number of commenters urge the

Commission to provide incentives for

the formation of RTGs within two years

of the adoption of the final rule.913

Several commenters argue that the

Commission should encourage a

regional approach to transmission issues

by expanding the role of RTGs.914 Com

Ed also claims that contract path pricing

problems probably will need to be

resolved at the regional level.

Sierra Pacific Power, which views

open access as the major benefit of

RTGs, questions the need to provide

incentives for the development of RTGs

once open access is implemented.

However, it does see that RTGs may

help promote open access with nonpublic utility entities, who have shown
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21667

915 If an RTG is not a corporate person, each

utility member of the RTG may file the same or

complementary tariffs.

916 58 FR 41626 (August 5, 1993), FERC Stats. &

Regs., Regulations Preambles ¶ 30,976 (RTG Policy

Statement).

917FERC Stats. & Regs. ¶ 32,514 at 33,095.

918E.g., UT Com, ID Com, LA DWP, Nebraska

Public Power District, Salt River, Nevada Power.

See also NEPCO, United Illuminating, Utility

Working Group.

919Also, as we explained with respect to RTGs,

we will review pricing proposals in regional tariffs

pursuant to our Transmission Pricing Policy

Statement.

920This Rule will not resolve disputes over

federal hydro preference policies or over the

agreements incorporated in the Northwest Power

Planning Act.

an increased interest in joining RTGs.

American Wind and MT Com request

that the Commission adopt policies that

will encourage a close working

relationship between RTGs and state

authorities.

Otter Tail contends that the final Rule

should stop short of establishing any

conditions on the formation,

governance, or functions of RTGs,

arguing that such issues are complex

and outside the scope of the NOPR.

ALCOA and Missouri Joint Commission

encourage the Commission to make

certain that its policy regarding RTGs is

not implemented in a manner that

conflicts with the new open access

regime.

Commission Conclusion

We continue to support the

development of RTGs and encourage the

formation of regional tariffs.915 In our

Policy Statement Regarding Regional

Transmission Groups, we first explained

our support for such voluntary

associations.916 We again explained our

support in the NOPR:

We believe that RTGs can speed the

development of competitive markets,

increase the efficiency of the operation of

transmission systems, provide a framework

for coordination of regional planning of the

system and reduce the administrative burden

on the Commission and on members of RTGs

by providing for voluntary resolution of

disputes.917

To further encourage the development

of RTGs, we will accept regional open

access transmission tariffs developed by

RTGs that are consistent with the

objectives of this Rule. This should

make it easier for all parties in a region

to coordinate their activities.

b. Deference to RTGs To Develop

Regional Tariffs and Prices

Comments

A number of commenters urge the

Commission to give considerable

deference to RTGs on such issues as the

formulation of pricing methods and

RTG member duties.918 Nebraska Public

Power District requests that the

Commission consider permitting a

megawatt-mile pricing mechanism for

MAPP. NWRTA urges the Commission

to define clearly how much deference it

will accord to RTGs and explicitly grant

deference to RTGs on such matters as

dispute resolution and decisionmaking

processes. It also asks that the

Commission honor the reciprocity

provisions related to Canadian

participation that are contained in the

NWRTA agreement. Nevada Power

requests the Commission to accept, as

not unduly discriminatory, RTG open

access tariffs that reflect the members’

specific terms and conditions so long as

the tariffs satisfy the substantive

requirements of the final rule. It

proposes that such tariffs be allowed to

become effective without hearing or

refund obligation.

Texas-New Mexico, while

encouraging deference to RTGs in

general, argues that deference must be

conditioned upon a requirement that the

RTG provide not only equal access but

also terms and conditions of service that

are comparable to what a customer

could otherwise obtain under the final

Rule tariff or under section 211 of the

FPA.

Southwest TDU Group contends that

RTGs should not be given deference,

and RTG filings should be subject to the

same standards and scrutiny as nonRTG filings.

Commission Conclusion

As we explained in the RTG Policy

Statement, we intend to give deference

to the planning, dispute resolution, and

decisionmaking processes of an RTG.

With respect to pricing proposals

submitted by RTGs, we believe that

RTGs may be able to develop solutions

to such problems as loop flows through

innovative flow-based pricing

methodologies. As we stated in the

Transmission Pricing Policy Statement,

we will afford considerable deference to

an RTG.

4. Pacific Northwest

Comments

Commenters in the Pacific Northwest

ask the Commission to be flexible in

reviewing tariffs that are based on

regional practices, and that differ from

the final Rule tariff as a result. Public

Generating Pool urges the Commission

to recognize that the Northwest’s

transmission system has been developed

and is operated to support the region’s

coordinated power system. That is, it

wants all hydro spill to be treated

equally with no preference between

federal and non-federal power. Also, it

asserts that firm available transmission

capacity in the Northwest must be

worked out by the NWRTA RTG to

account for the contingent operation of

generation to avoid hydro spill.

Similarly, other commenters note that

the Northwest’s integrated transmission

system was constructed to support a

unique regionwide hydroelectricdependent generating system and that

flexibility is needed to accommodate the

characteristics of the system.

WA Com argues that imposition of a

uniform national tariff would not reflect

the region’s specific system

characteristics or operating practices. It

argues that the final Rule could impede

rather than promote efficient

competition in the Northwest. It

believes that the Commission should

defer to RTGs for defining and

implementing wholesale transmission

access terms and conditions at the

regional level.

The Washington and Oregon Energy

Offices, while supporting the adoption

of regional practices, argues that

uniform transmission principles should

apply for all transmitting entities in the

region. They argue that dispatch

decisions are complicated by flood

control, salmon passage, navigation,

irrigation, and other constraints. Puget

requests that the Commission give each

transmitting utility the flexibility to file

tariffs that fit unique or unusual

circumstances and allow for regional

market differences.

Because the terms and conditions

offered by the smaller transmission

owners in the Northwest are determined

by the terms and conditions offered by

Bonneville, Pacific Northwest Coop

argues that the terms and conditions for

wholesale power transmission, ancillary

services, and RINs should be deferred

until BPA’s 1996 rate case is resolved

and until appropriate regional and

national systems and protocols are

developed.

Commission Conclusion

As we explained with respect to

RTGs, we encourage the filing of

regional open access transmission

tariffs.919 The Final Rule pro forma tariff

contains provisions allowing utilities to

modify tariff terms to reflect prevailing

regional practices. This should permit

entities in the Pacific Northwest to

address unique circumstances that exist

in the Pacific Northwest and to

incorporate prevailing regional practices

(e.g., treatment of hydropower

generation in the priority of dispatch)

into their open access transmission

tariffs.920 This should also encourage
21668 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

921See also Puget, Portland, Reynolds.

922See also Public Power Council.

923See also Snohomish, NPPC, W&O, Public

Power Council, Washington and Oregon Energy

Offices, Direct Service Industries.

924 16 U.S.C. 839–839h.

925 16 U.S.C. 838–838j.

other regional solutions, such as the

development of regional ISOs, to

transmission problems.

In addition, although we will put the

Final Rule pro forma tariff (which

already allow for certain provisions

consistent with regional practices) into

effect for all public utilities 60 days after

publication of this Rule in the Federal

Register, utilities may file regional

tariffs or propose deviations in the pro

forma tariff based on additional regional

needs to be effective at any time

thereafter. Such proposals, however,

will have to be consistent with the

requirements of the Final Rule and be

reasonable, generally accepted in the

region and consistently adhered to by

the transmission provider. Further, we

will not permit entities in a region to

claim different sets of prevailing

regional practices.

5. Power Marketing Agencies

a. Bonneville Power Administration

(BPA)

Comments

Washington Water Power explains

that for open access transmission to be

fully realized in the Pacific Northwest

there must be federal legislation to

remove the monopoly protections of

federally generated power. Until then,

Washington Water Power suggests

certain mitigating measures that would

increase competition in the Pacific

Northwest. It also urges the Commission

to take BPA’s special characteristics into

account in issuing the final rule.

Public Power Council encourages the

Commission to make broad use of

section 211 to mandate transmission

access to ensure that BPA continues to

provide comparable open access

transmission.921

Public Generating Pool argues that the

extent to which BPA’s tariffs are

allowed to deviate from the rule should

be governed by the technical

characteristics of the system and not by

BPA’s status.922

Direct Service Industries argues that

the non-discrimination standard is

made applicable to BPA by section

212(i) and that the Commission has the

authority to review all BPA rates under

the Northwest Power Act (citing Pacific

Northwest Electric Power Planning and

Conservation Act, section 7(a), 16 U.S.C.

839e(a)). It also argues that functional

unbundling is particularly important for

BPA because of BPA’s market power

and relative freedom from regulation.

Clark also argues that the Commission

should require BPA to meet the

comparability standard. It alleges that

BPA refuses to provide comparable

service. It asserts that the Commission

has authority to remedy the problem

under the Energy Policy Act

amendments to section 212, which

Clark states gives the Commission

authority over BPA’s transmission

practices. Clark also notes that BPA is

a member of WRTA and, as such, must

provide comparable service.

Pacific Northwest Coop argues that

many of the issues presented in this

rulemaking are currently being

contested in the BPA rate case in Docket

Nos. WP–96/TR–96 and TC–96. It says

that the Commission should defer

application of the rule to Pacific

Northwest Coop and all of BPA’s

customers until conclusion of the rate

case.

Washington and Oregon Energy

Offices asserts that it would be proper

for the Commission ‘‘to impose similar

transmission price structures upon

Bonneville under section 211 orders as

it will for jurisdictional [public] utilities

under sections 205, 206, and the

NOPR.’’

With respect to stranded costs, BPA

notes that it may be necessary to tailor

a stranded cost policy for BPA that

addresses the goals of open access and

wholesale stranded cost recovery in a

manner consistent with BPA’s unique

circumstances. BPA asks the

Commission to defer consideration of its

stranded investment and related cost

recovery issues until it makes a rate

filing with the Commission.923 It further

argues that the rule should not address

whether and how BPA stranded costs

might be recovered in transmission rates

approved by the Commission under

authority other than sections 211 and

212. Clark argues that the Commission’s

stranded cost recovery policy is

inapplicable to BPA.

NW Conservation Act Coalition makes

the following suggestions: (1) The

Commission should grant BPA the

authority to levy exit fees on customers

who are terminating service and who do

not use BPA’s transmission system for

their new power transaction; (2) any

affected person should be allowed to

petition the Commission for review of

BPA’s rates for inadequate or

inappropriate mitigation of its stranded

benefits; (3) the rule should insist upon

a requirement that open access and

stranded cost recovery be permitted

only if the entities involved can show

there will be no lessening of support for

public purposes; and (4) the

Commission should clarify that the

Direct Service Industries customers are

retail customers and that they will be

subject to recovery of stranded costs and

benefits.

Commission Conclusion

BPA is not a public utility under

section 201(e) of the FPA and, thus, is

not subject to the requirements of this

Rule to put the Final Rule pro forma

tariff into effect. However, there are

three circumstances under which the

Commission may review BPA’s

transmission access and pricing

policies. First, BPA could file an open

access tariff and accompanying rates for

review and confirmation under section

7 of the Pacific Northwest Electric

Power Planning and Conservation Act

(Northwest Power Act) 924 and at that

time could ask the Commission to find

that its tariff meets the Commission’s

open access policies. Second, BPA is a

transmitting utility subject to a request

for mandatory transmission services

under section 211 of the FPA.

Transmission required of BPA under

section 211 would have to be consistent

with the requirements imposed on BPA

under its organic statutes, the Northwest

Power Act, and the Federal Columbia

River Transmission System Act.925

Third, if BPA receives open access

transmission from a public utility, it is

subject to the reciprocity provision

contained in the utility’s Final Rule pro

forma tariff. If BPA seeks to comply

with the reciprocity provision, it could

use the declaratory order procedures we

have provided in this rule for nonpublic utility transmission providers.

Finally, we note that BPA has agreed to

provide open access as a member of two

RTGs approved by this Commission.

With respect to stranded costs, BPA

has asked us to clarify that the Stranded

Cost Rule does not address whether and

how BPA stranded costs might be

recovered in transmission rates

approved by the Commission under

authority other than sections 211 and

212 of the FPA (namely, section 7 of the

Northwest Power Act). We clarify that

this rule addresses only stranded costs

recovered by public utilities under the

FPA and transmitting utilities

(including BPA) that are subject to

mandatory transmission requests under

FPA section 211. It does not address

stranded cost recovery by BPA under

the Northwest Power Act.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21669

926PMAs, however, are transmitting utilities

subject to requests for mandatory transmission

services under section 211 of the FPA.

927See Section IV.G.4.f.

928TVA, however, is a transmitting utility subject

to requests for mandatory transmission services

under section 211 of the FPA.

929We recognize that sections 212(f)(1) and 212(j)

of the FPA, as amended by the Energy Policy Act,

limit the applicability of section 211 to TVA, but

conclude that this limitation in no way affects our

application of the reciprocity requirement to TVA.

Limitations on TVA’s authority to market power are

not the product of this rule but rather of TVA’s

enabling legislation. Thus, it is for Congress to

decide whether TVA should be permitted greater

marketing authority. As noted in our earlier

discussion of reciprocity, TVA is not being required

to file an open access tariff. Rather it is being

precluded from taking advantage of benefits

available under this rule without providing

comparable use of its system to others.

b. Other Power Marketing Agencies

Comments

SEPA requests that the final rule

assure that SEPA can receive network

transmission service when necessary. It

also indicates that it has 58 customers

that receive less than one MW of power,

but that the NOPR pro forma point-topoint tariff contains a one MW

minimum scheduling requirement.

Thus, it requests that the final rule

allow some flexibility with respect to

this requirement so that it can carry

forward its marketing program.

DOE notes that the Western Area and

Southwestern Area Power

Administrations have pledged to offer

transmission services that are

comparable to those required of public

utilities to the extent not otherwise

prohibited by law.

Commission Conclusion

Federal power marketing agencies

(PMAs) are not public utilities as

defined under section 201(e) of the FPA

and, thus, are not required by this rule

to file non-discriminatory open access

transmission tariffs.926 However, to the

extent a PMA receives open access

transmission service from a public

utility, it is subject to the reciprocity

provisions in the utility’s pro forma

tariff.927 If a PMA seeks to comply with

the reciprocity provision, it can file a

proposed tariff and seek a declaratory

ruling.

With respect to SEPA’s concern that

the proposed point-to-point tariff has a

one MW minimum scheduling

requirement, but many of its customers

have loads of less than one MW, we

clarify that the Final Rule pro forma

tariff will allow SEPA to continue to

schedule service for these customers.

Under SEPA’s current transmission

arrangements, it is allowed to aggregate

loads within a single control area that

are less than one MW individually, but

jointly are more than one MW, to meet

the requirement at an interface. The

revised language in the Final Rule tariff

permits this practice to continue. We

also clarify that SEPA, as a seller of

power to multiple purchasers inside

several control areas, is eligible to

receive network service.

6. Tennessee Valley Authority

Comments

TVA is concerned that the final rule

may place TVA at a disadvantage

because its opportunities to participate

in the electricity market outside the

TVA area are so severely limited by

statute. It explains that it is restricted

from directly participating in the new

competitive landscape except through

limited power exchange opportunities

with a few neighboring systems. It urges

the Commission to recognize these

circumstances in the final rule. TVA is

also concerned that its regional

customers may face stranded costs

because its ability to mitigate those costs

by making replacement sales to new

customers is limited.

Commission Conclusion

TVA is not a public utility under

section 201(e) of the FPA and, thus, is

not required to file a non-discriminatory

open access transmission tariff under

this rule.928. However, if TVA receives

open access transmission service from a

public utility, it is subject to the

reciprocity provision in the utility’s pro

forma tariff. If TVA seeks to comply

with reciprocity, it may avail itself of

the Commission’s reciprocity safe

harbor approach, through a declaratory

ruling, if it is fearful that a public utility

may deny it service simply on a claim

that TVA’s non-discriminatory open

access tariff is not satisfactory.929 The

details of this safe harbor procedure are

set forth in Section IV.G.4.f.

7. Hydroelectric Power

Comments

Non-Firm Transactions

ID Com believes that the NOPR

unfairly discriminates against hydrobased utilities. It argues that utilities

that rely heavily on hydropower need to

engage in non-firm market transactions

that depend on water levels; e.g., during

low water years, a utility must have

access to the transmission system to

make non-firm, off-system purchases. It

asserts that the NOPR treats non-firm

sales and purchases as subordinate to

firm transactions and does not allow the

utility to reserve capacity for its critical,

but non-firm, transactions. ID Com also

asserts that the NOPR would, in effect,

strand the utility’s investment in the

production plant being used to generate

power for the non-firm sales.

Idaho complains that the NOPR

unfairly allows a customer to buy and

reserve firm transmission rights surplus

to its needs, but does not permit a utility

to do the same. It explains that this

problem is particularly acute for hydro

utilities and argues that they must be

allowed to reserve at tariff rates at least

a portion of available transmission

capacity for firm and non-firm

wholesale transactions. In the

alternative, Idaho asserts that the

transmission owner should not be

required to provide point-to-point

service for transmission uses other than

from demonstrated firm obligations.

Commission’s Licensing Practices

National Hydropower argues that in

light of the NOPR the Commission

should reexamine the manner in which

it exercises its FPA Part I authority with

respect to (1) economic feasibility

determinations, (2) section 10(a)

findings, (3) determinations of section

10(j) recommendations, and (4) section

13. For example, it states that the NOPR

suggests that all future electric resource

selection decisions should be based

exclusively on short-run marginal cost

comparisons. Because, it asserts,

hydroelectric power provides many

public interest benefits not susceptible

to precise quantification, the

Commission should clarify how nonprice factors are to be considered in a

post-final rule wholesale electric

marketplace.

Commission Conclusion

Non-Firm Transactions

As we explained above with respect

to the Pacific Northwest, we will permit

entities to incorporate prevailing

regional practices (e.g., treatment of

hydropower generation in the priority of

dispatch) into regional open access

transmission tariffs. This should permit

entities in a region to resolve concerns

over the scheduling of non-firm

hydropower. In addition, if a utility and

its customers can agree on the

scheduling of non-firm hydropower and

the disruption of firm transactions, we

would permit that resolution to be

incorporated into the utility’s tariff.

Utilities are permitted to consider

seasonal variations in hydropower

availability in the determination of

Available Transmission Capacity to be

posted on the OASIS.

Commission’s Licensing Practices

The issues raised by National

Hydropower with respect to our
21670 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

930E.g., Urban League, Latin League, Black

Mayors, Homelessness Alliance, National Women’s

Caucus, La Raza.

931References throughout the Environmental

Statement are to emissions from the electric

industry, and not to emissions from all sources.

932Coalition on Sensible Transportation, Inc. v.

Dole, 826 F.2d 60, 66 (D.C. Cir. 1987). The Court

added that ‘‘[i]t is of course always possible to

explore a subject more deeply and to discuss it

more thoroughly. The line-drawing decisions

necessitated by this fact of life are vested in the

agencies, not the courts.’’ Id.

hydroelectric licensing practices are

beyond the scope of this rulemaking.

Indeed, National Hydropower has

already raised its concerns in a petition

to the Commission to revise our

hydroelectric licensing procedures, filed

on July 10, 1995. That is the proper

proceeding in which to address our

hydroelectric licensing practices.

8. Residential Customers

Comments

Several commenters are concerned

that the rule may undermine the

financial position of public utilities so

that they will not be able to provide

many of the programs that benefit lowincome residents (e.g., assistance to lowincome and elderly consumers,

weatherization and energy conservation

programs, and payment of taxes that

provide many city services).930

La Raza is concerned that the rule will

permit large preferred customers to opt

out of the regulated structure, leaving

behind a smaller and less affluent base

to support the long-term investments

made under the previous regulatory

environment.

Home Builders is concerned that

utilities may compensate for reduced

profits under the proposed rule by

raising infrastructure charges and

hookup fees for new homes, thus

reducing new home sales.

State and City Supervised Housing for

Equity in Electric Rates states that

publicly supervised housing is uniquely

qualified to obtain open access

electricity from wholesale markets, and

that the Commission should adopt

policies that bring competitive benefits

to residents of such housing.

Commission Conclusion

While some residential consumers

may be apprehensive about the changes

that this rule may have on the electric

industry, we are convinced that the

changes we are proposing for wholesale

markets will benefit them. As wholesale

transmission open access becomes a

reality, residential consumers should

reap the benefits of more competitive

bulk power markets and associated

lower costs. This rule does not require

retail transmission access for retail

customers of any size. Moreover, this

rule does not require any changes in

programs such as assistance to lowincome and elderly consumers and

weatherization and energy conservation.

As discussed in Section IV.I, those

programs are under the jurisdiction of

the individual states, and will remain

under their jurisdiction. Indeed, this

rule contains several safeguards to

maintain the ability of states to impose

conditions on retail access, such as

conditions that help to protect

residential customers from becoming

the residual payer of stranded costs.

V. Environmental Statement

This section reviews and adopts the

final environmental impact statement

(FEIS) prepared by the Commission staff

in connection with this rule. It identifies

the alternatives considered by the

agency in reaching its decision; analyzes

and considers whether and to what

extent the chosen alternative—adoption

of this rule—is likely to result in

environmental harm; evaluates

alternatives and suggestions for

mitigating environmental harm from the

rule, if any; and states the Commission’s

decision.

Summary

A. The Environmental Impact Statement

The Commission decided to prepare

an environmental impact statement

(EIS) evaluating the environmental

consequences that could result from

adoption of this rule. We did so largely

in response to the claims of several

commenters, including the

Environmental Protection Agency

(EPA), who charge that the rule will

have significant adverse environmental

effects.

Although a number of issues were

raised, by far the most prominent

concern arises from the theory that

competitive market conditions created

by the rule will provide an advantage to

power suppliers who produce power

from coal-fired facilities that are not

subject to stringent environmental

controls on nitrogen oxides (NOX)

emissions.931 Under this theory, these

facilities, located primarily in the

Midwest and South, will, as a result of

the rule, generate more power and emit

more NOX, which will contribute to

ozone formation. The ozone could add

to pollution both in those regions and

more significantly in the Northeast, to

which area such pollutants could be

transported. Those who propound this

theory argue that it is the responsibility

of the Commission, using its authority

under the Federal Power Act, to effect

environmental controls that will

mitigate what they predict will be

significant increases in NOX emissions

associated with this rule.

The staff prepared an FEIS based

upon computer modeling simulations of

power generation patterns and NOX

emissions likely to occur as a result of

the rule. Staff used widely accepted

models for studying economic

conditions in power markets and

simulating emissions of NOX and other

pollutants. These models took into

account a variety of different

assumptions concerning significant

factors such as coal and natural gas

prices and other competitive conditions.

These factors are critical because

increased use of coal-fired generation

tends to increase NOX emissions, while

increased use of gas-fired generation is

environmentally more benign.

The examination in the FEIS of the

environmental effects that are likely to

result from implementing the rule is

based on an analytic framework that

was shaped by comments received in

the scoping process and on the DEIS.

The study was revised to reflect the

frozen efficiency reference case

assumptions requested by EPA and

other commenters. This was done to

ensure full disclosure of possible

environmental impacts even though the

Commission disagrees that use of these

assumptions is appropriate.

It has been observed in the context of

agency preparation of an environmental

study that ‘‘(t)he NEPA process involves

an almost endless series of judgment

calls.’’ 932 That is particularly true

where, as here, the agency undertakes to

examine the impacts of a proposed

regulatory program. In designing an

effective assessment of the

environmental impacts of the rule, the

Commission had to make a number of

judgments as to the type and the scope

of studies necessary to analyze the

proposals sufficiently. Commenters also

raised many issues related to the design

of the study. For example, the Center for

Clean Air Policy contends that the

Commission should model a range of

mitigation policies; the Missouri

Department of Natural Resources

contends that the impact of the rule on

generation may be locally intense and

that these effects should have been

studied; and other commenters sought

to have the Commission examine

different database or modeling

assumptions.

For these and similar matters we

exercised our judgment as to the

appropriate manner in which to treat

the issue. For example, we determined

not to model a range of mitigation
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21671

933See Section V, Discussion, Subsection C.

934 Generally, a relative advantage for coal is

likely to increase environmental impacts while a

relative advantage for natural gas is likely to create

modest environmental benefits.

935A third scenario considered improved

conditions for the transmission system only. This

scenario showed very small effects from the rule

and is not addressed further here.

policies because we did not find that the

impacts of the rule require the

Commission to adopt or implement a

plan of mitigation. It would have been

extremely difficult, if not impossible, to

examine the many varied local impacts

that could be expected across the Nation

in response to the Rule. We made

judgments as to the appropriate

database and modeling assumptions to

use—in some cases, those assumptions

were shaped or changed by comments

we received.

In short, many competing

considerations came into play during

the design of the complex analysis used

to examine the environmental effects of

the rule. We exercised our judgment, for

example, based on consideration of

whether matters are within the scope of

the rule, the most appropriate way to

study the effects of the proposal, and

whether the issues raised were relevant

to a consideration of the environmental

effects of the rule. The Commission’s

response to issues raised by commenters

is reflected in the response to comments

set forth in Appendix J of the FEIS. We

conclude that the FEIS reflects the

appropriate consideration of these and

many similar issues.

B. Major Issues

Some comments on the draft

environmental impact statement (DEIS),

as well as earlier comments in response

to Commission scoping inquiries, raise

two major areas of objection to the

Commission’s analysis. First,

commenters claim that in determining

what NOX emission levels would be in

the future with the adoption of the rule,

the Commission did not compare the

emissions levels associated with the

rule against the appropriate base case.

They argue that the Commission should

have analyzed and compared the

impacts of the rule to a ‘‘no-action’’

alternative that assumes that the

Commission abandons all its open

access policies, not just this rule. Some

commenters, including EPA, go even

further, suggesting that the Commission

compare emission levels projected to

result from the rule against a ‘‘frozen

efficiency’’ case in which other major

factors—factors that would increase

industry efficiency independent of the

Rule—do not occur. Such factors

include adoption of pro-competitive

state policies and actions by utilities to

undertake mutually beneficial voluntary

transactions that do not require the use

of open access tariffs mandated under

this rule. Commenters who advocate

either a different ‘‘no-action’’ alternative

or the frozen efficiency case expect that

studies using those assumptions will

show that the rule will cause

significantly greater NOX emissions than

shown in the DEIS.933

Assuming these results, these

commenters raise their second major

area of concern, which is mitigating the

presumed effects of the rule. These

arguments vary somewhat but share a

common theme: That the Commission

has a responsibility, either as a legal or

public policy matter, to mitigate what

they expect to be the significant

environmental impact associated with

the rule. They suggest various

mitigation schemes, including a FERCadministered NOX emission allowance

program along the lines of the sulfur

dioxide (SO2) program enacted by

Congress and administered by the EPA

under the Clean Air Act. Other

proposals would have the Commission

condition the right of a seller to use an

open access tariff on certification that

the source of the power sold is in

compliance with (as yet undetermined)

emissions limitations. Another proposal

would have the Commission impose a

charge on emissions to be paid by

utilities to a fund established by the

Commission. The added cost to the

utilities would work to account for, or

‘‘internalize’’, the external costs of

emissions.

Commenters advocating Commissionadministered mitigation argue that the

mechanisms under current law for

regulating NOX emissions are

cumbersome and slow, and that the

Commission should not (some argue,

may not) go forward with the rule

unless it puts in place environmental

regulatory mechanisms that prevent

further increases in NOX emissions.

Various legal theories are advanced as

a basis for Commission environmental

regulation under the Federal Power Act.

Some argue that the conditioning

authority under the Federal Power Act

is sufficient to enable us to fashion

comprehensive controls on emissions

from utility generators because there is

a direct causal nexus between power

trading (which we regulate) and

generation (which we do not). Others

argue that such authority lies in the use

of our power to impose requirements on

utilities ‘‘in the public interest’’,

enhanced by the National

Environmental Policy Act. Others argue

that, in remedying undue

discrimination, we must correct

competitive advantages arising from

Congressional decisions to exempt

certain kinds of generation facilities

from some Clean Air Act regulation.

C. Commission Conclusions

After reviewing the comments and the

additional studies conducted by staff in

response to the comments, the

Commission adopts the findings in the

FEIS.

First, the findings show that, without

the rule, NOX emissions are expected to

decline until at least the year 2000.

Thereafter, again without the rule, NOX

emissions are expected to increase

steadily through the year 2010 (the end

of the FEIS study period). The extent of

the decrease and the increase will

largely be determined by the relative

prices of natural gas and coal, the two

main fuels used to generate electric

power in most regions.934

In reaching this conclusion, the FEIS

used two ‘‘base’’ cases. In one (the

‘‘High-Price-Differential Base Case’’),

natural gas was assumed to become

substantially more expensive compared

with coal than it is today. In the other

(the ‘‘Constant-Price-Differential Base

Case’’), natural gas was assumed to

maintain essentially the same price

relative to coal that has existed for the

last ten years. The two cases describe

the range of emissions due to fuel price

uncertainty without the rule and

demonstrate the overall trends of

decreases until 2000 and increases

thereafter.

Second, the FEIS finds that the rule

will not in any significant respect affect

these overall trends.

The potential impact of the rule was

studied initially under two scenarios.935

In one (the ‘‘Competition-Favors-Gas

Scenario’’), the rule is assumed to result

in efficiency gains in the electric

industry that would tend to favor

natural gas as a fuel. In this scenario the

effect of the rule is slightly beneficial.

Total NOX emissions are reduced

overall by about two percent nationwide

from the base cases. In the other (the

‘‘Competition-Favors-Coal Scenario’’),

the rule is assumed to result in

efficiency gains in the electric industry

that would tend to favor coal as a fuel.

In this scenario the effect is again slight,

showing approximately a one percent

increase in NOX emissions nationwide

from the base cases. In both scenarios,

however, the rule does not have an

overall effect on NOX emission trends.

Stated differently, under any case

studied, with or without the rule, there

will be an overall net decrease in NOX
21672 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

936These results are set forth graphically and in

tabular form in the FEIS at pp. ES–3 and ES–13.

They are also reproduced in Appendix H.

937Although DOE agreed with EPA’s request that

we analyze the frozen efficiency case as a reference

case, DOE believes that the DEIS selected the

appropriate base case. DOE also argues that the

mitigation of any adverse consequences from the

rule should be addressed by EPA under the Clean

Air Act or by the Congress.

938FEIS Table 6–10 at p. 6–17.

939 Id.

emissions through the year 2000.936

Thereafter, NOX emissions begin to

increase. The rule does not materially

affect either the decline prior to 2000 or

the increase thereafter.

Based on these findings the

Commission concludes that a

comprehensive, Commission-imposed

mitigation scheme to address the

environmental consequences of the rule

is not appropriate. If competition favors

gas, the effects are beneficial and

mitigation is unnecessary. If competitive

conditions favor coal through the year

2010, and NOX emissions increase

slightly as a result of the rule, these

minor effects would be effectively

mitigated as a part of a comprehensive

NOX cap and trading allowance scheme

developed by EPA in cooperation with

the Ozone Transport Assessment Group

(OTAG) and administered by EPA and

state environmental regulators under the

clearly established authority of the

Clean Air Act.

Further, the Commission believes that

staff has selected the appropriate ‘‘noaction’’ alternative. An alternative that

requires the Commission to reverse all

its other open access policies is simply

not a ‘‘no-action’’ alternative. To the

contrary, it would require decisive

action running counter to the direction

from the Congress in the Energy Policy

Act and the needs of the marketplace

and electricity consumers.

However, to ensure that the effects of

the rule were analyzed fully, the FEIS

did study a reference case based on the

‘‘frozen efficiency’’ case proffered by

EPA and the Department of Energy

(DOE).937 Although, as described below,

we believe this case to be highly

unlikely, the results show that, even

under this scenario, the impacts of the

rule are not great and do not vary

significantly from those projected by

staff under the other assumptions.

In one case requested by EPA, staff

studied a combination of assumptions

most likely to show significant increases

in emissions associated with the rule;

the case included EPA’s frozen

efficiency scenario, coupled with the

‘‘Competition-Favors-Coal’’

assumptions. Other cases requested by

EPA posit dramatic increases in

transmission capacity (that we find

highly unlikely). Even this combination

of assumptions—geared to demonstrate

the greatest impact the rule might have

on increased NOX emissions—produced

little in the way of environmental

consequences associated with the rule.

Under these extreme (and unlikely)

conditions, there would still be a net

decrease in NOX emissions until at least

the year 2000, albeit a smaller decrease

than in the base cases. Comparing

projections of emissions for the same

years, emissions would be higher than

the base cases only by two percent in

2000 and three percent in 2005.938 It is

only in the year 2010, assuming these

improbable scenarios, that NOX

emissions associated with the rule

would be higher than the base case by

even five percent.939

Based on these studies, including the

EPA reference case, the Commission

endorses the staff findings that the rule

will affect air quality slightly, if at all,

and that the environmental impacts are

as likely to be beneficial as negative.

This is true even under scenarios

contrived to maximize emissions

associated with the rule under

circumstances that this Commission

believes to be highly unlikely.

Importantly, this is also true in the

near- to mid-term. Until the year 2010,

even the worst case (the frozen

efficiency case) produces results very

similar to those produced using

assumptions the Commission believes to

be reasonable. In short, the rule will not

produce an ‘‘ozone cloud’’ coming

across the Appalachians to threaten the

Northeast on the day the rule goes into

effect. Assuming that any environmental

impacts occur, they are years in the

future and may well be beneficial. As a

result, calls for Commission mitigation,

and in particular for interim mitigation

to ‘‘fill the gap’’ until programs under

the Clean Air Act can be adopted, are

unnecessary and disproportionate to the

possible effects of the rule.

We also endorse the staff view that it

is neither within our statutory authority

nor appropriate as a matter of policy to

fashion from the FPA a comprehensive

clean air regulatory program to address

NOX emissions. As described below, we

believe that the mitigation proposals

proffered in comments exceed our

statutory authority to regulate rates,

terms and conditions of sales of electric

energy and transmission of electric

energy in interstate commerce. We are,

in essence and by law, economic

regulators. While we have an obligation

under NEPA to take the environmental

consequences of our actions into

account in fashioning our decision—and

we have done so—NEPA grants us no

new regulatory powers. While NEPA

extends our general obligation to engage

in reasoned decisionmaking to include

the consideration of possible

environmental consequences of our

actions, it compels no particular

substantive result.

Though our conditioning authority

under sections 205 and 206 of the FPA

is broad, our actions under it are

confined to the subject matter of our

jurisdiction. That subject matter

excludes the physical aspects of

generation and transmission. Our

actions must derive from and advance

our statutory mandate to protect

consumers by establishing utility rates

and business practices that are just,

reasonable, and not unduly

discriminatory or preferential. These

authorities, however broad they are with

respect to economic matters, are not

unbounded; they may not be used to

‘‘fill in the gaps’’ of regulatory programs

that, by law, are not our own.

Moreover, even if it were possible to

tease from the FPA some implicit

authority to regulate NOX emissions

from utility generators, it is not feasible

for this Commission to develop and

implement such a program. The

mitigation schemes presented in

comments are filled with unknowns and

complexities that are best resolved by

those charged with administration of the

Nation’s environmental laws. In some

cases, the mitigation schemes are based

on a model of utility transactions that is

fundamentally at odds with the

purposes of the rule. For example,

several proposals would require the

Commission to establish whether

emissions from certain units or systems

contribute to ozone noncompliance

elsewhere, perhaps hundreds of miles

away. Other proposals would require

the Commission to establish baseline

standards for emissions; generating

units with emissions above that level

would be required to adopt mitigation

measures. The technical difficulties

associated with these proposals are

evident on their face. While resolving

these issues is necessary to establish an

effective NOX regulatory program, the

Commission does not possess the

requisite expertise to establish baseline

NOX emission levels and address the

difficult technical and policy issues that

are presented in regulating NOX

emissions. EPA is the agency with

jurisdiction over and experience with

such matters. Although efforts are

underway to resolve these issues within

the framework of the Clean Air Act, all

air regulators agree that much work still

needs to be done.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21673

940For example, the data we used to project future

industry generation and fuel use update by several

years the data relied upon by EPA in its Regulatory

Impact Analysis used as a basis for its recently

proposed NOX rule, entitled ‘‘Acid Rain Program;

Nitrogen Oxides Emission Reduction Program.’’ 61

FR 1442 (1996). We believe the data developed in

the FEIS will make a useful contribution to EPA’s

effort.

941 18 CFR 380.4(a)(15).

942 60 FR 36752 (1995).

943 60 FR 58304 (1995).

944 61 Fed.Reg. 17,296 (1996).

945See 40 CFR 1507.3 (1995); 18 CFR 380.4

(1995).

Other proposals would require the

Commission to track generation that is

used for wholesale versus retail sales.

However, for example, use of holding

company corporate structures, as well as

emerging market structures, would

make it extremely difficult, if not

impossible to distinguish between retail

and wholesale transactions. In addition,

such measures are inconsistent with the

goals of the rule (and the Energy Policy

Act) to eliminate time-consuming,

inefficient transaction-based approvals

that impede open access and to promote

entry of sellers into bulk power markets

on a competitive basis.

Moreover, any such program

implemented by this Commission could

well undercut the existing regulatory

scheme crafted by Congress under the

Clean Air Act, as amended. In

particular, we are being asked

essentially to rework the legislative

decisions made by Congress regarding

certain coal-fired generators. Those

decisions are at the heart of the 1990

Clean Air Act compromise. The only

means Congress has made available for

addressing these problems under

current law are in the Clean Air Act. If

these means prove insufficient to

address the NOX problem overall, the

case for change must be presented to the

Congress.

Although we have concluded that

NOX emissions problems are most

effectively addressed by clean air

regulations within the framework of the

Clean Air Act, we do recognize that the

question of NOX emissions is a very

important one. Our FEIS documents

that, with or without this rule, NOX

emissions from all sources are expected

to increase over time. This will present

a significant environmental issue for the

Northeast, which is already struggling to

reach current NOX reduction standards,

as well as for other regions of the

country that are being called on to

participate in an inter-regional solution

to the NOX problem. As the EPA rightly

recognizes, attempting to frame an

appropriate solution with the tools

currently available is a tough job. We

therefore understand why those

concerned would try to enlist this

Commission in an effort to solve this

problem with regulatory mechanisms

other than those set out in the Clean Air

Act. We also understand why even the

prospect of exacerbating that problem

would ignite the kind of controversy

reflected in the comments to this rule,

and why, in response, those who have

gained Congressional exemptions from

certain regulations wish not to have

those benefits undermined. At the same

time, we understand, and have great

sympathy with, the many commenters

who have suggested that the economic

benefits of this rule to consumers

should not be suppressed or delayed by

this difficult, ongoing debate.

Our FEIS clearly demonstrates that

this rule is not the appropriate vehicle

for resolving this very important debate.

We believe that our study makes a

significant contribution nonetheless. We

have added significantly to the

understanding of the problem and have

established a viable, current baseline for

assessing future industry trends. This

baseline should serve air regulators well

in analyzing overall NOX emissions in

the future.940 We have resolved some

important questions about the role of

open access and have established

clearly the influence of energy prices on

NOX emissions in the future.

Our study also supports the view held

by many commenters that the

appropriate regulatory mechanisms for

addressing the NOX problem overall,

including emissions from electric utility

generating plants, is a NOX emissions

cap and allowance trading scheme along

the lines of that developed by the

Congress under the Clean Air Act for

SO2 emissions. As staff suggests, even if

there are slight environmental impacts

associated with the rule, they are better

and more effectively addressed as a part

of a comprehensive NOX regulatory

program. While Congress did not enact

such a scheme for NOX, it did, as

described below, empower the EPA to

establish such a program. The EPA is

the only federal agency with clear

authority and expertise to address this

problem. It should do so.

The FEIS also identifies the

importance of OTAG to the

development of a fair and effective NOX

regulatory program. OTAG, which

includes representatives from all

affected states, is currently at work

developing the analytic basis needed for

a regional consensus solution to the

NOX problem. OTAG is also evaluating

possible solutions, including an

allowance trading scheme. We believe

that OTAG’s efforts are to be applauded,

and we encourage the EPA and all

interested parties to work with OTAG to

address this issue of national concern.

Discussion

A. Compliance With NEPA

Requirements

1. Background

The Commission issued a NOPR in

this proceeding on March 29, 1995. In

doing so, we concluded that

promulgating the proposed Rule would

not represent a major federal action

having a significant adverse impact on

the human environment and that the

proposed Rule fell within the

categorical exemption provided in the

Commission’s regulations for electric

rate filings submitted by public utilities

under sections 205 and 206 of the

FPA.941 Subsequently, the Commission

determined that, despite the availability

of the categorical exclusion, it would

nonetheless prepare an environmental

analysis. On July 12, 1995, the

Commission directed staff to prepare an

EIS to assess the environmental impacts

of the proposed Rule. That notice

requested comments on environmental

issues and scheduled a scoping meeting

for September 8, 1995.942

A Notice of Availability of the DEIS

was published in the Federal Register

on November 27, 1995.943 The DEIS

evaluated several potential alternatives

and mitigation measures as summarized

below.

A Notice of Availability of the FEIS

was published in the Federal Register

on April 19, 1996.944

2. General Requirements

Section 102 of NEPA, 42 U.S.C. 4332,

requires that federal agencies prepare an

EIS on proposals for major federal

actions significantly affecting the

quality of the human environment. The

objective is to build into the agency

decisionmaking process careful

consideration of environmental aspects

of proposed actions, including the

evaluation of reasonable alternatives.

Although we believe a categorical

exclusion to be available,945 the

Commission has performed this EIS to

ensure that this Rule is promulgated

with the benefit of careful consideration

of its environmental aspects.

3. Alternatives

The consideration an agency must

give in an EIS to alternatives to its

proposed action is bounded by a

number of factors, including notions of

feasibility, whether basic changes would
21674 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

946 Vermont Yankee, 435 U.S. at 551.

947 Id.

948Laguna Greenbelt, Inc. v. DOT, 42 F.3d 517,

524–25 (9th Cir. 1994).

949Resources Limited, Inc. v. Robertson, 35 F.3d

1300, 1307 (9th Cir. 1993).

950 Id.

951 Id.

952 Id.

953National Wildlife Federation v. Whistler, 27

F.3d 1341, 1345 (8th Cir. 1994).

954Missouri Mining, Inc. v. ICC, 33 F.3d 980, 984

(8th Cir. 1994).

955Communities, Inc. v. Busey, 956 F.2d 619, 627

(6th Cir.), cert. denied, 506 U.S. 953 (1992).

956See Section V, Discussion, Subsection B.2.

957Methow Valley, 490 U.S. at 350–51 (citations

and footnote omitted) (emphasis added).

958 Id. at 351 (footnote omitted).

959 Id. at 351–52 (citation omitted).

be required to the statutes and policies

of other agencies, and the extent to

which the proposal would result in

significant impacts. The United States

Supreme Court (Supreme Court or

Court) stated what is required in an EIS

with regard to alternatives in Vermont

Yankee Nuclear Power Corp. v. NRDC,

435 U.S. 519, 551 (1978): ‘‘(A)s should

be obvious even upon a moment’s

reflection, the term ‘alternatives’ is not

self-defining. To make an impact

statement something more than an

exercise in frivolous boilerplate the

concept of alternatives must be bounded

by some notion of feasibility.’’ 946 In

this regard, the Supreme Court quoted

Natural Resources Defense Council v.

Morton, 458 F.2d 827, 837–38 (D.C.Cir.

1972), with approval as follows:

There is reason for concluding that NEPA

was not meant to require detailed discussion

of the environmental effects of ‘‘alternatives’’

put forward in comments when those effects

cannot be readily ascertained and the

alternatives are deemed only remote and

speculative possibilities, in view of basic

changes required in statutes and policies of

other agencies—making them available, if at

all, only after protracted debate and litigation

not meaningfully compatible with the timeframe of the needs to which the underlying

proposal is addressed.

The Supreme Court went on to discuss

the concept of ‘‘feasibility’’, stating that:

Common sense also teaches us that the

‘‘detailed statement of alternatives’’ cannot

be found wanting simply because the agency

failed to include every alternative device and

thought conceivable by the mind of man.

Time and resources are simply too limited to

hold that an impact statement fails because

the agency failed to ferret out every possible

alternative, regardless of how uncommon or

unknown that alternative may have been at

the time the project was approved.947

Thus, an EIS must discuss the

alternatives that are feasible and briefly

discuss the reasons others were

eliminated. There is no minimum

number of alternatives that must be

discussed.948 An agency’s consideration

of alternatives is adequate if it considers

an appropriate range of alternatives—it

does not have to consider every

available alternative.949

The range of alternatives that must be

considered in the EIS need not extend

beyond those reasonably related to the

purposes of the project.950 An agency is

entitled to identify some parameters and

criteria related to the proposal for

generating alternatives to which it

would devote serious consideration.

Without such criteria, an agency could

generate countless alternatives.951

Alternatives that are unlikely to be

implemented need not be considered,

nor must an agency consider

alternatives that are infeasible,

ineffective, or inconsistent with basic

policy objectives.952 In this sense,

central to evaluating practicable

alternatives is the determination of a

project’s purpose.953

Furthermore, the range of alternatives

that reasonably must be considered

decreases as the environmental impact

of a project becomes less and less

substantial. If a proposal would have

minimal environmental effect, the range

of alternatives that must be considered

is narrow. It would be an anomaly to

require that an agency search for more

environmentally sound alternatives to a

project that it has determined will have

no significant environmental effects.954

Moreover, feasible alternatives may be

rejected if they present unique problems

or cause extraordinary costs and

community disruption.955

As applied to the instant case, NEPA

does not require the consideration of

alternatives that are remote and

speculative possibilities because they

would require basic changes to statutes

and policies. Therefore, alternatives that

would require the Commission to ignore

open access policies enacted by

Congress in the Energy Policy Act and

to assume such policies would not be

pursued by the states are not feasible

and need not be considered. Likewise,

the Commission need not consider

alternatives that are ineffective or

inconsistent with basic policy

objectives, or that would cause

extraordinary costs and community

disruption. Finally, because the rule

would have minimal environmental

effect, the range of alternatives that must

be considered is narrow. We conclude

that staff has examined the appropriate

alternatives in the FEIS and correctly

determined that promulgation of the

rule represents the most appropriate

action.

Certain commenters have argued that

the alternative that calls for the

Commission to abandon the policy of

promoting transmission access is more

appropriate for the no-action alternative

than the no-action alternative selected

by the staff.956 We disagree. As

discussed below, that contention is

more properly an argument about the

appropriate baseline to use in the FEIS.

That debate has been resolved by the

consideration of a reference case that

includes a baseline which bounds the

effects that those commenters seek to

have analyzed.

4. Mitigation

To fulfill the requirements of NEPA

with regard to mitigation, an agency

must identify and evaluate the adverse

environmental effects of the proposed

action, in this case the rule. Having

identified and evaluated adverse

environmental effects, the agency is not

constrained from then deciding that

other values outweigh the

environmental costs of the proposal.

The leading case interpreting this

requirement is Robertson v. Methow

Valley Citizens Council, 490 U.S. 332

(1989)(Methow Valley). There, the Court

explained that:

Although these procedures (preparation and

circulation of an EIS) are almost certain to

affect the agency’s substantive decision, it is

now well settled that NEPA itself does not

mandate particular results, but simply

prescribes the necessary process. If the

adverse environmental effects of the

proposed action are adequately identified

and evaluated, the agency is not constrained

by NEPA from deciding that other values

outweigh the environmental costs * * *.

Other statutes may impose substantive

environmental obligations on federal

agencies, but NEPA merely prohibits

uninformed—rather than unwise—agency

action.957

The Court held that ‘‘(t)o be sure, one

important ingredient of an EIS is the

discussion of steps that can be taken to

mitigate adverse environmental

consequences.’’ 958 This is so because:

Implicit in NEPA’s demand that an agency

prepare a detailed statement on ‘‘any adverse

environmental effects which cannot be

avoided should the proposal be

implemented, 42 U.S.C. 4332(C)(ii), is an

understanding that the EIS will discuss the

extent to which adverse effects can be

avoided. More generally, omission of a

reasonably complete discussion of possible

mitigation measures would undermine the

‘‘action-forcing’’ function of NEPA. Without

such a discussion, neither the agency nor

other interested groups and individuals can

properly evaluate the severity of the adverse

effects * * * .959

The Court acknowledged that:

There is a fundamental distinction, however,

between a requirement that mitigation be
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21675

960 Id. at 352–53 (citation and footnote omitted).

961 Id. at 353 n .16.

962The process appropriate for CEQ referral of

actions by an independent regulatory agency is not

addressed here.

963For example, see the discussion on

transmission constraints at Section V, Discussion,

Subsection C.

964See Alaska v. Andrus, 580 F.2d 465 (D.C. Cir.),

vacated in part on other grounds sub nom. Western

Oil & Gas Ass’n v. Alaska, 439 U.S. 922 (1978).

965The Commission bears the ultimate

responsibility for evaluating the environmental

impacts of the rule. In doing so, it must consider

EPA’s comments, but is not bound by them. See

Citizens Against Burlington, Inc. v. Busey, 938 F.2d

190, 201 (D.C.Cir.), cert. denied, 502 U.S. 994

(1991). In that case the Court held that:

Congress wants the EPA to participate when other

agencies prepare environmental impact statements.

See 42 U.S.C. 7609(a). The EPA participated here.

But the (Federal Aviation Agency), not the EPA,

bore the ultimate statutory responsibility for

actually preparing the environmental impact

statement, and under the rule of reason, a lead

agency does not have to follow the EPA’s comments

slavishly—it just has to take them seriously. See

Alaska v. Andrus, 580 F.2d at 474.

966See Section III.

967See Section I.

discussed in sufficient detail to ensure that

environmental consequences have been fairly

evaluated, on the one hand, and a substantive

requirement that a complete mitigation plan

be actually formulated and adopted, on the

other * * *. Even more significantly, it

would be inconsistent with NEPA’s reliance

on procedural mechanisms—as opposed to

substantive, result-based standards—to

demand the presence of a fully developed

plan that will mitigate environmental harm

before an agency can act.960.

The Court again stressed that

‘‘(b)ecause NEPA imposes no

substantive requirement that mitigation

measures actually be taken, it should

not be read to require agencies to obtain

an assurance that third parties will

implement particular measures.’’ 961

Thus, the Court held that mitigation,

including mitigation that other

governmental bodies have jurisdiction

to implement, must be discussed in

sufficient detail to ensure that

environmental consequences of a

proposed action have been fairly

evaluated. However, a complete

mitigation plan need not be actually

formulated or adopted.

The suggestion by various

commenters that the Commission is

required to adopt and implement a plan

to mitigate the impacts of the rule is

without legal or factual basis. Even if

the effects of the rule were greater than

the FEIS shows them to be, Methow

Valley clearly establishes that,

regardless of the impacts of the

proposed action, the Commission is

required only to understand the impacts

of its actions. This compels us to

consider and discuss mitigation; it does

not require us to adopt and implement

mitigation. This FEIS thoroughly

examines mitigation of possible adverse

environmental effects and concludes

that sufficient mechanisms exist to

address the impacts of the rule, if any.

5. Role of EPA

Section 309 of the Clean Air Act, 42

U.S.C. 7609, authorizes EPA to review

and comment on environmental impact

statements prepared by federal agencies.

If the EPA Administrator determines

that a proposed regulation is

unsatisfactory from, among other things,

the standpoint of environmental quality,

she may refer the matter to the Council

on Environmental Quality (CEQ).962

In this case, EPA has commented

extensively on the DEIS. It sought

changes to the staff’s analysis, primarily

to include the use of the frozen

efficiency assumptions. The staff has

fully complied with EPA’s study

requests even though it regards such

assumptions as implausible, contrary to

the Energy Policy Act and Commission

policy, and at odds with industry trends

and practical considerations affecting

the industry.963

Although EPA may disagree with the

environmental acceptability of an

agency’s proposal, the agency is charged

with making the ultimate determination

whether to implement a proposal; in

making that decision, the agency is free

to reject advice offered through the

comment and referral process.964

Objections on the part of EPA may give

rise to a heightened obligation of the

agency to explain clearly and in detail

its reasons for proceeding in the face of

those objections. This the Commission

has done. It has thoroughly examined

the impact of the assumptions advanced

by EPA; that analysis is detailed in

Chapter 6 of the FEIS.965

In summary, NEPA prescribes a

process and not a result. What is critical

is that environmental impacts of a

proposed action be adequately

identified and evaluated—an important

component of this process is

understanding the possible mitigation

measures that are involved, including

measures which may be beyond the

jurisdiction of an agency to implement.

This requirement does not translate,

however, into a requirement that an EIS

adopt a mitigation plan, particularly

where, as here, the impacts of the rule

are small and may be either positive or

negative.

B. Analysis of Alternatives

The FEIS evaluated three alternatives

to the rule including: (1) A no-action

alternative which assumes that the rule

is not adopted, but that existing

statutory and regulatory policies remain

in place; (2) a Commission decision to

reverse existing policies and halt

implementation of mandatory open

access; and (3) a Commission decision

to aggressively develop competitive

power markets by mandating corporate

reorganization or divestiture.

1. The No-Action Alternative

The principal alternative to the

proposed action is for the Commission

not to adopt the rule, but to continue its

existing open access and stranded cost

policies. In recent years, the

Commission has required public

utilities that merge or seek to acquire

jurisdictional transmission facilities

under section 203 of the FPA to file

open access transmission tariffs. The

Commission also has required public

utilities to file open access transmission

tariffs to mitigate market power and to

ensure non-discrimination if they or

their affiliates wish to sell power at

market-based rates. In addition, the

Commission processes case-by-case

requests made by potential transmission

users under section 211 of the Energy

Policy Act for transmission service, and

has allowed utilities to include stranded

cost provisions in their open access

transmission tariffs on a case-by-case

basis.966

Actions taken pursuant to section 211,

and pursuant to sections 203 and 205 in

merger and market-based rate cases

respectively, represent a case-by-case

approach to establishing open access.

By contrast, the rule would, in a single

generic proceeding, require each

jurisdictional public utility to file open

access tariffs at the same time. The

consumer benefits from the rule are

expected to be $3.8 to $5.4 billion per

year.967

Absent action on the rule, the

Commission would continue on a caseby-case basis to require public utilities

to file open access tariffs and provide

case-specific service as necessary or

appropriate. Sections 205 and 206

charge the Commission with ensuring

that voluntary transmission tariffs are

not unduly discriminatory. If the rule

were not adopted, the Commission

would continue to require that

voluntary tariffs be upgraded to offer

non-discriminatory open access

transmission services pursuant to the

Commission’s current standards. The

result of continuing the Commission’s

policies without the rule is that the

Commission would effectuate a more

open transmission grid than is present

today, but in a patchwork manner and

at a slower pace. Over some extended

time period, many, but not necessarily
21676 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

968As discussed below, once baselines were

established to portray what is likely to happen in

the electric industry without the rule, the projected

impacts of the rule were then determined against

this background.

969FEIS Chapter 6.

970 Id.

all, utilities would become subject to

open access requirements.

The case-by-case approach to

achieving open access now in use is

slower and more costly, and thereby less

desirable, than the generic approach set

forth in the rule. Given the rapid

changes facing the industry, and the

opportunity for great consumer savings,

the no-action alternative is not a

reasonable alternative to the rule.

2. Abandon the Policy of Promoting

Transmission Access

A second alternative is for the

Commission to abandon its current

policy and take no action whatsoever to

foster transmission access. Under this

alternative, the Commission would no

longer require open access transmission

as a condition of mergers and asset

acquisitions under section 203 or

requests for market-based pricing under

section 205, and would no longer grant

applications filed pursuant to section

211. Offers of transmission would

become strictly voluntary.

This alternative is inconsistent with

Congress’ general intent in the Energy

Policy Act to foster wholesale

competition, and also with its specific

intent in expanding section 211 to

permit the Commission to require a

transmission-owning utility to make its

transmission system available to eligible

users if to do so is in the public interest.

This alternative is also inconsistent with

the Commission’s obligations under

sections 205 and 206 to ensure that

public utilities do not unduly

discriminate in providing jurisdictional

services. It is, therefore, not a reasonable

alternative to the rule.

3. Corporate Reorganization/Divestiture

Alternative

Under this alternative, the

Commission would require public

utilities either to divest control of their

transmission assets or to reorganize

their corporate structures to perform

their transmission functions through a

separate subsidiary, thereby segregating

transmission from the rest of the

utilities’ operations. However, corporate

reorganization or divestiture would

have no effect on the operation of power

plants, which are assumed to be

dispatched on the basis of economic

efficiencies. Thus, this alternative

would lead to the same environmental

impacts as the rule. That is, the

environmental effects would be no

different from those studied in the FEIS.

C. The Scope of the FEIS

The FEIS examines the environmental

impacts that could result from

implementing this rule. This analysis is

undertaken against the background of

the existing electric industry. The

electric industry currently produces

environmental impacts, and those

impacts are certain to change over time

as the industry responds to factors as

varied as changes in demand for

electricity, the price of fuels, changes in

regulatory programs, technological

developments, and changes in market

structure.

The FEIS does not examine the

environmental impact of electric

generation that is required to meet

generators’ existing service

requirements. Nor does it examine the

environmental effects of the inter-utility

power exchanges that have occurred in

the industry for as long as utilities have

been interconnected. Rather, the FEIS

examines impacts of potential increases

in generation and changes in patterns of

generation that might result from

implementation of the rule.

In creating an analytical construct to

examine the impacts of the rule, the

staff developed a set of cases that

defined the framework for running the

computer models utilized to examine

the changes in types of power plants

constructed in the future and changes in

operating patterns of existing power

plants, including changes in fuel mix.

First, staff characterized how electric

power markets might evolve absent

adoption and implementation of the

rule by establishing baselines (i.e., base

cases) to project the future impacts of

the industry.968 The relative prices of

coal and natural gas are critical in

establishing what is likely to happen in

the future. Accordingly, a range of

prices was developed to project the

impacts of these factors. In the first

baseline, the Constant-Price-Differential

Base Case, coal and natural gas prices

are assumed to maintain the same

relative position they have maintained

over the past ten years. In the second

baseline, the High-Price-Differential

Base Case, natural gas is assumed to

become substantially more expensive

compared with coal than it has been

over the past 10 years. In all other

respects, the assumptions underlying

the two base cases are the same.

Because the purpose of the base cases

is to describe the impacts of the electric

industry if the Commission takes no

action over and beyond continued

implementation of existing policies, the

baselines assume that the Commission

continues the open access and stranded

cost policies it has instituted in recent

years.

Some commenters have challenged

this aspect of the baselines used in the

study. The gist of their argument is that

the environmental impacts of these

programs have not been evaluated and

that the baselines therefore improperly

take credit for impacts that have not yet

occurred, thus understating the

projected impacts of the rule. In general,

these commenters argue that the second

alternative considered by the staff

represents the ‘‘true’’ no-action

alternative.

At bottom, this debate is not about

what constitutes the appropriate noaction alternative. Rather, it is a debate

about what aspects of the electric

industry should be taken into account

when determining future environmental

impacts of the industry against which to

measure the impacts of the rule. The

commenters urge the Commission to

consider varying baselines, but in

general they oppose inclusion in the

base cases of the Commission’s ongoing

open access and stranded cost programs.

Some commenters not only urge that

the Commission not take into account

continued implementation of its open

access and stranded cost programs, but

that it go much farther and establish

baselines (against which to examine the

impacts of the rule) that do not reflect

the impacts of a great many changes that

are already taking place in the electric

industry. This proposal would establish

a baseline that does not take into

account: (1) Current Commission

transmission policy; (2) programs that

states and industry players have

adopted to improve industry efficiency;

and (3) mutually beneficial transactions

that electric companies enter into on a

regular basis.

The use of these assumptions would

fly in the face of long-standing industry

trends which move in precisely the

opposite direction. Utilities are reducing

reserve margins, improving plant

availabilities, and reducing barriers to

transmission even without Commission

action.969 Many states are aggressively

pursuing plant efficiency policies.970

These trends are long-standing and are

not attributable to the rule, or even to

a broader Commission program of open

access. These trends, projected into the

future, form the basis for the conditions

reflected in the FEIS base cases. These

trends are fundamentally at odds with

the assumptions some commenters wish

the Commission to use to establish

baselines.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21677

971See, e.g., Sierra Club v. Marita, 46 F.3d 606,

621, 623 (7th Cir. 1995).

972Methow Valley, 490 U.S. at 354–55. The

revised requirement, 40 CFR 1502.22, which

pertains to incomplete or unavailable information,

is inapplicable as well. The problem here is not

incomplete or unavailable information, but rather

which existing policies and events should be

included in the analysis.

973 42 U.S.C. 4332.

974Several commenters, including EPA, are

concerned that increases in transmission capacities

resulting from open access might increase

generation levels and thus air emissions. EPA is

especially concerned with the expansion of

transmission links between the midwest and east

coast. The FEIS examines scenarios that increase

transmission capacity substantially beyond current

levels. This analysis finds that postulated increases

do not affect emissions attributable to the rule. We

believe increases considered in the FEIS far exceed

any transmission capacity increases that might

occur as a result of the rule. This is due in part to

the fact that state-level siting issues, the principal

barrier to major capacity increases in the

transmission grid, are unaffected by the rule. The

issues regarding enhancement of existing lines are

more complex. Competition under open access will

lead to improved efficiencies in generation.

Transmission, on the other hand, will remain a

regulated monopoly function. The rule will reduce

barriers to access, but will not open the

transmission system to direct competition. Thus,

we believe that the competitive effects of the rule

on transmission expansion will be relatively small.

EPA urges us to assume that transmission

capacity is expanded by 40 percent compared to our

base case. We do not believe this is likely to occur.

The experience with one proposed new

transmission line in the very area EPA focuses on

demonstrates this difficulty. Duquesne Light filed

an application with the Pennsylvania Public

Utilities Commission to construct a new 500 Kv line

across Pennsylvania to supply electricity to New

Jersey. Within a few days of the filing of the

application, over 3,000 individuals and groups filed

complaints in opposition to the proposed line.

‘‘Electricity Utility Week’’ (November 4, 1991). A

bill was proposed in the Pennsylvania Legislature

to prevent construction of the line. Another bill was

introduced in Congress to halt construction of new

transmission lines throughout the U.S. for two

years. Duquesne ultimately decided to withdraw its

proposal and the line was not constructed. ‘‘The

Energy Daily’’ (April 4, 1994).

975FEIS Figure ES–1 and Table ES–2, reproduced

at Appendix H.

976See, e.g., FEIS at ES–8.

We conclude that the approach used

by staff to develop the baselines used in

the FEIS is appropriate. Abandoning

current open access policies is

unrealistic, contrary to Congressional

intent, and at odds with procompetition policies that are at the heart

of the Commission’s current regulatory

mission. The selection of the

appropriate methodology to establish

the baselines used in the FEIS is clearly

within the Commission’s discretion and

expertise.971

What the commenters challenging this

assumption desire is additional study of

the impacts of the rule. Specifically,

they wish to test the rule against a

different set of assumptions for the

acknowledged purpose of attributing

greater adverse environmental

consequences to the rule. The

regulations of the Council on

Environmental Quality no longer

contain a requirement to conduct a

conjectural ‘‘worst-case analysis.’’ 972

NEPA requires an agency to adequately

identify and evaluate the adverse

environmental effects of a proposed

action.973 It does not require the agency

to ignore the world as it exists.

Nonetheless, to respond to concerns

about the baselines used in the DEIS

with respect to key atmospheric

emissions, the staff conducted

sensitivity analyses to examine the outer

boundaries of a range of cases requested

by some commenters. This range of

cases is called the ‘‘frozen efficiency’’

case. In essence, the frozen efficiency

cases assume that no further open

access of any kind occurs during the

study period and that efficiency in the

industry (for instance, power plant

availability) remains frozen through the

same period. The assumption that there

is substantially more inter-regional

transmission capacity than posited in

the original analysis is separately

examined in the base and rule cases.974

We must reiterate that the frozen

efficiency case is far more restrictive in

its assumptions than a true no-action

case in which the Commission simply

stops all efforts to promote open access.

A true no-action case would closely

resemble the FEIS base cases because

much of the efficiency gain in that base

case would occur even with no move

toward open access.

As detailed in Chapter 6 of the FEIS,

and as discussed below, even the frozen

efficiency case demonstrates results that

are essentially the same as those

demonstrated by the base cases used by

the staff. In the frozen efficiency worst

case, when coal prices become

considerably more attractive compared

to gas prices, national NOX emissions

would be lower than in the base cases

used by staff by only one percent (in

2000) to four percent (in 2010). If coal

and natural gas prices remain at today’s

relative levels, the effects would be

smaller—zero percent in 2000 to two

percent lower in 2010. National CO2

emissions would be between zero and

two percent lower than in the base cases

used by the staff over the same time

frame.

D. Economic and Environmental

Impacts of the Rule

The FEIS reports a quantitative

estimate of approximately $3.8 billion to

$5.4 billion in benefits per year of cost

savings expected from competition

under the rule. The FEIS also considers

other, non-quantifiable benefits that can

be expected from implementing the

rule. These benefits include better use of

existing assets and institutions, new

market mechanisms, technical

innovation, and less rate distortion.

Further, the FEIS demonstrates to our

satisfaction that the rule is likely to have

little or no adverse environmental

impact and that any impacts are as

likely to be beneficial as harmful.

The issue most frequently raised by

commenters involves air quality

impacts, particularly the possible

transport of NOX emissions from

upwind areas to airsheds in the

Northeast and the resulting impacts on

ozone non-attainment areas.

With regard to NOX, the FEIS

demonstrates that, as a result of clean

air regulatory programs, NOX emissions

nationwide, with or without the rule,

will decline through the year 2000, but

begin to climb thereafter.975 This basic

trend remains the same in all cases

examined in the FEIS. This is because

the level of NOX emissions in any given

year depends primarily on one key

uncertainty that is not related in any

way to the rule—the relative price of

natural gas and coal.976 Lower prices for

natural gas, relative to coal, lead to

lower levels of NOX emissions.

The FEIS also demonstrates that

increases in access to transmission and

efficiencies in electric power markets

associated with the rule do not alter the

expected trend of NOX emissions,

regardless of the relative price of natural

gas and coal. Increased transmission

access and industry efficiency

facilitated by the rule may either

decrease total emissions somewhat or

increase them somewhat, depending on

whether competitive conditions in the

electric industry favor natural gas or

coal. When competitive conditions favor

natural gas, the effect of the rule is

beneficial, reducing emissions

somewhat. When competitive

conditions favor coal, emissions

increase by a small amount.

Nevertheless, the overall trend of

expected NOX emissions retains its

general shape.

In assessing the projected impacts of

the electric industry absent adoption of

the rule (i.e., the base cases studied in

the FEIS), the most important factor

affecting changes in national NOX

emissions is the relative competitive

position of coal and natural gas. The

most important factor affecting the

relative competitive positions of coal

and natural gas is price.

National NOX emissions from the

electric industry were 5,844 thousand

tons in 1993, the last year for which

complete data is available. If relative gas
21678 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

977These assumptions include, and go

substantially beyond, the ‘‘no-action’’ alternative

advocated by EPA and others in positing a baseline

that would tend to maximize the amount of NOX

emissions attributed to the rule. This is because

under a frozen efficiency scenario all increases in

power trading (and resulting NOX emissions) would

be attributed to the Rule. In fact, as described

below, many of the efficiencies posited under the

EPA assumptions are attributable to other factors

and certain of the efficiencies (e.g., 40 percent

increase in transmission capacity) are wholly

unrealistic.

978Some commenters assume that large increases

in transmission capacity would result in a

significant expansion in generation and thus

increased emissions. In reality, the analysis present

in Chapter 6 of the FEIS indicates that this is not

the case.

979FEIS at ES–2.

980See Methow Valley, 490 U.S. at 348–53.

and coal prices remain the same, for

example, we project that national NOX

emissions will be 5,579 thousand tons

in 2005 without adoption of the rule. If

gas prices rise relative to coal prices, we

project that NOX emissions in 2005 will

be 6,053 thousand tons without

adoption of the rule. Stated another

way, favorable coal prices are projected

to result in NOX emissions that are

about three percent higher in 2000 to 10

percent higher in 2010 over the base

case where gas is the favored fuel.

The effect of adopting the rule could

be to raise or lower national emissions

slightly compared to the effects

projected in the base cases. Nationally,

in 2005, we project that the

Competition-Favors-Coal Scenario (with

rising relative gas prices) would add one

percent to NOX emissions above the

base case that favors coal. The

Competition-Favors-Gas Scenario (with

constant relative fuel prices) would

lower emissions by two percent

compared with the base case that favors

gas.

Regional effects are generally similar.

In 2005, in the East North Central region

(a source of potential increased NOX

emissions that might affect the

Northeast), the base cases project small

increases in industry emissions (two

percent). In that region in 2005, the rule

may add as much as one percent to NOX

emissions compared to the relevant base

case (the Competition-Favors-Coal

Scenario) or reduce emissions compared

to the relevant base case by as much as

three percent (the Competition-FavorsGas Scenario).

The EIS uses the UAM–V model to

track the effects of projected NOX

emissions on downstream ozone levels

during a severe weather period. This

detailed air quality modeling shows no

real difference in the Northeast between

the base case favoring coal (the HighPrice-Differential Base Case) and the

Competition-Favors-Coal Scenario.

Detailed local analysis shows slightly

lower ozone concentrations in some

locations and slightly higher

concentrations in others. None of the

differences adds to non-attainment

levels projected in the relevant base

case, and all fall within the noise levels

of the model. That is, they are smaller

than the uncertainties in the science

underlying the model.

As discussed above, the Commission

believes that the base cases used by staff

in its analysis are the most realistic and,

therefore, the most appropriate cases to

consider the potential environmental

impacts of the rule. However, as

requested by the EPA, DOE, and certain

other commenters, sensitivity analyses

were conducted to examine the impacts

on the results of the analysis if key

assumptions are changed as requested

by commenters. Presumably, comparing

the projected impacts of the rule to the

requested ‘‘frozen efficiency’’ case

provides a measure of the greatest

impacts that could possibly (albeit

unrealistically) be expected from

implementing the rule.977

As the FEIS discusses, even

comparing projected NOX emissions

under the rule to the highly implausible

frozen efficiency case, impacts

attributable to the Rule are projected to

be modest or non-existent. This holds

true even when large (up to 40 percent)

increases in transmission capacity are

assumed to occur under the rule.978

Moreover, adding coal-favoring

assumptions—which would presumably

increase emissions—about future

competitive conditions in the electric

industry to the implausible frozen

efficiency assumptions, NOX emissions

are projected to increase very modestly

until the year 2010 (by only two percent

in 2000 and three percent in 2005). Even

using this highly unlikely alternative to

the rule, the analysis projects a net

environmental benefit (although a very

small one) if gas prices stay constant

compared to coal prices.

Concern also has been expressed with

regard to the need to mitigate CO2,

mercury, and fine particulate emissions,

and with the impact of the rule on

visibility. As with NOX, the FEIS

demonstrates that the rule is as likely to

improve such emissions and visibility

as it is to exacerbate them. In any event,

the impact is expected to be small.

In sum, the Commission adopts the

FEIS findings that:

• The relative price of coal and natural gas

has a larger effect on NOX emissions than any

impacts from the proposed rule. Without the

proposed rule, different fuel price

assumptions are projected to lead to a 7

percent difference between the two base

cases in nationwide NOX emissions in 2005,

with some regions affected more than others.

• The rule is projected to have only slight

impacts on NOX emissions, and the impacts

are as likely to be beneficial as harmful. In

2005, if competitive conditions in the electric

industry (for instance, heat rates) favor

natural gas, the proposed rule is projected to

decrease baseline NOX emissions by 2

percent nationwide. If competitive

conditions favor coal, the rule is projected to

raise baseline NOX emissions by 1 percent.

Regional effects in both cases are generally

similar. In short, any negative impacts that

the rule might cause are a small fraction of

the uncertainty inherent in fuel price

projections.

• Even a substantial increase in

transmission capacity (up to 40 percent on

every transmission line in the country)

would change emission estimates by very

small amounts in all cases. In many cases,

the changes would represent net

environmental benefits.

• Even comparing projected emissions

under the proposed rule to the highly

implausible frozen efficiency case, impacts

attributable to the rule are projected to be

modest or non-existent. The staff believes

this is an unreasonable comparison because

the frozen efficiency assumptions ignore

industry trends that the Commission is

generally powerless to stop. In effect, they

assume that the alternative to the proposed

rule is (1) for the Commission to reverse

current transmission policy, an action that is

inconsistent with Congressional policies

under EPAct, (2) for states to cease adopting

programs to improve industry efficiency, and

(3) for electric companies to cease entering

mutually beneficial transactions. Even after

adding coal-favoring assumptions about

future competitive conditions in the electric

industry to the implausible frozen efficiency

assumptions, NOX emissions are projected to

increase only very modestly until 2010 (by

only 2 percent in 2000 and 3 percent in

2005). Even using this highly unlikely

alternative to the proposed rule, the analysis

projects a net environmental benefit

(although a very small one) if gas prices stay

constant compared to coal prices. EPA

indicates that it considers the lower gas price

assumption to be ‘‘the more likely of the base

cases’’ (DEIS comments, p. 35).979

E. Mitigation Analysis

An agency is required to consider

mitigation if the proposed action will

result in adverse environmental

impacts.980 The insistence of

commenters that the Commission adopt

and implement mitigation measures is

based on significantly overstated

assumptions regarding the contribution

of the rule to existing environmental

problems. The analysis presented in the

FEIS establishes that these assumptions

about the impact of the Rule are wrong.

As stated in the FEIS,

The sensitivity analyses (i.e., the frozen

efficiency case requested by EPA, DOE and

other commenters) do not support the

argument that the proposed rule is likely to

lead to large immediate impacts that require
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21679

981FEIS at 7–5.

982 61 FR 1442 (1996).

983 Id.

984 It should be noted that the science relating to

determining mercury emission levels and also to

the environmental impacts of CO2 is uncertain,

particularly with regard to the impacts of CO2

emissions. The FEIS evaluates these matters as best

it can under the circumstances.

immediate mitigation. In fact, using the more

reasonable EIS base cases, it is clear that the

proposed rule is at least as likely, if not more

likely, to benefit the environment as it is to

have adverse environmental impacts. As a

result, we believe it is not a responsible

course of action to undertake efforts to

mitigate speculative adverse environmental

consequences that may well not materialize;

such action could well have the opposite

effect and delay the clear benefits the

proposed rule will produce in order to

address small, highly uncertain

environmental impacts.981

Even if the rule were to result in

adverse environmental impacts as a

result of competitive conditions that

favor the future use of coal, such

impacts are not likely to occur until

about the end of the time period

examined in the FEIS. EPA in its

comments on the DEIS stressed, based

on views it formed prior to knowing the

results of the frozen efficiency case, that

the Commission should develop interim

mitigation until EPA can implement a

program of controls. EPA stated in its

comments that it has authority to

address ‘‘some’’ of the impacts it

believed would result from the rule, but

stated that it would take it considerable

time to do so—up to 10 years. The

results of the unrealistic worst case

analysis demonstrate that adverse

effects would not be expected to occur

for approximately 10 years in any event.

Thus, interim mitigation is not required;

EPA will have sufficient time to develop

under the Clean Air Act whatever

mitigation plan it may deem necessary.

Although the staff concluded that

mitigation was unnecessary given the

results of its analysis, given the

importance of this issue, it nonetheless

examined in considerable detail

measures, including those proposed by

commenters, that could be taken to

mitigate adverse environmental

consequences of the rule if they were to

occur. The FEIS focuses on NOX

emissions in particular given the

importance assigned to this issue by

commenters.

1. Mitigation Measures Under the Clean

Air Act

As discussed in greater detail in the

FEIS, the existence for many years of a

significant ozone non-attainment

problem in parts of the U.S. has led to

the development of mechanisms to

address this issue. In particular,

Congress has established requirements

in the Clean Air Act for regulating NOX

emissions. These requirements establish

specific NOX emission levels for certain

types of boilers. As discussed below, the

Commission is not authorized to alter

those requirements as requested by

certain commenters.

In the 1990 Amendments to the Clean

Air Act, Congress enacted the Acid Rain

Program to reduce annual SO2 and NOX

emissions. For SO2, Congress

established a cap and trade program that

uses a market-based allowance system

to reduce SO2 emissions from utilities

by approximately 50 percent. The

allowance system caps utility emissions

at 8.9 million tons a year by 2000. A

pool of 8.9 million allowances was then

created, each representing the right to

emit one ton of SO2 pollution in a

specified calendar year. The allowances

can be used to permit current emissions,

sold, or held in reserve.

As a result of uncertainty in the

understanding of ozone formation and

transport, Congress acted less

aggressively in regulating NOX

emissions. It chose to limit NOX

emissions from utilities by means of

allowable emission limits and to require

further study of ozone precursors,

leaving room for the EPA to abate NOX

requirements where scientifically

justified. Accordingly, in section 407 of

the Clean Air Act, 42 U.S.C. 7651f,

Congress established a NOX reduction

program which provides that EPA shall

by regulation establish annual allowable

emissions limitations for NOX for

specified types of utility boilers (Group

1 boilers). Section 407 also provides

that, by not later than January 1, 1997,

the Administrator shall establish

allowable emission limitations for NOX

on a lb/MMBtu, annual average basis for

specified other types of utility boilers

(Group 2 boilers).

On April 13, 1995, EPA promulgated

a Rule setting emission limitations on

Group 1 boilers that combust coal as a

primary fuel. EPA reports that the April

13, 1995 regulation ‘‘is expected, by the

year 2000, to nationally reduce NOX

emissions by an estimated 1.54 million

tons per year.’’ 982

On January 19, 1996, EPA published

a proposed rule to implement the

second phase of the Acid Rain Program.

This rule proposes to establish NOX

emission limitations for Group 2 boilers

and to revise NOX emission limitations

for Group 1 boilers to impose tougher

standards. EPA states that ‘‘[t]he

proposal would, by the year 2000,

achieve an additional reduction of

820,000 tons of NOX annually.’’ 983

In addition, Congress determined to

deal with the issue of the interstate

transport of ozone by authorizing the

formation of transport commissions.

The Clean Air Act authorizes EPA to

establish transport regions that are

charged with assessing the degree of

interstate transport of pollutants,

assessing mitigation strategies, and

recommending revisions to State

Implementation Plans to correct the

problem. The Clean Air Act specifically

establishes an ozone transport region

(OTR) for the Northeast. The

jurisdictions that comprise the OTR

have developed a coordinated approach

to this problem that includes adopting

a regional cap on NOX emissions.

Although the OTR process is

achieving its purpose, a broader

program is clearly appropriate to

address the overall problem. As a

consequence, the Ozone Transport

Assessment Group (OTAG) has been

formed which encompasses the OTR

and upwind states that contribute to

non-attainment. OTAG is performing

extensive photochemical grid modeling

of the eastern U.S. to determine ozone

transport problems and to evaluate the

efficiency of various control strategies.

OTAG is considering recommending a

cap and trade system for NOX emissions

from all sources in a 37-state area

comprising the Northeast OTR and

upwind states. If the cap and trading

system becomes effective it therefore

should fully mitigate NOX emission

increases, if any, attributable to open

access transmission within the 37-state

area. A cap and trade program is also

likely to mitigate CO2 and mercury

emissions.984 Any incremental increases

in NOX, mercury, or CO2 emissions that

may result from the rule can and should

be addressed within this existing

framework.

All of these factors lead us to agree

with the staff’s conclusion in the FEIS

that a cap and trading system such as

that under consideration in the OTAG

process is the preferred approach to the

overall NOX emissions problem,

including emissions associated with the

rule, if any. This approach brings

together EPA and the concerned states

in a program that utilizes existing

regulatory authority under the Clean Air

Act.

The OTAG process brings to the table

the parties that must participate in

making the difficult decisions necessary

to fully resolve this problem. OTAG

possesses the technical resources and

expertise to address the difficult

scientific and technical issues that must

be resolved to remedy this problem. A

cap and trading system will require the
21680 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

985For example, EPA suggests that we require

certain types of filings, such as a request to charge

market-based rates, to include an assessment of

environmental impacts and mitigation, if necessary.

Joint Commenters suggest we require wheeling and

interconnection applicants to demonstrate that their

requests will not contribute to increased NOX or

ozone in downwind regions, and Conservation Law

suggests linking recovery of stranded costs to the

retirement of unsuitable generators.

986The FEIS also discusses mitigation measures

that can be undertaken by others. These include

strategies to require some existing plants to meet

more stringent, new NOX standards, relying on

market forces to control inter-regional NOX

transport, or measures that could be employed by

the states to limit power purchases based on

environmental considerations. See FEIS at 7–26 to

7–28.

987FEIS at 7–28 to 7–43.

988FEIS at 7–43.

989The rule represents the Commission’s remedy

to unduly discriminatory practices found to exist by

public utilities that own and/or control interstate

transmission facilities. Having found an unlawful

practice, we must remedy it. However, EPA would

require that those seeking to enjoy the benefits of

non-discriminatory open access transmission

further agree to go beyond current environmental

requirements specified by federal and state

authorities authorized by Congress to regulate such

matters.

development of emission baselines for a

great many entities; development of

such baselines is certain to require

extensive modeling and many difficult

compromises. OTAG and others have

been working towards this end for a

long time. A more limited approach—

one undertaken by this Commission or

aimed at the limited (and only potential)

impacts of the rule—cannot render a

satisfactory solution. A program

designed to deal with the slight impacts

associated with the rule will not

contribute significantly to the overall

solution and could, indeed, impede it if

the Commission took actions that prove

inconsistent with solutions developed

by OTAG or if debate over Commissionsponsored mitigation were to continue

to distract interested parties from the

preferred route of developing a

consensus solution within the

framework of the Clean Air Act. We

respect the expertise and the goals of the

OTAG process and do not believe we

can or should substitute for them in

addressing this long-term national

problem.

2. Mitigation Measures Proposed by

Commenters

The FEIS also analyzes NOX

mitigation measures proposed by

commenters. These include voluntary

measures pursuant to which the

Commission would support utility

efforts to mitigate pollution and

proposals under which the Commission

would mandate mitigation. Commenters

suggest a variety of Commission actions

including using its conditioning

authority to require utilities to consider

environmental impacts; 985 sanctioning

imputed charges in rates to reflect

incurred environmental externalities;

and designing specific, transactionoriented mechanisms designed to

address the increment of emissions

attributable to new wholesale

transactions resulting from the rule.986

The FEIS discusses five proposals in

some detail: Those presented by the

Center for Clean Air Policy (CCAP), the

EPA, Joint Commenters, the Project for

Sustainable FERC Energy Policy

(Sustainable FERC), and the DOE.987 Of

these, the FEIS recommends the

proposal put forward by DOE:

Staff concurs (with the DOE analysis) that

the best solution to the problem of NOX

transport and ozone non-attainment lies in

exercise of statutory authority under the

Clean Air Act by EPA and the states. Absent

Congressional action, no resolution of the

difficult political and technical issues will

represent a lasting solution of this problem

except one that comes from a collaborative

process such as OTAG.988

As the FEIS explains in great detail,

each of the other recommendations

suffers from serious shortcomings. In

one form or another, they would require

the Commission to implement

technically complex emissions control

regimes outside of the Commission’s

expertise. Some would require that we

duplicate existing monitoring systems.

Others would require that we

implement provisions that would, in

effect, defeat the very purpose of the

rule.989 Indeed, these recommendations

would have the Commission embark

upon an extensive environmental

regulatory regime that appears

unwarranted, unworkable and, as

discussed below in some detail, beyond

our lawful authority. And they would

have us act in a way that may well

frustrate the ongoing efforts to deal with

these problems and would frustrate the

benefits to be derived from the rule.

The CCAP asserts that FERC should

establish an emissions monitoring

program for NOX and CO2 and

implement an emission neutrality

requirement (ENR) to mitigate what it

believes to be the impacts of the rule.

The monitoring program would require

generators to identify emissions

associated with off-system sales on a

kWh basis in real-time and integrate this

information with the data to be made

available on electronic bulletin boards

(EBBs). Under the ENR aspect of CCAP’s

proposal, to be eligible for service under

open access tariffs, companies that

operate plants upwind from the

Northeast OTR and the upper Midwest

would have to certify that firm and

economy off-system power sales using

an open access tariff would have no

incremental impact on ozone

compliance in other areas. All sales for

resale that require service under an

open access tariff and originate upwind

of the OTR would need to include NOX

emissions reduction credits equal to the

increase in emissions related to those

sales. The seller could meet its

requirement to be ‘‘emission neutral’’

under the mechanism by achieving the

required emission reductions annually

at their own facilities, or through

purchases of credits anywhere in the

airshed.

EPA proposes two mitigation

alternatives. In the first, it states that

FERC could deny open access service

unless there is a showing that the

service will not have an adverse

environmental impact. Under this

approach, EPA, in cooperation with the

states in OTAG, would recommend and

establish a mitigation mechanism that

could be entered into by a customer

seeking open access service and used by

such customer to make the necessary

environmental demonstration

supporting the provision of the service.

The FERC would rule on whether the

mitigation mechanism presented by the

customer and the evidence on the likely

effectiveness of the mechanism were

sufficient to make the environmental

demonstration.

In the second proposal, EPA suggests

that any fossil fuel-burning generating

entity seeking service under open access

transmission tariffs would be required

to commit by an enforceable contractual

undertaking that it will avoid or offset

emission increases (measured against as

yet undetermined baselines), and

periodically certify its compliance with

that commitment. Middlemen would

have a similar obligation. The generator

could meet its emission limits either by

making verified emission reductions

within its own facilities or by obtaining

eligible emissions offsets from other

entities. An important element of the

mitigation mechanism is the emissions

baseline above which mitigation would

be required. This mitigation mechanism

would operate until superseded by

appropriate programs addressing these

pollution problems under other

authority. EPA’s own comments on the

DEIS recognize that there may be

substantial practical complexities in

implementing such mechanism.

The Joint Commenters propose a

flexible mitigation strategy pursuant to

which FERC would require as part of

open access transmission a

demonstration that NOX emissions

would not be increased. To qualify for

open access transmission access, an

electric generating unit would be
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21681

990 Indeed, over 100 utilities are now providing

some form of open access on a voluntary basis.

responsible for mitigating any excess

NOX emissions that adversely affect

ozone non-attainment areas. Utility

systems would be able to comply by use

of emission control technology, fuel

changes, or other measures to reduce

applicable emissions, or by buying

appropriate emission reduction credits

to offset excess emissions. To comply

with this policy, a company would need

first to calculate whether it had excess

emissions for the ozone season. A

company that failed to mitigate would

be required to remit to a regional

emissions fund all revenues in excess of

the incremental operating cost of

producing electricity sold under the

open transmission access policy during

the previous ozone season plus an

emissions make-up penalty the

following year patterned after the

penalty for excess emissions in the Acid

Rain Program. The proposed mitigation

policy would apply generally

throughout the OTAG region.

The outlines of Sustainable FERC’s

proposal are vague, but it appears to

request that FERC, either singly or in

combination with other agencies,

eliminate the different environmental

standards that apply to entities

participating in open access

transmission. This plan would include

the reporting of emissions data to EPA,

principles to eliminate the adverse

impacts of non-comparable

environmental standards, and an EPAadministered emissions monitoring

process designed to determine whether

generating plant emissions of specific

pollutants under open access exceed

designated baselines.

Finally, DOE proposes action under

the Clean Air Act as the most effective

mitigation of the inter-regional NOX

transport problem. DOE supports the

activities of OTAG and believes that a

regional NOX cap and trading system is

a particularly promising approach. If

OTAG does not succeed in addressing

the problem, EPA should consider

exercising its authority under sections

110 and 126 of the Clean Air Act, 42

U.S.C. 7410 and 7426, respectively, to

require states to amend their State

Implementation Plans to reach the same

result.

The proposals advanced by CCAP,

EPA, Sustainable FERC, and Joint

Commenters suffer from practical and

legal problems that render them

unworkable. A common thread is for the

Commission to ‘‘level the environmental

playing field.’’ ‘‘Impacts of noncomparable environmental standards’’

are not impacts of this rule, but rather

of the Clean Air Act regulations and

statutory requirements under which

those standards have been imposed. We

have no authority to ‘‘level’’ the

different emissions standards for

different types of power plants, when

those differences in standards are the

direct result of the program adopted in

the Clean Air Act and regulations

promulgated by EPA. In enacting the

Clean Air Act, Congress chose not to

impose identical emission standards on

all electric utility powerplants, but did

create mechanisms for regulation of

certain pollutants that can be used to

‘‘level the playing field’’ if that is

appropriate clean air policy. For the

Commission to presume to overturn

those standards or seek to impose more

stringent standards is something the

Commission believes it cannot do.

A fundamental problem that plagues

several proposals is the difficulty in

identifying causation. While it is

generally accepted that there is a link

between increased emissions in certain

areas of the country and increases in

ozone levels in other areas, that link is

in many respects poorly understood. In

particular, it is difficult to prove that

emissions from a particular unit or

particular system contribute to ozone

noncompliance elsewhere. As a result, it

is very difficult to establish an analysis

that would support a certification that a

particular power sale would have no

incremental impact on ozone

compliance.

Similarly, the proposals tying

‘‘emission neutrality’’ to ‘‘open access

transactions’’ seem to fundamentally

misunderstand the operation of power

markets and the role of open access

tariffs in moving power from willing

sellers to willing buyers. In particular,

these proposals do not reflect the

difficulty in identifying the transactions

that are likely to result from the open

access policies adopted in this rule. The

rule does not authorize sales for resale

of electric energy; rather, it establishes

requirements for open access

transmission, i.e., it requires utilities

with monopoly control of transmission

to make transmission service available

to customers who want to buy power

from someone other than the

transmission owner. Open access will

facilitate transactions where the

transmission owner will not provide

service. However, generators do not

necessarily have to request service

under a Commission ordered open

access tariff to make specific sales.

There are a number of ways to structure

transactions where third party

transmission service is either not

necessary or is voluntarily available.990

Even when open access tariffs are used,

the sales are not always (or even often)

sales from specific generators to specific

buyers. Marketers or brokers can buy

generation from any number of sources.

They can also buy transmission service

in blocks that may not be associated

with specific sales. Service agreements

can be executed that allow use of nonfirm transmission service for

transactions that are not even known at

the time of the execution of the

agreement.

The rule envisions a world where

transmission will be arranged with

minimal transaction cost. Terms,

conditions, rates, and even approvals

often will be established far in advance

of particular transactions. All other

problems aside, requiring showings of

the kind required by the various

mitigation proposals would undermine

the basic philosophy behind the rule,

would make transactions much more

difficult to engage in, would increase

transaction costs, and would cause

delays resulting in lost efficiencies. In

addition, it would directly conflict with

the Commission’s responsibility under

the FPA to remedy undue

discrimination in jurisdictional services,

which is the fundamental purpose of the

rule.

Another significant issue with several

of the proposals is how to establish the

baselines against which to measure

emissions. Establishing such baselines

is extremely difficult; EPA itself, for

example, has not come to grips with

these complexities. The picture is

complicated by difficulties in

identifying open access transactions that

result from the policies implemented by

this rule. For example, some utilities

use holding company corporate

structures in which generation assets are

held in an affiliate that sells power at

wholesale to the holding company’s

distribution affiliate. For these utilities,

all retail native load service would be

subject to environmental review under

the mitigation proposals if the base were

established by reviewing all wholesale

sales. This would make the Commission

responsible for addressing all NOX

emissions from power plants for utilities

with such corporate structures, a result

that goes far beyond the stated goal of

mitigating emissions that result from

increased interstate trade facilitated by

the rule.

As the industry changes, new

structures are emerging that will make

any system that tries to keep track of

wholesale sales even more difficult to

administer. California is putting into

place an industry structure that could

see all generation in the state sold into

a central pool and then sold again at

wholesale to distributors. Other states
21682 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

991We are also very concerned about the time and

effort involved in developing the various programs

suggested by commenters. The EPA and OTAG are

working on the establishment of emissions

standards, which action is an essential prerequisite

to three of the proposals. However, developing

those standards is among the challenges that EPA

believes may take up to 10 years to complete. It

simply makes no sense to delay the benefits of the

rule (which has slight, if any, environmental

impacts) during the period required for experts in

the area to develop standards that, once established,

can form the basis of a program under existing

Clean Air Act authority.

992FEIS at 7–48.

993Many commenters state that the rule does not

require mitigation and urge that a mitigation plan

not be adopted. We would also note in light of the

substantial number of comments opposing the

proposition that we have mitigation authority, that

any such mitigation measure we may choose to

undertake would, in all likelihood, be subject to

judicial review and the inevitable delays and

uncertainties that accompany litigation. In the

meantime, we would expect actions by OTAG and

EPA to eclipse whatever action the Commission

attempted to implement during this time.

994Alliance for Affordable Energy, et al.

(Alliance); EPA; Project for Sustainable FERC

Energy Policy (Project for Sustainable FERC); and

Northeast States For Coordinated Air Use

Management (NESCAUM).

995See, e.g., AEP at 3; CINERGY at 8–9; Entergy

at 11–13; GPU at 2; Midwest Ozone Group at 3;

NMA at 5–8; Ohio Consumers’ Counsel at 5; Ohio

PUC at 1; TVA at 8; and WEPCO at 2. See also

CCEM Supplemental Comments at 1–5.

996See, e.g., CCAP (FERC should establish an

emissions monitoring program and implement an

emission neutrality requirement); EPA (either deny

open access service unless the customer

demonstrates no adverse environmental impact or

require, through contract terms, any generating

entity seeking open access service to avoid or offset

emission increases for the benefit of third parties);

Joint Commenters (electric generators to qualify for

open access must be held responsible for mitigating

any excess NOX emissions through a revenue

collection measure); Project for Sustainable FERC

(pro forma tariffs to contain environmental

mitigation measures imposed on generators). See

generally, FEIS at 7–28 to 7–42.

997Parts II and III of the FPA originated with the

Public Utility Act of 1935, 49 Stat. 803, 838 (Aug.

26, 1935) and stemmed in part from the financial

abuses in the utility industry in the late 1920s and

early 1930s. See Report of National Power Policy

Committee on Public-Utility Holding Companies, S.

Rep. No. 621, Appendix, 74th Cong., 1st Sess. 55–

60 (1935); see also H.R. Rep. No. 1318, 74th Cong.,

1st. Sess. 1–3 (1935). The FPA has been amended

several times, most recently by the Energy Policy

Act of 1992.

are contemplating retail market

structures that are even more fluid than

the California proposal. Differentiating

between sales for resale that are for

former retail customers and sales for

resale that are for ‘‘new’’ wholesale

customers, and therefore somehow the

result of open access policies, would be

extremely difficult. In general, it is not

easy to distinguish among growth in

generation for native retail load,

wholesale requirements customers,

existing economy sales, and new sales

that are facilitated by the rule, either for

purposes of establishing a baseline or

for tracking responsibility for

emissions.991

Joint Commenters proposal would

have the Commission impose a revenue

collection measure—in essence a tax on

open access transmission. The

Commission is authorized by the FPA to

pass through costs, not to collect

additional fees from entities utilizing

programs established by the

Commission. The payment of emission

fees is outside the Commission’s

authority under the FPA.

The FEIS concludes that mitigation by

the Commission should not be

undertaken in this rule because:

• Any mitigation measures the

Commission might undertake are not

justified by the small impacts of the rule,

which impacts are as likely to be beneficial

as they are to be harmful;

• The impacts of the proposed rule are

dwarfed by the far larger ozone and NOX

emission issues that either have nothing to

do with the electric industry or will be

unchanged by the rule or the larger open

access program. We believe that it would be

ineffective to address the NOX and ozone

issues in a piecemeal way;

• The NOX issue is part of a long-standing,

difficult set of inter-regional environmental

issues. Representatives of many interests

have invested substantial efforts toward

finding acceptable solutions through the

OTAG process. Any mitigation the

Commission might undertake could usurp

EPA’s mandate under the Clean Air Act and

undermine progress towards comprehensive

solutions sought by OTAG. This is not

justified by impacts that are small and just

as likely to be positive;

• We do not agree that the frozen

efficiency reference case should be

substituted for the EIS base cases or that

competitive forces will favor coal over the

next 15 years. But even accepting these

assumptions, emissions attributable to the

rule are relatively small until well after the

turn of the century. So, even accepting such

assumptions, the staff believes it would be

unreasonable for the Commission to adopt

mitigation requirements as part of the final

rule; to do so would be tantamount to

assuming that EPA and OTAG will not

implement reasonable control measures in

the next ten to 15 years;

• The Federal Power Act and NEPA, either

singly or conjointly, do not authorize the

Commission to adopt and implement the

proposed mitigation measures. The

Commission does not possess (and has no

mandate to possess) expertise on the

extremely difficult issues involved in

atmospheric chemistry and transport. It is

fundamentally an economic regulatory

agency. As a result, any mitigation measures

the Commission undertook would be based

on less-than-ideal information and analysis.

It is unreasonable for the Commission to

attempt such mitigation given the impacts

found in this FEIS. This is especially true in

light of the substantial additional research

that EPA and OTAG are undertaking on the

basic nature of the problem;

• Some suggested mitigation measures that

might work at the transaction level would

undermine the purpose of the rule. There is

no justification for endangering the

substantial benefits projected from the rule to

mitigate a problem that might not exist and

that is, in any case, likely to be small.992

In sum, the rule is expected to have

small impacts and those impacts are as

likely to be beneficial as they are to be

harmful. Therefore, mitigation is not

required. In addition, processes are in

place to address the pre-existing NOX

problem—a problem that dwarfs any

impacts the Rule might have. These

processes are expected to address the

underlying transport problems well

before any potential harmful effects of

the rule will develop.993

The mitigation measures that certain

commenters urge the Commission to

adopt are truly unwarranted in light of

these facts. They also fail to recognize

or adequately consider the

Commission’s limited jurisdiction, its

lack of expertise required to assess and

address the underlying problem, the

existing mechanisms and efforts to

address the underlying problem, and the

balance that has been reached and

continues to be defined by the many

interests that have invested substantial

efforts toward finding acceptable

solutions to these problems.

3. Legal and Policy Considerations

The FEIS concludes that the

mitigation measures recommended by

commenters are beyond our authority to

implement and that strong policy

considerations militate against their

adoption. We agree.

Several commenters contend that the

Commission is authorized to use the

rulemaking as a vehicle to impose an air

emissions regulatory regime on the

electric utility industry.994 Others argue

that, as a matter of law and policy, we

cannot and should not impose such

measures.995 While the conditioning

proposals vary in specifics, all have as

their central theme that generators

would be forced to agree to operate

generation facilities in a manner to

reduce air pollution below levels

currently authorized by EPA and the

states.996

The Commission’s authority to

regulate public utilities is set out in

Parts II and III of the FPA. Parts II and

III do not provide the Commission with

the authority to condition either the

provision of, or access to, jurisdictional

services on the agreement to undertake

environmental mitigation measures.997

Section 201, which is found in Part II of

the FPA, explicitly bars the Commission

from exercising the jurisdiction that the

proponents of the conditioning
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21683

998The statutory framework established by

Congress in sections 205 and 206 is not compatible

with the administration of environmental regulatory

regimes as a precondition to authorization. The

Commission has only 60 days to review rate filings

under section 205 before they become effective.

Absent Commission action rejecting a rate filing or

suspending its operation for up to five months

within such period, a jurisdictional transaction

(either the sale of energy or the transmission of

energy) and the proposed rates accompanying the

transaction go into effect by operation of law. Some

mitigation proposals would require us to reject

transactions within 60 days or allow them to go

forward but with case-by-case determinations or

hearings on environmental effects made within that

time period. This could result in transaction

gridlock for the trade of electricity in interstate

commerce—a situation that is totally at odds with

the regulatory framework established by Congress

in the FPA and the Commission policy objectives

under this rule to minimize regulatory impediments

to fluid competitive power sales markets. Moreover,

letting transactions go into effect subject to

environmental hearings is not likely to produce

meaningful environmental controls. Clearly, our

processes, which contemplate the resolution of

factual matters through hearings and the use of

refund obligations to adjust parties’ obligations on

the basis of the record, make no provision for

extensive scientific inquiry and are not designed to

accommodate the imposition of clean air standards

on power sellers.

999See FPA section 202(b), 16 U.S.C. 824c(b). See

also Department of Energy Organization Act, 42

U.S.C. 7151, 7172.

1000We also note that section 731 of the Energy

Policy Act preserves state and local authority over

environmental protection and the siting of facilities.

1001For example, we do not have jurisdiction over

the physical location of generation or transmission

facilities, even though we have exclusive

jurisdiction of the rates, terms and conditions of

sales for resale or transmission of electric energy in

interstate commerce by public utilities using such

facilities, i.e., the economic aspects of the use of

such facilities.

1002The Federal Water Power Commission was

established in 1920 with jurisdiction over the

licensing of hydropower projects. 41 Stat. 1063

(June 10, 1920). In 1935, it was reconstituted as the

Federal Power Commission, with expanded

responsibilities over utility regulation. The

jurisdiction over the licensing of hydropower was

preserved as Part I of the Federal Power Act.

1003See Report of National Power Policy

Committee on Public Utility Holding Companies.

1004FPA section 201(a), 16 U.S.C. 824(a). The

House, Senate and Conference Reports concerning

the Public Utility Act of 1935, i.e., concerning Parts

II and III of the FPA, are silent with respect to

environmental concerns.

1005See, e.g., comments by EPA, Project for

Sustainable FERC, and Attorneys General.

1006See, e.g., Methow Valley, 490 U.S. at 350–53;

see also, LaFlamme v. FERC, 852 F.2d 389, 399 (9th

Cir. 1988).

1007NAACP, 520 F.2d at 433.

1008 Id. at 437–38 (footnotes omitted). The

authorities listed cover FPA sections 202, 203, 204,

205, 206, and 207.

proposals would have us undertake:

authority over the operation of

generating facilities. Section 201(b)(1)

provides that:

The Commission shall have jurisdiction

over all facilities for (the transmission of

electric energy in interstate commerce) or

(the) sale of electric energy (at wholesale in

interstate commerce), but shall not have

jurisdiction, except as specifically provided

in (Parts II and III), over facilities used for the

generation of electric energy * * *.

(emphasis added).

This standard is reflected throughout

Parts II and III of the FPA. Sections 205

and 206, which are the cornerstones of

Parts II and III, concern the regulation

of rates, terms and charges occurring in

connection with transmission or sales

subject to the Commission’s

jurisdiction. Parts II and III do not grant

the Commission authority to regulate

the environmental aspects of

jurisdictional activities.998 Instead, they

provide authority over certain

interconnections; 999 the rates, terms and

conditions of wholesale sales of electric

energy in interstate commerce and

transmission in interstate commerce; the

disposition and merger of facilities used

for such sales and transmission;

issuance of securities; accounting

matters; and interlocking directorates.

Thus, the Commission’s jurisdiction

over generation extends only to matters

directly related to the economic aspects

of transactions resulting from such

facilities.1000 We do not have

jurisdiction over the physical aspects of

generation facilities.1001

This limitation on the Commission’s

jurisdiction stems from the historical

purposes for which the Commission was

established. Congress had two objectives

in expanding the authority of the

Federal Water Power Commission in

1935.1002 The first was to close the gap

created by Public Utilities Commission

v. Attleboro Steam & Electric Co., 273

U.S. 83 (1927)(Attleboro), in which the

Court found that under the Commerce

Clause states could not regulate

wholesale sales of electricity in

interstate commerce. The result was a

gap in regulation of such sales because

there was no federal entity with

authority to regulate them at that time.

The second was to eliminate the

economic abuses that were then

rampant in the industry.1003 In

expanding the Commission’s

jurisdiction Congress made clear that

such Federal regulation, however, was

‘‘to extend only to those matters which

are not subject to regulation by the

States.’’ 1004

Several commenters argue

nonetheless that the Commission may

do indirectly what it is barred from

doing directly. Their arguments boil

down to the claim that the

Commission’s responsibility under the

FPA to act in the ‘‘public interest’’,

either alone or in conjunction with

NEPA, provides the Commission with

the authority to impose environmental

regulation on generators to address the

supposed impacts of the Rule.1005 We

disagree. In making this argument, the

commenters attribute to that standard a

breadth of discretion that vastly exceeds

the traditional ambit of our authority.

It is well established that NEPA

merely establishes a procedural vehicle

for assessing the impacts of a proposed

action on the environment. It neither

expands nor contracts the basic grant of

jurisdiction made by Congress to the

agency conducting the review, and it

does not mandate particular results but

simply prescribes a process.1006

Commenters’ arguments that NEPA

somehow ‘‘fills in the blanks’’ of the

FPA to authorize us to impose

environmental regulatory regimes on

generating facilities, or those who may

purchase power from them, is simply

incorrect. If we have such authority, it

must be found in our substantive

statute, the FPA.

Courts have addressed the breadth of

our public interest standard on several

occasions. The principal case on this

point is National Association for the

Advancement of Colored People v. FPC

520 F.2d 432 (D.C. Cir. 1975), aff’d, 425

U.S. 662 (1976) (NAACP). In NAACP, a

number of organizations requested that

the Commission promulgate regulations

requiring equal employment

opportunity and proscribing racial

discrimination in the employment

practices of public utilities.1007 The

Commission declined, finding that the

FPA did not authorize it to do so.

Petitioners appealed, contending that

the Commission was authorized and

required to act in the public interest:

to order such interconnections of electric

power transmission facilities, setting such

terms and conditions for the same, as are

‘‘necessary or appropriate in the public

interest’’; to approve such asset sales and

consolidations of interstate electric power

companies as are ‘‘consistent with the public

interest; to approve such securities issuances

by those companies as are ‘‘compatible with

the public interest’’ and ‘‘consistent with the

proper performance * * * of service as a

public utility’’; to determine ‘‘just and

reasonable’’ rates for interstate sales and

transmission of electric power; and to order

that ‘‘proper, adequate or sufficient’’

interstate power service be rendered.1008

On this basis, they argued that because

prohibition of discrimination is in the

‘‘public interest,’’ the Commission was

therefore required to proscribe

discrimination by jurisdictional entities.

The Court rejected petitioners’

argument. It observed that:

the (Federal Power) Act’s preamble echoes

the generality of the foregoing quoted
21684 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

1009 Id. at 438 (footnote omitted).

1010 Id.

1011 Id. at 440, citing New York Central Securities

Co. v. United States, 287 U.S. 12, 24 (1932).

1012 Id., quoting Alabama Electric Cooperative,

Inc. v. SEC, 353 F.2d 905, 907 (1965), cert. denied,

383 U.S. 968 (1966).

1013 Id. at 441 (emphasis in original). The Court

made clear that ‘‘the conservation of natural

resources’’ was a Commission interest only with

regard to the regulation of hydropower resources

under Part I of the FPA. Id. at 437.

1014 Id. at 443 and 441.

1015NAACP, 425 U.S. 662 (1976).

1016 Id. at 670 (footnote omitted). Several

commenters, e.g., Project for Sustainable FERC at

31–32 and Alliance at 53, make much of the Court’s

statement that there are undoubtedly other

subsidiary purposes contained in the FPA and

NGA, noting its reference in a footnote that the

Commission has authority to consider

‘‘environmental’’ questions. NAACP, 425 U.S. at

670 n.6. However, they neglect to mention that the

section of the FPA which the Court identified in

support of this reference to environmental

questions is section 10 of the FPA concerning our

Part I authority over hydroelectric licensing matters,

not Parts II and III. Part I contains explicit authority

for the Commission to consider and require

environmental mitigation measures.

1017NAACP, 425 U.S. at 665.

1018 In analyzing the scope of the Commission’s

authority to act in the public interest, the NAACP

Court found it useful to analogize to federal labor

law. While noting that Congress had ‘‘unmistakably

defined the national interest in free collective

bargaining,’’ Id. at 671, the Court found that it could

not be supposed that in directing the Commission

to be guided by the ‘‘public interest,’’ Congress

instructed the Commission ‘‘to take original

jurisdiction over the processing of charges of unfair

labor practices on the part of its regulatees.’’ Id. Yet

this is exactly the form of what EPA and the other

commenters supporting our authority to require

environmental mitigation would have us do.

However, just as with discriminatory employment

practices, we can consider the consequences of air

pollution practices of our regulatees ‘‘only insofar

as such consequences are directly related to the

Commission’s establishment of just and reasonable

rates in the public interest.’’ Id. (emphasis added).

1019We note that the standard the Commission is

bound to apply in reviewing section 205 and

section 206 transactions (which are the focus of the

majority of commenters’ mitigation proposals) is

not a broad ‘‘public interest’’ standard, but rather

a standard that rates, terms and conditions of such

transactions be ‘‘just, reasonable and not unduly

discriminatory or preferential.’’ 16 U.S.C. 824d,

824e.

1020NAACP, 425 U.S. at 665.

1021The limited nature of the Commission’s

ability under NAACP to consider ‘‘environmental’’

issues is reflected in the few court decisions on this

subject. See Public Utility Commission of California

v. FERC, 900 F.2d 269, 281 (D.C. Cir. 1990) (The

broad public interest standards in the Commission’s

enabling legislation are limited to ‘‘the purposes

that Congress had in mind when it enacted this

(NGA and FPA) legislation. This rule helps confine

an agency’s authorization ‘‘to those areas in which

the agency fairly may be said to have expertise.’’);

Process Gas Consumers Group v. FERC, 930 F.2d

926, 935 & n.14 (D.C. Cir. 1991) (Commission

improperly allowed in rates the costs of research

intended to benefit ratepayers solely through a

‘‘cleaner environment’’; the Court found that the

Commission has no particular ‘‘expertise’’ in

determining and promoting the pollution-reducing

effects of natural gas vehicles).

1022The Supreme Court’s holding in NAACP as to

the limited ability of administrative agencies to

implement broad ‘‘public interest’’ mandates, and

direction to refrain from straying beyond the

specific purposes of the regulatory legislation they

are entrusted to administer, is well established. See

Community Television of Southern California v.

Gottfried, 459 U.S. 498, 510–11 n.17 (1983) (‘‘[A]n

agency’s general duty to enforce the public interest

does not require it to assume responsibility for

enforcing legislation that is not directed at the

agency’’); Hampton v. Mow Sun Wong, 426 U.S. 88,

114 (1976) (‘‘It is the business of the Civil Service

Commission to adopt and enforce regulations which

will best promote the efficiency of the federal civil

service. That agency has no responsibility for

foreign affairs, for treaty negotiations, for

establishing immigration quotas or conditions of

entry, or for naturalization policies’’); McLean

Trucking Company v. United States, 321 U.S. 67,

79 (1944) (that Congress ‘‘has vested expert

administrative bodies such as the Interstate

Commerce Commission with broad discretion and

has charged them with the duty to execute stated

and specific statutory policies’’ does not

‘‘necessarily include either the duty or the authority

to execute numerous other laws’’ beyond

enumerated statutory responsibilities); see also Bob

Jones University v. United States, 461 U.S. 574, 611

(1983) (Powell, J., concurring) (‘‘This Court often

has expressed concern that the scope of an agency’s

authorization be limited to those areas in which the

agency fairly may be said to have expertise’’).

Lower courts have repeated the Court’s

admonition in this regard on numerous occasions

phrases, declaring that the sale and

transmission of electric power are ‘‘affected

with the public interest,’’ federal regulation

of interstate aspects being ‘‘necessary in the

public interest.’’ The statute itself nowhere

defines the ‘‘public interest,’’ but instead

leaves the precise ambit of the Commission’s

concern uncertain.1009

The Court found from the entirety of the

Act that, ‘‘(o)f the Commission’s

primary task there is no doubt, however,

and that is to guard the consumer from

exploitation by non-competitive electric

power companies.’’ 1010 The Court

reiterated that ‘‘(t)he Supreme Court has

stated that the words ‘public interest’ do

not constitute a ‘mere general reference

to the general welfare, without any

standard to guide determinations.’ ’’ 1011

Significantly, the Court also found that

‘‘(w)ords like ‘public interest’ * * *

though of wide generality, take their

meaning from the substantive

provisions and purposes of the Act.’’ 1012

The Court concluded that:

Congress has not charged the Commission

with advancing all public interests, but only

the public’s interest in having the particular

mandates of the Commission carried out, its

interest, in other words, in the conservation

of natural resources and the enjoyment of

cheap and plentiful electricity and natural

gas. 1013

With this, the Court rejected

petitioners’ argument that the FPA

‘‘public interest’’ standard requires the

Commission to promulgate regulations

prohibiting discriminatory practices by

entities who are in some way regulated

by the Commission. The Court found

that the Commission was not

empowered to promulgate antidiscrimination regulations because to do

so would not be ‘‘reasonably related to

the furtherance of the Commission’s

proper objectives,’’ which, under Part II

of the FPA, are ‘‘the enjoyment of cheap

and plentiful electricity.’’ 1014

On review, the Supreme Court

affirmed this limited reading of the

Commission’s authority to act in the

public interest.1015 In doing so, the

Court noted that:

The use of the words ‘‘public interest’’ in

the Gas and Power Acts is not a directive to

the Commission to seek to eradicate

discrimination, but, rather, is a charge to

promote the orderly production of plentiful

supplies of electric energy and natural gas at

just and reasonable rates.1016

The question the Supreme Court

asked in NAACP is the appropriate

question here concerning the

commenters’ environmental mitigation

proposals:

The question presented is not whether the

elimination of discrimination from our

society is an important national goal. It

clearly is. The question is not whether

Congress could authorize the Federal (Energy

Regulatory) Commission to combat such

discrimination. It clearly could. The question

is simply whether and to what extent

Congress did grant the Commission such

authority.1017

We believe the same conclusion is true

here for air pollution as the Court found

there regarding discrimination.1018

The argument by EPA and others that

because the FPA authorizes the

Commission to act in the ‘‘public

interest’’ it somehow authorizes the

Commission to impose environmental

mitigation measures is virtually

indistinguishable from petitioners’

argument in NAACP.1019 Here, as in

NAACP, parties urge the Commission to

act to achieve worthwhile goals.

However, the question is not whether

the measures proposed by the parties

would advance important national

goals. Rather, ‘‘[t]he question is simply

whether or to what extent Congress did

grant the Commission such

authority.’’ 1020 Also here, as in NAACP,

the parties improperly base their belief

that the Commission has authority to act

under the FPA on an incorrect, overly

broad application of the ‘‘public

interest’’ standard. The goals sought to

be advanced by EPA and others are

broadly speaking ‘‘in the public

interest,’’ but they are not goals that

Congress has directed this Commission

to pursue.1021 Thus, just as the FPA did

not authorize the Commission to take

actions that petitioners requested in

NAACP, the FPA does not authorize the

Commission to undertake the types of

environmental mitigation measures

proposed by the commenters.1022
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21685

in finding that federal agencies improperly have

overstepped, or properly have refrained from

overstepping, the limitations of their ‘‘public

interest’’ (or similarly worded) jurisdiction. See,

e.g., The Business Roundtable v. Securities and

Exchange Commission, 905 F.2d 406, 413–14 (D.C.

1990) (SEC’s assertion of authority under ‘‘public

interest’’ standard to bar national security

exchanges and associations from listing stock of

certain corporations invaded traditional state

regulatory purview); Public Utility Commission of

California v. FERC, 900 F.2d 269, 281 (D.C. Cir.

1990) (FERC has no authority to consider

allegations of copyright infringement or unfair trade

practices in determining whether to issue

certificates of public convenience and necessity);

American Trucking Association v. United States,

642 F.2d 916 (5th Cir. 1981) (intention of ICC to

promote competition is consistent with statutory

standard; more generalized intention to promote

public welfare needs, unrelated to its legislative

instruction to attend to transportation needs of the

public, is not); Natural Resources Defense Council,

Inc. v. Securities and Exchange Commission, 606

F.2d 1031 (D.C. Cir. 1979) (SEC has no obligation

to promulgate regulations requiring comprehensive

disclosure of (among other things) corporate

environmental policies unrelated to objectives of

federal securities laws); Sunflower Electric

Cooperative, Inc. v. Kansas Power & Light

Company, 603 F.2d 791, 799 (D.C. Cir. 1979) (FERC

does not have primary jurisdiction to consider

antitrust-related issues that do not involve ratesetting practices of public utilities); O-J Transport

Company v. United States, 536 F.2d 126, 131–32

(6th Cir.), cert. denied, 429 U.S. 960 (1976) (ICC

properly did not stray beyond its congressionallydefined role over transportation regulation by

refusing to promote more generalized public

welfare concerns); see also, e.g., In re Multidistrict

Vehicle Air Pollution, 538 F.2d 231 (9th Cir. 1976)

(under antitrust laws, federal district court has no

authority to fashion an environmental remedy,

intended to reduce auto emissions, that serves no

antitrust purpose).

1023Project for Sustainable FERC at 31.

1024Richmond Power, 574 F.2d at 616–17

(footnotes omitted).

1025 Id. at 616 n.22 (emphasis added).

1026Alliance and the Project for Sustainable FERC

cite American Trucking Association, Inc. v. United

States, 642 F.2d 916 (5th Cir. 1981), to support an

argument that, even under NAACP, the Commission

can impose conditions under the FPA ‘‘public

interest’’ standard because there is a ‘‘nexus’’

between the primary goals of the FPA and the

proffered conditions. As discussed below in greater

detail, we disagree.

American Trucking involved review of an ICC

rulemaking effort to, among other things, allow

government agencies to tender a fair portion of their

freight shipments to small businesses and those

operated by disadvantaged persons. In reviewing

the case, the Court referenced the NAACP decision

to observe that under the governing law, the ICC’s

‘‘useful purpose’’ and ‘‘public need’’ criterion (used

here to justify the regulations) do ‘‘not (refer) to the

pursuit of affirmative action goals.’’ Id. at 921–922.

Indeed, it is clear that the Court read NAACP as

permitting the consideration of ‘‘racial, ethnic and

social-economic factors’’ only when they relate to

the matters within the ICC’s authority, i.e., the

transportation needs of the public, as opposed to

some generalized notion of the general public

welfare. Id. at 922 n.3.

1027NGA section 7(a), like, for example, FPA

section 203(a), provides for a ‘‘public interest’’

standard of review. Section 7 of the NGA represents

the maximum authority the Commission has over

environmental issues under that Act. Section 7

provides the Commission authority to approve the

siting and construction of facilities.

1028 Great Plains, 655 F.2d at 1147.

1029 Id.

1030 Id. at 1150.

1031 Id. at 1151.

1032 Id.

The Project for Sustainable FERC

argues that in Richmond Power & Light

v. FERC, 574 F.2d 610, 616–17 n.22

(D.C. Cir. 1978) (Richmond Power), the

Court ‘‘suggested’’ a broader agency

latitude than described in NAACP.1023

We disagree.

Richmond Power involved a case

where the Commission was challenged,

inter alia, because it declined to adopt

a particular transmission rate that

would have permitted Richmond to

shift from oil to some other fuel. The

Court affirmed the Commission’s

decision, finding that:

Although the Commission must serve the

public interest in approving rates, we see no

abuse of discretion in limiting this

proceeding to the shortrun problem of setting

just and reasonable rates for the service

theretofore provided in response to the 1973

oil embargo. While an administrative agency

must remain faithful to public policies

directly related to its regulatory authority,

surely at any given moment of history it may

rationally decline to affirmatively foster other

policies in weighing the specific interests

that it is required by the statute to consider.

This is especially true when the forum

chosen by proponents of the other policy is

not well suited to the study of its

implications.1024

In dicta, in a footnote that began with the

Court doubting whether the goal of energy

independence is within the Commission’s

regulatory jurisdiction at all, the Court

merely said that ‘‘(n)othing in NAACP v.

FPC, supra, forecloses agency discretion to

consider in given situations pervasive public

policies that it is not required to evaluate in

every decision it makes.’’ 1025

The discretion to consider public

policy matters is a far cry from the

authority, or obligation, to regulate

those matters. We have considered the

environmental impact of the rule.

Nothing in Richmond Power suggests

that the consideration of such matters

conveys an affirmative grant of broad

new regulatory powers to develop and

implement a comprehensive regulatory

program in an area expressly assigned

by Congress to another agency.1026

The cases rejecting commenters’

broad reading of our public interest

authority are supported by the decision

in Office of Consumers’ Counsel v.

FERC, 655 F.2d 1132 (D.C. Cir. 1980)

(Great Plains). There, the Court found

that, even under the explicit ‘‘public

interest’’ standard in section 7(a) of the

Natural Gas Act, the Commission is not

granted power to act on matters outside

of its statutory mandate.1027

In Great Plains, the Court reviewed a

Commission decision to grant a

certificate of public convenience and

necessity to facilitate construction and

operation of a coal gasification plant.

Although the NGA does not explicitly

provide the Commission with authority

to certificate coal gasification projects,

the Commission reasoned that it had

such authority because the

demonstration project was ‘‘in the

public interest’’ and, because the

Commission was authorized under

section 7 of the NGA to ‘‘consider’’ all

factors in reaching a decision on

whether to grant the certificate, it had

the requisite authority to act.

The Court rejected the Commission’s

reasoning in that case, stating that:

Any such authority to consider all factors

bearing on the ‘‘public interest’’ must take

into account what the ‘‘public interest’’

means in the context of the Natural Gas Act.

FERC’s authority to consider all factors

bearing on the public interest when issuing

certificates means authority to look into those

factors which reasonably relate to the

purposes for which FERC was given

certification authority.1028

The Court repeated the finding in

NAACP that the Commission’s authority

to act in the public interest is limited to

the furtherance of the purposes for

which its organic statutes were

adopted.1029

In concluding that the Commission

was not authorized to act as it did, the

Court looked to several factors. The

Court found it persuasive that Congress

had specifically authorized a different

governmental entity, the Synthetic Fuels

Corporation, to provide support for coal

gasification, and that Congress had

carefully crafted a special means for

providing federal financial assistance

for synfuel development.1030 The Court

also found it persuasive that the

Commission possessed no expertise in

making determinations regarding the

relative merits of different synfuel

processes, methods or technologies, and

that the financing arrangements ‘‘were

certainly not ordered with the interests

of ratepayers foremost in mind.’’1031 The

Court stated that ‘‘by utilizing its

statutory tools for a non-statutory

purpose, FERC very likely was

distracted from its primary statutory

duty to protect the interests of

ratepayers.’’ 1032 Finally, the Court

found that the Commission’s action

seemed to have been prompted at least

in part by an attitude that, because

Congress had not acted speedily, the

Commission could act. The Court

criticized the Commission for

improperly attempting to preempt

Congressional action and to ‘‘fill in’’
21686 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

1033 Id. at 1151–52.

1034To our knowledge the only time Congress has

asked the Commission with respect to its regulation

under Parts II and III of the FPA to address

environmental issues was in Section 808 of the

Clean Air Act Amendments of 1990. There,

Congress directed the Commission, in consultation

with EPA, to study the environmental externalities

of electricity production. The Commission staff did

so and provided the required report to Congress.

While the Commission in compliance with the 1990

Amendments also addressed the accounting issues

related to SO2 emissions trading, the Commission

did so within the context of its accounting authority

under the FPA.

1035EPA argues that the Commission would not

be required to monitor compliance with the

environmental mitigation measures. However, if

environmental mitigation is within our statutory

mandate, we could not delegate that authority to

others. See EPA at 51.

1036EPA at 4–5; see also Project for Sustainable

FERC (protections achieved by the Clean Air Act

Amendments of 1990 are in danger of being

destroyed by the Energy Policy Act’s open access

policies if those policies are implemented without

environmental mitigation).

We would also note that the premise upon which

EPA makes this argument—that air emissions will

rapidly increase with implementation of the rule—

is not supported by the record. See Section V,

Discussion, Subsection C.

1037We believe that this conclusion is supported

by section 205(a) of the Public Utility Regulatory

Policies Act of 1978 (PURPA). PURPA, inter alia,

amended the FPA in certain respects but also gave

the Commission authority in certain sections, such

as PURPA sections 205(a) and 210, that did not

amend the FPA. Under PURPA section 205(a), the

Commission in certain circumstances may exempt

electric utilities, in whole or in part, from state

laws, rules or regulations which prohibit or prevent

voluntary coordination, including agreements for

central dispatch. (Of course, the central dispatch is

dispatch of generation facilities.) However, PURPA

section 205(a)(2) provides that no exemption may

be granted if the state law, rule or regulation is

designed, among others, to protect public health,

safety or welfare or the environment. In

commenting on the limitation of the Commission’s

exemption authority under PURPA section 205(a),

the Conferees noted that the prohibition includes

‘‘regulations under the Clean Air Act.’’ H.R. Conf.

Rep. No. 1750, 95th Cong., 2d Sess. 95 (1978),

reprinted in 1978 U.S. Code Cong. & Ad. News

7797, 7829. While the Commission’s statutory

authority has been modified in legislation enacted

subsequent to PURPA, the provisions of PURPA

section 205(a) have not been modified.

1038See, e.g., EPA at 54. See also Alliance; Project

for Sustainable FERC; Coalition; Signatories; CCAP;

Attorneys General.

1039Under this logic, the Securities and Exchange

Commission, for example, which facilitates utility

financing for new facilities would be empowered to

administer environmental requirements.

1040We are also troubled by the confusion that

persists as to the usefulness of imposing a condition

on the use of open access tariffs as a means to

accomplish environmental goals. As noted earlier,

the Commission’s decision to compel the filing of

open access tariffs is intended to provide access to

third party power suppliers who need access across

a utility’s transmission system. Open access will

primarily benefit independent power suppliers

offering power from new facilities, most of which

under current market conditions are likely to be

gas-fired facilities. Traditional utilities that own the

generating plants of particular concern to

commenters (i.e., coal-fired plants subject to less

strict environmental controls) have extensive

transmission systems that they can use to get power

to market. Thus, the exercise of conditioning

authority is more likely to impede sales from new,

cleaner facilities than it is sales from older, coalfired facilities. It makes no sense from an economic

or environmental perspective to burden new

transactions with this cumbersome condition for

what will likely be little in the way of effective

environmental controls.

where the agency believed federal

action was needed.1033

The facts and reasoning in Great

Plains are directly analogous to this

proceeding. Congress has specifically

authorized other entities—EPA and the

states—under other statutes to address

air pollution. The Commission is being

urged to regulate in an area in which, as

in Great Plains, it possesses no special

expertise (i.e., in making determinations

regarding appropriate air pollution

control mitigation measures) and in

which it is not authorized to act.1034

Finally, as in Great Plains, if the

Commission were to undertake

mitigation, it would be diverted from its

primary statutory duty to protect the

economic interests of ratepayers, i.e., by

having to continually monitor

compliance with mitigation

conditions.1035

As in Great Plains, the Commission is

being urged to act at least in part

because of the belief that Congress has

not provided a sufficiently speedy

process by which to regulate air

pollution produced by electric utilities.

The EPA argues that:

Regulations under the Clean Air Act must

in general be implemented through State

Implementation Plans; the time from

reaching a general conclusion that control is

needed to adoption of necessary regulations

by states generally takes from three to five

years; that regulatory lag time means

compliance with new rules can be, and

usually is, more than a decade from the point

at which the problem occurred. Ten years of

bad air is ten years delay too many.1036

That Congress has imposed upon the

EPA procedures that the EPA and others

find burdensome and overly time

consuming is an issue for Congress and

EPA to address, not the Commission.1037

This conclusion has particular force

when, as here, we are urged to impose

environmental restrictions on certain

coal-fired generators in spite of

Congressional actions regulating those

entities. In essence, some commenters

argue that under a very tenuous

connection to the public interest

standard of the FPA we may undertake

to do more than the agency that

Congress has authorized to act on such

matters. This result is not a correct

reading of the law and we reject it.

Several commenters attempt to

overcome the various Courts’ views of

the scope of the public interest standard

under the FPA by arguing that there is

a ‘‘direct nexus’’ between the Rule and

environmental concerns that suffices to

invoke an imputed authorization under

the FPA to prescribe environmental

requirements on generators.1038 To this

end, they argue that the purpose of the

rule is really to facilitate the least-cost

use and construction of generation

resources and that the environmental

consequences of these actions will

impact economic efficiency, rates,

competition, and competitive markets.

Thus, they conclude that we have the

authority to require that those who seek

to obtain transmission access on a nondiscriminatory basis must first mitigate

air emissions under as yet undefined

standards.

These commenters misstate the

question. The question is not whether

there is a nexus between the rule and

environmental concerns. Clearly,

electric utilities contribute to pollution;

anything that facilitates the sale of

power from whatever source is, under

this tenuous logic, ‘‘related’’ to

environmental concerns.1039

However, as discussed below,

Congress did not give us plenary powers

over public utilities to shape their

activities in response to a broad range of

public policy concerns. The nexus that

must be established is a nexus between

the requirements sought to be imposed,

in this case emission controls, and the

statutory standards which authorize us

to act. That is, in order to impose the

environmental conditions sought by

commenters, a direct connection must

be established between those conditions

and our duty to determine that the rates,

terms and conditions of service under

our open access tariffs are not unjust,

unreasonable, unduly discriminatory, or

preferential.

It is on this point that commenters’

arguments founder. While the

Commission has broad latitude to

interpret these standards to advance the

interests of ratepayers, we cannot

implement policy objectives that are not

assigned to us and that are, in fact,

clearly assigned to other entities. The

Congress has assigned responsibility for

environmental regulation of air quality

to EPA and the states; it has explicitly

charged them with dealing with such

pollution from electric generating

facilities. While, as noted earlier, we do

not dispute the need to give appropriate

weight to environmental considerations

in making decisions within our

authority, we cannot use that authority

to accomplish public policy objectives

that, by statute, are required to be

implemented and administered by other

agencies.1040
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21687

1041Alliance at 55. See also Project for

Sustainable FERC at 37.

1042For the same reason, we do not have authority

to impose an obligation on utilities to ‘‘internalize’’

environmental externalities. See generally FEIS at

7–24. In effect, such proposals would involve the

Commission requiring a surcharge on power sales

rates fixed at some amount equal to the

environmental ‘‘cost’’ inflicted by the generation

supporting those sales. Assuming such a surcharge

could be calculated, imposing such a cost would be

to fix a rate without reference to any cost incurred

by the public utility. Indeed, we would impose in

rates, and require ratepayers to pay, a cost that was

manifestly not incurred by the utility. In reality,

such a surcharge would require us to impose a tax

or a penalty, neither of which we are authorized to

impose.

The SO2 program created under the 1990 Clean

Air Act Amendments illustrates the way in which

EPA and FERC authority can intersect to

accomplish the goal of internalizing externalities.

There, the Congress by capping emissions and

providing for a market in emission allowances

required utilities to ‘‘pay for’’ the right to emit SO2.

These costs are legitimate costs and the

Commission’s role is to permit their recovery in

rates. Similarly, a comparable NOX cap and trading

scheme established by EPA would ‘‘internalize’’ the

external costs of NOX pollution and the

Commission would provide for prudently incurred

allowance costs in rates.

1043NAACP, 425 U.S. at 670.

1044Cf. Utah Power & Light Co., Opinion No. 318,

45 FERC ¶ 61,095 at 61,280–83 (1988) (discussing

the Commission’s authority to condition a merger).

Unlike the situation in Opinion No. 318 where the

Commission had the authority under section 203 to

disapprove a merger upon a finding of actual and

potential anticompetitive effects, the Commission’s

rate authority under sections 205 and 206 does not

permit the Commission to deny the proposed rates

out of a concern that such action will result in an

increase in air pollution. See Monongahela Power

Co., 39 FERC ¶ 61,350 at 62,096, reh’g denied, 40

FERC ¶ 61,256 (1987). As a result, we have no

authority to condition the same result under these

sections on environmental mitigation.

1045The obligation of the Commission to weigh

antitrust considerations highlights this point. The

Commission must take into account anticompetitive

effects when setting rates. See Northern Natural Gas

Co. v. FPC, 399 F.2d 953 (D.C. Cir. 1968). However,

we are limited as to the remedies we may impose.

We cannot go further and assess the range of

remedies that, for example, a Court may exact upon

finding an antitrust violation. See generally

NAACP, 520 F.2d at 441.

1046Project for Sustainable FERC, at 32–33, and

Alliance, at 41–42, have attempted to argue that

NAACP actually supports the Commission having

authority to order environmental mitigation. Their

argument fails because they have not shown, and

cannot show, the necessary direct nexus to our

economic regulation.

1047For example, our regulations permit 100

percent of any construction work in progress for

pollution control facilities allocable to wholesale

sales to be included in rate base. See 18 CFR 35.25

(1995). This regulatory action, directly related to

our core ratemaking responsibilities, removes an

economic disincentive for public utilities to invest

in structures designed to reduce the amount of

pollution produced by a generating facility. See 18

CFR 35.25(b) (definition of pollution control

facility).

The Commission also addressed the ratemaking

consequences of SO2 emissions trading in response

to a petition from the Edison Electric Institute. This

is another example of the Commission’s proper

exercise of its jurisdiction, i.e., over the costs of

environmental compliance.

1048 Indeed, our regulations provide for such cost

recovery.

1049EPA at 50.

Some commenters have sought to

address this issue by characterizing the

proposed conditions as necessary to

create a level competitive playing field

among generators. For example,

Alliance argues that unless the

Commission requires environmental

mitigation certain competitors in the

bulk power market (those with ‘‘dirty

generation’’) would be favored over

‘‘clean’’ competitors. It argues that:

Mitigation of the environmental impacts

resulting from the NOPR has a direct

relationship to ensuring that open access is

implemented under terms of economic

fairness for all utilities and utility consumers,

and not merely those with current low-cost

regulatory advantages.1041

We note that all power generation

technologies have different costs. For

example, hydroelectric facilities which,

like coal-fired facilities, may have

environmental mitigation conditions

imposed on them, may be quite

expensive to build compared to gas or

oil-fired generation, but their operating

costs may be significantly lower. These

cost differences may reflect the different

costs of complying with mandated

environmental requirements; the

prudent costs of complying with such

mandates may be reflected in rates.

Indeed, sellers come to the power

markets with a variety of advantages

and disadvantages, many of which are

the result of federal laws—for example,

tax preferences, labor standards, and

similar matters. In empowering the

Commission to remedy undue

discrimination and promote

competition, Congress has not

authorized the Commission to equalize

the environmental costs of electricity

production in order to ensure

‘‘economic fairness.’’ Such

homogenization of competitors, or their

costs, has never been a goal of the

FPA.1042

In short, the ‘‘economic nexus’’ urged

by commenters advocating that the

Commission undertake to regulate air

emissions is inconsistent with the

‘‘charge to promote the orderly

production of plentiful supplies of

electric energy’’ envisioned by the

FPA.1043

We have exercised conditioning

authority in the past only where

necessary to ensure that jurisdictional

transactions and rates do not result in

anti-competitive effects, or are not

unjust, unreasonable or unduly

discriminatory or preferential.1044 Thus,

the conditions we have imposed have

involved economic regulatory matters

within our purview under the FPA.1045

Any exercise of conditioning authority

must, as the Supreme Court noted in

NAACP, be directly related to our

economic regulation responsibilities;

EPA and the other commenters have not

demonstrated such a nexus.1046

This distinction is more evident when

one considers the way in which we are

authorized to treat the costs of

environmental compliance. There are

legitimate costs of environmental

compliance that should be reflected in

jurisdictional rates to the extent

prudently incurred, just as the prudent

costs of complying with, for example,

occupational health and safety

requirements designed to protect utility

employees should be reflected in

jurisdictional rates. This we are

authorized to do and we routinely

review and allow such costs.1047

However, the fact that the costs of

providing utility workers with a safe

workplace are properly reflected in

utilities’ jurisdictional rates does not

mean that we have authority to

condition sellers’ rates or customers’ use

of jurisdictional services on meeting

safety regulations that are in the public

interest. The same rationale applies to

environmental matters related to the

rule.1048

Commenters also raise several other

arguments to support the claim that the

Rule requires us to undertake

environmental regulation to remedy

supposed impacts of the rule. EPA, for

example, argues that requiring

environmental mitigation would not run

afoul of the prescription of section

201(b)(1) of the FPA enjoining our

regulation of generation facilities

because the ‘‘regulation of transmission

tariffs necessarily has manifold indirect

effects on generation sources. The

proposed mitigation mechanism would

influence generation sources in a

similar, indirect manner.’’ 1049

EPA fundamentally misunderstands

the purpose of the Rule. We act to

remedy unduly discriminatory practices

in, as here for example, the provision of

transmission access. Since ‘‘undue

discrimination,’’ is one of the matters

‘‘specifically provided in this Part (II)’’,

i.e., in FPA sections 205 and 206, we are

acting within the bounds of our

statutory mandate and the effect that the

Rule may have ‘‘over facilities used for

the generation of electric energy’’ is

specifically sanctioned. Indeed, many

generators are transmission customers

who we are obliged to protect under the

FPA. That there may be indirect

environmental consequences from our

Rule does not trigger our jurisdiction

under the FPA.
21688 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

1050EPA at 51. See also NESCAUM at 19; Alliance

at 18, 53; Project for Sustainable FERC at 37.

1051CCEM argues that the tracking of

documentation with environmental compliance

requirements will stifle the very competitive bulk

power market that EPA and others profess to

support. CCEM notes that ‘‘(i)t is both ironic and

inexplicable why EPA, the agency charged with

enforcing the nation’s clean air and other

environmental protection laws is so anxious to shift

this responsibility away from itself and onto

economic participants in the incipient, competitive

power supply industry.’’ CCEM Supplemental

Comments at 4.

1052We also note that under EPA’s scheme those

most likely to benefit from denying access—

transmission sellers—would be provided the

authority to lawfully deny transmission access.

1053EPA states at 51–52 that:

In implementing section 210 of the Public Utility

Regulatory Policies Act, the FERC took the

approach of declining to act because of the potential

adverse environmental impacts of the action.

Section 210 required the FERC to prescribe

regulations ‘‘to encourage cogeneration and small

power production * * * Because of its concern that

‘‘diesel and dual-fuel commercial cogeneration

facilities in the New York City area had the

potential to cause environmentally significant

effects’’ (46 FR 33025) (1981)), the FERC issued

regulations that excluded new diesel cogeneration

facilities from being ‘‘qualifying facilities.’’ 45 FR

17964.

EPA maintains that the FERC similarly has

authority in the instant case to deny open access

transmission to the extent such transmission would

have adverse environmental impacts.

1054The Commission subsequently modified this

position and decided to treat diesel cogeneration

facilities like other QFs.

1055See CMS Midland, Inc., 50 FERC ¶ 61,098 at

61,277–278 (1990), reh’g denied, 56 FERC ¶ 61,177

(1991), aff’d mem. sub nom., Michigan Municipal

Cooperative Group, v. FERC, 990 F.2d 1377 (D.C.

Cir.) (per curiam), cert. denied, 114 S.Ct. 546 (1993);

see also Mesquite Lake Associates, Ltd., 63 FERC

¶ 61,351 (1993); Citizens for Clean Air and

Reclaiming Our Environment v. Newbay

Corporation, 56 FERC ¶ 61,428 at 62,532–33, reh’g

denied, 57 FERC ¶ 61,219 (1991).

1056Small Power Production and Cogeneration

Facilities—Environmental Findings, 10 FERC ¶

61,314 at 61,632 (1980). The Commission has

included similar language in every order it issues

finding qualifying facility status. See also Small

Power Production and Cogeneration, Order No. 70–

E, FERC Stats. & Regs., Regs. Preambles 1977–81 ¶

30,274 at 31,596 (1981).

1057The important point is that the Commission

has fully complied with its responsibilities under

NEPA in both instances. Whatever initial decision

it may have come to in 1981 with regard to the

particular circumstances involved in adopting QF

regulations under PURPA is irrelevant to the instant

rulemaking.

1058EPA’s proposal apparently would apply only

for NOX, CO2 and mercury. See EPA at 58 n.31 and

60 (because there is already a nationwide cap on

SO2 emissions in the Clean Air Act, there is no need

for mitigation for that pollutant). In other words,

EPA apparently would require us to impose

environmental mitigation only in those instances in

which Congress has not provided a nationwide cap

for a pollutant.

1059See United Gas Pipe Line Co. v. Mobile Gas

Service Corp., 350 U.S. 332 (1956); FPC v. Sierra

Pacific Power Co., 350 U.S. 348 (1956).

1060EPA at 59 (emphasis added). See also Project

for Sustainable FERC at 38–39 (proposing that a

regulatory plan be developed through consultations

between the Commission, EPA, DOE, and

appropriate regional and state regulators and then

presented in the FEIS).

EPA next argues that, even if we

could not impose a specific mitigation

mechanism for open access

transmission, we could deny

transmission service unless there is a

showing that the service will not have

an adverse environmental impact.1050

We have already discussed why we

believe this approach is unworkable and

inconsistent with sections 205 and 206

of the FPA.1051 Plainly stated, EPA

would have transmission customers

assume an additional regulatory burden

in order to be treated lawfully.1052 Quite

apart from this fundamental problem,

such a regime is beyond our authority.

Our regulation under sections 205 and

206 is over the selling public utility’s

rates, terms and conditions, not over the

buyer’s agreement to undertake

measures which have no nexus

whatsoever with the seller’s costs or

terms of service.

EPA states that its alternative

mitigation mechanism would not be a

condition of the open access tariff, but

apparently a condition on the ability of

customers to take service under the

tariff. However, our authority to set

terms and conditions of eligibility

derives from precisely the same

authority that we use to set other tariff

terms. It must still be based on a nexus

with the subject matter of our

jurisdiction. For buyers, open access is

a right, not a privilege. We fail to see,

given the direction of the FPA to ensure

these rights, any basis for us to

undertake the actions EPA proposes.

Finally, EPA points to the

Commission’s decision to exclude

certain diesel facilities in defining

qualifying facilities (QF) under PURPA

section 210.1053 However, this provides

no precedent for imposing

environmental standards to prevent

customers from obtaining

nondiscriminatory open access.

Whatever the merits of that decision,1054

the Commission subsequently found

that any facility that satisfies the

ownership and technical requirements

for QF status set forth in PURPA and the

Commission’s regulations is a QF

without any action by the

Commission.1055 More to the point, EPA

ignores the fact that, in issuing

environmental findings with its QF

Rules, the Commission found that

environmental concerns were a local

matter to be handled under other

statutory authorities. While PURPA

permitted certain qualifying facilities to

be exempt from state and federal laws,

it excludes exemptions from environmental

laws. Thus, a qualifying facility may not be

built or operated unless it complies with all

applicable local, State, and Federal zoning,

air, water, and other environmental quality

laws, and unless it obtains all required

permits.1056

Thus, while we have noted that QFs are

required to satisfy all environmental

requirements, we have not viewed our

responsibilities under PURPA as

permitting us to enforce compliance

with environmental laws.1057

EPA then proposes to require any

fossil fuel-burning generating entity

seeking service under an open access

tariff to (a) commit by contract to avoid

or offset emissions increases (measured

against certain baselines), and (b)

periodically certify its compliance with

that commitment.1058 This proposal is

neither workable nor within our

jurisdiction.

The deficiency with respect to (a) is

that we have no authority to require

such action. While EPA cites to FPA

section 206 for the proposition that we

may change jurisdictional contracts, we

may do so only if the contract is, for

example, unjust or unreasonable with

respect to matters within our

jurisdiction, i.e., economic regulation.

Our standards for acting are strictly

prescribed under the FPA.1059 As

NAACP and Great Plains teach, sections

205 and 206 do not provide the

Commission with the means to remedy

every possible problem that is in any

fashion related to a sale for resale or

transmission in interstate commerce by

a public utility. Since we do not have

the authority to require (a), it follows we

cannot require the periodic certification

of compliance recommended in (b).

EPA notes that it ‘‘could establish a

procedure whereby a generator could

voluntarily subject its facilities to

emission limits that are enforceable by

EPA and/or state environmental

authorities.’’ 1060 This is a matter within

EPA’s province, and we support EPA in

undertaking whatever measures it

determines to be within its authority

and appropriate to the problem.

Alliance argues, at 47–51, that

sections 211 and 212 of the FPA, as

amended by the Energy Policy Act,

authorize the Commission to impose

environmental conditions. To the extent

that Alliance’s arguments rely on the

‘‘public interest’’ language used in

section 211, we believe that the

discussion above already addresses such

arguments, with one exception: Alliance

argues that the House Report for the

Energy Policy Act states that the

purpose of the Act is to ‘‘increase U.S.

energy security in cost-effective and

environmentally beneficial ways
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21689

1061Alliance at 62, quoting H.R. Rep. No. 474

(Part I) (Vol. 4), 103d Cong., 2d Sess. 132 (1992),

reprinted in 1992 U.S. Code Cong. & Ad. News

1955.

1062For example, Title XVI concerned Global

Climate Change.

1063See, e.g., S. Rep. No. 228 (concerning the

Clean Air Act Amendments of 1990), 101st Cong.,

2d Sess. 5 (1990), reprinted in 1990 U.S. Code Cong.

& Ad. News 3391 (‘‘The States, together with EPA,

are responsible for ensuring that the primary air

quality standards are met * * *’’); S. Rep. No. 228,

101st Cong., 2d Sess. 9, reprinted in 1990 U.S. Code

Cong. & Ad. News 3395 (‘‘The 1970 and 1977 Clean

Air Act Amendments established a partnership

between the States and Federal government. EPA

sets nationally uniform air quality standards and

States, with the Agency’s assistance, are responsible

for meeting them.’’). See also, e.g., Connecticut v.

EPA, 696 F.2d 147, 163 (2d Cir. 1982) (‘‘One central

focus of the Clean Air Act Amendments of 1977

was to ensure that the EPA would monitor and

control the impact of pollution from one state on

air quality in another.’’); Ohio Environmental

Council v. EPA, 593 F.2d 24, 31 (6th Cir. 1979)

(‘‘Congress placed responsibility for enforcing the

Clean Air Act in the U.S. EPA.’’).

We further note the following limitations on the

Clean Air Act Amendments of 1990 with respect to

the emission allowance program in section 403(f),

which provides in pertinent part:

Nothing in this section shall be construed as

requiring a change of any kind in any State law

regulating electric utility rates and charges or

affecting any State law regarding such State

regulation or as limiting State regulation (including

any prudency review) under such a State law.

Nothing in this section shall be construed as

modifying the Federal Power Act (16 U.S.C.A. 791a

et seq.) or as affecting the authority of the Federal

Energy Regulatory Commission under that Act.

Nothing in this subchapter shall be construed to

interfere with or impair any program for

competitive bidding for power supply in a State in

which such program is established.

42 U.S.C. 7651b(f). Thus, Congress expressly

chose not to tie environmental authority under the

emission allowance program to the Commission’s

and states’ ratemaking authority.

1064The conference report on the 1990 CZMA

amendments expressly states that the principal

objective of the 1990 revisions to the language of

section 307(c)(1) was to overturn a Supreme Court

decision holding that Outer Continental Shelf oil

and gas lease sales were not subject to CZMA

consistency determinations. H.R. Rep. No. 101–964,

101st Cong., 2d Sess. 2675 (1990).

1065 In using the phrase ‘‘federal activities’’

Congress did not use the term ‘‘federal action’’

which has clear and broad meaning under NEPA.

* * *.’’ 1061 However, even if we assume

that the Report language reflects

Congressional intent for the Energy

Policy Act in general, we note that, in

Title VII of the Energy Policy Act

concerning electricity, the only mention

of the environment was, as noted above,

in section 731 which specifically

provided that nothing in the Energy

Policy Act in any way interferes with

the authority of any state or local

government relating to, inter alia,

environmental protection. While we do

not quarrel with the proposition that

Congress in the Energy Policy Act

obviously had concerns with

environmental matters,1062 Congress did

not provide the Commission with any

authority to mandate environmental

mitigation.

We have undertaken an extensive

NEPA analysis to consider the

environmental effects of our Rule. We

cannot, however, take NEPA’s

requirement to consider environmental

effects as authority to require the

environmental mitigation proposed in

the comments. Congress has charged

other agencies, most notably the EPA,

with the responsibility of protecting the

environment and enforcing

environmental laws.1063 While we stand

ready to work in a complementary

fashion with these agencies, we believe

that any attempt by the Commission to

go beyond the economic regulation that

Congress has delegated to us would be

ultra vires.

To summarize: The Commission’s

jurisdiction under Parts II and III of the

FPA is limited to matters relating to

economic regulation. Neither the

relevant statutes nor the case law

supports the expansive and novel

reading of the Commission’s authority

advocated by the commenters that argue

that we have environmental mitigation

authority. The Commission is not

explicitly given such authority in either

the FPA or NEPA. Moreover, the FPA

and the case law clearly compel the

conclusion that we cannot impose

environmental conditions that do not

directly relate to the economic matters

over which we have jurisdiction. To do

so, in fact, would prevent the

Commission from effectively carrying

out its responsibilities under the FPA.

F. Coastal Zone Management Act Issue

By letter dated February 22, 1996, and

filed with the Commission on March 5,

1996, the Connecticut Department of

Environmental Protection (Connecticut)

notified the Commission that it has

determined that the Commission’s

proposed action in this rulemaking

proceeding is likely to adversely affect

Connecticut’s coastal resources.

Connecticut reasons that the Rule’s

promotion of competition ‘‘is likely to

increase energy production by mid-west

coal burning plants(,) which will in turn

increase the export of nitrogen and

sulphur oxides.’’ Connecticut states that

airborne nitrogen emissions are linked

to adverse environmental impacts in

Long Island Sound. It therefore asserts

that, pursuant to section 307(c)(1) of the

Coastal Zone Management Act (16

U.S.C. 1456(c)(1)) (CZMA), and the

federal regulations promulgated

thereunder (15 CFR part 930), the

Commission is required to provide it

with a determination of the Rules’

consistency with Connecticut’s federally

approved coastal management plan.

Section 307(c)(1)(A) of the CZMA

deals with the prevention or

amelioration of adverse physical

impacts on coastal zone resources

attributable to federal activities. The

legislative history indicates that in

enacting the CZMA Congress was

concerned with the adverse effects on

coastal lands and waters of such

activities as excavation, filling,

diversion of water or sediment, clearing,

and off-shore energy exploration and

dumping.1064

As discussed more fully above,

section 201 of the FPA declares that the

Commission shall not have jurisdiction

over facilities used for the generation of

electricity except as specifically

provided. Thus, the Commission has no

direct jurisdiction over fossil-fuel

plants. Its jurisdiction extends only to

the rates, terms, and conditions of

wholesale sales and transmission of

electric energy in interstate commerce

from those plants. While we are aware

that the legislative history of the CZMA

indicates a Congressional intent to cover

all federal activities, there is absolutely

no indication in the CZMA or its

legislative history that ‘‘federal

activities’’ should include all federal

regulatory decisions, including

Commission orders involving interstate

electric rates and service (or any other

jurisdictional matter under Part II of the

FPA).1065 We are not aware of any

judicial or agency interpretation that

would cast the net of the states under

the CZMA broadly enough to include

the generic federal regulatory action

undertaken in this Rule. Such action is

clearly remote from the kind of

activities such as leasing of land, and

dredging and filling that either affect, or

authorize specific activities that affect,

the environment in the coastal zone.

Connecticut’s attempt to pull FPA

Part II regulation into the CZMA federal

consistency provisions by dint of the

rulemaking’s alleged adverse impact on

air quality and consequent adverse

impact on water quality in the coastal

zone is untenable in view of the

existence of the Clean Air Act, a

complex, 700-page environmental law

that constitutes a comprehensive

scheme of regulation of the Nation’s air

quality, including the direct regulation

of emissions by utility power plants.

Indeed, the CZMA provides that the

requirements of the Clean Air Act, and

governmental directives pursuant to that

Act, shall be incorporated in, and shall

be the air pollution control

requirements of, all state coastal zone
21690 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

1066Section 307(f) of the CZMA, 16 U.S.C. 1456(f).

A state may develop more stringent standards, if

they can be enforced by the state (15 CFR

923.45(c)(2)), but more stringent state air quality

standards would not alter the characteristics of FPA

Part II regulation that put it beyond the federal

consistency requirements of the CZMA.

1067The Connecticut Department of

Environmental Protection is on the service list for

the rulemaking proceeding. The Commission issued

a NOPR in this proceeding on March 29, 1995 (60

FR 17662, April 7, 1995). On July 12, 1995, it issued

a notice of intent to prepare an EIS in this

proceeding (60 FR 36752, July 18, 1995). On

November 17, 1995, the Commission issued a Draft

EIS (60 FR 58304, Nov. 27, 1995).

1068A Record of Decision (ROD) will not be issued

as a separate document; instead this rule, including

the FEIS as incorporated into the rule by adoption,

will serve as the ROD for the rule.

1069 5 U.S.C. 601–612.

1070 60 FR 17662 at 17721 (April 7, 1995), FERC

Stats. & Regs. ¶ 32,514 at 33,151.

1071SBA Initial Comments at 1 and n.1.

1072SBA Initial Comments at 2 n.1. SBA ‘‘defines

a small electric utility as one that disposes of 4

million MWh of electricity in a given year.’’ Id. At

an average wholesale price of between $30 and $40

per MWh (Energy Information Administration,

Financial Statistics of Major Investor-Owned

Utilities, 1994, Table No. 1), utilities that dispose

of 4 million MWh per year would have annual sales

in the range of $120 million to $180 million.

1073 5 U.S.C. 601–612. SBA Initial Comments at 2

n.1.

1074The Stranded Cost Final Rule is applicable to

public utilities and to transmitting utilities (that are

not also public utilities).

1075Over 100 of these entities have already filed

some type of open access tariff.

1076The sources for this figure are FERC Form No.

1 and FERC Form No. 1–F data.

1077The RFA defines a ‘‘small entity’’ as ‘‘one

which is independently owned and operated and

which is not dominant in its field of operation.’’ See

5 U.S.C. 601(3) and 601(6) and 15 U.S.C. 632(a)(1)

(definition of ‘‘small business concern’’).

1078We note that five of these 19 public utilities

have already filed open access tariffs with the

Commission. While these five public utilities fall

within SBA’s definition of small electric utility,

since they have already filed open access tariffs, the

effect of the Open Access Final Rule on these

entities should not be significant. The remaining 14

small public utilities constitute eight percent of the

total number of public utilities that would have to

have on file open access tariffs. To the extent these

14 small public utilities consider the impact of the

Final Rule to be significant, these entities may

request a waiver of the open access filing

requirements under the waiver provisions of the

Open Access Final Rule.

1079 In Mid-Tex Electric Coop., Inc. v. FERC, 773

F.2d 327, 340–43 (D.C. Cir. 1985) (Mid-Tex), the

court accepted the Commission’s conclusion that,

since virtually all of the public utilities that it

regulates do not fall within the meaning of the term

‘‘small entities’’ as defined in the RFA, the

Commission did not need to prepare a regulatory

flexibility analysis in connection with its proposed

rule governing the allocation of costs for

construction work in progress (CWIP). The CWIP

rules applied to all public utilities. The Open

Access Final Rule applies to only those public

utilities that own, control or operate interstate

transmission facilities. These entities are a subset of

the group of public utilities found not to require

preparation of a regulatory flexibility analysis for

the CWIP rule.

management programs.1066 It therefore

defies logic to assert that, despite the

pervasive regulatory reach of the Clean

Air Act and the clear authority of EPA

to regulate NOX emissions under that

statute, the CZMA is a separate source

of authority for state jurisdiction over

air quality impacts to coastal zones.

While it is clear that Connecticut’s

invocation of the CZMA is incorrect, we

note that, under the Commerce

Department’s implementing regulations,

Connecticut has in any event waived its

right to request a consistency

determination for the Commission’s

rulemaking. Connecticut’s coastal

management program’s list of federal

agency activities likely to require a

consistency determination does not (for

good reason) describe rulemakings of

this kind, and the rule will not ‘‘result

in a significant change in air or water

quality within the management area’’

(the program’s catch-all category). In

addition, Connecticut did not notify the

Commission of its conclusion that the

Rule requires a consistency

determination until well after 45 days

from receipt of several notices of the

rulemaking proceeding.1067

Consequently, pursuant to 15 CFR

930.35(b), Connecticut has in any event

waived its right to request a consistency

determination for this rulemaking.

Conclusion

After reviewing the record in this

proceeding, including the FEIS, we find

for the reasons discussed above that

proceeding with this rule is the best

alternative. No other alternative will

accomplish the Commission’s purposes.

The rule is expected to slightly

increase or slightly decrease total future

NOX emissions, depending on whether

competitive conditions in the electric

industry favor the utilization of natural

gas or coal as a fuel for the generation

of electricity. Other impacts of the rule

have also been determined to be slight.

Therefore, it is unnecessary to adopt

and implement a plan of mitigation.

A wide range of mitigation measures

have nonetheless been fully evaluated

as discussed in Chapter 7 of the FEIS.

This discussion concludes that the

Commission does not have authority

under the FPA and NEPA, singly or

conjointly, to impose mitigation, and

that existing and proposed mitigation

strategies and efforts are the best way to

deal with potential environmental

effects that might result from

implementing the rule. Such effects, if

they indeed materialize, are not

expected to occur for many years. In the

meantime, action by entities such as

EPA and OTAG are expected to address

the underlying air emission problems

facing parts of the Nation. Interim

mitigation efforts to be undertaken by

the Commission would address only a

very small part of the problem, would

require the exercise of technical

expertise and authority that the

Commission does not possess, and

could well interfere with efforts by EPA

and others to address this situation.

For these reasons, we support the

analysis in the staff’s FEIS and adopt the

conclusions in that document.1068

VI. Regulatory Flexibility Act

Certification

The Regulatory Flexibility Act

(RFA) 1069 requires rulemakings to

contain either a description and analysis

of the effect that the proposed rule will

have on small entities or a certification

that the rule will not have a significant

economic impact on a substantial

number of small entities. In the Open

Access and Stranded Cost NOPRs, the

Commission concluded that the

proposed rules would not have a

significant economic impact upon a

substantial number of small entities.1070

SBA questions this conclusion.1071 It

states that, ‘‘[a]ccording to data from the

Department of Energy, the vast majority

of utilities are small.’’ 1072 SBA requests

that if, upon reconsideration, the

Commission determines that the final

rule in the Open Access NOPR

proceeding would have a significant

economic impact on a substantial

number of small entities, the

Commission perform a Regulatory

Flexibility Analysis under the

requirements of the RFA.1073

A. Docket No. RM95–8–000 (Open

Access Final Rule)

1. Public Utilities

The Open Access Final Rule is

applicable to public utilities that own,

control or operate interstate

transmission facilities, not to electric

utilities per se.1074 The total number of

public utilities that, absent waiver,

would have to have open access tariffs

on file is 166.1075 Of these, only 50

public utilities dispose of 4 million

MWh or less per year.1076 Eliminating

those utilities that are affiliates of other

utilities whose sales exceed 4 million

MWh per year, or are not independently

owned,1077 the total number of public

utilities affected by the Open Access

Final Rule that qualify under the SBA’s

definition of small electric utility is 19,

or 11 percent of the total number of

public utilities that would have to have

on file open access tariffs.1078 We do not

consider this a substantial number,1079

and, in any event, these entities may

seek waiver of the Open Access Final
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21691

1080Those public utilities that already have open

access tariffs on file are not even required to

propose rates. They may elect to continue service

under the Open Access Final Rule’s non-rate terms

and conditions at their existing rates.

1081 In the Public Reporting Burden section

(Section II), the Commission reaffirms the average

reporting burden of 300 hours per response, which

was proposed and unchallenged in the NOPR. If a

cost of $200 per hour is used, the cost of making

the required filing would be $60,000. On average,

this is no more than one half of one percent of total

annual sales for small electric utilities. 1082 5 CFR 1320.11. 1083 5 U.S.C. 804(2).

Rule’s requirements under the Rule’s

waiver provisions.

Moreover, in the Open Access Final

Rule, the Commission is specifying the

non-rate terms and conditions of the

tariffs that the public utilities must have

on file. The public utilities need only

develop and file a rate.1080 When one

considers that the disposition of 4

million MWhs a year translates into

sales in the range of $120 million to

$180 million per year, the cost to

prepare and file proposed rates,1081

which these utilities must regularly do

anyway in the ordinary course of

business, is not a significant economic

impact.

2. Non-Public Utilities

The Open Access Final Rule will not

impose any burden on non-public

utilities, since they need not themselves

file open access tariffs. Triggering the

reciprocity provision in the Open

Access Final Rule is optional; it is

merely a condition of receiving a

benefit, i.e., open access transmission

service from a public utility. If nonpublic utilities elect not to take

advantage of open access services

because they do not want to meet the

tariff reciprocity provision, they can still

seek voluntary, bilateral transmission

services from public utilities. Also,

under the waiver provisions in the Open

Access Final Rule, small non-public

utilities may seek waiver from the

reciprocity provision.

B. Docket No. RM94–7–001 (Stranded

Cost Final Rule)

1. Public Utilities

As with the Open Access Final Rule,

there are not a substantial number of

public utilities that qualify under the

SBA’s definition of small electric utility

that are subject to the Stranded Cost

Final Rule. The Stranded Cost Rule

applies only to public utilities that seek

stranded cost recovery in connection

with a limited set of wholesale

requirements contracts (those executed

on or before July 11, 1994 that do not

contain an exit fee or other explicit

stranded cost provision). To the extent

that public utilities seek stranded cost

recovery, they will do so in a rate filing,

where stranded cost recovery is likely to

be one of many items considered.

Accordingly, the Stranded Cost Final

Rule will not pose a significant

economic impact on a substantial

number of public utility small entities.

2. Non-Public Utilities

With regard to non-public utilities,

the stranded cost issue would only arise

in a proceeding under sections 211 and

212 of the FPA when, in directing

transmission, the Commission addresses

the stranded cost issue in determining a

just and reasonable rate. As with public

utilities, stranded costs will be just one

more item to be considered in

establishing just and reasonable rates for

transmission. As a result, the Stranded

Cost Final Rule will not impose a

significant economic impact on a

substantial number of non-public utility

small entities.

C. Conclusion

Accordingly, the Commission certifies

that these final rules will not have a

significant economic impact on a

substantial number of small entities.

VII. Information Collection Statement

The Office of Management and

Budget’s (OMB) regulations 1082 require

that OMB approve certain information

and recordkeeping requirements

(collections of information) imposed by

an agency. Upon approval of a

collection of information, OMB shall

assign an OMB control number and an

expiration date. Respondents subject to

the filing requirements of this Rule shall

not be penalized for failing to respond

to this collection of information unless

the collection of information displays a

valid OMB control number.

There are now approximately 328

public utilities, including marketers and

wholesale generation entities. The

Commission estimates that 166 of these

utilities own, control or operate

facilities used for the transmission of

electric energy in interstate commerce

and would be subject to the filing

requirements of this Rule.

Title: FERC–516, Electric Rate

Schedule Filings.

Action: Final Rule.

OMB Control No: 1902–0096.

Respondents: Public Utilities that

own, control or operate facilities used

for the transmission of electric energy in

interstate commerce.

Frequency of Responses: On occasion.

Necessity of information: The Final

Rule requires public utilities that own,

control or operate facilities used for the

transmission of electric energy in

interstate commerce to have on file with

the Commission non-discriminatory

open access transmission tariffs that

contain minimum terms and conditions

of service and permits public utilities to

make filings to seek recovery of

legitimate, prudent and verifiable

stranded costs associated with

providing open access and FPA section

211 transmission services. The

Commission has a mandate under

sections 205 and 206 of the FPA to

ensure, with respect to any transmission

in interstate commerce or any sale of

electric energy for resale in interstate

commerce by a public utility, that no

entity is subject to undue

discrimination. The Commission will

use the data collected in this collection

of information to carry out its

responsibilities under Part II of the FPA.

The Commission’s Office of Electric

Power Regulation will use the data to

review electric rate and tariff filings.

The Commission is submitting

notification of this Final Rule to OMB.

Interested persons may obtain

information on the reporting

requirements by contacting the Federal

Energy Regulatory Commission, 888

First Street, NE., Washington, DC. 20426

[Attention: Michael Miller, Information

Services Division, (202) 208–1415], and

to the Office of Management and Budget

(Attention: Desk Officer for the Federal

Energy Regulatory Commission, (202)

395–3087).

VIII. Effective Date

This Rule will take effect on July 9,

1996. The Commission has determined,

with the concurrence of the

Administrator of the Office of

Information and Regulatory Affairs of

the Office of Management and Budget,

that this rule is a ‘‘major rule’’ within

the meaning of section 351 of the Small

Business Regulatory Enforcement Act of

1996.1083 The rule will be submitted to

both Houses of Congress and the

Comptroller General prior to its

publication in the Federal Register.

List of Subjects

18 CFR Part 35

Electric power rates, Electric utilities,

Reporting and recordkeeping

requirements.

18 CFR Part 385

Administrative practice and

procedure, Electric power, Penalties,

Pipelines, Reporting and recordkeeping

requirements.

By the Commission. Commissioner

Hoecker concurred in part and dissented in
21692 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

part with a separate statement attached.

Commissioner Massey dissented in part with

a separate statement attached.

Lois D. Cashell,

Secretary.

In consideration of the foregoing, the

Commission amends parts 35 and 385,

chapter I, title 18 of the Code of Federal

Regulations, as set forth below.

PART 35—FILING OF RATE

SCHEDULES

1. The authority citation for part 35

continues to read as follows:

Authority: 16 U.S.C. 791a-825r, 2601–

2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352.

2. Part 35 is amended by revising

§ 35.15, by redesignating § 35.28 as

§ 35.29, and by adding new §§ 35.26,

35.27, and 35.28 to read as follows:

§ 35.15 Notices of cancellation or

termination.

(a) General rule. When a rate schedule

or part thereof required to be on file

with the Commission is proposed to be

cancelled or is to terminate by its own

terms and no new rate schedule or part

thereof is to be filed in its place, each

party required to file the schedule shall

notify the Commission of the proposed

cancellation or termination on the form

indicated in § 131.53 of this chapter at

least sixty days but not more than one

hundred-twenty days prior to the date

such cancellation or termination is

proposed to take effect. A copy of such

notice to the Commission shall be duly

posted. With such notice each filing

party shall submit a statement giving the

reasons for the proposed cancellation or

termination, and a list of the affected

purchasers to whom the notice has been

mailed. For good cause shown, the

Commission may by order provide that

the notice of cancellation or termination

shall be effective as of a date prior to the

date of filing or prior to the date the

filing would become effective in

accordance with these rules.

(b) Applicability. (1) The provisions of

paragraph (a) of this section shall apply

to all contracts for unbundled

transmission service and all power sale

contracts:

(i) Executed prior to July 9, 1996; or

(ii) If unexecuted, filed with the

Commission prior to July 9, 1996.

(2) Any power sales contract executed

on or after July 9, 1996 that is to

terminate by its own terms shall not be

subject to the provisions of paragraph

(a) of this section.

(c) Notice. Any public utility

providing jurisdictional services under a

power sales contract that is not subject

to the provisions of paragraph (a) of this

section shall notify the Commission of

the date of the termination of such

contract within 30 days after such

termination takes place.

§ 35.26 Recovery of stranded costs by

public utilities and transmitting utilities.

(a) Purpose. This section establishes

the standards that a public utility or

transmitting utility must satisfy in order

to recover stranded costs.

(b) Definitions.

(1) Wholesale stranded cost means

any legitimate, prudent and verifiable

cost incurred by a public utility or a

transmitting utility to provide service to:

(i) A wholesale requirements

customer that subsequently becomes, in

whole or in part, an unbundled

wholesale transmission services

customer of such public utility or

transmitting utility; or

(ii) A retail customer, or a newly

created wholesale power sales customer,

that subsequently becomes, in whole or

in part, an unbundled wholesale

transmission services customer of such

public utility or transmitting utility.

(2) Wholesale requirements customer

means a customer for whom a public

utility or transmitting utility provides

by contract any portion of its bundled

wholesale power requirements.

(3) Wholesale transmission services

has the same meaning as provided in

section 3(24) of the Federal Power Act

(FPA): The transmission of electric

energy sold, or to be sold, at wholesale

in interstate commerce.

(4) Wholesale requirements contract

means a contract under which a public

utility or transmitting utility provides

any portion of a customer’s bundled

wholesale power requirements.

(5) Retail stranded cost means any

legitimate, prudent and verifiable cost

incurred by a public utility or

transmitting utility to provide service to

a retail customer that subsequently

becomes, in whole or in part, an

unbundled retail transmission services

customer of that public utility or

transmitting utility.

(6) Retail transmission services means

the transmission of electric energy sold,

or to be sold, in interstate commerce

directly to a retail customer.

(7) New wholesale requirements

contract means any wholesale

requirements contract executed after

July 11, 1994, or extended or

renegotiated to be effective after July 11,

1994.

(8) Existing wholesale requirements

contract means any wholesale

requirements contract executed on or

before July 11, 1994.

(c) Recovery of wholesale stranded

costs.

(1) General requirement. A public

utility or transmitting utility will be

allowed to seek recovery of wholesale

stranded costs only as follows:

(i) No public utility or transmitting

utility may seek recovery of wholesale

stranded costs if such recovery is

explicitly prohibited by a contract or

settlement agreement, or by any power

sales or transmission rate schedule or

tariff.

(ii) No public utility or transmitting

utility may seek recovery of stranded

costs associated with a new wholesale

requirements contract if such contract

does not contain an exit fee or other

explicit stranded cost provision.

(iii) If wholesale stranded costs are

associated with a new wholesale

requirements contract containing an exit

fee or other explicit stranded cost

provision, and the seller under the

contract is a public utility, the public

utility may seek recovery of such costs,

in accordance with the contract, through

rates for electric energy under sections

205–206 of the FPA. The public utility

may not seek recovery of such costs

through any transmission rate for FPA

section 205 or 211 transmission

services.

(iv) If wholesale stranded costs are

associated with a new wholesale

requirements contract, and the seller

under the contract is a transmitting

utility but not also a public utility, the

transmitting utility may not seek an

order from the Commission allowing

recovery of such costs.

(v) If wholesale stranded costs are

associated with an existing wholesale

requirements contract, if the seller

under such contract is a public utility,

and if the contract does not contain an

exit fee or other explicit stranded cost

provision, the public utility may seek

recovery of stranded costs only as

follows:

(A) If either party to the contract seeks

a stranded cost amendment pursuant to

a section 205 or section 206 filing under

the FPA made prior to the expiration of

the contract, and the Commission

accepts or approves an amendment

permitting recovery of stranded costs,

the public utility may seek recovery of

such costs through FPA section 205–206

rates for electric energy.

(B) If the contract is not amended to

permit recovery of stranded costs as

described in paragraph (c)(1)(v)(A) of

this section, the public utility may file

a proposal, prior to the expiration of the

contract, to recover stranded costs

through FPA section 205–206 or section

211–212 rates for wholesale

transmission services to the customer.

(vi) If wholesale stranded costs are

associated with an existing wholesale

requirements contract, if the seller

under such contract is a transmitting
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21693

utility but not also a public utility, and

if the contract does not contain an exit

fee or other explicit stranded cost

provision, the transmitting utility may

seek recovery of stranded costs through

FPA section 211–212 transmission rates.

(vii) If a retail customer becomes a

legitimate wholesale transmission

customer of a public utility or

transmitting utility, e.g., through

municipalization, and costs are stranded

as a result of the retail-turned-wholesale

customer’s access to wholesale

transmission, the utility may seek

recovery of such costs through FPA

section 205–206 or section 211–212

rates for wholesale transmission

services to that customer.

(2) Evidentiary demonstration for

wholesale stranded cost recovery. A

public utility or transmitting utility

seeking to recover wholesale stranded

costs in accordance with paragraphs

(c)(1)(v)–(vii) of this section must

demonstrate that:

(i) It incurred stranded costs on behalf

of its wholesale requirements customer

or retail customer based on a reasonable

expectation that the utility would

continue to serve the customer;

(ii) The stranded costs are not more

than the customer would have

contributed to the utility had the

customer remained a wholesale

requirements customer of the utility, or,

in the case of a retail-turned-wholesale

customer, had the customer remained a

retail customer of utility; and

(iii) The stranded costs are derived

using the following formula: Stranded

Cost Obligation = (Revenue Stream

Estimate¥Competitive Market Value

Estimate)×Length of Obligation

(reasonable expectation period).

(3) Rebuttable presumption. If a

public utility or transmitting utility

seeks recovery of wholesale stranded

costs associated with an existing

wholesale requirements contract, as

permitted in paragraph (c)(1) of this

section, and the existing wholesale

requirements contract contains a notice

provision, there will be a rebuttable

presumption that the utility had no

reasonable expectation of continuing to

serve the customer beyond the term of

the notice provision.

(4) Procedure for customer to obtain

stranded cost estimate. A customer

under an existing wholesale

requirements contract with a public

utility seller may obtain from the seller

an estimate of the customer’s stranded

cost obligation if it were to leave the

public utility’s generation supply

system by filing with the public utility

a request for an estimate at any time

prior to the termination date specified

in its contract.

(i) The public utility must provide a

response within 30 days of receiving the

request. The response must include:

(A) An estimate of the customer’s

stranded cost obligation based on the

formula in paragraph (c)(2)(iii) of this

section;

(B) Supporting detail indicating how

each element in the formula was

derived;

(C) A detailed rationale justifying the

basis for the utility’s reasonable

expectation of continuing to serve the

customer beyond the termination date

in the contract;

(D) An estimate of the amount of

released capacity and associated energy

that would result from the customer’s

departure; and

(E) The utility’s proposal for any

contract amendment needed to

implement the customer’s payment of

stranded costs.

(ii) If the customer disagrees with the

utility’s response, it must respond to the

utility within 30 days explaining why it

disagrees. If the parties cannot work out

a mutually agreeable resolution, they

may exercise their rights to Commission

resolution under the FPA.

(5) A customer must be given the

option to market or broker a portion or

all of the capacity and energy associated

with any stranded costs claimed by the

public utility.

(i) To exercise the option, the

customer must so notify the utility in

writing no later than 30 days after the

public utility files its estimate of

stranded costs for the customer with the

Commission.

(A) Before marketing or brokering can

begin, the utility and customer must

execute an agreement identifying, at a

minimum, the amount and the price of

capacity and associated energy the

customer is entitled to schedule, and the

duration of the customer’s marketing or

brokering of such capacity and energy.

(ii) If agreement over marketing or

brokering cannot be reached, and the

parties seek Commission resolution of

disputed issues, upon issuance of a

Commission order resolving the

disputed issues, the customer may

reevaluate its decision in paragraph

(c)(5)(i) of this section to exercise the

marketing or brokering option. The

customer must notify the utility in

writing within 30 days of issuance of

the Commission’s order resolving the

disputed issues whether the customer

will market or broker a portion or all of

the capacity and energy associated with

stranded costs allowed by the

Commission.

(iii) If a customer undertakes the

brokering option, and the customer’s

brokering efforts fail to produce a buyer

within 60 days of the date of the

brokering agreement entered into

between the customer and the utility,

the customer shall relinquish all rights

to broker the released capacity and

associated energy and will pay stranded

costs as determined by the formula in

paragraph (c)(2)(iii) of this section.

(d) Recovery of retail stranded costs.

(1) General requirement. A public

utility may seek to recover retail

stranded costs through rates for retail

transmission services only if the state

regulatory authority does not have

authority under state law to address

stranded costs at the time the retail

wheeling is required.

(2) Evidentiary demonstration

necessary for retail stranded cost

recovery. A public utility seeking to

recover retail stranded costs in

accordance with paragraph (d)(1) of this

section must demonstrate that:

(i) It incurred stranded costs on behalf

of a retail customer that obtains retail

wheeling based on a reasonable

expectation that the utility would

continue to serve the customer; and

(ii) The stranded costs are not more

than the customer would have

contributed to the utility had the

customer remained a retail customer of

the utility.

§ 35.27 Power sales at market-based rates.

(a) Notwithstanding any other

requirements, any public utility seeking

authorization to engage in sales for

resale of electric energy at market-based

rates shall not be required to

demonstrate any lack of market power

in generation with respect to sales from

capacity for which construction has

commenced on or after July 9, 1996.

(b) Nothing in this part

(1) Shall be construed as preempting

or affecting any jurisdiction a state

commission or other state authority may

have under applicable state and federal

law, or

(2) Limits the authority of a state

commission in accordance with state

and federal law to establish

(i) Competitive procedures for the

acquisition of electric energy, including

demand-side management, purchased at

wholesale, or

(ii) Non-discriminatory fees for the

distribution of such electric energy to

retail consumers for purposes

established in accordance with state

law.

§ 35.28 Non-discriminatory open access

transmission tariff.

(a) Applicability. This section applies

to any public utility that owns, controls

or operates facilities used for the

transmission of electric energy in
21694 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

interstate commerce and to any nonpublic utility that seeks voluntary

compliance with jurisdictional

transmission tariff reciprocity

conditions.

(b) Definitions.

(1) Requirements service agreement

means a contract or rate schedule under

which a public utility provides any

portion of a customer’s bundled

wholesale power requirements.

(2) Economy energy coordination

agreement means a contract, or service

schedule thereunder, that provides for

trading of electric energy on an ‘‘if, as

and when available’’ basis, but does not

require either the seller or the buyer to

engage in a particular transaction.

(3) Non-economy energy coordination

agreement means any non-requirements

service agreement, except an economy

energy coordination agreement as

defined in paragraph (b)(2) of this

section.

(c) Non-discriminatory open access

transmission tariffs.

(1) Every public utility that owns,

controls or operates facilities used for

the transmission of electric energy in

interstate commerce must have on file

with the Commission a tariff of general

applicability for transmission services,

including ancillary services, over such

facilities. Such tariff must be the open

access pro forma tariff contained in

Order No. 888, FERC Stats. & Regs.

¶ 31,036 (Final Rule on Open Access

and Stranded Costs) or such other open

access tariff as may be approved by the

Commission consistent with Order No.

888, FERC Stats. & Regs. ¶ 31,036.

(i) Subject to the exceptions in

paragraphs (c)(1)(ii), (c)(1)(iii), and

(c)(1)(iv) of this section, the pro forma

tariff contained in Order No. 888, FERC

Stats. & Regs. ¶ 31,036, and

accompanying rates, must be filed no

later than 60 days prior to the date on

which a public utility would engage in

a sale of electric energy at wholesale in

interstate commerce or in the

transmission of electric energy in

interstate commerce.

(ii) If a public utility owns, controls

or operates facilities used for the

transmission of electric energy in

interstate commerce as of July 9, 1996,

it must file the pro forma tariff

contained in Order No. 888, FERC Stats.

& Regs. ¶ 31,036, pursuant to section

206 of the FPA and accompanying rates

pursuant to section 205 of the FPA, no

later than July 9, 1996. However, if a

public utility has already filed, or has

on file, an open access tariff and

accompanying rates as of April 24, 1996,

it may, but is not required to, file new

rates with its section 206 pro forma

tariff filing.

(iii) If a public utility owns, controls

or operates transmission facilities used

for the transmission of electric energy in

interstate commerce as of July 9, 1996,

such facilities are jointly owned with a

non-public utility, and the joint

ownership contract prohibits

transmission service over the facilities

to third parties, the public utility with

respect to access over the public utility’s

share of the jointly owned facilities

must file no later than December 31,

1996 the pro forma tariff contained in

Order No. 888, FERC Stats. & Regs.

¶ 31,036, pursuant to section 206 of the

FPA and accompanying rates pursuant

to section 205 of the FPA.

(iv) If a public utility obtains a waiver

of the tariff requirement pursuant to

paragraph (d) of this section, it does not

need to file the pro forma tariff required

by this section.

(v) Any public utility that seeks a

deviation from the pro forma tariff

contained in Order No. 888, FERC Stats.

& Regs. ¶ 31,036, must demonstrate that

the deviation is consistent with the

principles of Order No. 888, FERC Stats.

& Regs. ¶ 31,036.

(2) Every public utility that owns,

controls or operates facilities used for

the transmission of electric energy in

interstate commerce, and that uses those

facilities to engage in wholesale sales

and/or purchases of electric energy, or

unbundled retail sales of electric energy,

must take transmission service for such

sales and/or purchases under the open

access tariff filed pursuant to this

section.

(i) Subject to the exceptions in

paragraphs (c)(2)(ii) and (c)(3)(iv) of this

section, this requirement is effective on

the date that such public utility engages

in a wholesale sale or purchase of

electric energy or any unbundled retail

sale of electric energy, but no earlier

than July 9, 1996.

(ii) For sales of electric energy

pursuant to a requirements service

agreement executed on or before July 9,

1996, this requirement will not apply

unless separately ordered by the

Commission. For sales of electric energy

pursuant to a bilateral economy energy

coordination agreement executed on or

before July 9, 1996, this requirement is

effective on December 31, 1996. For

sales of electric energy pursuant to a

bilateral non-economy energy

coordination agreement executed on or

before July 9, 1996, this requirement

will not apply unless separately ordered

by the Commission.

(3) Every public utility that owns,

controls or operates facilities used for

the transmission of electric energy in

interstate commerce, and that is a

member of a power pool, public utility

holding company, or other multi-lateral

trading arrangement or agreement that

contains transmission rates, terms or

conditions, must file a joint pool-wide

or system-wide open access

transmission pro forma tariff.

(i) For any power pool, public utility

holding company or other multi-lateral

arrangement or agreement that contains

transmission rates, terms or conditions

and that is executed after July 9, 1996,

this requirement is effective on the date

that transactions begin under the

arrangement or agreement.

(ii) For any public utility holding

company arrangement or agreement that

contains transmission rates, terms or

conditions and that is executed on or

before July 9, 1996, this requirement is

effective July 9, 1996, except for the

Central and South West System, which

must comply no later than December 31,

1996.

(iii) For any power pool or multilateral arrangement or agreement other

than a public utility holding company

arrangement or agreement, that contains

transmission rates, terms or conditions

and that is executed prior to July 9,

1996, this requirement is effective on

December 31, 1996.

(iv) A public utility member of a

power pool, public utility holding

company or other multi-lateral

arrangement or agreement that contains

transmission rates, terms or conditions

and that is executed on or before July 9,

1996 must begin to take service under

a joint pool-wide or system-wide pro

forma tariff for wholesale trades among

the pool or system members no later

than December 31, 1996.

(d) Waivers. A public utility subject to

the requirements of this section and

Order No. 889, FERC Stats. & Regs.

¶ 31,037 (Final Rule on Open Access

Same-Time Information System and

Standards of Conduct) may file a request

for waiver of all or part of the

requirements of this section, or Part 37

(Open Access Same-Time Information

System and Standards of Conduct for

Public Utilities), for good cause shown.

An application for waiver must be filed

either:

(i) No later than July 9, 1996 or

(ii) No later than 60 days prior to the

time the public utility would otherwise

have to comply with the requirement.

(e) Non-public utility procedures for

tariff reciprocity compliance.

(1) A non-public utility may submit a

transmission tariff and a request for

declaratory order that its voluntary

transmission tariff meets the

requirements of Order No. 888 (Final

Rule on Open Access and Stranded

Costs).
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21695

(i) Any submittal and request for

declaratory order submitted by a nonpublic utility will be provided an NJ

(non-jurisdictional) docket designation.

(ii) If the submittal is found to be an

acceptable transmission tariff, an

applicant in a Federal Power Act (FPA)

section 211 case against the non-public

utility shall have the burden of proof to

show why service under the open access

tariff is not sufficient and why a section

211 order should be granted.

(2) A non-public utility may file a

request for waiver of all or part of the

reciprocity conditions contained in a

public utility open access tariff, for good

cause shown. An application for waiver

may be filed at any time.

PART 385—RULES OF PRACTICE AND

PROCEDURE

1. The authority citation for part 385

continues to read as follows:

Authority: 5 U.S.C. 551–557; 15 U.S.C.

717–717z, 3301–3432; 16 U.S.C. 791a–825r,

2601–2645; 31 U.S.C. 9701; 42 U.S.C. 7101–

7352; 49 U.S.C. 60502; 49 App. U.S.C. 1–85.

2. Part 385 is amended by adding

paragraph (b)(5) to § 385.2011 to read as

follows:

§ 385.2011 Procedures for filing on

electronic media (Rule 2011).

* * * * *

(b) * * *

(5) Non-discriminatory open access

transmission tariffs filed pursuant to

§ 35.28 of this chapter.

* * * * *

Note: Appendices A through H and

statements of Commissioners Hoecker and

Massey will not be published in the Code of

Federal Regulations.

LIST OF SECTION 211 APPLICATIONS

No. Docket No. Applicant Transmitter Commission action

1 TX93–1–000 Tex-La Electric Cooperative of Texas,

Inc.

Texas Utilities Electric Company ......... Denied, 64 FERC ¶ 61,162.

2 TX93–2–000 City of Bedford, Virginia, et al .............. American Electric Power Company,

Inc.

Granted. Final order, 68 FERC

¶ 61,003. Reh’g denied, 73 FERC

¶ 61,322.

3 TX93–3–000 Wisconsin Electric Power Company .... Upper Peninsula Power Company ....... Withdrawn 9/10/93.

4 TX93–4–000 Florida Municipal Power Agency ......... Florida Power & Light Company .......... Granted. Final order, 67 FERC

¶ 61,167. Order on reh’g, 74 FERC

¶ 61,006.

5 TX94–1–000 Minnesota Municipal Power Agency .... Northern States Power Company ........ Granted. Proposed order, 66 FERC

¶ 61,114. Reh’g denied, 66 FERC

¶ 61,323 Settlement accepted by letter order, 68 FERC ¶ 61,031.

6 TX94–2–000 El Paso Electric Company, et al .......... Southwestern Public Service Company Proposed order, 68 FERC ¶ 61,182;

order on reh’g, 68 FERC ¶ 61,399;

order dismiss’g proceeding, 72

FERC ¶ 61,292.

7 TX94–3–000 Minnesota Municipal Power Agency .... Southern Minnesota Municipal Power

Agency.

Granted. Proposed order, 66 FERC

¶ 61,223; reh’g denied, 67 FERC

¶ 61,075; Final order, 68 FERC

¶ 61,060.

8 TX94–4–000 Tex-La Electric Cooperative of Texas,

Inc.

Texas Utilities Electric Company ......... Granted. Proposed order, 67 FERC

¶ 61,019; Final order, 69 FERC

¶ 61,269.

9 TX94–5–000 Old Dominion Electric Cooperative, Inc Delmarva Power & Light Company ..... Granted. Proposed order, 68 FERC

¶ 61,169. Settl’d, 69 FERC ¶ 61,436,

70 FERC ¶ 61,082.

10 TX94–6–000 Reading Municipal Light Department ... 16 New England Transmitting Utilities Terminated July 10, 1995 by OEPR

Letter Order, following notice of

withdrawal filed May 8, 1995.

11 TX94–7–000 AES Power, Inc .................................... Tennessee Valley Authority ................. Granted. Final Order issued Feb. 29,

1996, 74 FERC ¶ 61,220, reh’g

pending.

12 TX94–8–000 Duquesne Light Company ................... PJM Companies ................................... Granted. Proposed order issued 5/16/

95, 71 FERC ¶ 61,155.

13 TX94–9–000 Borough of Zelienople, Pennsylvania Pennsylvania Power Company ............ Granted. Proposed order issued 1/25/

95, 70 FERC ¶ 61,073.

14 TX94–10–

000

Duquesne Light Company ................... Allegheny Power System ..................... Granted. Proposed order issued 5/16/

95, 71 FERC ¶ 61,156.

15 TX95–1–000 Enron Power Marketing, Inc ................ Consolidated Edison Co. of New York Pending. Comments due 11/3/94.

16 TX95–2–000 Wisconsin Public Power Inc. SYSTEM WEPCO, WP&L, WPSC ...................... Pending. Comments due 11/16/94.

17 TX95–3–000 Municipal Energy Agency of Nebraska Nebraska Public Power District and

Tri-State Generation and Transmission Association, Inc.

w/drawn 11–16–95

18 TX95–4–000 American Municipal Power-Ohio, Inc ... Ohio Edison Company ......................... Granted. Proposed Order issued Feb.

1, 1996 74 FERC ¶ 61,086.

19 TX95–5–000 United States Department of Energy—

Southeastern Power Administration.

Southern Company System ................. Pending.

20 TX95–6–000 Cleveland Public Power ....................... Centerior Energy Corporation .............. Rejected Without Prejudice 72 FERC

¶ 61,189.

21 TX95–7–000 Cleveland Public Power ....................... Cleveland Electric Illuminating Company and Toledo Edison Company.Pending.

22 TX96–1–000 Citizens Utilities Company ................... Swanton Village, Vermont .................... Pending.
21696 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

LIST OF SECTION 211 APPLICATIONS—Continued

No. Docket No. Applicant Transmitter Commission action

23 TX96–2–000 City of College Station, Texas ............. City of Bryan, Texas and Texas Municipal Power Agency.Pending.

24 TX96–3–000 Citizens Utilities Company ................... Swanton Village, Vermont .................... Pending.

25 TX96–4–000 Suffolk County Electrical Agency ......... Long Island Lighting Company ............ Pending.

26 TX96–5–000 United States Department of Energy—

Western Area Power Administration.

Public Service Company of New Mexico.Pending.

27 TX96–6–000 Montana Power Company ................... Basin Electric Cooperative ................... Pending.

28 TX96–7–000 City of Palm Springs, California ........... Southern California Edison Company Pending.

Appendix B—List of Commenters

Abbreviation Commenter

1. ABATE ........................................................... Association of Businesses Advocating Tariff Equity.

2. AEC & SMEPA .............................................. Alabama Electric Cooperative, Inc. and South Mississippi Electric Power Association.

3. AEP ................................................................ American Electric Power System.

4. AGA ................................................................ American Gas Association.

5. Air Liquide ...................................................... Air Liquide America Corporation.

6. AL Com .......................................................... Alabama Public Service Commission.

7. ALCOA ........................................................... Aluminum Company of America.

8. Allegheny ....................................................... Allegheny Power Service Corporation.

9. Alma ............................................................... City of Alma, Michigan.

10. Aluminum ..................................................... Aluminum Association.

11. American Forest & Paper ............................ American Forest & Paper Association.

12. American Iron & Steel .................................. American Iron & Steel Institute American Forest & Paper Association, American Public Power

Association, Chemical Manufacturers Association, Citizen Action, Council of Industrial Boiler

Owners, Electricity Consumers Resource Council, Environmental Action Foundation, City of

Las Cruces, New Mexico, City of Westbrook, Maine, Sovereign California Cities Joint Powers

Committee, Toward Utility Rate Normalization.

13. American National Power ............................ American National Power, Inc.

14. American Wind ............................................. American Wind Energy Association.

15. AMP-Ohio ..................................................... American Municipal Power-Ohio, Inc. and Indiana Municipal Power Agency.

16. Anaheim ....................................................... Cities of Anaheim, Azusa, Banning, Colton and Riverside, California.

17. Anchorage .................................................... Anchorage Municipal Light and Power.

18. Anoka EC ..................................................... Anoka Electric Cooperative.

19. APPA ............................................................ American Public Power Association.

20. APS Customers ........................................... APS Wholesale Customer Group (Aquila Irrigation District, Buckeye Water Conservation District, Electrical District No. 3 of Pinal County, Electrical District No. 6 of Pinal County, Electrical District No. 7 of Maricopa County, Electrical District No. 8 of Maricopa County,

Harquahala Valley Power District, Maricopa County Municipal Water Conservation District

No. 1, McMullan Valley Water Conservation District, Roosevelt Irrigation District and

Tonopah Irrigation District).

21. Arcadia ......................................................... Arcadia Resources, Inc.

22. Arizona ......................................................... Arizona Public Service Company.

23. Arizona EC ................................................... Arizona Electric Power Cooperative.

24. Ark Elec ........................................................ Arkansas Electric Cooperative Corporation.

25. Arkansas Cities ............................................ Arkansas Cities and Farmers Electric Cooperative.

26. Associated EC ............................................. Associated Electric Cooperative, Inc.

27. Associated Power ........................................ Associated Power Services, Inc.

28. Atlantic City .................................................. Atlantic City Electric Company.

29. AZ Com ........................................................ Arizona Corporation Commission.

30. Baker EC ...................................................... Baker Electric Cooperative, Inc.

31. Baltimore Transp Bureau ............................. Transportation Bureau of Baltimore, Inc.

32. Basin EC ...................................................... Basin Electric Power Cooperative.

33. BG&E ........................................................... Baltimore Gas and Electric Company.

34. Big Horn REC .............................................. Big Horn Rural Electric Company.

35. Big Rivers EC .............................................. Big Rivers Electric Cooperative.

36. Black Hills EC .............................................. Black Hills Electric Cooperative.

37. Black Mayors ............................................... National Conference of Black Mayors.

38. Blue Ridge ................................................... Blue Ridge Power Agency, Northeast Texas Electric Cooperative, Inc., Sam Rayburn G&T

Electric Cooperative, Inc., and Tex-La Electric Cooperative of Texas, Inc.

39. Bon Homme Yankton EC ............................ Bon Homme Yankton Electric Association, Inc.

40. Boston Edison .............................................. Boston Edison Company.

41. Boulder ......................................................... City of Boulder, Colorado.

42. BPA .............................................................. Bonneville Power Administration.

43. Brazos .......................................................... Brazos Electric Power Cooperative, Inc.

44. Brownsville ................................................... Brownsville, Texas Public Utilities Board.

45. Building Owners ........................................... Building Owners and Managers Association International.

46. CA Cogen .................................................... Cogeneration Association of California.

47. CA Com ....................................................... California Public Utilities Commission.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21697

Abbreviation Commenter

48. CA Energy Co .............................................. California Energy Company, Inc.

49. CA Energy Com ........................................... California Energy Commission.

50. Cajun ............................................................ Cajun Electric Power Cooperative, Inc.

51. California DWR ............................................ California Department of Water Resources.

52. California Water Agencies ........................... Association of California Water Agencies.

53. Calpine ......................................................... Calpine Corporation.

54. CAMU ........................................................... Colorado Association of Municipal Utilities.

55. Canada ......................................................... Canadian Embassy.

56. Canadian Petroleum Producers ................... Canadian Association of Petroleum Producers.

57. Caparo ......................................................... Caparo Steel.

58. Carbon Power .............................................. Carbon Power & Light Inc.

59. Carolina P&L ................................................ Carolina Power & Light Company.

60. CCEM ........................................................... Coalition for a Competitive Electric Market (consisting of Catex Vitol Electric, Inc., Coastal

Electric Services Company, Destec Power Services, Inc., Electric Clearinghouse, Inc., Enron

Power Marketing, Inc., Equitable Power Services Company, KCS Power Marketing, Inc. and

MidCon Power Services Corp.).

61. Centerior ...................................................... Centerior Energy Corporation.

62. Central EC ................................................... Central Electric Power Cooperative.

63. Central Hudson ............................................ Central Hudson Gas & Electric Corporation.

64. Central Illinois Light ..................................... Central Illinois Light Company.

65. Central Illinois Public Service ...................... Central Illinois Public Service Company.

66. Central Louisiana ......................................... Central Louisiana Electric Company, Inc.

67. Central Montana EC .................................... Central Montana Electric Power Cooperative, Inc.

68. Christensen .................................................. Laurits R. Christensen Associates Inc.

69. Chugach ....................................................... Chugach Electric Association, Inc.

70. CINergy ........................................................ CINergy Corp.

71. Citizens Lehman .......................................... Citizens Lehman Power L.P.

72. Citizens Utilities ............................................ Citizens Utilities Company.

73. Clark ............................................................. Clark Public Utilities.

74. Clean Air ...................................................... Clean Air Action Corporation.

75. Cleveland ..................................................... Cleveland Public Power.

76. CO Com ....................................................... Colorado Public Utilities Commission Staff.

77. CO Consumers Counsel .............................. Colorado Office of Consumer Counsel.

78. Coalition for Economic Competition ............ Coalition for Economic Competition (consisting of Central Hudson Gas & Electric Corporation,

Central Maine Power Company, Consolidated Edison Company of New York, Inc., Illinois

Power Company, Long Island Lighting Company, New York State Electric & Gas Corporation, Niagara Mohawk Power Corporation, Orange and Rockland Utilities, Inc., and Rochester Gas and Electric Corporation.

79. Coalition on Federal-State Issues ............... Coalition on Federal-State Issues of the Power Marketing Association.

80. Com Ed ........................................................ Commonwealth Edison Company.

81. Com Electric ................................................. Commonwealth Electric Company.

82. Competitive Enterprise ................................. Competitive Enterprise Institute.

83. Concord ........................................................ Concord Municipal Light Plant.

84. ConEd .......................................................... Consolidated Edison Company of New York, Inc.

85. Conservation Law Foundation ..................... Conservation Law Foundation and Center for Efficiency and Renewable Technologies.

86. Consolidated Natural Gas ............................ Consolidated Natural Gas Company.

87. Consumers Power ....................................... Consumers Power Company.

88. Continental Power Exchange ...................... Continental Power Exchange, Inc.

89. Cooperative Power ...................................... Cooperative Power.

90. CSW ............................................................. Central and South West Corporation.

91. CT DPUC ..................................................... Connecticut Department of Public Utility Control.

92. CT Munis ...................................................... Connecticut Conference of Municipalities.

93. CVPSC ......................................................... Central Vermont Public Service Corporation.

94. Dairyland ...................................................... Dairyland Power Cooperative.

95. Dayton P&L .................................................. Dayton Power and Light Company.

96. DC Com ....................................................... Public Service Commission of the District of Columbia.

97. DE Muni ....................................................... Delaware Municipal Electric Corporation, Inc.

98. DE, DC, NJ and MD Coms .......................... Delaware Public Service Commission, District of Columbia Public Service Commission, Maryland Public Service Commission, and New Jersey Board of Public Utilities.

99. Deloitte & Touche ........................................ Deloitte & Touche LLP.

100. Destec ........................................................ Destec Energy.

101. Detroit Edison ............................................ Detroit Edison Company.

102. Detroit Edison ............................................ Detroit Edison Wholesale Customers (consisting of City of Croswell, Michigan, and Thumb

Electric Cooperative).

103. Direct Service Industries ............................ Direct Service Industries (consisting of ELF Atochem North America, Inc., Columbia Columbia

Aluminum Corporation, Columbia Falls Aluminum Co., Georgia Pacific, Kaiser Aluminum &

Chemical Corporation, Intalco Aluminum, Northwest Aluminum Company, Reynolds Metals

Company and Vanalco, Inc.).

104. DOD ........................................................... Department of Defense.

105. DOE ........................................................... United States Department of Energy.

106. DOJ ............................................................ United States Department of Justice.

107. Dominion .................................................... Dominion Resources.

108. Douglas EC ................................................ Douglas Electric Cooperative, Inc.

109. Duke ........................................................... Duke Power Company.
21698 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

Abbreviation Commenter

110. Duquesne ................................................... Duquesne Light Company.

111. East Kentucky ............................................ East Kentucky Power Cooperative, Big Rivers Electric Corporation, and Hoosier Energy Rural

Electric Cooperative.

112. East River EC ............................................ East River Electric Power Cooperative.

113. EDS Utilities ............................................... Electronic Data Systems Inc., Utilities Division (Joussef Heguzy, Clifford J. Meagh, Julius A.

Wright).

114. Education ................................................... American Council on Education and the National Association of College and University Business Officers

115. .................................................................... EEI Edison Electric Institute.

116. EGA ............................................................ Electric Generation Association.

117. El Paso ....................................................... El Paso Electric Company.

118. ELCON ....................................................... Electricity Consumers Resource Council, American Iron and Steel Institute, Chemical Manufacturers Association and Council of Industrial Boiler Owners.

119. Electric Consumers Alliance ...................... Electric Consumers’ Alliance.

120. Electronic Data Systems ............................ EDS Utilities Division (James F. Susman).

121. ENEREX .................................................... ENEREX, Inc.

122. Entergy ....................................................... Entergy Services, Inc.

123. Entergy Retail Regulators .......................... Arkansas Public Service Commission, City Council of New Orleans, Louisiana Public Service

Commission, and Mississippi Public Service Commission.

124. Environmental Action ................................. Environmental Action Foundation.

125. EPA ............................................................ United States Environmental Protection Agency.

126. Fertilizer Institute ........................................ The Fertilizer Institute.

127. FL Com ...................................................... Florida Public Service Commission.

128. Florida Power Corp .................................... Florida Power Corporation.

129. FPL ............................................................. Florida Power & Light Company.

130. Freedom Energy Co .................................. Freedom Energy Company, LLC.

131. FTC ............................................................ United States Federal Trade Commission, Staff of the Bureau of Economics.

132. Fuel Managers ........................................... Fuel Managers Association.

133. GA Com ..................................................... Georgia Public Service Commission.

134. GAPP Committee ....................................... General Agreement of Parallel Paths Committee (A. Garfield).

135. Graves ........................................................ Graves, Frank and Ilic, Marija.

136. Green Mountain ......................................... Green Mountain Power Corporation.

137. Heartland .................................................... Heartland Consumers Power District.

138. Hogan ......................................................... Hogan, William W.

139. Home Builders ........................................... National Association of Home Builders.

140. Homelessness Alliance .............................. National Alliance to End Homelessness, Inc.

141. Hoosier EC ................................................. Hoosier Energy Rural Electric Cooperative.

142. Hopkinsville EC .......................................... Hopkinsville Electric System.

143. Houston L&P .............................................. Houston Lighting & Power Company.

144. Hydro-Quebec ............................................ Hydro-Quebec.

145. IA Com ....................................................... Iowa Utilities Board.

146. IBM ............................................................. International Business Machines.

147. ID Com ....................................................... Idaho Public Utilities Commission.

148. Ida County REC ......................................... Ida County Rural Electric Cooperative.

149. Idaho .......................................................... Idaho Power Company.

150. IES Utilities ................................................. IES Utilities Inc.

151. IL Com ....................................................... Illinois Commerce Commission.

152. IL Industrials ............................................... Illinois Industrial Energy Consumers.

153. Illinois Municipal Electric Agency ............... Illinois Municipal Electric Agency.

154. Illinois Power .............................................. Illinois Power Company.

155. IN Com ....................................................... Indiana Utility Regulatory Commission.

156. IN Industrials .............................................. Indiana Industrial Energy Consumers, Inc.

157. Industrial Energy Applications ................... Industrial Energy Applications.

158. Inland Power Pool ...................................... Inland Power Pool.

159. IPALCO ...................................................... IPALCO Enterprises, Inc.

160. James Valley EC ....................................... James Valley Electric Cooperative, Inc.

161. Jay .............................................................. Town of Jay, Maine and the Jay Power District.

162. KCPL .......................................................... Kansas City Power & Light Company.

163. Knoxville ..................................................... Knoxville Utilities Board.

164. KS Com ...................................................... Kansas Corporation Commission Staff.

165. KU .............................................................. Kentucky Utilities Company.

166. KY AG ........................................................ Kentucky Attorney General.

167. KY Com ...................................................... Kentucky Public Service Commission.

168. LA DWP ..................................................... Department of Water and Power of the City of Los Angeles.

169. LA Industrials ............................................. Louisiana Energy Users Group.

170. La Raza ...................................................... National Council of La Raza.

171. Las Cruces ................................................. City of Las Cruces, New Mexico.

172. Latin League .............................................. League of United Latin American Citizens.

173. Legal Environmental Assistance ................ Legal Environmental Assistance Foundation.

174. LEPA .......................................................... Louisiana Energy and Power Authority.

175. Lester Fink ................................................. Fink, Lester.

176. LG&E .......................................................... LG&E Energy Corp.

177. LILCO ......................................................... Long Island Lighting Company.

178. Lincoln-Union EC ....................................... Lincoln-Union Electric Company.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21699

Abbreviation Commenter

179. Lively .......................................................... Lively, Mark B.

180. Local Furnishing Utilities ............................ Local Furnishing Utilities (Long Island Lighting Company, Nevada Power Company, and San

Diego Gas & Electric Company).

181. Lower Colorado River Authority ................. Lower Colorado River Authority.

182. LPPC .......................................................... Large Public Power Council.

183. MA DPU ..................................................... Massachusetts Department of Public Utilities.

184. Madison G&E ............................................. Madison Gas & Electric Company.

185. Maine Public Service ................................. Maine Public Service Company.

186. Maritime ..................................................... Maritime Electric Company.

187. McKenzie EC ............................................. McKenzie Electric Cooperative, Inc.

188. MD Com ..................................................... Maryland Public Service Commission.

189. ME Consumer-Owned Utilities ................... Maine Consumer-Owned Utilities (consisting of Eastern Maine Electric Cooperative, Inc., Fox

Islands Electric Cooperative, Inc. Houlton Water Company, Isle au Haut Electric Power Co.,

Kennebunk Light & Power District, Madison Electric Works, Swans Island Electric Cooperative, Inc., and Van Buren Light & Power District).

190. ME Industrials ............................................ Industrial Energy Consumer Group of Maine.

191. MEAG ......................................................... Municipal Electric Authority of Georgia.

192. Memphis ..................................................... Memphis Light, Gas and Water Division.

193. Mercer ........................................................ Mercer, Dorothy Ph.D.

194. MI Com ...................................................... Michigan Public Service Commission.

195. MI MEA ...................................................... Municipal Energy Agency of Mississippi.

196. Michigan Coalition ...................................... Consumers Power, Detroit Edison and Michigan Public Service Commission.

197. Michigan Systems ...................................... Florida Municipal Power Agency, Michigan Public Power Agency, Michigan South Central

Power Agency, Michigan Public Power Ratepayers Association and Wolverine Power Supply

Cooperative.

198. MidAmerican .............................................. MidAmerican Energy Company.

199. Midwest Commissions ............................... Arkansas, Kansas & Missouri State Commissions.

200. Minnesota P&L ........................................... Minnesota Power & Light Company.

201. Missouri Basin Group ................................ Missouri Basin Systems Group, Inc.

202. Missouri Basin MPA ................................... Missouri Basin Municipal Power Agency.

203. Missouri Joint Commission ........................ Missouri Joint Municipal Electric Utilities Commission.

204. Missouri-Kansas Industrials ....................... Missouri-Kansas Industrial Energy Consumers.

205. MMWEC ..................................................... Massachusetts Municipal Wholesale Electric Company.

206. MN DPS ..................................................... Minnesota Department of Public Service.

207. Montana Power .......................................... Montana Power Company.

208. Montana-Dakota Utilities ............................ Montana-Dakota Utilities Company.

209. Montaup ..................................................... Montaup Electric Company.

210. Mor-Gran-Sou EC ...................................... Mor-Gran-Sou Electric Cooperative.

211. Mountain States Petroleum Assoc ............ Independent Petroleum Association of Mountain States and Colorado Oil and Gas Association.

212. MS Com ..................................................... Mississippi Public Service Commission.

213. MT Com ..................................................... Montana Public Service Commission.

214. MT Dept of Environmental Quality ............ Montana Department of Environmental Quality.

215. Mt. Hope Hydro .......................................... Mt. Hope Hydro, Inc.

216. Municipal Energy Agency Nebraska .......... Municipal Energy Agency of Nebraska.

217. NARUC ...................................................... National Association of Regulatory Utility Commissioners.

218. NASUCA .................................................... National Association of State Utility Consumer Advocates.

219. National Hydropower ................................. National Hydropower Association.

220. National Women’s Caucus ........................ National Women’s Political Caucus.

221. Natural Resources Defense ....................... Natural Resources Defense Council and Pacific Gas and Electric Company.

222. NC Com ..................................................... North Carolina Utilities Commission.

223. NCMPA ...................................................... North Carolina Municipal Power Agency Number 1.

224. NCPA ......................................................... Northern California Power Agency.

225. ND Com ..................................................... North Dakota Public Service Commission.

226. NE Public Power District ............................ Nebraska Public Power District.

227. NE States Air Management ....................... Northeast States for Coordinated Air Use Management.

228. NEPCO ...................................................... New England Power Company.

229. NEPOOL .................................................... New England Power Pool Executive Committee.

230. NEPOOL Review Committee ..................... New England Public Power NEPOOL Review Committee.

231. NERC ......................................................... North American Electric Reliability Council.

232. Nevada ....................................................... Nevada Power Company.

233. New Brunswick .......................................... New Brunswick Power.

234. NGSA ......................................................... Natural Gas Supply Association.

235. NH Com ..................................................... New Hampshire Public Utilities Commission.

236. NH General Court ...................................... Retail Wheeling & Restructuring Committee of the New Hampshire General Court.

237. NIEP ........................................................... National Independent Energy Producers.

238. NIMO .......................................................... Niagara Mohawk Power Corporation.

239. NIPSCO ..................................................... Northern Indiana Public Service Company.

240. NJ BPU ...................................................... New Jersey Board of Public Utilities.

241. NJ Ratepayer Advocate ............................. New Jersey Division of the Ratepayer Advocate.

242. NM Com ..................................................... New Mexico Public Utility Commission.

243. NM Industrials ............................................ New Mexico Industrial Energy Consumers.

244. NorAm ........................................................ NorAm Energy Services, Inc.

245. Nordhaus .................................................... Nordhaus, William D.

246. North Dakota RECs ................................... North Dakota Association of Rural Electric Cooperatives.
21700 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

Abbreviation Commenter

247. NRECA ....................................................... National Rural Electric Cooperative Association.

248. NRECA/APPA ............................................ National Rural Electric Cooperative Association and APPA.

249. NRRI .......................................................... National Regulatory Research Institute.

250. NSP ............................................................ Northern States Power Company.

251. NU .............................................................. Northeast Utilities System Companies.

252. Nuclear Energy Institute ............................ Nuclear Energy Institute.

253. Nucor .......................................................... Nucor Corporation.

254. NV Com ..................................................... Public Service Commission of Nevada.

255. NW Conservation Act Coalition ................. Northwest Conservation Act Coalition.

256. NW Iowa Cooperative ................................ Northwest Iowa Power Cooperative.

257. NW Power Planning Council ..................... Northwest Power Planning Council.

258. NWRTA ...................................................... Northwest Regional Transmission Association.

259. NY AG ........................................................ New York State Attorney General.

260. NY Com ..................................................... Public Service Commission of the State of New York.

261. NY Consumer Protection ........................... New York Consumer Protection Board.

262. NY Energy Buyers ..................................... New York Energy Buyers Forum.

263. NY Industrials ............................................. Multiple Industrial Intervenors of New York.

264. NY IOUs ..................................................... Long Island Lighting, New York State Electric & Gas and Rochester Gas & Elec.

265. NY Mayors ................................................. New York State Conference of Mayors and Municipal Officals.

266. NYMEX ...................................................... New York Mercantile Exchange.

267. NYPP ......................................................... New York Power Pool.

268. NYSEG ....................................................... New York State Electric & Gas Corporation.

269. Oahe EC .................................................... Oahe Electric Cooperative, Inc.

270. Oak Ridge .................................................. Oak Ridge National Laboratory.

271. Occidental Chemical .................................. Occidental Chemical Corporation.

272. Oglethorpe ................................................. Oglethorpe Power Corporation.

273. OH Com ..................................................... Public Utilities Commission of Ohio.

274. OH Coops .................................................. Ohio Rural Electric Cooperatives, Inc. and Buckeye Power, Inc.

275. OH Industrials ............................................ Industrial Energy Users—Ohio.

276. Ohio Edison ............................................... Ohio Edison Company.

277. Ohio Manufacturers ................................... Ohio Manufacturers’ Association.

278. Ohio Valley ................................................. Ohio Valley Electric Corporation.

279. OK Com ..................................................... Oklahoma Corporation Commission.

280. Oklahoma G&E .......................................... Oklahoma Gas and Electric Company.

281. Old Dominion EC ....................................... Old Dominion Electric Cooperative, Inc.

282. Oliver-Mercer EC ....................................... Oliver-Mercer Electric Cooperative, Inc.

283. Omaha PPD ............................................... Omaha Public Power District.

284. Ontario Hydro ............................................. Ontario Hydro.

285. Orange & Rockland ................................... Orange and Rockland Utilities, Inc.

286. Oregon Trail EC ......................................... Oregon Trail Electric Cooperative, Inc.

287. Otter Tail .................................................... Otter Tail Power Company.

288. PA Com ...................................................... Pennsylvania Public Utility Commission.

289. PA Coops ................................................... Pennsylvania Rural Electric Association and Allegheny Electric Cooperative, Inc.

290. PA Industrials ............................................. Industrial Energy Consumers of Pennsylvania.

291. PA Munis .................................................... Pennsylvania Municipal Electric Association.

292. Pacific Northwest Coop ............................. Pacific Northwest Generating Cooperative.

293. PacifiCorp ................................................... PacifiCorp.

294. Panhandle Coop ........................................ Panhandle Rural Electric Membership Association.

295. PECO ......................................................... PECO Energy Company.

296. Pennsylvania P&L ...................................... Pennsylvania Power & Light Company.

297. PG&E ......................................................... Pacific Gas and Electric Company.

298. Phelps Dodge ............................................ Phelps Dodge Corporation.

299. Philip Morris ............................................... Philip Morris Management Corp.

300. PJM ............................................................ PJM—Pennsylvania New Jersey Maryland Interconnection.

301. Portland ...................................................... Portland General Electric Company.

302. Power Marketing Association .................... Power Marketing Association.

303. PSE&G ....................................................... Public Service Electric and Gas Company.

304. PSNM ......................................................... Public Service Company of New Mexico.

305. Public Generating Pool .............................. Public Generating Pool.

306. Public Power Council ................................. Public Power Council.

307. Public Service Co of CO ............................ Public Service Company of Colorado and Cheyenne Light, Fuel and Power Company.

308. Puget .......................................................... Puget Sound Power & Light Company.

309. Redding ...................................................... Cities of Redding and Santa Clara, California.

310. Reynolds .................................................... Reynolds Metals Company.

311. Rochester G&E .......................................... Rochester Gas and Electric Corporation.

312. Rocky Mountain Institute ........................... Rocky Mountain Institute (Amory Lovins).

313. Rosebud ..................................................... Rosebud Enterprises, Inc.

314. RUS ............................................................ Rural Utilities Service (formerly REA).

315. Rushmore EC ............................................ Rushmore Electric Power Cooperative, Inc.

316. Salt River ................................................... Salt River Project Agriculture Improvement and Power District.

317. San Diego G&E ......................................... San Diego Gas & Electric Company.

318. San Francisco ............................................ City and County of San Francisco.

319. San Luis Valley REC ................................. San Luis Valley Rural Electric Cooperative.

320. SBA ............................................................ United States Small Business Administration, Office of Advocacy.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21701

Abbreviation Commenter

321. SC Com ..................................................... South Carolina Public Service Commission.

322. SCE&G ....................................................... South Carolina Electric & Gas Company.

323. SC Public Service Authority ....................... South Carolina Public Service Authority.

324. Seattle ........................................................ Seattle City Light Department.

325. Seminole EC .............................................. Seminole Electric Cooperative, Inc.

326. SEPA .......................................................... Southeastern Power Administration/Federal Power Customers.

327. Shelby County ............................................ Shelby County Board of Commissioners.

328. Sierra .......................................................... Sierra Pacific Power Company.

329. Slope EC .................................................... Slope Electric Cooperative Inc.

330. SMUD ......................................................... Sacramento Municipal Utility District.

331. Snohomish ................................................. Public Utility District No. 1 of Snohomish County, Washington.

332. SoCal Edison ............................................. Southern California Edison Company.

333. SoCal Gas .................................................. Southern California Gas Company.

334. South Jersey Gas ...................................... South Jersey Gas Company.

335. Southern ..................................................... Southern Company Services, Inc.

336. Southwest TDU Group ............................... Southwest Transmission Dependent Utility Group (consisting of Aguila Irrigation District, AkChin Indian Community, Buckeye Irrigation District, Central Arizona Water Conservation District, Electrical District No. 3, No. 4, No. 5, No. 6, No. 7, Harquahala Valley Power District,

Maricopa Water District, McMullen Valley Water Conservation and Drainage District, City of

Needles, Roosevelt Irrigation District, City of Safford, Tonopah Irrigation District, Wellton-Mohawk Irrigation and Drainage District).

337. Southwestern ............................................. Southwestern Public Service Company.

338. Soyland ...................................................... Soyland Power Cooperative.

339. Spink EC .................................................... Spink Electric, Redfield, SD.

340. SPP ............................................................ Southwest Power Pool, Inc.

341. Springfield .................................................. City Utilities of Springfield, Missouri.

342. St. Joseph .................................................. St. Joseph Light & Power Company.

343. Suffolk County ............................................ Suffolk County (New York) Electric Agency.

344. Sunflower ................................................... Sunflower Electric Power Corporation.

345. Supervised Housing ................................... State and City Supervised Housing for Equity in Electric Rates.

346. Sustainable Energy Policy ......................... Project For Sustainable FERC Energy Policy (on behalf of Alliance for Affordable Energy, Citizens Action Coalition of Indiana, Conservation Law Foundation, Environmental Defense

Fund, Environmental Law & Policy Center of the Midwest, Izaak Walton League of America,

Land and Water Fund of the Rockies, Legal Environmental Assistance Foundation, Mid-Atlantic Energy Project, Minnesotans for an Energy-Efficient Economy, Natural Resources Defense Council, Northwest Conservation Act Coalition, Pace Energy Project, Public Citizen,

Texas, RENEW Wisconsin, Southern Environmental Law Center, Texas Ratepayers’ Organization to Save Energy, Union of Concerned Scientists, and Wisconsin’s Environmental Decade).

347. Tallahassee ................................................ City of Tallahassee, Florida.

348. Tampa ........................................................ Tampa Electric Company.

349. TANC ......................................................... Transmission Agency of Northern California.

350. TAPS .......................................................... Transmission Access Policy Study Group.

351. TDU Systems ............................................. Transmission Dependent Utility Systems (Arkansas Electric Cooperative Corporation, Connecticut Municipal Electric Energy Cooperative, Golden Spread Electric Cooperative, Inc., Holy

Cross Electric Association, Inc., Kansas Electric Power Cooperative, Inc., Magic Valley Electric Cooperative, Inc., Mid-Tex Generation & Transmission Electric Cooperative, Inc.,

NewCorp Resources, Inc., Old Dominion Electric Cooperative, Inc.).

352. Texaco ....................................................... Texaco Inc.

353. Texas Utilities ............................................. Texas Utilities Electric Company.

354. Texas-New Mexico .................................... Texas-New Mexico Power Company.

355. Tonko ......................................................... Tonko, Paul D. (NY State Assembly).

356. Torco .......................................................... Torco Energy Marketing, Inc.

357. Total Petroleum .......................................... Total Petroleum, Inc.

358. Traverse EC ............................................... Traverse Electric Cooperative, Inc.

359. Tri-County EC ............................................ Tri-County Electric Association, Inc.

360. Tri-State G&T ............................................. Tri-State Generation and Transmission Association, Inc.

361. Tucson Power ............................................ Tucson Electric Power Company.

362. Turlock ....................................................... Turlock Irrigation District.

363. Turner-Hutchinson EC ............................... Turner-Hutchinson Electric Cooperative, Inc.

364. TVA ............................................................ Tennessee Valley Authority.

365. TX Com ...................................................... Public Utility Commission of Texas.

366. TX Industrials ............................................. Texas Industrial Energy Consumers.

367. UAMPS ...................................................... Utah Associated Municipal Power Systems.

368. Union County EC ....................................... Union County Electric Cooperative, Inc.

369. Union Electric ............................................. Union Electric Company.

370. United Illuminating ..................................... United Illuminating Company.

371. UNITIL ........................................................ UNITIL Corporation.

372. Urban League ............................................ Greater Washington Urban League, Inc.

373. UT Com ...................................................... Utah Public Service Commission and Utah Division of Public Utilities.

374. UT Industrials ............................................. Utah Industrial Energy Consumers (consisting of Alliant Techsystems, Inc., Amoco Oil Company, Holnam, Inc., Kennecott Copper Corp., and Western Zirconium.

375. UtiliCorp ..................................................... UtiliCorp United Inc.
21702 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

Abbreviation Commenter

376. Utilities For Improved Transition ................ Utilities For an Improved Transition (consisting of Basin Electric Cooperative, Black Hills Corporation, Boston Edison Company, Central Vermont Public Service Corporation, Montaup

Electric Company, Wisconsin Electric Power Company, and Wisconsin Public Service Corporation).

377. Utility—Trade Corp. Utility—Trade Corp..

378. Utility Investors Analysts ............................ Utility Investors and Analysts.

379. Utility Shareholders .................................... United Utility Shareholders Association of America.

380. Utility Wind Interest Group ......................... Utility Wind Interest Group, Inc.

381. Utility Workers Union ................................. Utility Workers Union of America, AFL–CIO.

382. Utility Working Group ................................. Utility Working Group (consisting of Atlantic City Electric Company, Dominion Resources, Inc.,

Duke Power Company, Florida Power & Light Company, Niagara Mohawk Power Corporation, Pacific Gas and Electric Company, Public Service Electric and Gas Company, and San

Diego Gas & Electric Company).

383. VA Com ...................................................... Staff of the Virginia State Corporation Commission.

384. Vann ........................................................... Vann, Albert (NY State Assembly).

385. VEPCO ....................................................... Virginia Electric and Power Company.

386. Verendrye EC ............................................ Verendrye Electric Cooperative, Inc.

387. Vernon ........................................................ City of Vernon, California.

388. VT DPS ...................................................... Vermont Department of Public Service.

389. WA Com ..................................................... Washington Utilities and Transportation Commission.

390. Wabash ...................................................... Wabash Valley Power Association, Inc.

391. WAPA ......................................................... Western Area Power Administration and Department of Energy.

392. Washington and Oregon Energy Offices ... Washington State Energy Office and Oregon Department of Energy.

393. Washington Water Power .......................... Washington Water Power Company Energy Offices.

394. WEPCO ...................................................... Wisconsin Electric Power Company.

395. West River EC ........................................... West River Electric Association, Inc.

396. Western Resources ................................... Western Resources Inc.

397. Whetstone Valley EC ................................. Whetstone Valley Electric Cooperative, Inc.

398. WI Com ...................................................... Public Service Commission of Wisconsin.

399. Wing Group ................................................ Wing Group.

400. Wisconsin Coalition .................................... Wisconsin Coalition (Wisconsin Public Power Incorporated System, Municipal Electric Utilities

of Wisconsin, Madison Gas and Electric Company, and Citizens’ Utility Board of Wisconsin).

401. Wisconsin EC ............................................. Wisconsin Electric Cooperative Association.

402. Wisconsin Municipals ................................. Municipal Electric Utilities of Wisconsin.

403. Wollenberg ................................................. Wollenberg, Bruce, et al.

404. Wolverine Coop Members ......................... Wolverine Power Supply Cooperative Special Members Committee.

405. Woodbury County REC ............................. Woodbury County Rural Electric Cooperative.

406. WP&L ......................................................... Wisconsin Power and Light Company.

407. WSCC ........................................................ Western Systems Coordinating Council Board of Trustees.

408. WSPP ......................................................... Western Systems Power Pool.

409. Yellowstone Valley EC ............................... Yellowstone Valley Electric Cooperative, Inc.

Environmental Impact Commenters

1. Attorneys General of Massachusetts,

Connecticut, New Jersey and Vermont

2. Center for Clean Air Policy

3. Central Maine Power Company

4. Cincinnati Gas & Electric Company and

PSI Energy, Inc.

5. Clifton Below

6. Electric Consumer’s Alliance

7. Connecticut Siting Council

8. Southern Environmental Law Center

9. General Public Utilities Corporation

10. Public Advisory Committee of the Grand

Canyon Visibility Transport Commission

11. Institute of Clean Air Companies

12. Interstate Natural Gas Association of

America

13. Atlantic Electric Co. and Audubon

Society of New Hampshire et al.

14. Maryland Department of Natural

Resources and Maryland Energy

Administration

15. Midwest Ozone Group

16. Missouri Department of Natural

Resources

17. National Mining Association, Western

Fuels Association, Inc. and the Center for

Energy and Economic Efficiency

18. The Navajo Nation

19. Maine, Massachusetts, Vermont and New

Hampshire Public Service Commissions

20. New Jersey Board of Public Utilities and

the New Jersey Department of

Environmental Protection

21. New York State Department of Public

Service and the New York State

Department of Environmental Conservation

22. Office of the Ohio Consumers’ Counsel

23. Ohio Electric Utility Institute

Environmental Committee

24. Ozone Transport Assessment Group

25. Ozone Transport Commission

26. Utility Air Regulatory Group (Edison

Electric Institute, the National Rural

Electric Cooperative Association and the

American Public Power Association)

27. Wisconsin Department of Natural

Resources

Other (Including Technical Conference

Commenters)

1. Electric Power Research Institute

2. Electric Policy Technical Issues Group

3. Tejas Power Corporation

4. Competitive Power Coalition of New

England

5. Mid-Continent Area Power Pool

6. Michigan Electric Coordinated Systems

7. Independent Energy Producers Association

8. Praxair, Inc.

9. Utility-Trade Corp.

10. Competitive Power Coalition of New

England

11. Wyoming Public Service Commission

12. State of New Jersey

13. Paul Joskow

14. New England Conference of Public Utility

Commissioners

15. Commonwealth of Massachusetts

16. Florida Electric Power Coordinating

Group

17. Dine Power Authority

18. State of Connecticut Department of

Environmental Protection

19. Commonwealth of Massachusetts

Department of Environmental Protection

20. State of Maine Department of

Environmental Protection

21. Comision Federal de Electricidad of

Mexico

Appendix C—Allegations of Public

Utilities Exercising Transmission

Dominance

I. Examples From Proceedings Before

Administrative Law Judges

These are examples of allegations that

various public utilities have refused to
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21703

1After the Rehearing Order expanding the scope

of the proceeding, AMP-Ohio and IMPA withdrew

this testimony as no longer necessary. This

withdrawal does not change the fact that the

testimony was sworn to under oath.

2AEP generally limited its offer of short-term

transmission to buy/sell transactions; that is, AEP

would buy the power from the seller and resell it

to the purchaser. Supplemental testimony of AEP

Witness Baker (Ex. A–73) at 27–29. Often, the terms

of the buy/sell transaction required transmission

dependent utilities (TDUs) to maintain reserves and

meet contractual commitments for at least a year.

Id.

provide comparable service, either through

refusals to wheel, dilatory tactics that so

protracted negotiations as to effectively deny

wheeling, refusals to provide service priority

equal to native load, or refusals to provide

service flexibility equivalent to the utility’s

own use.

A. American Electric Power Service Corp.

(AEP)

In 1993, AEP filed, on behalf of its public

utility associate companies, an open access

tariff that offered only firm point-to-point

service with very limited flexibility. It did

not offer network service, flexible point-topoint service, or non-firm service. Thus, it

did not provide customers with the same

flexibility that AEP itself has. Nor did it

provide a service priority equivalent to that

enjoyed by native load. The Commission set

AEP’s tariff for hearing and, on rehearing,

held that in order not to be unduly

discriminatory, the tariff had to offer

comparable service. American Electric Power

Service Corp., 64 FERC ¶ 61,279 (1993),

reh’g, 67 FERC ¶ 61,168 (1994).

At hearing, Raj Rao of Indiana Michigan

Power Agency (IMPA) (Ex. IMPA–1, Feb 23,

1994) and Kenneth Hegemann of American

Municipal Power-Ohio, Inc. (AMP-Ohio) (Ex.

AMPO–1, Feb 23, 1994), both senior

management officials, testified concerning

AEP’s alleged discriminatory practices.1

AMP-Ohio is an association of municipalities

in Ohio, some of whose members depend on

AEP for transmission and partial

requirements service. IMPA is an association

of municipalities in Indiana, and many of

IMPA’s loads are captive to the AEP

transmission system. The witnesses alleged

as follows:

1. In anticipation of high peak demands,

AEP would contract for large blocks of

available short-term power, withhold sale of

short-term power, refuse to transmit third

party short-term power, and require

purchases from AEP at the emergency rate

(100 mill/kwh) when an emergency might

not exist. Ex. AMPO–1 at 6.

2. In December 1989, AMP-Ohio negotiated

a 20 MW purchase of short-term power from

Louisville Gas & Electric Company (LG&E).

AEP refused to wheel because LG&E had

earlier that day told AEP it had no power to

sell to AEP. AEP then bought the power from

LG&E and offered to resell it to AMP-Ohio.

Ex. AMPO–1 at 6–7.

3. In January 1990, AMP-Ohio solicited

bids for February power purchases from a

number of utilities including AEP. AEP was

not the winning bid. AMP-Ohio made

arrangements to purchase the power from

four winning bidders and sought

transmission through AEP. When AMP-Ohio

gave AEP the schedule for delivery, AEP

refused to transmit the power, matched the

average price of the winning bids, and made

the sale itself. Ex. AMPO–1 at 7.

4. In August 1993, an AMP-Ohio member

(Columbus, Ohio) was purchasing 10 MW of

hourly non-displacement power from AEP

and, after AEP raised its price to 60 mills/

kwh, sought another source for the next hour.

Consumers Power Company and Detroit

Edison Company both offered nondisplacement power at 40 mills. AEP refused

to transmit, saying it had a 600 MW unit out

and could not resell power from another

source.2 Columbus cancelled the transaction

and had to buy 10 MW of power from AEP

at 100 mills/kwh. Ex. AMPO–1 at 7–8.

5. In July 1993, two AMP-Ohio members

(Columbus and St. Mary’s) had been buying

hourly non-displacement power from AEP

when the price rose to 35 mills. Dayton

Power & Light Company (DP&L) offered to

sell at 23 mills and AEP agreed to transmit

for one hour. But for the next hour, AEP said

it had problems with its system, refused to

transmit the power, kept the power from

DP&L for itself and offered to sell power to

AMP-Ohio for Columbus and St. Mary’s at

100 mills. Columbus increased its local

generation, but St. Mary’s purchased 8 MW

at 100 mills. For the next hour, AMP-Ohio

arranged with DP&L for another 8 MW,

hoping AEP would transmit under the 24

hour buy-sell agreement. AEP did transmit

this power. Seven hours later in the day, St.

Mary’s Greenup Hydro project power was

available and the 8 MW from DP&L was no

longer needed. If St. Mary’s had been

receiving the hourly power that AEP had

refused to transmit, St. Mary’s could have

switched to Greenup power. But because

AMP-Ohio had changed to daily service, St.

Mary’s had to pay a demand charge for the

entire day, even though it used the power

only 7 hours and would have paid less under

the hourly rate. Ex. AMPO–1 at 8–9.

6. In January 1994, AMP-Ohio sought to

transfer power from one member with

generation to other members, which required

transmission over AEP and Toledo Edison

lines. Toledo Edison said yes, AEP said no.

AMP-Ohio’s northern members purchased

emergency power from Toledo Edison. AMPOhio then reminded AEP that it had agreed

not to deny transmission and AEP agreed to

transmit. Ex. AMPO–1 at 9.

7. IMPA arranged to buy 80 MW of shortterm power from LG&E and have it wheeled,

using buy-sell arrangements, through Public

Service Company of Indiana (PSI) and AEP

to serve IMPA’s load at Richmond (an IMPA

member). The delivered price was $.292 per

kW-day plus a 1 mill adder. At the same time

AEP arranged to buy 300 MW from PSI at

$.30 per kW day plus out-of-pocket energy

costs. Hence, PSI was shipping a total of 380

MW to AEP with 80 MW of that amount to

be delivered to IMPA’s load at Richmond.

Then, on a day when IMPA should have

received the 80 MW, AEP told IMPA that PSI

had sold everything to AEP and that IMPA

would have to buy from AEP at $.63 per kW

day plus the cost of energy from AEP. IMPA

purchased from AEP under protest. AEP used

its control over transmission to intercept the

80 MW at a lower price and resell it as shortterm power to IMPA. AEP claimed that PSI

had terminated its sales to AEP on that day.

But the 80 MW was independent of PSI’s

other sales to AEP and would not have been

interrupted if AEP had not interrupted it.

IMPA–1 at 7.

8. IMPA has combustion turbines owned

by and located at one member, which IMPA

would like to connect to the Joint

Transmission System owned by IMPA,

CINergy and Wabash Valley Power

Association. To do so, IMPA needed a

metering agreement with AEP, to which AEP

would not agree. IMPA–1 at 6.

9. In January 1994, IMPA had power to sell

from its turbines when AEP and others

needed power. IMPA offered power to AEP

but AEP it said could not purchase the power

without an existing contract. Moreover, since

there was no short-term tariff, IMPA could

not sell the power to another utility. IMPA–

1 at 6.

10. Another example of the utility engaging

in dilatory tactics that raised the customer’s

transaction costs and effectively denied

transmission is the ‘‘sham transaction’’

provision proposed by AEP. As filed, AEP’s

tariffs permitted it to deny service merely

because a portion of the transmitted power

might be used to serve a former retail

customer of AEP. See, e.g., Ex. BR&WVP–1 (J.

Bertram Solomon testimony, February 23,

1994). (As part of a settlement AEP filed the

pro forma tariff and withdrew this

provision.)

11. Finally, AEP’s originally filed tariff

contained a ‘‘prodigal customer’’ provision.

Under this provision, transmission customers

who sought to convert back to requirements

service had to give AEP five years’ notice, in

which case AEP and the customer would

enter into negotiations to determine whether

AEP will provide service at all and if so

under what rate, terms, and conditions. Ex.

S–39 at 1 (Staff testimony). AEP did not

require notice from all new customers, only

from prodigal customers. Id. at 2. That a

potential customer was previously served by

AEP is not a reason to treat the customer

differently. (AEP withdrew this provision

when it filed the pro forma tariff.)

B. Entergy Services, Inc. (Entergy)

Entergy filed a partial settlement largely

adopting the NOPR pro forma tariffs except

for two provisions (headroom and ancillary

services). Because the settlement predated

the filing date for customer testimony before

the ALJ, the customers did not address the

need for Entergy to file a tariff. However,

customers did make allegations of

discriminatory practices, as follows.

1. Customers alleged that Entergy flat-out

refused to wheel. Louisiana Energy and

Power Authority (LEPA) witness Sylvan J.

Richard testified that LEPA’s predecessor

systems could not obtain interconnections

from Entergy. Ex. SJR–1 at 50.

2. Customers also alleged that Entergy

refused to provide service priority equal to

native load and refused to provide service

flexibility equivalent to the utility’s own use.

For example, LEPA witness Richard testified

that even after state commissions ordered

interconnections and other coordination
21704 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

3All of these incidents are related to and

examples of PG&E’s conduct described in the NOPR

(FERC Stats. & Regs. ¶32,514 at 33,073 n.151), that

is, the history of PG&E’s attempt to avoid its

commitments made to the California owners of the

California Oregon Transmission Project (COTP).

However, these incidents are not exactly the same

as the incidents described in the NOPR, because

NCPA is not one of the owners of the COTP.

services, LEPA’s predecessors were still not

able to obtain coordination services because

Entergy was not willing to coordinate and

because the transmission service it did offer

was inflexible, unidirectional point-to-point

service, which prevented economic

coordination with others. Id. at 50–51.

3. South Mississippi Electric Power

Association (SMEPA) witness J. Bertram

Solomon testified that Entergy’s original

‘‘open access’’ tariff was restricted to pointto-point service, proposed separate charges

for each operating company, and required the

cancellation of existing agreements in order

to take service under the proposed tariff. Ex.

SMEPA–10 at 28. Entergy eventually filed a

network tariff, but proposed different local

facilities charges for the various Entergy

public utility operating subsidiaries. Id. at 29.

Since these local facilities charges were

higher than the transmission component of

the subsidiaries’ bundled rates, Entergy

obtained a competitive advantage. Id.

4. The Arkansas Cities and Cooperatives

(ACC) is a group of cities and cooperatives

that own or operate electric generation or

distribution systems in Arkansas. ACC

Witness Steven Merchant testified that

Entergy has segregated the wholesale market

between two of its subsidiaries, Arkansas

Power & Light Copmpany (APL) and Entergy

Power, Inc. (EPI). Ex. SMM–1 at 16. In

marketing power and energy in Arkansas, EPI

is subject to an Arkansas Commission order

that bars EPI from competing with APL for

wholesale loads without first obtaining a

waiver. Id. Recently, EPI requested this

waiver for all wholesale transactions in

Arkansas except for wholesale customers

currently served by an Entergy subsidiary; in

other words, EPI requested the Arkansas

Commission to expand competition for all

wholesale customers except where EPI might

compete with APL. Id. ACC witness

Merchant concluded that, since EPI does not

compete with APL, Entergy insulates APL’s

wholesale business from competition and

denies those wholesale customers access to

EPI as a source of power, thereby limiting

alternative generation sources available to

ACC. Id. at 17–19. (Entergy’s witness Kenney

stated that Entergy has recently filed a joint

motion with ACC to the Arkansas

Commission seeking to extend the waiver

and permit EPI to sell to APL’s wholesale

customers. Ex. JFK–11 at 14–15.)

C. Pacific Gas & Electric Company (PG&E)

Northern California Power Agency (NCPA)

attached several documents to its 1988

complaint in Docket No. EL89–4. These

documents were provided to support NCPA’s

claim that PG&E’s unreasonable practices

under the PG&E/NCPA Interconnection

Agreement (IA) effectively denied NCPA

access to transmission properly requested

under the IA. Although the parties eventually

settled and the Commission terminated the

docket with a letter order dated May 18,

1988, these documents provide allegations of

PG&E using dilatory tactics that so protracted

negotiations as to effectively equal a refusal

to wheel.3

1. PG&E stated that since transmission was

not currently available, it was entitled to wait

72 months before providing transmission;

that is, transmission access could not be

granted before the passing of the 72-month

notice period. NCPA 1988 Complaint, Ex. 3.

However, the IA provided that transmission

be provided when it becomes actually

available. PG&E also requested substantial

additional information, which NCPA

considered beyond that reasonably necessary

for a study, but still provided. PG&E then

determined that transmission was not

available, reasoning that transmission was

unavailable unless all the transmission

requested could be provided 8760 hours per

year without restrictions or limitations,

extending through the expiration of the

agreement in 2013. NCPA 1988 Complaint at

9.

2. On November 27, 1987, NCPA made a

new transmission request to PG&E, seeking

50 MW of bi-directional transmission at

Midway. NCPA 1988 Complaint, Ex. 5. On

January 28, 1988, PG&E filed an

interconnection agreement with Turlock

Irrigation District (TID) that provided TID

with 50 MW of bi-directional transmission at

Midway. Pacific Gas & Electric Company, 42

FERC ¶ 61,406, order on reh’g, 43 FERC

¶ 61,403 (1988). On February 22, 1988, PG&E

advised NCPA that all firm transmission

service available at Midway had been fully

subscribed. NCPA 1988 Complaint, Ex. 6.

Then, on March 29, 1988, PG&E filed with

the Commission an interconnection

agreement with Modesto Irrigation District

(MID), that provided MID with 50 MW of bidirectional transmission at Midway. Pacific

Gas & Electric Company, 44 FERC ¶ 61,010

(1988). At about the same time (in the last

week in March 1988), PG&E advised NCPA

that the allocations of transmission to TID,

MID, and others, including a not yet finalized

allocation to Sacramento Municipality Utility

District, had used all the transmission

available at Midway. NCPA 1988 Complaint,

Exs. 7 and 8.

D. Northeast Utilities Service Company (NU)

This is the case where Northeast Utilities

acquired Public Service of New Hampshire

(PSNH) (Docket No. EC90–10). New England

Power Company (NEP) witness Robert

Bigelow’s direct testimony expressed concern

over the ‘‘relatively restrictive transmission

policies of both’’ NU, on behalf of Northeast

Utilities’ public utility subsidiaries, and

PSNH. Bigelow Direct Testimony at 21 (filed

May 25, 1990). In his cross rebuttal

testimony, Mr. Bigelow testified that ‘‘NU has

a poor track record as a provider of

transmission service’’ and ‘‘PSNH also has an

abhorrent track record as a provider of

transmission services.’’ Bigelow Cross

Rebuttal Testimony, at 3 (filed June 20,

1990). Mr. Bigelow described both NU’s and

NEP’s (his own company) failure to provide

service flexibility equivalent to their own

use. Except for NEP’s TDUs, both NEP and

NU historically provided only point-to-point

transmission, which required separate

scheduling for each transaction. Bigelow

Cross Rebuttal at 4.

E. Southern California Edison Company and

San Diego Gas and Electric Company

The evidence in this merger proceeding

(Docket No. EC89–5) included testimony

from a number of witnesses describing

instances of Edison’s conduct. Richard

Greenwalt was the power supply supervisor

for the City of Riverside, California. He was

responsible for scheduling all purchases of

energy for Riverside and for the cities of

Azusa, Banning and Colton, California.

Greenwalt testimony at 1 (November 1989).

(These four cities and Anaheim, California,

are collectively referred to as the Southern

Cities or Cities.) Joseph Hsu was the Director

of Utilities for Azusa. Hsu testimony at 1

(November 1989). Gale Drews was the

electric utility director of Colton. Drews

testimony at 1–2 (November 1989). Bill

Carnahan was the director for Riverside.

Carnahan testimony at 1 (November 1989).

Gordon Hoyt was the general manager of the

Anaheim power department. Hoyt testimony

at 1 (November 1989). Dan McCann was the

power coordination supervisor for Anaheim.

He supervised Anaheim’s load scheduling

and is a former Edison employee, having

worked for Edison for 20 years. McCann

Testimony at 1–2 (November 1989). These

witnesses testified that Edison refused to

wheel as follows.

1. Edison’s policy was to curtail the Cities

any time it could be justified using any of a

list of acceptable reasons to deny

interruptible transmission service. Id. at 22–

23.

2. Edison would not generally provide

transmission service when Edison could save

money by itself purchasing the economy

energy that would be wheeled. McCann

testimony at 19. The Cities called Edison

every hour to request interruptible

transmission service. Id. Edison often refused

to sell energy available in the Western

Systems Power Pool to the Cities and then

made available higher cost contract energy or

partial requirements service. Id. at 19–20.

3. When Anaheim requested Edison

provide firm transmission of power from

neighboring states, Edison would often agree

to provide non-firm service but would not

integrate the capacity for many years in the

future, saying that its control area did not

need capacity at that time. Hoyt testimony at

9. Since the selling utility was interested in

a sale of capacity, not just energy, the

transaction would not occur. Id. Edison

repeatedly used its control over transmission

to deny Anaheim access to low-cost firm

power. Id. at 9–10.

4. While Edison provided short-term firm

transmission service to the Cities, it would

only provide long-term firm service for three

specific resources: The SONGS nuclear plant,

a specific IPP, and Hoover Dam power. Hoyt

testimony at 20. One of Edison’s reasons for

denying long-term transmission was that

Edison desired to reserve the transmission for

its own future (unspecified) needs. Id.

5. In the 1970s, Edison refused to allow the

Cities access to the Pacific Intertie. Hoyt

testimony at 21; Drews testimony at 7–8.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21705

4Special Condition 12 of the Integrated

Operations Agreement between Edison and the

Southern Cities defined certain Special Condition

12 resources and allowed the Cities to make certain

uses of those resources, subject to certain

restrictions.

6. In 1988, Edison refused to provide

transmission service for a Cities power

purchase from Public Service Company of

New Mexico (PSNM) from Palo Verde

Nuclear station. Hoyt testimony at 21.

7. Edison has refused to provide requested

firm transmission from

—California-Oregon border to Midway

Station

—Nevada-Oregon Border to Sylmar

Substation

—Palo Verde Switchyard to Vista

—SONGS Switchyard to Vista.

Carahan testimony at 15.

8. Riverside requested transmission from

Palo Verde and was told that such service

was not available. Carnahan testimony at 16.

Edison offered Riverside only 12 MW of

curtailable transmission entitlement to

provide Riverside’s share of Palo Verde. Id.

This service was neither large enough or long

enough, and Edison insisted on unreasonable

terms and conditions. Id.

9. Azusa, Banning and Colton had a

contract with Edison that entitled them to

use their Palo Verde firm transmission path

to schedule energy to meet their contract

energy obligation. Edison refused to permit

the three cities to use that path. Edison did

not contest that the contracts allowed this

use, but said that the scheduling of such

small amounts of energy for the three cities

would be too burdensome. Greenwalt

testimony at 14.

10. Edison would not respond in a timely

manner to the Cities’ requests, routinely

taking months to respond. Drews testimony

at 15.

11. During the 1980s, Edison provided

Colton with some transmission service to

allow the Cities to reach certain suppliers,

but limited the choices available to the Cities

and imposed terms and conditions that

increased the Cities’ costs and placed Colton

at a disadvantage against Edison. Drews

testimony at 9. Arranging alternative

generation sources was difficult because the

Cities always had to first get Edison to state

whether it would provide transmission.

12. During 1988 and 1989, a dispute arose

between Edison and the Cities concerning the

Hoover Uprating Project. Drews testimony at

16. Edison argued that for the months when

units were out of service for uprating, and

Southern Cities capacity was reduced to zero,

Southern Cities would not receive an energy

credit, even though energy was still available

and used by Edison. But the contracts

allowed a participant who did not have

capacity to still schedule its energy as nonfirm energy on the capacity of another

participant. Id. at 16–17.

13. In 1986, Azusa negotiated a power

purchase contract with the California

Department of Water Resources in

increments of first 5 MW and then 2 MW (for

a total of 7 MW). Hsu testimony at 14. First

Edison assured Azusa that the transmission

for the additional 2 MW would not be a

problem. Id. Then Edison would not agree to

amend the transmission service agreement

for the additional 2 MW. Id.

14. In 1986, Azusa notified Edison of

Special Condition 12 4 purchases from PG&E

and requested firm transmission service. Id.

Two months before service was to begin,

Edison notified the Cities of a problem with

the transmission lines. Id. Transmission was

eventually granted, but only after a fourmonth delay and substantial losses to the

Cities. Id. Then Edison decided there was no

problem with its transmission facilities. Id. at

14–15.

15. In 1986–87, the Cities purchased 20

MW from PG&E and 80 MW from Deseret

G&T Cooperative. Hoyt testimony at 7–8.

Edison stated that without reinforcement of

its transmission system, Edison would not

provide the transmission. Id. There was a

five-month delay during which the Cities

were forced to purchase from Edison at a

higher cost. Id. at 8–9. Then Edison decided

that the transmission system did not need

reinforcement. Id. at 8.

16. Edison also refused to provide a service

priority equal to that of native load. It would

curtail the Cities in order to purchase more

economy energy for itself. McCann testimony

at 28. If Edison could make the purchase, it

would curtail the City and use the energy for

itself. Id. When Edison curtailed the Cities,

they were not able to purchase economy

energy and instead purchased energy from

Edison. Id. at 24.

17. According to Edison, the interruptible

transmission it provided the Cities was

interruptible for any reason. Id. at 20. A

purchase could be terminated the hour after

it is begun or even during the hour. Id. As

a result, the Cities lost opportunities to make

advantageous economy purchases. Id. at 20–

21.

18. Edison also refused to provide

customers flexibility similar to the flexibility

Edison provided itself. Edison’s refusal to

provide bi-directional transmission service

restricted the Cities’ abilities to purchase

hydroelectric energy from the Pacific

Northwest. Hoyt testimony at 22. Because

most contracts with Northwest utilities

require a return of power, the Northwest

utilities would not deal with the Cities

without transmission to return energy. Id. at

22–23. Edison did provide bi-directional

transmission to the Los Angeles Department

of Water & Power (LADWP) to accommodate

flows to and from Arizona. Id.

19. Riverside was unable to obtain nonfirm service more than two hours in advance

of need. Carnahan testimony at 18.

20. Riverside and Colton were both served

out of Edison’s Vista substation. Although

the two cities were on the same 69 kV bus,

Edison would not allow them to sell energy

to each other. Greenwalt testimony at 17.

21. Riverside’s agreement with Edison

allowed Riverside to purchase a block of

energy through the WSPP and divide it up

among the four Cities (Azusa, Banning,

Colton and Riverside). Greenwalt testimony

at 17. When Riverside had excess energy

from other sources, Edison would not permit

it to sell that energy to the other three cities.

Id. For example, Riverside attempted to sell

Deseret energy transmitted by LADWP to the

Edison system. Id. at 17–18. LADWP would

not break out the Cities’ shares of that energy,

and Edison would not accept the energy as

a delivery for all four cities. Id. at 18. Edison

argued that because this energy was excess

energy that Riverside could not use,

Riverside did not have transmission rights to

bring it into the control area. Id. As a result,

Riverside paid for the energy delivered by

LADWP to the Edison control area, but could

not sell it to the other three cities, and gave

it to Edison itself, which consumed the

energy without making any payment for it.

Id. Riverside tried a number of alternative

paths, including using WSPP transmission

where Riverside paid Edison 5 mills to

connect to Azusa, 5 mills to connect to

Banning, and 5 mills to connect to Colton for

each megawatthour. While this approach was

successful for a while, eventually Edison

refused to permit these sales.

22. Edison claimed that the Cities only

have transmission rights to bring in enough

Special Condition 12 energy to satisfy the

Cities’ load. Greenwalt testimony at 18.

23. Edison contended that the Cities’ load

requirements were satisfied first by

integrated resources and then by Special

Condition 12 and economy energy purchases.

Id. at 19. When the Cities’ integrated

resources exceeded their load, any Special

Condition 12 resources became excess. Under

Riverside’s Deseret contract, the Cities were

required to take a minimum of 35 MW each

hour. Id. Edison acknowledged that it was

obligated to buy, or allow the Cities to sell,

any excess energy from Riverside’s integrated

resources. Id. However, Edison refused to

give the Cities credit for excess Special

Condition 12 energy brought into the area,

claiming that the Cities could not have

brought it in because they did not have

transmission rights. Id.

II. Other Examples of Transmission Disputes

Disputes over transmission are not

uncommon, contrary to EEI’s suggestion.

Some recent examples taken from pleadings

and other documents and from Commission

orders reveal that it has been very difficult

for various entities in the electric power

industry to agree on transmission rights.

These examples also reveal that even after

issuance of AEP and the Open Access NOPR

with its proposed pro forma tariffs, there has

been considerable controversy over whether

various utilities’ ‘‘open access’’ tariffs deviate

from those tariffs. (The Commission has

allowed utilities that adopt tariffs that match

or exceed the non-rate terms and conditions

in the NOPR pro forma tariffs to obtain

certain benefits.)

A. In a letter of February 3, 1995 to Mr.

Gerald Richman of the Commission’s

Enforcement section in the Office of the

General Counsel, Steven J. Kean, Vice

President, Regulatory Affairs, Enron Power

Marketing, Inc. (Enron) alleged that Niagara

Mohawk Power Corporation (NiMo) refused

to wheel power from Rochester Gas & Electric

(RG&E) to Enron under RG&E’s transmission

contract with NiMo; however, when Enron

revealed the buyer, NiMo did wheel power

for RG&E to the buyer. Mr. Kean alleged that

this was not an isolated incident. NiMo

argued that the contract did not require it to
21706 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

provide RG&E with transmission to Enron. It

also said that the principle of comparability

does not require the service. Letter of

November 21, 1994 from NiMo representative

A. Karen Hill to Gerald Richman.

B. The Commission’s Task Force Hot Line

(Hot Line) received a complaint that a

member of the New York Power Pool (NYPP)

refused to transmit power that another

member bought from a power marketer. In a

letter of November 17, 1994, from Chair

Moler to Mr. William J. Balet, Executive

Director of NYPP, Chair Moler explained that

the Commission’s enforcement staff had

investigated and found the allegation to be

true.

C. In Southern Minnesota Municipal Power

Agency v. Northern States Power Company

(Minnesota), 73 FERC ¶ 61,350 (1995), NSP

and SMMPA had a contract under which

NSP agreed to provide transmission service.

However, the parties had numerous disputes

over the service. The Commission found that

NSP had misinterpreted the contract in

several ways. For, example, SMMPA argued

that it should be able to directly schedule its

deliveries of energy out of the NSP control

area and that it should not be limited to

particular points of delivery. NSP argued that

only it was entitled to control the physical

operation of scheduling. The Commission

found that the clear language of the contracts

gave SMMPA the authority to schedule its

own power.

D. Mid-Continent Area Power Pool, 72

FERC ¶ 61,223 (1995), involved MAPP’s

membership criteria, which made it

impossible for a power marketer to join

MAPP and obtain the benefits of certain

transmission services available only to MAPP

members. The Commission found that the

membership criteria may be unreasonable,

particularly since there may be less

burdensome ways of setting up membership

criteria for non-traditional entities.

Appendix D—Pro Forma Open Access

Transmission Tariff

Table of Contents

I. Common Service Provisions

1 Definitions

1.1 Ancillary Services

1.2 Annual Transmission Costs

1.3 Application

1.4 Commission

1.5 Completed Application

1.6 Control Area

1.7 Curtailment

1.8 Delivering Party

1.9 Designated Agent

1.10 Direct Assignment Facilities

1.11 Eligible Customer

1.12 Facilities Study

1.13 Firm Point-To-Point Transmission

Service

1.14 Good Utility Practice

1.15 Interruption

1.16 Load Ratio Share

1.17 Load Shedding

1.18 Long-Term Firm Point-To-Point

Transmission Service

1.19 Native Load Customers

1.20 Network Customer

1.21 Network Integration Transmission

Service

1.22 Network Load

1.23 Network Operating Agreement

1.24 Network Operating Committee

1.25 Network Resource

1.26 Network Upgrades

1.27 Non-Firm Point-To-Point

Transmission Service

1.28 Open Access Same-Time

Information System (OASIS)

1.29 Part I

1.30 Part II

1.31 Part III

1.32 Parties

1.33 Point(s) of Delivery

1.34 Point(s) of Receipt

1.35 Point-To-Point Transmission Service

1.36 Power Purchaser

1.37 Receiving Party

1.38 Regional Transmission Group (RTG)

1.39 Reserved Capacity

1.40 Service Agreement

1.41 Service Commencement Date

1.42 Short-Term Firm Point-To-Point

Transmission Service

1.43 System Impact Study

1.44 Third-Party Sale

1.45 Transmission Customer

1.46 Transmission Provider

1.47 Transmission Provider’s Monthly

Transmission System Peak

1.48 Transmission Service

1.49 Transmission System

2 Initial Allocation and Renewal

Procedures

2.1 Initial Allocation of Available

Transmission Capability

2.2 Reservation Priority For Existing Firm

Service Customers

3 Ancillary Services

3.1 Scheduling, System Control and

Dispatch Service

3.2 Reactive Supply and Voltage Control

from Generation Sources Service

3.3 Regulation and Frequency Response

Service

3.4 Energy Imbalance Service

3.5 Operating Reserve—Spinning Reserve

Service

3.6 Operating Reserve—Supplemental

Reserve Service

4 Open Access Same-Time Information

System (OASIS)

5 Local Furnishing Bonds

5.1 Transmission Providers That Own

Facilities Financed by Local Furnishing

Bonds

5.2 Alternative Procedures for Requesting

Transmission Service

6 Reciprocity

7 Billing and Payment

7.1 Billing Procedure

7.2 Interest on Unpaid Balances

7.3 Customer Default

8 Accounting for the Transmission

Provider’s Use of the Tariff

8.1 Transmission Revenues

8.2 Study Costs and Revenues

9 Regulatory Filings

10 Force Majeure and Indemnification

10.1 Force Majeure

10.2 Indemnification

11 Creditworthiness

12 Dispute Resolution Procedures

12.1 Internal Dispute Resolution

Procedures

12.2 External Arbitration Procedures

12.3 Arbitration Decisions

12.4 Costs

12.5 Rights Under The Federal Power Act

II. Point-to-Point Transmission Service

Preamble

13 Nature of Firm Point-To-Point

Transmission Service

13.1 Term

13.2 Reservation Priority

13.3 Use of Firm Transmission Service by

the Transmission Provider

13.4 Service Agreements

13.5 Transmission Customer Obligations

for Facility Additions or Redispatch

Costs

13.6 Curtailment of Firm Transmission

Service

13.7 Classification of Firm Transmission

Service

13.8 Scheduling of Firm Point-To-Point

Transmission Service

14 Nature of Non-Firm Point-To-Point

Transmission Service

14.1 Term

14.2 Reservation Priority

14.3 Use of Non-Firm Point-To-Point

Transmission Service by the

Transmission Provider

14.4 Service Agreements

14.5 Classification of Non-Firm Point-ToPoint Transmission Service

14.6 Scheduling of Non-Firm Point-ToPoint Transmission Service

14.7 Curtailment or Interruption of

Service

15 Service Availability

15.1 General Conditions

15.2 Determination of Available

Transmission Capability

15.3 Initiating Service in the Absence of

an Executed Service Agreement

15.4 Obligation to Provide Transmission

Service that Requires Expansion or

Modification of the Transmission System

15.5 Deferral of Service

15.6 Other Transmission Service

Schedules

15.7 Real Power Losses

16 Transmission Customer Responsibilities

16.1 Conditions Required of

Transmission Customers

16.2 Transmission Customer

Responsibility for Third-Party

Arrangements

17 Procedures for Arranging Firm Point-ToPoint Transmission Service

17.1 Application

17.2 Completed Application

17.3 Deposit

17.4 Notice of Deficient Application

17.5 Response to a Completed

Application

17.6 Execution of Service Agreement

17.7 Extensions for Commencement of

Service

18 Procedures for Arranging Non-Firm

Point-To-Point Transmission Service

18.1 Application

18.2 Completed Application

18.3 Reservation of Non-Firm Point-ToPoint Transmission Service
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21707

18.4 Determination of Available

Transmission Capability

19 Additional Study Procedures For Firm

Point-To-Point Transmission Service

Requests

19.1 Notice of Need for System Impact

Study

19.2 System Impact Study Agreement and

Cost Reimbursement

19.3 System Impact Study Procedures

19.4 Facilities Study Procedures

19.5 Facilities Study Modifications

19.6 Due Diligence in Completing New

Facilities

19.7 Partial Interim Service

19.8 Expedited Procedures for New

Facilities

20 Procedures if The Transmission Provider

is Unable to Complete New

Transmission Facilities for Firm PointTo-Point Transmission Service

20.1 Delays in Construction of New

Facilities

20.2 Alternatives to the Original Facility

Additions

20.3 Refund Obligation for Unfinished

Facility Additions

21 Provisions Relating to Transmission

Construction and Services on the

Systems of Other Utilities

21.1 Responsibility for Third-Party

System Additions

21.2 Coordination of Third-Party System

Additions

22 Changes in Service Specifications

22.1 Modifications On a Non-Firm Basis

22.2 Modification On a Firm Basis

23 Sale or Assignment of Transmission

Service

23.1 Procedures for Assignment or

Transfer of Service

23.2 Limitations on Assignment or

Transfer of Service

23.3 Information on Assignment or

Transfer of Service

24 Metering and Power Factor Correction at

Receipt and Delivery Points(s)

24.1 Transmission Customer Obligations

24.2 Transmission Provider Access to

Metering Data

24.3 Power Factor

25 Compensation for Transmission Service

26 Stranded Cost Recovery

27 Compensation for New Facilities and

Redispatch Costs

III. Network Integration Transmission Service

Preamble

28 Nature of Network Integration

Transmission Service

28.1 Scope of Service

28.2 Transmission Provider

Responsibilities

28.3 Network Integration Transmission

Service

28.4 Secondary Service

28.5 Real Power Losses

28.6 Restrictions on Use of Service

29 Initiating Service

29.1 Condition Precedent for Receiving

Service

29.2 Application Procedures

29.3 Technical Arrangements to be

Completed Prior to Commencement of

Service

29.4 Network Customer Facilities

29.5 Filing of Service Agreement

30 Network Resources

30.1 Designation of Network Resources

30.2 Designation of New Network

Resources

30.3 Termination of Network Resources

30.4 Operation of Network Resources

30.5 Network Customer Redispatch

Obligation

30.6 Transmission Arrangements for

Network Resources Not Physically

Interconnected With The Transmission

Provider

30.7 Limitation on Designation of

Network Resources

30.8 Use of Interface Capacity by the

Network Customer

30.9 Network Customer Owned

Transmission Facilities

31 Designation of Network Load

31.1 Network Load

31.2 New Network Loads Connected With

the Transmission Provider

31.3 Network Load Not Physically

Interconnected with the Transmission

Provider

31.4 New Interconnection Points

31.5 Changes in Service Requests

31.6 Annual Load and Resource

Information Updates

32 Additional Study Procedures For

Network Integration Transmission

Service Requests

32.1 Notice of Need for System Impact

Study

32.2 System Impact Study Agreement and

Cost Reimbursement

32.3 System Impact Study Procedures

32.4 Facilities Study Procedures

33 Load Shedding and Curtailments

33.1 Procedures

33.2 Transmission Constraints

33.3 Cost Responsibility for Relieving

Transmission Constraints

33.4 Curtailments of Scheduled

Deliveries

33.5 Allocation of Curtailments

33.6 Load Shedding

33.7 System Reliability

34 Rates and Charges

34.1 Monthly Demand Charge

34.2 Determination of Network

Customer’s Monthly Network Load

34.3 Determination of Transmission

Provider’s Monthly Transmission System

Load

34.4 Redispatch Charge

34.5 Stranded Cost Recovery

35 Operating Arrangements

35.1 Operation under The Network

Operating Agreement

35.2 Network Operating Agreement

35.3 Network Operating Committee

Schedule 1

Scheduling, System Control and Dispatch

Service

Schedule 2

Reactive Supply and Voltage Control from

Generation Sources Service

Schedule 3

Regulation and Frequency Response

Service

Schedule 4

Energy Imbalance Service

Schedule 5

Operating Reserve—Spinning Reserve

Service

Schedule 6

Operating Reserve—Supplemental Reserve

Service

Schedule 7

Long-Term Firm and Short-Term Firm

Point-To-Point Transmission Service

Schedule 8

Non-Firm Point-To-Point Transmission

Service

Attachment A

Form of Service Agreement for Firm PointTo-Point Transmission Service

Attachment B

Form Of Service Agreement For Non-Firm

Point-To-Point Transmission Service

Attachment C

Methodology To Assess Available

Transmission Capability

Attachment D

Methodology for Completing a System

Impact Study

Attachment E

Index Of Point-To-Point Transmission

Service Customers

Attachment F

Service Agreement For Network Integration

Transmission Service

Attachment G

Network Operating Agreement

Attachment H

Annual Transmission Revenue

Requirement For Network Integration

Transmission Service

Attachment I

Index Of Network Integration Transmission

Service Customers

I. Common Service Provisions

1. Definitions

1.1 Ancillary Services: Those services

that are necessary to support the

transmission of capacity and energy from

resources to loads while maintaining reliable

operation of the Transmission Provider’s

Transmission System in accordance with

Good Utility Practice.

1.2 Annual Transmission Costs: The total

annual cost of the Transmission System for

purposes of Network Integration

Transmission Service shall be the amount

specified in Attachment H until amended by

the Transmission Provider or modified by the

Commission.

1.3 Application: A request by an Eligible

Customer for transmission service pursuant

to the provisions of the Tariff.

1.4 Commission: The Federal Energy

Regulatory Commission.

1.5 Completed Application: An

Application that satisfies all of the

information and other requirements of the

Tariff, including any required deposit.

1.6 Control Area: An electric power

system or combination of electric power

systems to which a common automatic

generation control scheme is applied in order

to:

(1) Match, at all times, the power output

of the generators within the electric power

system(s) and capacity and energy purchased

from entities outside the electric power

system(s), with the load within the electric

power system(s);
21708 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

(2) maintain scheduled interchange with

other Control Areas, within the limits of

Good Utility Practice;

(3) maintain the frequency of the electric

power system(s) within reasonable limits in

accordance with Good Utility Practice; and

(4) provide sufficient generating capacity to

maintain operating reserves in accordance

with Good Utility Practice.

1.7 Curtailment: A reduction in firm or

non-firm transmission service in response to

a transmission capacity shortage as a result

of system reliability conditions.

1.8 Delivering Party: The entity supplying

capacity and energy to be transmitted at

Point(s) of Receipt.

1.9 Designated Agent: Any entity that

performs actions or functions on behalf of the

Transmission Provider, an Eligible Customer,

or the Transmission Customer required under

the Tariff.

1.10 Direct Assignment Facilities:

Facilities or portions of facilities that are

constructed by the Transmission Provider for

the sole use/benefit of a particular

Transmission Customer requesting service

under the Tariff. Direct Assignment Facilities

shall be specified in the Service Agreement

that governs service to the Transmission

Customer and shall be subject to Commission

approval.

1.11 Eligible Customer: (i) Any electric

utility (including the Transmission Provider

and any power marketer), Federal power

marketing agency, or any person generating

electric energy for sale for resale; electric

energy sold or produced by such entity may

be electric energy produced in the United

States, Canada or Mexico; however, such

entity is not eligible for transmission service

that would be prohibited by Section 212(h)(2)

of the Federal Power Act; and (ii) any retail

customer taking unbundled Transmission

Service pursuant to a state retail access

program or pursuant to a voluntary offer of

unbundled retail transmission service by the

Transmission Provider.

1.12 Facilities Study: An engineering

study conducted by the Transmission

Provider to determine the required

modifications to the Transmission Provider’s

Transmission System, including the cost and

scheduled completion date for such

modifications, that will be required to

provide the requested transmission service.

1.13 Firm Point-To-Point Transmission

Service: Transmission Service under this

Tariff that is reserved and/or scheduled

between specified Points of Receipt and

Delivery pursuant to Part II of this Tariff.

1.14 Good Utility Practice: Any of the

practices, methods and acts engaged in or

approved by a significant portion of the

electric utility industry during the relevant

time period, or any of the practices, methods

and acts which, in the exercise of reasonable

judgment in light of the facts known at the

time the decision was made, could have been

expected to accomplish the desired result at

a reasonable cost consistent with good

business practices, reliability, safety and

expedition. Good Utility Practice is not

intended to be limited to the optimum

practice, method, or act to the exclusion of

all others, but rather to be acceptable

practices, methods, or acts generally accepted

in the region.

1.15 Interruption: A reduction in nonfirm transmission service due to economic

reasons pursuant to Section 14.7.

1.16 Load Ratio Share: Ratio of a

Transmission Customer’s Network Load to

the Transmission Provider’s total load

computed in accordance with Sections 34.2

and 34.3 of the Network Integration

Transmission Service under Part III the Tariff

and calculated on a rolling twelve month

basis.

1.17 Load Shedding: The systematic

reduction of system demand by temporarily

decreasing load in response to transmission

system or area capacity shortages, system

instability, or voltage control considerations

under Part III of the Tariff.

1.18 Long-Term Firm Point-To-Point

Transmission Service: Firm Point-To-Point

Transmission Service under Part II of the

Tariff with a term of one year or more.

1.19 Native Load Customers: The

wholesale and retail power customers of the

Transmission Provider on whose behalf the

Transmission Provider, by statute, franchise,

regulatory requirement, or contract, has

undertaken an obligation to construct and

operate the Transmission Provider’s system

to meet the reliable electric needs of such

customers.

1.20 Network Customer: An entity

receiving transmission service pursuant to

the terms of the Transmission Provider’s

Network Integration Transmission Service

under Part III of the Tariff.

1.21 Network Integration Transmission

Service: The transmission service provided

under Part III of the Tariff.

1.22 Network Load: The load that a

Network Customer designates for Network

Integration Transmission Service under Part

III of the Tariff. The Network Customer’s

Network Load shall include all load served

by the output of any Network Resources

designated by the Network Customer. A

Network Customer may elect to designate

less than its total load as Network Load but

may not designate only part of the load at a

discrete Point of Delivery. Where an Eligible

Customer has elected not to designate a

particular load at discrete points of delivery

as Network Load, the Eligible Customer is

responsible for making separate arrangements

under Part II of the Tariff for any Point-ToPoint Transmission Service that may be

necessary for such non-designated load.

1.23 Network Operating Agreement: An

executed agreement that contains the terms

and conditions under which the Network

Customer shall operate its facilities and the

technical and operational matters associated

with the implementation of Network

Integration Transmission Service under Part

III of the Tariff.

1.24 Network Operating Committee: A

group made up of representatives from the

Network Customer(s) and the Transmission

Provider established to coordinate operating

criteria and other technical considerations

required for implementation of Network

Integration Transmission Service under Part

III of this Tariff.

1.25 Network Resource: Any designated

generating resource owned or purchased by

a Network Customer under the Network

Integration Transmission Service Tariff.

Network Resources do not include any

resource, or any portion thereof, that is

committed for sale to third parties or

otherwise cannot be called upon to meet the

Network Customer’s Network Load on a noninterruptible basis.

1.26 Network Upgrades: Modifications or

additions to transmission-related facilities

that are integrated with and support the

Transmission Provider’s overall

Transmission System for the general benefit

of all users of such Transmission System.

1.27 Non-Firm Point-To-Point

Transmission Service: Point-To-Point

Transmission Service under the Tariff that is

reserved and scheduled on an as-available

basis and is subject to Curtailment or

Interruption as set forth in Section 14.7

under Part II of this Tariff. Non-Firm PointTo-Point Transmission Service is available

on a stand-alone basis for periods ranging

from one hour to one month.

1.28 Open Access Same-Time

Information System (OASIS): The

information system and standards of conduct

contained in Part 37 of the Commission’s

regulations.

1.29 Part I: Tariff Definitions and

Common Service Provisions contained in

Sections 2 through 12.

1.30 Part II: Tariff Sections 13 through 27

pertaining to Point-To-Point Transmission

Service in conjunction with the applicable

Common Service Provisions of Part I and

appropriate Schedules and Attachments.

1.31 Part III: Tariff Sections 28 through 35

pertaining to Network Integration

Transmission Service in conjunction with the

applicable Common Service Provisions of

Part I and appropriate Schedules and

Attachments.

1.32 Parties: The Transmission Provider

and the Transmission Customer receiving

service under the Tariff.

1.33 Point(s) of Delivery: Point(s) on the

Transmission Provider’s Transmission

System where capacity and energy

transmitted by the Transmission Provider

will be made available to the Receiving Party

under Part II of the Tariff. The Point(s) of

Delivery shall be specified in the Service

Agreement.

1.34 Point(s) of Receipt: Point(s) of

interconnection on the Transmission

Provider’s Transmission System where

capacity and energy will be made available

to the Transmission Provider by the

Delivering Party under Part II of the Tariff.

The Point(s) of Receipt shall be specified in

the Service Agreement.

1.35 Point-To-Point Transmission

Service: The reservation and transmission of

capacity and energy on either a firm or nonfirm basis from the Point(s) of Receipt to the

Point(s) of Delivery under Part II of the Tariff.

1.36 Power Purchaser: The entity that is

purchasing the capacity and energy to be

transmitted under the Tariff.

1.37 Receiving Party: The entity receiving

the capacity and energy transmitted by the

Transmission Provider to Point(s) of

Delivery.

1.38 Regional Transmission Group (RTG):

A voluntary organization of transmission

owners, transmission users and other entities

approved by the Commission to efficiently
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21709

coordinate transmission planning (and

expansion), operation and use on a regional

(and interregional) basis.

1.39 Reserved Capacity: The maximum

amount of capacity and energy that the

Transmission Provider agrees to transmit for

the Transmission Customer over the

Transmission Provider’s Transmission

System between the Point(s) of Receipt and

the Point(s) of Delivery under Part II of the

Tariff. Reserved Capacity shall be expressed

in terms of whole megawatts on a sixty (60)

minute interval (commencing on the clock

hour) basis.

1.40 Service Agreement: The initial

agreement and any amendments or

supplements thereto entered into by the

Transmission Customer and the

Transmission Provider for service under the

Tariff.

1.41 Service Commencement Date: The

date the Transmission Provider begins to

provide service pursuant to the terms of an

executed Service Agreement, or the date the

Transmission Provider begins to provide

service in accordance with Section 15.3 or

Section 29.1 under the Tariff.

1.42 Short-Term Firm Point-To-Point

Transmission Service: Firm Point-To-Point

Transmission Service under Part II of the

Tariff with a term of less than one year.

1.43 System Impact Study: An

assessment by the Transmission Provider of

(i) the adequacy of the Transmission System

to accommodate a request for either Firm

Point-To-Point Transmission Service or

Network Integration Transmission Service

and (ii) whether any additional costs may be

incurred in order to provide transmission

service.

1.44 Third-Party Sale: Any sale for resale

in interstate commerce to a Power Purchaser

that is not designated as part of Network

Load under the Network Integration

Transmission Service.

1.45 Transmission Customer: Any

Eligible Customer (or its Designated Agent)

that (i) executes a Service Agreement, or (ii)

requests in writing that the Transmission

Provider file with the Commission, a

proposed unexecuted Service Agreement to

receive transmission service under Part II of

the Tariff. This term is used in the Part I

Common Service Provisions to include

customers receiving transmission service

under Part II and Part III of this Tariff.

1.46 Transmission Provider: The public

utility (or its Designated Agent) that owns,

controls, or operates facilities used for the

transmission of electric energy in interstate

commerce and provides transmission service

under the Tariff.

1.47 Transmission Provider’s Monthly

Transmission System Peak: The maximum

firm usage of the Transmission Provider’s

Transmission System in a calendar month.

1.48 Transmission Service: Point-ToPoint Transmission Service provided under

Part II of the Tariff on a firm and non-firm

basis.

1.49 Transmission System: The facilities

owned, controlled or operated by the

Transmission Provider that are used to

provide transmission service under Part II

and Part III of the Tariff.

2 Initial Allocation and Renewal

Procedures

2.1 Initial Allocation of Available

Transmission Capability: For purposes of

determining whether existing capability on

the Transmission Provider’s Transmission

System is adequate to accommodate a request

for firm service under this Tariff, all

Completed Applications for new firm

transmission service received during the

initial sixty (60) day period commencing

with the effective date of the Tariff will be

deemed to have been filed simultaneously. A

lottery system conducted by an independent

party shall be used to assign priorities for

Completed Applications filed

simultaneously. All Completed Applications

for firm transmission service received after

the initial sixty (60) day period shall be

assigned a priority pursuant to Section 13.2.

2.2 Reservation Priority For Existing Firm

Service Customers: Existing firm service

customers (wholesale requirements and

transmission-only, with a contract term of

one-year or more), have the right to continue

to take transmission service from the

Transmission Provider when the contract

expires, rolls over or is renewed. This

transmission reservation priority is

independent of whether the existing

customer continues to purchase capacity and

energy from the Transmission Provider or

elects to purchase capacity and energy from

another supplier. If at the end of the contract

term, the Transmission Provider’s

Transmission System cannot accommodate

all of the requests for transmission service

the existing firm service customer must agree

to accept a contract term at least equal to a

competing request by any new Eligible

Customer and to pay the current just and

reasonable rate, as approved by the

Commission, for such service. This

transmission reservation priority for existing

firm service customers is an ongoing right

that may be exercised at the end of all firm

contract terms of one-year or longer.

3 Ancillary Services

Ancillary Services are needed with

transmission service to maintain reliability

within and among the Control Areas affected

by the transmission service. The

Transmission Provider is required to provide

(or offer to arrange with the local Control

Area operator as discussed below), and the

Transmission Customer is required to

purchase, the following Ancillary Services (i)

Scheduling, System Control and Dispatch,

and (ii) Reactive Supply and Voltage Control

from Generation Sources.

The Transmission Provider is required to

offer to provide (or offer to arrange with the

local Control Area operator as discussed

below) the following Ancillary Services only

to the Transmission Customer serving load

within the Transmission Provider’s Control

Area (i) Regulation and Frequency Response,

(ii) Energy Imbalance, (iii) Operating

Reserve—Spinning, and (iv) Operating

Reserve—Supplemental. The Transmission

Customer serving load within the

Transmission Provider’s Control Area is

required to acquire these Ancillary Services,

whether from the Transmission Provider,

from a third party, or by self-supply. The

Transmission Customer may not decline the

Transmission Provider’s offer of Ancillary

Services unless it demonstrates that it has

acquired the Ancillary Services from another

source. The Transmission Customer must list

in its Application which Ancillary Services

it will purchase from the Transmission

Provider.

If the Transmission Provider is a public

utility providing transmission service but is

not a Control Area operator, it may be unable

to provide some or all of the Ancillary

Services. In this case, the Transmission

Provider can fulfill its obligation to provide

Ancillary Services by acting as the

Transmission Customer’s agent to secure

these Ancillary Services from the Control

Area operator. The Transmission Customer

may elect to (i) have the Transmission

Provider act as its agent, (ii) secure the

Ancillary Services directly from the Control

Area operator, or (iii) secure the Ancillary

Services (discussed in Schedules 3, 4, 5 and

6) from a third party or by self-supply when

technically feasible.

The Transmission Provider shall specify

the rate treatment and all related terms and

conditions in the event of an unauthorized

use of Ancillary Services by the

Transmission Customer.

The specific Ancillary Services, prices

and/or compensation methods are described

on the Schedules that are attached to and

made a part of the Tariff. If the Transmission

Provider offers an affiliate a rate discount, or

attributes a discounted Ancillary Service rate

to its own transactions, the Transmission

Provider must offer at the same time the same

discounted Ancillary Service rate to all

Eligible Customers. Information regarding

any discounted Ancillary Service rates must

be posted on the OASIS pursuant to Part 37

of the Commission’s regulations. In addition,

discounts to non-affiliates must be offered in

a not unduly discriminatory manner.

Sections 3.1 through 3.6 below list the six

Ancillary Services.

3.1 Scheduling, System Control and

Dispatch Service: The rates and/or

methodology are described in Schedule 1.

3.2 Reactive Supply and Voltage Control

from Generation Sources Service: The rates

and/or methodology are described in

Schedule 2.

3.3 Regulation and Frequency Response

Service: Where applicable the rates and/or

methodology are described in Schedule 3.

3.4 Energy Imbalance Service: Where

applicable the rates and/or methodology are

described in Schedule 4.

3.5 Operating Reserve—Spinning Reserve

Service: Where applicable the rates and/or

methodology are described in Schedule 5.

3.6 Operating Reserve—Supplemental

Reserve Service: Where applicable the rates

and/or methodology are described in

Schedule 6.

4 Open Access Same-Time Information

System (OASIS)

Terms and conditions regarding Open

Access Same-Time Information System and

standards of conduct are set forth in 18 CFR

part 37 of the Commission’s regulations

(Open Access Same-Time Information

System and Standards of Conduct for Public
21710 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

Utilities). In the event available transmission

capability as posted on the OASIS is

insufficient to accommodate a request for

firm transmission service, additional studies

may be required as provided by this Tariff

pursuant to Sections 19 and 32.

5 Local Furnishing Bonds

5.1 Transmission Providers That Own

Facilities Financed by Local Furnishing

Bonds: This provision is applicable only to

Transmission Providers that have financed

facilities for the local furnishing of electric

energy with tax-exempt bonds, as described

in Section 142(f) of the Internal Revenue

Code (‘‘local furnishing bonds’’).

Notwithstanding any other provision of this

Tariff, the Transmission Provider shall not be

required to provide Transmission Service to

any Eligible Customer pursuant to this Tariff

if the provision of such Transmission Service

would jeopardize the tax-exempt status of

any local furnishing bond(s) used to finance

the Transmission Provider’s facilities that

would be used in providing such

Transmission Service.

5.2 Alternative Procedures for Requesting

Transmission Service:

(i) If the Transmission Provider determines

that the provision of transmission service

requested by an Eligible Customer would

jeopardize the tax-exempt status of any local

furnishing bond(s) used to finance its

facilities that would be used in providing

such transmission service, it shall advise the

Eligible Customer within thirty (30) days of

receipt of the Completed Application.

(ii) If the Eligible Customer thereafter

renews its request for the same transmission

service referred to in (i) by tendering an

application under Section 211 of the Federal

Power Act, the Transmission Provider,

within ten (10) days of receiving a copy of

the Section 211 application, will waive its

rights to a request for service under Section

213(a) of the Federal Power Act and to the

issuance of a proposed order under Section

212(c) of the Federal Power Act and shall

provide the requested transmission service in

accordance with the terms and conditions of

this Tariff.

6 Reciprocity

A Transmission Customer receiving

transmission service under this Tariff agrees

to provide comparable transmission service

to the Transmission Provider on similar

terms and conditions over facilities used for

the transmission of electric energy in

interstate commerce owned, controlled or

operated by the Transmission Customer and

over facilities used for the transmission of

electric energy in interstate commerce

owned, controlled or operated by the

Transmission Customer’s corporate affiliates.

A Transmission Customer that is a member

of a power pool or Regional Transmission

Group also agrees to provide comparable

transmission service to the members of such

power pool and Regional Transmission

Group on similar terms and conditions over

facilities used for the transmission of electric

energy in interstate commerce owned,

controlled or operated by the Transmission

Customer and over facilities used for the

transmission of electric energy in interstate

commerce owned, controlled or operated by

the Transmission Customer’s corporate

affiliates. This reciprocity requirement also

applies to any Eligible Customer that owns,

controls or operates transmission facilities

that uses an intermediary, such as a power

marketer, to request transmission service

under the Tariff. If the Transmission

Customer does not own, control or operate

transmission facilities, it must include in its

Application a sworn statement of one of its

duly authorized officers or other

representatives that the purpose of its

Application is not to assist an Eligible

Customer to avoid the requirements of this

provision.

7 Billing and Payment

7.1 Billing Procedure: Within a

reasonable time after the first day of each

month, the Transmission Provider shall

submit an invoice to the Transmission

Customer for the charges for all services

furnished under the Tariff during the

preceding month. The invoice shall be paid

by the Transmission Customer within twenty

(20) days of receipt. All payments shall be

made in immediately available funds payable

to the Transmission Provider, or by wire

transfer to a bank named by the Transmission

Provider.

7.2 Interest on Unpaid Balances: Interest

on any unpaid amounts (including amounts

placed in escrow) shall be calculated in

accordance with the methodology specified

for interest on refunds in the Commission’s

regulations at 18 CFR 35.19a(a)(2)(iii).

Interest on delinquent amounts shall be

calculated from the due date of the bill to the

date of payment. When payments are made

by mail, bills shall be considered as having

been paid on the date of receipt by the

Transmission Provider.

7.3 Customer Default: In the event the

Transmission Customer fails, for any reason

other than a billing dispute as described

below, to make payment to the Transmission

Provider on or before the due date as

described above, and such failure of payment

is not corrected within thirty (30) calendar

days after the Transmission Provider notifies

the Transmission Customer to cure such

failure, a default by the Transmission

Customer shall be deemed to exist. Upon the

occurrence of a default, the Transmission

Provider may initiate a proceeding with the

Commission to terminate service but shall

not terminate service until the Commission

so approves any such request. In the event of

a billing dispute between the Transmission

Provider and the Transmission Customer, the

Transmission Provider will continue to

provide service under the Service Agreement

as long as the Transmission Customer (i)

continues to make all payments not in

dispute, and (ii) pays into an independent

escrow account the portion of the invoice in

dispute, pending resolution of such dispute.

If the Transmission Customer fails to meet

these two requirements for continuation of

service, then the Transmission Provider may

provide notice to the Transmission Customer

of its intention to suspend service in sixty

(60) days, in accordance with Commission

policy.

8 Accounting for the Transmission

Provider’s Use of the Tariff

The Transmission Provider shall record the

following amounts, as outlined below.

8.1 Transmission Revenues: Include in a

separate operating revenue account or

subaccount the revenues it receives from

Transmission Service when making ThirdParty Sales under Part II of the Tariff.

8.2 Study Costs and Revenues: Include in

a separate transmission operating expense

account or subaccount, costs properly

chargeable to expense that are incurred to

perform any System Impact Studies or

Facilities Studies which the Transmission

Provider conducts to determine if it must

construct new transmission facilities or

upgrades necessary for its own uses,

including making Third-Party Sales under

the Tariff; and include in a separate operating

revenue account or subaccount the revenues

received for System Impact Studies or

Facilities Studies performed when such

amounts are separately stated and identified

in the Transmission Customer’s billing under

the Tariff.

9 Regulatory Filings

Nothing contained in the Tariff or any

Service Agreement shall be construed as

affecting in any way the right of the

Transmission Provider to unilaterally make

application to the Commission for a change

in rates, terms and conditions, charges,

classification of service, Service Agreement,

rule or regulation under Section 205 of the

Federal Power Act and pursuant to the

Commission’s rules and regulations

promulgated thereunder.

Nothing contained in the Tariff or any

Service Agreement shall be construed as

affecting in any way the ability of any Party

receiving service under the Tariff to exercise

its rights under the Federal Power Act and

pursuant to the Commission’s rules and

regulations promulgated thereunder.

10 Force Majeure and Indemnification

10.1 Force Majeure: An event of Force

Majeure means any act of God, labor

disturbance, act of the public enemy, war,

insurrection, riot, fire, storm or flood,

explosion, breakage or accident to machinery

or equipment, any Curtailment, order,

regulation or restriction imposed by

governmental military or lawfully established

civilian authorities, or any other cause

beyond a Party’s control. Neither the

Transmission Provider nor the Transmission

Customer will be considered in default as to

any obligation under this Tariff if prevented

from fulfilling the obligation due to an event

of Force Majeure. However, a Party whose

performance under this Tariff is hindered by

an event of Force Majeure shall make all

reasonable efforts to perform its obligations

under this Tariff.

10.2 Indemnification: The Transmission

Customer shall at all times indemnify,

defend, and save the Transmission Provider

harmless from, any and all damages, losses,

claims, including claims and actions relating

to injury to or death of any person or damage

to property, demands, suits, recoveries, costs

and expenses, court costs, attorney fees, and

all other obligations by or to third parties,
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21711

arising out of or resulting from the

Transmission Provider’s performance of its

obligations under this Tariff on behalf of the

Transmission Customer, except in cases of

negligence or intentional wrongdoing by the

Transmission Provider.

11 Creditworthiness

For the purpose of determining the ability

of the Transmission Customer to meet its

obligations related to service hereunder, the

Transmission Provider may require

reasonable credit review procedures. This

review shall be made in accordance with

standard commercial practices. In addition,

the Transmission Provider may require the

Transmission Customer to provide and

maintain in effect during the term of the

Service Agreement, an unconditional and

irrevocable letter of credit as security to meet

its responsibilities and obligations under the

Tariff, or an alternative form of security

proposed by the Transmission Customer and

acceptable to the Transmission Provider and

consistent with commercial practices

established by the Uniform Commercial Code

that protects the Transmission Provider

against the risk of non-payment.

12 Dispute Resolution Procedures

12.1 Internal Dispute Resolution

Procedures: Any dispute between a

Transmission Customer and the

Transmission Provider involving

Transmission Service under the Tariff

(excluding applications for rate changes or

other changes to the Tariff, or to any Service

Agreement entered into under the Tariff,

which shall be presented directly to the

Commission for resolution) shall be referred

to a designated senior representative of the

Transmission Provider and a senior

representative of the Transmission Customer

for resolution on an informal basis as

promptly as practicable. In the event the

designated representatives are unable to

resolve the dispute within thirty (30) days [or

such other period as the Parties may agree

upon] by mutual agreement, such dispute

may be submitted to arbitration and resolved

in accordance with the arbitration procedures

set forth below.

12.2 External Arbitration Procedures:

Any arbitration initiated under the Tariff

shall be conducted before a single neutral

arbitrator appointed by the Parties. If the

Parties fail to agree upon a single arbitrator

within ten (10) days of the referral of the

dispute to arbitration, each Party shall choose

one arbitrator who shall sit on a threemember arbitration panel. The two arbitrators

so chosen shall within twenty (20) days

select a third arbitrator to chair the

arbitration panel. In either case, the

arbitrators shall be knowledgeable in electric

utility matters, including electric

transmission and bulk power issues, and

shall not have any current or past substantial

business or financial relationships with any

party to the arbitration (except prior

arbitration). The arbitrator(s) shall provide

each of the Parties an opportunity to be heard

and, except as otherwise provided herein,

shall generally conduct the arbitration in

accordance with the Commercial Arbitration

Rules of the American Arbitration

Association and any applicable Commission

regulations or Regional Transmission Group

rules.

12.3 Arbitration Decisions: Unless

otherwise agreed, the arbitrator(s) shall

render a decision within ninety (90) days of

appointment and shall notify the Parties in

writing of such decision and the reasons

therefor. The arbitrator(s) shall be authorized

only to interpret and apply the provisions of

the Tariff and any Service Agreement entered

into under the Tariff and shall have no power

to modify or change any of the above in any

manner. The decision of the arbitrator(s)

shall be final and binding upon the Parties,

and judgment on the award may be entered

in any court having jurisdiction. The

decision of the arbitrator(s) may be appealed

solely on the grounds that the conduct of the

arbitrator(s), or the decision itself, violated

the standards set forth in the Federal

Arbitration Act and/or the Administrative

Dispute Resolution Act. The final decision of

the arbitrator must also be filed with the

Commission if it affects jurisdictional rates,

terms and conditions of service or facilities.

12.4 Costs: Each Party shall be

responsible for its own costs incurred during

the arbitration process and for the following

costs, if applicable:

(A) The cost of the arbitrator chosen by the

Party to sit on the three member panel and

one half of the cost of the third arbitrator

chosen; or

(B) One half the cost of the single arbitrator

jointly chosen by the Parties.

12.5 Rights Under the Federal Power Act:

Nothing in this section shall restrict the

rights of any party to file a Complaint with

the Commission under relevant provisions of

the Federal Power Act.

II. Point-To-Point Transmission Service

Preamble

The Transmission Provider will provide

Firm and Non-Firm Point-To-Point

Transmission Service pursuant to the

applicable terms and conditions of this

Tariff. Point-To-Point Transmission Service

is for the receipt of capacity and energy at

designated Point(s) of Receipt and the

transmission of such capacity and energy to

designated Point(s) of Delivery.

13 Nature of Firm Point-To-Point

Transmission Service

13.1 Term: The minimum term of Firm

Point-To-Point Transmission Service shall be

one day and the maximum term shall be

specified in the Service Agreement.

13.2 Reservation Priority: Long-Term

Firm Point-To-Point Transmission Service

shall be available on a first-come, first-served

basis i.e., in the chronological sequence in

which each Transmission Customer has

reserved service. Reservations for Short-Term

Firm Point-To-Point Transmission Service

will be conditional based upon the length of

the requested transaction. If the Transmission

System becomes oversubscribed, requests for

longer term service may preempt requests for

shorter term service up to the following

deadlines: one day before the commencement

of daily service, one week before the

commencement of weekly service, and one

month before the commencement of monthly

service. Before the deadline, if available

transmission capability is insufficient to

satisfy all Applications, an Eligible Customer

with a reservation for shorter term service

has the right of first refusal to match any

longer term reservation before losing its

reservation priority. After the deadline,

service will commence pursuant to the terms

of Part II of the Tariff. Firm Point-To-Point

Transmission Service will always have a

reservation priority over Non-Firm Point-ToPoint Transmission Service under the Tariff.

All Long-Term Firm Point-To-Point

Transmission Service will have equal

reservation priority with Native Load

Customers and Network Customers.

Reservation priorities for existing firm

service customers are provided in Section

2.2.

13.3 Use of Firm Transmission Service by

the Transmission Provider: The Transmission

Provider will be subject to the rates, terms

and conditions of Part II of the Tariff when

making Third-Party Sales under (i)

agreements executed on or after July 9, 1996,

or (ii) agreements executed prior to the

aforementioned date that the Commission

requires to be unbundled, by the date

specified by the Commission. The

Transmission Provider will maintain separate

accounting, pursuant to Section 8, for any

use of the Point-To-Point Transmission

Service to make Third-Party Sales.

13.4 Service Agreements: The

Transmission Provider shall offer a standard

form Firm Point-To-Point Transmission

Service Agreement (Attachment A) to an

Eligible Customer when it submits a

Completed Application for Firm Point-ToPoint Transmission Service. Executed

Service Agreements that contain the

information required under the Tariff shall be

filed with the Commission in compliance

with applicable Commission regulations.

13.5 Transmission Customer Obligations

for Facility Additions or Redispatch Costs: In

cases where the Transmission Provider

determines that the Transmission System is

not capable of providing Firm Point-To-Point

Transmission Service without (1) degrading

or impairing the reliability of service to

Native Load Customers, Network Customers

and other Transmission Customers taking

Firm Point-To-Point Transmission Service, or

(2) interfering with the Transmission

Provider’s ability to meet prior firm

contractual commitments to others, the

Transmission Provider will be obligated to

expand or upgrade its Transmission System

pursuant to the terms of Section 15.4. The

Transmission Customer must agree to

compensate the Transmission Provider for

any necessary transmission facility additions

pursuant to the terms of Section 27. To the

extent the Transmission Provider can relieve

any system constraint more economically by

redispatching the Transmission Provider’s

resources than through constructing Network

Upgrades, it shall do so, provided that the

Eligible Customer agrees to compensate the

Transmission Provider pursuant to the terms

of Section 27. Any redispatch, Network

Upgrade or Direct Assignment Facilities costs

to be charged to the Transmission Customer

under the Tariff will be specified in the

Service Agreement prior to initiating service.
21712 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

13.6 Curtailment of Firm Transmission

Service: In the event that a Curtailment on

the Transmission Provider’s Transmission

System, or a portion thereof, is required to

maintain reliable operation of such system,

Curtailments will be made on a nondiscriminatory basis to the transaction(s) that

effectively relieve the constraint. If multiple

transactions require Curtailment, to the

extent practicable and consistent with Good

Utility Practice, Curtailments will be

proportionally allocated among the

Transmission Provider’s Native Load

Customers, Network Customers, and

Transmission Customers taking Firm PointTo-Point Transmission Service. All

Curtailments will be made on a nondiscriminatory basis, however, Non-Firm

Point-To-Point Transmission Service shall be

subordinate to Firm Transmission Service.

When the Transmission Provider determines

that an electrical emergency exists on its

Transmission System and implements

emergency procedures to Curtail Firm

Transmission Service, the Transmission

Customer shall make the required reductions

upon request of the Transmission Provider.

However, the Transmission Provider reserves

the right to Curtail, in whole or in part, any

Firm Transmission Service provided under

the Tariff when, in the Transmission

Provider’s sole discretion, an emergency or

other unforeseen condition impairs or

degrades the reliability of its Transmission

System. The Transmission Provider will

notify all affected Transmission Customers in

a timely manner of any scheduled

Curtailments.

13.7 Classification of Firm Transmission

Service:

(a) The Transmission Customer taking Firm

Point-To-Point Transmission Service may (1)

change its Receipt and Delivery Points to

obtain service on a non-firm basis consistent

with the terms of Section 22.1 or (2) request

a modification of the Points of Receipt or

Delivery on a firm basis pursuant to the terms

of Section 22.2.

(b) The Transmission Customer may

purchase transmission service to make sales

of capacity and energy from multiple

generating units that are on the Transmission

Provider’s Transmission System. For such a

purchase of transmission service, the

resources will be designated as multiple

Points of Receipt, unless the multiple

generating units are at the same generating

plant in which case the units would be

treated as a single Point of Receipt.

(c) The Transmission Provider shall

provide firm deliveries of capacity and

energy from the Point(s) of Receipt to the

Point(s) of Delivery. Each Point of Receipt at

which firm transmission capacity is reserved

by the Transmission Customer shall be set

forth in the Firm Point-To-Point Service

Agreement along with a corresponding

capacity reservation associated with each

Point of Receipt. Each Point of Delivery at

which firm transmission capacity is reserved

by the Transmission Customer shall be set

forth in the Firm Point-To-Point Service

Agreement along with a corresponding

capacity reservation associated with each

Point of Delivery. The greater of either (1) the

sum of the capacity reservations at the

Point(s) of Receipt, or (2) the sum of the

capacity reservations at the Point(s) of

Delivery shall be the Transmission

Customer’s Reserved Capacity. The

Transmission Customer will be billed for its

Reserved Capacity under the terms of

Schedule 7. The Transmission Customer may

not exceed its firm capacity reserved at each

Point of Receipt and each Point of Delivery

except as otherwise specified in Section 22.

The Transmission Provider shall specify the

rate treatment and all related terms and

conditions applicable in the event that a

Transmission Customer (including ThirdParty Sales by the Transmission Provider)

exceeds its firm reserved capacity at any

Point of Receipt or Point of Delivery.

13.8 Scheduling of Firm Point-To-Point

Transmission Service: Schedules for the

Transmission Customer’s Firm Point-ToPoint Transmission Service must be

submitted to the Transmission Provider no

later than 10:00 a.m. [or a reasonable time

that is generally accepted in the region and

is consistently adhered to by the

Transmission Provider] of the day prior to

commencement of such service. Schedules

submitted after 10:00 a.m. will be

accommodated, if practicable. Hour-to-hour

schedules of any capacity and energy that is

to be delivered must be stated in increments

of 1,000 kW per hour (or a reasonable

increment that is generally accepted in the

region and is consistently adhered to by the

Transmission Provider). Transmission

Customers within the Transmission

Provider’s service area with multiple requests

for Transmission Service at a Point of

Receipt, each of which is under 1,000 kW per

hour, may consolidate their service requests

at a common point of receipt into units of

1,000 kW per hour for scheduling and billing

purposes. Scheduling changes will be

permitted up to twenty (20) minutes (or a

reasonable time that is generally accepted in

the region and is consistently adhered to by

the Transmission Provider) before the start of

the next clock hour provided that the

Delivering Party and Receiving Party also

agree to the schedule modification. The

Transmission Provider will furnish to the

Delivering Party’s system operator, hour-tohour schedules equal to those furnished by

the Receiving Party (unless reduced for

losses) and shall deliver the capacity and

energy provided by such schedules. Should

the Transmission Customer, Delivering Party

or Receiving Party revise or terminate any

schedule, such party shall immediately

notify the Transmission Provider, and the

Transmission Provider shall have the right to

adjust accordingly the schedule for capacity

and energy to be received and to be

delivered.

14 Nature of Non-Firm Point-To-Point

Transmission Service

14.1 Term: Non-Firm Point-To-Point

Transmission Service will be available for

periods ranging from one (1) hour to one (1)

month. However, a Purchaser of Non-Firm

Point-To-Point Transmission Service will be

entitled to reserve a sequential term of

service (such as a sequential monthly term

without having to wait for the initial term to

expire before requesting another monthly

term) so that the total time period for which

the reservation applies is greater than one

month, subject to the requirements of Section

18.3.

14.2 Reservation Priority: Non-Firm

Point-To-Point Transmission Service shall be

available from transmission capability in

excess of that needed for reliable service to

Native Load Customers, Network Customers

and other Transmission Customers taking

Long-Term and Short-Term Firm Point-ToPoint Transmission Service. A higher priority

will be assigned to reservations with a longer

duration of service. In the event the

Transmission System is constrained,

competing requests of equal duration will be

prioritized based on the highest price offered

by the Eligible Customer for the

Transmission Service. Eligible Customers

that have already reserved shorter term

service have the right of first refusal to match

any longer term reservation before being

preempted. Transmission service for Network

Customers from resources other than

designated Network Resources will have a

higher priority than any Non-Firm Point-ToPoint Transmission Service. Non-Firm PointTo-Point Transmission Service over

secondary Point(s) of Receipt and Point(s) of

Delivery will have the lowest reservation

priority under the Tariff.

14.3 Use of Non-Firm Point-To-Point

Transmission Service by the Transmission

Provider: The Transmission Provider will be

subject to the rates, terms and conditions of

Part II of the Tariff when making Third-Party

Sales under (i) agreements executed on or

after July 9, 1996 or (ii) agreements executed

prior to the aforementioned date that the

Commission requires to be unbundled, by the

date specified by the Commission. The

Transmission Provider will maintain separate

accounting, pursuant to Section 8, for any

use of Non-Firm Point-To-Point

Transmission Service to make Third-Party

Sales.

14.4 Service Agreements: The

Transmission Provider shall offer a standard

form Non-Firm Point-To-Point Transmission

Service Agreement (Attachment B) to an

Eligible Customer when it first submits a

Completed Application for Non-Firm PointTo-Point Transmission Service pursuant to

the Tariff. Executed Service Agreements that

contain the information required under the

Tariff shall be filed with the Commission in

compliance with applicable Commission

regulations.

14.5 Classification of Non-Firm Point-ToPoint Transmission Service: Non-Firm PointTo-Point Transmission Service shall be

offered under terms and conditions

contained in Part II of the Tariff. The

Transmission Provider undertakes no

obligation under the Tariff to plan its

Transmission System in order to have

sufficient capacity for Non-Firm Point-ToPoint Transmission Service. Parties

requesting Non-Firm Point-To-Point

Transmission Service for the transmission of

firm power do so with the full realization

that such service is subject to availability and

to Curtailment or Interruption under the

terms of the Tariff. The Transmission

Provider shall specify the rate treatment and

all related terms and conditions applicable in
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21713

the event that a Transmission Customer

(including Third-Party Sales by the

Transmission Provider) exceeds its non-firm

capacity reservation. Non-Firm Point-ToPoint Transmission Service shall include

transmission of energy on an hourly basis

and transmission of scheduled short-term

capacity and energy on a daily, weekly or

monthly basis, but not to exceed one month’s

reservation for any one Application, under

Schedule 8.

14.6 Scheduling of Non-Firm Point-ToPoint Transmission Service: Schedules for

Non-Firm Point-To-Point Transmission

Service must be submitted to the

Transmission Provider no later than 2:00

p.m. [or a reasonable time that is generally

accepted in the region and is consistently

adhered to by the Transmission Provider] of

the day prior to commencement of such

service. Schedules submitted after 2:00 p.m.

will be accommodated, if practicable. Hourto-hour schedules of energy that is to be

delivered must be stated in increments of

1,000 kW per hour [or a reasonable increment

that is generally accepted in the region and

is consistently adhered to by the

Transmission Provider]. Transmission

Customers within the Transmission

Provider’s service area with multiple requests

for Transmission Service at a Point of

Receipt, each of which is under 1,000 kW per

hour, may consolidate their schedules at a

common Point of Receipt into units of 1,000

kW per hour. Scheduling changes will be

permitted up to twenty (20) minutes [or a

reasonable time that is generally accepted in

the region and is consistently adhered to by

the Transmission Provider] before the start of

the next clock hour provided that the

Delivering Party and Receiving Party also

agree to the schedule modification. The

Transmission Provider will furnish to the

Delivering Party’s system operator, hour-tohour schedules equal to those furnished by

the Receiving Party (unless reduced for

losses) and shall deliver the capacity and

energy provided by such schedules. Should

the Transmission Customer, Delivering Party

or Receiving Party revise or terminate any

schedule, such party shall immediately

notify the Transmission Provider, and the

Transmission Provider shall have the right to

adjust accordingly the schedule for capacity

and energy to be received and to be

delivered.

14.7 Curtailment or Interruption of

Service: The Transmission Provider reserves

the right to Curtail, in whole or in part, NonFirm Point-To-Point Transmission Service

provided under the Tariff for reliability

reasons when, an emergency or other

unforeseen condition threatens to impair or

degrade the reliability of its Transmission

System. The Transmission Provider reserves

the right to Interrupt, in whole or in part,

Non-Firm Point-To-Point Transmission

Service provided under the Tariff for

economic reasons in order to accommodate

(1) a request for Firm Transmission Service,

(2) a request for Non-Firm Point-To-Point

Transmission Service of greater duration, (3)

a request for Non-Firm Point-To-Point

Transmission Service of equal duration with

a higher price, or (4) transmission service for

Network Customers from non-designated

resources. The Transmission Provider also

will discontinue or reduce service to the

Transmission Customer to the extent that

deliveries for transmission are discontinued

or reduced at the Point(s) of Receipt. Where

required, Curtailments or Interruptions will

be made on a non-discriminatory basis to the

transaction(s) that effectively relieve the

constraint, however, Non-Firm Point-ToPoint Transmission Service shall be

subordinate to Firm Transmission Service. If

multiple transactions require Curtailment or

Interruption, to the extent practicable and

consistent with Good Utility Practice,

Curtailments or Interruptions will be made to

transactions of the shortest term (e.g., hourly

non-firm transactions will be Curtailed or

Interrupted before daily non-firm

transactions and daily non-firm transactions

will be Curtailed or Interrupted before

weekly non-firm transactions). Transmission

service for Network Customers from

resources other than designated Network

Resources will have a higher priority than

any Non-Firm Point-To-Point Transmission

Service under the Tariff. Non-Firm Point-ToPoint Transmission Service over secondary

Point(s) of Receipt and Point(s) of Delivery

will have a lower priority than any Non-Firm

Point-To-Point Transmission Service under

the Tariff. The Transmission Provider will

provide advance notice of Curtailment or

Interruption where such notice can be

provided consistent with Good Utility

Practice.

15 Service Availability

15.1 General Conditions: The

Transmission Provider will provide Firm and

Non-Firm Point-To-Point Transmission

Service over, on or across its Transmission

System to any Transmission Customer that

has met the requirements of Section 16.

15.2 Determination of Available

Transmission Capability: A description of the

Transmission Provider’s specific

methodology for assessing available

transmission capability posted on the

Transmission Provider’s OASIS (Section 4) is

contained in Attachment C of the Tariff. In

the event sufficient transmission capability

may not exist to accommodate a service

request, the Transmission Provider will

respond by performing a System Impact

Study.

15.3 Initiating Service in the Absence of

an Executed Service Agreement: If the

Transmission Provider and the Transmission

Customer requesting Firm or Non-Firm PointTo-Point Transmission Service cannot agree

on all the terms and conditions of the PointTo-Point Service Agreement, the

Transmission Provider shall file with the

Commission, within thirty (30) days after the

date the Transmission Customer provides

written notification directing the

Transmission Provider to file, an unexecuted

Point-To-Point Service Agreement containing

terms and conditions deemed appropriate by

the Transmission Provider for such requested

Transmission Service. The Transmission

Provider shall commence providing

Transmission Service subject to the

Transmission Customer agreeing to (i)

compensate the Transmission Provider at

whatever rate the Commission ultimately

determines to be just and reasonable, and (ii)

comply with the terms and conditions of the

Tariff including posting appropriate security

deposits in accordance with the terms of

Section 17.3.

15.4 Obligation to Provide Transmission

Service that Requires Expansion or

Modification of the Transmission System: If

the Transmission Provider determines that it

cannot accommodate a Completed

Application for Firm Point-To-Point

Transmission Service because of insufficient

capability on its Transmission System, the

Transmission Provider will use due diligence

to expand or modify its Transmission System

to provide the requested Firm Transmission

Service, provided the Transmission Customer

agrees to compensate the Transmission

Provider for such costs pursuant to the terms

of Section 27. The Transmission Provider

will conform to Good Utility Practice in

determining the need for new facilities and

in the design and construction of such

facilities. The obligation applies only to those

facilities that the Transmission Provider has

the right to expand or modify.

15.5 Deferral of Service: The

Transmission Provider may defer providing

service until it completes construction of

new transmission facilities or upgrades

needed to provide Firm Point-To-Point

Transmission Service whenever the

Transmission Provider determines that

providing the requested service would,

without such new facilities or upgrades,

impair or degrade reliability to any existing

firm services.

15.6 Other Transmission Service

Schedules: Eligible Customers receiving

transmission service under other agreements

on file with the Commission may continue to

receive transmission service under those

agreements until such time as those

agreements may be modified by the

Commission.

15.7 Real Power Losses: Real Power

Losses are associated with all transmission

service. The Transmission Provider is not

obligated to provide Real Power Losses. The

Transmission Customer is responsible for

replacing losses associated with all

transmission service as calculated by the

Transmission Provider. The applicable Real

Power Loss factors are as follows: [To be

completed by the Transmission Provider].

16 Transmission Customer Responsibilities

16.1 Conditions Required of

Transmission Customers: Point-To-Point

Transmission Service shall be provided by

the Transmission Provider only if the

following conditions are satisfied by the

Transmission Customer:

a. The Transmission Customer has pending

a Completed Application for service;

b. The Transmission Customer meets the

creditworthiness criteria set forth in Section

11;

c. The Transmission Customer will have

arrangements in place for any other

transmission service necessary to effect the

delivery from the generating source to the

Transmission Provider prior to the time

service under Part II of the Tariff commences;

d. The Transmission Customer agrees to

pay for any facilities constructed and
21714 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

chargeable to such Transmission Customer

under Part II of the Tariff, whether or not the

Transmission Customer takes service for the

full term of its reservation; and

e. The Transmission Customer has

executed a Point-To-Point Service Agreement

or has agreed to receive service pursuant to

Section 15.3.

16.2 Transmission Customer

Responsibility for Third-Party Arrangements:

Any scheduling arrangements that may be

required by other electric systems shall be

the responsibility of the Transmission

Customer requesting service. The

Transmission Customer shall provide, unless

waived by the Transmission Provider,

notification to the Transmission Provider

identifying such systems and authorizing

them to schedule the capacity and energy to

be transmitted by the Transmission Provider

pursuant to Part II of the Tariff on behalf of

the Receiving Party at the Point of Delivery

or the Delivering Party at the Point of

Receipt. However, the Transmission Provider

will undertake reasonable efforts to assist the

Transmission Customer in making such

arrangements, including without limitation,

providing any information or data required

by such other electric system pursuant to

Good Utility Practice.

17 Procedures for Arranging Firm Point-ToPoint Transmission Service

17.1 Application: A request for Firm

Point-To-Point Transmission Service for

periods of one year or longer must contain a

written Application to: [Transmission

Provider Name and Address], at least sixty

(60) days in advance of the calendar month

in which service is to commence. The

Transmission Provider will consider requests

for such firm service on shorter notice when

feasible. Requests for firm service for periods

of less than one year shall be subject to

expedited procedures that shall be negotiated

between the Parties within the time

constraints provided in Section 17.5. All

Firm Point-To-Point Transmission Service

requests should be submitted by entering the

information listed below on the Transmission

Provider’s OASIS. Prior to implementation of

the Transmission Provider’s OASIS, a

Completed Application may be submitted by

(i) transmitting the required information to

the Transmission Provider by telefax, or (ii)

providing the information by telephone over

the Transmission Provider’s time recorded

telephone line. Each of these methods will

provide a time-stamped record for

establishing the priority of the Application.

17.2 Completed Application: A

Completed Application shall provide all of

the information included in 18 CFR § 2.20

including but not limited to the following:

(i) The identity, address, telephone number

and facsimile number of the entity requesting

service;

(ii) A statement that the entity requesting

service is, or will be upon commencement of

service, an Eligible Customer under the

Tariff;

(iii) The location of the Point(s) of Receipt

and Point(s) of Delivery and the identities of

the Delivering Parties and the Receiving

Parties;

(iv) The location of the generating

facility(ies) supplying the capacity and

energy and the location of the load ultimately

served by the capacity and energy

transmitted. The Transmission Provider will

treat this information as confidential except

to the extent that disclosure of this

information is required by this Tariff, by

regulatory or judicial order, for reliability

purposes pursuant to Good Utility Practice or

pursuant to RTG transmission information

sharing agreements. The Transmission

Provider shall treat this information

consistent with the standards of conduct

contained in Part 37 of the Commission’s

regulations;

(v) A description of the supply

characteristics of the capacity and energy to

be delivered;

(vi) An estimate of the capacity and energy

expected to be delivered to the Receiving

Party;

(vii) The Service Commencement Date and

the term of the requested Transmission

Service; and

(viii) The transmission capacity requested

for each Point of Receipt and each Point of

Delivery on the Transmission Provider’s

Transmission System; customers may

combine their requests for service in order to

satisfy the minimum transmission capacity

requirement.

The Transmission Provider shall treat this

information consistent with the standards of

conduct contained in Part 37 of the

Commission’s regulations.

17.3 Deposit: A Completed Application

for Firm Point-To-Point Transmission Service

also shall include a deposit of either one

month’s charge for Reserved Capacity or the

full charge for Reserved Capacity for service

requests of less than one month. If the

Application is rejected by the Transmission

Provider because it does not meet the

conditions for service as set forth herein, or

in the case of requests for service arising in

connection with losing bidders in a Request

For Proposals (RFP), said deposit shall be

returned with interest less any reasonable

costs incurred by the Transmission Provider

in connection with the review of the losing

bidder’s Application. The deposit also will

be returned with interest less any reasonable

costs incurred by the Transmission Provider

if the Transmission Provider is unable to

complete new facilities needed to provide the

service. If an Application is withdrawn or the

Eligible Customer decides not to enter into a

Service Agreement for Firm Point-To-Point

Transmission Service, the deposit shall be

refunded in full, with interest, less

reasonable costs incurred by the

Transmission Provider to the extent such

costs have not already been recovered by the

Transmission Provider from the Eligible

Customer. The Transmission Provider will

provide to the Eligible Customer a complete

accounting of all costs deducted from the

refunded deposit, which the Eligible

Customer may contest if there is a dispute

concerning the deducted costs. Deposits

associated with construction of new facilities

are subject to the provisions of Section 19. If

a Service Agreement for Firm Point-To-Point

Transmission Service is executed, the

deposit, with interest, will be returned to the

Transmission Customer upon expiration of

the Service Agreement for Firm Point-ToPoint Transmission Service. Applicable

interest shall be computed in accordance

with the Commission’s regulations at 18 CFR

§ 35.19a(a)(2)(iii), and shall be calculated

from the day the deposit check is credited to

the Transmission Provider’s account.

17.4 Notice of Deficient Application: If an

Application fails to meet the requirements of

the Tariff, the Transmission Provider shall

notify the entity requesting service within

fifteen (15) days of receipt of the reasons for

such failure. The Transmission Provider will

attempt to remedy minor deficiencies in the

Application through informal

communications with the Eligible Customer.

If such efforts are unsuccessful, the

Transmission Provider shall return the

Application, along with any deposit, with

interest. Upon receipt of a new or revised

Application that fully complies with the

requirements of Part II of the Tariff, the

Eligible Customer shall be assigned a new

priority consistent with the date of the new

or revised Application.

17.5 Response to a Completed

Application: Following receipt of a

Completed Application for Firm Point-ToPoint Transmission Service, the

Transmission Provider shall make a

determination of available transmission

capability as required in Section 15.2. The

Transmission Provider shall notify the

Eligible Customer as soon as practicable, but

not later than thirty (30) days after the date

of receipt of a Completed Application either

(i) if it will be able to provide service without

performing a System Impact Study or (ii) if

such a study is needed to evaluate the impact

of the Application pursuant to Section 19.1.

17.6 Execution of Service Agreement:

Whenever the Transmission Provider

determines that a System Impact Study is not

required and that the service can be

provided, it shall notify the Eligible

Customer as soon as practicable but no later

than thirty (30) days after receipt of the

Completed Application. Where a System

Impact Study is required, the provisions of

Section 19 will govern the execution of a

Service Agreement. Failure of an Eligible

Customer to execute and return the Service

Agreement or request the filing of an

unexecuted service agreement pursuant to

Section 15.3, within fifteen (15) days after it

is tendered by the Transmission Provider

will be deemed a withdrawal and

termination of the Application and any

deposit submitted shall be refunded with

interest. Nothing herein limits the right of an

Eligible Customer to file another Application

after such withdrawal and termination.

17.7 Extensions for Commencement of

Service: The Transmission Customer can

obtain up to five (5) one-year extensions for

the commencement of service. The

Transmission Customer may postpone

service by paying a non-refundable annual

reservation fee equal to one-month’s charge

for Firm Transmission Service for each year

or fraction thereof. If during any extension

for the commencement of service an Eligible

Customer submits a Completed Application

for Firm Transmission Service, and such

request can be satisfied only by releasing all

or part of the Transmission Customer’s

Reserved Capacity, the original Reserved
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21715

Capacity will be released unless the

following condition is satisfied. Within thirty

(30) days, the original Transmission

Customer agrees to pay the Firm Point-ToPoint transmission rate for its Reserved

Capacity concurrent with the new Service

Commencement Date. In the event the

Transmission Customer elects to release the

Reserved Capacity, the reservation fees or

portions thereof previously paid will be

forfeited.

18 Procedures for Arranging Non-Firm

Point-To-Point Transmission Service

18.1 Application: Eligible Customers

seeking Non-Firm Point-To-Point

Transmission Service must submit a

Completed Application to the Transmission

Provider. Applications should be submitted

by entering the information listed below on

the Transmission Provider’s OASIS. Prior to

implementation of the Transmission

Provider’s OASIS, a Completed Application

may be submitted by (i) transmitting the

required information to the Transmission

Provider by telefax, or (ii) providing the

information by telephone over the

Transmission Provider’s time recorded

telephone line. Each of these methods will

provide a time-stamped record for

establishing the service priority of the

Application.

18.2 Completed Application: A

Completed Application shall provide all of

the information included in 18 CFR § 2.20

including but not limited to the following:

(i) The identity, address, telephone number

and facsimile number of the entity requesting

service;

(ii) A statement that the entity requesting

service is, or will be upon commencement of

service, an Eligible Customer under the

Tariff;

(iii) The Point(s) of Receipt and the Point(s)

of Delivery;

(iv) The maximum amount of capacity

requested at each Point of Receipt and Point

of Delivery; and

(v) The proposed dates and hours for

initiating and terminating transmission

service hereunder.

In addition to the information specified

above, when required to properly evaluate

system conditions, the Transmission

Provider also may ask the Transmission

Customer to provide the following:

(vi) The electrical location of the initial

source of the power to be transmitted

pursuant to the Transmission Customer’s

request for service; and

(vii) The electrical location of the ultimate

load.

The Transmission Provider will treat this

information in (vi) and (vii) as confidential

at the request of the Transmission Customer

except to the extent that disclosure of this

information is required by this Tariff, by

regulatory or judicial order, for reliability

purposes pursuant to Good Utility Practice,

or pursuant to RTG transmission information

sharing agreements. The Transmission

Provider shall treat this information

consistent with the standards of conduct

contained in Part 37 of the Commission’s

regulations.

18.3 Reservation of Non-Firm Point-ToPoint Transmission Service: Requests for

monthly service shall be submitted no earlier

than sixty (60) days before service is to

commence; requests for weekly service shall

be submitted no earlier than fourteen (14)

days before service is to commence, requests

for daily service shall be submitted no earlier

than two (2) days before service is to

commence, and requests for hourly service

shall be submitted no earlier than noon the

day before service is to commence. Requests

for service received later than 2:00 p.m. prior

to the day service is scheduled to commence

will be accommodated if practicable [or such

reasonable times that are generally accepted

in the region and are consistently adhered to

by the Transmission Provider].

18.4 Determination of Available

Transmission Capability: Following receipt

of a tendered schedule the Transmission

Provider will make a determination on a nondiscriminatory basis of available

transmission capability pursuant to Section

15.2. Such determination shall be made as

soon as reasonably practicable after receipt,

but not later than the following time periods

for the following terms of service (i) thirty

(30) minutes for hourly service, (ii) thirty (30)

minutes for daily service, (iii) four (4) hours

for weekly service, and (iv) two (2) days for

monthly service. [Or such reasonable times

that are generally accepted in the region and

are consistently adhered to by the

Transmission Provider].

19 Additional Study Procedures for Firm

Point-To-Point Transmission Service

Requests

19.1 Notice of Need for System Impact

Study: After receiving a request for service,

the Transmission Provider shall determine

on a non-discriminatory basis whether a

System Impact Study is needed. A

description of the Transmission Provider’s

methodology for completing a System Impact

Study is provided in Attachment D. If the

Transmission Provider determines that a

System Impact Study is necessary to

accommodate the requested service, it shall

so inform the Eligible Customer, as soon as

practicable. In such cases, the Transmission

Provider shall within thirty (30) days of

receipt of a Completed Application, tender a

System Impact Study Agreement pursuant to

which the Eligible Customer shall agree to

reimburse the Transmission Provider for

performing the required System Impact

Study. For a service request to remain a

Completed Application, the Eligible

Customer shall execute the System Impact

Study Agreement and return it to the

Transmission Provider within fifteen (15)

days. If the Eligible Customer elects not to

execute the System Impact Study Agreement,

its application shall be deemed withdrawn

and its deposit, pursuant to Section 17.3,

shall be returned with interest.

19.2 System Impact Study Agreement and

Cost Reimbursement:

(i) The System Impact Study Agreement

will clearly specify the maximum charge,

based on the Transmission Provider’s

estimate of the actual cost, and time for

completion of the System Impact Study. The

charge shall not exceed the actual cost of the

study. In performing the System Impact

Study, the Transmission Provider shall rely,

to the extent reasonably practicable, on

existing transmission planning studies. The

Eligible Customer will not be assessed a

charge for such existing studies; however, the

Eligible Customer will be responsible for

charges associated with any modifications to

existing planning studies that are reasonably

necessary to evaluate the impact of the

Eligible Customer’s request for service on the

Transmission System.

(ii) If in response to multiple Eligible

Customers requesting service in relation to

the same competitive solicitation, a single

System Impact Study is sufficient for the

Transmission Provider to accommodate the

requests for service, the costs of that study

shall be pro-rated among the Eligible

Customers.

(iii) For System Impact Studies that the

Transmission Provider conducts on its own

behalf, the Transmission Provider shall

record the cost of the System Impact Studies

pursuant to Section 20.

19.3 System Impact Study Procedures:

Upon receipt of an executed System Impact

Study Agreement, the Transmission Provider

will use due diligence to complete the

required System Impact Study within a sixty

(60) day period. The System Impact Study

shall identify any system constraints and

redispatch options, additional Direct

Assignment Facilities or Network Upgrades

required to provide the requested service. In

the event that the Transmission Provider is

unable to complete the required System

Impact Study within such time period, it

shall so notify the Eligible Customer and

provide an estimated completion date along

with an explanation of the reasons why

additional time is required to complete the

required studies. A copy of the completed

System Impact Study and related work

papers shall be made available to the Eligible

Customer. The Transmission Provider will

use the same due diligence in completing the

System Impact Study for an Eligible

Customer as it uses when completing studies

for itself. The Transmission Provider shall

notify the Eligible Customer immediately

upon completion of the System Impact Study

if the Transmission System will be adequate

to accommodate all or part of a request for

service or that no costs are likely to be

incurred for new transmission facilities or

upgrades. In order for a request to remain a

Completed Application, within fifteen (15)

days of completion of the System Impact

Study the Eligible Customer must execute a

Service Agreement or request the filing of an

unexecuted Service Agreement pursuant to

Section 15.3, or the Application shall be

deemed terminated and withdrawn.

19.4 Facilities Study Procedures: If a

System Impact Study indicates that additions

or upgrades to the Transmission System are

needed to supply the Eligible Customer’s

service request, the Transmission Provider,

within thirty (30) days of the completion of

the System Impact Study, shall tender to the

Eligible Customer a Facilities Study

Agreement pursuant to which the Eligible

Customer shall agree to reimburse the

Transmission Provider for performing the

required Facilities Study. For a service

request to remain a Completed Application,

the Eligible Customer shall execute the
21716 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

Facilities Study Agreement and return it to

the Transmission Provider within fifteen (15)

days. If the Eligible Customer elects not to

execute the Facilities Study Agreement, its

application shall be deemed withdrawn and

its deposit, pursuant to Section 17.3, shall be

returned with interest. Upon receipt of an

executed Facilities Study Agreement, the

Transmission Provider will use due diligence

to complete the required Facilities Study

within a sixty (60) day period. If the

Transmission Provider is unable to complete

the Facilities Study in the allotted time

period, the Transmission Provider shall

notify the Transmission Customer and

provide an estimate of the time needed to

reach a final determination along with an

explanation of the reasons that additional

time is required to complete the study. When

completed, the Facilities Study will include

a good faith estimate of (i) the cost of Direct

Assignment Facilities to be charged to the

Transmission Customer, (ii) the Transmission

Customer’s appropriate share of the cost of

any required Network Upgrades as

determined pursuant to the provisions of Part

II of the Tariff, and (iii) the time required to

complete such construction and initiate the

requested service. The Transmission

Customer shall provide the Transmission

Provider with a letter of credit or other

reasonable form of security acceptable to the

Transmission Provider equivalent to the costs

of new facilities or upgrades consistent with

commercial practices as established by the

Uniform Commercial Code. The

Transmission Customer shall have thirty (30)

days to execute a Service Agreement or

request the filing of an unexecuted Service

Agreement and provide the required letter of

credit or other form of security or the request

will no longer be a Completed Application

and shall be deemed terminated and

withdrawn.

19.5 Facilities Study Modifications: Any

change in design arising from inability to site

or construct facilities as proposed will

require development of a revised good faith

estimate. New good faith estimates also will

be required in the event of new statutory or

regulatory requirements that are effective

before the completion of construction or

other circumstances beyond the control of

the Transmission Provider that significantly

affect the final cost of new facilities or

upgrades to be charged to the Transmission

Customer pursuant to the provisions of Part

II of the Tariff.

19.6 Due Diligence in Completing New

Facilities: The Transmission Provider shall

use due diligence to add necessary facilities

or upgrade its Transmission System within a

reasonable time. The Transmission Provider

will not upgrade its existing or planned

Transmission System in order to provide the

requested Firm Point-To-Point Transmission

Service if doing so would impair system

reliability or otherwise impair or degrade

existing firm service.

19.7 Partial Interim Service: If the

Transmission Provider determines that it will

not have adequate transmission capability to

satisfy the full amount of a Completed

Application for Firm Point-To-Point

Transmission Service, the Transmission

Provider nonetheless shall be obligated to

offer and provide the portion of the requested

Firm Point-To-Point Transmission Service

that can be accommodated without addition

of any facilities and through redispatch.

However, the Transmission Provider shall

not be obligated to provide the incremental

amount of requested Firm Point-To-Point

Transmission Service that requires the

addition of facilities or upgrades to the

Transmission System until such facilities or

upgrades have been placed in service.

19.8 Expedited Procedures for New

Facilities: In lieu of the procedures set forth

above, the Eligible Customer shall have the

option to expedite the process by requesting

the Transmission Provider to tender at one

time, together with the results of required

studies, an ‘‘Expedited Service Agreement’’

pursuant to which the Eligible Customer

would agree to compensate the Transmission

Provider for all costs incurred pursuant to the

terms of the Tariff. In order to exercise this

option, the Eligible Customer shall request in

writing an expedited Service Agreement

covering all of the above-specified items

within thirty (30) days of receiving the

results of the System Impact Study

identifying needed facility additions or

upgrades or costs incurred in providing the

requested service. While the Transmission

Provider agrees to provide the Eligible

Customer with its best estimate of the new

facility costs and other charges that may be

incurred, such estimate shall not be binding

and the Eligible Customer must agree in

writing to compensate the Transmission

Provider for all costs incurred pursuant to the

provisions of the Tariff. The Eligible

Customer shall execute and return such an

Expedited Service Agreement within fifteen

(15) days of its receipt or the Eligible

Customer’s request for service will cease to

be a Completed Application and will be

deemed terminated and withdrawn.

20 Procedures if the Transmission Provider

is Unable to Complete New Transmission

Facilities for Firm Point-To-Point

Transmission Service

20.1 Delays in Construction of New

Facilities: If any event occurs that will

materially affect the time for completion of

new facilities, or the ability to complete

them, the Transmission Provider shall

promptly notify the Transmission Customer.

In such circumstances, the Transmission

Provider shall within thirty (30) days of

notifying the Transmission Customer of such

delays, convene a technical meeting with the

Transmission Customer to evaluate the

alternatives available to the Transmission

Customer. The Transmission Provider also

shall make available to the Transmission

Customer studies and work papers related to

the delay, including all information that is in

the possession of the Transmission Provider

that is reasonably needed by the

Transmission Customer to evaluate any

alternatives.

20.2 Alternatives to the Original Facility

Additions: When the review process of

Section determines that one or more

alternatives exist to the originally planned

construction project, the Transmission

Provider shall present such alternatives for

consideration by the Transmission Customer.

If, upon review of any alternatives, the

Transmission Customer desires to maintain

its Completed Application subject to

construction of the alternative facilities, it

may request the Transmission Provider to

submit a revised Service Agreement for Firm

Point-To-Point Transmission Service. If the

alternative approach solely involves NonFirm Point-To-Point Transmission Service,

the Transmission Provider shall promptly

tender a Service Agreement for Non-Firm

Point-To-Point Transmission Service

providing for the service. In the event the

Transmission Provider concludes that no

reasonable alternative exists and the

Transmission Customer disagrees, the

Transmission Customer may seek relief

under the dispute resolution procedures

pursuant to Section 12 or it may refer the

dispute to the Commission for resolution.

20.3 Refund Obligation for Unfinished

Facility Additions: If the Transmission

Provider and the Transmission Customer

mutually agree that no other reasonable

alternatives exist and the requested service

cannot be provided out of existing capability

under the conditions of Part II of the Tariff,

the obligation to provide the requested Firm

Point-To-Point Transmission Service shall

terminate and any deposit made by the

Transmission Customer shall be returned

with interest pursuant to Commission

regulations 35.19a(a)(2)(iii). However, the

Transmission Customer shall be responsible

for all prudently incurred costs by the

Transmission Provider through the time

construction was suspended.

21 Provisions Relating to Transmission

Construction and Services on the Systems of

Other Utilities

21.1 Responsibility for Third-Party

System Additions: The Transmission

Provider shall not be responsible for making

arrangements for any necessary engineering,

permitting, and construction of transmission

or distribution facilities on the system(s) of

any other entity or for obtaining any

regulatory approval for such facilities. The

Transmission Provider will undertake

reasonable efforts to assist the Transmission

Customer in obtaining such arrangements,

including without limitation, providing any

information or data required by such other

electric system pursuant to Good Utility

Practice.

21.2 Coordination of Third-Party System

Additions: In circumstances where the need

for transmission facilities or upgrades is

identified pursuant to the provisions of Part

II of the Tariff, and if such upgrades further

require the addition of transmission facilities

on other systems, the Transmission Provider

shall have the right to coordinate

construction on its own system with the

construction required by others. The

Transmission Provider, after consultation

with the Transmission Customer and

representatives of such other systems, may

defer construction of its new transmission

facilities, if the new transmission facilities on

another system cannot be completed in a

timely manner. The Transmission Provider

shall notify the Transmission Customer in

writing of the basis for any decision to defer

construction and the specific problems
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21717

which must be resolved before it will initiate

or resume construction of new facilities.

Within sixty (60) days of receiving written

notification by the Transmission Provider of

its intent to defer construction pursuant to

this section, the Transmission Customer may

challenge the decision in accordance with

the dispute resolution procedures pursuant

to Section 12 or it may refer the dispute to

the Commission for resolution.

22 Changes in Service Specifications

22.1 Modifications On a Non-Firm Basis:

The Transmission Customer taking Firm

Point-To-Point Transmission Service may

request the Transmission Provider to provide

transmission service on a non-firm basis over

Receipt and Delivery Points other than those

specified in the Service Agreement

(‘‘Secondary Receipt and Delivery Points’’),

in amounts not to exceed its firm capacity

reservation, without incurring an additional

Non-Firm Point-To-Point Transmission

Service charge or executing a new Service

Agreement, subject to the following

conditions.

(a) Service provided over Secondary

Receipt and Delivery Points will be non-firm

only, on an as-available basis and will not

displace any firm or non-firm service

reserved or scheduled by third-parties under

the Tariff or by the Transmission Provider on

behalf of its Native Load Customers.

(b) The sum of all Firm and non-firm PointTo-Point Transmission Service provided to

the Transmission Customer at any time

pursuant to this section shall not exceed the

Reserved Capacity in the relevant Service

Agreement under which such services are

provided.

(c) The Transmission Customer shall retain

its right to schedule Firm Point-To-Point

Transmission Service at the Receipt and

Delivery Points specified in the relevant

Service Agreement in the amount of its

original capacity reservation.

(d) Service over Secondary Receipt and

Delivery Points on a non-firm basis shall not

require the filing of an Application for NonFirm Point-To-Point Transmission Service

under the Tariff. However, all other

requirements of Part II of the Tariff (except

as to transmission rates) shall apply to

transmission service on a non-firm basis over

Secondary Receipt and Delivery Points.

22.2 Modification On a Firm Basis: Any

request by a Transmission Customer to

modify Receipt and Delivery Points on a firm

basis shall be treated as a new request for

service in accordance with Section 17 hereof,

except that such Transmission Customer

shall not be obligated to pay any additional

deposit if the capacity reservation does not

exceed the amount reserved in the existing

Service Agreement. While such new request

is pending, the Transmission Customer shall

retain its priority for service at the existing

firm Receipt and Delivery Points specified in

its Service Agreement.

23 Sale or Assignment of Transmission

Service

23.1 Procedures for Assignment or

Transfer of Service: Subject to Commission

approval of any necessary filings, a

Transmission Customer may sell, assign, or

transfer all or a portion of its rights under its

Service Agreement, but only to another

Eligible Customer (the Assignee). The

Transmission Customer that sells, assigns or

transfers its rights under its Service

Agreement is hereafter referred to as the

Reseller. Compensation to the Reseller shall

not exceed the higher of (i) the original rate

paid by the Reseller, (ii) the Transmission

Provider’s maximum rate on file at the time

of the assignment, or (iii) the Reseller’s

opportunity cost. If the Assignee does not

request any change in the Point(s) of Receipt

or the Point(s) of Delivery, or a change in any

other term or condition set forth in the

original Service Agreement, the Assignee will

receive the same services as did the Reseller

and the priority of service for the Assignee

will be the same as that of the Reseller. A

Reseller should notify the Transmission

Provider as soon as possible after any

assignment or transfer of service occurs but

in any event, notification must be provided

prior to any provision of service to the

Assignee. The Assignee will be subject to all

terms and conditions of this Tariff. If the

Assignee requests a change in service, the

reservation priority of service will be

determined by the Transmission Provider

pursuant to Section 13.2.

23.2 Limitations on Assignment or

Transfer of Service: If the Assignee requests

a change in the Point(s) of Receipt or Point(s)

of Delivery, or a change in any other

specifications set forth in the original Service

Agreement, the Transmission Provider will

consent to such change subject to the

provisions of the Tariff, provided that the

change will not impair the operation and

reliability of the Transmission Provider’s

generation, transmission, or distribution

systems. The Assignee shall compensate the

Transmission Provider for performing any

System Impact Study needed to evaluate the

capability of the Transmission System to

accommodate the proposed change and any

additional costs resulting from such change.

The Reseller shall remain liable for the

performance of all obligations under the

Service Agreement, except as specifically

agreed to by the Parties through an

amendment to the Service Agreement.

23.3 Information on Assignment or

Transfer of Service: In accordance with

Section 4, Resellers may use the

Transmission Provider’s OASIS to post

transmission capacity available for resale.

24 Metering and Power Factor Correction at

Receipt and Delivery Points(s)

24.1 Transmission Customer Obligations:

Unless otherwise agreed, the Transmission

Customer shall be responsible for installing

and maintaining compatible metering and

communications equipment to accurately

account for the capacity and energy being

transmitted under Part II of the Tariff and to

communicate the information to the

Transmission Provider. Such equipment

shall remain the property of the

Transmission Customer.

24.2 Transmission Provider Access to

Metering Data: The Transmission Provider

shall have access to metering data, which

may reasonably be required to facilitate

measurements and billing under the Service

Agreement.

24.3 Power Factor: Unless otherwise

agreed, the Transmission Customer is

required to maintain a power factor within

the same range as the Transmission Provider

pursuant to Good Utility Practices. The

power factor requirements are specified in

the Service Agreement where applicable.

25 Compensation for Transmission Service

Rates for Firm and Non-Firm Point-ToPoint Transmission Service are provided in

the Schedules appended to the Tariff: Firm

Point-To-Point Transmission Service

(Schedule 7); and Non-Firm Point-To-Point

Transmission Service (Schedule 8). The

Transmission Provider shall use Part II of the

Tariff to make its Third-Party Sales. The

Transmission Provider shall account for such

use at the applicable Tariff rates, pursuant to

Section 8.

26 Stranded Cost Recovery

The Transmission Provider may seek to

recover stranded costs from the Transmission

Customer pursuant to this Tariff in

accordance with the terms, conditions and

procedures set forth in FERC Order No. 888.

However, the Transmission Provider must

separately file any specific proposed

stranded cost charge under Section 205 of the

Federal Power Act.

27 Compensation for New Facilities and

Redispatch Costs

Whenever a System Impact Study

performed by the Transmission Provider in

connection with the provision of Firm PointTo-Point Transmission Service identifies the

need for new facilities, the Transmission

Customer shall be responsible for such costs

to the extent consistent with Commission

policy. Whenever a System Impact Study

performed by the Transmission Provider

identifies capacity constraints that may be

relieved more economically by redispatching

the Transmission Provider’s resources than

by building new facilities or upgrading

existing facilities to eliminate such

constraints, the Transmission Customer shall

be responsible for the redispatch costs to the

extent consistent with Commission policy.

III. Network Integration Transmission

Service

Preamble

The Transmission Provider will provide

Network Integration Transmission Service

pursuant to the applicable terms and

conditions contained in the Tariff and

Service Agreement. Network Integration

Transmission Service allows the Network

Customer to integrate, economically dispatch

and regulate its current and planned Network

Resources to serve its Network Load in a

manner comparable to that in which the

Transmission Provider utilizes its

Transmission System to serve its Native Load

Customers. Network Integration

Transmission Service also may be used by

the Network Customer to deliver economy

energy purchases to its Network Load from

non-designated resources on an as-available

basis without additional charge.

Transmission service for sales to nondesignated loads will be provided pursuant

to the applicable terms and conditions of Part

II of the Tariff.
21718 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

28 Nature of Network Integration

Transmission Service

28.1 Scope of Service: Network

Integration Transmission Service is a

transmission service that allows Network

Customers to efficiently and economically

utilize their Network Resources (as well as

other non-designated generation resources) to

serve their Network Load located in the

Transmission Provider’s Control Area and

any additional load that may be designated

pursuant to Section 31.3 of the Tariff. The

Network Customer taking Network

Integration Transmission Service must obtain

or provide Ancillary Services pursuant to

Section 3.

28.2 Transmission Provider

Responsibilities: The Transmission Provider

will plan, construct, operate and maintain its

Transmission System in accordance with

Good Utility Practice in order to provide the

Network Customer with Network Integration

Transmission Service over the Transmission

Provider’s Transmission System. The

Transmission Provider, on behalf of its

Native Load Customers, shall be required to

designate resources and loads in the same

manner as any Network Customer under Part

III of this Tariff. This information must be

consistent with the information used by the

Transmission Provider to calculate available

transmission capability. The Transmission

Provider shall include the Network

Customer’s Network Load in its Transmission

System planning and shall, consistent with

Good Utility Practice, endeavor to construct

and place into service sufficient transmission

capacity to deliver the Network Customer’s

Network Resources to serve its Network Load

on a basis comparable to the Transmission

Provider’s delivery of its own generating and

purchased resources to its Native Load

Customers.

28.3 Network Integration Transmission

Service: The Transmission Provider will

provide firm transmission service over its

Transmission System to the Network

Customer for the delivery of capacity and

energy from its designated Network

Resources to service its Network Loads on a

basis that is comparable to the Transmission

Provider’s use of the Transmission System to

reliably serve its Native Load Customers.

28.4 Secondary Service: The Network

Customer may use the Transmission

Provider’s Transmission System to deliver

energy to its Network Loads from resources

that have not been designated as Network

Resources. Such energy shall be transmitted,

on an as-available basis, at no additional

charge. Deliveries from resources other than

Network Resources will have a higher

priority than any Non-Firm Point-To-Point

Transmission Service under Part II of the

Tariff.

28.5 Real Power Losses: Real Power

Losses are associated with all transmission

service. The Transmission Provider is not

obligated to provide Real Power Losses. The

Network Customer is responsible for

replacing losses associated with all

transmission service as calculated by the

Transmission Provider. The applicable Real

Power Loss factors are as follows: [To be

completed by the Transmission Provider].

28.6 Restrictions on Use of Service: The

Network Customer shall not use Network

Integration Transmission Service for (i) sales

of capacity and energy to non-designated

loads, or (ii) direct or indirect provision of

transmission service by the Network

Customer to third parties. All Network

Customers taking Network Integration

Transmission Service shall use Point-ToPoint Transmission Service under Part II of

the Tariff for any Third-Party Sale which

requires use of the Transmission Provider’s

Transmission System.

29 Initiating Service

29.1 Condition Precedent for Receiving

Service: Subject to the terms and conditions

of Part III of the Tariff, the Transmission

Provider will provide Network Integration

Transmission Service to any Eligible

Customer, provided that (i) the Eligible

Customer completes an Application for

service as provided under Part III of the

Tariff, (ii) the Eligible Customer and the

Transmission Provider complete the

technical arrangements set forth in Sections

29.3 and 29.4, (iii) the Eligible Customer

executes a Service Agreement pursuant to

Attachment F for service under Part III of the

Tariff or requests in writing that the

Transmission Provider file a proposed

unexecuted Service Agreement with the

Commission, and (iv) the Eligible Customer

executes a Network Operating Agreement

with the Transmission Provider pursuant to

Attachment G.

29.2 Application Procedures: An Eligible

Customer requesting service under Part III of

the Tariff must submit an Application, with

a deposit approximating the charge for one

month of service, to the Transmission

Provider as far as possible in advance of the

month in which service is to commence.

Unless subject to the procedures in Section

2, Completed Applications for Network

Integration Transmission Service will be

assigned a priority according to the date and

time the Application is received, with the

earliest Application receiving the highest

priority. Applications should be submitted

by entering the information listed below on

the Transmission Provider’s OASIS. Prior to

implementation of the Transmission

Provider’s OASIS, a Completed Application

may be submitted by (i) transmitting the

required information to the Transmission

Provider by telefax, or (ii) providing the

information by telephone over the

Transmission Provider’s time recorded

telephone line. Each of these methods will

provide a time-stamped record for

establishing the service priority of the

Application. A Completed Application shall

provide all of the information included in 18

CFR § 2.20 including but not limited to the

following:

(i) The identity, address, telephone number

and facsimile number of the party requesting

service;

(ii) A statement that the party requesting

service is, or will be upon commencement of

service, an Eligible Customer under the

Tariff;

(iii) A description of the Network Load at

each delivery point. This description should

separately identify and provide the Eligible

Customer’s best estimate of the total loads to

be served at each transmission voltage level,

and the loads to be served from each

Transmission Provider substation at the same

transmission voltage level. The description

should include a ten (10) year forecast of

summer and winter load and resource

requirements beginning with the first year

after the service is scheduled to commence;

(iv) The amount and location of any

interruptible loads included in the Network

Load. This shall include the summer and

winter capacity requirements for each

interruptible load (had such load not been

interruptible), that portion of the load subject

to interruption, the conditions under which

an interruption can be implemented and any

limitations on the amount and frequency of

interruptions. An Eligible Customer should

identify the amount of interruptible customer

load (if any) included in the 10 year load

forecast provided in response to (iii) above;

(v) A description of Network Resources

(current and 10-year projection), which shall

include, for each Network Resource:

—Unit size and amount of capacity from that

unit to be designated as Network Resource

—VAR capability (both leading and lagging)

of all generators

—Operating restrictions

—Any periods of restricted operations

throughout the year

—Maintenance schedules

—Minimum loading level of unit

—Normal operating level of unit

—Any must-run unit designations required

for system reliability or contract reasons

—Approximate variable generating cost ($/

MWH) for redispatch computations

—Arrangements governing sale and delivery

of power to third parties from generating

facilities located in the Transmission

Provider Control Area, where only a

portion of unit output is designated as a

Network Resource

—Description of purchased power designated

as a Network Resource including source of

supply, Control Area location,

transmission arrangements and delivery

point(s) to the Transmission Provider’s

Transmission System;

(vi) Description of Eligible Customer’s

transmission system:

—Load flow and stability data, such as real

and reactive parts of the load, lines,

transformers, reactive devices and load

type, including normal and emergency

ratings of all transmission equipment in a

load flow format compatible with that used

by the Transmission Provider

—Operating restrictions needed for reliability

—Operating guides employed by system

operators

—Contractual restrictions or committed uses

of the Eligible Customer’s transmission

system, other than the Eligible Customer’s

Network Loads and Resources

—Location of Network Resources described

in subsection (v) above

—10 year projection of system expansions or

upgrades

—Transmission System maps that include

any proposed expansions or upgrades

—Thermal ratings of Eligible Customer’s

Control Area ties with other Control Areas;

and

(vii) Service Commencement Date and the

term of the requested Network Integration
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21719

Transmission Service. The minimum term for

Network Integration Transmission Service is

one year.

Unless the Parties agree to a different time

frame, the Transmission Provider must

acknowledge the request within ten (10) days

of receipt. The acknowledgement must

include a date by which a response,

including a Service Agreement, will be sent

to the Eligible Customer. If an Application

fails to meet the requirements of this section,

the Transmission Provider shall notify the

Eligible Customer requesting service within

fifteen (15) days of receipt and specify the

reasons for such failure. Wherever possible,

the Transmission Provider will attempt to

remedy deficiencies in the Application

through informal communications with the

Eligible Customer. If such efforts are

unsuccessful, the Transmission Provider

shall return the Application without

prejudice to the Eligible Customer filing a

new or revised Application that fully

complies with the requirements of this

section. The Eligible Customer will be

assigned a new priority consistent with the

date of the new or revised Application. The

Transmission Provider shall treat this

information consistent with the standards of

conduct contained in Part 37 of the

Commission’s regulations.

29.3 Technical Arrangements to be

Completed Prior to Commencement of

Service: Network Integration Transmission

Service shall not commence until the

Transmission Provider and the Network

Customer, or a third party, have completed

installation of all equipment specified under

the Network Operating Agreement consistent

with Good Utility Practice and any additional

requirements reasonably and consistently

imposed to ensure the reliable operation of

the Transmission System. The Transmission

Provider shall exercise reasonable efforts, in

coordination with the Network Customer, to

complete such arrangements as soon as

practicable taking into consideration the

Service Commencement Date.

29.4 Network Customer Facilities: The

provision of Network Integration

Transmission Service shall be conditioned

upon the Network Customer’s constructing,

maintaining and operating the facilities on its

side of each delivery point or interconnection

necessary to reliably deliver capacity and

energy from the Transmission Provider’s

Transmission System to the Network

Customer. The Network Customer shall be

solely responsible for constructing or

installing all facilities on the Network

Customer’s side of each such delivery point

or interconnection.

29.5 Filing of Service Agreement: The

Transmission Provider will file Service

Agreements with the Commission in

compliance with applicable Commission

regulations.

Network Resources

30.1 Designation of Network Resources:

Network Resources shall include all

generation owned or purchased by the

Network Customer designated to serve

Network Load under the Tariff. Network

Resources may not include resources, or any

portion thereof, that are committed for sale

to non-designated third party load or

otherwise cannot be called upon to meet the

Network Customer’s Network Load on a noninterruptible basis. Any owned or purchased

resources that were serving the Network

Customer’s loads under firm agreements

entered into on or before the Service

Commencement Date shall initially be

designated as Network Resources until the

Network Customer terminates the

designation of such resources.

30.2 Designation of New Network

Resources: The Network Customer may

designate a new Network Resource by

providing the Transmission Provider with as

much advance notice as practicable. A

designation of a new Network Resource must

be made by a request for modification of

service pursuant to an Application under

Section 29.

30.3 Termination of Network Resources:

The Network Customer may terminate the

designation of all or part of a generating

resource as a Network Resource at any time

but should provide notification to the

Transmission Provider as soon as reasonably

practicable.

30.4 Operation of Network Resources:

The Network Customer shall not operate its

designated Network Resources located in the

Network Customer’s or Transmission

Provider’s Control Area such that the output

of those facilities exceeds its designated

Network Load plus losses.

30.5 Network Customer Redispatch

Obligation: As a condition to receiving

Network Integration Transmission Service,

the Network Customer agrees to redispatch

its Network Resources as requested by the

Transmission Provider pursuant to Section

33.2. To the extent practical, the redispatch

of resources pursuant to this section shall be

on a least cost, non-discriminatory basis

between all Network Customers, and the

Transmission Provider.

30.6 Transmission Arrangements for

Network Resources Not Physically

Interconnected With The Transmission

Provider: The Network Customer shall be

responsible for any arrangements necessary

to deliver capacity and energy from a

Network Resource not physically

interconnected with the Transmission

Provider’s Transmission System. The

Transmission Provider will undertake

reasonable efforts to assist the Network

Customer in obtaining such arrangements,

including without limitation, providing any

information or data required by such other

entity pursuant to Good Utility Practice.

30.7 Limitation on Designation of

Network Resources: The Network Customer

must demonstrate that it owns or has

committed to purchase generation pursuant

to an executed contract in order to designate

a generating resource as a Network Resource.

Alternatively, the Network Customer may

establish that execution of a contract is

contingent upon the availability of

transmission service under Part III of the

Tariff.

30.8 Use of Interface Capacity by the

Network Customer: There is no limitation

upon a Network Customer’s use of the

Transmission Provider’s Transmission

System at any particular interface to integrate

the Network Customer’s Network Resources

(or substitute economy purchases) with its

Network Loads. However, a Network

Customer’s use of the Transmission

Provider’s total interface capacity with other

transmission systems may not exceed the

Network Customer’s Load Ratio Share.

30.9 Network Customer Owned

Transmission Facilities: The Network

Customer that owns existing transmission

facilities that are integrated with the

Transmission Provider’s Transmission

System may be eligible to receive

consideration either through a billing credit

or some other mechanism. In order to receive

such consideration the Network Customer

must demonstrate that its transmission

facilities are integrated into the planning and

operations of the Transmission Provider to

serve all of its power and transmission

customers. For facilities constructed by the

Network Customer subsequent to the Service

Commencement Date under Part III of the

Tariff, the Network Customer shall receive

credit where such facilities are jointly

planned and installed in coordination with

the Transmission Provider. Calculation of the

credit shall be addressed in either the

Network Customer’s Service Agreement or

any other agreement between the Parties.

31 Designation of Network Load

31.1 Network Load: The Network

Customer must designate the individual

Network Loads on whose behalf the

Transmission Provider will provide Network

Integration Transmission Service. The

Network Loads shall be specified in the

Service Agreement.

31.2 New Network Loads Connected With

the Transmission Provider: The Network

Customer shall provide the Transmission

Provider with as much advance notice as

reasonably practicable of the designation of

new Network Load that will be added to its

Transmission System. A designation of new

Network Load must be made through a

modification of service pursuant to a new

Application. The Transmission Provider will

use due diligence to install any transmission

facilities required to interconnect a new

Network Load designated by the Network

Customer. The costs of new facilities

required to interconnect a new Network Load

shall be determined in accordance with the

procedures provided in Section 32.4 and

shall be charged to the Network Customer in

accordance with Commission policies.

31.3 Network Load Not Physically

Interconnected with the Transmission

Provider: This section applies to both initial

designation pursuant to Section 31.1 and the

subsequent addition of new Network Load

not physically interconnected with the

Transmission Provider. To the extent that the

Network Customer desires to obtain

transmission service for a load outside the

Transmission Provider’s Transmission

System, the Network Customer shall have the

option of (1) electing to include the entire

load as Network Load for all purposes under

Part III of the Tariff and designating Network

Resources in connection with such

additional Network Load, or (2) excluding

that entire load from its Network Load and

purchasing Point-To-Point Transmission
21720 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

Service under Part II of the Tariff. To the

extent that the Network Customer gives

notice of its intent to add a new Network

Load as part of its Network Load pursuant to

this section the request must be made

through a modification of service pursuant to

a new Application.

31.4 New Interconnection Points: To the

extent the Network Customer desires to add

a new Delivery Point or interconnection

point between the Transmission Provider’s

Transmission System and a Network Load,

the Network Customer shall provide the

Transmission Provider with as much advance

notice as reasonably practicable.

31.5 Changes in Service Requests: Under

no circumstances shall the Network

Customer’s decision to cancel or delay a

requested change in Network Integration

Transmission Service (e.g. the addition of a

new Network Resource or designation of a

new Network Load) in any way relieve the

Network Customer of its obligation to pay the

costs of transmission facilities constructed by

the Transmission Provider and charged to the

Network Customer as reflected in the Service

Agreement. However, the Transmission

Provider must treat any requested change in

Network Integration Transmission Service in

a non-discriminatory manner.

31.6 Annual Load and Resource

Information Updates: The Network Customer

shall provide the Transmission Provider with

annual updates of Network Load and

Network Resource forecasts consistent with

those included in its Application for Network

Integration Transmission Service under Part

III of the Tariff. The Network Customer also

shall provide the Transmission Provider with

timely written notice of material changes in

any other information provided in its

Application relating to the Network

Customer’s Network Load, Network

Resources, its transmission system or other

aspects of its facilities or operations affecting

the Transmission Provider’s ability to

provide reliable service.

32 Additional Study Procedures for

Network Integration Transmission Service

Requests

32.1 Notice of Need for System Impact

Study: After receiving a request for service,

the Transmission Provider shall determine

on a non-discriminatory basis whether a

System Impact Study is needed. A

description of the Transmission Provider’s

methodology for completing a System Impact

Study is provided in Attachment D. If the

Transmission Provider determines that a

System Impact Study is necessary to

accommodate the requested service, it shall

so inform the Eligible Customer, as soon as

practicable. In such cases, the Transmission

Provider shall within thirty (30) days of

receipt of a Completed Application, tender a

System Impact Study Agreement pursuant to

which the Eligible Customer shall agree to

reimburse the Transmission Provider for

performing the required System Impact

Study. For a service request to remain a

Completed Application, the Eligible

Customer shall execute the System Impact

Study Agreement and return it to the

Transmission Provider within fifteen (15)

days. If the Eligible Customer elects not to

execute the System Impact Study Agreement,

its Application shall be deemed withdrawn

and its deposit shall be returned with

interest.

32.2 System Impact Study Agreement and

Cost Reimbursement:

(i) The System Impact Study Agreement

will clearly specify the maximum charge,

based on the Transmission Provider’s

estimate of the actual cost, and time for

completion of the System Impact Study. The

charge shall not exceed the actual cost of the

study. In performing the System Impact

Study, the Transmission Provider shall rely,

to the extent reasonably practicable, on

existing transmission planning studies. The

Eligible Customer will not be assessed a

charge for such existing studies; however, the

Eligible Customer will be responsible for

charges associated with any modifications to

existing planning studies that are reasonably

necessary to evaluate the impact of the

Eligible Customer’s request for service on the

Transmission System.

(ii) If in response to multiple Eligible

Customers requesting service in relation to

the same competitive solicitation, a single

System Impact Study is sufficient for the

Transmission Provider to accommodate the

service requests, the costs of that study shall

be pro-rated among the Eligible Customers.

(iii) For System Impact Studies that the

Transmission Provider conducts on its own

behalf, the Transmission Provider shall

record the cost of the System Impact Studies

pursuant to Section 8.

32.3 System Impact Study Procedures:

Upon receipt of an executed System Impact

Study Agreement, the Transmission Provider

will use due diligence to complete the

required System Impact Study within a sixty

(60) day period. The System Impact Study

shall identify any system constraints and

redispatch options, additional Direct

Assignment Facilities or Network Upgrades

required to provide the requested service. In

the event that the Transmission Provider is

unable to complete the required System

Impact Study within such time period, it

shall so notify the Eligible Customer and

provide an estimated completion date along

with an explanation of the reasons why

additional time is required to complete the

required studies. A copy of the completed

System Impact Study and related work

papers shall be made available to the Eligible

Customer. The Transmission Provider will

use the same due diligence in completing the

System Impact Study for an Eligible

Customer as it uses when completing studies

for itself. The Transmission Provider shall

notify the Eligible Customer immediately

upon completion of the System Impact Study

if the Transmission System will be adequate

to accommodate all or part of a request for

service or that no costs are likely to be

incurred for new transmission facilities or

upgrades. In order for a request to remain a

Completed Application, within fifteen (15)

days of completion of the System Impact

Study the Eligible Customer must execute a

Service Agreement or request the filing of an

unexecuted Service Agreement, or the

Application shall be deemed terminated and

withdrawn.

32.4 Facilities Study Procedures: If a

System Impact Study indicates that additions

or upgrades to the Transmission System are

needed to supply the Eligible Customer’s

service request, the Transmission Provider,

within thirty (30) days of the completion of

the System Impact Study, shall tender to the

Eligible Customer a Facilities Study

Agreement pursuant to which the Eligible

Customer shall agree to reimburse the

Transmission Provider for performing the

required Facilities Study. For a service

request to remain a Completed Application,

the Eligible Customer shall execute the

Facilities Study Agreement and return it to

the Transmission Provider within fifteen (15)

days. If the Eligible Customer elects not to

execute the Facilities Study Agreement, its

Application shall be deemed withdrawn and

its deposit shall be returned with interest.

Upon receipt of an executed Facilities Study

Agreement, the Transmission Provider will

use due diligence to complete the required

Facilities Study within a sixty (60) day

period. If the Transmission Provider is

unable to complete the Facilities Study in the

allotted time period, the Transmission

Provider shall notify the Eligible Customer

and provide an estimate of the time needed

to reach a final determination along with an

explanation of the reasons that additional

time is required to complete the study. When

completed, the Facilities Study will include

a good faith estimate of (i) the cost of Direct

Assignment Facilities to be charged to the

Eligible Customer, (ii) the Eligible Customer’s

appropriate share of the cost of any required

Network Upgrades, and (iii) the time required

to complete such construction and initiate

the requested service. The Eligible Customer

shall provide the Transmission Provider with

a letter of credit or other reasonable form of

security acceptable to the Transmission

Provider equivalent to the costs of new

facilities or upgrades consistent with

commercial practices as established by the

Uniform Commercial Code. The Eligible

Customer shall have thirty (30) days to

execute a Service Agreement or request the

filing of an unexecuted Service Agreement

and provide the required letter of credit or

other form of security or the request no

longer will be a Completed Application and

shall be deemed terminated and withdrawn.

33 Load Shedding and Curtailments

33.1 Procedures: Prior to the Service

Commencement Date, the Transmission

Provider and the Network Customer shall

establish Load Shedding and Curtailment

procedures pursuant to the Network

Operating Agreement with the objective of

responding to contingencies on the

Transmission System. The Parties will

implement such programs during any period

when the Transmission Provider determines

that a system contingency exists and such

procedures are necessary to alleviate such

contingency. The Transmission Provider will

notify all affected Network Customers in a

timely manner of any scheduled Curtailment.

33.2 Transmission Constraints: During

any period when the Transmission Provider

determines that a transmission constraint

exists on the Transmission System, and such

constraint may impair the reliability of the

Transmission Provider’s system, the

Transmission Provider will take whatever
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21721

actions, consistent with Good Utility

Practice, that are reasonably necessary to

maintain the reliability of the Transmission

Provider’s system. To the extent the

Transmission Provider determines that the

reliability of the Transmission System can be

maintained by redispatching resources, the

Transmission Provider will initiate

procedures pursuant to the Network

Operating Agreement to redispatch all

Network Resources and the Transmission

Provider’s own resources on a least-cost basis

without regard to the ownership of such

resources. Any redispatch under this section

may not unduly discriminate between the

Transmission Provider’s use of the

Transmission System on behalf of its Native

Load Customers and any Network Customer’s

use of the Transmission System to serve its

designated Network Load.

33.3 Cost Responsibility for Relieving

Transmission Constraints: Whenever the

Transmission Provider implements least-cost

redispatch procedures in response to a

transmission constraint, the Transmission

Provider and Network Customers will each

bear a proportionate share of the total

redispatch cost based on their respective

Load Ratio Shares.

33.4 Curtailments of Scheduled

Deliveries: If a transmission constraint on the

Transmission Provider’s Transmission

System cannot be relieved through the

implementation of least-cost redispatch

procedures and the Transmission Provider

determines that it is necessary to Curtail

scheduled deliveries, the Parties shall Curtail

such schedules in accordance with the

Network Operating Agreement.

33.5 Allocation of Curtailments: The

Transmission Provider shall, on a nondiscriminatory basis, Curtail the

transaction(s) that effectively relieve the

constraint. However, to the extent practicable

and consistent with Good Utility Practice,

any Curtailment will be shared by the

Transmission Provider and Network

Customer in proportion to their respective

Load Ratio Shares. The Transmission

Provider shall not direct the Network

Customer to Curtail schedules to an extent

greater than the Transmission Provider

would Curtail the Transmission Provider’s

schedules under similar circumstances.

33.6 Load Shedding: To the extent that a

system contingency exists on the

Transmission Provider’s Transmission

System and the Transmission Provider

determines that it is necessary for the

Transmission Provider and the Network

Customer to shed load, the Parties shall shed

load in accordance with previously

established procedures under the Network

Operating Agreement.

33.7 System Reliability: Notwithstanding

any other provisions of this Tariff, the

Transmission Provider reserves the right,

consistent with Good Utility Practice and on

a not unduly discriminatory basis, to Curtail

Network Integration Transmission Service

without liability on the Transmission

Provider’s part for the purpose of making

necessary adjustments to, changes in, or

repairs on its lines, substations and facilities,

and in cases where the continuance of

Network Integration Transmission Service

would endanger persons or property. In the

event of any adverse condition(s) or

disturbance(s) on the Transmission

Provider’s Transmission System or on any

other system(s) directly or indirectly

interconnected with the Transmission

Provider’s Transmission System, the

Transmission Provider, consistent with Good

Utility Practice, also may Curtail Network

Integration Transmission Service in order to

(i) limit the extent or damage of the adverse

condition(s) or disturbance(s), (ii) prevent

damage to generating or transmission

facilities, or (iii) expedite restoration of

service. The Transmission Provider will give

the Network Customer as much advance

notice as is practicable in the event of such

Curtailment. Any Curtailment of Network

Integration Transmission Service will be not

unduly discriminatory relative to the

Transmission Provider’s use of the

Transmission System on behalf of its Native

Load Customers. The Transmission Provider

shall specify the rate treatment and all

related terms and conditions applicable in

the event that the Network Customer fails to

respond to established Load Shedding and

Curtailment procedures.

34 Rates and Charges

The Network Customer shall pay the

Transmission Provider for any Direct

Assignment Facilities, Ancillary Services,

and applicable study costs, consistent with

Commission policy, along with the following:

34.1 Monthly Demand Charge: The

Network Customer shall pay a monthly

Demand Charge, which shall be determined

by multiplying its Load Ratio Share times

one twelfth (1⁄12) of the Transmission

Provider’s Annual Transmission Revenue

Requirement specified in Schedule H.

34.2 Determination of Network

Customer’s Monthly Network Load: The

Network Customer’s monthly Network Load

is its hourly load (including its designated

Network Load not physically interconnected

with the Transmission Provider under

Section 31.3) coincident with the

Transmission Provider’s Monthly

Transmission System Peak.

34.3 Determination of Transmission

Provider’s Monthly Transmission System

Load: The Transmission Provider’s monthly

Transmission System load is the

Transmission Provider’s Monthly

Transmission System Peak minus the

coincident peak usage of all Firm Point-ToPoint Transmission Service customers

pursuant to Part II of this Tariff plus the

Reserved Capacity of all Firm Point-To-Point

Transmission Service customers.

34.4 Redispatch Charge: The Network

Customer shall pay a Load Ratio Share of any

redispatch costs allocated between the

Network Customer and the Transmission

Provider pursuant to Section 33. To the

extent that the Transmission Provider incurs

an obligation to the Network Customer for

redispatch costs in accordance with Section

33, such amounts shall be credited against

the Network Customer’s bill for the

applicable month.

34.5 Stranded Cost Recovery: The

Transmission Provider may seek to recover

stranded costs from the Network Customer

pursuant to this Tariff in accordance with the

terms, conditions and procedures set forth in

FERC Order No. 888. However, the

Transmission Provider must separately file

any proposal to recover stranded costs under

Section 205 of the Federal Power Act.

35 Operating Arrangements

35.1 Operation under The Network

Operating Agreement: The Network

Customer shall plan, construct, operate and

maintain its facilities in accordance with

Good Utility Practice and in conformance

with the Network Operating Agreement.

35.2 Network Operating Agreement: The

terms and conditions under which the

Network Customer shall operate its facilities

and the technical and operational matters

associated with the implementation of Part III

of the Tariff shall be specified in the Network

Operating Agreement. The Network

Operating Agreement shall provide for the

Parties to (i) operate and maintain equipment

necessary for integrating the Network

Customer within the Transmission Provider’s

Transmission System (including, but not

limited to, remote terminal units, metering,

communications equipment and relaying

equipment), (ii) transfer data between the

Transmission Provider and the Network

Customer (including, but not limited to, heat

rates and operational characteristics of

Network Resources, generation schedules for

units outside the Transmission Provider’s

Transmission System, interchange schedules,

unit outputs for redispatch required under

Section 33, voltage schedules, loss factors

and other real time data), (iii) use software

programs required for data links and

constraint dispatching, (iv) exchange data on

forecasted loads and resources necessary for

long-term planning, and (v) address any other

technical and operational considerations

required for implementation of Part III of the

Tariff, including scheduling protocols. The

Network Operating Agreement will recognize

that the Network Customer shall either (i)

operate as a Control Area under applicable

guidelines of the North American Electric

Reliability Council (NERC) and the

[applicable regional reliability council], (ii)

satisfy its Control Area requirements,

including all necessary Ancillary Services, by

contracting with the Transmission Provider,

or (iii) satisfy its Control Area requirements,

including all necessary Ancillary Services, by

contracting with another entity, consistent

with Good Utility Practice, which satisfies

NERC and the [applicable regional reliability

council] requirements. The Transmission

Provider shall not unreasonably refuse to

accept contractual arrangements with another

entity for Ancillary Services. The Network

Operating Agreement is included in

Attachment G.

35.3 Network Operating Committee: A

Network Operating Committee (Committee)

shall be established to coordinate operating

criteria for the Parties’ respective

responsibilities under the Network Operating

Agreement. Each Network Customer shall be

entitled to have at least one representative on

the Committee. The Committee shall meet

from time to time as need requires, but no

less than once each calendar year.
21722 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

Schedule 1—Scheduling, System Control

and Dispatch Service

This service is required to schedule the

movement of power through, out of, within,

or into a Control Area. This service can be

provided only by the operator of the Control

Area in which the transmission facilities

used for transmission service are located.

Scheduling, System Control and Dispatch

Service is to be provided directly by the

Transmission Provider (if the Transmission

Provider is the Control Area operator) or

indirectly by the Transmission Provider

making arrangements with the Control Area

operator that performs this service for the

Transmission Provider’s Transmission

System. The Transmission Customer must

purchase this service from the Transmission

Provider or the Control Area operator. The

charges for Scheduling, System Control and

Dispatch Service are to be based on the rates

set forth below. To the extent the Control

Area operator performs this service for the

Transmission Provider, charges to the

Transmission Customer are to reflect only a

pass-through of the costs charged to the

Transmission Provider by that Control Area

operator.

Schedule 2—Reactive Supply and Voltage

Control from Generation Sources Service

In order to maintain transmission voltages

on the Transmission Provider’s transmission

facilities within acceptable limits, generation

facilities (in the Control Area where the

Transmission Provider’s transmission

facilities are located) are operated to produce

(or absorb) reactive power. Thus, Reactive

Supply and Voltage Control from Generation

Sources Service must be provided for each

transaction on the Transmission Provider’s

transmission facilities. The amount of

Reactive Supply and Voltage Control from

Generation Sources Service that must be

supplied with respect to the Transmission

Customer’s transaction will be determined

based on the reactive power support

necessary to maintain transmission voltages

within limits that are generally accepted in

the region and consistently adhered to by the

Transmission Provider.

Reactive Supply and Voltage Control from

Generation Sources Service is to be provided

directly by the Transmission Provider (if the

Transmission Provider is the Control Area

operator) or indirectly by the Transmission

Provider making arrangements with the

Control Area operator that performs this

service for the Transmission Provider’s

Transmission System. The Transmission

Customer must purchase this service from

the Transmission Provider or the Control

Area operator. The charges for such service

will be based on the rates set forth below. To

the extent the Control Area operator performs

this service for the Transmission Provider,

charges to the Transmission Customer are to

reflect only a pass-through of the costs

charged to the Transmission Provider by the

Control Area operator.

Schedule 3—Regulation and Frequency

Response Service

Regulation and Frequency Response

Service is necessary to provide for the

continuous balancing of resources

(generation and interchange) with load and

for maintaining scheduled Interconnection

frequency at sixty cycles per second (60 Hz).

Regulation and Frequency Response Service

is accomplished by committing on-line

generation whose output is raised or lowered

(predominantly through the use of automatic

generating control equipment) as necessary to

follow the moment-by-moment changes in

load. The obligation to maintain this balance

between resources and load lies with the

Transmission Provider (or the Control Area

operator that performs this function for the

Transmission Provider). The Transmission

Provider must offer this service when the

transmission service is used to serve load

within its Control Area. The Transmission

Customer must either purchase this service

from the Transmission Provider or make

alternative comparable arrangements to

satisfy its Regulation and Frequency

Response Service obligation. The amount of

and charges for Regulation and Frequency

Response Service are set forth below. To the

extent the Control Area operator performs

this service for the Transmission Provider,

charges to the Transmission Customer are to

reflect only a pass-through of the costs

charged to the Transmission Provider by that

Control Area operator.

Schedule 4—Energy Imbalance Service

Energy Imbalance Service is provided

when a difference occurs between the

scheduled and the actual delivery of energy

to a load located within a Control Area over

a single hour. The Transmission Provider

must offer this service when the transmission

service is used to serve load within its

Control Area. The Transmission Customer

must either purchase this service from the

Transmission Provider or make alternative

comparable arrangements to satisfy its Energy

Imbalance Service obligation. To the extent

the Control Area operator performs this

service for the Transmission Provider,

charges to the Transmission Customer are to

reflect only a pass-through of the costs

charged to the Transmission Provider by that

Control Area operator.

The Transmission Provider shall establish

a deviation band of +/¥ 1.5 percent (with a

minimum of 1 MW) of the scheduled

transaction to be applied hourly to any

energy imbalance that occurs as a result of

the Transmission Customer’s scheduled

transaction(s). Parties should attempt to

eliminate energy imbalances within the

limits of the deviation band within thirty (30)

days or within such other reasonable period

of time as is generally accepted in the region

and consistently adhered to by the

Transmission Provider. If an energy

imbalance is not corrected within thirty (30)

days or a reasonable period of time that is

generally accepted in the region and

consistently adhered to by the Transmission

Provider, the Transmission Customer will

compensate the Transmission Provider for

such service. Energy imbalances outside the

deviation band will be subject to charges to

be specified by the Transmission Provider.

The charges for Energy Imbalance Service are

set forth below.

Schedule 5—Operating Reserve—Spinning

Reserve Service

Spinning Reserve Service is needed to

serve load immediately in the event of a

system contingency. Spinning Reserve

Service may be provided by generating units

that are on-line and loaded at less than

maximum output. The Transmission

Provider must offer this service when the

transmission service is used to serve load

within its Control Area. The Transmission

Customer must either purchase this service

from the Transmission Provider or make

alternative comparable arrangements to

satisfy its Spinning Reserve Service

obligation. The amount of and charges for

Spinning Reserve Service are set forth below.

To the extent the Control Area operator

performs this service for the Transmission

Provider, charges to the Transmission

Customer are to reflect only a pass-through

of the costs charged to the Transmission

Provider by that Control Area operator.

Schedule 6—Operating Reserve—

Supplemental Reserve Service

Supplemental Reserve Service is needed to

serve load in the event of a system

contingency; however, it is not available

immediately to serve load but rather within

a short period of time. Supplemental Reserve

Service may be provided by generating units

that are on-line but unloaded, by quick-start

generation or by interruptible load. The

Transmission Provider must offer this service

when the transmission service is used to

serve load within its Control Area. The

Transmission Customer must either purchase

this service from the Transmission Provider

or make alternative comparable arrangements

to satisfy its Supplemental Reserve Service

obligation. The amount of and charges for

Supplemental Reserve Service are set forth

below. To the extent the Control Area

operator performs this service for the

Transmission Provider, charges to the

Transmission Customer are to reflect only a

pass-through of the costs charged to the

Transmission Provider by that Control Area

operator.

Schedule 7—Long-Term Firm and ShortTerm Firm Point-To-Point Transmission

Service

The Transmission Customer shall

compensate the Transmission Provider each

month for Reserved Capacity at the sum of

the applicable charges set forth below:

(1) Yearly delivery: one-twelfth of the

demand charge of $llll/KW of Reserved

Capacity per year.

(2) Monthly delivery: $llll/KW of

Reserved Capacity per month.

(3) Weekly delivery: $llll/KW of

Reserved Capacity per week.

(4) Daily delivery: $llll/KW of

Reserved Capacity per day.

The total demand charge in any week,

pursuant to a reservation for Daily delivery,

shall not exceed the rate specified in section

(3) above times the highest amount in

kilowatts of Reserved Capacity in any day

during such week.

(5) Discounts: If the Transmission Provider

offers an affiliate a rate discount or attributes

a discounted transmission rate to its own
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21723

transactions, the Transmission Provider must

offer at the same time the same discounted

Firm Point-To-Point Transmission Service

rate to all Eligible Customers on the same

path and on all unconstrained transmission

paths. Information regarding any firm

transmission discounts must be posted on the

OASIS pursuant to Part 37 of the

Commission’s regulations. In addition,

discounts to non-affiliates must be offered in

a not unduly discriminatory manner.

Schedule 8—Non-Firm Point-To-Point

Transmission Service

The Transmission Customer shall

compensate the Transmission Provider for

Non-Firm Point-To-Point Transmission

Service up to the sum of the applicable

charges set forth below:

(1) Monthly delivery: $llll/KW of

Reserved Capacity per month.

(2) Weekly delivery: $llll/KW of

Reserved Capacity per week.

(3) Daily delivery: $llll/KW of

Reserved Capacity per day.

The total demand charge in any week,

pursuant to a reservation for Daily delivery,

shall not exceed the rate specified in section

(2) above times the highest amount in

kilowatts of Reserved Capacity in any day

during such week.

(4) Hourly delivery: The basic charge shall

be that agreed upon by the Parties at the time

this service is reserved and in no event shall

exceed $llll/MWH. The total demand

charge in any day, pursuant to a reservation

for Hourly delivery, shall not exceed the rate

specified in section (3) above times the

highest amount in kilowatts of Reserved

Capacity in any hour during such day. In

addition, the total demand charge in any

week, pursuant to a reservation for Hourly or

Daily delivery, shall not exceed the rate

specified in section (2) above times the

highest amount in kilowatts of Reserved

Capacity in any hour during such week.

(5) Discounts: If the Transmission Provider

offers an affiliate a rate discount or attributes

a discounted transmission rate to its own

transactions, the Transmission Provider must

offer at the same time the same discounted

Non-Firm Point-To-Point Transmission

Service rate to all Eligible Customers on the

same path and on all unconstrained

transmission paths. Information regarding

any non-firm transmission discounts must be

posted on the OASIS pursuant to Part 37 of

the Commission’s regulations. In addition,

discounts to non-affiliates must be offered in

a not unduly discriminatory manner.

Attachment A—Form Of Service Agreement

for Firm Point-To-Point Transmission

Service

1.0 This Service Agreement, dated as of

llllllll, is entered into, by and

between llllllll (the Transmission

Provider), and llllllll

(‘‘Transmission Customer’’).

2.0 The Transmission Customer has been

determined by the Transmission Provider to

have a Completed Application for Firm

Point-To-Point Transmission Service under

the Tariff.

3.0 The Transmission Customer has

provided to the Transmission Provider an

Application deposit in the amount of

$llll, in accordance with the provisions

of Section 17.3 of the Tariff.

4.0 Service under this agreement shall

commence on the later of (1)

llllllll, or (2) the date on which

construction of any Direct Assignment

Facilities and/or Network Upgrades are

completed, or (3) such other date as it is

permitted to become effective by the

Commission. Service under this agreement

shall terminate on llllllll.

5.0 The Transmission Provider agrees to

provide and the Transmission Customer

agrees to take and pay for Firm Point-ToPoint Transmission Service in accordance

with the provisions of Part II of the Tariff and

this Service Agreement.

6.0 Any notice or request made to or by

either Party regarding this Service Agreement

shall be made to the representative of the

other Party as indicated below.

Transmission Provider:

lllllllllllllllllllll

lllllllllllllllllllll

Transmission Customer:

lllllllllllllllllllll

lllllllllllllllllllll

7.0 The Tariff is incorporated herein and

made a part hereof.

In Witness Whereof, the Parties have

caused this Service Agreement to be executed

by their respective authorized officials.

Transmission Provider:

By: lllllllllllllllllll

Name

lllllllllllllllllllll

Title

lllllllllllllllllllll

Date

lllllllllllllllllllll

lllllllllllllllllllll

Transmission Customer:

By: lllllllllllllllllll

Name

lllllllllllllllllllll

Title

lllllllllllllllllllll

Date

lllllllllllllllllllll

lllllllllllllllllllll

Specifications for Firm Point-To-Point

Transmission Service

1.0 Term of Transaction: llllllll

Start Date: lllllllllllllll

Termination Date: llllllllllll

2.0 Description of capacity and energy to be

transmitted by Transmission Provider including the electric Control Area in which the

transaction originates. llllllllll

lllllllllllllllllllll

3.0 Point(s) of Receipt: lllllllll

Delivering Party: lllllllllllll

4.0 Point(s) of Delivery: lllllllll

Receiving Party: lllllllllllll

5.0 Maximum amount of capacity and energy to be transmitted llllllllll

(Reserved Capacity): lllllllllll

6.0 Designation of party(ies) subject to reciprocal service obligation: llllllll

7.0 Name(s) of any Intervening Systems

providing transmission service: llllll

8.0 Service under this Agreement may be

subject to some combination of the charges

detailed below. (The appropriate charges for

individual transactions will be determined in

accordance with the terms and conditions of

the Tariff.)

8.1 Transmission Charge: llllllll

8.2 System Impact and/or Facilities Study

Charge(s): llllllllllllllll

8.3 Direct Assignment Facilities Charge: l

lllllllllllllllllllll

8.4 Ancillary Services Charges: lllll

Attachment B—Form Of Service Agreement

For Non-Firm Point-To-Point Transmission

Service

1.0 This Service Agreement, dated as of

llllll, is entered into, by and between

llllll, (the Transmission Provider),

and llllll, (Transmission Customer).

2.0 The Transmission Customer has been

determined by the Transmission Provider to

be a Transmission Customer under Part II of

the Tariff and has filed a Completed

Application for Non-Firm Point-To-Point

Transmission Service in accordance with

Section 18.2 of the Tariff.

3.0 Service under this Agreement shall be

provided by the Transmission Provider upon

request by an authorized representative of the

Transmission Customer.

4.0 The Transmission Customer agrees to

supply information the Transmission

Provider deems reasonably necessary in

accordance with Good Utility Practice in

order for it to provide the requested service.

5.0 The Transmission Provider agrees to

provide and the Transmission Customer

agrees to take and pay for Non-Firm PointTo-Point Transmission Service in accordance

with the provisions of Part II of the Tariff and

this Service Agreement.

6.0 Any notice or request made to or by

either Party regarding this Service Agreement

shall be made to the representative of the

other Party as indicated below.

Transmission Provider:

lllllllllllllllllllll

Transmission Customer:

lllllllllllllllllllll

7.0 The Tariff is incorporated herein and

made a part hereof.

In Witness Whereof, the Parties have

caused this Service Agreement to be executed

by their respective authorized officials.

Transmission Provider:

lllllllllllllllllllll

By: lllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

Name

lllllllllllllllllllll

Title

lllllllllllllllllllll

Date

Transmission Customer:

lllllllllllllllllllll

By: lllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

Name

lllllllllllllllllllll

Title

lllllllllllllllllllll

Date
21724 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

Attachment C—Methodology To Assess

Available Transmission Capability

To be filed by the Transmission Provider.

Attachment D—Methodology for Completing

a System Impact Study

To be filed by the Transmission Provider.

Attachment E—Index Of Point-To-Point

Transmission Service Customers

Customer llllllllllllllll

Date of Service Agreement llllllll

Attachment F—Service Agreement for

Network Integration Transmission Service

To be filed by the Transmission Provider.

Attachment G—Network Operating

Agreement

To be filed by the Transmission Provider.

Attachment H—Annual Transmission

Revenue Requirement for Network

Integration Transmission Service

1. The Annual Transmission Revenue

Requirement for purposes of the Network

Integration Transmission Service shall be

llllll.

2. The amount in (1) shall be effective until

amended by the Transmission Provider or

modified by the Commission.

Attachment I—Index of Network Integration

Transmission Service Customers

Customer llllllllllllllll

Date of Service Agreement llllllll

Appendix E—Group 1 Public Utilities

Alabama Power Company

Appalachian Power Company

Arkansas Power & Light Company

Atlantic City Electric Company

Baltimore Gas & Electric Company

Black Hills Power & Light Company

Cambridge Electric Light Company

Central Illinois Light Company

Central Power and Light Company

Central Vermont Public Service Corporation

Cheyenne Light, Fuel and Power Company

Cincinnatti Gas & Electric Company

Citizens Utilities Company

Columbus Southern Power Company

Commonwealth Edison Company

Commonwealth Electric Company

Connecticut Light & Power Company

Connecticut Valley Electric Company

Consumers Power Company

Dayton Power & Light Company

Delmarva Power & Light Company

Duke Power Company

Duquesne Light Company

Florida Power & Light Company

Florida Power Corporation

Georgia Power Company

Granite State Electric Company

Gulf Power Company

Gulf States Utilities Company

Holyoke Power & Electric Company

Holyoke Water Power Company

Idaho Power Company

IES Utilities, Inc.

Illinois Power Company

Indiana Michigan Power Company

Interstate Power Company

Jersey Central Power & Light Company

Kansas City Power & Light Company

Kansas Gas & Electric Company

Kentucky Power Company

Kentucky Utilities Company

Kingsport Power Company

Louisiana Power & Light Company

Louisville Gas & Electric Company

Maine Public Service Company

Massachusetts Electric Company

Metropolitan Edison Company

MidAmerican Energy Company

Midwest Energy, Inc.

Minnesota Power & Light Company

Mississippi Power Company

Mississippi Power & Light Company

Monongahela Power Company

Montana Power Company

Montaup Electric Company

Nantahala Power & Light Company

Narragansett Electric Company

Nevada Power Company

New England Power Company

New Orleans Public Service Inc.

Northern Indiana Public Service Company

Northern States Power Company( Wisconsin)

Northern States Power Company (Minnesota)

Ohio Power Company

Orange & Rockland Utilities, Inc.

Pacific Gas & Electric Company

PacifiCorp

PECO Energy Company

Pennsylvania Electric Company

Pennsylvania Power & Light Company

Pike County Light & Power Company

Portland General Electric Company

Potomac Edison Company

Potomac Electric Power Company

PSI Energy, Inc.

Public Service Company of Colorado

Public Service Company of New Mexico

Public Service Company of New Hampshire

Public Service Electric and Gas Company

Public Utility Company of Oklahoma

Puget Sound Power & Light Company

Rockland Electric Company

San Diego Gas & Electric Company

Savannah Electric and Power Company

South Carolina Electric & Gas Company

Southern California Edison Company

Southern Indiana Gas & Electric Company

Southwestern Electric Power Company

Southwestern Public Service Company

Tampa Electric Company

United Illiminating Company

UtiliCorp United, Inc.

Washington Water Power Company

West Penn Power Company

West Texas Utilities Company

Western Massachusetts Electric Company

Western Resources, Inc.

Wheeling Power Company

Wisconsin Electric Power Company

Wisconsin Power & Light Company

Wisconsin Public Service Corporation

Note: Transmission tariffs have also been

filed for some public utilities associated with

pending merger applications. These

individual utilities are not included in Group

1 and will be required to file tariffs on

compliance with the Final Rule. They are:

Centerior’s filing for Cleveland Electric

Illuminating Company and Toledo Edison

Company; Interstate Energy Corporation’s

filing for South Beloit Water, Gas & Electric

Company; Resources West’s for Sierra Pacific

Power Company; and the rate filing

associated with the merger of Union Electric

Company and Central Illinois Public Service

Company.

Appendix F—Group 2 Public Utilities

Arizona Public Service Company

Bangor Hydro-Electric Company

Blackstone Valley Electric Company

Boston Edison Company

Carolina Power & Light Company

Central Hudson Gas & Electric Corporation

Central Illinois Public Service Company

Central Louisiana Electric Company, Inc.

Central Maine Power Company

Cleveland Electric Illuminating Company

Commonwealth Edison Company of Indiana

Concord Electric Company

Consolidated Edison Company of New York

Inc.

Consolidated Water Power Company

Detroit Edison Company

Eastern Edison Company

Edison Sault Electric Company

El Paso Electric Company

Electric Energy Inc.

Empire District Electric Company

Exeter & Hampton Electric Company

Fitchburg Gas & Electric Light Company

Green Mountain Power Corporation

Indiana-Kentucky Electric Corporation

Indianapolis Power & Light Company

Kanawha Valley Power Company

Lockhart Power Company

Long Island Lighting Company

Long Sault, Inc.

Madison Gas & Electric Company

MDU Resources Group, Inc.

Mt. Carmel Public Utility Company

New England Electric Transmission

Corporation

New England Hydro Transmission Electric

Company

New England Hydro Transmission

Corporation

New York State Electric & Gas Corporation

Newport Electric Corporation

Niagara Mohawk Power Corporation

Northwestern Public Service Company

Northwestern Wisconsin Electric Company

Ohio Edison Company

Ohio Valley Electic Corporation

Oklahoma Gas & Electric Company

Old Dominion Electric Cooperative

Otter Tail Power Company

Pennsylvania Power Company

Peoples Electric Cooperative

Rayburn Country Electric Cooperative

Rochester Gas & Electric Corporation

Sierra Pacific Power Company

South Beloit Water, Gas & Electric Company

St. Joseph Light & Power Company

Superior Water, Light and Power Company

Texas-New Mexico Power Company

Toledo Edison Company

Tucson Electric Power Company

UGI Utilities, Inc.

Union Electric Company

Union Light, Heat & Power Company

Unitil Power Corporation

Upper Penninsula Power Company

Vermont Electric Transmission Company

Vermont Electric Power Company

Virginia Electric & Power Company

Yadkin, Inc.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21725

1Section 212(h) of the FPA provides that no order

issued under the FPA shall be conditioned upon or

require the transmission of electric energy directly

to an ultimate consumer. 16 U.S.C. 824k(h). The

Commission’s assertion of jurisdiction in this final

rule is over the rates, terms and conditions of retail

transmission that occurs voluntarily or as a result

of a state retail access program.

2U.S. Const. art I, Section 8, cl.3.

3U.S. Const. art. VI, cl.2.

4See Montana-Dakota Utilities Co. v.

Northwestern Public Service Co., 341 U.S. 246,

251–52 (1951) (Montana-Dakota).

5Public Utilities Commission v. Attleboro Steam

& Electric Co., 273 U.S. 83 (1927) (Attleboro). In

Attleboro, the Supreme Court held that State

regulation of the interstate sale of electricity was

barred by the Commerce Clause because such

regulation would impose a ‘‘direct burden’’ on

interstate commerce.

6S. Rep. No. 621, 74th Cong., 1st Sess. 48 (1935).

See also H.R. Rep. No. 1318, 74th Cong., 1st Sess.

8 (1935).

7The provisions of the Senate bill regarding

federal jurisdiction over generating facilities were

eliminated from the final version of the bill.

8Section 201(a) declares that Federal regulation

of the transmission of electric energy in interstate

commerce and the sale of such energy at wholesale

in interstate commerce is necessary in the public

interest, ‘‘such Federal regulation, however, to

extend only to those matters which are not subject

to regulation by the States.’’ 16 U.S.C. 824(a).

Section 201(b)(1) states that the provisions of Part

II of the FPA apply to the transmission of electric

energy in interstate commerce and the sale of

electric energy at wholesale in interstate commerce

but, except as specifically provided, ‘‘shall not

apply to any other sale of electric energy or deprive

a State or State commission of its lawful authority

now exercised over the exportation of hydroelectric

energy which is transmitted across a State line.’’ 16

U.S.C. 824(b)(1).

9New England Power Co. v. New Hampshire, 455

U.S. 331, 341 (1982) (NEPCO).

10 Id. (citation omitted).

11While Congress may exercise its Commerce

Clause authority to grant the States that ‘‘ability to

restrict the flow of interstate commerce that they

would not otherwise enjoy,’’ Lewis v. BT

Investment Managers, Inc., 447 U.S. 27, 44 (1980),

States may not exercise such regulatory powers

unless Congress has expressly stated its intention to

make such an affirmative grant of power. NEPCO,

455 U.S. at 343.

Appendix G

I. Legal Analysis of Commission Jurisdiction

Over the Rates, Terms and Conditions of

Unbundled Retail Transmission in Interstate

Commerce

Based on an analysis of the relevant

legislative history and case law under the

Federal Power Act (FPA), the Commission

concludes that it has exclusive jurisdiction

over the rates, terms and conditions of the

unbundled transmission in interstate

commerce, by a public utility, of electric

energy to an end user. This is also known as

retail wheeling in interstate commerce. 1

The Commission’s jurisdiction over the

rates, terms and conditions of transmission in

interstate commerce derives from Congress’

power to regulate interstate commerce under

the United States Constitution 2 and the FPA.

When Congress enacted the FPA, it gave the

Commission exclusive jurisdiction over the

rates, terms and conditions of transmission in

interstate commerce by public utilities. The

Supremacy Clause of the Constitution

provides that federal laws enacted pursuant

to the powers delegated to the federal

government by the United States Constitution

are the supreme law of the land.3

Accordingly, to the extent that retail

wheeling involves transmission in interstate

commerce by public utilities, the rates, terms

and conditions of such service are subject to

the exclusive jurisdiction of the Commission,

and must be filed with the Commission.4

1. Relevant Federal Power Act Provisions

Section 201(b)(1) of the FPA provides:

The provisions of this Part shall apply to

the transmission of electric energy in

interstate commerce and to the sale of

electric energy at wholesale in interstate

commerce * * *. The Commission shall

have jurisdiction over all facilities for such

transmission or sale of electric energy, but

shall not have jurisdiction * * * over

facilities used in local distribution or only for

the transmission of electric energy in

intrastate commerce, or over facilities for the

transmission of electric energy consumed

wholly by the transmitter.

16 U.S.C. 824(b)(1) (emphasis added). Thus,

the statute on its face limits Commission

jurisdiction over sales of energy to sales at

wholesale, but does not limit jurisdiction

over transmission to transmission used only

for wholesale sales.

Sections 201 (c) and (d) define the meaning

of ‘‘the transmission of electric energy in

interstate commerce’’ and ‘‘sale of electric

energy at wholesale in interstate commerce.’’

Section 201(c) provides:

For the purpose of this Part, electric energy

shall be held to be transmitted in interstate

commerce if transmitted from a State and

consumed at any point outside thereof: but

only insofar as such transmission takes place

within the United States.

16 U.S.C. 824(c). Section 201(d) provides:

The term ‘‘sale of electric energy at

wholesale’’ when used in this Part means a

sale of electric energy to any person for

resale.

16 U.S.C. 824(d).

Sections 205 and 206 of the FPA give the

Commission jurisdiction over the rates, terms

and conditions of transmission in interstate

commerce, and sales at wholesale in

interstate commerce, by public utilities. 16

U.S.C. 824d and 824e.

2. Legislative History and Case Law

Much of the legislative history of the FPA

indicates that Congress intended the

Commission’s jurisdiction to extend only to

those matters which the Attleboro decision 5

held to be beyond the reach of the States. For

instance, the report accompanying the Senate

bill states that subsection (b) ‘‘leaves to the

States the authority to fix local rates even in

cases where the energy is brought in from

another State.’’ 6 In other words, states retain

authority to regulate rates of electric energy

to ultimate consumers. The Senate report

also states:

The rate-making powers of the Commission

are confined to those wholesale transactions

which the Supreme Court held in (Attleboro)

to be beyond the reach of the States.

Jurisdiction is asserted also over all interstate

transmission lines whether or not there is

sale of the energy carried by those lines and

over the generating facilities which produce

energy 7 for interstate transmission and sale.

S. Rep. No. 621, 74th Cong., 1st Sess. 48

(1935) (emphasis added). Thus, federal

jurisdiction over transmission lines is not

dependent on whether those lines are used

to effect a sale, wholesale or otherwise.

The provisions of FPA section 201

reserving certain regulatory authority to the

States have been interpreted narrowly.8 The

Supreme Court has stated:

In section 201(b), Congress did no more

than leave standing whatever valid state laws

then existed relating to the exportation of

hydroelectric energy; by its plain terms,

section 201(b) simply saves from pre-emption

under Part II of the Federal Power Act such

state authority as was otherwise ‘‘lawful.’’ 9

The Court also stated:

Nothing in the legislative history or

language of the statute evinces a

congressional intent ‘to alter the limits of

state power otherwise imposed by the

Commerce Clause,’ * * * or to modify the

earlier holding of this Court concerning the

limits of state authority to restrain interstate

trade.10

Unlike the narrow interpretations given to

the FPA provisions reserving certain

regulatory authority to the States,11 the courts

have construed transmission ‘‘in interstate

commerce’’ broadly. The term does not turn

on whether the contract path for a particular

power or transmission sale crosses state

lines, but rather follows the physical flow of

electricity. Because of the highly integrated

nature of the electric system, this results in

most transmission of electric energy being

‘‘in interstate commerce.’’

One of the earliest cases construing

Commission jurisdiction over transmission

was Jersey Central Power & Light Co. v. FPC,

319 U.S. 61 (1943) (Jersey Central). In that

case, the Commission asserted jurisdiction

over a New Jersey utility by showing that the

utility owned transmission facilities that

were used to transmit energy in interstate

commerce. The Court found that the

Commission had demonstrated that the

utility owned transmission facilities that

were indirectly interconnected, through a

second New Jersey utility, to facilities owned

by a New York utility and that the facilities

were used to transmit electric energy in

interstate commerce.

The Court noted that section 201(c) of the

FPA defines electric energy transmitted in

interstate commerce to be energy

‘‘transmitted from a State and consumed at

any point outside thereof.’’ The Court stated:

It is impossible for us to conclude that this

definition [of transmission in interstate

commerce] means less than it says and

applies only to the energy at the instant it

crosses the state line and so only to the

facilities which cross the line and only to the

company which owns the facilities that cross

the line.

319 U.S. at 71. Thus, a critical question

regarding the jurisdictional status of a

wheeling transaction is whether the facilities

used to provide the service transmit electric

energy in interstate commerce.
21726 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

12A bus is an electrical conductor which serves

as a common connection for two or more electrical

circuits. Electric Utility Rate Design Study,

Glossary: Electric Utility and Ratemaking Load &

Management Terms, Edison Electric Institute (Sept.

11, 1978).

13There are, of course, facilities that are used to

provide delivery to both wholesale purchasers and

end users. In those situations, we believe that the

Commission and the States have jurisdiction to set

rates for the services that are within their respective

jurisdictions. That facilities are used to serve resale

and retail customers does not, however, necessarily

mean that the facilities are local distribution

facilities.

14 16 U.S.C. 824.

15 16 U.S.C. 824(b) (emphasis added).

16 16 U.S.C. 824b (emphasis added).

17 16 U.S.C. 824e(d) (emphasis added).

18H.R. Rep. No. 1318, 74th Cong., 1st Sess. 7–8

(1935).

19 Id. at 27.

In Connecticut Light & Power Co. v. FPC,

324 U.S. 515 (1945) (CL&P), the Court

reviewed the Commission’s finding that a

Connecticut utility was jurisdictional

because it owned transmission facilities that

were used in interstate commerce. The Court

generally embraced the Jersey Central

standard for determining whether facilities

are used to transmit electric energy in

interstate commerce. The Court emphasized

that whether certain facilities transmit

electric energy in interstate commerce is

more a technical than a legal question. The

Court stated:

Federal jurisdiction was to follow the flow

of electric energy, an engineering and

scientific, rather than a legalistic or

governmental, test.

324 U.S. at 529. Thus, the Court adopted the

Jersey Central test providing that the

Commission’s jurisdiction generally extends

to transmission facilities that transmit

electric energy in interstate commerce.

The Court also applied the Jersey Central

test in FPC v. Florida Power & Light Co., 404

U.S. 453 (1972), affirming the Commission’s

finding of jurisdiction over a Florida utility.

The Commission demonstrated that the

utility transmitted power to another Florida

utility’s ‘‘bus’’ 12 and that power was

simultaneously transferred from the ‘‘bus’’ to

a Georgia utility. The Court upheld the

Commission’s finding that electric energy

from the two Florida utilities was

commingled and was therefore transmitted in

interstate commerce. 404 U.S. at 463.

In all of the above cases, the Court’s

decisions turned on whether energy being

transmitted flowed in interstate commerce as

a technical matter. The decisions did not turn

on whether the transmission of energy

flowing in interstate commerce involved

energy that was being sold for resale or was

being sold to an end user. Thus, there is

nothing in the statute, its legislative history,

or the case law to indicate that the

Commission’s jurisdiction over rates, terms

and conditions of transmission in interstate

commerce extends only to wholesale

transmission and not retail transmission.

Indeed, the statute on its face gives the

Commission jurisdiction over transmission in

interstate commerce and makes no

distinction between wholesale transmission

and retail transmission.

However, there are two important

limitations on Commission authority. First,

as discussed above, the FPA does not give the

Commission jurisdiction over sales of electric

energy at retail. Such sales historically have

been bundled sales (i.e., generation and

transmission), and courts and the

Commission have recognized State

jurisdiction over bundled sales of energy.

Second, under section 201(b)(1) of the FPA,

the Commission does not have jurisdiction

over facilities used in local distribution. In

CL&P, the Court stated that local distribution

facilities are exempt from Commission

jurisdiction even if those facilities ‘‘carry no

energy except extra-state energy.’’ 324 U.S. at

531.

In the next section the Commission further

discusses the statutory provisions and case

law that shed light on the demarcation

between transmission and local distribution,

and thus on the jurisdictional line between

federal and State authority.

II. Legal Analysis of Commission

Jurisdictional Transmission Facilities and

State Jurisdictional Local Distribution

Facilities

Two specific circumstances are addressed:

First, what facilities are jurisdictional to

the Commission in a situation involving the

unbundled delivery in interstate commerce

by a public utility of electric energy from a

third-party supplier to a purchaser who will

then re-sell the energy to an end user?

Second, what facilities are jurisdictional to

the Commission in a situation involving the

unbundled delivery in interstate commerce

by a public utility of electric energy from a

third-party supplier to an end user?

Based on an analysis of the relevant

legislative history and case law under the

FPA, the Commission reaches the following

conclusions. With respect to the first

circumstance, the Commission concludes

that a public utility’s facilities used to deliver

electric energy to a wholesale purchaser,

whether labeled ‘‘transmission,’’

‘‘distribution,’’ or ‘‘local distribution’’ are

subject to the Commission’s exclusive

jurisdiction under sections 205 and 206 of

the FPA, and that a public utility’s facilities

used to deliver electric energy from the

wholesale purchaser to the ultimate

consumer are ‘‘local distribution’’ facilities

subject to the rate jurisdiction of the state. 13

With respect to the second circumstance,

the Commission believes that, based on the

particular facts of the case, some of the

public utility’s facilities used to deliver

electric energy to an end-user may be FERCjurisdictional transmission facilities, while

some of the facilities used may be statejurisdictional local distribution facilities.

We set forth below the relevant legislative

history and case law, our legal conclusions,

and the factors which we believe are

indicative of whether facilities are used in

‘‘local distribution’’ or ‘‘transmission in

interstate commerce,’’ as those terms are used

in the FPA.

1. Relevant Federal Power Act Provisions

The Commission’s jurisdiction is set forth

in section 201 of the FPA. 14 Section

201(b)(1) provides in pertinent part:

The provisions of this Part shall apply to

the transmission of electric energy in

interstate commerce and to the sale of

electric energy at wholesale in interstate

commerce * * *. The Commission shall

have jurisdiction over all facilities for such

transmission or sale of electric energy, but

shall not have jurisdiction * * * over

facilities used in local distribution or only for

the transmission of electric energy in

intrastate commerce, or over facilities for the

transmission of electric energy consumed

wholly by the transmitter.15

Some of the court decisions that construe

jurisdictional facilities under section 201 also

construe the Commission’s jurisdiction under

section 203. Section 203(a) provides, in

relevant part:

No public utility shall sell, lease, or

otherwise dispose of the whole of its

facilities subject to the jurisdiction of the

Commission, * * * or by any means

whatsoever, directly or indirectly, merge or

consolidate such facilities or any part thereof

with those of any other person * * * without

first having secured an order of the

Commission to do so.16

In addition, section 206(d) concerns

facilities ‘‘under the jurisdiction of the

Commission’’:

The Commission upon its own motion, or

upon the request of any State commission

whenever it can do so without prejudice to

the efficient and proper conduct of its affairs,

may investigate and determine the cost of the

production or transmission of electric energy

by means of facilities under the jurisdiction

of the Commission in cases where the

Commission has no authority to establish a

rate governing the sale of such energy.17

2. Legislative History of the FPA

The relevant legislative history of the

general purposes of Title II of the FPA, and

of section 201 in particular, focuses primarily

on bundled sales of electric energy and does

not directly address the issue of what

constitutes local distribution as opposed to

transmission in interstate commerce.

In discussing the general purposes of Title

II of the House bill, the House Report states:

Title II * * * establishes for the first time

regulation of electric utility companies

transmitting energy in interstate commerce.

* * * * *

* * * Under the decision of the Supreme

Court of the United States in (Attleboro), the

rates charged in interstate wholesale

transactions may not be regulated by the

States. Part II gives the Federal Power

Commission jurisdiction to regulate these

rates. A ‘‘wholesale’’ transaction is defined to

mean the sale of electric energy for resale and

the Commission is given no jurisdiction over

local rates even where the electric energy

moves in interstate commerce.18

In its analysis of section 201, the House

Report states:

As in the Senate bill no jurisdiction is

given over local distribution of electric

energy, and the authority of States to fix local

rates is not disturbed even in those cases

where the energy is brought in from another

State.19
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21727

20S. Rep. No. 621, 74th Cong., 1st Sess. at 17

(1935). See id. at 18 (‘‘The revision [between the

original and final versions of the Senate bill] has

also removed every encroachment upon the

authority of the States. The revised bill would

impose Federal regulation only over those matters

which cannot effectively be controlled by the

States.’’)

21 Id. at 19.

22 Id. at 48. The provisions of the Senate bill

regarding federal jurisdiction over generating

facilities were eliminated from the final version of

the bill.

23H.R. Conf. Rep. No. 1903, 74th Cong., 1st Sess.

74 (1935).

24Pub. L. No. 100–473, 102 Stat. 2299 (1988).

25S. Rep. No. 621, 74th Cong., 1st Sess. 51 (1935)

(emphasis added).

26H.R. Rep. No. 1318, 74th Cong., 1st Sess. 29

(1935) (emphasis added).

27The Senate Report states that interstate

distribution rates are left in the States’ control.

Obviously, the Senate drew a distinction between

interstate distribution (left in the States’ control)

and interstate transmission (given to the FPC).

Compare S. Rep. No. 621 at 49 with H.R. Rep. No.

1318 at 51.

28Section 201(e) defines a ‘‘public utility’’ as

‘‘any person who owns or operates facilities subject

to the jurisdiction under this Part (other than

facilities subject to such jurisdiction solely by

reason of section 210, 211, or 212).’’ 16 U.S.C.

824(e). The section as adopted in 1935 did not

contain the parenthetical, which was adopted in

1978 as part of the Public Utility Regulatory

Policies Act.

29 Jersey Central, 319 U.S. at 63–65.

30 Id. at 66.

31 Id. at 67 (citation omitted).

32 Id. at 73.

33 273 U.S. at 86, 89–90.

34 319 U.S. at 71 (footnote omitted).

The Senate Report’s discussion of the

general purposes of the FPA states:

The decision of the Supreme Court in

(Attleboro) placed the interstate wholesale

transactions of the electric utilities entirely

beyond the reach of the States. Other features

of this interstate utility business are equally

immune from State control either legally or

practically.20

In discussing material differences between

the final version of the Senate bill and the

original version, the Senate Report states:

Subsection (b), formerly (a), which states

the subject matter to which the part relates,

has been clarified to make plain that it

includes interstate transmission where there

is no sale and excludes all facilities used

only for production of transmission in

intrastate commerce or in local distribution.21

In discussing section 201 of the Senate bill,

the Senate Report further states:

The rate-making powers of the Commission

are confined to those wholesale transactions

which the Supreme Court held in (Attleboro)

to be beyond the reach of the States.

Jurisdiction is asserted also over all interstate

transmission lines whether or not there is

sale of the energy carried by those lines and

over the generating facilities which produce

energy for interstate transmission and sale. It

is obvious that no steps can be taken to

secure the planned coordination of this

industry on a regional scale unless all of the

facilities, other than those used solely for

retail distribution, are made subject to the

jurisdiction of the Commission. Facilities

used only for intrastate commerce or local

distribution are expressly excluded from the

operation of the act.22

The Conference Report adds little

description regarding jurisdictional facilities.

In reference to section 201(b) it states that:

[T]he language of the House amendment

has been followed with a clarifying phrase

added to remove any doubt as to the

Commission’s jurisdiction over facilities used

for the generation and local distribution of

electric energy to the extent provided in

other sections of this part and the part next

following.23

In addition to the above statements

pertaining to section 201 of the FPA,

Congress referenced distribution of energy in

the legislative history of section 206(d).

Section 206(d) was originally enacted as

section 206(b) of the FPA. Under the

Regulatory Fairness Act of 1988,24 section

206(b) was redesignated as section 206(d).

The Conference Report on the original FPA

does not address section 206(b). The Senate

Report on the FPA bill states in pertinent

part:

Subsection (b) authorizes the Commission

to investigate and determine the cost of the

production or transmission of electric energy

by means of facilities under the jurisdiction

of the Commission in cases where the

Commission has no authority to establish a

rate governing the sale of such energy. * * *

Since the rate-making powers granted to the

Commission apply only to the wholesale

rates of energy sold in interstate commerce,

this last subsection should be of great benefit

in removing the practical difficulty which the

States may encounter in regulating the

interstate distribution rates which are left

under their control. Such rate regulation

involves the examination and valuation of

property outside the State. The task is one

requiring an agency with a jurisdiction

broader than that of a single State. The

authority of the Federal Commission is to

render assistance to the State commissions in

a way which would preserve and make more

effective the jurisdiction which is thus left to

the States.25

The House Report discusses section 206(b)

as follows:

This subsection reaches those situations

where electric energy is transmitted in

interstate commerce by the same company

which distributes it locally, and will greatly

aid State commissions in fixing reasonable

rates in such cases.26

Thus, the discussions in the two reports do

not appear to contemplate a situation in

which the transmitter and seller of electric

energy are different, and neither is a ‘‘local’’

distributor. The House Report expressly

refers to the same company being the

transmitter and seller of electric energy. The

Senate Report by its terms addresses the

regulation of interstate distribution rates.27

The above legislative history on sections

201 and 206(b) does not provide any

definitive answers to the questions raised.

We therefore turn to the case law under the

FPA.

3. Case Law Under the FPA

Jersey Central was the first of the major

FPC jurisdictional cases considered by the

Supreme Court. The case involved the

acquisition by New Jersey Power and Light

Company (New Jersey Power) of certain

securities of Jersey Central Power & Light

Company (Jersey Central) without the

Commission’s prior approval. The question

before the Court was whether Jersey Central

was a ‘‘public utility’’ under section 201(e) 28

of the FPA so that the Commission’s prior

approval of the stock acquisition was

necessary under section 203 of the FPA.

Jersey Central owned transmission

facilities that connected to facilities that

Public Service Electric & Gas Company

(Public Service) owned. The interconnection

of these transmission facilities was in New

Jersey. Public Service’s facilities in turn

connected to the facilities of the Staten Island

Edison Corporation (Staten Island Edison), a

New York utility, at the mid-channel of Kill

van Kull, a body of water separating New

Jersey and New York. Jersey Central

delivered energy to and received energy from

Public Service under contract, and Public

Service delivered energy to and received

energy from Staten Island Edison under

contract.29

The Court found that, although Jersey

Central generated and received electricity

only in New Jersey, some of the electric

energy that it dispatched to Public Service

‘‘was instantaneously transmitted to New

York.’’ 30 The Court held that ‘‘[t]his evidence

* * * furnishes substantial basis for the

conclusion of the Commission that facilities

of Jersey Central are utilized for the

transmission of electric energy across state

lines.’’ 31 Therefore, the Court found that

Jersey Central was a public utility within the

meaning of section 201(e).32

The Court cited Attleboro, in which the

Court found that the sale of locally produced

electric energy for use in another state

resulted in the transmission of electric energy

in interstate commerce, even though title

passed at the state line.33 In Jersey Central,

the Court explained the rationale for federal

jurisdiction as follows:

(Section 201(c) of the FPA) defines the

electric energy in commerce as that

‘‘transmitted from a State and consumed at

any point outside thereof.’’ There was no

change in this definition in the various drafts

of the bill. The definition was used to ‘‘lend

precision to the scope of the bill.’’ It is

impossible for us to conclude that this

definition means less than it says * * *. The

purpose of this act was primarily to regulate

the rates and charges of the interstate

energy.34

The Court in Jersey Central thus

interpreted the FPA as placing within the

federal province regulation of wholesale sales

of electric energy that, in any manner, flows

in interstate commerce. The language quoted

above and the citation to section 201(c) of the

FPA, to be relied upon in subsequent

Supreme Court cases, strongly suggested that

the Commission’s jurisdiction was not based

on whether there was a sale by the utility, but

rather on the flow of electric energy either

into or out of a state, so long as the energy

crosses state lines.

CL&P, which was decided two years after

Jersey Central, is the leading case interpreting
21728 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

35CL&P, 324 U.S. at 517.

36 Id. at 518.

37 Id. at 521.

38 Id. at 522.

39 Id. at 519–21.

40 Id.

41 Id. at 522, quoting Connecticut Light & Power

Co. v. FPC, 141 F.2d 14, 18 (D.C. Cir. 1944).

42 324 U.S. at 529.

43 Id. at 529–31.

44 Id. at 531.

45 It appears that while the Company received

power (at one location) at 66 kV, it primarily owned

facilities at 13.8 kV and below.

46 324 U.S. at 531.

47 Id. at 531 (emphasis added).

48 Id. at 534.

49See United States v. Public Utilities

Commission of California, 345 U.S. 295, 316 (1953)

(Public Utilities Commission): Certainly the

concrete fact of resale of some portion of the

electricity transmitted from a state to a point

outside thereof invokes federal jurisdiction at the

outset, despite the fact that the power thus used

traveled along its interstate route ‘‘commingled’’

with other power sold by the same seller and

eventually directly consumed by the same

purchaser-distributor.

See also Arkansas Power & Light Co. v. FPC, 368

F.2d 376, 383 (8th Cir. 1966) (‘‘Where a company

is in fact a public utility, all wholesale sales for

resale in interstate commerce are subject to the

provisions of sections 205 and 206 of the (FPA),

regardless of the facilities used.’’). The Eighth

Circuit further noted that the section 201(b)

exemption applies to a company’s status as a public

utility and not to the Commission’s jurisdiction

over sales in interstate commerce for resale. Id.,

citing Public Utilities Commission, Colton, infra,

and Wisconsin-Michigan, infra.

50 Id. at 536.

51 197 F.2d 472 (7th Cir. 1952), cert. denied, 345

U.S. 934 (1953) (Wisconsin-Michigan).

52 Id. at 474.

53 Id. (‘‘Obviously the energy thus transmitted in

interstate commerce is not changed in form or in

character except that the voltage is reduced to an

extent consistent with efficient economic

management and operation.’’).

54 197 F.2d at 476 (emphasis added).

the section 201(b) local distribution proviso.

In CL&P, the Commission sought to regulate

the accounting practices of Connecticut Light

& Power Company (CL&P). 35 At issue was

whether CL&P was a ‘‘public utility’’ under

the FPA. The utility’s system encompassed

an area solely within a single state

(Connecticut) 36 and did not interconnect

with any other company that operated out of

state. 37 ‘‘Its purchases and sales, its receipts

and deliveries of power, (were) all within the

state.’’ 38 However, CL&P did purchase energy

from companies that had, in turn, purchased

energy from Massachusetts. The company

also sold energy to a municipality that

exported a portion of that energy to Fishers

Island, located off the coast of Connecticut

but ‘‘territory of New York.’’ 39 The

Commission based its jurisdiction on these

few transactions.40

The Court of Appeals affirmed the

Commission, holding that the Commission’s

jurisdiction extended to ‘‘electric distribution

systems which normally would operate as

interstate businesses.’’ The Court of Appeals

found that:

Whether or not the facilities by which

petitioner distributes energy from

Massachusetts should be classified as ‘local’

is not relevant to this case. The sole test of

jurisdiction of the Commission over accounts

is whether these facilities, ‘local’ or

otherwise, are used for the transmission of

electric energy from a point in one state to

a point in another.( 41)

The Supreme Court reversed. It held that

the statutory language in section 201(b) of the

FPA providing that the Commission ‘‘shall

not have jurisdiction * * * over facilities

used in local distribution’’ is a limitation

upon Commission jurisdiction that ‘‘the

Commission must observe and the courts

must enforce.’’ 42 In analyzing the statute, the

Court stated:

It has never been questioned that

technologically generation, transmission,

distribution and consumption are so fused

and interdependent that the whole enterprise

is within the reach of the commerce power

of Congress, either on the basis that it is, or

that it affects, interstate commerce, if at any

point it crosses a state line.

* * * * *

But whatever reason or combination of

reasons led Congress to put the provision in

the Act, we think it meant what it said by the

words ‘‘but shall not have jurisdiction * * *

over facilities used in local distribution.’’

Congress by these terms plainly was trying to

reconcile the claims of federal and local

authorities and to apportion federal and state

jurisdiction over the industry.43

The Court decided that this limitation on

jurisdiction was ‘‘a legal standard that must

be given effect in this case in addition to the

technological transmission test.’’44

The Court stated that whether or not local

distribution facilities carried out-of-state

electric energy was irrelevant. Whatever the

origin of the electric energy they carried, so

long as the utility used the lines for local

distribution,45 they were exempt from federal

jurisdiction.46 In fact, the Court stated that

local distribution facilities ‘‘may carry no

energy except extra-state energy and still be

exempt under the Act.’’ Id. at 531. The Court

concluded that the Commission’s order:

Must stand or fall on whether this

company owned facilities that were used in

transmission of interstate power and which

were not facilities used in local

distribution.47

Upon reversing the Court of Appeals, the

Court commented, in dictum, on the

evidence the Commission had relied upon in

finding that the facilities in question were

used for transmission. It noted that the

Commission had relied upon certain gas

transportation cases in concluding that

transmission extends from the generator to

the point where the function of conveyance

in bulk over distance is completed and the

process of subdividing the energy to serve

ultimate consumers, which is the

characteristic of ‘‘local distribution,’’ is

begun. The Court cautioned:

But a holding that distributing gas at low

pressure to consumers is a local business is

not a holding that the process of reducing it

from high to low pressure is not also part of

such local business. In so far as the

Commission found in these cases a rule of

law which excluded from the business of

local distribution the process of reducing

energy from high to low voltage in

subdividing it to serve ultimate consumers,

the Commission has misread the decisions of

this Court. No such rule of law has been laid

down.48

The Court also noted in its dictum,

however, that once a company is properly

found to be a ‘‘public utility’’ under the Act,

the fact that a local commission may also

have jurisdiction does not preclude exercise

of the Commission’s functions. Id. at 533.49

The Court instructed the lower court to

remand the case to the Commission for a

finding regarding whether the facilities in

question were used in local distribution.50

The CL&P case was ultimately disposed of

without the Commission having made a

finding that the facilities were used in local

distribution. While the Commission found

that it was ‘‘extremely doubtful’’ that it could

find that the facilities in question were not

local distribution facilities, 6 FPC 104, 106

(1947), the Commission did not articulate a

definition of local distribution facilities.

In Wisconsin-Michigan Power Co. v.

Federal Power Commission, 51 the Seventh

Circuit held that a utility was a jurisdictional

public utility where it operated two divisions

in Wisconsin and Michigan in a coordinated

manner such that electric energy from one

state was transmitted to the other, and vice

versa, ‘‘in appreciable amounts by the power

company and by it commingled with energy

generated in the two respective districts and

then delivered to the [wholesale] customers

* * *.’’ 52 The court also rejected the notion

that the energy changed its form or character

when it was stepped down in voltage before

it reached the wholesale purchasers. 53

The court in Wisconsin-Michigan

distinguished between transmission and

local distribution by focusing on wholesale

sales of electric energy versus retail sales

(‘‘local rates’’) of electric energy. It cited the

House Report on the FPA, and characterized

the legislative history as follows:

The legislative history, (H.R. Rep. No.

1318), 74th Cong., 1st Sess. pages 7, 8 and

27 (1935), discloses that the Congressional

Committee intended that the provisions of

the (FPA) should apply to the transmission

of electric energy in interstate commerce, i.e.,

the sale of energy at wholesale in interstate

commerce, but not to the retail sale of any

such energy in local distribution; that the

(FPA) left to the state the authority to fix

local rates where the energy is brought in

from other states, and that the rate making

power of the (FPC) was to be confined to

those wholesale transmissions which the

Supreme Court had held in (Attleboro) to be

beyond the reach of the state. Under that

decision, said the committee, the rates

charged in interstate wholesale transactions

could not be regulated by the states. It

defined a wholesale transaction as the sale of

electric energy for resale.54

The Seventh Circuit’s characterization of

the House Report seems to equate

transmission of electric energy in interstate

commerce with the sale of energy at

wholesale in interstate commerce. However,

this interpretation is at odds with both the
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21729

55See H.R. Rep. No. 1318 at 27. (‘‘Subsection (b)

confers jurisdiction upon the Commission over the

transmission of electric energy in interstate

commerce and the sale of electric energy in

wholesale in interstate commerce * * *.’’ emphasis

added).

56See S. Rep. No. 621 at 48 (‘‘Jurisdiction is

asserted over all interstate transmission lines

whether or not there is a sale of the energy carried

by those lines * * *.’’).

57 197 F.2d at 477.

58 Id., citing FPC v. East Ohio Gas Co., 338 U.S.

464 (1950) (East Ohio).

59 376 U.S. 205 (1964) (Colton).

60The Supreme Court noted that Edison’s status

as a public utility did not decide the question of

whether the FPC could assert jurisdiction over the

rates for the Edison-Colton sale. Id. at 208 n.3.

61 Id. at 208, 209 & n.5.

62 Id. at 208. See Arkansas Electric Cooperative

Corp. v. Arkansas Public Service Commission, 461

U.S. 375, 380 (1983) (‘‘(Colton) held, among other

things, that * * * a California utility that received

some of its power from out-of-state was subject to

federal and not state regulation in its sales of

electricity to a California municipality that resold

the bulk of the power to others.’’).

63 Illinois Natural Gas Co. v. Central Illinois

Public Service Co., 314 U.S. 498, 504 (1942).

64 376 U.S. at 214.

65 Id. at 215–216.

66 Id. at 216 (footnote omitted).

67 Id. at 210 n.6 (citation omitted).

68 Id. at 210 n.6.

69 401 F.2d 930 (D.C. Cir. 1968) (Duke).

70 Duke delivered power to Clemson at a

distribution voltage of 4,160 volts. The step-down

transformers by which the voltage was reduced, and

the substations at which the delivery was effected,

were owned by Duke. 401 F.2d at 931, n.8.

71 401 F.2d at 938–39 (emphasis added, footnotes

omitted).

72 Id. (footnote omitted).

plain words of the statute as well as the

language of the House Report, both of which

refer to transmission in interstate commerce

separately from sales for resale in interstate

commerce.55 In addition, the Senate Report,

which the Seventh Circuit did not mention,

clearly recognized jurisdiction over all

interstate transmission lines, whether or not

a sale of energy is carried by those lines.56

The Wisconsin-Michigan court also cited

analogous natural gas cases, stating that

‘‘[t]he question is essentially, when does

interstate commerce transportation end and

where do the local distribution facilities first

become operative.’’ 57 The court further stated

that:

(U)pon delivery to (the wholesaler) local

distribution begins when he resells. His sales

and distribution at retail are clearly local in

character, and constitute only local

distribution; but at no point before delivery

to him has been completed, has interstate

transmission terminated. In other words,

‘‘facilities used in local distribution’’ means

facilities used for making resale and

distribution to consumers, jurisdiction over

which is left to the states. It was only because

of this conclusion that the Supreme Court

said, (citation omitted), the Act ‘‘cut(s)

sharply and cleanly between sales for resale

and direct sales for consumptive uses.’’ We

think there is no ground for the position that

local distribution includes any transmission

occurring before the wholesaler who resells

at retail is reached.58

The Seventh Circuit concluded that the

sales for resale were made in interstate

commerce; that local distribution had not

begun; that the interstate character of the

transmission persisted until delivery to the

wholesaler; that, up to that point, no local

distribution facilities were in operation and

that, therefore, the sales were subject to

Commission regulation.

In Federal Power Commission v. Southern

California Edison Company (the Colton

case),59 the Supreme Court held that the FPA

provides a clear line of demarcation between

jurisdictional transactions and nonjurisdictional transactions. However, this

case, too, involved bundled sales of electric

energy. In the facts of the case, Southern

California Edison Company (Edison)

admitted that it was a public utility by virtue

of owning two interstate transmission lines.60

At issue was whether its sales of electric

energy to the City of Colton, California, for

resale to Colton’s retail customers, were

jurisdictional. Included in the electric energy

that Edison sold to Colton was out-of-state

electric energy from Hoover Dam.61 The

Commission ruled that the sale to Colton was

a sale of electric energy at wholesale in

interstate commerce subject to regulation

under the FPA.62 In upholding the

Commission, the Court held that Edison’s

importation of out-of-state electricity for

resale to Colton sufficed to confer federal

jurisdiction.

The Court, citing an earlier Supreme Court

case,63 characterized Congressional intent in

the FPA:

(W)hat Congress did was to adopt the test

developed in the Attleboro line which denied

state power to regulate a sale ‘‘at wholesale

to local distributing companies’’ and allowed

state regulation of a sale at ‘‘local retail rates

to ultimate consumers.’’ 64

The Court rejected the argument that FPC

jurisdiction was confined to those interstate

wholesale sales constitutionally beyond the

power of state regulation by force of the

Commerce Clause, and was to be determined

on a case-by-case analysis of the impact of

state regulation upon the national interest.

The Court stated that in the FPA:

(C)ongress meant to draw a bright-line

easily ascertained, between state and federal

jurisdiction, making unnecessary such caseby-case analysis. This was done in the Power

Act by making FPC jurisdiction plenary and

extend[ed] it to all wholesale sales in

interstate commerce except those which

Congress has made explicitly subject to

regulation by the States.65

The Court held that ‘‘(t)here is no such

exception covering the Edison-Colton

sale.’’ 66

Parties in the Colton case had raised the

question of whether jurisdiction over the

Colton sale was prevented by the ‘‘local

distribution’’ proviso of section 201(b). The

Court stated that whether facilities are local

distribution facilities is a matter for the

Commission to decide in the first instance.

Citing CL&P, supra, it stated:

Whether facilities are used in local

distribution—although a limitation on FPC

jurisdiction and a legal standard that must be

given effect in addition to the technological

transmission test * * *—involves a question

of fact to be decided by the FPC as an original

matter.67

The Court cited evidentiary support and the

Commission’s expertise in such matters in

upholding the Commission’s determination

that certain facilities owned by Edison were

used exclusively to effect the wholesale sale

to Colton and not for local distribution. Such

facilities included 12 kV lines that served an

industrial customer, several lighted highway

signs, a residence and a railroad section

house before they reached the transformers in

the Colton substation. The FPC had held that

those uses prior to the lines reaching the

Colton substation did not transform the lines

into local distribution facilities.68

In Duke Power Company v. Federal Power

Commission (Duke),69 the D.C. Circuit held

that a public utility’s acquisition of facilities

used solely in local distribution, and which

would continue to be used for local

distribution, was beyond the Commission’s

jurisdiction under section 203. The case

involved Duke Power Company’s (Duke’s)

proposed acquisition of facilities owned by

Clemson University (Clemson), which were

used to distribute electricity off-campus to

customers (primarily university personnel) in

two South Carolina counties. Clemson

purchased the power at wholesale from

Duke. No one appeared to contest the

conclusion that the 7 miles of distribution

line and 418 service connections owned by

Clemson were ‘‘local distribution’’

facilities.70 Rather, the case turned on

interpreting section 203 and whether it was

intended to affect only acquisitions of

jurisdictional facilities, or also to affect

acquisitions of non-jurisdictional facilities. In

interpreting section 203, however, the D.C.

Circuit extensively analyzed and discussed

the fundamental jurisdictional lines that

Congress drew in section 201.

Citing to the CL&P case, the court in Duke

stated:

The Act, as we have seen, effectuated

federal control over the transmission and the

sale at wholesale of electric energy in

interstate commerce, and established the

Commission’s regulatory power over public

utilities engaging in either of these

pursuits.71

However, quoting CL&P, the court further

stated:

The expression ‘‘facilities used in local

distribution’’ is one of relative generality. But

as used in this Act it is not a meaningless

generality in the light of our history and the

structure of our government. We hold the

phrase to be a limitation on jurisdiction and

a legal standard that must be given effect in

this case in addition to the technological

transmission test.72

The court further rejected the

Commission’s concept that, in order to

determine whether jurisdiction over any

particular acquisition existed, the impact of

local supervision be measured on a case-bycase basis. Quoting from Colton, the court

stated:

[T]his ‘‘flexible approach’’—involving as it

does the consideration, inter alia, of ‘‘the
21730 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

73 Id. at 949 (footnotes omitted).

74 Id. at 936 (quoting from Hearings on H.R. 5423

before the House Committee on Interstate and

Foreign Commerce, 74th Cong., 1st Sess. 393 (1935)

(testimony of then-FPC Commissioner Seavey)).

75 404 U.S. 453, reh’g denied, 405 U.S. 948 (1972)

(Florida Power & Light).

76 404 U.S. at 456.

77 Id. at 456.

78A ‘‘bus’’ is a connector or group of connectors

that serves as a common connection for two or more

circuits.

79 404 U.S. at 457.

80 Id.

81 Id. at 457 & n.8.

82 Id. at 461. (emphasis omitted).

83 Id. at 461 n.10. (emphasis added).

84See Section 201(d), 16 U.S.C. 824(d) (1988).

85Public Utilities Commission, supra note 345;

City of Oakland, California v. FERC, 754 F.2d 1378

(9th Cir. 1985) (Oakland). See also Alexander v.

FERC, 609 F.2d 543 (D.C. Cir. 1979) (Alexander).

86Courts often rely on cases construing the NGA

when interpreting the FPA, and vice versa. E.g.,

Arkansas Louisiana Gas Co. v. Hall, 453 U.S. 571,

577 n.7 (1981).

87 15 U.S.C. 717(b) (emphasis added).

88H.R. Rep. No. 709, 75th Cong., 1st Sess. 3

(1937); S. Rep. No. 1162, 75th Cong., 1st Sess. 3

(1937).

effect of the regulation upon the national

interest in the commerce’’—has been flatly

rejected as a technique for resolving

jurisdictional conflicts between the

Commission and state bodies. * * * We

think that like the line ‘‘(i)t cut sharply and

cleanly between sales for resale and direct

sales for consumptive uses’’ to facilitate

jurisdictional determinations in rate

regulation, ‘‘Congress meant to draw a bright

line easily ascertained, between state and

federal jurisdiction, making unnecessary

such case-by-case analysis,’’ in distributing

regulatory power over the acquisition of

facilities.73

The court rejected the Commission’s

argument that jurisdiction over the merger or

consolidation of jurisdictional facilities with

those of any other ‘‘person’’ under section

203 gave the Commission jurisdiction over

Duke’s acquisition. The court stated that the

FPA reflects a policy ‘‘‘ that matters largely of

a local nature, even though interstate in

character, should be handled locally and

should receive the consideration of local

[officials] familiar with the local conditions

in the communities involved.’ ’’ 74

Federal Power Commission v. Florida

Power & Light Company 75 is the last major

court case to address the Commission’s

transmission jurisdiction. In this case, the

Commission sought to impose its accounting

rules upon Florida Power & Light Company

(Florida Power & Light). The company’s

system lay solely within the borders of

Florida and did not directly connect with any

out-of-state utility.76 The Commission held

that Florida Power & Light did own facilities

that transmitted electric energy in interstate

commerce, but the Court of Appeals for the

Fifth Circuit ruled that the Commission did

not have substantial evidence to support its

finding.

The Supreme Court reversed. The Supreme

Court noted that Florida Power & Light was

a member of the Florida Power Pool along

with Florida Power Corporation (Florida

Power Corp.).77 In turn, Florida Power Corp.

connected with Georgia Power Company

(Georgia Power) at a ‘‘bus’’ 78 south of the

Georgia-Florida border.79 Florida Power

Corp. regularly exchanged power with

Georgia Power.80 In many instances, Florida

Power Corp. transferred power to Florida

Power & Light instantly after receiving power

from Georgia Power, and transferred power to

Georgia Power immediately after receiving

power from Florida Power & Light.81 The

Supreme Court found that power

commingled in the bus moved across state

lines, and concluded that Florida Power &

Light engaged in transmission in interstate

commerce. The Court held that, to establish

jurisdiction, the Commission need only show

that ‘‘some (Florida Power & Light) power

goes out of State.’’ 82 The Court further

explained that ‘‘(i)f any (Florida Power &

Light) power has reached Georgia, or (if

Florida Power & Light) makes use of any

Georgia power * * * FPC jurisdiction will

attach * * *.’’83

There is also a line of cases that address,

among other things, what constitutes a

Commission jurisdictional ‘‘sale of electric

energy at wholesale’’ 84 under section 201 of

the FPA.85 These cases all concerned

bundled sales. While the issues posed above

involve unbundled wheeling, the ‘‘resale’’

cases are helpful to the extent they suggest

that local distribution takes place only after

power is subdivided. See, e.g., 345 U.S. at

316 (‘‘the facilities supplied ‘local

distribution’ only after the current was

subdivided for individual consumers.’’).

4. Natural Gas Act

The Natural Gas Act (NGA) was adopted in

1938. Like the FPA, the NGA contains

language limiting the Commission’s

jurisdiction in situations involving local

distribution.86

Section 1(b) of the NGA provides:

The provisions of this Act shall apply to

the transportation of natural gas in interstate

commerce, to the sale in interstate commerce

of natural gas for resale for ultimate public

consumption for domestic, commercial,

industrial, or any other use, and to natural

gas companies engaged in such

transportation or sale, but shall not apply to

any other transportation or sale of natural gas

or to the local distribution of natural gas or

to the facilities used for such distribution or

to the production or gathering of natural.87

There is similarity in many respects

between the House and Senate Reports on the

FPA and the NGA with respect to the

jurisdiction given the Commission. For

example, all four reports mention Attleboro

as placing interstate wholesale transactions

beyond the reach of the States. As indicated

in the House Report on the NGA, the States

could ‘‘regulate sales to consumers even

though such sales are in interstate commerce,

such sales being considered local in character

and in the absence of congressional

prohibition subject to State regulation.’’ (See

H.R. Rep. No. 709, 75th Cong., 1st Sess. 1).

However, the House and Senate Reports on

the NGA contain identical language not

found in the reports on the FPA:

In view of the importance of section 1(b),

which states the scope of the act, it seems

advisable to comment on certain provisions

appearing therein. It will be noted that this

subsection of the bill, after affirmatively

stating the matters to which the act is to

apply, contains a provision specifying what

the act is not to apply to, as follows:

But shall not apply to any other

transportation or sale of natural gas or to the

local distribution of natural gas or to the

facilities used for such distribution or to the

production or gathering of natural gas.

The quoted words are not actually

necessary, as the matters specified therein

could not be said fairly to be covered by the

language affirmatively stating the jurisdiction

of the Commission, but similar language was

in previous bills, and, rather than invite the

contention, however unfounded, that the

elimination of the negative language would

broaden the scope of the act, the committee

has included it in this bill. That part of the

negative declaration stating that the act shall

not apply to ‘‘the local distribution of natural

gas’’ is surplusage by reason of the fact that

distribution is made only to consumers in

connection with sales, and since no

jurisdiction is given to the Commission to

regulate sales to consumers the Commission

would have no authority over distribution,

whether or not local in character. (Emphasis

added).88

As a result of this language it can be argued

that Congress considered distribution (and

local distribution) only in the context of

bundled retail sales of natural gas. In fact, it

appears that all of the court cases affirming

the states’ right to regulate local distribution

of gas have involved bundled retail sales. See

Panhandle Eastern Pipe Line Co. v. Michigan

Public Service Commission, 341 U.S. 329

(1951) (Panhandle). There the Court, in

affirming the State of Michigan’s right to

regulate an interstate pipeline’s proposed

bundled retail sales of gas to industrial

consumers, noted that the pipeline company

proposed to lay pipeline in ‘‘the streets and

alleys of Detroit’’ and ignored the local

distribution company’s request for additional

gas to meet the increased needs of the

industrial consumers. Id. at 333. While the

Court based its holding on a state’s authority

to regulate direct (retail) sales to an end-user,

rather than on the basis of the section 1(b)

local distribution provision, it also found that

the proposed sales were ‘‘primarily of local

interest’’ and ‘‘emphasized the need for local

regulation.’’ Id. Two years before Panhandle,

the Supreme Court issued its decision in FPC

v. East Ohio Gas Co., 338 U.S. 465 (1949)

(East Ohio). East Ohio Gas Company owned

and operated a natural gas business wholly

within the State of Ohio. The company sold

gas only to Ohio customers but most of the

gas was transported to Ohio from other states

by interstate pipelines. These interstate

pipelines connected inside Ohio with East

Ohio’s large high pressure lines. The gas then

was transported over 100 miles through East

Ohio’s system to its local distribution system.

East Ohio argued that it was exempt from

Commission jurisdiction because all of its

facilities were local distribution.

The Court disagreed, finding the

Commission’s jurisdiction extends over the
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21731

89 338 U.S. at 469–70.

90See Mojave Pipeline Company, 35 FERC

¶ 61,199 (1986), reh’g denied, 41 FERC ¶ 61,040

(1987), reh’g denied, 42 FERC ¶ 61,351 (1988); see

also Mojave Pipeline Company, 66 FERC ¶ 61,194

(1994), reh’g pending.

91See Public Utilities Commission of the State of

California v. FERC, et al., 900 F.2d 269, 273 (D.C.

Cir. 1990) (footnote omitted) (WyCal).

92 Id. at 276.

93 Id. (emphasis in original).

94 955 F.2d 1412, 1414 (10th Cir. 1992).

95Unlike the situation in WyCal where the

pipeline made direct sales to end users, in Cascade

the pipeline transported gas purchased from third

parties. See Northwest Pipeline Corporation, 51

FERC ¶ 61,289 at 61,909 (1990).

96Cascade, 955 F.2d at 1421.

97 345 U.S. at 316 (footnote omitted).

98The Commission would not have jurisdiction

over the rates for the sale of generation by the

distant supplier because the transaction would be

a retail sale of electric energy.

99 In the case of a distribution-only utility, which

is franchised by a State or local government and

sells only at retail, all of the circuits (and related

wires, transformers, towers, and rights of way)

which it owns or operates (regardless of voltage)

would be local distribution facilities.

100The Commission has analyzed utilities’ filings

required by the Commission’s regulations. These

filings are made on FERC Form No. 1. While there

is no uniform breakpoint between transmission and

distribution, it appears that utilities account for

facilities operated at greater than 30 kV as

transmission and that distribution facilities are

usually less than 40 kV.

transportation of gas in interstate commerce

through high-pressure transmission lines and

that distribution did not begin until the point

where pressure is reduced and gas enters

local mains. The Court stated that: ‘‘[w]hat

Congress must have meant by ‘facilities’ for

‘local distribution’ was equipment for

distributing gas among customers within a

particular local community, not the highpressure pipelines transporting the gas to the

local mains.’’ 89

The Commission relied in part on East

Ohio’s high pressure/low pressure

distinction in a recent NGA section 7

certificate case which authorized

construction of facilities to bypass the local

distribution company.90 On appeal, the

California Commission argued that under

section 1(b) it should at least have

‘‘jurisdiction over the ‘taps, meters and other

tie-in facilities’ that link the pipeline to end

users.’’ 91 The court disagreed:

While as a matter of ordinary English ‘local

distribution’ might be understood to

encompass any delivery to an end user, that

is hardly the only or even more plausible

reading. Distribution conjures up receiving a

large quantity of some good and parcelling it

out among many takers.92

After reviewing the report language

discussed above, the court also stated:

Insofar as congressional committees spoke

to the matter * * * they appear to have

viewed distribution as confined to its

parcelling out function and (probably) even

more narrowly, to parcelling out

accompanied by retail sales. 93

In Cascade Natural Gas Corporation v.

FERC, et al. (Cascade), the court affirmed the

Commission’s authorizing an interstate

pipeline under section 7 of the NGA ‘‘to

construct a tap and meter facility that would

allow it to deliver natural gas directly to two

industrial consumers * * *.’’94 To reach the

interstate pipeline, the industrials

constructed a nine-mile pipeline. Together,

the facilities bypassed the local distribution

company.95

The court rejected arguments that section

1(b) deprived the Commission of jurisdiction

holding that:

‘‘Local distribution,’’ as Congress viewed

the term, involves two components: the retail

sale of natural gas and its local delivery,

normally through a network of branch lines

designed to supply local consumers.96

5. Analysis

a. What facilities are jurisdictional to the

Commission in a situation involving the

unbundled delivery in interstate commerce

by a public utility of electric energy from a

third-party supplier to a purchaser who will

then re-sell the energy to an end user?

The case law supports the conclusion that

any facilities of a public utility used to

deliver electric energy in interstate commerce

to a wholesale purchaser, whether such

facilities are labeled ‘‘transmission,’’

‘‘distribution’’ or ‘‘local distribution,’’ are

subject to the Commission’s jurisdiction

under sections 205 and 206.

This conclusion is supported by Public

Utilities Commission, supra, in which the

Supreme Court, in the section of its opinion

addressing the section 201(b) local

distribution provision, held that local

distribution facilities began ‘‘only after the

current was subdivided for individual

consumers.’’ 97 Wisconsin-Michigan, supra,

in which the Seventh Circuit held that there

is no local distribution until the wholesaler

who re-sells at retail is reached, is to like

effect.

This conclusion, which results in a

‘‘functional’’ line being drawn to determine

Commission jurisdiction, is not only

consistent with the case law under section

201, but is also consistent with our

interpretation of the line drawn under newly

amended FPA sections 211 and 212. As long

as electric energy is being sold to a legitimate

wholesale purchaser, we believe the

Commission has jurisdiction under sections

201, 205, and 206 of the FPA over the public

utility’s facilities used to deliver electric

energy to that purchaser.

b. What facilities are jurisdictional to the

Commission in a situation involving the

unbundled delivery in interstate commerce

by a public utility of electric energy from a

third-party supplier directly to an end user?

In analyzing jurisdiction over unbundled

retail wheeling, we believe it is important to

distinguish between unbundled wheeling

provided by the public utility who

previously provided bundled retail service to

the end user, and unbundled wheeling

provided by other public utilities to the end

user. For example, a former bundled retail

customer may need unbundled wheeling

services from its previous public utility

generation supplier, as well as unbundled

wheeling from one or more intervening

public utilities, in order to reach a distant

generation supplier. In this scenario, the

Commission believes it would have

jurisdiction over all of the facilities used for

the unbundled wheeling provided by the

intervening public utilities.98 The more

difficult issue is whether some portion of the

facilities used to transmit energy from the

transmitting utility in closest proximity to

the end user (the former supplier of the

bundled product) is local distribution

facilities. We believe that in most, if not all

circumstances, some portion will be local

distribution facilities.

The case law is replete with statements

that the local distribution provision of

section 201 must be given effect. However,

the Supreme Court in both CL&P and Colton,

supra, has stated that whether facilities are

used in local distribution is a question of fact

to be decided by the Commission as an

original matter. Thus, there is no clear case

law on a ‘‘bright line’’ between transmission

and local distribution. In addition, regardless

of the details of the chain of delivery services

necessary to move electric energy from the

generator to the end user, in most cases the

last public utility in the chain will use

facilities that historically were considered

local distribution facilities. Accordingly,

unlike the situation involving unbundled

wholesale wheeling, for which the case law

clearly supports a ‘‘functional’’ test, the

Commission believes the case law and

practical realities of a changing industry

support an analysis of local distribution

facilities based on the facilities’ functional as

well as technical characteristics.

While it would be preferable to draw an

absolutely ‘‘bright’’ line (e.g., based on

technical characteristics such as voltage), the

Commission does not believe this is required

by the case law and, importantly, would not

be a workable approach in all cases because

of the variety of circumstances that may arise

and because utilities themselves classify

facilities differently (e.g., one utility may

classify a 69 kV facility as transmission;

another may classify it as distribution).

Therefore, the Commission is adopting

several indicators it will evaluate in

determining whether particular facilities are

transmission or local distribution in the case

of vertically integrated transmission and

distribution utilities: 99

• Local distribution facilities are normally

in close proximity to retail customers.

• Local distribution facilities are primarily

radial in character.

• Power flows into local distribution

systems, it rarely, if ever, flows out.

• When power enters a local distribution

system, it is not reconsigned or transported

on to some other market.

• Power entering a local distribution

system is consumed in a comparatively

restricted geographical area.

• Meters are based at the transmission/

local distribution interface to measure flows

into the local distribution system.

• Local distribution systems will be of

reduced voltage.100

In summary, for unbundled wholesale

wheeling the Commission will apply a
21732 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

functional test. The only definitive question

will be whether the entity to whom the

power is delivered is a lawful wholesaler. For

unbundled retail wheeling the Commission

will apply a combination functionaltechnical test that will take into account

technical characteristics of the facilities used

for the wheeling. The Commission concludes

that these tests are consistent with the FPA,

its legislative history and the case law

discussed above.

BILLING CODE 6717–01–P

BILLING CODE 6717–01–C

APPENDIX H.—TABLE ES–2.—NATIONAL EMISSIONS OF NOX as Projected in Both Base Cases and All Proposed Rule Scenarios

[Thousand tons]

Year

Under assumption that relative gas and coal prices

remain constant

Under assumption that gas prices increase compared to coal prices

Constant

price-differential

base case

Competition-favorsgas proposed rule

scenario

High-pricedifferential

base case

Competition-favorscoal proposed rule

scenario

Low response proposed rule

scenario

1993 .......................................................................................................... 5,844 5,844 5,844 5,844 5,844

2000 .......................................................................................................... 5,362 5,255 5,672 5,763 5,743

2005 .......................................................................................................... 5,579 5,449 6,053 6,108 6,056

2010 .......................................................................................................... 5,772 5,638 6,426 6,519 6,426
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21733

1The Commission leaves unexplored the precise

meaning of ‘‘deference’’ in these circumstances. At

Continued

Promoting Wholesale Competition Through

Open Access Non- Discriminatory

Transmission Services by Public Utilities

Recovery of Stranded Costs by Public

Utilities and Transmitting Utilities

(As corrected April 25, 1996)

[Docket No. RM95–8–000; Docket No. RM94–

7–001]

Issued April 24, 1996.

HOECKER, Commissioner, concurring in

part and dissenting in part:

General Observations

A. Four years and untold numbers of

conferences, studies, and speculations after

the Energy Policy Act, the Commission today

takes a major step in bringing competition to

the wholesale bulk power market in the

United States. Order No. 888 (FERC Stats. &

Regs. ¶ 31,036), together with our order

establishing an open access same-time

information system (OASIS) (Order No. 889,

FERC Stats. & Regs. ¶ 31,037) and our

proposal to conform all transmission tariffs to

a uniform capacity reservation system (FERC

Stats. & Regs. ¶ 32,517), will set in motion a

dynamism seldom witnessed in the electric

power business. In that sense, the

organizational, operational, and economic

consequences of the requirements we adopt

today defy prediction. I believe nevertheless

that the Commission’s Final Rule today is a

sound and reasoned decision about the

industry as we now know it and as we think

it may evolve. I therefore announce my

unequivocal support for the order’s basic

tenets as we have chosen to implement

them—the unbundled wholesale utility

services, open and non-discriminatory access

to transmission and to information about

transmission, service comparability, an

opportunity for increased competition among

generation sources, coordination with and

deference to state regulatory interests, and

full recovery of eligible stranded

investments.

B. Restructuring the electric power

industry is a matter of national interest and

priority. Electricity is ubiquitous. Its benefits

are key to the American quality of life.

Operating 750,000 MW of generation

capacity arrayed across three synchronous

regional transmission grids, the electric

industry is the nation’s most capital

intensive. The 179 largest investor-owned

utilities alone control nearly $600 billion in

assets. And, total electricity revenues

constitute between 3 and 4 percent of the

gross domestic product (GDP)—larger than

telecommunications, natural gas pipeline,

and airline revenues combined.

Both the Congress and the President have

recognized our obligation to ensure that these

resources are used wisely and efficiently. We

all recognize that systemic change is

happening within the industry and that

regulation must change to take maximum

advantage of the most constructive of those

forces. ‘‘At the center of the success of our

economy is the market, and at the core of the

success of the market is competition,’’ states

the President in his 1996 Economic Report to

the Congress; ‘‘it is competition that drives

down costs and prices, induces firms to

produce the goods consumers want, and

spurs innovation and the expansion of new

markets abroad.’’ Yet, as state and local

governments consider the future of industries

heretofore heavily regulated in the public

interest, deregulation is not enough, states

the President. Competition must be actively

promoted and preserved from the abuses and

distortions associated with monopoly power,

as well as from outdated forms of regulation

that provide inappropriate incentives.

In the electric utility restructuring process,

several difficult challenges must still be met

here and elsewhere. First, policymakers must

make the tough choices to attack access

discrimination and promote competition

while also ensuring reliability and

economical service. Success in these

undertakings may require pricing innovation

and structural reforms to attain significant

long-run gains in efficiency and productivity.

Economic Report, at 183–185. Second, no

transition to a new regime of operating rules

and assumptions, can be achieved reasonably

if regulated companies are shorn of the

opportunity to recover prudently incurred

costs. Utility investments that may become

stranded or uneconomic as competitive

choice displaces franchise monopoly are

estimated to represent a $100 billion-plus

risk for public utilities. State and federal

regulators must confront this issue in the

interest of equity and a swift readjustment to

the new competitive realities. As the

President’s Economic Report makes clear, it

will be important to future suppliers of

private capital for public use that a regulatory

bargain made must remain a bargain kept.

‘‘Credible government is key to a successful

market economy, because it is so important

for encouraging long-term investments.’’ Id.,

at 186–188. Third, maintaining competitive

parity and environmental protection are key

challenges as well. That means, among other

things, that environmental policy must

respond to the environmental risks

associated with restructuring and vice versa.

Id., at 188–189. This assessment of the

realities and challenges facing this

Commission, its state counterparts, and the

diverse elements of the industry substantially

ratifies the Commission’s actions today.

C. The long-run prospect for reform of the

wholesale market is promising, though the

task seems daunting. The preamble to the

Final Rule begins by outlining the difficult

issues that await this Commission and the

industry: (1) Corporate organizational

matters, including the role of independent

system operators (ISOs) in promoting more

efficient operation of the transmission system

on a regional basis; (2) the need for a new

merger policy, which I believe must be

predicated on a thorough understanding of

emerging markets and genuine ratepayer

protections instead of a subjective tally of

supposed ‘‘benefits’’; and (3) further efforts to

make greater use of flow-based pricing where

appropriate. In adopting the OASIS

requirements, we have taken a first step in

recognizing that competitive markets do not

consist of wires and turbines alone, but of

information also. Full competition requires

the consolidation of the electron

transportation system with the electronic

information superhighway.

One thing is abundantly clear:

restructuring will require continued

innovation and fortitude from our capable

staff, cooperation from state regulators,

patience and foresight from legislators and,

most of all, creativity, responsiveness, and

endurance from both utility management and

electric consumers.

II. Concurrence on Specific Issues

The Final Rule resolves certain matters of

policy and law in ways which, despite my

fundamental agreement, I would like to offer

some additional perspectives.

A. Coordinating State and Federal Regulatory

Interests

Perhaps no single issue will influence the

success or failure of restructuring as will the

capacity of the FERC and state regulators to

reach meaningful accommodations as the

electric utility industry becomes increasingly

subject to competitive forces. The vertical

organization and technological integration of

the electric power business contributes to the

impression of a regulatory system riddled

with gaps and overlaps, interregional

inequities, and uncertainty. To the extent

that impression predominates in the months

to come, the pressure from legislators and the

financial community to devise single-minded

national solutions to issues of regional or

local significance will likely prove

irresistible.

The regulation of this industry is a unique

exercise in federalism. The Deputy Secretary

of Energy wisely acknowledged months ago

that, ‘‘the aftermath of FERC’s open access

rulemaking will put to the test our ability to

evolve improved means for unsnarling the

governance problems of federal and state

authorities.’’ Charles B. Curtis, Remarks

Before the Third DOE/NARUC National

Symposium, December 4, 1995. I find no

shortage of good ideas on how to achieve

better state, federal, and inter-regional

cooperation. But, unanswered questions

persist about the availability of sufficient

political will and leadership to achieve

electricity markets that at once satisfy the

need for operational efficiency on a regional

level and also provide the ‘‘opportunity for

experimentation and market testing with the

flexibility to comprehend local differences

* * * [that is] the very genius of the federal

system.’’ Id.

Although it remains unclear today whether

this challenge will be met, I firmly believe

that the Final Rule is a sound resolution of

the jurisdictional questions facing this

Commission as a result of competition and

open access. State PUC comments reflect

enormous concern about the potential loss of

jurisdiction over some wires and services, if

and when ‘‘retail transmission’’ becomes

unbundled. States raise legal objections to

our claim of jurisdiction. While reaffirming

our view that the Commission has exclusive

jurisdiction over the rate, terms, and

conditions of interstate transmission, today’s

order addresses state concerns squarely—

first, by adhering to the practical distinctions

between transmission and distribution set

forth in the NOPR and, second, by according

deference 1 to states where appropriate when
21734 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

one extreme, it could mean courteous regard for

another’s views and, at the other, binding

submission to another’s judgment. I would, for

example, accord state views on cost allocation

considerable or presumptive, but not conclusive,

weight.

2NEPA (42 U.S.C. 4321–4370), the Council on

Environmental Quality’s (CEQ) regulations

promulgated thereunder (40 CFR parts 1500–1508

(1995)), and our own environmental regulations

supplementing those of CEQ (18 CFR part 380

(1995)) together establish an important procedural

mechanism that was designed, not to impose upon

this Commission substantive duties to achieve

particular results, but to infuse our decisional

processes with a broad awareness of the

environmental consequences of our actions. Under

NEPA, the Commission must in any applicable

instance consider and weigh its core objectives and

responsibilities under the Federal Power Act and

the impacts of its actions on all aspects of the

human environment—economic and social as well

as ecological. This exercise requires the

Commission to ascertain the availability and

consider the feasibility of alternative approaches

with lesser impacts. In other words, the

Commission’s duty is to take a ‘‘hard look’’ at the

environmental effects of its major actions.

Robertson v. Methow Valley Citizens Council, et al.,

490 U.S. 332 (1988); Strycker’s Bay Neighborhood

Council, Inc. v. Karlen, et al., 444 U.S. 223 (1980).

The EIS process fulfills that requirement.

retail transmission services become subject to

a FERC tariff. These accommodations will

smooth the transition to a seamless

competitive market with full customer

choice, if and when individual states initiate

retail competition.

While the Final Rule, not unexpectedly,

manifests this Commission’s strong interest

in preventing balkanization of the interstate

power market, nothing adopted by the

Commission today, including the

interpretation of its authority over retail

transmission when retail service is

unbundled, is inconsistent with the

traditional state roles in developing

regulatory, social, and environmental

requirements and programs suited to the

circumstances of their localities. Section I of

the Final Rule is emphatic about this.

I will conclude with two observations on

matters I believe to be of particular

sensitivity to the states. First, it appears to

me that state regulators may impose

distribution and other non-bypassable

charges or other retail requirements on direct

access services, even in those circumstances

where no distribution facilities can be

identified under the functional/technical test.

The Final Rule ensures that result by

acknowledging state authority over

distribution-related services under the FPA.

Second, state authority is traditionally

employed to ensure that power production

conforms to local economic, environmental,

and resource diversity policy preferences. A

state may wish, for example, to ensure that

a direct access industrial customer is no less

obligated to purchase power consistent with

the resource diversity or environmental

requirements than is that customer’s

franchise distribution utility. To the extent

that state requirements to own or purchase a

certain amount of generation from, say,

renewable sources are enshrined in utility

supply portfolios, those states have direct

influence on the economic and

environmental consequences of energy

consumption in that jurisdiction. Moreover,

such requirements ought to be compatible

with open access transmission. However, it

will be important that state authority over

resource procurement be exercised on a not

unduly discriminatory basis. In other words,

a PUC may not treat in-state and out-of-state

suppliers differently. If access over the

network is non-discriminatory in nature, the

federal regulatory and constitutional interests

are arguably satisfied.

B. Environmental Effects of Restructuring

1. Last July, we instructed our staff to

prepare an Environmental Impact Statement

(EIS) in conjunction with this rulemaking.

The Final EIS (FEIS), issued on April 12,

1996, is an impressive and, with respect to

the air impacts of electric restructuring, a

pioneering work. It considers in detail: (1)

The possible environmental consequences of

adopting this Rule, including a number of

additional analyses requested by

commenters, (2) alternative methods of

pursuing open access transmission service,

(3) a range of environmental mitigation

actions proposed by commenters, and (4) the

Commission’s legal and technical ability to

undertake environmental mitigation. On the

whole, I find staff’s studies to be analytically

sound and generally in conformance with my

understanding of this agency’s powers to

engage in environmental mitigation.

Moreover, its conclusions and

recommendations are thoughtful and wellreasoned. I therefore believe that

consideration of the FEIS as part of the

Commission’s actions today meets our

National Environmental Policy Act of 1969

(NEPA) obligations 2 and the requirement of

reasoned decisionmaking.

The FEIS highlights a very important

public health and social welfare issue, not to

mention a matter of great financial

importance to certain utilities. To be specific,

the FEIS examines potential air quality

impacts in the event generation increases

from certain coal-fired units. Open

transmission access is expected by some to

stimulate that additional generation and

hence additional nitrogen oxide (NOX)

emissions and related ozone formation. From

these projections, a substantive and not

altogether constructive debate has ensued. As

Section V of the Final Rule describes more

fully, the Commission conducted additional

studies to respond to comments on the draft

EIS, using new recommended baselines for

comparison. The results confirm that the air

quality impacts of the rule are within reason.

The Commission has satisfied itself that

the three most pressing questions have been

addressed: (1) What increment of the NOX

emissions problem may be attributable to this

Final Rule? (2) Will Final Rule-induced NOX

emission increases be so significant and their

impacts sufficiently adverse to justify an

alternative regulatory approach, such as ‘‘no

action’’ on utility restructuring? (3) Short of

no action, can the Commission undertake

direct actions that mitigate any potential

adverse effects? Based on the FEIS, I can find

no justification in the cause, size, or certainty

of near-term emissions increases for delaying

or diluting the Open Access Rule and no

clear basis for a FERC-sponsored emissions

control regime, even on an interim basis.

2. Having discharged our NEPA

obligations, I cannot pretend that this matter

of public interest is no longer of any interest

or concern to us. Clean air is a birthright. Air

emissions are therefore an important

concern. I would not relegate this issue to the

periphery of our deliberations. If the EIS

process accomplishes nothing else, it has

familiarized the FERC with the difficulties of

addressing the seemingly intractable problem

of NOX emissions. The problem engenders

interregional economic and environmental

conflicts that can be addressed only by a

sophisticated balancing of interests and a

selfless commitment to the greater good. EPA

and several commenters on our Rule express

frustration over the progress being made to

reduce NOX emissions. For this and other

environmental issues, such as NOX waivers,

resort to the courts has become customary,

and complex technological and economic

disputes are the norm. See e.g., Electric

Power Alert, April 24, 1996, at 29–30.

Regions of the country differ, often

vehemently, about the source and effects of

ozone-causing emissions and how best to

curb the generation and transport of

pollutants that create ozone. Utilities in some

regions have made commitments and

invested heavily to achieve ‘‘attainment’’

levels, while the blessings of geography and

circumstance have imposed no such burden

on others. We recognize in essence that

reconciling these interests is a task the

Congress has assigned to the EPA. Although

the Clean Air Act authorizes EPA to develop

a national program to enforce emissions

reduction largely through state

environmental regulatory efforts (the socalled State Implementation Plans (SIPs)), the

statutory process is ponderous in practice.

Moreover, even where gains are expected to

be made in the form of reduced NOX

emissions (e.g., under EPA’s pending

rulemaking to set NOX emissions limitations

for certain types of utility boilers), those

gains might arguably be offset by future

increases in the demand for electricity or,

according to some parties, by the additional

power generation some say will be

encouraged by open access transmission.

The inability to guarantee future NOX

reductions for a variety of reasons that range

well beyond this Rule presents formidable

challenges. EPA places great faith in the

ability of the Ozone Transport Assessment

Group (OTAG), a voluntary multi-state

organization established in part to set up

NOX emission mitigation mechanism, to

address these complex issues and achieve a

resolution. It nevertheless appears to me that,

for the most part, consensus remains distant.

The alternative appears to be an even more

protracted EPA procedure.

With respect to the gravamen of this issue

(i.e., the establishment of an emissions cap

and credit trading system reminiscent of

what Congress ordered for sulphur dioxide

(SO2)), this Commission has no real choice

but to defer to agencies with jurisdiction by

law and special expertise. The EPA has done

an outstanding job implementing the marketbased SO2 allowance program. It is widely

regarded as both creative and successful.
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations 21735

3 18 CFR 35.25 (1995).

4 18 CFR 35.13(h)(38) (1995).

5Revisions to Uniform Systems of Accounts to

Account for Allowances under the Clean Air Act

Amendments of 1990, Order No. 552, III FERC

Statutes and Regulations ¶30,967 (1993).

6My views conform generally to Commissioner

Massey’s partial dissent today.

OTAG, regardless of any concerns about its

processes, brings together a broad range of

regional interests, thereby offering an

unprecedented opportunity for achieving

consensus resolution of this difficult

problem.

3. In my view, it behooves this

Commission to assist in any way it can,

consistent with its expertise and authority, to

find consensual solutions. I do not think that

means denying polluting utilities access to

the transmission system and thereby merely

reinforcing their monopoly power. Rather,

we must stand ready to assist EPA and OTAG

in making competition and environmental

responsibility equally attractive. We have

begun providing that assistance by ensuring

(see II.A. above) that state regulators retain

their customary authority under state law to

structure the generation and purchase power

portfolios of state-regulated utilities.

Moreover, the Commission has in the past

addressed through its rate jurisdiction

various public interest goals, including

environmental concerns, intergenerational

equities, and least-cost planning needs. For

instance, in order to encourage capital

investment in pollution control equipment

and conservation, the Commission has long

allowed utilities to include in rate base the

costs of ‘‘construction work in progress’’

(CWIP) for pollution control devices and fuel

conversion measures that discourage use of

certain fossil fuels.3 In addition, utilities are

not eligible for CWIP treatment for plant

construction not shown to be the product of

integrated resource planning.4

With respect to the NOX issue specifically,

the Commission is competent to help

facilitate an emissions cap and trading

system. For instance, the accounting

treatment provided for the cost of SO2

emissions allowances in rates was done to

assist implementation of the Clean Air Act.5

The same accommodations could be

instituted for a NOX program. Perhaps the

greatest potential for DOE–EPA–OTAG–FERC

collaboration and consultation involves our

knowledge of the industry and, after

preparing the FEIS, our familiarity with the

NOX problem itself. That information should

be useful beyond the confines of this

rulemaking. In addition, the FEIS indicates

(at p. 7–22) that we can structure the

electronic bulletin board systems we require

so as to facilitate the posting of emissions

data required by EPA.

4. Based upon the mutual concerns and the

different but complementary expertise of the

affected agencies, I encourage the

development of consultative mechanisms,

memoranda of understanding, or other

procedures that will support and help ensure

the success of OTAG’s efforts. Such efforts

must be consistent with the goals and

allocation of responsibilities under the Clean

Air Act, and our own regulatory role.

Restructuring may pose some environmental

risks. We think they are small and (at least

eventually) manageable. Further experience

is likely to demonstrate that restructuring

opens up new possibilities for addressing

longstanding environmental problems

associated with utility operations. Open

access enhances the prospects for

environmental dispatch on a statewide or

regional basis. It gives isolated renewable

plants, particularly hydroelectric and wind

power units that are tied to specific

geographical features, better market access. I

must note that investments in DSM and

renewable resources, which offer relatively

stable costs, may be an attractive component

of utilities’ generation portfolios because they

also minimize risks. And, as restructuring

makes electricity a more customer-driven

business, the public’s documented preference

for environmentally benign power will

become more powerful. In addition, efficient

markets provide the necessary means to

‘‘marketize’’ environmental rules and

perhaps to modify siting and other regulatory

processes that are predicated on the vertical

integration of the utility sector. And, finally,

energy services companies that can promote

conservation and generation alternatives

require more open and dynamic markets. For

the environment, the prospects offered by

restructuring are exciting. Inhibiting or

stopping its development will not help it.

III. Partial Dissent

The Final Rule announces that the

Commission will be the ‘‘primary forum’’ to

hear stranded cost claims where a retail

power customer turns wholesale wheeling

customer, usually through a municipalization

(Situation 2). Although the Final Rule

recognizes that states do have authority to

deal with stranded costs in Situation 2, the

majority nevertheless instructs parties to

bring their claims to this Commission ‘‘in the

first instance.’’ However, where costs are

stranded due to state authorized retail

wheeling (Situation 3), the majority takes a

different and, I contend, incongruent

approach that effectively denies any forum

for those costs if state regulators possess

authority to act but do not do so. Because I

find nothing in policy or law to commend

this approach, I respectfully dissent.6

I take issue with the ‘‘primary forum’’

approach because I believe that it: (1)

Requires the Commission to second-guess

state determinations on recovery of costs

incurred at retail at a time when many states

are addressing the issue; (2) will encourage

forum shopping; and (3) is inconsistent with

our approach in the retail wheeling situation;

and (4) involves an unnecessary legal risk for

the Commission.

A. Second-Guessing State Determinations of

Retail Stranded Costs is Unwise and

Unnecessary

The Final Rule’s stranded cost recovery

methodologies and the underlying

jurisdictional assumptions are aimed at

achieving full recovery of all legitimate,

verifiable and prudent stranded costs,

consistent with a utility’s reasonable

expectations and the justness and

reasonableness of the underlying contract. I

believe that this is a worthy objective, but it

is not one which requires the Commission to

second-guess state determinations. As state

proceedings now reveal, the Commission’s

leadership in raising this issue has borne

fruit. Where municipalization is occurring,

states are addressing stranded costs

responsibly. In nearby Virginia, for example,

the Virginia State Corporation Commission

has interceded into the dispute between

Virginia Electric Power Company and the

City of Falls Church over the City’s plans to

undertake a ‘‘muni-lite’’ form of

municipalization. Moreover, the record

before us today does not endorse the view

that municipalization constitutes a major

bypass threat to stranded cost recovery.

Notwithstanding such developments, the

Final Rule announces that the Commission

will be the ‘‘primary forum’’ to hear stranded

cost claims where a retail power customer

turns wholesale wheeling customer, usually

through a municipalization. While

declaration of ‘‘primary forum’’ status sounds

very legalistic, there is in fact no legal basis

for it. The policy is not founded on a concept

of federal preemption in the area. Indeed, the

Federal Power Act provides no basis for

preemption. Moreover, the Final Rule

recognizes that states do have authority to

deal with stranded costs in these

circumstances. The majority’s instruction to

bring claims directly to FERC will, if

anything, afford states a reason to avoid this

difficult issue altogether.

B. The ‘‘Primary Forum’’ Approach May

Encourage Forum Shopping

As a policy matter, the majority’s approach

is peculiar on its face. Although the ‘‘primary

forum’’ approach is intended to eliminate

forum shopping, it will not achieve even that

objective. Indeed, I think the ‘‘primary

forum’’ approach may encourage parties to

forum shop. State commissions or

legislatures will often provide for stranded

cost recovery at the time the wholesale entity

is formed. Similarly, condemnation

proceedings may provide for stranded costs

in whole or part. Moreover, standards for

stranded cost recovery are occasionally

prescribed by statute. In reality, the

Commission cannot preclude the states from

acting on stranded cost issues and our

proposed rule may encourage rather than

discourage forum shopping.

C. The ‘‘Primary Forum’’ Approach Covers

Fact Situations Largely Indistinguishable

From the Retail Wheeling Scenario

The majority’s decision to take primary

jurisdiction of costs where a retail power

customer becomes wholesale wheeling

customer through municipalization and to

distance itself from virtually any cost

recovery responsibility where retail power

customers becomes retail wheeling customers

does not withstand scrutiny. These are not

factually distinguishable cases, insofar as

jurisdiction over stranded costs is concerned.

The inadequacy of the majority’s reasoning is

palpable because it has adopted very

different policies with respect to two

stranded cost situations that, if properly

understood, are virtually indistinguishable.
21736 Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and Regulations

7The policy adopted with respect to Situation 3

is that the Commission would only be a forum for

hearing stranded costs issues in the narrow

circumstance where ‘‘the state regulatory authority

does not have authority under state law to address

stranded costs when the retail wheeling is

required.’’ The majority fails to address what would

happen if a legislature addresses the issue of

stranded costs directly without delegating the task

to a state regulatory authority. I would hope that the

Commission would not set itself up for

confrontation with a state legislature and I would

have preferred that to also exclude those

circumstances ‘‘where the state otherwise addresses

the issue’’ from the circumstances in which the

Commission would act in Situation 3.

8This argument is made both by commenters

arguing that the Commission has no jurisdiction

over stranded costs in Situation 2 or 3 (California

Public Utilities Commission Initial Comments at 7)

and by commenters arguing that the Commission

should assert primary jurisdiction over stranded

costs in both Situations (see e.g., Edison Electric

Institute Initial Comments at IV–13; Coalition For

Economic Competition Initial Comments at 22;

Utilities For An Improved Transition Initial

Comments at 16–26).

First, in both Situations 2 and 3, retail

power costs are stranded by customers who

gain access to FERC jurisdictional

transmission tariffs via state action. In

Situation 2, state municipalization law

governs. In Situation 3, the state has

authorized retail wheeling by statute or

regulation, or both. Notwithstanding the need

for state authorization in both cases, the

majority decides that the Commission should

be the ‘‘primary forum’’ in Situation 2, but

that a much more narrow approach to retail

stranded costs in Situation 3.7 The more

aggressive ‘‘primary forum’’ approach to

municipalization is predicated on the view

that any strandings are a result of an

inducement (i.e., market options) created by

this Commission’s Open Access Rule. Yet,

since both wholesale transmission customers

and retail transmission customers are

‘‘eligible customers’’ under the tariffs

required by this Rule, if the Rule induces the

stranding of retail power costs in one

situation, it obviously does it in both.

As commenters have noted, the

relationship between FERC-regulated

transmission service and retail power

customers is generally the same in both

Situations 2 and 3.8 The similarity runs first

to the actions that actually cause costs to be

stranded. While it is true that retail wheeling

will only occur pursuant to state legislative

or regulatory action, it is also true that a retail

customer can only convert to wholesale

status (e.g., municipalize) pursuant to state

law. This process sometimes may occur in

the absence of regulatory or other oversight

(e.g., municipalization under pre-established

statutory scheme), or with direct and

immediate review and approval. The current

evidence reflects active state commission

oversight, typically. In this latter case, there

is even less reason to distinguish between

these Situations.

The majority implicitly seeks to delimit the

area of appropriate state authority over

stranded costs according to whether the state

acts directly and by current enactments to

authorize retail wheeling, on one hand, or

less directly through established state

municipalization laws, on the other.

However, costs could be stranded under state

law by either action. Under the former

scenario, however, a state is presumed to be

more willing and capable of dealing with

stranded costs. Under the latter, it is

presupposed to be less interested. This

distinction is specious.

A second similarity pertains to the

jurisdictional status of transmission service.

The Commission has been clear and

consistent that the FPA gives the

Commission exclusive jurisdiction over

interstate transmission service, regardless of

whether the customer is a wholesale or a

retail wheeling customer. It is this authority

upon which we rely to claim jurisdiction

over transmission assets and related costs

originally incurred to provide customers at

the retail level with bundled service. New

wheeling customers in both Situations 2 and

3 will take service under FERC open access

tariffs. There are identical cost-causational

facts in Situations 2 and 3, yet the majority

adopts very different outcomes in each case

under the Final Rule.

D. The ‘‘Primary Forum’’ Approach is More

Subject to Legal Challenge

In my view, our disagreement involves

more than a policy choice. The majority’s

chosen approach clearly makes our stranded

cost recovery approach more vulnerable to a

legal challenge. The cost recovery scheme

which would result from the majority’s

approach will render a FERC-ordered

transmission surcharge to recover retail

stranded costs susceptible to legal challenge

on the basis that it is anti-competitive and

unduly discriminatory. The ‘‘primary forum’’

approach imposes upon a retail-turnedwholesale customer something akin to

double jeopardy. In other words, a departing

customer might have to pay both an exit fee

for the retail costs which the state

commission finds it has stranded and, in

addition, an entry fee for wholesale access in

the amount of the additional retail stranded

costs which FERC determines are

inadequately covered by state proceedings.

This, in my view, makes the Final Rule

more susceptible to challenges that FERC’s

transmission surcharge is anti-competitive.

E.g., Cajun Electric Power Cooperative, Inc. v.

FERC, 28 F.3d 173 (D.C. Cir. 1994). The

second-guessing of states inherent in the

‘‘primary forum’’ approach makes any

arguments that stranded cost recovery is anticompetitive more difficult to overcome than

if the stranded costs resulted from wholesale

customers simply changing wholesale

suppliers. This is because, unlike wholesaleto-wholesale strandings, the Commission

cannot plausibly argue that the costs incurred

were originally addressed in the context of its

own rate decisions or were previously part of

its responsibility for administering wholesale

service obligations.

I am strongly persuaded that the

Commission would be on much stronger

legal ground if we were to treat state

authority over stranded costs with the same

deference in the municipalization or ‘‘retailturned-wholesale’’ situation in the same

manner as the Final Rule prescribes for

situations where retail wheeling occurs. In

the latter case, the Commission ought to

provide a forum where neither the state

legislature nor the state commission attempts

to address this important transition issue.

James J. Hoecker,

Commissioner.

Promoting Wholesale Competition Through

Open Access Non-Discriminatory

Transmission Services by Public Utilities

Recovery of Stranded Costs by Public

Utilities and Transmitting Utilities

[Docket No. RM95–8–000; Docket No. RM94–

7–001]

Issued April 24, 1996.

MASSEY, Commissioner, dissenting in

part:

I support all of the provisions of this rule

save one, the provision on stranded costs

arising from retail competition and from

municipalization. When the Commission

issued the Notice of Proposed Rulemaking, I

stated that the Commission should treat

stranded costs arising from retail competition

and municipalizations similarly, as follows:

For either retail competition or

municipalization, when the state commission

has authority to address the issue, and uses

such authority to decide the recoverability of

the stranded costs, the state’s decision should

not be second-guessed by this Commission.

However, when a state commission does not

have the authority to decide the

recoverability of stranded costs, or has

authority but does not use it, this

Commission should act on requests for

stranded cost recovery.

My approach would assure utilities of

getting a decision on the merits of their

claim. Costs would not be stranded for lack

of a regulatory decision. At the same time,

this Commission would allow states to make

decisions, when they have authority, on

issues of critical concern to their local

utilities and ratepayers. Only if states lack, or

fail to use, such authority would this

Commission step in to assure the utility of

receiving a decision on the merits.

For the reasons I stated then, I still disagree

with the rule’s approach to stranded costs

arising from retail competition or

municipalization. In all other respects, I

support this rule.

William L. Massey,

Commissioner.

[FR Doc. 96–10694 Filed 5–9–96; 8:45 am]

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