17662 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

amounts of iron-containing supplement

powders which are difficult for children

to handle without spilling or to swallow

without gagging. A child would have to

ingest approximately 11 tablespoons of

petitioner’s product (20 mg/kg in a 10 kg

child) in order to produce a minimally

toxic dose. Approximately 100

tablespoons would be required for a

lethal dose. Most of the factors that

make toxic ingestions of petitioner’s

unflavored product unlikely would also

apply to flavored supplement powders.

After considering the available

information, the Commission

preliminarily concludes that the degree

and nature of the hazard to children

presented by the availability of dietary

supplement powders with no more than

the equivalent of 0.12 percent weight-toweight elemental iron are such that

special packaging is not required to

protect children from serious personal

injury or serious illness resulting from

handling, or ingesting such substance.

Accordingly, the Commission voted to

grant the petition and proposes to

amend 16 CFR 1700.14(a)(13) to exempt

from requirements for child resistant

packaging those dietary supplement

powders with no more than the

equivalent of 0.12 percent weight toweight-elemental iron.

E. Regulatory Flexibility Certification

Under the Regulatory Flexibility Act

(Public Law 96–354, 5 U.S.C. 601 et

seq.), when an agency issues proposed

and final rules, it must examine the

rules’ potential impact on small

businesses. The Act requires agencies to

prepare and make available for public

comment an initial regulatory flexibility

analysis if a proposed rule would have

a significant impact on a substantial

number of small businesses, small

organizations, and small governmental

jurisdictions.

The exemption proposed below, to

exempt powdered iron-containing

dietary supplements from CRP

requirements, will give manufacturers of

these products the option of packaging

products using any packaging they

choose. As far as CPSC is aware,

powdered iron-containing dietary

supplements are not currently packaged

in CRP. The Commission’s Compliance

staff is exercising its enforcement

discretion regarding these products

pending completion of this rulemaking.

Thus, the proposed exemption will

bring no change in the current

packaging of products subject to the

exemption. Accordingly, the

Commission concludes that this

exemption will not have any significant

economic effect on a substantial number

of small entities.

F. Environmental Considerations

The Commission’s regulations at 16

CFR 1021.5(c)(3) state that rules

exempting products from child-resistant

packaging requirements under the PPPA

normally have little or no potential for

affecting the human environment. The

Commission does not foresee any

special or unusual circumstances

surrounding this proposed rule.

Therefore, exempting these products

from the PPPA requirements will have

little or no effect on the human

environment. For this reason, the

Commission concludes that no

environmental assessment or impact

statement is required in this proceeding.

G. Effective Date

Since the proposed rule provides for

an exemption, no delay in the effective

date is required. 5 U.S.C. 553(d)(1).

Accordingly, the rule shall become

effective upon publication of the final

rule in the Federal Register.

List of Subjects in 16 CFR Part 1700

Consumer protection, Infants and

children, Packaging and containers,

Poison prevention, Toxic substances.

Conclusion

For the reasons given above, the

Commission amends Title 16 of the

Code of Federal Regulations to read as

follows:

PART 1700—[AMENDED]

1. The authority citation for part 1700

continues to read as follows:

Authority: Pub. L. 91–601, secs. 1–9, 84

Stat. 1670, 15 U.S.C. 1471–76, Secs. 1700.1

and 1700.14 also issued under Pub. L. 92–

573, sec. 30(a), 88 Stat. 1231, 15 U.S.C.

2079(a).

2. Section 1700.14(a)(13) is revised to

read as follows:

§ 1700.14 Substances requiring special

packaging.

(a) * * *

(13) Dietary supplements containing

iron. Dietary supplements, as defined in

§ 1700.1(a)(3), that contain an

equivalent of 250 mg or more of

elemental iron, from any source, in a

single package in concentrations of

0.025 percent or more on a weight-tovolume basis for liquids and 0.05

percent or more on a weight-to-weight

basis for nonliquids (e.g., powders,

granules, tablets, capsules, wafers, gels,

viscous products, such as pastes and

ointments, etc.) shall be packaged in

accordance with the provisions of

§ 1700.15 (a), (b), and (c), except for the

following:

(i) Preparations in which iron is

present solely as a colorant; and

(ii) Powdered preparations with no

more than the equivalent of 0.12 percent

weight-to-weight elemental iron.

* * * * *

Dated: April 3, 1995.

Sadye E. Dunn,

Secretary, Consumer Product Safety

Commission.

Reference Documents

The following documents contain

information relevant to this rulemaking

proceeding and are available for inspection at

the Office of the Secretary, Consumer

Product Safety Commission, Washington,

Room 502, 4330 East-West Highway,

Bethesda, Maryland 20814.

1. Briefing Memorandum with attached

briefing package, March 14, 1995.

2. Memorandum from Sandra E. Inkster,

Ph.D., HSPS, to Jacqueline N. Ferrante, Ph.D.,

HSPS, ‘‘Review of Iron Toxicity: Relevance to

a Petition Requesting Exemption for

Powdered, Iron-Containing Dietary

Supplements,’’ February 15, 1995.

3. Memorandum from Catherine A.

Sedney, EPHF, to Jacqueline N. Ferrante,

Ph.D., HSPS, ‘‘Petition to Exempt IronContaining Supplement Powders from PPPA

Requirements,’’ February 16, 1995.

4. Memorandum from Marcia P. Robins,

EPSS, to Jacqueline N. Ferrante, Ph.D., HSPS,

‘‘Preliminary Market Information: Petition for

Exemption from Child-Resistant Packaging

Requirements for Powdered Iron-Containing

Dietary Supplements,’’ March 10, 1995.

[FR Doc. 95–8522 Filed 4–6–95; 8:45 am]

BILLING CODE 6355–01–P

DEPARTMENT OF ENERGY

Federal Energy Regulatory

Commission

18 CFR Part 35

[Docket Nos. RM95–8–000 and RM94–7–

001]

Promoting Wholesale Competition

Through Open Access Nondiscriminatory Transmission Services

by Public Utilities, Recovery of

Stranded Costs by Public Utilities and

Transmitting Utilities; Proposed

Rulemaking and Supplemental Notice

of Proposed Rulemaking

March 29, 1995.

AGENCY: Federal Energy Regulatory

Commission.

ACTION: Notice of proposed rulemaking

and supplemental notice of proposed

rulemaking.

SUMMARY: The Federal Energy

Regulatory Commission (Commission) is

proposing to require that public utilities

owning and/or controlling facilities

used for the transmission of electric

energy in interstate commerce have on
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17663

file tariffs providing for nondiscriminatory open access transmission

services. The Commission is also

proposing to permit public utilities and

transmitting utilities to recover

legitimate and verifiable stranded costs.

The Commission’s goal is to encourage

lower electricity rates by structuring an

orderly transition to competitive bulk

power markets. The Commission is

seeking public comment on its

proposals.

DATES: Written comments must be

received by the Commission by August

7, 1995. Reply comments must be

received by the Commission by October

4, 1995.

FOR FURTHER INFORMATION CONTACT:

David D. Withnell, Office of the General

Counsel, Federal Energy Regulatory

Commission, 825 North Capitol St.,

NE., Washington, DC 20426,

telephone: (202) 208–2063, (Docket

No. RM95–8–000—legal issues).

Deborah B. Leahy, Office of the General

Counsel, Federal Energy Regulatory

Commission, 825 North Capitol

Street, NE., Washington, DC 20426,

telephone: (202) 208–2039, (Docket

No. RM94–7–001—legal issues).

Michael A. Coleman, Office of Electric

Power Regulation, Federal Energy

Regulatory Commission, 825 North

Capitol Street, NE., Washington, DC

20426, telephone: (202) 208–1236,

(technical issues).

ADDRESSES: Send comments to: Office of

the Secretary Federal Energy Regulatory

Commission 825 North Capitol Street,

N.E. Washington, D.C. 20426.

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 Room 3401, at 941 North Capitol

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. To

access CIPS, set your communications

software to 19200, 14400, 12000, 9600,

7200, 4800, 2400, 1200 or 300bps, full

duplex, no parity, 8 data bits and 1 stop

bit. The full text of this document will

be available on CIPS for 60 days from

the date of issuance in ASCII and

WordPerfect 5.1 format. After 60 days

the document will be archived, but still

accessible. 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 room 3104,

941 North Capitol Street, NE.,

Washington, DC 20426.

Promoting Wholesale Competition

Through Open Access Non-discriminatory

Transmission Services by Public Utilities

Docket No. RM95–8–000

Recovery of Stranded Costs by Public

Utilities and Transmitting Utilities

Docket No. RM94–7–001

Notice of Proposed Rulemaking and

Supplemental Notice of Proposed

Rulemaking

March 29, 1995.

Table of Contents

I. Introduction

II. Public Reporting Burden

III. Discussion

A. Summary of Authority and Findings

B. Legal Authority

1. Undue Discrimination/Anticompetitive

Effects

2. Section 211 Services

C. Background

1. Structure of the Electric Industry at

Enactment of Federal Power Act

2. Significant Changes in the Electric

Industry

3. The Public Utility Regulatory Policies

Act and the Growth of Competition

4. The Energy Policy Act

5. The Present Competitive Environment

a. Use of Sections 211 and 212 to Obtain

Transmission Access

b. Commission’s Comparability Standard

c. Lack of Market Power in New Generation

d. Further Commission Action Addressing

a More Competitive Electric Industry

D. Need for Reform

1. Market Power

2. Discriminatory Access

3. Analogies to the Natural Gas Industry

4. Coordination Rates

E. The Proposed Regulations

1. Non-discriminatory Open Access Tariff

Requirement

2. Implementing Non-discriminatory Open

Access: Functional Unbundling

3. Real-time Information Networks

4. Non-discriminatory Open Access Tariff

Provisions

5. Pro Forma Tariffs

6. Broader Use of Section 211

7. Status of Existing Contracts

8. Effect of Proposed Rule on Commission’s

Criteria for Market-based Rates

9. Effect of Proposed Rule on Regional

Transmission Groups

F. Stranded Costs and Other Transition

Costs

G. Transmission/Local Distribution

H. Implementation

IV. Regulatory Flexibility Act

V. Environmental Statement

VI. Information Collection Statement

VII. Public Comment Procedures Regulatory

Text

Appendices (Appendices A, B and C will

not be published in the Federal Register.)

A. Electric Utility Average Revenue Per

Kilowatthour, by State

B. Point-to-Point Tariff

C. Network Tariff

D. List of Commenters in Docket No. RM94–

7–000

I. Introduction

The electric power industry is today

an industry in transition. In response to

changes in the law, technology, and

markets, competitive pressures are

steadily building in the industry. Once

the primary domain of large, vertically

integrated utilities providing power at

regulated rates, the industry now

includes companies selling

‘‘unbundled’’ power at rates set by

competitive markets. New generating

facilities are being built at costs well

below the average costs of some

vertically integrated utilities. In this

environment, more competition will

mean lower rates for wholesale

customers and, ultimately, for

consumers.

The Commission’s goal is to

encourage lower electricity rates by

structuring an orderly transition to

competitive bulk power markets.

Development of such markets is certain.

The questions are when and how.

Experience has shown that competitive

pressures cannot be contained for long

without serious economic distortions.

Competition will, we are confident,

result in lower rates. But experience has

also shown that a measured transition

from regulated to competitive markets is

absolutely essential.

Moving to competitive generation

markets will fundamentally change

long-standing regulatory relationships.

Utilities have invested billions of

dollars in order to meet their

obligations. Those investments have

been made under a ‘‘regulatory

compact’’ whereby utilities—and their

shareholders—expect to recover

prudently incurred costs. With the

advent of competition, even prudent

investments may become stranded.

Reliance on past contractual and

regulatory practices must be recognized

and past investments must be protected

to assure an orderly, fair transition to

competition.

The focus of our proposal today is to

facilitate competitive wholesale electric

power markets. The key to competitive

bulk power markets is opening up

transmission services. Transmission is

the vital link between sellers and

buyers. To achieve the benefits of

robust, competitive bulk power markets,

all wholesale buyers and sellers must

have equal access to the transmission
17664 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

1Throughout this NOPR this requirement will be

referred to as the ‘‘non-discriminatory open access’’

requirement.

2Notice of Technical Conference and Request for

Comments, Docket No. RM95–9–000.

3Section 206 of the FPA applies to public

utilities, whereas section 211 applies to

transmitting utilities. A public utility is defined

under section 201(e) of the FPA as ‘‘any person who

owns or operates facilities subject to the jurisdiction

of the Commission under this Part (other than

facilities subject to such jurisdiction solely by

reason of sections 210, 211, or 212).’’ A transmitting

utility is defined under section 3(23) of the FPA 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.’’ Not all transmitting utilities are public

utilities. For instance, a municipally-owned electric

utility that owns transmission facilities that are

used for the sale of electric energy at wholesale is

a transmitting utility, but is not a public utility.

4See Kansas City Power & Light Company, 67

FERC ¶ 61,183 at 61,557 (1994) (KCP&L).

grid. Otherwise, efficient trades cannot

take place and ratepayers will bear

unnecessary costs. Thus, market power

through control of transmission is the

single greatest impediment to

competition. Unquestionably, this

market power is still being used today,

or can be used, discriminatorily to block

competition.

The Commission has an obligation to

prevent unduly discriminatory practices

in transmission access. In current

circumstances, the absence of tariffs

offering open access, nondiscriminatory transmission services by

each public utility impedes the

transition to competitive markets greatly

enough to be unduly discriminatory

under section 206 of the Federal Power

Act (FPA). Proceeding as we have in the

past, case-by-case, would delay

unreasonably the transition to

competitive markets. A patchwork of

transmission systems—some open and

some not—would also lead to unfair

practices and inequitable burdens.

At the same time, while fulfilling our

duty under section 206 of the FPA to

cure undue discrimination, we see no

need now to abrogate existing

contractual relationships. Rather, we

propose to provide a transition to a

competitive generation industry that

allows for the recovery of legitimate,

prudent and verifiable costs lawfully

incurred to serve customers under the

terms of existing contracts. In the

context of today’s electric industry, the

goals of increased competition and

lower bulk power rates are best pursued

through a structured transition rather

than through abrogating all existing

contracts.

In short, at this crossroad for the

industry, it is critical to take the

regulatory steps now to facilitate the

transition to competitive bulk power

markets in an orderly manner. The most

important of these steps are to ensure

non-discriminatory access to the

transmission grid for all wholesale

buyers and sellers of electric energy in

interstate commerce, and to address the

transition costs associated with open

transmission access. The Commission

will take these steps in a manner

consistent with maintaining the

reliability of the interstate transmission

grid.

In this proceeding, the Commission

pursuant to its authority under sections

205 and 206:

• proposes to require all public utilities

owning or controlling facilities used for

transmitting electric energy in interstate

commerce to file open access transmission

tariffs;

• proposes to require the utilities to take

transmission service (including ancillary

services) for their own wholesale sales and

purchases of electric energy under the open

access tariffs;

• issues a supplemental proposed rule to

permit the recovery of legitimate and

verifiable stranded costs associated with

requiring open access tariffs; and

• proposes regulations to implement the

filing of the open access tariffs and the initial

rates under these tariffs.

The open access tariffs—to be offered

to all sellers and buyers of electric

energy sold at wholesale in interstate

commerce—must offer wholesale

transmission services (network and

point-to-point), including ancillary

services, on a non-discriminatory basis

to third parties.1 In addition, the public

utility must price separately all

wholesale generation and transmission

services (including ancillary services)

and take wholesale transmission service

under its own tariff, i.e., ‘‘functionally

unbundle’’ its wholesale generation and

transmission services. The proposed

rule does not mandate the corporate

separation of generation, transmission,

and distribution functions.

The proposed rule proposes pro forma

tariffs for network and point-to-point

services, defines non-discriminatory

open access to include access to

ancillary services, and requires that

tariffs include a reciprocity provision

requiring any user or agent of the user

of the tariff that owns and/or controls

transmission facilities to provide nondiscriminatory access to the tariff

provider.

To assure that the open access tariffs

promote competition and do not operate

in an unduly discriminatory manner,

the proposed rule would require public

utilities to provide all actual or potential

transmission users the same access to

information as the public utility enjoys.

The Commission is proposing to

develop industry-wide real-time

information networks in a separate

Notice of Technical Conference that is

being issued concurrently with this

proposed rule.2

Not all transmitting utilities are

public utilities subject to the

Commission’s jurisdiction under section

206 of the FPA.3 The Commission

cannot pursuant to section 206 require

non-public utilities to file open access

tariffs . Therefore, the proposed rule

would encourage the broad application

of section 211 as an additional means of

achieving the goal in the Energy Policy

Act of 1992 of promoting increased

wholesale competition. Without broader

application of section 211, wholesale

bulk power market participants could be

denied access to more competitive

generation sources to the detriment of

consumers.

We presently do not find it necessary

to use our authority under section 206

of the FPA to reform public utilities’

existing requirements contracts or any

other contracts to eliminate undue

discrimination or attain more

competitive bulk power markets.

However, we seek information about

existing requirements contracts,

including the remaining life and notice

provision in each such contract, and

whether it would be in the public

interest to modify any existing

contracts.

The Commission believes that the

open access requirement will eliminate

the transmission market power of public

utilities by ensuring that all participants

in wholesale power markets will have

non-discriminatory open access to the

transmission systems of public utilities.

This market power has been the

Commission’s primary concern in recent

years in analyzing requests for marketbased generation rates. We therefore

seek comments on the effect of industrywide non-discriminatory open access on

the Commission’s criteria for

authorizing power sales at market-based

rates.

The Commission’s market-rate criteria

also have included other aspects of

market power, such as generation

dominance. In particular, we note the

Commission’s recent KCP&L decision,

in which we dropped the generation

dominance standard for market-based

sales from new capacity.4 This rule

proposes to codify that decision, and

seeks comment on whether the

generation dominance standard should

also be dropped for market-based sales

from existing capacity.

In issuing this proposed rule, we are

particularly concerned with its possible

effect on stranded costs. It is important
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17665

5See Recovery of Stranded Costs by Public

Utilities and Transmitting Utilities, Notice of

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

IV FERC Stats. & Regs., Proposed Regulations

¶ 32,507 (Stranded Cost NOPR).

6Because power pools raise complex issues, we

seek comments on how to implement the NOPR for

power pools. 7 16 U.S.C. 824d(b) and 824(d).

to couple our open access rule with a

rule ensuring recovery of all legitimate

transition costs, consistent with the

guidelines established herein.

Accordingly, we are making preliminary

findings with respect to the Stranded

Cost NOPR issued on June 29, 1994,

seeking additional comments, and

consolidating the Stranded Cost NOPR5

with this proposed rule.

Because of the benefits associated

with the transition to a competitive

regime, it is important to have the open

access tariffs in place as soon as

possible. Thus, we propose a two-stage

procedure to accomplish that goal. In

Stage One, we would place generic open

access tariffs in effect simultaneously on

a date certain for every public utility

that owns and/or controls transmission

facilities 6 and would establish rates for

each public utility based on the most

current Form No. 1 data available. In

Stage Two, utilities would be free to

propose changes to the rates, terms, and

conditions in the generic tariffs and

customers and others would be free to

file complaints seeking changes in the

rates, terms, and conditions. However,

Stage Two tariffs must contain at least

the non-price tariff terms and conditions

contained in the pro forma tariffs.

Comments of all interested persons

should be filed pursuant to the

procedures set out below.

II. Public Reporting Burden

A. Docket No. RM95–8–000

The proposed rule specifies filing

requirements to be followed by public

utilities in making non-discriminatory

open access tariff filings. The

information collection requirements of

the proposed rule are attributable to

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

current total annual reporting burden

for FERC–516 is 784,488 hours.

The proposed rule requires public

utilities filing non-discriminatory open

access tariffs to provide certain

information to the Commission. The

public reporting burden for the

information collection requirements

contained in the proposed rule is

estimated to average 300 hours per

response. This estimate includes 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 required

information.

There are approximately 328 public

utilities, including marketers and

wholesale generation entities. The

Commission estimates that

approximately 137 of these utilities own

or control facilities used for the

transmission of electric energy in

interstate commerce and will respond to

the information collection. The

respondents would be all public utilities

required to file non-discriminatory open

access tariffs. These are the public

utilities that are also transmitting

utilities and either file Form 715 or have

it filed on their behalf. The information

will be provided with each filing by a

respondent. Accordingly, the public

reporting burden is estimated to be

41,100 hours.

Send comments regarding this burden

estimate or any other aspect of the

Commission’s collection of information,

including suggestions for reducing this

burden, to the Federal Energy

Regulatory Commission, 941 North

Capitol Street NE., Washington, DC

20426 [Attention: Michael Miller,

Information Services Division, (202)

208–1415], and to the Office of

Information and Regulatory Affairs of

the Office of Management and Budget

[Attention: Desk Officer for Federal

Energy Regulatory Commission (202)

395–3087].

B. Docket No. RM94–7–001

The initially proposed rule would

require public utilities seeking to

recover stranded costs to provide certain

information to the Commission. The

Commission estimated that the public

reporting burden for the information

collection requirements contained in the

initially proposed rule would be 50

hours per response. The Commission

also estimated that there would be ten

respondents to the information

collection annually.

Under the proposed rule contained in

this supplemental notice of proposed

rulemaking, the information that public

utilities will be required to file is not

substantially different from that

required by the initially proposed rule.

The Commission also believes that the

average filing burden and frequency of

filing will be approximately the same as

under the initially proposed rule.

Therefore, the Commission estimates

that there will be no additional public

filing burden associated with the

proposed rule.

Send comments regarding this burden

estimate or any other aspect of the

Commission’s collection of information,

including suggestions for reducing this

burden, to the Federal Energy

Regulatory Commission, 941 North

Capitol Street, NE., Washington, DC

20426 [Attention: Michael Miller,

Information Services Division, (202)

208–1415], and to the Office of

Information and Regulatory Affairs of

the Office of Management and Budget

[Attention: Desk Officer for Federal

Energy Regulatory Commission (202)

395–3087].

III. Discussion

A. Summary of Authority and Findings

The primary purposes of the Federal

Power Act are to curb abusive practices

by public utility companies and to

protect consumers from excessive rates

and charges. To achieve these ends,

section 205 of the FPA requires that no

public utility shall ‘‘make or grant any

undue preference or advantage to any

person or subject any person to any

undue preference or disadvantage,’’

with respect to the transmission of

electric energy in interstate commerce

or the sale for resale of electric energy

in interstate commerce. 7 Section 206 of

the FPA authorizes the Commission to

investigate and remedy unduly

discriminatory or preferential rules,

regulations, practices or contracts

affecting public utility rates for

transmission in interstate commerce or

for sales for resale in interstate

commerce.

The significant technological,

structural, statutory, and regulatory

changes over the past twenty years have

affected the electric utility industry

such that competitive bulk power

markets are now emerging. This

transition has expanded what the

Commission must consider to be undue

discrimination in the rates, terms, and

conditions offered by public utilities.

We find that utilities owning or

controlling transmission facilities

possess substantial market power; that,

as profit maximizing firms, they have

and will continue to exercise that

market power in order to maintain and

increase market share, and will thus

deny their wholesale customers access

to competitively priced electric

generation; and that these unduly

discriminatory practices will deny

consumers the substantial benefits of

lower electricity prices. We propose to

prevent this discrimination by requiring

all public utilities owning and/or

controlling transmission facilities to

offer non-discriminatory open access

transmission services.

At the same time, we see no need now

to abrogate existing contractual

relationships. Instead, contracts should
17666 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

8On February 16, 1995, the Coalition for a

Competitive Electric Market filed a petition for a

rulemaking on comparability. The Industrial

Consumers and the Transmission Access Policy

Study Group filed comments in support of the

petition. The Commission will not separately notice

the Coalition’s petition, but seeks comment on that

pleading, and the supporting pleadings, in this

notice of proposed rulemaking.

9Associated Gas Distributors v. FERC, 824 F.2d

981, 998 (D.C.Cir. 1987), cert. denied, 485 U.S. 1006

(1988) (AGD).

10See Gulf States Utilities Company v. FPC, 411

U.S. 747, 758–59 (1973).

11 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.

12Order No. 436, Regulation of Natural Gas

Pipelines After Partial Wellhead Decontrol, III FERC

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

(1985).

13AGD, supra, 824 F.2d at 997.

14 Id. at 998.

15 410 U.S. 366 (1974).

16 Id. at 375–76.

17 574 F.2d 610 (D.C. Cir. 1978).

be permitted to run their course.

Additionally, we believe that recovery

of legitimate stranded costs is critical to

the successful transition of the electric

utility industry from a tightly regulated,

cost-of-service utility industry to an

open access, competitively priced

power industry.

The requirement of open access

coupled with the recovery of legitimate

stranded costs furthers the

Congressional purposes embodied in the

Federal Power Act and the Energy

Policy Act of 1992 of protecting

consumers, ensuring reasonable rates,

and encouraging competition.

Below, we set out the Commission’s

legal authority to require nondiscriminatory open access, the relevant

historical developments in the electric

industry, and the need for regulatory

reform. 8

B. Legal Authority

1. Undue Discrimination/

Anticompetitive Effects

The Commission has authority to

remedy undue discrimination. That is

clear. Some may argue that case law

under the FPA limits our authority to

order wheeling. We have carefully

analyzed relevant cases examining our

wheeling authority. We conclude that

we have authority to require wheeling,

or non-discriminatory open access, as a

remedy for undue discrimination. Our

analysis of the case law is set forth

below.

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.9 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 as a remedy for undue

discrimination. 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.’’ 10

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.11 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 NGA was

upheld and discussed in detail in AGD.

In AGD, the court upheld in relevant

part the Commission’s Order No. 436.12

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 were

‘‘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.13 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.

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.14

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)15 That case was a

civil antitrust suit against an electric

utility. The Court rejected the argument

that the District Court could not order

wheeling because to do so would

conflict with the Federal Power

Commission’s (FPC) purported wheeling

authority.16 It pointed out 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 granted power to

order wheeling. The Otter Tail case,

however, did not address whether the

Commission can require transmission in

fulfillment of its duty to remedy undue

discrimination.

Richmond Power & Light Company v.

FERC (Richmond)17 also did not involve
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17667

18 Id. at 620.

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

20 606 F.2d 1156 (D.C. Cir. 1979).

21While 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.

22 606 F.2d at 1168.

23 Id. at 1169; see also Municipalities of Groton v.

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

24 660 F.2d 668 (5th Cir. 1981), cert. denied sub

nom. Fort Pierce Utilities Authority v. FERC, 459

U.S. 1156 (1983).

25FP&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.

26All 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).

27Under 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’’).

28 Id. at 676.

29 Id. at 678.

30The 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.

requiring wheeling to remedy undue

discrimination. In that case, 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 * * *.’’ 18

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.19 The case thus does not in any

way limit the Commission’s authority to

remedy undue discrimination.

In Central Iowa Power Cooperative v.

FERC,20 the FPC21 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.’’ [ 22]

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.23

However, neither the Commission nor

the court was presented with the

argument that wheeling was necessary

as a remedy for undue discrimination.

In Florida Power & Light Company v.

FERC (Florida),24 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.25 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.26 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.27 The Commission order

would impose common carrier status on

FP&L, the court found.28 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.29

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.30 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
17668 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

31 824 F.2d at 999.

32 Id. at 999.

33 Id. at 1006.

34See, 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).

35 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 Natural Gas Act) to remedy undue

discrimination.

36See El Paso Electric Company and Central and

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

61,916 (1994) (CSW), reh’g pending.

37Paul 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).

38See Joskow, supra note 37, at 312; see also

Phillips, supra note 37, at 12.

39See Joskow, supra note 37, at 312; see also

Phillips, supra note 37, at 12–13.

40See Joskow, supra note 37, at 312–13; see also

Phillips, supra note 37, 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).

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. [ 31]

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.’’ 32 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.33

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.34 Thus, we conclude that

we have the authority to remedy undue

discrimination and anticompetitive

effects by requiring all public utilities

that own and/or control transmission

facilities to file non-discriminatory open

access transmission tariffs.

2. Section 211 Services

In concluding that we must invoke

our section 206 authority to remedy

undue discrimination and

anticompetitive actions in the electric

industry, we have carefully considered

the goals of Title VII of the Energy

Policy Act, and whether section 211, by

itself, is sufficient to remedy undue

discrimination in public utility

transmission services.35 Title VII of the

Energy Policy Act, which amended

section 211 of the FPA, 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, 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. While

we interpret section 211 to permit a

customer or group of customers to seek

broad tariff-like arrangements,36 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 cannot be cured

effectively through section 211.

The Commission believes that its

actions under sections 205 and 206 will

complement the section 211 procedures

in achieving the goals of creating more

competitive bulk power markets and

lower rates for consumers, while

avoiding many years of costly and

unnecessary litigation. Section 211 will

be particularly important for developing

non-discriminatory access by nonpublic utilities.

C. Background

1. 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.37 Thus, there

was no pressure on regulatory

commissions to use regulation to affect

the structure of the industry.38

2. 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.39 This

was the beginning of periods of rapid

inflation, higher nominal interest rates,

and higher electricity rates.40 During
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17669

41See Joskow, supra note 37, at 313; see also

Phillips, supra note 37, at 13.

42See generally Jersey Central Power & Light

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

1987).

43 Id.

44See Pierce, supra note 40, 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.

45 Id.

46See 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%.’’).

47See Phillips, supra note 37, at 13. Fossil fuelfired 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.

48Based 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)).

49 Id.

50See Black & Pierce, supra note 46, at 1346

(These writeoffs were ‘‘about 17% of the book value

of total 1992 utility investment.’’).

51 Id.

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

disallowances reversed utilities’ incentives to

overinvest, and made utilities extremely reluctant

to build new power plants.’’).

53See 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).

54 Id. at 965.

55Energy 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.’’)

56 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.’’).

57 ‘‘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.

58See Charles E. Bayless, Less is More: Why Gas

Turbines Will Transform Electric Utilities, Pub.

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

59 Id. at 24.

this time, consumers became concerned

about higher electricity rates and

questioned any price increases filed by

utilities.41

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.42 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.43 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.44 In addition, by

the 1980s, the oil cartel collapsed, with

a resulting glut of low-priced oil.45 At

the same time, inflation substantially

increased the costs of these large

baseload generating plants.46 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.47

As a result, expensive large baseload

plants came onto the market or were in

the process of being constructed, for

which there was little or no demand.

Accordingly, between 1970 and 1985,

average residential electricity prices

more than tripled in nominal terms, and

increased by 25% after adjusting for

general inflation.48 Moreover, average

electricity prices for industrial

customers more than quadrupled in

nominal terms over the same period and

increased 86% after adjusting for

inflation.49 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.50 These

writeoffs significantly reduced the

earnings of the affected utilities.51

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.52

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.53 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.54 A significant factor

was that larger generation units were

found to need relatively greater

maintenance and experience longer

downtimes.55 The electric industry

faced the situation ‘‘where the price of

each incremental unit of electric power

exceeded the average cost.’’ 56 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.57

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.58 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].’’ 59

Indeed, smaller and more efficient

gas-fired combined-cycle generation

facilities can produce power on the grid

at a cost between 3 and 5 cents per
17670 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

60FERC staff calculations based in part on

combined-cycle plant cost data reported in 1993

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

service during 1990–92. Costs vary with regional

fuel and construction costs, among other reasons.

61Coal and Nuclear plant cost data reported in

1993 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 1986–93; 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 * * * ’’).

62See Black & Pierce, supra note 46, 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.’’).

63Coordination 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.

64Pub. L. 95–617, 92 Stat. 3117 (codified in

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

65See generally FERC v. Mississippi, 456 U.S.

742, 745–46 (1982).

66The Power Plant and Industrial Fuel Use Act

of 1978. Pub. L. 95–617, 92 Stat. 3117 (codified in

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

67QFs 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.

68 456 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.

69For 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. 796 (17) and

(18).

70Energy Information Administration, Electric

Power Annual 1993 (December 1994) 124 (Table

77).

71 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.

72 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. 101–575, 104 Stat. 2834 (1990),

amended, Pub. L. 102–46, 105 Stat. 249 (1991).

73The 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.

74 15 U.S.C. 79 et seq.

75As discussed infra, Congress eventually

provided a means to avoid the PUHCA restrictions

by creating exempt wholesale generators (EWGs) in

the Energy Policy Act.

76The 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).

kWh.60 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.61

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.62

This has 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 63 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.

3. The Public Utility Regulatory Policies

Act and the Growth of Competition

In enacting PURPA,64 Congress

recognized that the rising costs and

decreasing efficiencies of utility-owned

generating facilities were increasing

rates and harming the economy as a

whole.65 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.66 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.67

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.68

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.69

Notwithstanding these limitations, QFs

proliferated. In 1989, there were 576 QF

facilities. By 1993, there were more than

1,200 such facilities.70 For the same

time period, installed QF capacity

increased from 27,429 megawatts to

47,774 megawatts.71 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.72 However, other nontraditional 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.73

There were two major impediments to

the development of IPPs and APPs.

First, the ownership restrictions of the

Public Utility Holding Company Act

(PUHCA) 74 severely inhibited these new

entities from entering the generation

business.75 Second, these entities

needed transmission service in order to

compete in electricity markets.

While the Commission had no

authority to remove PUHCA

restrictions,76 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
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17671

77Energy Information Administration, Electric

Power Annual 1993 (December 1994) 124 (Table

77).

78Black & Pierce, supra note 46, at 1349 n.25.

possessed.

79See, 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) (Doswell); and Dartmouth

Power Associates Limited Partnership, 53 FERC

¶ 61,117 (1990).

80See, e.g., Doswell, 50 FERC at 61,757.

81Citizens 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).

82 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,

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.

83See, 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).

84See, 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).

85See infra sections III.D.1 and 2.

86Pub. L. 102–486, 106 Stat. 2776 (1992).

87See El Paso Electric Company and Central and

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

61,914 (1994); 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.’’).

88 15 U.S.C. 79z–5a.

89 15 U.S.C. 79z–5a(e).

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.77

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

generating capacity added by

independent producers exceeded

capacity added by utilities.’’ 78

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

power that they may have possessed.79

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.80 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.81

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.82 In addition,

beginning in the late 1980s, 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 to mitigate their

market power to meet Commission

conditions.83 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.84

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

proposed in this rule. However, only 21

public utilities have any form of open

access transmission; the vast majority of

IOUs still do not provide any form of

‘‘open access’’ transmission over their

transmission systems.

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, the advantages of these

technological advances can be achieved

only if more efficient generating plants

can obtain access to the regional

transmission grids. Because the

traditional vertically integrated utilities

still favor their own generation if and

when they provide transmission access

to third parties, barriers continue to

exist to cheaper, more efficient

generation sources.

4. The Energy Policy Act

In response to the competitive

developments following PURPA, and

the fact that PUHCA and lack of

transmission access 85 remained major

barriers to new generators, Congress

enacted Title VII of the Energy Policy

Act of 1992 (Energy Policy Act).86 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.87

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.88

If the Commission, upon an application,

determines that a person is an EWG,

that person will be exempt from

PUHCA.89 This provision removed a

significant impediment to the

development of IPPs and APPs by
17672 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

90See supra note 67.

91See 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), III FERC Stats. & Regs.,

Regulations Preambles ¶ 30,975 (1993) (Policy

Statement Regarding Good Faith Requests for

Transmission Services).

92See Order No. 558, 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, III FERC Stats. &

Regs., Regulations Preambles ¶ 30,980, reh’g

denied, Order No. 558–A, 65 FERC ¶ 61,324 (1993),

regulations modified, 59 FR 15333 (April 1, 1994),

III FERC Stats. & Regs., Regulations Preambles ¶

30,993.

93See Order No. 550, Filing Requirements and

Ministerial Procedures for Persons Seeking Exempt

Wholesale Generator Status, 58 FR 8897 (February

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

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

A, 58 FR 21250 (April 20, 1993), III 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 91

and 92. This opened the ‘‘black box’’ of information

that previously was available only to transmission

owners.

94See Stranded Cost NOPR at 32,866; American

Electric Power Service Corporation, 67 FERC ¶

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

95 16 U.S.C.A. 824j–824k (West 1985 and Supp.

1994).

96See, e.g., final orders issued in City of Bedford,

68 FERC ¶ 61,003 (1994), reh’g pending; Florida

Municipal Power Agency v. Florida Power & Light

Company, 67 FERC ¶ 61,167 (1994), reh’g pending;

Minnesota Municipal Power Agency, 68 FERC ¶

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

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

168.

97See 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), reh’g pending. 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 resource-load pairing.

98 Florida Municipal, 67 FERC at 61,477.

99 69 FERC ¶ 61,035 at 61,165 (1994), reh’g

pending; see also Southwest Regional Transmission

Association, 69 FERC ¶ 61,100 at 61,398 (1994)

(SWRTA).

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 most circumstances.90 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

physical or other constraints.91 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.92

5. 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; 93

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.94

a. 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.95 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 requiring

wheeling in 9 of the 10 cases it has acted

on, including 3 proposed orders and 6

final orders.96

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.97 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.98

As discussed in more detail above,

however, our preliminary conclusion is

that section 211 alone is not enough to

eliminate undue discrimination. The

significant time delays involved in filing

an individual service request for

bilateral service under section 211

places 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.’’ 99

b. 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
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17673

100 64 FERC ¶ 61,279 (1993), reh’g granted, 67

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

101The 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.

102AEP, 67 FERC at 61,489.

103With 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.

104 Id. at 61,490.

105 Id. at 61,490–91.

106See Kansas City Power & Light Company, 67

FERC ¶ 61,183 (1994), reh’g pending.

107E.g., CSW, supra 68 FERC at 61,914.

108 Id.

109 Id. at 915 (footnote omitted).

110 68 FERC ¿ 61,223 (1994).

111 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.

112See 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.

113 Id. at 61,165.

114See 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) (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), III FERC

Stats. & Regs., Regulations Preambles ¶ 30,976 at

30,870 n.4 (RTG Policy Statement).

transmission service for a minimum of

one month.100 The Commission

accepted the proposed transmission

tariff for filing and suspended its

effectiveness for one day, subject to

refund.101 Rehearing requests

challenged the Commission’s summary

approval of the restriction of service to

point-to-point as being discriminatory

and anticompetitive.102 The rehearing

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.103 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.104

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.105

After AEP, the Commission applied

this comparability standard to a

proposed open access transmission tariff

that was filed by Kansas City Power &

Light Company in support of a proposal

to sell generation at market-based

rates.106 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 marketbased 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.107 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.108 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.109

In Heartland Energy Services, Inc., 110

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. 111

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.112 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.113

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.’’ 114 The Commission further

declared that comparable services must

be provided through ‘‘open access’’

tariffs rather than only on a contract-bycontract basis:

[T]ariffs are essential to the provision of

comparable services. Tariffs set out the

services that are available and the terms and
17674 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

115SWRTA, 69 FERC at 61,398.

116 70 FERC ¶ 61,204 (1995).

117 70 FERC ¶ 61,074 (1995).

118 70 FERC ¶ 61,075 (1995).

119 KCP&L, 67 FERC ¶ 61,183 (1994).

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

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

(Entergy)).

121 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.

122 Id. In KCP&L, the Commission declined to

dismiss the possibility of market power in

generation associated with sales out of existing

capacity. As noted, however, we here seek

comments on whether, and if so under what

conditions, to drop the generation dominance

standard in short-run markets, i.e., for sales from

existing capacity.

123See supra note 5.

124See 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), III FERC Stats. &

Regs., Regulations Preambles ¶ 31,005

(Transmission Pricing Policy Statement).

125See Inquiry Concerning Alternative Power

Pooling Institutions Under the Federal Power Act,

59 FR 54851 (October 26, 1994), IV FERC Stats. &

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

Inquiry).

126See Policy Statement Regarding Regional

Transmission Groups, 58 FR 41626 (August 5,

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

Preambles ¶ 30,976 (RTG Policy Statement).

127Stranded Cost NOPR at 32,864.

128The Commission herein is making preliminary

findings on stranded costs and issuing a

supplemental Stranded Cost NOPR, seeking

comments on the impact of our proposed open

access NOPR on stranded costs.

129Most 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 infra discussion of Indiana Michigan Power

Company, 64 FERC ¶ 61,184.

130Unlike 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 would be

compensated for the transaction.

131Transmission Pricing Policy Statement at

31,136.

132 Id. at 31,142.

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.115

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.

Most recently, the Commission has set

for hearing whether transmission tariffs

meet the AEP comparability standard in

Commonwealth Edison Company,116

Wisconsin Electric Power Company,117

and Wisconsin Public Service

Corporation.118 In all three cases, the

company agreed in principle to provide

comparable service, but issues arose as

to what constitutes such service.

c. Lack of Market Power in New

Generation. In KCP&L, 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.119 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. 120

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.121 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.122

d. 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 additional proceedings: (1)

Stranded Cost Notice of Proposed

Rulemaking,123 (2) Transmission Pricing

Policy Statement,124 (3) Pooling Notice

of Inquiry,125 and (4) Regional

Transmission Group (RTG) Policy

Statement.126

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.’’ 127

Accordingly, the Commission proposed

to establish provisions concerning the

recovery of wholesale and retail

stranded costs by public utilities and

transmitting utilities.128

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.129 Under

the new policy, it will permit a variety

of proposals, including distance

sensitive and flow-based pricing,130

which may be more suitable for

competitive wholesale power markets.

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.’’ 131 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.132

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
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17675

133Pooling Notice of Inquiry at 35,715.

134 Id. at 35,714.

135See WRTA and SWRTA, supra.

136The Energy Information Administration

recently indicated that at least nine states—

California, Connecticut, Illinois, Michigan, Nevada,

Ohio, Texas, Utah, and Vermont have proposals or

legislation for retail wheeling. EIA, Performance

Issues for a Changing Electricity Power Industry,

January 1995 19–22. Most prominent among the

recent state proposals are the California Public

Utility Commission’s ‘‘Blue Book’’ proposal (Order

Instituting Rulemaking on the Commission’s

Proposed Policies Governing Restructuring

California’s Electric Services Industry and

Reforming Regulation, R. 94–04–031; Order

Instituting Investigation on the Commission’s

Proposed Policies Governing Restructuring

California’s Electric Services Industry and

Reforming Regulation, I. 94–04–032) and the

Michigan Public Service Commission’s proposal

(Interim Order on Experimental Retail Wheeling

Program, Case No. U–10143/U–10176 (April 11,

1994)).

137Energy Information Administration,

Performance Issues for a Changing Electric Power

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

138Current Competition, November 1994, Vol. 5,

No. 8, at 8.

139See map attached as Appendix A. This

Appendix will not appear in the Federal Register.

140As discussed above, only a minimal number of

public utilities have any form of an ‘‘open access’’

tariff on file with the Commission and no public

utility has on file a non-discriminatory open access

tariff as defined by this rule.

141An example of this is that, except in the

limited case of licensed hydroelectric projects

under Part I of the FPA, there is no Federal right

of eminent domain available to assist in acquiring

rights of way for new transmission lines. In

addition, the regulatory requirements to build a

transmission line vary from state to state. In all

states, siting new transmission lines is getting

harder.

are appropriately balancing our dual

objectives of promoting coordination and

competition.133

Accordingly, the Commission explained

that it wished to look at alternative

power pooling institutions and to reexamine 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.’’ 134

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

recently conditionally approved the

formation of two RTGs.135 One of the

conditions is that each RTG member

must offer comparable transmission

services by tariff to other RTG members.

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.136

D. 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 3 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

1993.137 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.138 In addition, the cost of

utility-generated 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.139

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. It is also 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.140

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. Such action is

required by the FPA’s mandate that the

Commission remedy undue

discrimination.

1. Market Power

Unlike new generating capacity (see

prior discussion of KCP&L),

transmission remains and is expected to

remain a natural monopoly. The

Commission has addressed the natural

monopoly character of transmission in

the major cases summarized above and

in the Commission’s recent

Transmission Pricing Policy Statement.

The monopoly characteristic exists in

part because entry into the transmission

market is restricted or difficult.141 In

addition, as unit costs are less for larger

lines and networks, transmission

facilities still exhibit scale economies.

From an economic, environmental, and

aesthetic viewpoint, it is often better for

a single owner (or group of owners) to

build a single large transmission line

rather than for many transmission

owners to build smaller parallel lines on

a non-coordinated basis.

Further, effective competition among

owners of parallel transmission lines is

unlikely, and often impossible, with

existing practices and technology. For

example, on an alternating current (AC)

electric system, electricity flows on

parallel paths based on the impedance

of each path. With two electric systems

providing parallel contract paths, a

share of the actual power flows would

occur on each system according to the

physical characteristics of the system.

Thus, each of the two transmission

service providers would have the

incentive to underbid the other because

the winner would receive all of the

transmission revenues, but only incur a

fraction of the costs. The loser, on the

other hand, would incur the remaining

costs, but would receive no revenues.

In today’s electric industry, which is

dominated by vertically integrated

utilities, an owner or controller of

transmission service can exclude

generation competitors from the market,

thereby favoring the transmission
17676 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

142See, e.g., David W. Penn, A Municipal

Perspective on Electric Transmission Access

Questions, Pub. Util. Fort. 18–19 (Feb. 6, 1986).

143The majority have offered only point-to-point

services. However, a few utilities have sought to

comply with the non-discrimination

(comparability) standard announced in AEP. For

example, Kansas City Power & Light Company

(KCP&L) and Louisville Gas & Electric Company

(LG&E) recently filed settlements to this effect.

KCP&L, Docket No. ER94–1045 (settlement filed

February 14, 1995) and LG&E, Docket No. ER94–

1380 (settlement filed February 10, 1995).

144 In Indiana Michigan Power Company, 64 FERC

¶ 61,184 (1993), the Commission explained loop

flows and parallel power flows:

In general, utilities transact with one another

based on a contract path concept. For pricing

purposes, parties assume that power flows are

confined to a specified sequence of interconnected

utilities that are located on a designated contract

path. However, in reality power flows are rarely

confined to a designated contract path. Rather,

power flows over multiple parallel paths that may

be owned by several utilities that are not on the

contract path. The actual power flow is controlled

by the laws of physics which cause power being

transmitted from one utility to another to travel

along multiple parallel paths and divide itself

among those paths along the lines of least

resistance. This parallel path flow is sometimes

called ‘‘loop flow.’’

Id. at 62,545.

145The Commission partially addressed this

concern by allowing reciprocity provisions in open

access transmission tariffs. See, e.g., Southwestern

Electric Power Company and Public Service

Company of Oklahoma, 65 FERC ¶ 61,212 at

61,981–82 (1993), order on reh’g, 66 FERC ¶ 61,099

(1994).

146While the Commission has conditioned its

approval of RTGs to achieve this same result, the

formation of RTGs is voluntary. By contrast,

compliance with the final rules adopted in this

proceeding will be required.

147See, e.g., Penn, supra note 142, at 18.

148Otter Tail Power Company refused to wheel

power for the village of Elbow Lake. The Supreme

Court ultimately ruled against Otter Tail on

antitrust grounds. Otter Tail Power Company, 410

U.S. 366 (1974). The Commission has also found

that Utah Power & Light Company consistently

refused to permit the wheeling of low-cost power

across its system in order to use its strategically

located bottleneck transmission system to extract

monopoly prices. Utah Power & Light Company,

supra, 45 FERC at 61,287 and n.137 (1988).

149See, e.g., Penn, supra note 142, at 18–19

(discussion of methods used to deny access). Penn

also noted in his 1986 article that the American

Public Power Association had conducted a survey

of its members in which about 25% indicated a

owner’s own generation. This can occur

through outright denial of transmission

access, or, as is more likely, through

access that is discriminatory as to rates,

terms or conditions of service.142 Thus,

in the absence of non-discriminatory

open access tariffs, the development of

fully competitive bulk power markets

cannot occur, and consumers will be

deprived of the benefits that would be

expected from such a competitive

market.

2. Discriminatory Access

Some transmission-owning utilities

have voluntarily begun to offer

unbundled transmission tariff services

to third-party suppliers and purchasers

of wholesale power, though none have

done so to the extent proposed by this

proposed rule.143 However, because

utilities are naturally profit maximizers

and monopoly suppliers to their native

load, the vast majority of transmissionowning utilities have not agreed to give

up their market power voluntarily.

Transmission-owning utilities have an

incentive to deny access either by not

filing any open access tariff or by filing

a tariff that offers services inferior to

those used by the transmission owner.

This is particularly true for those

utilities that emerged from the recent

decades of technological and legal

changes as high-cost generation

companies. Open access transmission

places their existing generation at risk

because their wholesale customers may

seek alternative lower price suppliers. It

is in their self-interest to maintain and

use market power to retain (or expand)

market share for their existing

generation facilities, at least until they

can get their generation costs in line

with current market prices. Because

generating units are usually depreciated

over a 30- to 50-year physical life, many

high cost companies may attempt to

exercise transmission market power for

decades to preserve the value of past

generation investments.

Unless all public utilities are required

to provide non-discriminatory open

access transmission, the ability to

achieve full wholesale power

competition, and resulting consumer

benefits, will be jeopardized. If utilities

are allowed to discriminate in favor of

their own generation resources at the

expense of providing access to others’

lower cost generation resources by not

providing open access on fair terms, the

transmission grid will be a patchwork of

open access transmission systems,

systems with bilaterally negotiated

arrangements, and systems with

transmission ordered under section 211.

Under such a patchwork of transmission

systems, sellers will not have access to

transmission on an equal basis, and

some sellers will benefit at the expense

of others. The ultimate loser in such a

regime is the consumer.

A patchwork of transmission systems

will also result in inefficiencies across

the Nation’s transmission grids. Because

of the physical properties of the

transmission system, electric power

moves over parallel transmission lines

from generator to load, without regard to

whether a line is part of a system

providing open access or not.144

However, today the industry develops

transmission contracts as if power

flowed along one series of lines

belonging to specific owners, which is

called the ‘‘contract path.’’ Thus,

transmission users will search for

contract paths through open access

systems to take advantage of the nondiscriminatory open access tariffs.

Because open access transmission tariffs

include an obligation to expand when

necessary to accommodate third-party

requirements for service, transmitting

companies offering open access services

across their systems could end up

constructing a disproportionate share of

new transmission facilities.

Expansion cannot be efficient under

such a patchwork of open access

transmission systems. Not only would

this misallocate cost burdens to open

access companies, but it is unlikely that

the optimal transmission development

will always be within their service

territories. Expansion on closed

systems, instead of open systems, may

in some cases be the more efficient way

to relieve constraints. Thus, a

patchwork of open access systems will

not result in the least cost expansion of

the Nation’s transmission grids. In

addition, states with open access

utilities may refuse to site new lines if

their closed access neighbors are not

doing their share.145

A discriminatory, patchwork system

also works against pricing parallel

power flows on a sensible regional

basis. The formation of effective

regional transmission groups, which the

Commission strongly encourages, would

be fostered if all utilities in a region

offered non-discriminatory open

access.146 In fact, optimal cooperative

regional action would involve all

transmission systems in the region

offering non-discriminatory open access

to all wholesale customers.

A transmission-owning utility may

deny access to third parties not only to

avoid losing its own generation sales,

but also to maintain other trading gains.

For example, a company can buy low

cost power for its own use from a

neighbor at a low price if other buyers

cannot reach that neighbor to bid up the

price. Furthermore, if it does not need

the energy, it can market that power by

buying low and selling high.

In the past, transmission-owning

utilities have discriminated against

others seeking transmission access.

Transmission-owning utilities have

denied access by outright refusals to

deal. While such actions tend to be rare,

likely because transmission owners fear

they may trigger antitrust action,147 they

have occurred.148 More often, however,

discrimination is likely to be manifested

more subtly and indirectly.149 One such
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17677

problem in securing transmission in effecting

coordination services and about an equal amount

had reported being denied transmission access in

the recent past. Id. at 18. See also Pacific Gas &

Electric Company, 51 FPC 1030, 1031–32, reh’g

denied, 51 FPC 1543 (1974) (parties alleged that

public utility proposed ‘‘a wholesale rate so high

that its wholesale customers would be unable to

compete with PG&E for large industrial retail loads’’

and entered into restrictive and anticompetitive

contracts that strengthened public utility’s

monopoly).

150Members of the Coalition for a Competitive

Electricity Market alleged that they have

encountered this strategy. Coalition Petition at 13,

n.19.

151An example of this tactic is evident in 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). 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

what came to be known as the South of Tesla

Principles). PG&E spent the next four years filing

substitute provisions for what it had promised in

the Principles. See 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).

152See Pacific Gas and Electric Company, 52

FERC ¶ 61,347 at 62,375–76 (1990) (proposal to

charge a base demand and a flexibility adder for an

integrating transmission service). PG&E eventually

withdrew the proposal. 56 FERC ¶ 61,373 at 62,429

(1991); see also Florida Municipal Power Agency v.

Florida Power & Light Company, 65 FERC ¶ 61,125

(1993) (Federal Municipal Power Agency requested

a section 211 order directing network service); TexLa Electric Cooperative of Texas, 67 FERC ¶ 61,019

at 61,057 (1994) (Tex-La requested a section 211

order directing network service).

153See notes 129 and 130, supra; see also Tex-La

Electric Cooperative of Texas, 69 FERC ¶ 61,269 at

62,034–35 (1994), in which the Commission found

this practice to be unduly discriminatory.

154See AEP, 64 FERC at 62,971–72.

155 Id.

156See Coalition Petition at 20–21.

157See Borough of Zelienople, 70 FERC ¶ 61,073

at 61,184 (1995) (load exceeding schedule by 1 MW

would be filled at a partial requirements rate using

a 60% demand ratchet for 11 months, i.e., 1 MW

times 60% times $9.30 per kW times 11, for a total

of $61,380).

158See Coalition Petition at 20–21.

159See, e.g., Pacific Gas and Electric Company, 53

FERC ¶ 61,145 at 61,505 (1990) (utility proposed a

reassignment prohibition on the use of Reserve

Transmission Service available to the Sacramento

Municipal Utility District under a proposed

Interconnection Agreement).

160 Id. at 61,504–05 (utility proposed an export

restriction on the use of Reserve Transmission

Service available to the Sacramento Municipal

Utility District under a proposed Interconnection

Agreement).

161See Coalition Petition at 28–29 and 32.

162For example, it is reported that one customer

was told that a $13 million line of credit would be

required to ensure creditworthiness for a request of

only one MW of transmission capacity for a

coordination trade. See Coalition Petition at 30.

163See Coalition Petition at 25; see also AES

Power, Inc., 69 FERC ¶61,345 at 62,295 and 62,301

(1994) (AES).

164See Coalition Petition at 13–14.

165See Mid-Continent Area Power Pool, 69 FERC

¶ 61,347 at 62,308 (1994).

way would be for transmission owners

to adopt a negotiating strategy that

involves a sequence of informational

and other requirements over a

protracted period of time. By the time

all of the requirements are finally

satisfied, the window for the customer’s

trade opportunity has closed.150 Another

way of frustrating access is to

substantially change the terms of

negotiated agreements through

protracted delay, including filings with

regulatory agencies.151

Another way for transmission-owning

utilities to frustrate access and

competition is to allow access, but only

on non-comparable or unsupportable

terms and conditions that are inferior to

the conditions under which the

transmission owners themselves use or

could use the transmission grid or on

terms and conditions that have no

operational or financial basis.

Discrimination can be exercised this

way in the following areas:

(1) Network Service. Network service

allows a transmission customer to distribute

a given amount of transmission usage

between specified resources and specified

loads without having to pay multiple charges

for each resource-load pairing. Transmission

owners can refuse to provide service on these

terms and instead insist on charges that are

a function of the number of resource load

pairings.152 This can dramatically increase

the cost of such service. Such treatment does

not reflect the way transmission owners’

costs are allocated to their own native load

customers.

(2) Pricing. Transmission service can be

made unattractive to third-party customers

by pricing such service on a basis that is

different from that used by the transmission

owner and that results in higher rates. One

example would be charging third-party

customers distance-sensitive rates, while

pricing all similar transmission bundled with

power services on a postage stamp basis.153

(3) Service Priority. The priority of

transmission service is a critical service

factor. The transmission provider could

disadvantage third-party transmission

customers by making firm transmission

service to them subordinate to the

transmission utility’s native load service.154

(4) Scheduling and Balancing Provisions. A

transmission owner could hold transmission

customers to unnecessarily long lead times to

change power schedules. In some cases,

scheduling could be required as much as a

month ahead of time.155 This precludes

transmission customers from using their

service for short-term trading. Transmitting

utilities may also insist that customers keep

strict adherence to scheduling and balancing

provisions by requiring them to get back on

schedule quickly or face stiff penalties.156

One example of a stiff penalty for failure to

schedule sufficient power would be to assess

shortfalls based on a partial requirements rate

with an 11-month ratchet.157 In contrast,

transmitting utilities may have access to less

costly balancing alternatives, such as

substituting resources without notice or

borrowing capacity from neighboring utilities

and settling the imbalance by returning

energy in-kind within a much longer time

period than allowed to customers.158

(5) Use of Firm Transmission Capacity.

Transmission owners can unnecessarily

restrict the firm transmission capacity made

available to transmission customers. One way

to restrict service would be to prohibit the

customer from reassigning such capacity

when it is not needed.159 This restricts the

customer’s ability to manage the risk of longterm capacity purchases and to compete as a

seller in the transmission service market.

Another example would be that the

transmission owner could restrict a

customer’s use of transmission capacity by

allowing sales only from the customer’s

generating resources that are temporarily in

excess of actual load needs.160 Transmission

owners do not face these restrictions in their

own use of transmission capacity.

(6) Ancillary Services. A transmitting

utility may offer to a transmission customer

ancillary services (e.g., scheduling) that are

inferior to the services it provides for itself.

Transmission owners may be free to choose

whether to supply some of these services to

themselves or contract for them if available

more cheaply elsewhere.161 Third-party

transmission customers do not always have

this option on a comparable basis.

(7) Creditworthiness and Security Deposits.

Customers are sometimes required to make

onerous deposits in order to obtain service.162

(8) Reciprocity Double Payments.

Transmission agreements often require

reciprocity. Non-transmission owners could

be required to contract with, and pay, thirdparty transmitting utilities to provide the

required reciprocal service.163 Transmission

owners do not face such obstacles in using

their own systems.

Finally, an additional way for

transmission-owning utilities to

frustrate access and competition is by

granting each other superior rights and

lower rates—compared to those

available to non-transmission owning

customers—in pools, interconnection

agreements, and other protocols.164 For

example, pool-wide transmission

service can be made available to

members at rates less than those that

each member would separately propose

under traditional rate methods. This

could disadvantage non-transmission

owners if pool membership is restricted

or if it requires excessive or vaguely

stated transmission contributions that

could be difficult to meet.165

Section 211 is not always a sufficient

remedy for this discriminatory behavior.

Third parties may seek nondiscriminatory transmission under

section 211, but they will not be able to

compete if the sale or purchase
17678 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

166For example, an applicant must make a request

for transmission service to the transmitting utility

at least 60 days before filing an application with the

Commission for an order to provide transmission.

The Commission must first issue a proposed order

and allow the parties a reasonable time to negotiate

agreeable terms and conditions before it can issue

a final order. Moreover, a final order faces possible

rehearing and a court appeal.

167–168One request was withdrawn.

169We note that NEPOOL and MAPP are currently

exploring ways to modify their pool structures to

accommodate competitive power markets. As noted

in the Pooling Notice of Inquiry, supra, the poolco

concept basically involves an independent entity

that would control the operation of all transmission

facilities and some or all generating facilities in a

region. It would be open and would provide

transmission service to all generators. Thus, the

poolco would create a spot market for power in the

region.

170Order No. 436, Regulation of Natural Gas

Pipelines After Partial Wellhead Decontrol, FERC

Regulations Preambles ¶ 30,665 (1985); Order 636,

Pipeline 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, 57 FR

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

Regulations Preambles ¶ 30,939 (Order No. 636),

appeal pending.

171See AGD, supra, 824 F.2d at 1008 (‘‘Agencies

do not need to conduct experiments in order to rely

on the prediction that an unsupported stone will

fall.’’). The ongoing discriminatory behavior by

owners or controllers of transmission in the electric

industry is detailed supra.

opportunity is gone before a final order

can be obtained under section 211. This

could be the case in many situations

because of the procedural requirements

of sections 211 and 212.166 Indeed, to

date, the Commission has received

eighteen section 211 transmission

requests,167–168 which it has tried to

process expeditiously within the

procedural constraints contained in

sections 211 and 212. As to the seven

requests that have received a final order,

the average elapsed time from date of

filing to the date of a final order was 9

months. The remaining ten requests

have been pending, on average, more

than 6 months.

The following sets forth the status of

the section 211 cases filed with the

Commission:

Docket

No.

Date of application Status

Months

pending

TX93–1 .. 01/19/93 Final

Order7/29/

93.

6

TX93–2 .. 06/18/93 Final

Order7/1/94.

12

TX93–3 .. 06/30/93 Withdrew9/10/

93.

2

TX93–4 .. 07/02/93 Final

Order5/11/

94.

10

TX94–1 .. 10/21/93 Final

Order7/6/94.

9

TX94–2 .. 11/04/93 Pending a 16

TX94–3 .. 11/09/93 Final

Order7/13/

94.

8

TX94–4 .. 12/15/93 Final

Order12/1/

94.

11

TX94–5 .. 04/15/94 Final

Order3/23/

95.

11

TX94–6 .. 07/05/94 Pending 8

TX94–7 .. 07/15/94 Pending a 8

TX94–8 .. 08/05/94 Pending 7

TX94–9 .. 09/09/94 Pending a 6

TX94–10 09/16/94 Pending 6

TX95–1 .. 10/11/94 Pending 5

TX95–2 .. 10/17/94 Pending 5

TX95–3 .. 01/19/95 Pending 2

Docket

No.

Date of application Status

Months

pending

TX95–4 .. 01/24/95 Pending 2

aA proposed order has been issued.

As the wholesale power markets

become more competitive, delayed

access becomes a matter of increasing

concern. Not only have long-term

purchases from non-traditional

generators become more important, but

short-term firm and non-firm power

sales and purchases create significant

profit or cost-saving opportunities for

utilities, marketers, and their customers.

As a result, market participants are

exploring various ways to reduce their

costs through trading. These include

poolcos, changes to existing pools,

short-term trading systems, and futures

contracts.169 We do not see how such

options will work unless all parties have

non-discriminatory transmission access

rights and hour-to-hour access without

having to go through a regulatory

proceeding for each trade.

In today’s emerging competitive

wholesale power markets, the practices

of some transmission-owning utilities

are unduly discriminatory and

anticompetitive. These practices

produce market distortions today,

undermine the goal of the Energy Policy

Act to create competitive bulk power

markets, and will continue if this

Commission does not take action. Most

important, they can harm consumers by

denying them the benefits of

competitively priced power. We seek

additional specific examples of such

practices.

3. Analogies to the Natural Gas Industry

The electric industry today is

analogous in many ways to the natural

gas industry before the Commission

issued Order Nos. 436 and 636.170 Then,

natural gas pipelines were primarily

merchants offering a bundled sales

service, which provided gas to

customers at the city-gate from the

pipelines’ own system supplies. In

addition, pipelines moved a relatively

small amount of third-party gas under a

separate transportation service. To meet

their sales service obligations, pipelines

purchased most of their system supply

from third-party producers under longterm contracts. In the early 1980s, due

to changing market conditions, the

prices under many of these contracts

ended up being higher than those

available in the then evolving spot

market. Because of the long-term

contracts and the resulting higher cost

gas, system supply gas tended to be

more costly than gas that the customers

could buy in the competitive spot

market. At the same time, the

transportation service bundled with a

pipeline’s sales service was usually

superior to the transportation service

third parties could obtain. Essentially,

the pipeline would provide itself service

that had much greater flexibility and

often promised greater reliability than

that available to third-party shippers.

Pipelines had a considerable incentive

to maintain this difference in

transportation service quality to make

their own, more expensive gas more

attractive.

A similar situation exists today in the

electric industry. Traditional public

utilities deliver bundled service—

generation and transmission—to most of

their wholesale customers. They have

monopoly control over transmission

facilities and thus control access to their

customers. The lack of nondiscriminatory access to transmission

services raises the same general

concerns that were prevalent in the gas

industry. Accordingly, unless similar

regulatory measures are undertaken, the

Commission expects the same type of

discriminatory and anticompetitive

behavior will continue in the electric

industry as was present in the gas

industry, because denying nondiscriminatory access will continue to

be in the economic self-interest of

transmission monopolists, absent

regulatory changes.171

In its regulation of interstate pipelines

under the Natural Gas Act (NGA) the

Commission initially addressed the

problem of undue discrimination in

Order No. 436, finding natural gas

pipeline practices to be unduly
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17679

172 In this regard, sections 4 and 5 of the NGA are

virtually identical to sections 205 and 206 of the

FPA.

173Order No. 636 at 30,402. The Commission

explained that pipelines were selling a regulated

bundled sales and transportation service, but that

their competitors were generally selling only the gas

commodity. The Commission also recognized that

pipelines were at a competitive disadvantage due to

their certificate and contractual obligations to their

firm sales customers. Id. at 30,403.

174Order No. 636 at 30,393–94.

175As discussed infra, sellers must also meet the

Commission’s other requirements to obtain marketbased rates.

176Examples of ancillary services (which include

control area services) are: Scheduling service

between control areas, and various services that

facilitate power movements within control areas,

Continued

discriminatory under the NGA 172 and

effectuating ‘‘open access’’

transportation. The Commission in that

order sought to make transportation

available to third parties on a nondiscriminatory basis. The Commission

provided that, if a pipeline held itself

out as a transporter of gas for others, it

must provide that service to all shippers

without discrimination. At the same

time, the Commission allowed pipelines

and their customers to retain the

traditional bundled sales and

transportation services under existing

certificate authority.

As a result of Order No. 436, pipelines

became primarily transporters of natural

gas. However, in Order No. 636, the

Commission noted that pipelines were

still providing, albeit at a reduced level,

a bundled, city gate, sales service in

competition with third-party sales and

transportation, and concluded that the

competition was not occurring on an

equal basis. The Commission also noted

that pipelines’ natural gas sales prices

exceeded those of their competitors,

much as electric utilities’ embedded

costs can exceed the cost of new

generating capacity and excess

generating capacity of others. In this

regard, the Commission determined that

the transportation service bundled with

pipelines’ sales service was superior to

that made available to third parties and

that pipelines and unregulated

competitors were not selling the same

product.173 Accordingly, in Order No.

636, the Commission found this

behavior anticompetitive and required

pipelines to ‘‘unbundle’’ their sales

services from their transportation

services and to provide open access

transportation service that is equal in

quality for all gas supplies whether

purchased from the pipeline or some

other supplier.174

Our experience in the gas area

influences our decision that, at a

minimum, functional unbundling of

wholesale services is necessary in order

to obtain non-discriminatory open

access and to avoid anticompetitive

behavior in wholesale electricity

markets.

4. Coordination Rates

In finding a need for nondiscriminatory open access

transmission, the Commission has

considered the structure of the

coordination market, i.e., the market for

wholesale sales to a public utility’s nonrequirements customers. Utilities now

engage in coordination trades primarily

under rates no lower than the seller’s

variable cost and no higher than that

variable cost plus 100% contribution to

the fixed costs of the production unit

used to price energy and the relevant

transmission facilities. This rate

flexibility allows the buyer and seller to

negotiate a price reflecting the market at

the time of the sale, including the

number of buyers and sellers, the

relative incremental and decremental

variable costs, and the amount of

savings attainable by transacting. Thus,

while the seller’s ceiling rate reflects

some measure of fixed and variable

costs, the actual transaction price is set,

to a certain extent, by the marketplace.

This marketplace, however, may be

skewed by the general lack of

transmission access, and the resulting

price may be considerably above prices

in a fully competitive market.

Some utilities transact under a splitsavings rate that generally sets the price

halfway between the seller’s

incremental variable cost and the

buyer’s decremental variable cost. Here

again, price is a function of the

alternatives reachable through the

transmission grid at the time of the

transaction. This rate form is primarily

used today to distribute the savings

derived from the central dispatch of

power pools on an after-the-fact basis.

The Commission believes that unless

the participants in coordination markets

mitigate their transmission market

power, market-driven prices for

coordination trades may no longer be

just and reasonable. Thus, our

preliminary conclusion is that current

coordination pricing is no longer

justified in the absence of a tariff offer

of non-discriminatory open access

transmission services by the seller

(owning or controlling transmission) in

a coordination transaction.175 The

Commission’s past practice of allowing

such pricing for coordination trades

appears to be inconsistent with

emerging competitive markets unless

those who benefit from such trading

offer access to other, lower-priced

trading opportunities. We seek

comments on this issue.

E. The Proposed Regulations

The goals of the proposed regulations

are two-fold: (1) To facilitate the

development of competitive wholesale

bulk power markets by ensuring that

wholesale purchasers of electric energy

and wholesale sellers of electricity can

reach each other by eliminating

anticompetitive practices and undue

discrimination in transmission services;

and (2) to address the transition costs

associated with the development of

competitive wholesale markets. This

section addresses the elimination of

undue discrimination. Transition costs

are addressed below in Section F.

Non-discriminatory open access

transmission is critical to the ability of

sellers to compete on a fair basis and the

ability of purchasers to reach the lowest

priced generation options. Thus far, the

Commission has developed an open

access comparability requirement on a

case-by-case basis. We have directed our

administrative law judges, to whom the

various cases have been referred, to

examine the factual circumstances

surrounding a utility’s use of its own

system vis-a-vis the type of service

provided to third parties. Nonetheless, it

has now become evident to us that it is

necessary for the Commission to define

the parameters of a non-discriminatory

open access tariff much more precisely.

Until now, we have been applying the

new standard of what constitutes undue

discrimination only to new voluntary

tariff filings. We now no longer believe

it is appropriate to apply this standard

so narrowly; therefore, we are proposing

to require all public utilities to offer

non-discriminatory open access services

in accord with the proposed rule and

the attached tariffs. This broad

application is consistent with our

determination that undue

discrimination by jurisdictional public

utilities must be prevented or remedied.

It is also consistent with our desire to

bring further efficiencies to the

provision of electric service by

encouraging competitive bulk power

markets.

1. Non-discriminatory Open Access

Tariff Requirement

Transmission owners can

discriminate by restricting access to, or

restricting expansion of, transmission

facilities, or by restricting access to the

ancillary services that control the

generation resources on the

transmission grid.176 To ensure that all
17680 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

e.g., dispatch service, load following service,

imbalance resolution service, reactive power

support, and operating reserves. We invite comment

on definitions of these terms and their component

parts. Regardless, the proposed rule would require

that all ancillary services be offered on a nondiscriminatory basis.

177See generally William W. Hogan, Reshaping

the Electricity Industry, Prepared for the Federal

Energy Bar Conference, ‘‘Turmoil for the Utilities,’’

5 Washington, D.C. (Nov. 17, 1994):

Commercial functions must facilitate nondiscriminatory, comparable open access and

support market operations in the competitive

sectors. The EPAct requirements and the FERC

implementation emphasize the need to obtain

market access under terms and conditions that

support competition. Everyone should have equal

access to and use of essential facilities, particularly

transmission, with the rights of ownership limited

to compensation consistent with opportunity costs

in a competitive market.

178See, e.g., AEP, 67 FERC at 61,491.

179Order Providing Guidance Concerning

Pending and Future Proceedings involving Nondiscriminatory Open Access Transmission Services,

Docket Nos. ER93–540–000, et al.

180While there may be any number of specific

services used by a particular customer, we have

concluded, after analyzing the historical types of

transmission service tariffs on file, as well as the

tariffs filed in the ongoing comparability

proceedings, that all transmission services generally

fall within these two categories.

181A utility’s own coordination purchases may

involve hourly scheduled transfers of fixed blocks

of power. These schedules are supported by the

utility’s own network transmission service used for

its economic dispatch. Consequently, network

service is covered by the proposed rule because it

supports a utility’s coordination purchases,

regardless of whether or not the utility has any

requirements customers that also would use

network service.

182 ‘‘Wheeling through’’ refers to transmittal of

electric energy through a transmitting utility’s grid,

i.e., entering at one point of interconnection and

leaving at another. 183This would be true of other services as well.

participants in wholesale electricity

markets have non-discriminatory open

access to the transmission network,

transmission owners must offer nondiscriminatory open access transmission

and ancillary services to wholesale

sellers and purchasers of electric energy

in interstate commerce.177 This will

require tariffs that offer point-to-point

and network transmission services,

including ancillary services. All of these

services must be non-discriminatory as

to price as well as to non-price terms

and conditions. Services must be

available to any entity that could obtain

transmission services under section 211.

In our AEP rehearing order and in

several subsequent cases,178 we set for

hearing the following issues:

1. The different uses that a transmission

owner makes of its transmission system and

whether there are any operational differences

between any particular use that the owner

makes of the system and the use third parties

might need, and in particular, the degree of

flexibility the transmission owner accords

itself in using its transmission system for

different purposes.

2. Any potential impediments or

consequences to providing a particular

service to third-party transmission customers

which is the same or comparable to service

that the transmission owner provides itself.

3. The costs that the transmission owner

incurs in providing transmission associated

with its use of the system, and whether the

costs to provide such service or comparable

service to third parties would be different.

Based on what we have learned in the

past year, the Commission proposes to

address these issues generically.

Concurrently with this order, the

Commission is issuing a separate order

on how a final rule would apply to

pending cases.179 We believe that the

parties and the administrative law

judges in the individual pending

proceedings should continue their

efforts, but in doing so should take into

account the principles announced in

this proposed rule. This will permit any

fine tuning of the broader principles

announced here and set forth in the pro

forma tariffs that may be necessary to

recognize the individual circumstances

of particular systems.

With regard to the first issue, the

Commission believes 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).180 This network

transmission service is bundled as part

of retail service and as part of wholesale

requirements service, and is the

fundamental support of a utility’s

dispatch that underlies its trading in the

wholesale coordination market.181

The Commission has preliminarily

concluded that third parties may need

one or both of these basic uses in order

to obtain competitively priced

generation or to have the opportunity to

be competitive sellers of power. 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 tariffs. The

Commission believes that a utility’s

tariff must offer to provide any point-topoint transmission service and network

transmission service that customers

need, even though the utility may not

provide itself the specific service

requested. For example, a utility may

not provide itself ‘‘wheeling-through’’

service, 182 which is a specific form of

point-to-point service. However,

because ‘‘wheeling-through’’ service is

merely a subset of basic point-to-point

service, which the utility does provide

to itself, the Commission will require a

utility to provide such service. 183

Similarly, a utility may contend that it

does not provide non-firm point-topoint service to itself because all of its

transmission investment results in firm

entitlements. Nonetheless, the utility

provides itself with the functional

equivalent of non-firm service when it

uses, subject to curtailment or

interruption, capacity that is

temporarily unused by other firm

reservation holders. Therefore, it must

offer non-firm point-to-point service.

We will not allow transmission

providers to define terms or specify

transmission uses to erect barriers to fair

and equal competition in power

markets, or to engage in undue

discrimination.

On the second issue set for hearing in

AEP, et al. (potential impediments to

providing a particular service), we

believe there are none, except for

impediments to siting. However, any

impediments to siting are the same

whether the utility is providing service

to itself or to a third party.

On the third issue set for hearing AEP,

et al. (the costs of providing comparable

service), we believe there is no

difference in the costs incurred by a

transmission provider in providing

transmission to itself or to a third party.

Thus, the transmission owner must

charge itself and third parties the same

rates for the use of its system.

All electricity trade is supported and

facilitated in one way or another by

ancillary services, and transmission

services may be comprised of many

different combinations of ancillary

services. Therefore, the Commission

will require that such ancillary services

be offered separately through open

access tariffs. These are discussed in

detail infra.

Public utilities that are transmissiononly companies or transcos, i.e.,

companies that do not own or control

generation, do not use their own

transmission systems to sell their own

power. However, a public utility transco

would be required to offer open access

transmission services as well as

ancillary services. It would also have to

provide a real-time information

network, as discussed below. The

Commission is also announcing certain

quality-of-service guidelines to aid in

evaluating the quality of transmission

service that must be provided by public

utilities. These are described infra and

are reflected in proposed pro forma

point-to-point and network tariffs
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17681

184This means that a customer who buys both

generation and transmission services from the

utility will have a separately stated rate for the

generation, transmission, and ancillary services that

it purchases. The rates for transmission and

ancillary services would be stated in the open

access tariff. The rates for the generation service

would be under a separate rate schedule.

185Similarly, public utilities that own

transmission, but get their ancillary services from

another entity must authorize that entity to provide

ancillary services under a filed tariff and must take

their ancillary services from that tariff.

186The Commission recognizes that the proposal

here overlaps with the pending Pooling Notice of

Inquiry. However, the fundamental nondiscrimination requirements of the FPA, and

therefore the basic requirements of the proposed

rule, must be applied to power pools in which

public utilities participate. This issue is discussed

further in the Implementation Section, infra.

attached to this notice of proposed

rulemaking. Our preliminary conclusion

is that the provisions contained in the

pro forma tariffs are the minimum

provisions necessary to meet the

requirement of non-discriminatory open

access. We seek comments on these

tariffs.

2. Implementing Non-Discriminatory

Open Access: Functional Unbundling

The Commission’s preliminary view

is that functional unbundling of

wholesale services is necessary to

implement non-discriminatory open

access. Accordingly, the proposed rule

requires that a public utility’s uses of its

own transmission system for the

purpose of engaging in wholesale sales

and purchases of electric energy must be

separated from other activities, and that

transmission services (including

ancillary services) must be taken under

the filed transmission tariff of general

applicability. The proposed rule does

not require corporate unbundling

(selling off assets to a non-affiliate, or

establishing a separate corporate

affiliate to manage a utility’s

transmission assets) in any form,

although some utilities may ultimately

choose such a course of action. The

proposed rule accommodates corporate

unbundling, but does not require it.

Functional unbundling means three

things. First, it means that 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 under which

others take service. New wholesale sales

and purchases are those under any

contracts executed on or after the open

access tariffs required by this proposed

rule become effective. Nondiscriminatory service requires that the

utility charge itself the same price for

these services that it charges its thirdparty wholesale transmission customers.

We seek comment as to the appropriate

means to enforce this requirement, such

as a revenue crediting mechanism.

Second, functional unbundling means

that a transmission owner must include

in its open access tariffs separately

stated rates for the transmission and

ancillary service components of each

transmission service it provides. 184 The

rates must satisfy the Commission’s

Transmission Pricing Policy Statement.

Third, functional unbundling means

that the public utility, in order to

provide non-discriminatory open access

to transmission and ancillary services

information, must rely upon the same

electronic network that its transmission

customers rely upon to obtain

transmission information about its

system when buying or selling power.

For example, the proposed rule

requires that a public utility unbundle

its new wholesale requirements service

contracts, and its new wholesale

coordination purchase transactions, and

take the firm network transmission

component of those services under its

own firm network transmission tariff.

Similarly, the proposed rule requires

that a public utility unbundle any new

wholesale coordination sales

transactions and take the point-to-point

transmission component of that service

under its own point-to-point

transmission tariff. Finally, the

proposed rule requires that a utility

unbundle ancillary services and take

these services under its network and

point-to-point tariffs.

Public utilities also must authorize

their power pool agents to offer any

transmission service available under

power pool arrangements to all

transmission customers. In addition,

public utilities that participate in a

power pool that acts as a control area

must authorize the power pool’s control

center to offer ancillary services under

a filed tariff, and must take all of their

control area services from that tariff. 185

A public utility must take dispatch

service and other ancillary transmission

services on the same terms and

conditions as those offered to its

transmission customers. 186

The requirement to provide ancillary

services and to take those services under

a tariff is not intended to mandate any

federal rules that would prescribe the

actual merit order of dispatch. Rather, it

is a requirement that public utilities

ensure that dispatch practices and

procedures applicable to them are also

applied to third-party transmission

customers.

The proposed requirement that a

public utility take transmission service

used for wholesale requirements service

and wholesale coordination transactions

under its own filed tariff means that all

wholesale trade, both that of the public

utility and its competitors, would be

taken under a single wholesale

transmission tariff. Our preliminary

view is that such a requirement places

the correct incentives on the public

utility to file a fair tariff since it must

live under those terms for wholesale

purposes. The Commission invites

comment on its approach to functional

unbundling. Will it provide strong

enough incentives for nondiscriminatory access without some

form of corporate restructuring? If

utilities restructure, how will our

proposed rules apply to different types

of corporate structures?

While this approach to unbundling

creates good incentives with respect to

wholesale service, it omits retail service.

In other words, it does not require the

transmission owner to take unbundled

transmission service under the same

tariff as third parties in order to serve its

retail customers. This will result in

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. It also raises the

possibility that the quality of

transmission service for retail purposes

will be superior to the quality of

transmission service offered for

wholesale purposes.

We seek comment on how this

bifurcated approach would affect the

public utility’s incentives to provide

non-discriminatory open access

wholesale transmission service. For

example, will planning of incremental

transmission facilities be comparable or

will the transmission provider’s retail

customers retain an advantage from

having expansion costs placed on third

parties? What would be the benefits of

an approach that required the

transmission provider to take

unbundled transmission service for both

wholesale and retail purposes under the

same tariff used by third-party

transmission customers? Is such an

approach necessary to ensure that all

participants have the same incentives to

achieve non-discriminatory open access

transmission service and competitive

power markets? What would be the

disadvantages, if any, of such an

approach?

The Commission recognizes that the

unbundling of transmission for retail

purposes would intrude upon matters

that state commissions have

traditionally regulated. One possible

approach that would unify service

standards for wholesale and retail
17682 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

187As discussed infra, there would be a

component of local distribution in such a

transaction, subject to the state’s jurisdiction.

188This determination is consistent with our

findings regarding similar types of transactions in

the natural gas area. See El Paso Natural Gas

Company, 59 FERC ¶ 61,031 (1992), dismissed sub

nom. Windward Energy and Marketing Company v.

FERC, No. 92–1208 (D.C. Feb. 2, 1994).

189 Id.

190 56 FERC ¶ 61,289 at 62,133 (1991).

191This Commission does not have authority to

order retail wheeling. Section 212(h) of the Federal

Power Act, as amended by the Energy Policy Act

of 1992, Pub. L. 102–486, 106 Stat. 2776.

192 59 FERC ¶ 61,031 (1992); reh’g denied, 60

FERC ¶ 61,117 (1992).

193These Appendices will not appear in the

Federal Register.

194However, as discussed infra, in determining

the level of capacity that must be made available

for new transmission service requests, we have

proposed that capacity needed to meet current and

reasonably forecasted native load and to meet

existing contractual obligations may be excluded

from capacity made available for new transmission

service requests.

195Under 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.

196See, e.g., Northeast Utilities Service Company,

56 FERC ¶ 61,269 at 62,022 (1991), order on reh’g,

58 FERC ¶ 61,070, reh’g denied, 59 FERC ¶ 61,042

(1992), remanded, 993 F.2d 937 (1st Cir. 1993),

order on remand, 66 FERC ¶ 61,332 (1994)

(Northeast Utilities) (wheeling customer must

provide reasonable financial assurance before the

public utility undertakes substantial investments in

new facilities for that customer).

service would be for each vertically

integrated utility to establish a

distribution function that would be

responsible for obtaining transmission

service on behalf of retail customers.

This distribution function then could be

treated just as any other wholesale

customer. The distribution function of

the utility would take service under the

single Commission filed tariff. This

could change the traditional approach of

state-federal allocation of transmission

costs. The Commission seeks comment

on the merits of such an approach. How

could the Commission cooperate with

state commissions if it were to adopt

such an approach?

Finally, we address a specific type of

retail service that we believe to be

‘‘bundled’’ retail service in name only:

a so-called ‘‘buy-sell’’ transaction 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

‘‘bundled’’ retail sale to the end user.

We have determined that in these types

of transactions the retail ‘‘bundled’’ sale

is actually the functional equivalent of

two unbundled retail sales: (1) A

voluntary sale of unbundled

transmission at retail in interstate

commerce, subject to our exclusive

jurisdiction; 187 and (2) a sale of

unbundled generation at retail, subject

to the state’s jurisdiction.188 For these

types of sales, public utilities will have

to provide the voluntary retail

transmission component of the sale

under a FERC-filed tariff consistent with

the substantive requirements of this

proposed rule.

We are aware that some public

utilities are already contemplating

initiating this type of ‘‘buy-sell’’ service.

Similar services occurred in the natural

gas area, but the Commission did not

address the jurisdictional issue until a

substantial number of transactions had

been negotiated and implemented.

When the Commission ultimately

addressed the natural gas buy-sell

programs, we concluded that we have

jurisdiction over buy-sell transactions

since such agreements utilize interstate

transportation.189 We were concerned

then, just as we are concerned now, that

interstate and intrastate programs

operate together in an appropriately

integrated way.190 It is our preliminary

view that the interstate transmission

aspect of the buy-sell program must take

place under a FERC-filed tariff.

In imposing this requirement we wish

to stress that the state has jurisdiction to

determine which group of retail

customers may participate in such a

program. We also recognize that state

regulatory commissions will be called

upon to determine whether they have

jurisdiction under state law over retail

wheeling or direct access programs and,

if so, whether to authorize such

programs.191 However, the rates, terms,

and conditions for the interstate

transmission aspects of the program are

jurisdictional to this Commission.

The Commission did not address this

jurisdictional issue at an early state in

the evolution of competition in the

natural gas market. Consequently, when

we finally acted we chose to grandfather

ongoing programs so that energy supply

arrangements would not be disrupted.192

We do not want to face that difficulty

again. Thus, we are addressing the issue

at an early stage so that public utilities

and their customers will be on notice of

the jurisdictional implications of their

actions, and can make plans

accordingly.

3. Real-Time Information Networks

With this proposed rule, the

Commission is issuing a Notice of

Technical Conference and Request for

Comments on a proposal to require that

public utilities provide all transmission

users, including the transmission owner

or controller, simultaneous access to

transmission and ancillary services

information through real-time

information networks that would

operate under industry-wide standards.

Based upon the lessons we have learned

from our experience with gas pipeline

EBBs, we believe the proposed approach

is necessary and can work.

4. Non-Discriminatory Open Access

Tariff Provisions

It is important that the tariffs filed to

meet the non-discriminatory open

access service requirement contain

terms and conditions necessary to

ensure a certain minimum level of

service quality and to provide a level of

certainty to both customers and

transmission service providers as to

procedures and obligations. The

discussion in this section is intended to

give guidance about our proposed nondiscriminatory open access

requirements. The terms and conditions

discussed here are reflected in the pro

forma tariffs in Appendices B and C.193

We note at the outset two basic

principles proposed to be used when

evaluating tariff terms. First, the terms

and conditions governing service should

be clear and specific. Vague or general

tariff terms introduce uncertainty,

controversy and delay. In many

situations, delaying access or increasing

the transaction cost of access is, for all

practical purposes, denying access.

Second, any restrictions or limitations

on service or procedures must be

limited to technical or operational needs

that can be verified, and they must be

the least restrictive way to meet those

needs.194

The Commission invites comment on

the terms and conditions proposed as

well as whether others may be

necessary.

a. Customer eligibility. A nondiscriminatory open-access tariff must

be available to any entity that can

request transmission services under

section 211.195

b. Expansion obligation. A public

utility must offer to enlarge its

transmission capacity (or expand its

ancillary service facilities) if necessary

to provide transmission services. This

provision is necessary to mitigate the

utility’s transmission market power that

could be exercised by restricting

capacity. The customer must agree to

reasonable terms, conditions and prices,

including the financial responsibility for

its share of the incremental expansion

costs.196

The Commission recognizes that a

utility may not be able to enlarge

transmission capacity because it cannot

obtain the necessary approvals or

property rights under applicable
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17683

197However, we have previously noted that a

utility may bear a heavy burden in demonstrating

that it cannot enlarge its transmission capacity to

meet a new transmission request. See Northeast

Utilities, 58 FERC at 61,209.

198See Entergy Services, Inc., 58 FERC ¶ 61,234

at 61,767, order on reh’g, 60 FERC ¶ 61,168 (1992),

rev’d on other grounds sub nom. Cajun Electric

Power Cooperative, Inc. v. FERC, 28 F.3d 173 (D.C.

Cir. 1994).

Federal, state and local laws. If the

utility has failed after making and

documenting a good faith effort to

obtain the necessary approvals or

property rights, it can request to be

relieved of its expansion obligation by

an appropriate filing at the

Commission.197 This will result in

consistent treatment under FPA sections

205 and 206 and FPA section 211.

c. Service obligation. The

transmission tariff must offer nondiscriminatory transmission services

(including related ancillary services that

the utility can provide) to eligible

transmission customers. For example, a

tariff should make available both

flexible (i.e., firm and non-firm) pointto-point transmission service and

network transmission service, as well as

those ancillary services necessary to

accomplish such transmission services.

(1) Network Transmission Service.

Network transmission service allows a

transmission customer to use the entire

transmission network to provide

generation service for specified

resources and specified loads without

having to pay a separate charge for each

resource-load pairing. Such service

allows a transmission customer to

integrate, plan, commit, economically

dispatch, and regulate its resources to

serve its consolidated load. Network

service provides the customer with the

same flexible network usage needed to

optimize its resources to meet its

customers’ needs that transmission

owners have to optimize their resources

to meet their customers’ needs. Network

service includes the ability to import

power from other control areas to

economically and reliably serve the

customers’ load. Non-discrimination

requires that network service be made

available in an open access tariff.

Network service would be valuable to

customers such as municipals,

cooperatives, and municipal joint action

agencies that supply the long-term firm

power needs of members with multiple

loads that are wholly or partly within a

single transmission system. Indeed,

network service is essential for the

resource integration that is needed for

efficient operation. For example, a

generation and transmission cooperative

whose generating facilities and member

cooperatives are widely dispersed may

not own all of the transmission facilities

needed to link the generators with the

members’ distribution systems. In this

case, the cooperative must rely on a

transmission-owning utility to provide

network service. Without such service,

the cooperative would have difficulty

supplying reliable, efficient power to its

own members.

(2) Flexible Point-to-Point Service.

The second required service in a nondiscriminatory open access tariff is

point-to-point transmission service.

Both firm and non-firm service must be

available on a point-to-point basis.

Under firm point-to-point service, the

transmission owner would provide firm

deliveries of power from designated

points of receipt to designated points of

delivery. Each point of receipt would be

set forth in a service agreement along

with a corresponding capacity

reservation for that point of receipt.

Each point of delivery would be set

forth in the service agreement along

with a corresponding capacity

reservation for that point of delivery.

The greater of (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

would be the firm capacity reservation

for which the transmission customer

would be charged.

However, firm point-to-point service

must have the same flexibility in use as

that available to the transmission

provider and obligate the transmission

provider to supply non-firm

transmission service, if available, over

non-designated receipt and delivery

points (or over designated receipt and

delivery points in excess of its firm

reservation at those points) without

incurring any additional charges (or

executing a new service agreement) so

long as the customer’s use does not

exceed its total firm capacity

reservation. Any use by a customer in

excess of its firm capacity reservation at

each point of receipt or point of delivery

will be on an as-available basis and will

be treated as non-firm service. A

customer may also request non-firm

point-to-point transmission service on a

stand-alone basis.

Transmission customers may be

willing to trade off the higher risk of

interruption with non-firm service for

the lower non-firm transmission rate.

Customers should be able to make that

choice, which will depend on their own

balancing of the risk of transmission

service interruption with the

interruptibility of, and trade gains

associated with, the power resource. It

is important that the customer, not the

transmission provider, make this choice.

The tariff should not restrict non-firm

transmission service to the transporting

of only non-firm power transactions.198

Tariffs should offer flexible point-topoint transmission service for

transactions that involve power flows

into, out of, within or through the

control areas. Whether or not a

transmission provider actually

undertakes such specific services on its

own behalf, it has the flexibility to do

so. Therefore, if service to third parties

is to be non-discriminatory, they, too,

must have such flexibility. In addition,

tariff restrictions on receipt and delivery

points should not preclude particular

types of transactions. For example, a

transmission provider should not limit

receipt and delivery points to points of

interconnection with other transmission

systems because such a restriction may

preclude transactions that originate or

terminate with generation or particular

loads within a transmission provider’s

control area.

(3) Ancillary Services. Ancillary

services are those services necessary to

support the transmission of electric

power from seller to purchaser given the

obligations of control areas and

transmitting utilities within those

control areas to maintain reliable

operations of the interconnected

transmission system. Basic transmission

service without ancillary services may

be of little or no value to prospective

customers. A variety of ancillary

services is needed in conjunction with

providing 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 (such as load

following, reactive power support, and

system protection services). Other

ancillary services are needed to correct

for the effects associated with

undertaking a transaction (such as loss

compensation and energy imbalance

services). Due to the nature of certain

ancillary services (such as scheduling

and dispatching service), the

transmission provider may be uniquely

positioned to provide these services.

However, for other ancillary services

(such as loss compensation service), the

customer may wish to provide the

service itself or purchase the service

from a party other than the transmission

owner or its agent.

If the transmission provider provides

the ancillary services for its own use of

the transmission system, the public

utility should offer in the tariff to

provide ancillary services for

transmission customers. Tariffs should
17684 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

commit to provide specific ancillary

services at specific prices or under

specific compensation methods that are

clearly described.

If the transmission provider obtains

ancillary services from a third party,

e.g., does not operate its own control

area or obtains ancillary services from a

pool, the transmission provider should

offer in the tariff to secure ancillary

services for transmission customers

from that third party. Examples of such

third-party arrangements may include a

public utility obtaining ancillary

services from a power pool or from a

control area operator.

Based on our experience to date, we

propose that the following ancillary

services should be offered in the tariff:

1. Reactive Power/Voltage Control

Service

In order to maintain transmission

voltages on the transmission provider’s

transmission facilities within acceptable

limits, transmission facilities and some

or all generation facilities (in the service

area where the transmission provider’s

transmission facilities are located) are

operated to produce (or absorb) reactive

power. Thus, the need for reactive

power/voltage control service must be

considered for each transaction on the

transmission provider’s transmission

facilities. The amount of reactive power/

voltage control 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.

The transmission provider will be

responsible for providing the necessary

transmission-related reactive power

support. A transmission customer may

elect (or arrange through a third party)

to supply some or all of the necessary

generation-related reactive power/

voltage control support to the extent

that it (or the third party) has the ability

to supply such reactive power. If the

transmission customer elects (or

arranges through a third party) to

provide reactive power/voltage control

support, such service must be

coordinated with the transmission

provider (or the entity that is

responsible for the operation of the

transmission provider’s transmission

facilities). Alternatively, the

transmission provider will supply the

necessary generation-related reactive

power/voltage control support.

2. Loss Compensation Service

Capacity and energy losses occur

when a transmission provider delivers

electricity across its transmission

facilities for a transmission customer. A

transmission customer may elect to (1)

supply the capacity and/or energy

necessary to compensate the

transmission provider for such losses,

(2) receive an amount of electricity at

delivery points that is reduced by the

amount of losses incurred by the

transmission provider, or (3) have the

transmission provider supply the

capacity and/or energy necessary to

compensate for such losses.

3. Scheduling and Dispatching Services

Scheduling is the control room

procedure to establish a pre-determined

(before-the-fact) use of generation

resources and transmission facilities to

meet anticipated load (including

interchange). Dispatching is the control

room operation of all generation

resources and transmission facilities on

a real-time basis to meet load within the

transmission provider’s designated

service area (or other larger area of

coordinated dispatch operation).

Scheduling and dispatching services are

to be provided by the transmission

provider or other entity that performs

scheduling and dispatching for the

transmission provider’s service territory.

In certain regions, dynamic

scheduling is also allowed. Dynamic

scheduling involves responding to load

changes or controlling generation within

one transmission provider’s service

territory (or other larger area of

coordinated dispatch operation) through

the real-time control and dispatch of

another transmission provider. Under

dynamic scheduling, the operator of an

area of coordinated dispatch (control

area) agrees to assign certain customer

load or generation to another area of

coordinated dispatch, and to send the

associated control signals to the

respective control center of that area.

Dynamic scheduling is implemented

through the use of special telemetry and

control equipment. The transmission

customer must be allowed to use

dynamic scheduling when it is feasible

and reliable.

4. Load Following Service

Load following service is necessary to

provide for the continuous balancing of

resources (generation and interchange)

with load under the control of the

transmission provider (or other entity

that performs this function for the

transmission provider). Load following

service is accomplished by increasing or

decreasing the output of on-line

generation (predominantly through the

use of automatic generating control

equipment) to match moment-tomoment load changes. The obligation to

maintain this balance between resources

and load lies with the transmission

provider (or other entity that performs

this function for the transmission

provider). Because of the nature of this

service, the transmission provider (or

other entity that performs this function

for the transmission provider’s facilities)

may be uniquely positioned to provide

load following service. Therefore, unless

the transmission customer is able to

obtain such service from its own

generation or from third-party

generation that is capable of supplying

such service in accordance with

conditions generally accepted in the

region and consistently adhered to by

the transmission provider, the

transmission provider will supply load

following service.

5. System Protection Service

A transmission provider must have

adequate operating reserves or other

system protection facilities available in

order to maintain the integrity of its

transmission facilities in the event of (1)

unscheduled outages of a portion of its

transmission facilities or facilities

connected to the transmission

provider’s service territory or (2)

unscheduled interruption of energy

deliveries to the transmission provider’s

transmission facilities. The amount of

system protection service that must be

supplied with respect to the

transmission customer’s transaction will

be determined based on operating

reserve margins or other relevant criteria

that are generally accepted in the region

and consistently adhered to by the

transmission provider.

The transmission customer may elect

or arrange through a third party to

provide resources that are sufficient to

satisfy the system protection needs of

the transmission provider. Operation

and dispatch of such resources must be

coordinated with the transmission

provider or other entity that maintains

operating reserves and other system

protection facilities for the transmission

provider’s service territory.

6. Energy Imbalance Service

Energy Imbalance Service is provided

when a difference occurs between the

hourly scheduled amount and the

hourly metered (actual delivered)

amount associated with a transaction.

Typically, an energy imbalance is

eliminated during a future period by

returning energy in-kind under

conditions similar to those when the

initial energy was delivered.
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17685

199See Florida Power & Light Company, 66 FERC

¶61,227 at 61,524 (1994), order on reh’g, 70 FERC

¶61,150 (1995). The Commission has required a

similar cap for released pipeline capacity. See

Order No. 636–A, Pipeline Service Obligations and

Revisions to Regulations Governing SelfImplementing Transportation Under Part 284 of the

Commission’s Regulations, Regulation of Natural

Gas Pipelines After Partial Wellhead Decontrol and

Order Denying Rehearing in Part, Granting

Rehearing in Part, and Clarifying Order No. 636,

Ferc Stats. & Regs. ¶30,950 at 30,560 (1992), appeal

pending.

200 In FP&L, the Commission approved network

service billing based on a load ratio method of cost

allocation, instead of on contract demand.

The transmission provider shall

establish a deviation band (e.g., +/¥1.5

percent 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 30

days or a reasonable period of time that

is generally accepted in the region and

consistently adhered to by the

transmission provider. If an energy

imbalance is not corrected within 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.

To the extent another entity performs

this service for the transmission

provider, charges to the transmission

customer are to reflect only a passthrough of the costs charged to the

transmission provider by that entity.

We seek comment on our proposed

treatment of ancillary services. Are there

alternative ways to ensure the nondiscriminatory provision of ancillary

services? We also seek comment on the

above-described ancillary services. Are

they the appropriate ancillary services

for the needs of entities seeking

transmission service? Are the

descriptions of the ancillary services

appropriate? Should any of the

described services not be offered, and if

so, why? Are there other ancillary

services that should be offered? Should

all ancillary services be offered as

discrete services with separate prices, or

should certain ancillary services be

offered as a package? Additionally, we

seek comment on whether the

additional complexity of obtaining

ancillary service externally from the

host control area with the use of

dynamic scheduling is the appropriate

course to follow.

d. Service Periods. The duration of

service reservations should not be

unduly limited. Non-discriminatory

service requires any such limits on

third-party service to be the same as

those the transmission provider or

controller faces. In particular, the tariff

should allow firm service contracts to

extend at least for the life of a

customer’s power plant or purchase

contract. Power developers are unlikely

to build new plants if they cannot

secure firm transmission services for the

plant’s life. Integrated transmission

owners plan their transmission systems

to ensure capacity to deliver the output

of their own planned generation units.

Non-discriminatory service requires the

same for transmission-only customers.

Likewise, the minimum duration for

service should be the same as the

minimum scheduling period of the

transmission owner. All minimum or

maximum restrictions must be justified

on a technical or operational basis.

e. Reassignment Rights. A tariff must

explicitly permit reassignment of firm

service entitlements. Capacity

reassignment rights can have a number

of benefits. First, reassignment rights are

important in helping transmission users

manage the financial risk associated

with long-term commitments to take

transmission service. A robust

reassignment market would aid, among

others, customers who can get or must

take transmission capacity now but do

not actually need it until some time in

the future, and customers whose need

for capacity they have under contract is

intermittent or suddenly declines.

Transmission owners have the

flexibility to manage this sort of risk by

offering transmission capacity to others.

Non-discriminatory service demands

that non-owner holders of rights to

transmission capacity have the same

flexibility to manage their risk as

owners have.

Second, capacity reassignment,

combined with assured access to firm

transmission service, reduces the

transmission provider’s market power

by enabling transmission customers to

compete with the owner to some extent

in the firm transmission market. To

promote competition in such a

secondary market, firm service rights

should be defined as broadly as

possible, consistent with reliable

operation of the system. In particular,

using firm transmission capacity to

deliver non-firm power or repackaging

firm transmission capacity for sale as

non-firm capacity should not be unduly

restricted.

Third, the ability to reassign capacity

rights can also improve capacity

allocation. When capacity is constrained

and some market participants value

capacity more than current capacity

holders, the current holders may be

willing to reassign their capacity rights

at rates below the opportunity costs of

the transmission provider, thereby

lowering rates to the new customer. We

note that the prices of reassignments are

currently capped at the price the public

utility sold the transmission.199 The

Commission invites comments on

whether the current price cap on resale

should be modified or eliminated.

In addition, the service agreement

must state clearly the respective

obligations of the original right holder

and any subsequent purchaser of the

right. In particular, it should state the

conditions, if any, under which the

original right holder can be released

from its obligations under the service

agreement if the right is reassigned or

sold. Any reassignments must be done

in a not unduly discriminatory manner.

We invite comment on these

reassignment issues.

Given the current specification of

basic transmission services (network,

flexible point-to-point, and ancillary),

some services may be more reassignable

than others. The ease with which rights

can be reassigned depends on two

factors: the ability of ensuring

operational feasibility and the

specificity of contract rights. Point-topoint service involves a well-specified

right to transfer a given amount of

power between specific points or across

an interface under certain conditions.

The transmission provider is

operationally indifferent as to who

wants to transfer the power that flows

between those points. Thus, point-topoint service is well-suited to

reassignment.

Network service, as currently defined,

is idiosyncratic because it is unique to

the transmission user receiving the

service. This service is purchased to

integrate a set of resources into a set of

loads given specific dispatch parameters

and load profiles. The transmission

provider has to plan and operate its

system for this specific service. It is not

clear that such service could be of any

value to an entity other than the original

buyer. It is also not clear precisely what

would be resold because network

customers do not have rights to a

specific amount of transmission

capacity, but have rights only to a

varying amount of capacity needed to

integrate load with their dispersed

power resources.200 Such indeterminate

rights may not be amenable to

reassignment. We seek comments on

reassigning network service. Can

network service be structured such that
17686 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

201The Commission previously accepted tariffs

that contain reciprocity provisions. See, e.g., El

Paso Electric Company and Central and South West

Services Inc., 68 FERC ¶61,181 at 61,916 (1994),

reh’g pending; Southwestern Electric Power

Company and Public Service Company of

Oklahoma, 65 FERC ¶61,212 at 61,981–82 (1993),

reh’g denied, 66 FERC ¶61,099 (1994).

202See Order Nos. 558 and 558–A, supra note 92.

203See supra note 91.

capacity rights could be specified and

reassigned?

Ancillary services also may not be

suitable for reassignment. We seek

comments on these reassignment issues.

e. Reciprocity provision. The

Commission proposes to require that

transmission tariffs contain a reciprocity

provision.201 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.

f. Available Transmission Capacity

(ATC). ATC is capacity that must be

made available for new firm

transmission service requests. Basically,

it is the capacity not committed to other

firm uses during the scheduling

interval(s) for which service is

requested. The tariff must clearly

specify the other uses for which

capacity will be excluded from ATC.

Acceptable other uses may include:

• A requirement to meet generally

applicable reliability criteria.

• Meeting current and reasonably

forecasted load (retail customers and

network transmission customers) on the

transmission provider’s system. The

term ‘‘reasonably forecasted’’ should be

defined in terms of the utility’s current

planning horizon. Capacity needed to

serve reasonably forecasted load must

be made available until the forecasted

load develops.

• Fulfilling the transmission

provider’s current firm power and firm

transmission contracts.

• Meeting pending firm transmission

service requests.

In the tariff, the utility must commit

to provide an index of other holders of

firm transmission entitlements and

describe the method used to estimate

ATC in sufficient detail to allow others

to do the same analysis. The utility must

make all data used in calculating the

ATC publicly available. The

methodology and the data used to

develop the ATC must be consistent

with the information submitted in the

FERC Form No. 715, Annual

Transmission Planning and Evaluation

Report.202

Capacity can be withheld from ATC

only if it is to be used during the

scheduling period for which service is

requested. For example, if a customer

requests firm service for ten years and

the utility needs that capacity to serve

native load during years six to ten, the

utility must provide service using the

existing capacity for the first five years

and then use expanded capacity or some

other alternative arrangement for the

third-party service during the remainder

of the term.

Under the proposed rule, ATC

information will be required to be made

available in the public utility’s

information system. The nature of the

ATC information to be made available

and the manner in which it is made

available will be the subject of the realtime information networks technical

conference that we are concurrently

initiating.

g. Procedures for obtaining service.

This section must clearly describe all

notice and response requirements,

including deadlines for each step in the

process, the information required in a

valid request for service, the procedure

for obtaining service from existing

capacity and the additional steps to

follow when capacity expansion is

required. The discussion below

highlights some particularly important

aspects of procedures for obtaining

service.

The tariff must specify minimum

notice periods. Notice for accepting

requests for short-term service is

particularly important. Because market

opportunities may be short-lived, the

advance notice required for short-term

service should be as brief as possible

and should be able to be secured

through the real-time information

network. Similarly, the tariff also should

specify the minimum time needed to

accommodate customers’ needs to plan

and construct new generating units or to

enter into long-term power supply

contracts.

A tariff must specify the information

that must accompany a service request.

This information should generally track

that specified in the Commission’s

Policy Statement Regarding Good Faith

Requests for Transmission Services.203

The tariff should require only

information that is clearly necessary to

determine whether capacity is available,

the price for the service requested and

other information necessary to process

the service request.

A tariff may require scheduling of

receipt and delivery points and amounts

of energy flows but not require

disclosure of power contract terms as

part of the request process. While the

Commission has accepted such a

requirement in some tariffs, our

preliminary view is that there are less

intrusive and less ambiguous ways of

dealing with transmission owner

concerns. If the concern is the need to

know intended power flows, the needed

information of the anticipated

transaction can be specified in a service

request.

The concern may be that a customer

will reserve scarce capacity and then

hold it without using it (for whatever

reason). While reservation holders as

well as transmission providers should

not be allowed to withhold capacity,

there are less restrictive options for

dealing with this concern. One is to

allow the transmission provider to use

or sell the capacity for so long as the

reservation holder is not using it.

Another is to have a pool that clears the

short-term market. Of course, the

reservation holder would be

compensated. Another option is to

require the customer to begin using the

capacity within some period or lose its

reservation rights for that capacity. Any

of these alternatives can allay legitimate

concerns without forcing customers to

reveal unnecessary details of the

transaction. The Commission requests

comments on these and other

approaches. Could pooling help address

these issues? In particular, how would

a use-it-or-lose-it rule work? How would

a utility know which reservation holder

to compensate with non-firm revenues if

network service customers hold no

reservation rights? Non-firm revenues

could be shared among load-ratio

customers and reservation customers on

the basis of the non-use of the firm

entitlements.

With respect to network service, our

preliminary view is somewhat different.

Because network service is billed on a

load ratio basis, customers would have

the incentive to specify unlimited

generation resources to be integrated

into their load without any

commensurate financial obligation. The

transmission provider would

nevertheless have to plan its system to

dispatch those resources. Thus, network

customers, when designating their

network resources, must show that they

own or have contracted for those

resources. We seek comment on this

issue. Are there alternative ways of

dealing with this problem for network

service?
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17687

204See Energy Services, Inc., 58 FERC ¶ 61,234 at

61,766 and 61,768 (1992) (security deposit or some

other form of assurance permitted; approval of

provision requiring transmission customers to have

‘‘suitable interconnection agreement’’ with

transmission-owning utility).

205Of course, the utility always may curtail if

necessary to maintain the reliability of the system.

For example, if a major transmission line fails, the

utility may quickly have to interrupt transactions

without regard to priority of service in order to

stabilize the system. Once the system is stabilized,

however, the utility should allocate remaining

capacity on the basis of contractual priorities.

The tariff should provide that, if

service can be provided using existing

capacity, a service agreement will be

tendered in time for the customer to

execute it so that service can begin at

the time requested. The tariff should

clearly state the applicable rates for

service from existing capacity. In

addition, the tariff should contain

provisions, as well as rates, for reserving

capacity now for use at a later time.

Also, the tariff should contain a

standardized service agreement that

applies to all service provided from

existing capacity.

When existing capacity is not

adequate to provide additional firm

service, the tariff should require the

transmission provider to prepare, if

needed, an engineering study of options

for expanding capacity, including the

costs of each option, within a specified

period. The customer should be

required to pay the reasonable costs of

performing the study. If the customer

elects to take service after reviewing the

engineering study and cost estimates,

including supporting documentation,

the transmission provider may require

the customer to enter into a contract,

provide a security deposit, and agree to

take service at rates calculated in

accordance with the pricing provisions

of the tariff.204 The tariff should allow

the customer to specify the contract

term.

h. Service priority. Service priority

becomes important when capacity is

constrained (i.e., demand exceeds

supply). This, in turn, has two aspects:

when new service requests are

considered and when, after service has

begun, interruptions are required.

(1) Considering new service requests.

A tariff should specify a reasonable

basis upon which service requests will

be considered. As long as transmission

capacity is available for all requests,

they can all be accommodated. When

capacity is short, however, the priority

of requests is important because the

determination as to which requests are

met from existing capacity and which

require expanded facilities will affect

pricing. However, firm service requests

should always receive priority over nonfirm service requests, and firm service

requests from third-party transmission

customers should have the same priority

as new transmission services for the

public utility’s native load.

The industry currently operates under

a contract rights regime whereby

customers are given contract rights for a

specific period at a set price. Under this

regime, requests are generally processed

under a first-in-time rule. Capacity is

allocated in the order in which the

requests were made. If available

transmission capacity is exhausted, a

requester may be required to pay the

incremental cost of relieving the

constraint. Incremental cost could be

either the redispatch cost of unloading

a line or the cost of expanding capacity.

Thus, the position of the requester in

the queue may affect price and possibly

determine when service is provided.

Alternatively, all requesters during a

given period could be treated as making

one request for a large increment of

capacity and pay the same average

incremental cost. We seek comments on

appropriate ways to process requests.

(2) Allocating interruptions. After

service has begun, priority is important

if capacity becomes unexpectedly

constrained and service must be

interrupted.205 Contracts must spell out

the obligations and priorities in dealing

with operating and reliability

procedures. Priorities will affect the

order in which services are interrupted.

A tariff must specify that firm

transmission service always has priority

over non-firm transmission service.

Non-discriminatory service requires that

firm transmission customers have the

same assurance of uninterrupted use of

the grid, within their contractual

commitments and obligations, as the

transmission provider. That is, the

public utility’s personnel who trade

wholesale power should have the same

firm transmission service as does a firm

transmission customer. Both have the

same standing when the control area

operator deals with emergencies. That

is, both must recognize that the operator

is authorized to interrupt scheduled

power transfers as needed in order to

maintain reliability. Operators must be

allowed to maintain safe and reliable

service on the overall system.

Generally, interruption of firm

transmission service should occur only

because of: (1) Emergencies or force

majeure; or (2) the need to maintain

overall reliability or to protect

equipment as prescribed in industry

operating guidelines. The specific

reasons for interruptions will have to be

determined in accordance with the

characteristics of each transmission

provider’s system. The tariff should

require the provider to notify all

customers in a timely manner of any

scheduled interruptions, while

recognizing the right to take appropriate

actions under operating procedures to

deal with unscheduled emergency

conditions.

i. Security deposits and

creditworthiness. A tariff may require

that a reasonable, returnable deposit

accompany the request for service, and

that the customer demonstrate basic

creditworthiness. A creditworthiness

investigation (including a security

deposit requirement) must be applied

on a non-discriminatory basis.

j. Short-term and interruptible service

agreements. A copy of standard

transmission service agreements for

short-term and interruptible

transmission services must be included

in the tariff in order to expedite service

and limit the possibility of undue

discrimination or other abuse. The tariff

must list all information needed from

the customer.

k. Dispute resolution. The tariff must

clearly set forth the steps to be followed

to resolve disputes. Procedures should

be designed to resolve conflicts quickly.

This suggests the use of some type of

alternative dispute resolution (ADR)

process, such as mediation or

arbitration. ADR would be especially

useful when the dispute is over

response times, capacity additions, a

highly technical matter, or any matter

that applies, but does not extend,

existing Commission policy. The tariff

should specify which types of disputes

must go to ADR and which disputes

must be taken directly to this

Commission.

A tariff should provide that capacity

expansion proceed while cost disputes

are pending, provided the customer

agrees to pay the costs actually incurred

and the rate ultimately determined by

the Commission. This is needed to

minimize delays when the customer

wants the service but disputes the cost.

Such a provision would require the

transmission owner to proceed with

whatever steps are necessary to provide

service to the customer, as long as the

customer agrees to furnish a deposit and

state in writing that it will take service

at the rates, terms and conditions that

are ultimately found just and reasonable

by the Commission, or to pay all out-ofpocket costs incurred in processing the

request up to the date of cancellation of

the request.

l. Pricing. Transmission pricing must

be consistent with the Commission’s

Transmission Pricing Policy
17688 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

206See supra note 124.

207For example, there are approximately 56

electric utilities operating control areas in the

United States that are not public utilities.

208This assumes, of course, that all have made the

requisite request to the transmitting utility 60 days

prior to filing. FMPA, for example, filed on behalf

of numerous Florida municipals in the FP&L

section 211 case. See Florida Municipal Power

Agency v. Florida Power & Light Company, 65 FERC

¶ 61,125 (1993).

209See CSW, supra, 68 FERC at 61,916. Section

211 bars the Commission from ordering service that

would unreasonably impair the continued

reliability of electric systems affected by the order.

To meet this requirement, the transmission owner

and the applicant (or the Commission if necessary)

can craft provisions in the general tariffs discussed

above to assure that service will comply with

standard industry operating practices and, thus, not

have an unreasonable impact on reliability.

210Such a hearing is required only if there are

material issues of fact in dispute. See Citizens for

Allegan County, Inc. v. FPC, 414 F.2d 1125, 1128

(D.C. Cir. 1969).

211For applicants with transmission market

power, the Commission has required the mitigation

of such power through the filing of a nondiscriminatory open access tariff. The Commission

also has examined an applicant’s control over

potential barriers to entry, e.g., ownership or

control of sites for generation facilities, generation

equipment, or pipelines for supplying fuel.

212 67 FERC at 61,557.

Statement.206 We especially note that

the transmission public utility must

charge itself the same price for

transmission services that it charges its

third-party wholesale transmission

customers.

5. Pro Forma Tariffs

Appendices B and C to this proposed

rulemaking contain pro forma tariffs

that contain the minimally acceptable

terms and conditions of service for

point-to-point and network transmission

services. They contain tariff language

that assures acceptable levels of service

quality for non-price terms and

conditions. For the most part, we have

avoided specifying pricing provisions.

The pro forma tariff provisions would of

course be subject to case specific

scrutiny to ensure that services are

provided on a non-discriminatory open

access basis. We seek comment on

whether these tariffs provide a good

basis for defining the minimum

acceptable non-price terms and

conditions of service.

6. Broader Use of Section 211

The Commission intends to exercise

its authority under sections 205 and

206, as described in this proposed rule,

in a complementary manner with its

authority under section 211. Requiring

all public utilities to file nondiscriminatory open access tariffs, as set

forth in this NOPR, will not alone

ensure competitive bulk power markets

in all regions of the United States. Many

utilities providing transmission services

are not public utilities subject to our full

jurisdiction.207

Section 211, however, permits entities

to seek open access to all transmission

facilities, including those owned by

non-public utilities. Thus, to further

eliminate unduly discriminatory

practices in the industry, the proposed

rule encourages the broad use of section

211.

While the Commission cannot order

transmission sua sponte under section

211, nothing in section 211 prohibits

groups of qualified applicants from

simultaneously or jointly filing

applications for the same service. 208

Such group or joint action would permit

the Commission to order tariffs of

broader applicability.

Moreover, sections 211 and 212

require that applicants specify only

rates, terms, and conditions of service,

not specific transactions. Thus,

applicants can file requests for tariffs to

accommodate future, currently

unspecified, short-notice transactions,

similar to the type of tariff filed by many

utilities seeking approval of marketbased rates or mergers.209

Section 211 bars the Commission

from ordering service that would

unreasonably impair the continued

reliability of electric systems affected by

the order. To meet this requirement, the

transmission owner and the applicant

(or the Commission if necessary) can

craft provisions in the general tariffs

discussed above to assure that service

will comply with standard industry

operating practices and, thus, not have

an unreasonable impact on reliability.

Finally, section 211 permits an

opportunity for an evidentiary

hearing.210

Section 211 does not preclude

applicants from lodging the record from

a section 205 undue discrimination case

involving the same service, nor does it

preclude the Commission from

incorporating and relying on the record

and findings in a section 205 proceeding

if the section 211 applicant, the

transmitting utility, and the service

requested are the same. In sum, sections

211 and 212 provide the Commission

and the electric industry a much

broader means to attain wider

transmission access than has been

achieved so far. In this regard, the

Commission invites comment on further

avenues the Commission can pursue to

facilitate and expedite 211 applications.

Section 211 also complements our

section 205 and 206 authority in that it

allows customers to request unique

services not available in the nondiscriminatory open access tariff. While

our objective in this proposed rule is to

implement a very broad service

commitment in the non-discriminatory

open access tariff, customers may have

unique service needs that are not

contemplated in the open access tariff.

7. Status of Existing Contracts

There are three general types of

existing wholesale contracts that could

be affected by the proposed rule: (1)

Requirements and other firm service

contracts under which customers take

bundled transmission and generation

services; (2) coordination contracts for

purchases or sales of economy energy;

and (3) transmission-only contracts. The

Commission believes that it can

eliminate unduly discriminatory

practices and achieve more competitive

bulk power markets without abrogating

existing contracts. Accordingly, as

discussed supra, we have proposed to

apply the unbundling requirement only

to transmission services under new

requirements contracts and new

coordination transactions. In addition,

although the open access tariffs must be

open to all entities that could request

transmission service under section 211,

i.e., all non-sham wholesale purchasers,

we are not proposing to abrogate any

existing power or transmission

contracts. However, there may be

situations in which it would be contrary

to the public interest to allow existing

wholesale power or transmission

contracts to remain in effect.

Accordingly, we 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.

8. Effect of Proposed Rule on

Commission’s Criteria for Market-Based

Rates

As stated above, one of the primary

reasons for this rulemaking is to foster

increased wholesale competition, in

order to reduce prices for consumers.

Moreover, the increased competition

allowed by non-discriminatory open

access may allow lighthanded

regulation of wholesale sales for many

more transactions and perhaps

throughout many regions.

The Commission’s standards for

allowing market-based rates for

wholesale power sales require an

applicant and its affiliates to

demonstrate that they lack or have

mitigated market power in generation

and transmission, that they cannot erect

other barriers to entry,211 and that there

is no affiliate abuse or reciprocal

dealing. In KCP&L,212 the Commission
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17689

213See Entergy Services Inc., 58 FERC ¶61,234 at

61,755 (1992). 214See SWRTA and WRTA, supra.

determined that it no longer needed to

examine generation dominance in

analyzing market-based rate proposals

for sales from new generation facilities.

However, the Commission has

continued to evaluate generation

dominance in analyzing market-based

rate proposals for sales from existing

generation capacity.213

If this rulemaking achieves the

Commission’s goals, and competition

fueled by open access increases in the

wholesale bulk power markets to the

extent we expect, the increased

competition may reduce or even

eliminate generation-related market

power in the short-term market.

Increased wholesale competition could

reduce the need for cost-based

regulation of bulk power sales and allow

broader use of market-based rates. For

example, more competitive markets may

allow us at some point to drop the

generation dominance standard for

existing capacity. We believe that the

increased competition expected to result

from this rulemaking may allow us to

consider innovative approaches to

authorizing market-based rates for

generation. One suggestion in this

regard has been that the Commission

ought to consider filings made pursuant

to section 205 seeking authorization of

market-based rates for all sellers in a

defined region. For example, such a

region conceivably could be defined by

the boundaries of an RTG, a power pool,

a reliability council, or the less formal

boundaries of an economic market.

However, before proceeding to consider

this suggestion, or any other innovative

proposal for dealing with market-based

rates for existing wholesale generation,

the Commission must address certain

threshold questions. Therefore, the

Commission solicits comments on the

following questions:

(1) Assuming that a final rule in this

proceeding mandates that all public utilities

must file generally applicable nondiscriminatory open access tariffs, would

wholesale sellers of generation from existing

generating facilities still possess market

power?

(a) Can we eliminate our generation

dominance standard based on before-the-fact

predictions of changes to come from our

rulemaking, or must we rely on after-the-fact

evidence of the changes that did occur?

(2) For purposes of assessing whether

existing wholesale generators still possess

market power, how ought the relevant market

be defined in an open access transmission

environment? To what extent do the

boundaries of a regional transmission group,

a power pool, or a reliability council lend

themselves to being used to define the

relevant market in an open access

environment?

(3) Should it be determined that,

notwithstanding non-discriminatory open

access transmission, existing generators still

possess market power, can such market

power be mitigated effectively to permit

market-based rates for existing generation?

And, if so, what are the Commission’s

options? For example:

(a) Ought the Commission rely on rules of

conduct, market mechanisms intended to

ensure competition in wholesale power sales

(such as bidding procedures) and monitoring

as the means to curb such market power; or

(b) Ought the Commission rely on

structural reforms as the means to curb such

market power?

(4) Once the Commission has determined

how to define the relevant market in an open

access environment, ought the Commission

entertain requests that all wholesale sellers

within such a market be authorized to charge

market-based rates?

9. Effect of Proposed Rule on Regional

Transmission Groups

In the Commission’s Policy Statement

Regarding Regional Transmission

Groups (RTGs) we expressed support for

the development of voluntary

transmission associations and

encouraged their formation. 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.

Since the issuance of the Policy

Statement, the Commission has given

conditional approval to the bylaws of

two RTGs.214 Both approvals were

conditioned on the members agreeing to

offer comparable transmission services

at least to other members, through either

individual transmission tariffs or a

generic regional tariff. For public

utilities, that condition would be

superseded by fulfillment of the

requirements of the proposed rule.

To the extent public utilities view the

comparability requirement in our two

RTG orders as a disincentive to joining

an RTG, that disincentive would be

mooted. All such utilities will be

required to file tariffs. Moreover, we

will continue to provide substantial

latitude for innovative pricing proposals

by an RTG, as indicated in the

Transmission Pricing Policy Statement.

Some transmission users might

conclude that the availability of

comparability tariffs makes membership

in an RTG less necessary. But, this

conclusion would ignore the

comparative benefit of a member having

its needs planned for on a region-wide

basis under an RTG instead of on a

system-by-system basis. Coordination of

planning that results in a more efficient

system creates economies for both

transmitting utilities and users.

Also, the reduction in administrative

burden for all parties involved in an

RTG would remain. RTG members can

work out their own disputes without

incurring the substantial costs and

delays involved in litigating at the

Commission or in the courts. This fact

alone makes for more flexible and

responsive markets and reduces costs.

Moreover, the Commission has stated its

willingness to give deference to

decisions resolved through RTG dispute

resolution procedures.

In short, RTGs are still a valuable tool

in promoting wholesale competition

and in achieving other Commission

goals. RTGs are structures to reflect the

interests of all of the grid’s users, not

just some. RTGs allow for consensual

solutions to local or regional issues,

instead of solutions imposed by FERC.

RTGs can function as regional

laboratories for experimentation on

transmission issues. And, RTGs will

provide a regional forum, a necessary

predicate to regional cooperation. The

potential benefits of RTGs would in no

way be undermined by the rules

proposed in this Open Access NOPR.

F. Stranded Costs and Other Transition

Costs

1. Supplemental Notice of Proposed

Rulemaking on Stranded Costs by

Public Utilities and Transmitting

Utilities

a. Introduction. The Commission’s

Open Access NOPR would impose

significant new requirements on public

utilities—requirements that would help

us to achieve the goal of robust

competitive wholesale power markets,

and that would result in a new way of

doing business for utilities. The Open

Access NOPR would give a utility’s

historical wholesale customers

enhanced opportunities to reach new

suppliers and, therefore, would affect

the way in which utilities traditionally

have recovered costs. We believe it is

essential to address the transition issues

associated with the move toward

competition responsibly. The most

significant of these issues is stranded

cost recovery.

The recovery of legitimate and

verifiable stranded costs is critical to the

successful transition of the electric

utility industry from a tightly regulated,

cost-of-service industry to an open
17690 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

215Many also have committed millions of dollars

to purchase power under long-term power supply

contracts.

216See AGD, supra note 9, 824 F.2d at 1021–30.

However, our mechanisms for addressing stranded

costs in the electric industry differ from those used

in the gas industry for the reasons discussed below.

217See supra note 5.

218 If we were not issuing the Open Access NOPR,

we would be inclined to adopt a final rule on

stranded costs at this time. However, we are

concerned that the Stranded Cost NOPR might not

provide appropriate mechanisms to address

transition costs that could result from the open

access environment envisioned by this NOPR.

Accordingly, our findings here are interlocutory in

nature, and rehearing does not lie.

219A list of commenters is attached as Appendix

D.

220As discussed infra, section III.F.1.c(13),

however, this does not foreclose case-specific

proposals for dealing with stranded costs in the

context of voluntary corporate restructuring

proceedings.

221For recovery of wholesale stranded costs, the

proposed rule distinguishes between stranded costs

associated with wholesale requirements contracts

executed after July 11, 1994, the date the proposed

rule was published in the Federal Register (‘‘new’’

contracts) and stranded costs associated with

wholesale requirements contracts executed on or

before that date (‘‘existing’’ contracts). Stranded

Cost NOPR at 32,860.

222As we indicated in the Stranded Cost NOPR,

if the seller under a new wholesale requirements

contract is a transmitting utility subject to the

Commission’s jurisdiction under section 211 of the

FPA, but not also a public utility subject to the

Commission’s section 205–206 jurisdiction, there

will be no Commission forum for addressing

wholesale stranded costs associated with the new

contract. Such utilities will not be able to seek

recovery of wholesale stranded costs associated

with such new contracts through rates for

transmission services ordered under section 211,

and the Commission does not have jurisdiction over

their power sales contracts. Therefore, these

utilities must address recovery of stranded costs

through their new wholesale requirements contracts

subject to the appropriate regulatory authority

approval. Stranded Cost NOPR at 32,860–61.

223Existing wholesale power sales contracts are

those contracts executed on or before July 11, 1994.

Stranded Cost NOPR at 32,860, 32,881.

224 If the selling utility under the existing contract

is a transmitting utility that is not also a public

utility, its wholesale requirements contracts are not

transmission access, competitively

priced industry. Public utilities have

invested billions of dollars in facilities

built under a regulatory regime in which

they have been permitted to recover all

prudently incurred costs, plus the

opportunity to earn a reasonable rate of

return on their investment. 215 At the

wholesale level (and in some instances

the retail level), they are now entering

a regulatory era in which they will have

to compete to supply electric service.

We believe that utilities should be

allowed to recover the costs incurred

under the old regulatory regime

according to the expectations of cost

recovery established under that regime.

The primary goal of the Open Access

NOPR is to promote competitive

wholesale markets by assuring that all

wholesale sellers of generation have the

opportunity to compete on a fair basis

and that all wholesale purchasers can

reach alternative sellers. Ultimately, this

should result in lowering electricity

prices for the Nation’s consumers. In the

meantime, however, if a wholesale

customer is able to leave its existing

generation supplier to shop for power

elsewhere, we do not believe the

existing supplier’s shareholders or its

remaining customers should have to

bear costs that were prudently incurred

under the old regulatory system to serve

the departing customer.

We cannot successfully and fairly

encourage the development of

competitive wholesale markets as

envisioned by the Open Access NOPR

until we have made provision for

electricity suppliers to seek recovery of

existing uneconomic costs (primarily

generation) which they already have

incurred (i.e., those that could not earn

a reasonable return in a competitive

market). Recovery of legitimate and

verifiable transition costs will permit all

sellers, including the utilities who

prudently incurred these costs, to

compete on a more equal footing in

competitive bulk power markets. In

addition, while stranded cost recovery

may delay some of the benefits of

competitive bulk power markets for

some customers, the Commission

learned from its experience in the

restructuring of the natural gas industry

that these types of transition costs must

be addressed at an early stage if we are

to fulfill our regulatory responsibilities

in moving to competitive markets. 216

The Commission believes that the

approach proposed in the Stranded Cost

NOPR issued on June 29, 1994 217

should adequately cover most, if not all,

costs that could be stranded in an

environment where transmission access

is more widely available, including the

access environment that the

Commission expects if the provisions of

the Open Access NOPR are adopted.

Some of the mechanisms proposed in

the initial NOPR have been revised in

this Supplemental NOPR to reflect

submitted comments. In addition, there

may be implementation or other issues

raised by the open access requirements

that were not contemplated when the

Stranded Cost NOPR was originally

proposed. Accordingly, we are issuing a

Supplemental Notice of Proposed

Rulemaking on Stranded Costs. In this

Supplemental NOPR, we make

preliminary determinations 218 on

certain issues and seek additional

comments limited to the new matters

proposed in this document, including

the proposed open access requirements.

We also propose to permit public

utilities and transmitting utilities to

seek recovery through transmission

rates of stranded costs associated with a

discrete set of existing wholesale

requirements contracts.

b. Summary of Major Preliminary

Determinations. In response to the June

29 Stranded Cost NOPR, the

Commission received initial and/or

reply comments from 128 entities,

representing a broad cross-section of

parties that participate in, or are affected

by, the electric utility industry.219 The

Commission has carefully reviewed all

of the comments, and made several

preliminary determinations. First, we

have determined that recovery of

legitimate and verifiable stranded costs

should be allowed, and that direct

assignment of stranded costs to

departing customers, as proposed in the

Stranded Cost NOPR, is the appropriate

method for recovery.220

Second, with respect to stranded costs

associated with new wholesale

requirements contracts, 221 we reaffirm

our proposal that a public utility may

not seek recovery of such costs except

in accordance with an exit fee or other

explicit provision contained in the

contract. The public utility may seek

recovery in accordance with the

contract. However, no public utility or

transmitting utility may seek recovery of

stranded costs associated with new

requirements contracts through any

transmission rate under section 205, 206

or 211.222

Third, with respect to stranded costs

associated with existing wholesale

requirements contracts 223 that are not

renewed and that do not contain exit

fees or other stranded cost provisions, if

the seller can demonstrate that it had a

reasonable expectation that the contract

would be renewed and can meet other

evidentiary criteria, we believe that

stranded cost recovery should be

allowed. We encourage the parties to

such contracts to attempt to negotiate a

mutually agreeable stranded cost

amendment. We have determined,

however, that the three-year negotiation

period proposed in the initial Stranded

Cost NOPR should be abandoned. We

propose instead that: (1) A public utility

or its customer under the contract may,

at any time prior to the expiration of the

contract, file a proposed stranded cost

amendment to the contract under

section 205 or section 206; or (2) a

public utility may, at any time prior to

the expiration of the contract, file a

proposal to recover stranded costs

through transmission rates for a

departing customer.224 We believe it is
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17691

subject to this Commission’s jurisdiction.

Nevertheless, we do encourage such a transmitting

utility to attempt to negotiate a mutually agreeable

stranded cost amendment with its customer. In

addition, we will allow such a transmitting utility

to file a request to recover stranded costs in

transmission rates under FPA sections 211–212.

However, such transmitting utility would be

required to make the same evidentiary

demonstration as that required of public utilities

seeking extra-contractual stranded cost recovery.

225The customer’s maximum possible stranded

cost exposure without mitigation would be the

revenues that the utility would have received from

the customer had the customer continued to take

service from the utility. This is the amount from

which the competitive market value of the power

that the customer would have purchased would be

deducted to compute the amount of recoverable

stranded costs (using the ‘‘revenues lost’’ approach

for calculating stranded costs that this rule proposes

to adopt (see section III.F.1.c(8) infra)). The utility

will be required to make every effort to mitigate the

amount of the stranded cost charge. See section

III.F.1.c(9).

226Although the Commission’s June 29 NOPR

characterized these types of stranded costs as

‘‘retail’’ stranded costs, we believe they are more

appropriately characterized as ‘‘wholesale’’

stranded costs, since it is not only state or local

authority that permits the costs to be stranded, but

also the availability of wholesale transmission that

causes the costs to be stranded.

227See 16 U.S.C. § 824(c).

228We do not address whether states have the

lawful authority to order retail wheeling in

interstate commerce.

229 16 U.S.C. 824(b).

230States may also use their jurisdiction over

local distribution facilities to address potential

‘‘stranded benefits,’’ e.g., environmental benefits

associated with conservation, load management,

and other demand side management (DSM)

programs. See NARUC Resolution on Competition,

the Public Interest, and Potentially Stranded

Benefits, November 16, 1994 (Appendix C to

NARUC’s comments).

231Electric Generation Association comments at

1.

in the public interest to permit public

utilities to seek recovery of stranded

costs associated with existing contracts

that do not explicitly address stranded

costs, and that they be permitted to do

so either through transmission rates or

through amendment to the existing

power sales contracts. However, for a

utility to be eligible for stranded cost

recovery, it must meet the evidentiary

demonstration required by this rule.

In examining proposals to recover

stranded costs, we propose to apply a

‘‘reasonable expectation’’ standard and a

rebuttable presumption that if contracts

contain notice provisions, the utility

had no reasonable expectation of

continuing to serve the customer

beyond the term of the notice provision.

We further propose to retain the

requirement in the initial Stranded Cost

NOPR that utilities attempt to mitigate

stranded costs. In addition, we are

proposing that public utilities be

required to follow certain procedures

specified herein that permit a customer

to obtain advance notice of its

maximum possible stranded cost

exposure without mitigation.225

Fourth, with respect to costs stranded

as a result of retail wheeling, or as a

result of wholesale wheeling obtained

by a retail-turned-wholesale customer,

the Stranded Cost NOPR explored the

issue of whether we should assume

some responsibility for addressing such

costs. The vast majority of those

commenting on our proposed rule urged

us not to get involved or otherwise

assume responsibility for those types of

stranded costs, except in certain very

limited circumstances. At this juncture,

we have concluded that it is appropriate

to leave it to state regulatory authorities

to assume the responsibility for any

stranded costs occasioned by retail

wheeling, except in the narrow

circumstance in which the state

regulatory authority does not have

authority under state law, at the time

retail wheeling is required, to address

recovery of such costs. The Commission

holds the strong expectation that states

will provide procedures for, and the full

recovery of, legitimate and verifiable

stranded costs.

We also have determined that this

Commission should be the primary

forum for public utilities to seek

recovery, through FERC jurisdictional

transmission rates, of stranded costs

resulting from wholesale wheeling for

newly created wholesale customers who

leave their franchised utility’s supply

system (e.g., through

municipalization).226

In deciding that states are the more

appropriate entities to address stranded

costs resulting from retail wheeling, we

are relying on assurances from our state

colleagues, as evidenced, for example,

in NARUC’s comments on the proposed

rule, that they will address and resolve

this difficult issue. We continue to be of

the opinion that utilities are entitled,

from both a legal and policy

perspective, to an opportunity to

recover their past prudently incurred

costs, including costs incurred to serve

retail customers who obtain retail

wheeling in interstate commerce. We

emphasize that we will not allow states

to use rates for transmission in interstate

commerce as the vehicle for passing

through any stranded costs resulting

from retail wheeling, except in the

narrow circumstance described. Thus,

these costs must be recovered in rates in

a manner that does not involve

‘‘transmission of electric energy in

interstate commerce’’ as that phrase is

used in the FPA.227 This approach

ensures that the wholesale market will

not be burdened by retail costs. It also

ensures that one state will not be able

to place costs stranded by its ordering

of retail wheeling228 on customers in

another state.

As discussed infra, we believe the

states have a number of mechanisms to

provide for recovery of retail stranded

costs in retail rates. One of those

mechanisms is a surcharge to statejurisdictional rates for local distribution.

Accordingly, we are proposing to define

‘‘facilities used in local distribution’’

under section 201(b) of the FPA.229 We

believe states may impose retail

stranded costs on facilities or services

falling under this definition.230

We set out our preliminary findings

here for the limited purpose of

reopening the comment period of the

Stranded Cost NOPR as to whether the

requirements proposed in the Open

Access NOPR raise additional

implementation or other issues

pertaining to stranded cost recovery that

were not addressed in the initial

Stranded Cost NOPR and, if so, whether

the mechanisms we propose based on

our preliminary determinations are

adequate to allow recovery of stranded

costs. Additional issues on which we

seek comment are delineated below.

c. The Proposed Regulations. (1)

Justification for Allowing Recovery of

Stranded Costs and Estimates of the

Magnitude of Stranded Costs. (a)

Comments

Virtually all of the investor-owned

utility commenters support the NOPR’s

basic assumption that stranded costs

can be created when a customer

switches suppliers. Many commenters,

including Electric Generation

Association and Public Power Council,

applaud the Commission for timely

‘‘addressing the difficult and

controversial stranded cost issue and for

recognizing that this issue must be

resolved in order for all parties to

harvest fully the benefits of a

competitive electric industry.’’ 231

Edison Electric Institute (EEI) strongly

endorses the recovery of stranded costs.

A number of commenters, primarily

representing customer groups, disagree

that the risk that a utility could lose

customers (and thereby incur stranded

costs) is a new phenomenon created by

regulatory and statutory initiatives that

utilities could not anticipate. These

commenters argue that utilities have

long been aware that they risk losing

customers to competition and that

utilities should have planned for this

eventuality.

In support of this argument, American

Forest and Paper Association (American

Forest) and others argue that utilities

have known for some time that

wholesale customers can—and in the
17692 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

232E.g., American Power Association (APPA),

Florida Municipal Power Agency, Michigan

Municipal Cooperative Group and Wolverine Power

Supply Cooperative (Florida and Michigan

Municipals), the Illinois Commerce Commission

(Illinois Commission), Electricity Consumers

Resource Council, the American Iron and Steel

Institute an the Chemical Manufacturers

Association (Industrial Consumers), and TDU

Customers.

233See Otter Tail, supra note 15.

234 Village of Elbow Lake v. Otter Tail Power

Company, 40 FPC 1262 (1968).

235 Kentucky Utilities Co., Opinion No. 169, 23

FERC § 61,317, aff’d on reh’g in relevant part, 25

FERC § 61.205 (1983), reversed on other grounds,

766 F.2d 239 (6th Cir. 1985).

236E.g., American Forest, Industrial Consumers,

the Municipal Resale Service Customers of Ohio,

and the Stranded Cost Order Opponent Parties

(SCOOP). SCOOP consists of Delaware Municipal

Electric Corporation, Village of Freeport, New York,

City of Jamestown, New York, Town of Massena,

New York, Modesto Irrigation District, M–S–R

Public Power Agency, City of Santa Clara,

California, and Southern Maryland Electric

Cooperative, Inc. 237SCOOP comments at 2.

238For example, a number of utilities (e.g.,

Allegheny Power Service Corporation (Allegheny

Power), Consumers Power Company, and

Wisconsin Power & Light Company (Wisconsin

Power)) indicate that their total potential wholesale

exposure is minimal.

239As discussed in section III.C.2 supra, new

generation facilities can produce power on the grid

at a cost of 3 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 per kWh

for nuclear plants.

240The Commission has never determined

whether there is an actual obligation in the FPA to

serve requirements customers. Construction Work

In Progress, Order No. 474, III FERC Stats. & Regs.

¶ 30,751 at 30,718 (1987). The Commission’s

regulations, however, do require a rate filing to

terminate a jurisdictional contract. 18 C.F.R. § 35.15

(1994). Moreover, in a few cases, the Commission

has required service beyond the contract term. E.g.,

general course of business, in fact, do—

leave utilities’ systems for other

suppliers without being obligated to pay

for stranded costs. Several commenters

also argue that Congress put the

industry on notice through PURPA and

then EPAct that utilities are at risk of

losing customers as a result of the procompetitive provisions of these statutes.

Numerous parties232 note that the courts

and the Commission have, in various

cases, provided notice that, as a result

of competitive forces in the industry,

utilities have had no reasonable

expectation that customers will remain

on their systems after contract

expiration. Commenters cite, among

other cases, the Supreme Court’s 1973

decision in Otter Tail233 (in which the

Court held that the refusal to wheel

power could place a utility at risk of

antitrust liability), the Commission’s

1968 decision in Village of Elbow Lake

v. Otter Tail Power Company234 (in

which utilities were alerted to the threat

of municipalization), and the

Commission’s 1983 decision in

Kentucky Utilities Co.235 (in which a

notice of termination provision was

deemed to constitute the extent of the

utility’s protection of its investment

incurred to support the contract

service).

Some commenters 236 argue that the

Stranded Cost NOPR incorrectly

assumes the existence of a wholesale

service obligation. These commenters

argue that the NOPR improperly

assumes that a utility has had an

obligation to serve a wholesale

requirements customer beyond the term

set forth in the contract unless the

contract contained a notice of

termination provision or other more

explicit stranded cost provisions.

According to these commenters, the

wholesale service obligation is purely

contractual, and utilities could not

reasonably have expected to continue to

provide service after the expiration of a

particular contract.

Some state commissions (e.g., Illinois

Commission) also find the NOPR’s

notion of wholesale stranded costs to be

misplaced. These state commission

commenters note that competition and

notice provisions have existed for

decades and that a customer leaving the

system for another supplier is no

different from a customer leaving due to

an economic downturn (e.g., a plant

closing or relocation). Under the latter

circumstance, they note that the costs

are allocated among the remaining

customers, or, in some instances,

shareholders. A number of other state

commissions (e.g., Indiana Utility

Regulatory Commission (Indiana

Commission)) urge that stranded cost

recovery exclude costs associated with

normal business risk, such as poor

planning, customer relocation, selfgeneration, or cogeneration.

With regard to the magnitude of the

level of total industry stranded costs,

while estimates vary widely, most

commenters agree that the level of

potential wholesale stranded costs is

small relative to that of retail stranded

costs. Several state commissions and

customer groups (e.g., Florida Public

Service Commission (Florida

Commission), APPA, Industrial

Consumers, Illinois Commission, and

SCOOP) argue that the potential level of

wholesale stranded costs is largely

exaggerated. For example, SCOOP

claims that ‘‘[s]eparating out only the

wholesale exposure to stranded costs,

and critically analyzing the extent of

that exposure, will permit the

Commission to recognize that wholesale

stranded costs are little more than the

‘flea on the tail of the dog’ and not the

dog itself.’’ 237 Many of these

commenters, including the Illinois

Commission, note that wholesale

stranded costs are likely to be minimal

because wholesale requirements sales

for major investor-owned utilities

account for roughly 6 percent of their

total net energy generated and received.

Furthermore, these commenters contend

that it is ridiculous to suggest that all of

the generation assets associated with

serving this wholesale load suddenly

would become stranded. In fact, some

commenters expect the investor-owned

utilities with lower-cost generation to

benefit from increased competition.

Additionally, the Environmental

Action Foundation (Environmental

Action) notes that some industry

estimates assume a zero asset (or

salvage) value for any stranded assets.

Environmental Action claims that this

assumption grossly overestimates the

claimed industry level of stranded costs

by failing to recognize that a utility with

a stranded generating asset will likely

lower its power prices to market levels

to mitigate the total level of stranded

costs. Accordingly, Environmental

Action suggests that estimated levels of

potential wholesale stranded costs may,

in fact, be lower after accounting for

costs recovered by the utility as a result

of aggressively marketing any stranded

generating assets.

EEI indicates that, based on an

informal survey of its members, the

number of cases likely to be filed at the

Commission seeking to recover stranded

costs from wholesale requirements

customers under existing contracts will

be far less than those filed during

restructuring of the natural gas pipeline

industry.238 However, EEI states that,

while the number of filings may be

relatively small, the dollar amounts and

the significance to the parties are great.

EEI indicates that the magnitude of

potential wholesale and retail stranded

cost liability to the industry is in the

upper range of the NOPR’s tens of

billions of dollars to $200 billion

estimate.

(b) Preliminary Findings. The electric

utility industry has billions of dollars

invested in utility assets and contracts

that, in today’s markets, may become

uneconomic. 239 If wholesale or retail

customers leave their utilities’ systems

without paying a share of these costs,

the costs will become stranded unless

they can be recovered either from the

departing customers or other customers.

These are very real costs that, as

previously discussed, were incurred

under a regulatory system that imposed

an obligation to serve on utilities (an

explicit obligation at retail and arguably

an implicit obligation at wholesale) 240
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Tapoco, Inc., et al., 39 FERC ¶ 61,363 (1987);

Florida Power & Light Company, 8 FERC ¶ 61,121,

reh’g denied, 9 FERC ¶ 61,015 (1979)).

241The costs of gas supply contracts in the gas

industry can be viewed as somewhat analogous to

the costs of generation resources in the electric

industry.

242Order No. 436, supra note 12 at 31,492–93; see

also AGD, supra note 9, 824 F.2d at 1026.

243 824 F.2d at 1027.

244 Id. at 1021.

245Cajun Electric Power Cooperative, Inc. v.

FERC, 28 F.3d 173 (D.C. Cir. 1994) (Cajun).

246The two other electric power tariffs under

review in that case provided for the sale of

wholesale power by various Entergy public utility

subsidiaries at negotiated, market-based rates. As

the court indicated, these tariffs, in combination

with the open access transmission tariff, ‘‘were

designed to permit Entergy—a monopolist of

transmission services in the relevant market—to

engage in market-based pricing in the generation

market, while simultaneously introducing

competition to that market through the unbundling

of generation sales from transmission services.’’ Id.

at 175.

247 Id. at 178.

248The court noted that although the Commission

suggested that the stranded investment provision is

necessary to lure Entergy into competition and

provides an equitable recovery of costs from the

parties for whom the costs were incurred, this is

irrelevant if the Entergy tariffs do not sufficiently

mitigate Entergy’s market power. Id. at 180.

249 Id.

250 Id. at 179 (emphasis in original).

and also permits recovery of all

prudently incurred costs. Moreover,

while we recognize that there has

always been some risk of a utility losing

a customer, that risk has been greatly

increased by significant statutory,

regulatory, technological, and structural

changes, including this rule, that

utilities may not have reasonably

foreseen at the time their investments

were made.

As discussed in the introduction of

this document, the wholesale bulk

power segment of the electric industry

is undergoing a fundamental

transformation from a monopolistic

industry regulated on a cost-of-service

basis to an open access, competitively

priced industry. The transformation will

accelerate if the Commission adopts the

open access transmission requirements

it is proposing in Docket No. RM95–8–

000. We do not believe that utilities that

made large capital expenditures or longterm contractual commitments to buy

power many years ago should now be

held responsible for failing to foresee

such fundamental changes in the

industry. The Commission will not

ignore the effects of regulatory and

statutory changes on the past

investment decisions of utilities. We

believe that equity requires that utilities

have an opportunity to recover

legitimate and verifiable stranded costs

associated with the development of

competitive wholesale markets.

This belief is bolstered by our

experience during the restructuring of

the natural gas industry. During the

1980s and early 1990s, the Commission

undertook a series of actions that

eventually led to the restructuring of the

gas pipeline industry. The restructuring

of the industry and the introduction of

competitive forces in the gas supply

market left many pipelines holding

uneconomic take-or-pay contracts with

gas producers.241

In Order No. 436, the Commission

declined to take direct action to

alleviate the burden that the

uneconomic take-or-pay contracts

placed on pipelines. The Commission

based its decision on a number of

considerations, including its concern

‘‘regarding the ability of private parties

in the gas production industry to rely on

private contracts as a tool for structuring

basic economic relationships.’’ 242

However, in AGD, the U.S. Court of

Appeals for the District of Columbia

Circuit noted that the pipelines were

‘‘caught in an unusual transition’’ as a

result of regulatory changes beyond the

pipelines’ control.243 The court faulted

the Commission for failing to take direct

action to address the effect of such

regulatory changes on the uneconomic

take-or-pay contracts.244

The court’s reasoning in AGD

concerning the restructuring of the gas

industry is also applicable to the current

move to competitive bulk power

markets in the electric industry. Once

again, a regulated industry is faced with

an ‘‘unusual transition’’ to a more

competitive market. Once again, one

result of the transition is the possibility

that utilities will be left with large

unrecoverable costs. In these

circumstances, we believe that we must

directly address the costs of the

transition to a competitive industry by

allowing utilities to recover their

legitimate and verifiable stranded costs,

and that we must do so simultaneously

with any final rule we adopt concerning

open access transmission.

(2) The D.C. Circuit Court of Appeals

Decision in Cajun Electric Power

Cooperative, Inc. v. FERC. In the Cajun

case,245 the D.C. Circuit found that the

Commission should have held an

evidentiary hearing to determine

whether the recovery of stranded

investment costs, as permitted in an

open access transmission tariff

approved by the Commission, was

anticompetitive and would preclude

mitigation of Entergy Corporation’s

(Entergy) market power. The

transmission tariff under review in that

case was intended to mitigate Entergy’s

market power by providing open access

to its transmission system.246 The open

access transmission tariff provided that

Entergy’s subsidiaries could seek to

recover their stranded investments from

a departing generation customer by

including in the departing customer’s

transmission rate the cost of Entergy’s

generation capacity that was stranded

when the former customer switched

suppliers. The court expressed concern

that this provision might constitute a

tying arrangement whose purpose is to

‘‘cabin’’ Entergy’s market power, stating:

‘‘If a company can charge a former

customer for the fixed costs of its

product whether or not the customer

wants that product, and can tie this cost

to the delivery of a bottleneck monopoly

product that the customer must

purchase, the products are as effectively

tied as they would be in a traditional

tying arrangement.’’ 247

The court noted that central to the

Commission’s approval of Entergy’s

open access transmission tariff was the

Commission’s finding that Entergy’s

market power would be mitigated upon

the implementation of the tariff. 248

However, the court suggested that

permitting a transmission monopolist

such as Entergy to impose generationrelated charges on competitors who only

seek transmission services might serve

to increase, not mitigate, Entergy’s

market power because ‘‘Entergy can

compete for generation sales outside its

transmission grid without concern for a

stranded investment charge [but]

Entergy’s competitors cannot compete

for the customers on its transmission

system on the same basis.’’ 249 Thus, the

court held that ‘‘[t]he Commission must

address whether the [transmission

tariff’s] provision of a process for

recovery of stranded investment costs

* * * precludes genuine open access to

Entergy’s transmission system. In short,

the question that must be asked now is

whether the [transmission tariff] allows

for ‘meaningful access to alternative

suppliers.’ ’’ 250 The court went on to

identify other provisions of the

transmission tariff (in addition to the

stranded cost provision) that might

lessen the mitigation of Entergy’s market

power, including Entergy’s retention of

sole discretion to determine the amount

of transmission capability available for

its competitors’ use; the point-to-point

service limitation; the failure to impose

reasonable time limits on Entergy’s

response to requests for transmission

service; and Entergy’s reservation of the

right to cancel service in certain

instances even where a customer has
17694 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

251 Id. at 179–80.

252 Id. at 180.

253Blue Ridge consists of Blue Ridge Power

Agency, Northeast Texas Electric Cooperative, Sam

Rayburn G & T Electric Cooperative and Tex-La

Electric Cooperative.

254Environmental Action comments at 79.

255Wisconsin Power argues that stranded costs

should be recovered, but not through transmission

rates.

256The Coalition for Economic Competition

consists of the following New York investor-owned

utilities: Central Hudson Gas & Electric

Corporation, Consolidated Edison Company of New

York, Long Island Lighting Company, New York

State Electric & Gas Corporation, Niagara Mohawk

paid for transmission system

modifications.251

The court concluded that the

transmission tariff as a whole ‘‘seems to

provide Entergy with the means to stifle

the very competition it purports to

create.’’ 252 The court determined that

the Commission erred in approving

Entergy’s tariffs without conducting

hearings on whether, notwithstanding

the purpose of the transmission tariff to

mitigate market power, Entergy might

retain market power. Significantly,

however, the court did not hold that

stranded cost recovery could not be

justified; its objection was to the

Commission’s procedures in that

particular case and lack of explanation

for its substantive decision to approve

the stranded cost provision.

(a) Comments. Most customer groups

and many state representatives (e.g.,

APPA, Blue Ridge,253 National

Association of Regulatory Utility

Commissioners (NARUC) and the

Vermont Department of Public Service

(Vermont Department)) contend that the

Cajun decision either prevents the

Commission from allowing the recovery

of stranded costs through transmission

charges, or, at best, raises questions

concerning the scope of the

Commission’s legal authority to do so.

In light of Cajun, some commenters,

such as the National Rural Electric

Cooperative Association (NRECA), urge

the Commission to terminate the NOPR.

Environmental Action contends that a

transmission adder does not by itself

constitute tying or leveraging. It submits

that if the transmission adder consists of

costs that a customer is obligated to pay

in any event, the adder merely holds the

customer to its existing bargain.

Environmental Action argues that in

Cajun, however, the transmission adder

was not being used to recover costs for

which the transmission customer was

already obligated, but had the effect of

penalizing the customer for entering

into a new obligation. According to

Environmental Action, the NOPR

‘‘makes the same error’’ to the extent

that the costs proposed to be recovered

in the transmission adder are not part of

the contractual quid pro quo.254

All of the investor-owned utility

commenters, except Wisconsin Power &

Light Company (Wisconsin Power),

argue that the Cajun decision is not a

bar to recovery of stranded costs

through transmission rates.255 These

commenters (e.g., EEI and Duke) argue

that the Cajun decision was based on

procedural grounds and merely stands

for the proposition that the Commission

should have held an evidentiary hearing

in that case to resolve anticompetitive

concerns. These commenters also argue

that the portion of the Cajun decision

relied on by the customer commenters

is only dictum.

Some commenters further contend

that allowing the recovery of stranded

costs through a transmission surcharge

does not constitute an unlawful tying

arrangement. EEI notes, as an initial

matter, that the courts no longer view

every bundling of products or services

as a tying arrangement that is per se

unlawful under the antitrust laws.

Moreover, EEI submits that in a tie-in,

a seller of one product requires its

purchasers to buy the tied product by

bundling the products together to

promote sales in related markets that it

could not achieve under competitive

circumstances, effectively foreclosing

the purchaser from obtaining the second

product from competitors even if it

could do so at a lower cost. EEI argues

that a stranded cost surcharge, in

contrast, would include only part of the

former price of the power (the mark-up

above its marginal cost included in the

price approved by regulators), and

would thereby allow the purchaser to

obtain bulk power from competitive

suppliers with the lowest marginal

costs.

With regard to the potential

anticompetitive effects of allowing

stranded cost recovery, some

commenters contend that stranded cost

recovery would inhibit the movement

toward competition, distort price

signals, result in inefficient

decisionmaking, and unfairly reward

the least efficient utilities.

For example, APPA argues that

charges for stranded costs are

anticompetitive and hinder the

development of a competitive market

by, among other things: (1) Distorting

transmission prices and erecting

artificial barriers to new suppliers; (2)

giving the host utility a paid-off asset

with which to compete unfairly; and (3)

slowing the introduction of new

technology. APPA argues that the

disallowance of stranded costs would

encourage all utilities to strive for

greater efficiencies and to compete for

sales on the basis of price and service.

The Ad Hoc Coalition on

Environmental and Consumer

Protection (Ad Hoc Coalition) argues

that stranded cost recovery will amount

to a government-ordered subsidy for

electric generation from older, less

efficient units that will further

environmental degradation and stifle

the move toward greater competition. It

claims that the stranded costs that

utilities primarily will be seeking to

recover are uneconomical nuclear

generation assets, and that the NOPR

thus offers a new subsidy for nuclear

power by shifting cost responsibility for

nuclear assets from shareholders to

ratepayers. The Ad Hoc Coalition

believes that such a subsidy could affect

investment decisions for the next

generation of nuclear power plants if

investors believe that they will be

allowed to recover their costs as long as

a ‘‘reasonable expectation’’ existed at

the time the decision to build was made.

Thus, the Ad Hoc Coalition argues that

the NOPR will send an improper signal

to utility managers and investors that

generation investments remain safe

investments, even when they do not

pass the tests of a competitive market.

According to the Ad Hoc Coalition, such

a policy perpetuates the continued

reliance on older, less efficient

generating units that harm the

environment.

American Forest asserts that blanket

assurances of stranded cost recovery are

anticompetitive and create no incentive

for utilities to lower their operating

costs and mitigate any uneconomic

costs. According to American Forest,

stranded costs create enormous

uncertainty that may make financing of

competitors’ plants impossible at any

cost, thus killing the very competitive

market the Commission seeks to foster.

The Illinois Commission believes that

stranded cost recovery produces an

incorrect competitive result because

such action effectively ‘‘props up’’ the

least efficient (high-cost and high-price)

utilities. The Illinois Commission argues

that stranded cost recovery mechanisms

effectively punish the more efficient

suppliers that have paid attention to

changing realities and have assumed a

more competitive market-sensitive

posture.

In sharp contrast to the commenters

that argue stranded cost recovery would

hinder competition, commenters such

as EEI, the United States Department of

Energy (DOE), the Coalition for

Economic Competition,256 and the
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17695

Power Corporation, and Rochester Gas & Electric

Company.

257CLF is a non-profit environmental law

organization that represents approximately 10,000

members in the six New England states.

258The Competitive Working Group consists of

Electric Clearinghouse, Inc., Enron Power

Marketing, Inc., and Destec Power Services, Inc.

259See Cajun, 28 F.3d at 179.

260 In seeking comment in the Open Access NOPR

on the adequacy of these terms and conditions, we

seek specific comment on the terms and conditions

that were of concern to the Cajun court. See

discussion supra Section III.E.4. For example, the

Cajun court expressed concern that the point-topoint service limitation in Entergy’s transmission

tariff might restrain competition. However, under

the Open Access NOPR, service will not be limited

to point-to-point. Instead, customers will be

allowed to choose between point-to-point and

network service.

261There is a wide disparity in consumer

electricity prices across the United States. Some

consumers pay more than 10 cents per kilowatthour on average, while others pay about one-third

as much. While some of this price disparity is due

to regional cost differentials, some of it may also be

due to ineffective access to new power supplies. We

believe that all consumers will benefit from changes

that allow their suppliers greater access to lowercost power supplies. This greater access can best be

achieved by ensuring that non-discriminatory open

access transmission service is available to all

potential users of the transmission grid. The result

will be greater trading opportunities among

suppliers, and also more investment opportunities

for new entrants in generating markets. All of this

should serve the interests of consumers by lowering

electricity prices.

262Cajun, 28 F.3d at 177–78.

Conservation Law Foundation (CLF) 257

contend that stranded cost recovery can

promote a quicker transition to

competition and can be used to enhance

efficiency. Some commenters (e.g., DOE,

Industrial Consumers, Enron Power

Marketing, Inc. (Enron), CLF, and the

Competitive Electric Market Working

Group (Competitive Working Group) 258)

suggest linking the recovery of stranded

costs to utility actions that will further

wholesale competition, such as the

filing of an open access transmission

tariff or membership in a regional

transmission group (RTG).

Commenters representing the

financial community (e.g., Utility

Investors and Analysts, American

Society of Utility Investors, United

Utility Shareholders Association of

America) strongly support recovery of

stranded costs so that the financial

stability of the electric utility industry

will be protected. These commenters

argue that the amount of potential

stranded costs exceeds the amount of

equity investment in electric utilities.

According to these commenters,

investors have not made their current

investment decisions with the rigors of

competition in mind, nor have rate of

return hearings included testimony

concerning competitive risk. Without

full recovery of stranded costs, financial

community commenters argue, financial

integrity will deteriorate, and utilities

will be unable to attract capital. Due to

the capital-intensive nature of the

electric utility industry, these

commenters note that lack of access to

capital markets at reasonable rates will

prevent utilities from keeping costs

down.

(b) Preliminary Findings. We do not

interpret the Cajun court decision as

barring the recovery of stranded costs.

Rather, the Cajun court remanded the

case because the Commission failed to

hold an evidentiary hearing concerning

whether the inclusion of a stranded cost

recovery provision in Entergy’s

transmission tariff precluded the

mitigation of Entergy’s market power.

As previously discussed, the court also

found the Commission’s substantive

decision flawed because the

Commission failed to explain

adequately its approval of the stranded

cost provision, among others. In this

consolidated proceeding (i.e., the

Stranded Cost NOPR, the Supplemental

Stranded Cost NOPR, and the Open

Access NOPR), we are providing the

evidentiary record for addressing all of

the court’s concerns on a generic basis,

and the opportunity for all participants

in the electric industry to present

evidence and arguments. We are also

providing a full explanation of why the

recovery of legitimate stranded costs is

critical to the successful transition of

the electric utility industry from a

tightly regulated, cost-of-service

industry to an open transmission access,

competitive industry that will drive

down the prices of electricity to

consumers.

The court in Cajun was concerned

about whether Entergy’s tariff allowed

‘‘meaningful’’ access to alternative

suppliers. In this regard, the court stated

that the Commission must address not

only whether the stranded cost

provision allowed for meaningful

access, but also whether other

provisions in the tariff might lessen the

utility’s market power. In the Open

Access NOPR, the Commission is

attempting to mitigate the core of market

power not only for Entergy, but for all

traditional public utilities: control over

transmission access. The Commission is

generically addressing all aspects of

transmission market power, including

those specifically identified by the

Cajun court (e.g., point-to-point service

limitations). Indeed, a fundamental

purpose of the Open Access NOPR is to

ensure the meaningful access to

alternative suppliers that was identified

by the Cajun court.259 The Open Access

NOPR includes the specific terms and

conditions of access (contained in the

pro-forma tariffs) that we believe are the

minimum necessary to mitigate

transmission market power.260 Of

utmost importance in mitigating market

power is the Commission’s nondiscrimination (comparability)

requirement, a requirement that had not

been articulated at the time of the

Commission’s order under review in

Cajun, and that is proposed to be

codified in the Open Access NOPR

proceeding.

With regard to the Cajun court’s

concern about stranded cost provisions,

the Commission in Entergy failed to

articulate the transition that the

industry is experiencing, the

fundamental fact that full competition is

not yet a reality, and that stranded costs

are a temporary but serious

phenomenon that must be addressed if

we are to successfully move from one

regulatory regime to another, thereby

creating fully competitive bulk power

markets. In this regard, the Open Access

NOPR provides a detailed explanation

of the fundamental industry and

regulatory changes that have given rise

to the potential for stranded costs. In

addition, in the Stranded Cost NOPR

and the Supplemental Stranded Cost

NOPR, we have gathered (and are

continuing to gather) information

concerning the magnitude of potential

stranded costs; we have provided an

explanation of the transitional nature of

stranded costs; and we have explained

the critical need to deal with these costs

in order to reach competitive wholesale

markets. We have also explained

existing disparities in electricity rates

and the consumer benefits that can

accrue if we achieve fully competitive

markets.261

Failure to deal with the stranded cost

problem would likely delay and would

certainly complicate the transition to

fully competitive bulk power markets.

For example, stranded costs would then

be borne by the utilities’ shareholders,

which could threaten the stability of the

industry and the service it provides, or

be reallocated to remaining customers,

raising the price to such customers. An

additional consideration is the fact that

the AGD court instructed the

Commission that it must consider the

transition costs borne by regulated

utilities when the Commission changes

the regulatory rules of the game.

We conclude that stranded cost

recovery as proposed in this rulemaking

is not a tying arrangement, as discussed

by the Cajun court, and that the

proposed cost recovery procedure will

not ‘‘cabin’’ market power.262 Rather,

the stranded cost recovery procedure is
17696 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

263Methods of direct assignment include a lump

sum payable when the customer leaves the system.

Such an exit fee could also be recovered over time

in monthly installments. Presumably the utility

would charge interest on the unamortized balance

if the customer selected a delayed payment

approach.

264Stranded Cost NOPR at 32,867–68.

265Some commenters (e.g., Allegheny Power)

distinguish between transmission surcharges

imposed on transmission-only customers as

opposed to all customers. In the former case, only

those customers taking transmission-only service

from the utility would be assessed stranded costs;

customers taking bundled service would not be

assessed such costs. Allegheny Power indicates that

it would support such an approach only if the

Commission decides not to fully assign stranded

costs to departing customers.

266SCOOP comments at 38 (citing Northern States

Power Company, Opinion No. 383, 64 FERC

¶ 61,324 at 63,377 (1993)).

267Trigen Energy Corporation advocates that

Congress impose a ‘‘sunset’’ energy tax on all

electricity used in order to pay off stranded costs.

268Because we are also proposing to entertain

requests for recovery of stranded costs attributable

to retail-turned-wholesale wheeling customers, or to

retail wheeling customers in certain limited

circumstances, our determinations and rationale

regarding direct assignment also apply to those

situations.

being prescribed to enable utilities,

during a transitional period, to recover

costs prudently incurred under a

different regulatory regime.

Finally, the financial community

argues strongly and plausibly that

recovery of legitimate and verifiable

stranded costs at this critical stage in the

industry’s move toward competition is

needed to protect the financial stability

of the electric industry. They confirm

that the prospect of not recovering

stranded costs could erode a utility’s

ability to attract capital, which, in turn,

could impede the long-term goal of

achieving competitive wholesale

markets.

(3) Responsibility for Wholesale

Stranded Costs (Whether to Adopt

Direct Assignment to Departing

Customers). In the initial NOPR, the

Commission proposed to allow utilities

to seek to assign stranded costs

associated with the departure of a given

wholesale customer directly to that

departing wholesale customer.263 We

noted, however, that an alternative

might be to assign stranded costs more

broadly by, for example, requiring all

transmission customers (including

native load which takes bundled

service) to pay a higher rate for use of

the transmission system. We invited

comments on the direct assignment and

alternative methods of stranded cost

recovery. 264

(a) Comments. Many parties

(representing all constituencies) support

the direct assignment of stranded costs

to the departing customer as proposed

in the initial NOPR. Most commenters

contend that the cost causation

principle supports this approach. These

parties argue that utilities undertake

obligations on a customer’s behalf and

that, by leaving the system, the

departing customer avoids paying for its

fair share of these obligations. They

further argue that general fairness

requires that customers remaining on

the system should not have to pay for

a departing customer’s obligations; they

allege that this could lead to more

customers leaving the system and the

eventual bankruptcy of the utility.

Nevertheless, other commenters

suggest a framework for stranded cost

recovery that is different from the direct

assignment method suggested in the

NOPR. According to some commenters

(e.g., South Carolina Electric & Gas

Company), stranded costs should be

allocated to all customers and

shareholders because everyone will

benefit from the transition to

competitive generation markets. In this

manner, they contend that the overall

burden would be reduced, because

stranded costs would be spread among

a greater number of parties. Commenters

that support spreading the costs to all

customers argue that requiring the

departing customer to shoulder all

stranded costs will result in few

customers going off-system due to the

economic inefficiency of paying two

suppliers. Several commenters (e.g.,

Indiana Commission, Rhode Island

Division of Public Utilities and Carriers,

Department of Water and Power of the

City of Los Angeles, and Fuel Managers

Association) suggest that some

shareholder liability for stranded cost

recovery should be required, arguing

that it would provide utilities with a

greater incentive to mitigate stranded

costs.

Some commenters support the

recovery of stranded costs through a

transmission surcharge applicable to all

transmission customers. 265

Other commenters oppose a general

surcharge on all transmission

customers, arguing that existing

transmission customers, including

native load, should not be allocated any

stranded costs because they did not

cause any costs to be stranded in the

first place. Washington Water Power

Company and Wisconsin Electric Power

Company oppose a transmission

surcharge on the basis that it makes an

otherwise competitive supplier less

marketable due to higher wheeling rates.

Others allege that a transmission

surcharge is inconsistent with the

unbundling of transmission service and

would slow the restructuring

(disaggregation) of vertically-integrated

utilities. Thus, according to some

commenters, the use of a transmission

surcharge would slow the move to

competitive markets because the

surcharge sends the wrong price signal,

involves cross-subsidization by native

load, penalizes competitive alternatives,

and awards monopoly rents to the

utility. Some commenters also note that,

where the departing customer does not

take transmission service from its

former supplier, the departing customer

escapes all responsibility for the

stranded costs.

Some commenters contend that the

Cajun decision prohibits the use of a

transmission surcharge. Still others

argue that generation costs should not

be assigned to transmission users

because utilities would then have an

incentive to shift costs to transmission

in order to make their generation more

competitive. SCOOP argues that the

shifting of generation costs to

transmission rates violates the

Commission’s policy prohibiting costs

unrelated to the transmission function

from being included in transmission

charges.266

The Public Utility Commission of

Texas (Texas Commission) proposes a

hybrid approach whereby a portion of

stranded costs would be directly

assigned to the departing customer and

the remainder allocated through a

general surcharge to all wholesale

market participants. However, if a

general surcharge on transmission

customers is adopted, the Texas

Commission supports the pooling of all

stranded costs and the creation of an

industry-wide surcharge. The Texas

Commission does not explain how such

a pool would be administered.267

Commenters that represent

shareholder interests (American Society

of Utility Investors, United Utility

Shareholders Association of America,

and Utility Investors and Analysts)

argue against allocation of any stranded

costs to shareholders because the rates

of return granted to utilities in the past

have not included any compensation for

the risk of competition. They submit

that fairness dictates that those placed at

risk by a sudden change in the rules not

be penalized. Tennessee Valley

Authority (TVA), which as a Federal

corporation has no shareholders to

absorb stranded costs, shares this view.

(b) Preliminary Findings. After careful

consideration of the various comments,

we believe that direct assignment of

stranded costs to the departing

wholesale customer, as proposed in the

initial NOPR, is the appropriate method

for recovery of such costs.268 This

method is consistent with the cost
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17697

269Contrary to arguments made by SCOOP, the

shifting of generation costs to transmission rates

does not violate Commission policy. The Northern

States case cited by SCOOP deals with the

Commission’s bright line functionalization policy,

pursuant to which the Commission, largely as a

matter of administrative convenience, has

attempted to maintain a boundary between

generation and transmission functions. In that case,

we found that refunctionalization is not per se

improper or contrary to Commission policy, and we

suggested that strict application of the traditional

bright line approach may need to be reexamined in

light of changes taking place in the electric

industry. 64 FERC at 63,379. Significantly, we

stated that the ‘‘fundamental theory of Commission

ratemaking is that costs should be recovered in the

rates of those customers who utilize the facilities

and thus cause the costs to be incurred.’’ Id.

(emphasis in original).

This is exactly what we propose to do in the

Stranded Cost NOPR and the Supplemental

Stranded Cost NOPR. The customer that caused the

costs to be incurred and stranded will continue to

pay the costs. 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.

270 I.e., departing wholesale requirements

customers under contracts entered into on or before

July 11, 1994, who will use the utility’s

transmission system to reach other suppliers and

whose contracts do not explicitly address stranded

costs.

271Order No. 636 at 30,457–62.

272Under the proposed regulations, a public

utility may seek recovery of such costs in

accordance with the contract. However, 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. See Stranded Cost NOPR at

32,882.

causation principle.269 As discussed in

greater detail below, as part of the

evidentiary demonstration necessary for

stranded cost recovery associated with

certain departing wholesale

requirements customers,270 retailturned-wholesale transmission

customers, or unbundled retail

transmission customers, a utility must

show that the costs are not more than

the customer would have contributed to

the utility had the customer continued

to take generation service from that

utility. We believe it only appropriate

that the departing customer, and not the

remaining customers (or shareholders),

bear its fair share of the legitimate and

prudent obligations that the utility

undertook on that customer’s behalf.

The Commission recognizes that the

direct assignment approach for

addressing stranded costs for the

electric industry differs from the

approach eventually taken for the

natural gas industry. In Order No. 636,

which involved the restructuring of the

gas industry, the Commission

determined that it was appropriate to

spread the majority of the remaining

transition costs associated with take-orpay and other contracts to all customers

(existing and new) using the interstate

natural gas transportation system.271

However, unlike the situation facing the

electric utility industry today, by the

time the Commission issued Order No.

636, changes in the natural gas industry

had progressed to such a point that it

was not possible for the Commission to

use a strict cost causation approach.

Many natural gas customers had already

left their historical pipeline suppliers’

systems. Others had converted from

sales and transportation customers to

transportation-only 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. In

contrast, in the electric area, the

Commission (and the states) will be

better able to address the transition cost

issue up front, and to address stranded

cost recovery before customers leave

their suppliers’ systems. This, in effect,

will prevent the accumulation of

unrecovered costs and will comport

with our past policy of assigning costs

to customers who caused the costs to be

incurred.

In addition, allowing direct

assignment of stranded costs will ensure

that there are no stranded costs left to

be borne by the remaining customer

base or by the shareholders. This, in

turn, will ensure that the financial

health of the industry is not placed in

jeopardy. If some customers are

permitted to leave their suppliers

without paying for costs incurred to

serve them, this may cause an excessive

burden on the remaining customers

(such as residentials) who cannot leave

and therefore may have to bear those

costs. Moreover, the prospect or lack

thereof for recovering such costs from

ratepayers could erode a utility’s access

to capital markets or significantly

increase the utility’s cost of capital. This

higher 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.

The alternatives to direct assignment

of stranded costs are to do nothing or to

assess stranded costs more broadly

through some type of general surcharge

on all customers. As discussed above, to

do nothing would mean that the

Commission would have to reallocate

stranded costs to shareholders or to

remaining customers. Those customers

that caused the costs to be stranded

would not have to pay. This would

violate the cost causation principle

which has been fundamental to the

Commission’s regulation since 1935.

The other alternative, to assess costs

more broadly, also violates this

principle. Moreover, there appears to be

no strong countervailing reason to

assess costs broadly in the electric

utility industry.

(4) Recovery of Stranded Costs

Associated With New Wholesale Power

Sales Contracts. The NOPR proposed

that public utilities and transmitting

utilities would not be permitted to seek

extra-contractual recovery of stranded

costs associated with ‘‘new’’ contracts,

i.e., contracts executed after July 11,

1994, through transmission rates for

section 205 or 211 transmission

services. For new contracts, the NOPR

proposed that stranded cost recovery

would be allowed only if explicit

stranded cost provisions are contained

in the contract accepted by the

Commission.272 We also stated our

preliminary view that it is not

appropriate in this new regime to

impose on wholesale requirements

suppliers any regulatory obligation to

continue to serve their existing

requirements customers beyond the end

of the contract term. However, we

invited comment on the extent to which

there should be such an obligation. We

also sought comment concerning

whether section 35.15 of the

Commission’s regulations, concerning

notice of termination, should be deleted.

(a) Comments. Some of the

commenters dispute the Commission’s

belief that there should not be a future

regulatory obligation to continue to

serve wholesale requirements customers

beyond the end of the contract. SCOOP

argues that the FPA imposes an

obligation on a public utility to continue

wholesale service beyond the term of

the contract when such service is

required by the public interest, and that

the Commission does not have the

power to abrogate this authority.

Sunflower Electric Power Corporation

(Sunflower) submits that, for stability

reasons, a utility’s obligation to serve

requirements customers should run

beyond the end of the contract term.

Some commenters (e.g., SCOOP,

Sunflower, Illinois Commission)

generally support Commission retention

of its section 35.15 notice of termination

filing requirement, arguing that such

filing requirement is reasonable and/or

necessary to ensure that any termination

in service is not contrary to the public

interest.

Other commenters support the

Commission’s position that there should

not be a future regulatory obligation to

continue to serve wholesale

requirements customers beyond the end

of the contract and support modification

or elimination of section 35.15. These
17698 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

273We also propose to retain the section 35.15

filing requirement for any unexecuted contracts that

were filed prior to the effective date of the generic

tariffs proposed herein.

274We request comments on whether this

proposal should also be applied to transmission

contracts.

275The parties, of course, could always

voluntarily renegotiate the contract.

276Stranded Cost NOPR at 32,861; 32,869–70.

277See 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).

commenters argue that if contracts are to

govern future requirements

relationships in the electric industry,

the Commission should allow the

contracts to terminate on their own

terms, without the need for a filing and

Commission approval. New England

Power Company submits that

continuation of such a filing

requirement would add uncertainty to

the parties’ mutually agreed upon

termination date and, in turn, promote

inequitable and asymmetrical risk/

benefit allocations and ineffective

resource planning. EEI asks the

Commission to make a finding that it is

in the public interest to end the

regulation of the termination of bulk

power contracts. EEI suggests that the

Commission could (1) grant a blanket

waiver of the regulations requiring

notice of termination for new contracts;

(2) amend section 35.15 to pre-grant

waiver of notice of termination; or (3)

amend the regulations to pre-grant

waiver of notice of termination in all

bulk power contracts signed after the

Commission makes its public interest

finding to end the regulation of contract

terminations.

(b) Preliminary Findings. The

Commission believes that future

wholesale 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. 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. Accordingly, public utilities and

transmitting utilities will be allowed

stranded cost recovery associated with

new contracts (executed after July 11,

1994) only if explicit stranded cost

provisions are contained in the contract.

Recovery of wholesale stranded costs

associated with any new requirements

contract (executed after July 11, 1994)

will not be allowed unless such

recovery is provided for in the contract.

Further, to ensure that the rights and

obligations of sellers and buyers are

symmetrical in the new competitive era,

we do not believe that it is 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. A requirements

customer thus will be responsible for

planning to meet its power needs

beyond the end of the contract term. In

this regard, it may sign a new contract

with its existing supplier, or it may

contract with new suppliers in

conjunction with obtaining transmission

service under its existing supplier’s

open access transmission tariff.

We believe that the section 35.15

filing requirement should be retained

for all contracts required to be filed

under sections 205 and 206 of the FPA

that were executed prior to the effective

date of the generic tariffs that we

discuss herein.273 With regard to any

power sale contract executed on or after

that date,274 we propose to no longer

require prior notice of termination

pursuant to the provisions of section

35.15. However, for administrative

reasons, we will require written

notification of the termination of such

contract within 30 days after the date

termination takes place.

(5) Recovery of Stranded Costs

Associated With Existing Wholesale

Power Sales Contracts. In the initial

Stranded Cost NOPR (and again in this

Supplemental NOPR) we stated that

stranded costs are a transitional problem

and that neglecting their recovery could

delay the realization of fully

competitive bulk power markets. We

stated that it is thus important to set a

date beyond which the Commission will

no longer permit extra-contractual

recovery of stranded costs that result

from existing requirements contracts. To

that end, we proposed a three-year

transition period during which public

utilities must attempt and non-public

utilities are encouraged to attempt to

renegotiate certain existing wholesale

requirements contracts (i.e., those that

do not explicitly address stranded costs

through an exit fee or other stranded

cost provision), and during which they

may seek recovery of stranded costs.

However, if an existing wholesale

requirements contract explicitly

addresses stranded costs through an exit

fee or other stranded cost provision, the

initial NOPR would require the utility to

recover such costs only as specified in

the contract; it would not permit

unilateral filings to change stranded cost

provisions and would not permit the

utility to seek recovery through

transmission rates of stranded costs

associated with that contract. Under the

initial NOPR, existing contracts that

prohibit stranded cost recovery, or

explicitly prohibit renegotiation of an

existing stranded cost or exit fee

provision, or that prohibit renegotiation

until after the three-year period has

expired would not be subject to the

obligation to renegotiate.275

Where an existing contract does not

contain a stranded cost provision and

the parties to the contract are unable to

negotiate a stranded cost amendment,

and the selling utility is a public utility,

the initial NOPR proposed to permit the

public utility to unilaterally file under

section 205 or 206 of the FPA prior to

the end of the three-year period a

proposed stranded cost provision as an

amendment to the existing contract. The

NOPR also proposed to permit the

selling public or transmitting utility to

seek to recover stranded costs through

jurisdictional transmission rates if, prior

to the end of the three-year transition

period, the customer under the existing

wholesale requirements contract gives

notice pursuant to the contract that it

will no longer purchase all or part of its

requirements from the selling utility,

but instead will purchase unbundled

section 205 or section 211 transmission

services from the selling utility that will

begin prior to the end of the three-year

period.

Under the initial NOPR, if a contract

does not include an exit fee or other

explicit stranded cost provision, but

does contain a notice provision, the

Commission proposed that there be a

rebuttable presumption that the selling

utility had no reasonable expectation of

continuing to serve the customer

beyond the period provided in the

notice provision. We proposed to apply

such presumption when the public

utility proposed a unilateral amendment

to the contract to change the notice

provision and/or add an exit fee

provision, or if the public utility or

transmitting utility sought stranded cost

recovery through transmission rates.276

The Commission recognized that

some utilities’ existing contracts may

not provide for unilateral rate changes.

We noted that although under the

Mobile-Sierra doctrine 277 a customer

may waive its right to challenge the

contract and/or the utility may waive its

right to make unilateral rate changes,

the parties may not waive the

indefeasible right of the Commission to

alter rates that are contrary to the public

interest. We went on to explain why we

believe that it is in the public interest

to permit public utilities with MobileSierra contracts a limited opportunity to
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17699

278Notable exceptions to this general observation

include Southern California Edison Company,

which opposes renegotiation of Mobile-Sierra

contracts, and the Pennsylvania Public Utility

Commission (Pennsylvania Commission) and the

Vermont Department, which favor upholding the

sanctity of contracts.

279 56 FPC 3414 (1976).

280 18 FERC ¶ 61,197 (1982).

propose contract changes unilaterally to

address stranded costs if their contracts

do not already explicitly do so.

In the NOPR, the Commission invited

comments regarding, among other

things, whether there should be a

transition period during which utilities

may renegotiate existing contracts, the

appropriate length for such a transition

period, whether utilities or customers

with contracts that do not provide for

unilateral amendments should be able

to make unilateral filings or file

complaints, whether the Commission

should make a Mobile-Sierra public

interest finding based on companyspecific findings instead of generic

industry-wide findings, the types of

contractual provisions that might

demonstrate a sufficient meeting of the

minds between the parties so that

requiring renegotiation would be

inappropriate, whether to apply the

rules regarding existing contracts only

to contracts between unaffiliated

entities, and whether the rebuttable

presumption should also be applied to

any contract entered into after the date

of enactment of the Energy Policy Act,

even though the contract does not

contain an exit fee or other explicit

stranded cost provision or a notice

provision.

(a) Comments. (i) Contract

Renegotiation. Investor-owned utilities,

EEI, and the majority of state

commissions generally favor

renegotiation of requirements

contracts.278 These commenters argue

that the transition to a competitive

market should not preclude utilities

from recovering costs prudently

incurred to serve customers who may

wish to leave the system that was

planned and built to serve the

customers’ needs.

Commenters representing

cooperatives, municipal, industrial

customers, and independent power

producers generally oppose

renegotiation. These commenters

suggest that the framework established

in the NOPR, requiring good faith

renegotiation of contracts and

permitting the unilateral filing of

revised contracts to provide for recovery

of stranded costs (where renegotiation

fails), will result in a violation of the

Mobile-Sierra doctrine. Numerous

commenters argue that contracts should

stand on their own, and that there is no

factual record upon which the

Commission can make a generic public

interest finding, as required by MobileSierra, that contracts should be

modified. These commenters maintain

that ‘‘assumed’’ threats to the financial

stability of the industry do not meet the

extremely heavy Mobile-Sierra burden

of proof that is required to release a

public utility from a contract. They

argue that it is not the Commission’s

place to relieve utilities of improvident

bargains. Many customer group

commenters argue that requiring

contract renegotiation improperly shifts

the burden of proof from the utility to

the customer. These commenters further

argue that permitting contract

renegotiation implies that customers

should pay for a utility’s failure to

protect itself from business risk.

Some commenters, such as American

Forest, argue that the NOPR would, in

essence, rewrite the law of contracts.

These commenters state that there is no

legal (or logical) basis for the NOPR’s

suggestion that wholesale customers

with existing contracts containing valid

notice of termination provisions can be

forced to renegotiate such contracts to

allow stranded cost recovery. Many of

these commenters cite Boston Edison

Company 279 and Arizona Public

Service Company 280 for the proposition

that notice provisions have been

allowed and enforced. Many

commenters contend that contract

renegotiation is unfair because the

policy would make the terms of existing

contracts binding on only one party,

while letting the other party unilaterally

revise contract terms.

Some commenters, including the

Electric Generation Association and the

Iowa Utilities Board, generally oppose

renegotiation, but would allow it in

certain situations. They state that a

utility’s right to recover stranded costs

should depend on the terms for which

the parties have bargained. However,

they recognize that there may be

situations in which the parties’ intent is

not clearly defined. Accordingly, these

commenters support renegotiation to

supply missing terms to an ambiguous

contract. Some commenters such as the

Iowa Utilities Board maintain that

companies should always be free to

renegotiate contracts; however, they

oppose allowing utilities to make

unilateral filings to amend contracts that

do not provide for unilateral

amendment.

With regard to whether the

renegotiation proposal should apply

only to contracts between unaffiliated

entities, some commenters (e.g.,

Wisconsin Power, Sunflower) support

the application of the renegotiation

policy to both affiliated and nonaffiliated entities alike. However, other

commenters (e.g., the Ohio Office of the

Consumers’ Counsel) recommend that

the Commission not apply the proposed

renegotiation rule to affiliated entities.

They note that due to the mutual

interest of affiliates, negotiations

between them may not be arm’s-length.

These commenters urge the Commission

to review all stranded investment

agreements between affiliates to prevent

cross-subsidization and to prevent

interference with competition.

(ii) Three-Year Transition Period.

With regard to the proposed transition

period, although some commenters

argue against permitting contract

renegotiation, commenters generally

raise no serious objections to three years

as the period for contract negotiation.

However, several commenters suggest

that it is undesirable and unnecessary to

delay the movement to competition for

three years while contract renegotiations

take place. For example, the

Competitive Working Group argues that

there is no assurance that stranded cost

recovery will be resolved during the

three-year period proposed in the initial

notice. It suggests that the Commission

could shorten the transition to

competition while still providing for

recovery of stranded costs by requiring

that eligibility for recovery be

conditioned on utilities agreeing to: (1)

Grant wholesale customers the right to

reduce or terminate purchase

obligations under preexisting contracts

and to convert to transmission-only

service; (2) file comparable open-access

transmission tariffs; and (3) mitigate the

level of stranded assets by either

divestiture or auction. The Competitive

Working Group claims that these

measures would ensure the move to

competitive wholesale power markets.

DOE, Industrial Consumers, Enron

and CLF also suggest linking the

recovery of stranded costs to utility

actions that will further wholesale

competition. These commenters suggest

linking the recovery of stranded costs to

the filing of an open access transmission

tariff or membership in an RTG. CLF

notes that environmental as well as

economic benefits may be achieved by

linking the recovery of stranded costs to

the retirement of environmentally

unsuitable electric generating plants or

initiatives that encourage the

development and deployment of

renewable and clean energy

technologies.

Detroit Edison Company (Detroit

Edison) suggests that the renegotiation

period be the greater of (1) three years,
17700 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

281 If a complaint is filed, neither the customer

nor the utility could raise issues not identified in

their earlier discussions. The burden of proof would

be on the utility to satisfy the evidentiary standards

related to stranded cost recovery.

(2) the term of any existing contract, or

(3) the period of any moratorium on

changes in rates established in existing

settlement agreements. According to

Detroit Edison, adoption of this

provision would allow utilities that

already have established long-term

contracts or that have agreed to a

moratorium on rate changes to honor

previously negotiated agreements.

(b) Preliminary Findings. We reaffirm

our proposal to permit the recovery of

legitimate and verifiable stranded costs

for a limited set of existing wholesale

contracts, namely, contracts executed on

or before July 11, 1994 that do not

already contain exit fees or other

explicit stranded cost provisions. We

further reaffirm our desire that utilities

and their customers attempt to

renegotiate such contracts promptly to

specify the rights and obligations of the

parties. To that end, we encourage the

parties to existing contracts that do not

address stranded costs to reach a

mutually agreeable resolution. If the

parties negotiate such a 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. Of

course, in some cases, the parties may

disagree in good faith about whether the

utility’s expectations that the customer

would continue taking service were

reasonable. If so, negotiations may prove

unsuccessful.

In place of the three-year transition

period proposed in the initial NOPR, we

propose that, if an existing requirements

contract does not contain an exit fee or

other explicit stranded cost provision

and is not mutually renegotiated to add

such a provision: (1) A public utility or

its customer may, at any time prior to

the expiration of the contract, file a

proposed stranded cost amendment to

the contract under section 205 or 206;

or (2) a public utility or transmitting

utility may, at any time prior to the

expiration of the contract, file a

proposal to recover, through its

transmission rates for a customer that

uses the utility’s transmission system to

reach another generation supplier,

stranded costs associated with any such

existing contract. However, for a utility

to be eligible for recovery of stranded

costs, it must meet the evidentiary and

procedural criteria discussed infra.

Consistent with the initial NOPR, if

an existing 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. As proposed in the initial

Stranded Cost NOPR and reaffirmed

here, we will reject a stranded cost

amendment to an existing contract that

already contains an exit fee or stranded

cost provision, unless the contract

permits renegotiation of the existing

stranded cost provision or the parties to

the contract mutually agree to

renegotiate the contract.

However, if a contract does not

contain an exit fee or other explicit

stranded cost provision, 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. In addition, even if the

contract contains an explicit MobileSierra provision, the Commission

reaffirms its preliminary determination

that it is in the public interest to permit

public utilities to seek unilateral

amendments to add stranded cost

provisions if the contracts do not

already contain exit fees or other

explicit stranded cost provisions. If a

utility demonstrates that it has met the

standards for recovery outlined in this

Supplemental NOPR, we believe that its

recovery of stranded costs will be in the

public interest.

If neither of the parties to such a

contract seeks and obtains acceptance or

approval of an explicit stranded cost

amendment, the Commission proposes

to permit the public utility to seek

recovery of stranded costs through its

wholesale transmission rates. We also

propose to establish procedures to

provide an existing wholesale

requirements customer who is

contemplating switching suppliers, and

using its existing supplier’s

transmission system in order to reach a

new supplier, advance notice of how the

utility would propose to calculate costs

that the utility claims would be

stranded by the customer’s departure.

We believe that the following

procedures would enable such a

customer to make an informed decision

whether or not to switch suppliers:

(1) A customer may, at any time prior

to the termination date specified in its

existing wholesale requirements

contract, request the public utility to

either: (i) Calculate the customer’s

maximum possible stranded cost

exposure without mitigation, as of the

date set forth in the customer’s request;

or (ii) provide the formula that the

utility would use to calculate the

customer’s maximum possible stranded

cost exposure without mitigation, to

enable the customer to assess whether to

contract for new generation service from

another supplier. The customer should

specify in its request, to the extent

possible, pursuant to its rights under the

power sales agreement with the seller,

the date on which the customer would

substitute alternative generation for the

requirements purchase and the amount

of the substitution. Any remaining

requirements 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(s) (e.g., a monthly or annual

adder to its transmission rate or an upfront lump-sum payment).

(2) The utility shall, within thirty

days of receipt of the request, or other

mutually agreed upon period, provide

the customer: (i) The customer’s

maximum possible stranded cost

exposure without mitigation; or (ii) the

formula that the utility would use to

calculate the customer’s maximum

possible stranded cost exposure without

mitigation. The utility’s response should

indicate the period over which the

utility proposes to charge the departing

customer. There should be appropriate

support for each element in the

calculation or formula to enable the

customer to understand the basis for the

element. The utility should provide a

detailed rationale for its proposal as to

how long the utility reasonably

expected to keep the customer. The

utility also should address how it

intends to mitigate stranded costs.

(3) If the customer believes that the

utility has failed to establish that it had

a reasonable expectation of continuing

to serve the customer beyond the

contract term or that the proposed

maximum stranded cost charge without

mitigation (or formula) is unreasonable,

it will have thirty days in which to

respond to the utility explaining why it

disagrees with the charge. The parties

should then attempt to reach a

mutually-agreeable charge for stranded

costs within a reasonable period.

(4) If the parties are unable to resolve

the matter pursuant to the procedures

specified in (1)–(3) above, the customer

may either: (a) File a complaint with the

Commission under section 206 of the

FPA to seek a Commission

determination whether the utility has

met the reasonable expectation standard

and, if so, whether the proposed

maximum stranded cost charge (or

formula) satisfies the other evidentiary

standards set forth in this rule; 281 or (b)

wait until the proposed stranded cost

charge is filed under section 205 of the
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17701

282As discussed in section III.F.1.c(10) infra,

retail customers contemplating becoming wholesale

customers may use the same procedures.

FPA, and contest it at that time.282 In

either case, i.e., a section 205 or 206

proceeding, the utility would only be

able to seek stranded cost recovery

according to the formula and other

terms identified in its earlier

discussions with the customer.

The above-described procedure would

provide a customer an opportunity to

know its maximum possible exposure as

far in advance of its decision to change

suppliers as the customer chooses (i.e.,

the customer can file its request for a

stranded cost computation at any time).

If the customer decides to contest the

proposed stranded cost charge, in either

a section 206 or 205 proceeding, it will

know its exact exposure once the

Commission has completed its review of

the proposed charge. This procedure

attempts to address the Cajun court’s

concern that exposure to an unknown

stranded cost fee will discourage

customers from looking at other

suppliers. At the same time, this

procedure will permit recovery of

legitimate stranded costs as set forth

herein.

We strongly encourage utilities and

their existing customers to attempt to

resolve stranded cost issues through a

mutually-agreeable exit fee or other

stranded cost amendment to existing

contracts that do not address stranded

cost recovery.

We invite comments on our proposal

to drop the three-year negotiation

requirement originally proposed in the

Stranded Cost NOPR, and instead to

permit amendments to certain existing

requirements contracts at any time prior

to the expiration of the contracts, or to

permit utilities to seek recovery through

a departing customer’s transmission

rates at any time prior to the expiration

of the power sales contracts. We also

invite comments on our proposal to

establish a procedure whereby a

wholesale requirements customer with

an existing contract that does not

explicitly address stranded costs can

obtain its maximum stranded cost

exposure without mitigation from the

utility and can seek Commission review

of the utility’s reasonable expectation

claim and the utility’s proposed

stranded cost charge or formula.

(6) Filing Requirements for Wholesale

Stranded Cost Recovery. The

Commission proposes to amend Part 35,

Chapter I, Title 18 of the Code of

Federal Regulations to establish filing

requirements for public utilities (as

defined in FPA section 201(e)) and

transmitting utilities (as defined in FPA

section 3(23)) that seek stranded cost

recovery. We reaffirm our view that the

only circumstance in which

transmitting utilities that are not also

public utilities may seek stranded cost

recovery from this Commission is

through customer-specific surcharges to

rates for transmission services under

FPA sections 211 and 212, and that

those surcharges may only apply to

costs associated with existing contracts.

The proposed regulations 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 seek comment on whether the

proposed definition of ‘‘wholesale

stranded cost’’ 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, and the

customer does not thereafter become an

unbundled transmission services

customer of that utility. This situation

might occur, for example, in a situation

where the former requirements

customer was in a non-contiguous

service area and does not need

unbundled transmission service from

the former seller in order to purchase

power from a replacement supplier.

Consistent with the initial Stranded

Cost NOPR, the proposed regulations

would 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

(i.e., any wholesale requirements

contract executed after July 11, 1994),

the proposed regulations would allow

recovery of stranded costs only if the

contract explicitly provides for recovery

of stranded costs.

Second, for existing wholesale

requirements contracts (i.e., any

wholesale requirements contract

executed on or before July 11, 1994), the

proposed regulations would specify that

a utility may not recover stranded costs

associated with such contract 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, the proposed rule would

allow a public utility to seek recovery of

stranded costs only as follows: (1) if the

parties to the existing contract

renegotiate the contract in accordance

with this rule 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,

prior to the date the contract expires,

and the Commission accepts or

approves an amendment permitting

stranded cost recovery; or (3) if the

public utility files a request, prior to the

date the contract expires, to recover

stranded costs through an adder to a

departing 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 an adder to a departing

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 contract does contain

an explicit exit fee or other stranded

cost provision.

Fifth, for a retail-turned-wholesale

customer, the proposed rule would

allow a public utility or transmitting

utility to file a request to recover

stranded costs from the newly created

wholesale customer through an adder to

that customer’s transmission rate.

Sixth, for customers who obtain retail

wheeling, a public utility or

transmitting utility may seek recovery

through transmission rates only if the

state regulatory authority has no

authority under state law at the time

retail wheeling is required to address

stranded costs.

(7) Evidentiary Demonstration

Necessary—Reasonable Expectation

Standard.—In the Stranded Cost NOPR,

we proposed, as part of the evidentiary

demonstration that a public utility or

transmitting utility must make to

recover stranded costs in wholesale

transmission rates, or through a

unilateral amendment to the power

sales contract, that the utility must show
17702 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

283Stranded Cost NOPR at 32,873–74.

284 Id. at 32,874. 285See id. at 32,874.

that it incurred costs based on a

reasonable expectation when the costs

were incurred that the applicable

contract would be extended.283 We

indicated that, in these situations, the

question of whether a utility had a

reasonable expectation of continuing to

serve a customer is a factual matter that

will depend on the evidence produced

in each case. We further proposed that

a notice provision in a contract would

create a rebuttable presumption that the

utility had no reasonable expectation of

serving the customer beyond the period

provided for in the notice provision. We

invited comments with regard to these

proposals and also asked whether we

should adopt a minimum notice period

that would create a presumption that

the utility had no reasonable

expectation of continuing to provide

service beyond such period (e.g., a fiveyear notice period).284

(a) Comments. Commenters express a

variety of views on the reasonable

expectation standard for extracontractual cost recovery. Some

commenters (e.g., the Transmission

Access Policy Study Group) do not

believe there is a legal basis to permit

the claimed expectation of indefinite

renewal of a contract to override a

customer’s express contractual

termination rights. These commenters

argue that there has never been any

assurance that utilities will be allowed

to recover all of their costs, no matter

how incurred. These commenters assert

that utilities have been on notice for

years that customers may try to exercise

their contractual right to terminate

service when their contracts end, and

that utilities would not be entitled to

any contract extensions or other relief.

These commenters state that the

reasonable expectation test is an

inadequate basis for denying customers

their contractual termination rights.

Other commenters (e.g.,

Environmental Action) state that if

reasonable expectations (as opposed to

contract language) are relevant, one

must determine both the utility’s and

the customer’s reasonable expectations.

These commenters support the concept

of contract symmetry; if there is no

obligation to serve beyond the contract

term, imposing an obligation to pay

beyond the contract term is

asymmetrical.

With regard to the Commission’s

proposal that a notice provision in an

existing contract creates a rebuttable

presumption that there is no reasonable

expectation that the contract will be

renewed, many investor-owned utility

commenters, as well as the Florida

Commission and the Texas Commission,

question whether a notice provision

constitutes sufficient grounds for such

an assumption. Because of the

obligation to serve and the long lead

time needed to construct new base-load

generating units, they argue that a utility

could have been found to be imprudent

if it did not plan for and build sufficient

generating capacity to meet its service

obligations. These commenters maintain

that it would have been unreasonable

for a utility to assume that a customer

that is served under a contract with a

notice provision that has been

repeatedly renewed would not again

renew the contract. These commenters

maintain that a notice provision is not

sufficient to demonstrate a ‘‘meeting of

the minds’’ on this issue.

TVA states that the notice provisions

in its contracts in no way lessen its

intention to serve its customers. TVA

states that its legislative provisions,

planning process, and history all

support the assumption that it will

continue serving its wholesale

customers indefinitely.

Certain customer groups, such as the

TDU Customers and the Wisconsin

Wholesale Customers (Wisconsin

Customers), believe that the

Commission should make the rebuttable

presumption stronger, i.e., that contracts

with notice provisions should

absolutely preclude stranded cost

recovery. Wisconsin Customers state

that there should be no opportunity for

renegotiation to include stranded cost

provisions in contracts with reasonable

notice provisions.

(b) Preliminary Findings. We believe

we should retain a reasonable

expectation standard as part of the

evidentiary demonstration that a public

utility or transmitting utility must make.

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.

Depending on all of the facts and

circumstances, a reasonable expectation

that a contract would be extended could

be established, for example, by: (1)

Whether the customer had access to

alternative suppliers; (2) a showing that

the parties’ actual conduct or course of

dealing has been to renew the contract

upon its scheduled expiration; (3)

evidence that a utility has recovered

construction-work-in-progress (for

projects that would enter service after

the scheduled contract expiration) from

a particular customer without the

customer’s objection; or (4)

communications between supplier and

customer concerning system planning,

such as an indication by a buyer that the

seller should continue to include the

buyer’s load in the seller’s resource

planning beyond the contract term.285

In addition, as proposed in the initial

NOPR, we believe that the existence of

a notice provision in a contract should

create a rebuttable presumption that the

utility had no reasonable expectation of

serving the customer beyond the period

provided for in the notice provision. Of

course, evidence that a contract with a

notice provision has been repeatedly

renewed (the scenario described by

commenters opposing the creation of a

rebuttable presumption) may,

depending on the particular case, be

sufficient to rebut the presumption that

the utility had no reasonable

expectation of contract renewal.

Further, we will not adopt a

minimum notice period for purposes of

applying the reasonable expectation

rebuttable presumption. We believe that

whether a utility had 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. In these

circumstances, we do not believe that a

generic minimum notice period would

be appropriate.

In addition, 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.

We seek further comment on the

following specific aspect of the

reasonable expectation standard: Should

the reasonable expectation standard

apply in a case where 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 or utilities? Should

the Commission 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? In the alternative, should the

Commission 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 or utilities?

Finally, in the event that the seller

establishes that it had a reasonable

expectation, and the former wholesale

customer does not take unbundled
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17703

286 Id. at 32,874–75.

287 Id. at 32,867.

288The Utility Working Group members

participating in UWG’s comments in this

proceeding are Dominion Resources, Inc., Duke

Power Company, Duquesne Light Company,

Entergy Corporation, General Public Utilities

Corporation, Niagara Mohawk Power Corporation,

Northern States Power Company, Pacific Gas and

Electric Company, Portland General Electric

Company, Public Service Electric and Gas

Company, San Diego Gas & Electric Company,

Southern California Edison Company, and

Wisconsin Electric Power Company.

transmission service from the former

seller, what means ought to be available

for the collection of stranded costs?

(8) Identification of Recoverable

Wholesale Stranded Costs. The

Stranded Cost NOPR proposed, as part

of the evidentiary demonstration

necessary for wholesale stranded cost

recovery, that a utility show that the

stranded costs it incurred are not more

than the customer would have

contributed to the utility had the

customer remained a wholesale

requirements customer of the utility. We

invited comments in the initial NOPR

on what would constitute reasonable

compensation for stranded costs and on

how to determine the amount of

stranded costs that the departing

customer may be liable to pay. For

example, we asked whether it would be

reasonable to limit the annual amount of

stranded costs to what the departing

customer would have contributed to the

utility’s capital (customer revenues

minus variable costs), or whether an

alternative concept would be

appropriate. We also requested

comments as to what would constitute

a ‘‘reasonable compensation period’’

over which to determine a customer’s

liability for stranded costs (e.g., five

years, ten years, or some other period).

We indicated that the present value of

the customer’s liability could be the

discounted value of an annual amount

for such reasonable compensation

period and that this total amount could

be paid in a lump sum or over any

mutually agreeable period.286

We also assumed in the NOPR that

stranded costs will be dominated by

generating capacity, but stated that it is

appropriate to consider stranded costs

more broadly, including the possibility

that fuel supply costs, purchased power

costs (including QF costs), nuclear

decommissioning costs, regulatory

assets, and possibly other utility

obligations may be stranded.

Accordingly, we invited public

comment on what categories of costs, in

addition to investment costs, should be

eligible for stranded cost recovery.287

(a) Comments. (i) Acceptable

Calculation Methods. Most commenters

were not very specific regarding how to

calculate the level of recoverable

wholesale stranded costs. However,

commenters that address this issue

generally fall into three groups.

The first group reflects the position of

EEI and most investor-owned utility

commenters. This group proposes an

asset-by-asset review of stranded

investments (including contractual

liabilities, regulatory assets, and certain

social program costs) to develop a total

company estimate of stranded costs that

need to be recovered. These costs could

then be allocated among customers to

determine a hypothetical cost-of-service

measure of stranded cost liability. From

this amount, the utility would subtract

wheeling service revenues and any

revenues from mitigation measures

taken. As explained in more detail

below in the discussion of allowable

cost categories, investor-owned utility

commenters argue for inclusion of a

broad number of investments, expenses

and future costs in the revenue

requirement calculation of recoverable

stranded costs. Commenters that

support this approach also suggest that

costs are properly included in the

calculation (i.e., are recoverable

wholesale stranded costs) to the extent

that such costs have been ruled to be

prudently incurred in a state

determination.

Some commenters, however, oppose a

hypothetical cost-of-service calculation

approach to determining recoverable

stranded costs arguing that it will

engender litigation. These commenters

note that generating units are not built,

and specific costs are not generally

incurred, on behalf of individual

customers. According to these

commenters, attempting to define

specific components of stranded costs

associated with a specific departing

customer is inconsistent with utility

investment planning and historical cost

incurrence.

A second approach for determining

recoverable wholesale stranded costs is

based on ‘‘revenues lost’’ as a result of

a customer switching suppliers. Most

non-investor-owned utility commenters

(e.g., state commissions and customers)

and some investor-owned utilities (e.g.,

Commonwealth Edison Company

(Commonwealth Edison), Utility

Working Group (UWG) 288) support this

method of calculation. Commenters that

support this approach argue that the

calculation is less complex than a

hypothetical cost-of-service approach

and avoids an asset-by-asset review with

its attendant accounting and tracking

complexities.

Many commenters note that the

revenues lost approach recognizes that

utilities that made multiple investment

decisions under the prior regulatory

scheme compact expected a revenue

stream from their customers to cover the

costs of those investments. Under this

approach, the measure of recoverable

stranded costs is the difference between

revenues expected from a customer

under traditional regulation and the

expected revenues in a competitive

market. Some commenters suggest

further limitations on the revenue

stream calculation, i.e., calculating

revenues on a present value basis, or

using current revenues as the ceiling for

utility expected revenues under the

prior regulatory regime. According to

commenters, these limitations serve at

least two purposes: (1) Simplifying the

calculation; and (2) creating incentives

for utilities to mitigate stranded costs,

which will shorten the transition period

to a competitive market.

Some commenters, including Public

Service Electric and Gas Company

(Public Service Electric), also point out

that this approach is consistent with

resource acquisition. These commenters

note that specific investment decisions

are not made on a retail/wholesale or

customer-by-customer basis, but rather

on the basis of resources needed to meet

load, i.e., generation plant additions are

made based on an analysis of total

system needs. Commenters also note

that under a revenues lost approach,

specific investments/assets do not need

to be assigned (or tracked) to a

particular event causing stranded costs.

A few commenters (e.g., APPA,

Electric Generation Association, Illinois

Commission) advocate a third method of

calculating the level of recoverable

wholesale stranded costs. Under this

method, which is a ‘‘netting’’ or ‘‘market

analysis’’ approach, recoverable

stranded costs would be determined

based on the difference between

embedded capital costs and the market

value of stranded assets. While this

approach is not dissimilar to a

‘‘revenues lost’’ approach, the level of

stranded costs is generally determined

only after a future action with respect to

the stranded costs, i.e., auction,

divestiture or other future disposition of

assets. Other commenters (e.g., Central

Vermont Public Service Corporation,

Long Island Lighting Company (Long

Island Lighting)) suggest variations of

this ‘‘netting’’ approach, such as

comparing the utility’s revenues with

some measure of the utility’s marginal

cost of requirements service.

Commenters claim that, in a competitive

market, the marginal cost would equal

the market price. Thus, under this
17704 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

289 Illinois Commission comments at 61–62.

290Texas Eastern Transmission Corporation, 63

FERC ¶ 61,100 at 61,507 (1993).

291For details on the mechanics of this program,

see Texas Eastern Transmission Corporation, 63

FERC at 61,507–08; Texas Eastern Transmission

Corporation, 64 FERC ¶ 61,378 (1994).

approach, recoverable stranded costs are

the excess above market value of the

stranded assets. Duke Power Company

notes that mitigation measures would be

unnecessary if this method were used to

calculate recoverable stranded costs

because the utility’s marginal cost (not

just its variable expenses), i.e., the

market price of the stranded assets, is

used as the ‘‘offsetting’’ value in the

calculation.

(ii) Reasonable Compensation Period

(how long utility could reasonably

expect to keep customer). Commenters

support a wide range of time periods as

appropriate for determining a

customer’s stranded cost liability.

Almost all of the commenters, however,

request that the Commission provide

flexibility in this regard and not

establish a generic recovery period so

that a variety of recovery mechanisms

can be accommodated.

Some state commission commenters

(e.g., Illinois Commission) support a

limited time period for determining a

customer’s stranded cost liability as an

incentive for utilities to mitigate

stranded costs. According to the Illinois

Commission, limiting the time period

over which a customer’s stranded cost

liability is to be determined should

encourage utilities to ‘‘fervently remarket the services produced by the

potentially stranded resources.’’ 289

Utility customer commenters (e.g., city

of Las Cruces, TDU Customers) also

support a limitation on the period over

which stranded costs would be

determined. These commenters propose

limiting the reasonable compensation

period to the lesser of the contractual

notice period; the remaining portion of

the stated term of a contract; a five-year

period (as a maximum reasonable time

to plan for mitigation measures); or the

utility’s planning horizon.

Some investor-owned utility

commenters (e.g., EEI, Centerior Energy

Corporation), on the other hand, oppose

limiting the period over which a

customer’s stranded cost liability would

be determined. EEI, for example, states

that as a general rule, the departing

customer should be responsible for its

regulated rate less the utility’s marginal

cost and mitigating revenue. It contends

that the period of such responsibility

should continue until the utility needs

the capacity freed up by the departing

customer to meet retail load growth or

firm wholesale obligations. In effect,

these commenters support an openended opportunity to recoup wholesale

stranded costs. They argue that the

recovery period should continue as long

as possible to ensure that native load

customers are held harmless.

(iii) Allowable Cost Categories.

Almost all commenters agree that

stranded costs should not include

variable expenses. The majority of

customer commenters either: (1)

Support the Commission’s proposed

categories; or (2) do not express an

opinion regarding cost categories that

are appropriate for recovery because

they support the use of some type of

‘‘revenues lost’’ approach for

determining recoverable costs, which

does not require the identification of

specific utility investments or expenses.

Many investor-owned utility

commenters, however, contend that, in

addition to the items identified in the

NOPR, recoverable stranded costs

should include a broad number of other

investments, expenses and future costs.

These commenters propose that the

additional items that are eligible for

recovery should include, but not be

limited to:

• Construction work in progress;

• Regulatory assets, such as phase-in

plans for new generation plant, and

accrual accounting requirements (e.g.,

income tax normalization, accounting

for pension and PBOP costs);

• Actual nuclear decommissioning

costs as well as a utility’s pro rata

obligation to dismantle and

decontaminate DOE’s uranium

enrichment facilities;

• All fuel costs pending recovery via

fuel adjustment mechanisms;

• Mandatory social program costs

including DSM, low-income assistance,

environmental clean-up and various

R&D projects;

• Clean Air Act compliance costs;

• Storm damage expenses; and

• Other unknown future liabilities.

In addition, EEI states that before

1992, i.e., pre-EPAct, no regulatory

commission explicitly authorized a rate

of return that compensated a utility for

the risk of future retail competition. EEI

notes that after EPAct only four

regulatory commission decisions have

addressed this issue. Because the risks

of the new competitive market were

neither contemplated by investors nor

compensated by regulators under

existing ratemaking, EEI argues that the

cost of such risk must also be included

as a category of costs eligible for

stranded cost recovery.

Public Power Council suggests that

there are two dangers in creating lists of

eligible and ineligible costs: (1) Wasteful

regulatory battles are likely; and (2)

utility managers will have the incentive

to reduce ineligible costs, while

ignoring opportunities to reduce eligible

costs.

(b) Preliminary Findings. The

Commission preliminarily concludes

that the determination of recoverable

stranded costs should be based on a

‘‘revenues lost’’ approach rather than a

hypothetical cost-of-service approach.

The Commission believes that this

approach has greater benefits than a

hypothetical cost-of-service approach. A

‘‘revenues lost’’ approach avoids the

asset-by-asset review that is required by

alternative cost-of-service approaches in

order to calculate recoverable stranded

costs. Cost allocation procedures are

also minimized. Moreover, the

Commission believes that this approach

will be easier to apply, thereby

minimizing the cost of administering

stranded cost recovery.

The Commission’s experience in the

natural gas industry is relevant here.

Certain pipelines faced with take-or-pay

obligations under uneconomic natural

gas supply contracts have developed a

‘‘pricing differential’’ mechanism that

has enabled them to honor existing takeor-pay obligations, while attempting to

renegotiate the contracts.290 Under this

mechanism, the pipeline continues to

meet its contractual purchase obligation

and continues to market the gas

purchased through its separate

marketing operation. The ‘‘differential’’

or ‘‘revenues lost’’ between the purchase

price and the sales price is passed

through as a transition cost.291

Under the revenues lost method that

we propose here, the utility would

calculate a customer’s stranded cost

liability by subtracting the competitive

market value of the power the customer

would have purchased from the utility

(and the basic revenues from the

transmission service) had the customer

continued to take service under its

contract from the revenues that the

customer would have paid the utility.

As discussed in section III.F.1.c(9) infra,

the utility must attempt to mitigate

stranded costs by marketing stranded

power supplies.

The Commission seeks further

comments on the revenues lost

approach. In particular, what would be

the appropriate method to calculate

what the utility’s revenue stream would

have been had the customer continued

service (e.g., current revenues based on

current service levels, or should

projection and adjustments reflecting

changes in the revenue stream be

permitted)? The Commission also seeks

comments on the appropriate method to
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17705

calculate the revenues that the utility

would receive in a competitive market

for the stranded assets. Should the

Commission require the utility to track

the actual selling price of the power

over time, or should it require the utility

to use an up-front approach, such as an

estimate of the forecasted market value

of the power for the period during

which the customer would have taken

service? Should the Commission allow

prices in futures markets or forward

markets to be used in an up-front

approach, assuming such financial

instruments become available? In

addition, how should revenues received

as a result of mitigation measures 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? Once

determined, should any adjustment 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?

With regard to establishing a

reasonable compensation period (i.e.,

setting a limit on how long the utility

could have reasonably expected to keep

the customers), we do not believe that

a one-size-fits-all approach is

appropriate. A particular customer’s

stranded cost liability will depend, in

each instance, on such case-specific

factors as whether the utility can

demonstrate that it had a reasonable

expectation of continuing to serve the

customer beyond the term of the

contract and, if so, for how long.

Therefore, we believe it appropriate to

permit utilities and their customers

some flexibility with regard to the

period over which a customer’s

stranded cost liability would be

determined. However, we will not allow

an open-ended opportunity to recoup

wholesale stranded costs. Although our

preliminary finding is that a one-sizefits-all approach is not appropriate, we

seek further comment with respect to

whether the Commission ought to

establish presumptions or, in the

alternative, absolute limits on a

customer’s maximum liability in those

situations where a utility establishes

that it had a reasonable expectation that

the contract would be extended. For

instance, would it 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? What other

events or criteria might the Commission

use to establish either presumptions or

absolute limits on the time period over

which the customer’s liability for

stranded costs would be determined?

Our decision to adopt a revenues lost

approach for determining recoverable

stranded costs, which avoids an assetby-asset review, in effect eliminates the

need to enumerate specific categories of

costs that may be recovered. However,

there may be special categories of costs

that are properly allocated to departing

customers and that are not captured in

the revenues lost approach. For

example, nuclear decommissioning

costs may not be reflected, or may not

be fully reflected, in current

requirements rates. To the extent this is

true, a departing customer may be

‘‘escaping’’ from costs that it caused as

a result of taking power service from its

supplier during the time that the

nuclear plant was operating. We seek

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. We also solicit

comments as to whether the Open

Access NOPR raises any additional

implementation or other issues affecting

stranded cost recovery as proposed here.

(9) Mitigation Measures. As part of the

evidentiary demonstration that a utility

must make in order to recover stranded

costs, the Stranded Cost NOPR would

require the utility to show that it has

taken and will take reasonable and

prudent measures to mitigate stranded

costs. The Commission proposed in the

initial NOPR that adequate mitigation

measures might include: (1) Evidence

that the utility has tried to market the

asset or assets, market the generating

capacity, reconfigure or delay

investment in or purchase of new

generating capacity, or reform fuel

supply contracts that form the basis for

the stranded costs charge, and that such

measures to mitigate stranded costs will

continue for the entire period for which

the stranded costs charge will be paid;

or (2) the utility has given the customer

the option to market the generating

capacity or supply of fuel or purchased

power that forms the basis for the

stranded cost charge in order to afford

the customer an opportunity to lower its

stranded costs charge. We invited

comment on the mitigation requirement

and what reasonable measures to

mitigate may include.

(a) Comments. Although there is

nearly unanimous support for requiring

that mitigation measures be taken,

commenters raise several issues

regarding how mitigation should be

implemented and the effectiveness of

such a requirement.

As noted above, many investor-owned

utility commenters argue that stranded

costs should be defined to include costs

other than capital investment in utility

property. According to these

commenters, stranded costs also may

include environmental clean-up costs,

decommissioning costs, and regulatory

assets resulting from cost recovery

deferrals. Unlike capacity, these costs

cannot be ‘‘marketed.’’ Therefore,

mitigation measures cannot be taken

with respect to these costs. Thus,

according to some commenters, there is

a category of ‘‘unmarketable’’ stranded

costs for which mitigation efforts to

reduce the level of the costs are not

possible.

Many commenters (e.g., Texas

Commission, TDU Customers) contend

that a mitigation requirement will be

more effective if incentives to mitigate

are created. These commenters suggest

several options, including:

• Limiting recovery of stranded costs

to current rate levels (no projections of

increases in stranded costs for future

periods);

• Requiring shareholders to shoulder

some cost responsibility (to ensure that

mitigation measures will be aggressively

pursued); and

• Requiring any stranded investment

to be offered for sale, either with the

departing customer permitted to ‘‘sell’’

the stranded investment, or through

some form of auction.

Other commenters suggested that

effective mitigation would require

auctioning off stranded assets or some

type of general divestiture of assets by

the utility that is allowed to recover

stranded costs.

Many commenters acknowledge that

revenues from mitigation measures

should reduce the amount of wholesale

stranded costs. An issue is raised,

however, regarding how revenues

associated with mitigation measures

should be credited. Given the overall

preference by commenters supporting

stranded cost recovery for direct

assignment of stranded costs to a

departing customer, explicit crediting

mechanisms and accounting

requirements—and perhaps new

accounts or subaccounts—would be

needed to keep track of amounts owed

by those assessed wholesale stranded

costs. Consequently, these commenters

contend that decisions regarding who

should pay (and how) for wholesale

stranded costs must be coordinated with

decisions regarding the implementation

of required mitigation measures so that

parties receive appropriate credits.
17706 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

292Stranded Cost NOPR at 32,878–79.

(b) Preliminary Findings. We note that

the revenues lost approach for

determining recoverable stranded costs

encompasses 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 under its

contract. Thus, our suggestion in the

initial NOPR that revenues associated

with mitigation measures be credited to

the departing customer through

reductions to that customer’s surcharge

is in effect accomplished by adoption of

the revenues lost approach. 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.

Nonetheless, we emphasize that

mitigation as a general matter remains

important, and seek comment regarding

implementation of a mitigation

requirement. For example, if mitigation

is trued-up over time, how should the

Commission ensure that the utility takes

all reasonable steps to mitigate its own

costs so as to minimize what the

customer would have paid? How should

the Commission ensure that the utility

does its best to sell the power at its

highest possible value so as to mitigate

the customer’s stranded cost liability?

Are there other mitigation measures that

should be taken into account (e.g.,

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)?

(10) Federal Forum for ‘‘Retail’’

Stranded Cost Recovery and Proposed

New Definition of ‘‘Wholesale’’

Stranded Costs. In the initial NOPR, the

Commission described two general ways

in which retail stranded costs are likely

to occur: (1) A retail franchise customer

or group of such customers may,

through state or local government

action, become a wholesale customer

that can then obtain unbundled

transmission services in order to reach

a new power supplier; and (2) a retail

franchise customer may obtain

voluntary unbundled retail transmission

services from its existing power supplier

in order to reach a new power supplier,

or there may be a State or local

government action that results in the

existing supplier providing such retail

transmission services. The Commission

requested comments concerning the

extent to which the Commission should

provide a forum for resolving retail

stranded cost issues. The Commission

proposed two alternatives for addressing

this issue. Under the first alternative,

the Commission proposed that it would

not entertain a request for retail

stranded cost recovery if, in a specific

circumstance, an appropriate state

authority explicitly considers and deals

with retail stranded costs and there is

no conflict within or among state

regulatory bodies regarding a state’s

disposition of the issue. However, in the

absence of a clear expression by an

appropriate state authority that it has

dealt with the issue, or in the event of

a conflict between states or among state

officials within a single state, the

Commission proposed to entertain

requests to recover retail stranded costs.

Under the second alternative, the

Commission proposed not to entertain

any request for recovery of retail

stranded costs. Under this alternative,

we proposed that state or local

authorities would be the only forum for

addressing the issue.292

(a) Comments. Most of the state

commissions comment that the

Commission should not provide a forum

for addressing retail stranded cost

issues. The Massachusetts Department

of Public Utilities suggests Commission

involvement only if a conflict arises

through disparate stranded cost

treatment by different states that the

states are unable or unwilling to resolve.

The Pennsylvania Commission suggests

Commission involvement in retail

stranded cost issues only if states have

lost jurisdiction (for instance, due to

municipalization). Most of the state

commissions argue that retail costs are

subject to exclusive state jurisdiction

and that action or inaction by a state or

any differences between state actions

are matters to be resolved by the courts,

not the Commission. Many of these

commenters (e.g., NARUC) note that

numerous differences in ratemaking

currently exist among states and that the

Commission has not attempted to

resolve those differences; they see no

distinction with regard to retail stranded

cost recovery. Some state commissions

also argue that the possibility of

Commission involvement in retail

stranded cost recovery could introduce

‘‘forum shopping.’’

The New York State Public Service

Commission (New York Commission)

suggests that the Commission provide a

backstop to the states only if a state has

taken no action regarding retail stranded

costs. The Ohio Public Utilities

Commission (Ohio Commission) and the

Wyoming Public Service Commission

suggest that the Commission become

involved in retail stranded costs only at

the request or petition of a state.

Commenters representing investorowned utilities, on the other hand,

overwhelmingly agree that the

Commission should provide a forum for

resolving retail stranded cost issues.

They propose a broad range of scenarios

in which Commission involvement in

retail stranded cost recovery is

appropriate.

EEI, Commonwealth Edison, Florida

Power and Northern States Power

Company argue that the Commission

should act as a backstop to state

commissions with authority to address

retail stranded cost issues: (1) To

address yet undefined questions; (2)

when no state commission action is

taken; or (3) when state commission

action is not taken in a fair and timely

manner or results in the confiscation of

utility property.

Allegheny Power, Arizona Public

Service Company and Virginia Electric

and Power Company argue that the

Commission should provide a forum to

address situations in which states

allegedly have no authority to address

retail stranded cost issues (primarily

municipalization).

The Coalition for Economic

Competition, Entergy, Utility Working

Group, and the Nuclear Energy Institute

urge the Commission to address

situations in which state policy is

inconsistent with Commission policy. In

fact, many investor-owned utilities

advocate the establishment of uniform

national guidelines for stranded cost

recovery that will be applicable to both

wholesale and retail stranded costs.

These commenters contend that the

Commission is the only body capable of

fulfilling this role.

Houston Lighting & Power Company

urges the Commission to address retail

stranded costs whenever retail stranded

costs have a substantial adverse impact

on interstate transmission.

Two investor-owned utilities support

Commission involvement in retail

stranded cost issues only in limited

circumstances. Entergy contends that

Commission involvement is necessary

only if state jurisdiction is evaded (i.e.,

certain cases of municipalization).

Public Service Electric states that

Commission oversight is needed to

ensure that final results are consistent

with Commission guidelines and are

pro-competitive.

Commenters representing small

customer interests, such as Electric

Consumers’ Alliance and the National

Black Caucus of State Legislators,

support Commission involvement in

retail stranded cost issues in order to

ensure that large customers that leave

the system do not evade their fair share
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17707

293Nuclear Energy Institute’s utility members

operate all (109) of the nuclear power plants in the

United States.

294EEI states that these states are Arizona,

Connecticut, Delaware, Florida, Georgia, Idaho,

Illinois, Kansas, Kentucky, Louisiana, Michigan,

Minnesota, Montana, Nevada, New Jersey, New

Mexico, New York, North Dakota, Ohio, Oklahoma,

Oregon, Rhode Island, South Dakota, Tennessee,

Utah, Virginia, Washington and Wyoming.

295EEI states that these states are Alaska,

Arkansas, Iowa, Indiana, Maryland, Massachusetts,

North Carolina, New Hampshire, South Carolina,

South Dakota, Texas, Vermont, West Virginia and

Wisconsin.

of stranded costs to the detriment of

residential and other small customers.

Commenters representing municipal

and electric cooperatives (such as

APPA, TAPS and SCOOP), commenters

representing independent power

producers (such as the National

Independent Energy Producers),

commenters representing industrial

customers, some customer advocacy

group commenters (such as Industrial

Consumers, American Forest, and the

National Association of State Utility

Consumer Advocates (NASUCA)), and

commenters representing environmental

groups (such as CLF) generally oppose

Commission involvement in retail

stranded cost issues.

DOE agrees with the Commission that

retail stranded cost recovery is primarily

a state issue. However, DOE states that

the Commission has correctly

determined that it has authority to

regulate the rates, terms and conditions

of retail transmission service.

Accordingly, DOE supports Commission

involvement in retail stranded cost

issues.

DOE notes that states may decide to

make retail competition contingent

upon the recovery of stranded costs by

their jurisdictional utilities. DOE states

that the Commission does not appear to

have considered the possibility that a

utility may seek recovery of retailrelated stranded costs through a retail

transmission tariff filed with this

Commission that has the support of the

state commission. DOE submits that the

Commission, as a matter of policy,

should allow utilities to file tariffs for

retail transmission service that recover

stranded retail costs when such filings

have the support of the affected state

commissions. However, DOE states that

the Commission should not give

deference to tariffs for retail

transmission service that contain a

provision for stranded cost recovery if

the tariff is opposed by any state

commission that has a material interest

in the filing.

Public Service Electric states that due

to the vertical integration of electric

utilities, the distinction between

wholesale and retail stranded costs is

merely a matter of cost allocation. It

contends that utilities generally do not

have specific generating facilities in

place to serve strictly wholesale

customers, but rather include wholesale

customer loads into their planning

models as if they were retail customers.

Public Service Electric thus concludes

that no distinction between wholesale

and retail stranded costs is necessary for

purposes of evaluating stranded cost

recovery.

In contrast, other commenters

contend that there are inherent

differences between retail and

wholesale stranded costs, resulting

primarily from the different regulatory

regimes in place. These commenters

state that, at the state level, a utility

provides retail service pursuant to a

‘‘regulatory compact’’ under which the

utility undertakes an obligation to serve

retail customers in exchange for an

exclusive service franchise. In contrast,

they submit that the utility’s obligation

to serve a customer at the wholesale

level is established through contract.

Some commenters conclude that these

differences necessitate different

approaches for recovery of wholesale

and retail stranded costs.

Several commenters (e.g., Duke,

Entergy, Long Island Lighting, Nuclear

Energy Institute,293 Public Service

Electric, Coalition for Economic

Competition, Utility Working Group)

request that the Commission issue a

uniform national set of standards to

govern the treatment of all stranded

investment (both retail and wholesale),

irrespective of jurisdiction with respect

to retail stranded costs.

In contrast, several of the state

commission commenters emphasize a

need for flexibility in dealing with retail

stranded costs in lieu of a one-size-fitsall solution, which they argue may fail

to address important differences

between states. Accordingly, several of

the state commission commenters,

including the Alabama, California,

Indiana, Michigan, and New York

Commissions, urge that the Commission

develop in cooperation with the state

commissions a flexible approach to

retail stranded cost recovery through

various means such as joint boards or

through more informal conferences or

other joint forums.

With respect to the issue of stranded

costs caused by retail-turned-wholesale

customers, EEI and several investorowned utilities (particularly those in

Michigan, New York and California)

maintain that the most important

stranded cost issue before the

Commission at this time is the

formation of new municipal utilities.

These commenters urge Commission

involvement in the recovery of stranded

costs resulting from this action. EEI

notes that most states have constitutions

or laws that permit municipalization,

through which groups of retail

customers may, in effect, become

wholesale customers and thereby

transfer primary regulatory

responsibility for regulating sales to

such entities from a state commission to

the Commission.

EEI argues that in most instances the

Commission will be the regulatory body

that will have to consider stranded cost

recovery issues resulting from

municipalization. EEI states that in

approximately 28 states, there is

virtually no limitation on the ability of

municipalities to form utilities or to

oust current suppliers; 294 these states

will be unable to protect their utilities

from stranded costs. According to EEI,

only 14 state commissions have some

jurisdiction over the creation or

expansion of municipal utilities,295 and

only a few states require reimbursement

for stranded generation or for lost

earnings. Moreover, EEI notes that

condemnation proceedings based on

eminent domain principles often do not

consider regulatory policies regarding

stranded cost assignment and recovery.

NARUC, on the other hand, argues

that states and/or state commissions

have the ability to address all retail

stranded cost issues. From NARUC’s

perspective, the recovery of stranded

costs due to municipalization is a matter

to be addressed by state authorities.

Appendix D to NARUC’s comments

contains information regarding state

practices and policies in the areas of

municipalization and newlymunicipalized service territory (i.e.,

annexation). While policies do vary

among the states, NARUC as well as

most state commission commenters

(e.g., Iowa Commission) maintain that

state authorities (commissions, courts

and legislative bodies) clearly have the

ability to impose stranded asset

payments on new municipal utilities.

NARUC contends that resolution by

state authorities is mandated by the

legal authority of the states to act, and

does not depend upon Commission

deference to the states. NARUC also

cautions the Commission against

becoming an appellate body for

reviewing state determinations that

allegedly overrecover or underrecover

stranded costs.

However, NARUC suggests two

situations where Commission

involvement with stranded cost

recovery in a municipalization scenario
17708 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

is reasonable. The first case is when a

state determines that the appropriate

cost recovery mechanism would involve

a wholesale transmission rate beyond

the state’s jurisdiction. The second case

is when the sequence of events or the

timing of the transaction creates some

ambiguity regarding the retail or

wholesale character of the costs (e.g.,

the Massachusetts Bay Transit Authority

case cited in the NOPR).

Some commenters (e.g., Florida

Commission) request joint federal/state

consultation on the issue of

municipalization. The Florida

Commission also requests that the

Commission delay the effectiveness of

wholesale contracts resulting from

municipalization until retail stranded

cost issues are resolved.

(b) Preliminary Findings. As

discussed in the initial NOPR, as a

general matter we believe 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 wholesale

wheeling, or from retail customers who

obtain retail wheeling, in order to reach

a different generation supplier. Based on

an analysis of all the comments

received, we propose to exercise our

authority to address stranded costs as

follows.

Because the vast majority of

commenters have urged the Commission

not to assume responsibility for retail

stranded costs, except in certain

circumstances, we have concluded that

it is appropriate to leave it to state

regulatory authorities to deal with any

stranded costs occasioned by retail

wheeling. The circumstances under

which we will entertain requests to

recover stranded costs caused by retail

wheeling are when the state regulatory

authority does not have authority under

state law to address stranded costs at the

time the retail wheeling is required. We

continue to believe that utilities are

entitled, from both a legal and policy

perspective, to an opportunity to

recover all of their prudently incurred

costs. In addition, as discussed further

below, we believe the Commission

should be the primary forum for

addressing recovery of stranded costs

caused by retail-turned-wholesale

customers.

With regard to stranded costs caused

by retail wheeling, we emphasize that

we will not allow states to use the

interstate transmission grid as a vehicle

for passing through any retail stranded

costs, with the limited exception

discussed above. Only if the state

regulatory authority does not have

authority under state law at the time the

retail wheeling is required to resolve the

retail stranded cost issue will we permit

a utility to seek a customer-specific

surcharge to be added to an unbundled

transmission rate. We have accepted the

view that stranded costs caused by retail

wheeling are primarily a matter of local

or state concern. Thus, these costs

generally must be passed through in a

manner that does not involve

‘‘transmission of electric energy in

interstate commerce’’ as that phrase is

used in the FPA. We are proposing to

prohibit the pass-through of these costs

on interstate transmission facilities

except in the limited circumstance

described. As discussed in section

III.F.1.c(11), we believe that most states

have a number of mechanisms for

addressing stranded costs caused by

retail wheeling, as well as retail-turnedwholesale customers. In addition, as

further discussed in section III.F.1.c(12),

we are proposing to define ‘‘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. States

therefore will be free to impose stranded

costs caused by retail wheeling on

facilities or services used in local

distribution.

At this juncture, the Commission is

comfortable with this approach and our

hope is that a federal forum for recovery

of retail stranded costs ultimately will

not be necessary. When states address

retail stranded costs caused by retail

wheeling, the Commission holds the

strong expectation that states will

provide procedures for, and the full

recovery of, legitimate and verifiable

stranded costs. This is the same

standard we set out for wholesale

stranded costs. We do so as part of our

goal to assure a smooth and orderly

industry transition to competition that

is fair to all affected parties. In this

proposal we also set out procedures that

all parties can use to seek equitable

treatment of stranded cost recovery.

Again, we expect a state providing for

direct access to provide similar

procedures. We know that states are

aware and concerned about the impacts

of providing direct access as shown by

many state comments. Based on this

awareness and concern, we anticipate

state approaches to retail stranded costs

not unlike our approach to wholesale

stranded costs. Although our hope is

that a federal forum will not be

necessary, we will watch with interest

the states’ efforts to address the retail

stranded cost problem.

We believe this approach represents

an appropriate balance between federal

and state interests. It ensures that the

wholesale market, 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 burden

customers in another state with

stranded costs due to retail wheeling.

We have a different view with regard

to stranded costs caused by retailturned-wholesale customers. If a retail

customer becomes a legitimate

wholesale customer, e.g., through

municipalization, it would thereby

become eligible to use the nondiscriminatory open access tariffs we

are proposing to require public utilities

to provide. 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 FERCfiled open access transmission tariff,

such costs would not be stranded. While

the stranded costs likely would derive

primarily from generation investments

that previously were in retail rate base,

we note that utilities generally build

generating facilities and incur other

costs to serve their entire load, both

retail and wholesale. We believe that

costs stranded by the departure of a

retail-turned-wholesale customer could

and should be considered FERCjurisdictional stranded costs once the

new wholesale customer begins taking

wholesale transmission services. They

are identifiable economic costs that

were incurred by the jurisdictional

transmitting utility, and they do not

disappear simply because the identity of

the customer changes from retail to

wholesale. There is a clear nexus

between the FERC-jurisdictional

transmission and the exposure to nonrecovery of prudently incurred costs.

Accordingly, we believe 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.

To implement this policy, we propose

to change the definition of ‘‘wholesale

stranded costs’’ that was contained in

the initial NOPR, and to propose a

definition that includes stranded costs

resulting from unbundled wholesale

transmission for newly created

wholesale customers. We seek comment

on this proposed change.

We propose 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 wholesale requirements

customers leave a utility’s system. In

this regard, we no longer propose to
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17709

296Stranded Cost NOPR at 32,879.

297We note, however, that certain states do not

have service territories or have non-exclusive

service territories (e.g., Louisiana).

298 If a complaint is filed, neither the customer

nor the utility could raise issues not identified in

their earlier discussions. 299Stranded Cost NOPR at 32,878.

adopt the proposal in the initial NOPR

that the ‘‘reasonable expectation’’ test

should not apply in the case of retailturned-wholesale customers or retail

customers that obtain retail wheeling.296

We propose that the utility must

demonstrate that it incurred stranded

costs based on a reasonable expectation

that the customers would continue to

receive bundled retail service. We

expect 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.297 We

solicit comments on this proposed

change.

We reaffirm our proposal in the initial

NOPR that utilities will have to make an

evidentiary showing that the stranded

costs are not more than the net revenues

that retail-turned-wholesale customers

or retail customers that obtain retail

wheeling would have contributed to the

utility had they remained retail

customers of the utility, and that it has

taken and will take reasonable steps to

mitigate stranded costs. If the state has

permitted any recovery from departing

retail-turned-wholesale customers, we

will deduct that amount from what we

determine to be legitimate stranded

costs for which we will allow recovery.

The procedures that we propose for a

wholesale customer to file with the

public utility when it requests

computation of its stranded cost

exposure will apply with equal force to

a retail customer contemplating

becoming a wholesale transmission

customer (e.g., through

municipalization). In particular:

(1) Such a retail customer or group of

customers may, at any time, request the

public utility to either: (i) Calculate its

maximum possible stranded cost

exposure without mitigation, as of the

date set forth in the customer’s request;

or (ii) provide the formula that the

utility would use to calculate the

customer’s maximum possible stranded

cost exposure without mitigation, to

enable the customer to assess whether to

become a wholesale transmission

customer. The customer should specify

in its request, to the extent possible, the

date on which the customer would

become a wholesale transmission

customer of the utility and the amount

of generation, if any, it will continue to

purchase from its existing supplier. 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(s) (e.g., a monthly or annual

adder to its transmission rate or an upfront lump-sum payment).

(2) The utility shall, within thirty

days of receipt of the request, or other

mutually agreed upon period, provide to

the customer: (i) The customer’s

maximum possible stranded cost

exposure without mitigation; or (ii) the

formula that the utility would use to

calculate the customer’s maximum

possible stranded cost exposure without

mitigation. The utility’s response should

indicate the period over which the

utility proposes to charge the departing

customer. There should be appropriate

support for each element in the

calculation or formula to enable the

customer to understand the basis for the

element. The utility should provide a

detailed rationale for its proposal as to

how long the utility reasonably

expected to keep the customer. The

utility also should address how it

intends to mitigate stranded costs.

(3) If the customer believes that the

utility has failed to establish that it had

a reasonable expectation of continuing

to serve the customer or that the

proposed maximum stranded cost

charge without mitigation (or formula)

is unreasonable, it will have thirty days

in which to respond to the utility

explaining why it disagrees with the

charge. The parties should then attempt

to reach a mutually-agreeable charge for

stranded costs within a reasonable

period.

(4) If the parties are unable to resolve

the matter pursuant to the procedures

specified in (1)–(3) above, the customer

may either: (a) File a complaint with the

Commission under section 206 of the

FPA to seek a Commission

determination whether the utility has

met the reasonable expectation standard

and, if so, whether the proposed

maximum stranded cost charge (or

formula) satisfies the other evidentiary

standards set forth in this rule; 298 or (b)

wait until the proposed stranded cost

charge is filed under section 205 of the

FPA, and contest it at that time. In

either case, i.e., a section 205 or 206

proceeding, the utility would only be

able to seek stranded cost recovery

according to the formula and other

terms identified in its earlier

discussions with the customer.

(11) State Mechanisms to Address

Stranded Costs Caused By Retail

Wheeling. The initial NOPR set forth a

number of mechanisms that the

Commission believes states can use to

address stranded costs caused by retail

wheeling and retail-turned-wholesale

customers. We suggested that a state

that permits a retail franchise customer

to become a wholesale entity may

consider whether to impose an exit fee

prior to, or as a condition of, creating

the wholesale entity.299 We also

suggested that a state may consider

whether to require payment of an exit

fee prior to a franchise customer being

permitted to obtain unbundled retail

wheeling. We noted that, in situations

in which local distribution facilities are

used by a retail wheeling customer, the

state may consider whether to allow

recovery of stranded costs through rates

for local distribution services. Further, if

a state decides not to impose an exit fee,

or a surcharge through distribution

rates, 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.

We further suggested the possibility

that state condemnation proceedings

will provide a forum for a utility to seek

recovery of any stranded costs where a

new wholesale entity obtains ownership

or control of a franchise utility’s

transmission or distribution facilities.

The Commission solicited comments on

other mechanisms that states can use to

determine whether to allow stranded

cost recovery, and from whom to allow

recovery, and whether those

mechanisms are adequate to deal with

retail stranded costs.

(a) Comments. We note, as an initial

matter, that many of the state

commission commenters did not

specifically respond to our questions

concerning mechanisms available to the

states for addressing stranded costs.

Those that did, such as NARUC, the

Texas Commission and the Vermont

Department, however, agree that the

states have a variety of mechanisms

available to deal with stranded costs. In

addition to the mechanisms that we

identified in the initial NOPR (i.e.,

imposing an exit fee prior to, or as a

condition of, creating the wholesale

entity; requiring an exit fee before a

franchise customer is permitted to

obtain unbundled retail wheeling;

imposing a surcharge on local

distribution rates; or state condemnation

proceedings), these commenters

identified the following: (1) Avoiding

stranded costs in the first instance by

seeking to preserve the integrity of the
17710 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

300The Texas Commission suggests, for example,

that a state might limit certain forms of retail

competition, such as retail wheeling or multiple

certification in utility service areas.

301As discussed above, we have determined that

we will address stranded costs caused by retailturned-wholesale customers. 302Stranded Cost NOPR at 32,876–77.

303The Ohio Commission proposes a model for

drawing the line of demarcation between federal

and state jurisdiction whereby the states would

have rate jurisdiction over the wheeling-in portion

of unbundled retail service (i.e., the point at which

retail power enters the system of the last entity who

redelivers the power to the end-use customer) and

this Commission would retain jurisdiction over the

wheeling-out and wheeling-through portions of a

transaction. It contends that retention of

utility’s franchised service territory; 300

(2) seeking to reduce the burden of

uneconomic costs through accelerated

depreciation, revaluing of assets, or

adjusting returns during the transition

period; (3) allowing utilities to charge

discounted rates (i.e., below embedded

cost but above marginal cost) or

reforming retail rates through new rate

methodologies such as performancebased pricing or price caps; (4) charging

access fees to generating entities seeking

to enter retail markets; (5) adopting taxbased solutions, such as credits or

deductions; (6) requiring utility writeoffs of uneconomic costs; (7)

establishing a stranded cost recovery

fund to be funded through a broadbased surcharge or a tax on retail market

participants; (8) encouraging research

and development of more efficient enduse electrical technologies; and (9) not

guaranteeing service to a departing

customer that seeks to resume retail

service if capacity is unavailable when

the customer seeks to return. NARUC

suggests that these options are not

mutually-exclusive, but instead could

be used in combination with others

depending on the particular

circumstances.

In response to our question whether

these mechanisms are adequate to deal

with retail stranded costs, NARUC

submits that the states have adequate

legal authority to impose any existing

regulatory mechanisms or to enact new

mechanisms that may be needed to

address stranded cost issues. NARUC

further states that whether these

mechanisms are adequate to provide

utilities firm assurance that stranded

costs will be recovered is not relevant to

the Commission’s inquiry. It argues that

whether a utility in a particular case

recovers all or part of what it identifies

as stranded retail costs should be a factbased determination made by the

appropriate state commission(s).

(b) Preliminary Findings. We are

satisfied that the states do have a

number of mechanisms available to

them to address stranded costs that

result from retail customers who obtain

retail wheeling, in order to reach a

different generation supplier.301 We

encourage the states to use the

mechanisms available to them in

whatever way they deem appropriate to

address stranded costs.

(12) Commission Authority to

Regulate Transmission Rates, Terms,

and Conditions for Unbundled Retail

Transactions and Definition of State

Jurisdictional Local Distribution. In the

NOPR, the Commission stated that it has

exclusive jurisdiction over the rates,

terms and conditions of unbundled

retail interstate transmission services.

We based our conclusion in that regard

on the plain meaning of the FPA and

noted that there is nothing in the

statute, the legislative history, or the

case law to indicate that the

Commission’s jurisdiction over the

rates, terms and conditions of

transmission in interstate commerce

extends only to wholesale transmission

and not to retail transmission.302 In the

initial NOPR, we left open the question

of the jurisdictional line between

Commission- jurisdictional

‘‘transmission’’ and state-jurisdictional

‘‘local distribution.’’ However, as

discussed, we believe it is appropriate

to set forth our views in this document

on the demarcation of our respective

authorities in this regard.

(a) Comments. Some commenters note

that the Commission’s authority to

regulate sales for resale and

transmission of electric energy in

interstate commerce is premised on

Congressional intent to fill the

‘‘Attleboro gap.’’ These commenters

note that Congress enacted the FPA to

complement, not diminish, state

authority. In light of this

complementary jurisdictional posture,

several commenters believe the

Commission must explain how an

unbundled retail sale is different from a

bundled retail sale, which state

commissions have regulated and will

continue to regulate.

Various non-investor-owned utility

commenters, including the Illinois

Commission and NASUCA, maintain

that the Commission does not have

jurisdiction over transmission service

for an unbundled retail transaction.

NARUC maintains that the issue is, at

the very least, unsettled. Therefore,

before addressing the question of

whether and how the Commission has

jurisdiction over retail stranded costs,

these commenters argue that the

Commission should first re-examine

whether its jurisdictional premise is

correct, or simply convenient. Investorowned utility commenters, on the other

hand, generally concur with the

conclusions in the NOPR regarding

Commission jurisdiction.

The Illinois Commission maintains

that this Commission’s jurisdiction

extends only to the transmission of

electricity between utility systems. It

fails to see how ‘‘unbundling’’ of

generation service from transmission/

distribution services, in order to

effectuate ‘‘retail wheeling,’’ changes the

basic intrastate nature of such services.

The Illinois Commission states that if

unbundled retail transmission is within

the scope of federal jurisdiction, then

one may question why the retail

transmission portion of bundled

services would not also be subject to

Commission jurisdiction. It maintains

that there is no legal or policy

foundation supporting Commission

jurisdiction over either bundled or

unbundled retail electric services.

The Illinois Commission further

argues that the case law relied upon in

the NOPR fails to establish that the

Commission has retail wheeling

ratemaking authority. The Illinois

Commission contends that each of the

cases cited by the Commission (as well

as the FPA itself) all predate the issues

of retail wheeling and retail stranded

costs. Thus, according to the Illinois

Commission, the courts have never

contemplated retail wheeling or the

effects that retail wheeling would have

in terms of stranded costs for public

utilities or transmission carriers. The

Illinois Commission argues that,

because section 201(a) of the FPA

prohibits infringement of Federal

regulation on matters subject to

regulation by the states and because

states currently regulate bundled retail

transmission, the Commission is

necessarily precluded by the FPA from

regulating retail transmission.

The Illinois Commission notes that

under the Natural Gas Act, the states,

and not the Commission, determine the

rates, terms, and conditions of

unbundled retail transportation services

provided by local distribution

companies. The Illinois Commission

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.

Notwithstanding the jurisdictional

debate, other state commission

commenters such as the Ohio

Commission contend that Commission

assertion of jurisdiction may chill state

willingness to undertake competitive

reform at a retail level.303 These
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17711

jurisdiction over a portion of wheeling is necessary

for states to be able to assess retail stranded costs.

304States also have the authority to address socalled ‘‘stranded benefits’’ (e.g., environmental

benefits associated with conservation, load

management and other DSM programs) through

their jurisdiction over local distribution.

305The 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.

306There 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.

307 16 U.S.C. 824.

308 16 U.S.C. 824(b) (emphasis added).

commenters further contend that

Commission intervention in retail

ratemaking will undermine a state’s

ability to address retail issues without

being ‘‘second guessed.’’ Commenters

view this regulatory uncertainty as an

unwarranted and unnecessary result of

the Commission’s purported invalid

assumption of jurisdiction.

(b) Commission Ruling. We reaffirm

our legal conclusion that the

Commission has jurisdiction over the

rates, terms and conditions of

unbundled interstate transmission

services by public utilities to retail

customers, and that we have the

authority to address retail stranded costs

through our jurisdiction over such

services.

However, we also believe the States

have authority to address retail stranded

costs through their jurisdiction over

facilities used in local distribution.304 It

is therefore important to define what we

believe to be the legal demarcation

between ‘‘transmission in interstate

commerce’’ and ‘‘local distribution,’’ as

used in the FPA. In addition, this

demarcation is important because of the

consequences it will have for the public

utility facilities that will be affected by

the open access requirements being

proposed. We set forth below our

jurisdictional analysis, and technical

factors, for determining what constitutes

‘‘facilities used in local distribution.’’

(13) Stranded Costs in the Context of

Voluntary Restructuring. As we note in

the Open Access NOPR, the functional

unbundling of wholesale services that

we are proposing does not require

corporate unbundling (disposition of

assets to a non-affiliate, or establishing

a separate corporate affiliate to manage

a utility’s transmission assets) in any

form. At the same time, we recognize

that some utilities may ultimately

choose such a course of action. The

Commission is willing to consider casespecific proposals for dealing with

stranded costs in the context of any

restructuring proceedings that may be

instituted by individual utilities.

G. Transmission/Local Distribution

In light of the proposals in both the

Open Access NOPR and the Stranded

Cost Supplemental NOPR, the

Commission believes it is important to

express its views on the distinction

between Commission-jurisdictional

transmission in interstate commerce,

and state-jurisdictional local

distribution, in the context of

unbundled wheeling by public

utilities.305 The distinction is important

for three reasons. First, facilities that

can be used for wholesale transmission

in interstate commerce would be subject

to the Commission’s open access

requirements. It is important that public

utilities and their customers have a good

understanding of which facilities will be

subject to such requirements. Such

understanding will be crucial to

appropriate planning as we enter into

the competitive regime. It is also

important that utilities not be able to

shield themselves from the

Commission’s open access requirements

by claiming that the facilities necessary

to deliver power to a wholesale

purchaser are non-jurisdictional ‘‘local

distribution’’ facilities.

Second, as discussed supra, states

may, through their jurisdiction over

facilities used in local distribution,

impose a surcharge on local distribution

that will permit recovery of stranded

costs resulting from retail wheeling or

retail-turned-wholesale customers.

Providing guidance on the demarcation

between transmission and local

distribution should assure States that

they have the ability to assess stranded

costs on the departing customers. This

should result in more realistic economic

evaluations by retail customers

contemplating leaving via retail

wheeling and/or municipalization.

Third, as the structure of the electric

industry continues to change

dramatically, particularly with the wide

availability of unbundled wholesale

(and perhaps retail) services to deliver

power and the potential for various

forms of voluntary corporate

unbundling, utilities need to know

which regulator has jurisdiction over

which facilities in order to meet State

and Federal statutory filing

requirements.

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 directly 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, 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.306

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

state-jurisdictional 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 (FPA)

Provisions

The Commission’s jurisdiction is set

forth in section 201 of the FPA.307

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.308

Section 201(c) provides that:
17712 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

309 16 U.S.C. 824(c).

310 16 U.S.C. 824b (emphasis added).

311 16 U.S.C. 824e(d) (emphasis added).

312H.R. Rep. No. 1318, 74th Cong., 1st Sess. 7–

8 (1935).

313 Id. at 27.

314S. 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.’’)

315 Id. at 19.

316 Id. at 48. The provisions of the Senate bill

regarding federal jurisdiction over generating

facilities were eliminated from the final version of

the bill.

317H.R. Conf. Rep. No. 1903, 74th Cong., 1st Sess.

74 (1935).

318Pub. L. 100–473, 102 Stat. 2299 (1988).

319S. Rep. No. 621, 74th Cong., 1st Sess. 51 (1935)

(emphasis added).

320H.R. Rep. No. 1318, 74th Cong., 1st Sess. 29

(1935) (emphasis added).

321The 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.

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.309

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.310

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.311

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 Public Utilities

Commission v. Attleboro Steam & E. Co. (273

U.S. 83 [(1927)]) [(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.312

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.313

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.314

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.315

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.316

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.317

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 1988,318 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.319

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.320

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.321
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17713

322 319 U.S. 61 (1943) (Jersey Central).

323Section 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.

324 Jersey Central, 319 U.S. at 63–65.

325 Id. at 66.

326 Id. at 67 (citation omitted).

327 Id. at 73.

328 273 U.S. at 86, 89–90.

329 319 U.S. at 71 (footnote omitted).

330 324 U.S. 515 (1945) (CL&P).

331 Id. at 517.

332 Id. at 518.

333 Id. at 521.

334 Id. at 522.

335 Id. at 519–21.

336 Id.

337 Id. at 522, quoting Connecticut Light & Power

Co. v. FPC, 141 F.2d 14, 18 (D.C. Cir. 1944).

338 324 U.S. at 529.

339 Id. at 529–31.

340 Id. at 531.

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 Power & Light

Company v. Federal Power Commission

(Jersey Central) 322 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) 323 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.324

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.’’ 325 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.’’ 326 Therefore, the

Court found that Jersey Central was a

public utility within the meaning of

section 201(e).327 The

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.328 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.329

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.

Connecticut Light & Power Company

v. Federal Power Commission (CL&P),330

which was decided two years after

Jersey Central, is the leading case

interpreting 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).331 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) 332

and did not interconnect with any other

company that operated out of state.333

‘‘Its purchases and sales, its receipts and

deliveries of power, [were] all within

the state.’’ 334 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.’’ 335 The Commission based its

jurisdiction on these few transactions.336

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.337

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.’’ 338 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.339]

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.’’ 340

The Court stated that whether or not

local distribution facilities carried outof-state electric energy was irrelevant.

Whatever the origin of the electric

energy they carried, so long as the

utility used the lines for local
17714 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

341 It appears that while the Company received

power (at one location) at 66 kV, it primarily owned

facilities at 13.8 kV and below.

342 324 U.S. at 531.

343 Id. at 531 (emphasis added).

344 Id. at 534.

345See 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.

346 Id. at 536.

347 197 F.2d 472 (7th Cir. 1952), cert. denied, 345

U.S. 934 (1953) (Wisconsin-Michigan).

348 Id. at 474.

349 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.’’).

350 197 F.2d at 476 (emphasis added).

351See 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).

352See 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 * * *’’).

353 197 F.2d at 477.

354 Id., citing FPC v. East Ohio Gas Co., 338 U.S.

464 (1950) (East Ohio).

distribution,341 they were exempt from

federal jurisdiction. 342 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.343

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.344

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 533.345

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.346

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, 347 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.* * * ’’ 348

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.349

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.[350]

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 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.351 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.352

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

does the local distribution facilities first

become operative.’’353 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. [354]

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
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17715

355 376 U.S. 205 (1964) (Colton).

356The 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.

357 Id. at 208, 209 & n.5.

358 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.’’).

359 Illinois Natural Gas Co. v. Central Illinois

Public Service Co., 314 U.S. 498, 504 (1942).

360 376 U.S. at 214.

361 Id. at 215–216.

362 Id. at 216 (footnote omitted).

363 Id. at 210 n.6 (citation omitted).

364 Id. at 210 n.6.

365 401 F.2d 930 (D.C. Cir. 1968) (Duke).

366 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.

367 401 F.2d at 938–39 (emphasis added, footnotes

omitted).

368 Id. (footnote omitted).

369 Id. at 949 (footnotes omitted).

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),355 the Supreme Court

held that the FPA provides a clear line

of demarcation between jurisdictional

transactions and non-jurisdictional

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.356 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.357 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.358 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,359 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.’’ [360]

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. [361]

The Court held that ‘‘[t]here is no such

exception covering the Edison-Colton

sale.’’ 362

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. [363]

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.364

In Duke Power Company v. Federal

Power Commission (Duke), 365 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 offcampus 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.366 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.[367]

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.[368]

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-by-case basis. Quoting from

Colton, the court stated:

[T]his ‘‘flexible approach’’—involving as it

does the consideration, inter alia, of ‘‘the

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 caseby-case analysis,’’ in distributing regulatory

power over the acquisition of facilities.369

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
17716 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

370 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)).

371 404 U.S. 453, reh’g denied, 405 U.S. 948 (1972)

(Florida Power & Light).

372 404 U.S. at 456.

373 Id. at 456.

374A ‘‘bus’’ is a connector or group of connectors

that serves as a common connection for two or more

circuits.

375 404 U.S. at 457.

376 Id.

377 Id. at 457 & n.8.

378 Id. at 461. (emphasis omitted).

379 Id. at 461 n.10. (emphasis added).

380See Section 201(d), 16 U.S.C. § 824(d) (1988).

381Public 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).

382Courts 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).

383 15 U.S.C. 717(b) (emphasis added).

384H.R. Rep. No. 709, 75th Cong., 1st Sess. 3

(1937); S. Rep. No. 1162, 75th Cong., 1st Sess. 3

(1937).

interstate in character, should be

handled locally and should receive the

consideration of local [officials] familiar

with the local conditions in the

communities involved.’’370

Federal Power Commission v. Florida

Power & Light Company 371 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.372 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.).373 In

turn, Florida Power Corp. connected

with Georgia Power Company (Georgia

Power) at a ‘‘bus’’ 374 south of the

Georgia-Florida border.375 Florida Power

Corp. regularly exchanged power with

Georgia Power.376 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.377 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.’’ 378 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 * * *.’’ 379

There is also a line of cases that

address, among other things, what

constitutes a Commission jurisdictional

‘‘sale of electric energy at wholesale’’ 380

under section 201 of the FPA.381 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.382

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.383

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). [ 384]

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
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17717

385 338 U.S. at 469–70.

386See 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.

387See Public Utilities Commission of the State of

California v. FERC, et al., 900 F.2d 269, 273 (D.C.

Cir. 1990) (footnote omitted) (WyCal).

388 Id. at 276.

389 Id. (emphasis in original).

390 955 F.2d 1412, 1414 (10th Cir. 1992).

391Unlike 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).

392Cascade, 955 F.2d at 1421.

393 345 U.S. at 316 (footnote omitted).

394The 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.

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 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 high-pressure pipelines

transporting the gas to the local

mains.’’ 385

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.386 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.’’ 387 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.388

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.389

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 * * *.’’ 390 To reach the

interstate pipeline, the industrials

constructed a nine-mile pipeline.

Together, the facilities bypassed the

local distribution company.391

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.392

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.’’ 393

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.394 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), this does not appear to be
17718 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

395 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.

396The 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.

397Such uncertainty could adversely impact on

utilities’ cost of capital. Moreover, case-by-case

implementation would result in a patchwork of

open access around the country until the process

is complete. This patchwork of conflicting

requirements could inhibit the timely transition to

competitive markets—a result directly at odds with

the objectives of this proceeding.

398As noted infra, we will address in a separate

document the application of the proposed rule to

public utilities who have open access proceedings

pending before the Commission.

399Electrical District No. 1, et al. v. FERC, 774

F.2d 490 (D.C. Cir. 1985).

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).

There are several indicators that we

propose to evaluate in determining

whether particular facilities are

transmission or local distribution in the

case of vertically integrated

transmission and distribution

utilities. 395

• 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.396

In summary, for unbundled wholesale

wheeling we will apply a 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 we

will apply a combination functionaltechnical test that will take into account

technical characteristics of the facilities

used for the wheeling. In most, if not all,

circumstances in this situation, we

expect there to be local distribution

facilities. To assist states in dealing with

stranded costs resulting from retail

wheeling, we will make every attempt to

expedite a decision if a state requests

clarification concerning whether certain

facilities are local distribution facilities.

By clarifying the tests the Commission

will apply to determine if facilities used

to deliver unbundled electric energy are

FERC-jurisdictional or statejurisdictional, we believe we have

facilitated the ability of this

Commission and, importantly, state

commissions to assess legitimate

stranded costs to customers who leave

their existing suppliers’ systems. The

application of these tests means that

states will be able to address stranded

costs by imposing an exit fee on

departing retail customers, or including

an adder in the retail customers’ local

distribution rates.

H. Implementation

Because the proposed requirements in

the Open Access NOPR are aimed at

eliminating undue discrimination in the

provision of transmission services in

interstate commerce, and at achieving

competitive bulk power markets for the

benefit of electricity consumers, our

preliminary view is that open access

tariffs should be in place as soon as

possible. Very simply, we would not

want to delay a program which we

expect to produce significant ratepayer

benefits over time. We also would want

to provide procedures and guidance for

stranded cost recovery as soon as

possible in order to complete the

transition from a tightly-controlled costof-service regulatory regime to the

competitive regime we expect in the

very near future.

To those ends, we propose

implementation procedures that the

Commission currently believes will be

appropriate for non-discriminatory open

access transmission and stranded

(transition) cost recovery. These

proposed implementation procedures

attempt to balance the goals of: Placing

good open access tariffs into effect as

soon as possible; supporting the

transmission pricing flexibility

permitted by our Transmission Pricing

Policy Statement; and providing for

implementation that is administratively

feasible for utilities, customers, and the

Commission.

With respect to open access, we

currently estimate that about 137 public

utilities would be required to have on

file non-discriminatory open access

tariffs if the Commission adopts a final

rule.

If the Commission were to employ

traditional filing procedures in

implementing an open access regime,

we could attempt to streamline the

process by, for example, relying, where

appropriate, on paper hearing

procedures and technical conferences

and summarily disposing of the

maximum number of issues possible.

Nevertheless, we would still expect

delays (and attendant uncertainty)

measured in years.397 As a result, we

propose a two-stage procedure to put in

place without delay basic open access

tariffs. We believe this procedure will

ensure non-discriminatory open access

transmission services that would: (1)

Satisfy most utilities and customers; and

(2) provide a framework for utilities to

subsequently submit novel proposals

that they believe to be better tailored to

their individual circumstances. We

request comments on all aspects of the

proposed procedure, including the

proposed generic tariffs discussed infra.

1. Two-Stage Implementation Process

Stage One

The Commission proposes to put into

effect (not subject to refund) for every

public utility that owns and/or controls

transmission facilities, pursuant to

section 206 of the FPA, generic tariffs

providing network transmission

services, firm and non-firm point-topoint transmission services, and

ancillary services necessary to effect

network and point-to-point service.398

The Commission proposes to specify the

rates, terms, and conditions in the final

rule and to put all such tariffs into effect

simultaneously on a date certain—12:00

midnight 60 days after the effective date

of the final rule.

The proposed network and point-topoint tariffs contained in Appendices B

and C establish the minimum terms and

conditions which we believe are

necessary to eliminate undue

discrimination in the transmission of

electric energy in interstate commerce.

We propose to place these terms and

conditions into effect for each affected

public utility.

Although the proposed generic tariffs

contain the minimum terms and

conditions of service that is not unduly

discriminatory, they do not contain

specific rates. However, section 206(a)

of the FPA requires the Commission to

fix by order the just and reasonable

rate.399 We therefore propose to

establish and set forth in the final rule,

for each affected public utility, just and

reasonable rates for network service,

point-to-point service, and six identified

ancillary services. We propose to
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17719

establish such rates using the most

current Form No. 1 data available for

each public utility, and to incorporate

them into the generic tariffs for each

affected public utility.

While the rates we will calculate

using Form No. 1 data will be postage

stamp rates, we wish to emphasize that

utilities are free in Stage Two to propose

immediately and support nontraditional conforming, as well as nonconforming, transmission pricing

proposals consistent with the

Commission’s Transmission Pricing

Policy Statement. The proposed

calculation of these rates is discussed in

detail infra.

Customers will be able to rely on

existing contracts for transmission

service until such contracts expire or are

otherwise terminated. While customers

will be able to use the generic tariffs and

any revised tariffs established in Stage

Two for new or additional services, we

do not propose to allow customers to

seek termination of their existing

transmission arrangements in order to

use the generic or subsequently revised

tariffs, unless such filings are

contractually authorized or shown to be

in the public interest. Of course, to the

extent that such filings are contractually

authorized, the Commission must still

determine whether the termination of

such existing transmission arrangements

is just and reasonable, based upon the

circumstances presented.

The above procedures would apply to

individual public utility open access

tariffs. However, many public utilities

transact under jurisdictional power

pooling agreements. As discussed

herein, power pools would have to

comply with the non-discrimination

requirements of the Open Access NOPR

by making power pool transmission

services available to all wholesale

transmission customers and offering

services at rates, terms, and conditions

that are not unduly discriminatory.

However, power pools raise complex

issues and the Commission cannot at

this time develop compliance tariffs for

power pools. Therefore, we seek

comments on how to implement the

NOPR for power pools. After we have

received comments on this matter, and

before a final rule is adopted, we intend

to hold technical conferences with

power pools to discuss implementation

issues. After holding these technical

conferences, and taking into account the

comments received in the Open Access

NOPR proceeding as well as in our

pending Notice of Inquiry on

Alternative Power Pooling Institutions,

we will issue a supplemental order

directing compliance for power pools.

Stage Two

The Commission proposes that Stage

Two begin 61 days after the date the

final rule becomes effective. On and

after that date, public utilities may

propose changes to the rates, terms, and

conditions in the generic tariffs

pursuant to section 205 of the FPA and

Part 35 of the regulations. In addition,

customers and others may file

complaints pursuant to section 206 of

the FPA seeking changes in the rates,

terms, and conditions in the generic

tariffs. We note, however, that Stage

Two tariffs must contain at least the

non-price tariff terms and conditions

contained in the pro forma tariffs.

Moreover, customers (or potential

customers) dissatisfied with the generic

tariffs may file section 211 applications

at any time (i.e., before Stage Two).

We are hopeful that the generic tariffs

will initially be acceptable to large

numbers of utilities and their customers.

Because we expect our Stage One tariffs

to be satisfactory for the immediate

needs of many transmission providers

and customers, we would expect Stage

Two proposals to be staggered

somewhat, permitting us to process and

reach final decisions more quickly on

subsequent proposals to revise the

generic tariffs.

We propose to require any utility

seeking to modify the generic tariffs in

Stage Two to file, in addition to the

other requirements specified in the

regulations, an original and 14 copies of

the revised tariffs showing any changes

proposed by means of highlighting and

striking out. In addition, we propose

that the utilities also file two copies of

such changes on diskette in ASCII

format.

2. Calculations of Stage One Rates

Because most utilities currently use

embedded cost pricing for the

transmission component of their own

power sales and purchases, and because

the Commission’s Transmission Pricing

Policy Statement requires comparability

between transmission rates and the

transmission pricing component of

those power sales and purchases, the

Commission proposes to establish rates

for the generic tariffs based on

embedded cost principles. However,

these tariffs will include a provision

that allows the transmission provider to

file unilateral changes in all rates, terms,

and conditions any time after the

effective date of the generic tariffs (Stage

Two filings). However, as we noted

above, the minimally acceptable tariff

terms and conditions in Stage Two will

be the terms and conditions established

in Stage One.

We emphasize that utilities and

customers have discretion under the

Commission’s Transmission Pricing

Policy Statement to pursue other types

of rate treatments, and that they may file

a proposal any time after the generic

tariffs become effective. For example,

Stage Two filings could include:

• A filing by the public utility under

section 205 amending the generic tariff

in a limited respect, such as a change in

the loss factor, a change in the

embedded cost unit charge,

implementing an option to charge an

incremental cost rate, including

opportunity cost, when capacity is

constrained, or the addition of another

ancillary service.

• A filing by the public utility under

section 205 proposing an entirely new

rate method such as a zone or distance

based transmission rate. The generic

tariff would constitute a conforming

open access transmission tariff, but

revised tariff filings could also include

nonconforming proposals.

• A complaint by a customer (or

potential customer) under section 206

seeking limited changes to the generic

tariff, such as a change in the loss factor,

a change in the embedded cost unit

charge, or the addition of another

ancillary service.

• A complaint by a customer (or

potential customer) under section 206

proposing an entirely new rate method.

We expect that, for many transmission

providers and customers, the Stage One

tariffs will satisfy their immediate

needs. For example, a customer might

believe that it could demonstrate in a

section 206 proceeding that a lower rate

is appropriate, but decide the monetary

impact is not sufficient to justify the

filing of a complaint because its current

needs are small or because the expected

rate reduction is slight. In this situation,

the customer may delay raising

objections to the Stage One tariffs until

the company files its next general rate

case. Also, a company might believe

that it could demonstrate that a higher

rate is reasonable, but decide that its

resources are best spent

comprehensively designing a Stage Two

non-traditional tariff, such as, a distance

sensitive rate, a non-conforming

proposal, or a spin-off of transmission

assets into a separate company.

Similarly, companies negotiating

regional transmission tariffs may decide

to devote their resources to that project

rather than fine tuning their company

specific rates.

If we had not proposed this two-stage

process and simply directed the filing of

company specific tariffs, utilities and

customers would have been forced to

proceed on an inflexible schedule. In
17720 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

405Commonwealth Edison Company, 64 FERC

¶ 61,253 (1993). 406See supra, 67 FERC at 61,481.

addition, parties may have felt

pressured to file proposals prematurely

out of concern that a failure to do so

would prejudice their ability to initiate

them later. We believe that industry

participants are better served by a

process that, in addition to avoiding the

delay inherent in a series of separate

section 206 compliance filings, allows

affected parties to raise these complex

issues when it best meets their needs

and after taking whatever time is

necessary to evaluate non-traditional

alternatives.

The Commission proposes to establish

the rates for Stage One tariffs as follows:

Derivation of the Embedded Cost

Transmission Charge for Point-to-Point

Service

To establish firm point-to-point

transmission charges, the Commission

proposes to use the fixed charge

methodology that it uses to evaluate rate

schedule filings. This methodology is

available to the public on the

Commission’s Electric Power Data

Bulletin Board and has been referenced

in various proceedings before the

Commission.400

Form No. 1 data are used to develop

the cost relationship between fixed

transmission costs and transmission

plant investment (a fixed charge rate).

The unit charge is calculated by: (1)

Dividing plant investment by capability,

using the annual system peak as a proxy

for capability; 401 and (2) multiplying the

result by the fixed charge rate. All data

would be taken from the Form No. 1

except the return on equity.

For the equity return, the Commission

proposes to use an industry-wide return

calculated using the Commission’s

standard discounted cash flow (DCF)

analysis of company specific dividend

yields and an industry average constant

growth rate.402 As an alternative, the

Commission could use its DCF method

to compute company specific equity

returns. However, this is not likely to

change materially the Stage One rates

(e.g., a 1% change in the equity return

would change the monthly charge by

about $.08/kW/month, equivalent to an

hourly charge of 0.1 mill/kWh). We

invite comments on this issue.

We also propose an alternative rate

treatment and we ask for comment on

which we should adopt for all affected

public utilities. The alternative is a

variation of our fixed charge rate

method. Under our alternative proposal,

the Commission would multiply an

industry-wide transmission fixed charge

rate by the company-specific investment

cost per kW from the Form No. 1.403

This would simplify the process. In our

experience, differences in unit charges

among companies are due primarily to

differences in investment cost per kW of

capability and not the fixed charge rate.

We note that we adopted a similar

approach in developing cost-based

ceiling rates for the WSPP, although we

developed a single composite rate for

WSPP services.

The following illustrates the

computation of a specific Stage One

point-to-point transmission charge for

three utilities using the alternative

proposal and 1993 Form No. 1 data,

Dayton Power & Light Company

(Dayton), Louisville Gas & Electric

Company (LGE), and Minnesota Power

& Light Company (MPL):

(1)

Company

(2)

Transmission

plant in service

(3)

System peak

(4)

Annual charge

(000) MW (2)/(3)×17.5%

(1) Dayton .............................................................................................................................. $247,186 2,765 $15.64/kW

(2) LGE ................................................................................................................................... 173,836 2,239 13.59/kW

(3) MPL .................................................................................................................................. 162,656 1,252 22.74/kW

Under either alternative, the final rule

would establish specific unit charges.

Charges for shorter term services would

be derived from the annual charge using

standard Commission methods:

Monthly Charge = Annual Charge/12

Weekly Charge = Annual Charge/52

Daily Charge = Weekly Charge/5

Hourly Charge = Daily Charge/16

Revenues for daily and hourly service

would be capped at the equivalent

weekly and daily rates pursuant to our

standard requirements.404

400See, e.g., Western Systems Power Pool (WSPP),

55 FERC ¶ 61,099 (1991); Jersey Central Power &

Light Company, 38 FERC ¶ 61,275 (1987); and

UtiliCorp United Inc., 70 FERC ¶ 61,149 (1995).

401The Commission consistently requires this

method for non-customer specific rates such as this.

See, e.g., American Electric Power Service

Company, 67 FERC ¶ 61,168 (1994); Kentucky

Utilities Company, 67 FERC ¶ 61,189 (1994).

402An industry-wide return on equity calculated

using this method would currently yield a return

of about 11%.

403Based on analyses prepared by the

Commission’s staff to support acceptance of filings

tendered by utilities during the last two years, a

representative transmission fixed charge rate is

17.5%. The Form No. 1 data used to compute a

company specific investment cost per kW of load

is found at Page 207, line 69, column g (end of year

plant transmission plant in service) and Page 401,

column D (system peak load) of the Form No. 1.

404See Appalachian Power Company, et al., 39

FERC ¶ 61,296 at 61,965 (1987); WSPP, supra, 55

FERC at 61,321.

We propose to establish ceiling rates

for non-firm service equal to the firm

rates, consistent with industry practice.

As a practical matter, there is generally

a charge for non-firm service only in the

hours when energy is scheduled and,

therefore, non-firm service is provided

at a discount from firm service, which

is generally subject to a charge based on

reservations without regard to actual

usage. As we have emphasized in the

past, we expect that a rate for firm

service will be higher than a rate for

another service that differs only in the

degree of firmness.405 We also expect

that such discounts will be offered on a

non-discriminatory basis to all

customers and that customers will have

sufficient information about the

availability of discounts (e.g., through

an information network).

Derivation of Embedded Cost Charge

for Network Service

To establish network transmission

charges, the Commission proposes to

adopt the load ratio method we

approved in Florida Municipal Power

Agency.406 Under this approach, the

company’s annual transmission costs

(the product of column (2) in the table

above for point-to-point service and the

same fixed charge rate used to develop

the point-to-point rates) are multiplied

by a load ratio percentage. The load

ratio reflects the average of the 12

monthly customer coincident peaks

divided by the average of the 12

monthly total system peaks. Total

monthly system peaks for this

calculation would reflect all firm uses of

the transmission system, including the

transmission owners’ own long term
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17721

407 5 U.S.C. 601–612.

408 5 U.S.C. 601(3) (citing section 3 of the Small

Business Act, 15 U.S.C. 632). Section 3 of the Small

Business Act defines a ‘‘small-business concern’’ as

a business which is independently owned and

operated and which is not dominant in its field of

operation. 15 U.S.C. 632(a).

409 18 CFR Part 380.

410 18 CFR 380.4(a)(15).

411 5 CFR 1320.13.

firm and unit power sales. We shall

specify the annual revenue requirement

in the generic tariff and direct the

transmission provider to insert the load

ratio computation into the service

agreement when filed after a request for

service is accepted by the utility.

Derivation of the Charges for Ancillary

Services

Loss Compensation

The Commission proposes to establish

a loss factor of 3% and a charge for

energy losses equal to 110% of seller’s

incremental cost. A 3% loss factor is

representative of those in transmission

agreements on file and a loss

compensation charge based on the

seller’s incremental cost is also

common.

Energy Imbalances

The Commission proposes to establish

an hourly deviation band of +/- 1.5%

with a minimum of 1 MW per hour and

imbalances within this band would be

returned in kind or subject to a charge

equal to seller’s incremental cost (or a

payment equal to decremental cost if the

public utility transmission provider

receives too much energy and must

compensate the transmission customer).

Energy imbalances outside this band

would be subject to a charge of 100

mills/kWh, the standard industry rate

for emergency service. We propose the

emergency service charge for this

purpose because, as with emergency

service, the rate should provide an

incentive to minimize energy

imbalances. We seek comment on the

size of the deviation band and size of

the imbalance charge.

Scheduling & Dispatching Charges

The Commission’s fixed charge rate

methodology which will be used to

establish the transmission charge

includes Account No. 566, where the

costs of transmission related scheduling

and dispatching are booked.

Accordingly, the generic tariffs would

include no separate charge for

scheduling and dispatching. This

should be adequate for most

transmission services because most

customers are likely to require this

scheduling and dispatching service. If a

customer does not require this service,

it may propose a different rate treatment

by filing a complaint at Stage Two.

Other Charges

The other ancillary services—Load

Following, System Protection, and

Reactive Power—have a common

attribute. They all involve the cost

incurred by the transmission provider as

a result of using generation facilities to

support the transmission service. In the

past, some or all of these services were

often provided at a rate reflecting

embedded transmission costs, i.e.,

without a separate charge reflecting the

cost of generation facilities. However,

the Commission has allowed a 1 mill/

kWh charge for difficult to quantify

costs that served to compensate

transmission providers for costs like

these. We propose, for purposes of the

Stage One tariffs, to maintain a ceiling

of 1 mill/kWh as the charge for these

three ancillary services on a combined

basis. We would expect that the parties

would negotiate charges below this

ceiling if the customer can provide some

or all of these ancillary services and that

this would be filed as a change in Stage

Two. We emphasize that, if a utility

believes that a 1 mill/kWh charge is

unsatisfactory, it may file to revise the

charge under section 205 in Stage Two.

Similarly, if a customer finds a 1 mill/

kWh charge unsatisfactory, it may file a

complaint in Stage Two.

Questions

We invite comments on which of the

methodologies we should adopt. For

example, we are interested in

commenters’ preference for the first

alternative, which uses company

specific Form No. 1 data for all inputs,

or the second alternative, which uses

company specific Form No. 1 data only

for investment and load. With respect to

the first alternative, we seek comments

on our proposal to use an industry-wide

equity return for each affected public

utility and, with respect to the second

alternative, we seek comments on our

proposed uniform 17.5% transmission

fixed charge rate. We also seek

comments as to whether a more specific

definition of the load ratio should be

adopted, and whether this ratio can be

used fairly in all situations. We also

invite comments on our proposals for

ancillary service charges. All comments

should take into account our intention

to immediately put in place generic

tariffs so that there will be no delay in

the availability of nondiscriminatory

open access transmission services.

3. Ongoing Proceedings

There are currently a number of

ongoing proceedings in which the

Commission is investigating utilities’

open access tariff filings. Concurrently

with this order, the Commission is

issuing a separate order concerning

those cases.

IV. Regulatory Flexibility Act

The Regulatory Flexibility Act

(RFA) 407 requires that rulemakings

contain either a description and analysis

of the effect the proposed rule will have

on small entities or a certification that

the rule will not have a substantial

economic effect on a substantial number

of small entities. Because the entities

that would be required to comply with

the proposed rule are public utilities

and transmitting utilities that do not fall

within the RFA’s definition of small

entities,408 the Commission certifies that

this rule will not have a ‘‘significant

economic impact on a substantial

number of small entities.’’

V. Environmental Statement

The Commission concludes that

promulgating the proposed rule would

not represent a major federal action

having a significant adverse impact on

the human environment under the

Commission’s regulations implementing

the National Environmental Policy

Act.409 The proposed rule falls 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.410 Consequently, neither an

environmental assessment nor an

environmental impact statement is

required.

VI. Information Collection Statement

The Office of Management and

Budget’s (OMB) regulations 411 require

that OMB approve certain information

and recordkeeping requirements

imposed by an agency.

The information collection

requirements in the proposed

regulations are contained in FERC–516,

‘‘Electric Rate Filings’’ (OMB approval

No. 1902–0096). The Commission uses

the data collected in this information

collection to carry out its

responsibilities under Part II of the FPA.

The Commission’s Office of Electric

Power Regulation uses the data to

review electric rate filings. The data

enable the Commission to examine and

evaluate the utility’s costs and rate of

return.

The Commission is submitting

notification of this proposed rule to

OMB. Interested persons may obtain
17722 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

information on the reporting

requirements by contacting the Federal

Energy Regulatory Commission, 941

North Capitol Street, NE., Washington,

DC 20426 [Attention: Michael Miller,

Information Services Division, (202)

208–1415]. Comments on the

requirements of the proposed rule can

also be sent to the Office of Information

and Regulatory Affairs of OMB

[Attention: Desk Officer for Federal

Energy Regulatory Commission].

VII. Public Comment Procedures

The Commission invites comments on

the proposed rule from interested

persons. An original and 14 copies of

written comments on the proposed rule

must be filed with the Commission no

later than August 7, 1995.

The Commission will also permit

interested persons to submit reply

comments in response to the initial

comments filed in this proceeding.

Reply comments should be submitted

no later than October 4, 1995.

In addition, commenters are requested

to submit a copy of their comments on

a 31⁄2 inch diskette formatted for MS–

DOS based computers. In light of our

ability to translate MS–DOS based

materials, the text need only be

submitted in the format and version that

it was generated (i.e., MS Word,

WordPerfect, ASCII, etc.). It is not

necessary to reformat word processor

generated text to ASCII. For Macintosh

users, it would be helpful to save the

documents in Macintosh word

processor format and then write them to

files on a diskette formatted for MS–

DOS machines. All comments should be

submitted to the Office of the Secretary,

Federal Energy Regulatory Commission,

825 North Capitol Street, NE.,

Washington, DC 20426, and should refer

to Docket Nos. RM95–8–000 and RM94–

7–001.

All written comments will be placed

in the Commission’s public files and

will be available for inspection in the

Commission’s public reference room at

941 North Capitol Street, NE.,

Washington, DC, 20426, during regular

business hours.

List of Subjects in 18 CFR Part 35

Electric power rates, Electric utilities,

Reporting and recordkeeping

requirements.

By direction of the Commission.

Commissioner Massey concurred in part

and dissented in part with a separate

statement attached.

Lois D. Cashell,

Secretary.

In consideration of the foregoing, the

Commission proposes to amend part 35,

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 [INSERT DATE

90 DAYS AFTER THE FINAL RULE IS

PUBLISHED IN THE FEDERAL

REGISTER]; or

(ii) If unexecuted, filed with the

Commission prior to [INSERT DATE 90

DAYS AFTER THE FINAL RULE IS

PUBLISHED IN THE FEDERAL

REGISTER].

(2) Any power sales contract executed

on or after [INSERT DATE 90 DAYS

AFTER THE FINAL RULE IS

PUBLISHED IN THE FEDERAL

REGISTER] 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 cancellation or

termination of such contract within 30

days after such cancellation or

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:

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 contract means any contract

executed after July 11, 1994, or
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17723

extended or renegotiated to be effective

after July 11, 1994.

(8) Existing contract means any

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) 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 through 206 of the FPA. The public

utility may not seek recovery of such

costs through any transmission rate for

section 205 or 211 transmission

services.

(iii) 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.

(iv) 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 existing

contract seeks a stranded cost

amendment pursuant to a section 205 or

section 206 filing 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

section 205 rates for electric energy.

(B) If the existing contract is not

amended to permit recovery of stranded

costs as described in paragraph

(c)(1)(iv)(A) of this section, the public

utility may file a proposal, prior to the

expiration of the contract, to recover

stranded costs through section 205 or

section 211 through 212 rates for

wholesale transmission services to the

customer.

(v) If wholesale stranded costs are

associated with an existing wholesale

requirements contract, if the seller

under such contract is a transmitting

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

section 211 through 212 transmission

rates.

(vi) 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 section

205 or section 211 through 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)(iv) through (vi) 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) it has taken and will take

reasonable measures to mitigate

stranded costs.

(3) Rebuttable Presumption. If a

public utility or transmitting utility

seeks recovery of wholesale stranded

costs associated with an existing

contract, as permitted in paragraph

(c)(1) of this section, and the existing

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.

(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;

(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; and

(iii) it has taken and will take

reasonable measures to mitigate

stranded costs.

§ 35.27 Power sales at market-based rates.

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 [INSERT DATE 30 DAYS AFTER

THE FINAL RULE IS PUBLISHED IN

THE FEDERAL REGISTER].

§ 35.28 Non-discriminatory open access

transmission tariffs.

(a) Every public utility owning and/or

controlling facilities used for the

transmission of electric energy in

interstate commerce must have on file

with the Commission no later than

[INSERT DATE 90 DAYS AFTER THE

FINAL RULE IS PUBLISHED IN THE

FEDERAL REGISTER] tariffs of

generally applicability for transmission

services, including ancillary services,

over these facilities on both a point-topoint basis and network basis consistent

with the requirements of Order No.

lll (Final Order on Open Access and

Stranded Costs).

(b) Every public utility owning and/or

controlling facilities used for the

transmission of electric energy in

interstate commerce, but not in

existence on [INSERT DATE THE

FINAL RULE IS PUBLISHED IN THE

FEDERAL REGISTER], must file tariffs

of generally applicability for

transmission services, including

ancillary services, over these facilities

on both a point-to-point basis and

network basis consistent with the

requirements of Order No. lll (Final

Rule on Open Access and Stranded

Costs) no later than the date any

agreement under which such public

utility would engage in a sale of electric
17724 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

energy at wholesale in interstate

commerce or the transmission of electric

energy in interstate commerce is

accepted for filing by the Commission.

(c) Any public utility that owns and/

or controls 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,

must take transmission service for such

sales and/or purchases under the tariffs

filed pursuant to paragraph (a) or (b) of

this section.

Note: Appendix D and Commissioner

Massey’s statement will not appear in the

Code of Federal Regulations.

Appendix D—Docket No. RM94–7–000,

Recovery of Stranded Costs by Public

Utilities and Transmitting Utilities List of

Commenters

1. Ad Hoc Coalition on Environmental and

Consumer Protection (Ad Hoc Coalition),

consisting of Environmental Action

Foundation, Citizen Action, Consumer

Federation of America, Greenpeace,

Toward Utility Rate Normalization,

Public Citizen, Sierra Club, Nuclear

Information & Resource Service,

Economic Opportunity Research

Institute, and U.S. Public Interest

Research Group

2. Alabama Public Service Commission

3. Allegheny Electric Cooperative, Inc.

4. Allegheny Power Service Corporation

(Allegheny Power)

5. American Forest & Paper Association

(American Forest)

6. American Public Power Association

(APPA)

7. American Society of Utility Investors

8. Arizona Public Service Company

9. Arkansas Public Service Commission

10. Atlantic City Electric Company

11. Blue Ridge Power Agency, Northeast

Texas Electric Cooperative, Sam Rayburn

G&T Electric Cooperative and Tex-La

Electric Cooperative (Blue Ridge)

12. California Public Utilities Commission

13. Centerior Energy Corporation

14. Central Maine Power Company

15. Central Vermont Public Service

Corporation

16. Cities of Anaheim, Azusa, Banning,

Colton and Riverside, California

17. City of Las Cruces, New Mexico

18. Coalition For Economic Competition,

consisting of Central Hudson Gas &

Electric Corporation, Consolidated

Edison Company of New York, Long

Island Lighting Company, New York

State Electric & Gas Corporation, Niagara

Mohawk Power Corporation, and

Rochester Gas & Electric Company

19. Coalition of California Utility Employees

20. Colorado Association of Municipal

Utilities

21. Colorado Office of Consumer Counsel

22. Colorado Public Utilities Commission

23. Commonwealth Edison Company

(Commonwealth Edison)

24. Competitive Electric Market Working

Group (Competitive Working Group),

consisting of Electric Clearinghouse, Inc.,

Enron Power Marketing, Inc., and Destec

Power Services, Inc.

25. Conservation Law Foundation

26. Consumer-Owned Utilities in Maine,

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., Union River

Electric Cooperative, Inc., and Van Buren

Light & Power District

27. Consumers Power Company

28. Dairyland Power Cooperative

29. Department of Water and Power of the

City of Los Angeles

30. Detroit Edison Company (Detroit Edison)

31. Direct Action For Rights and Equality

32. District of Columbia Public Service

Commission

33. Duke Power Company

34. Duquesne Light Company

35. Edison Electric Institute (EEI)

36. Electric Consumers’ Alliance

37. Electric Generation Association

38. Electricity Consumers Resource Council,

the American Iron and Steel Institute

and the Chemical Manufacturers

Association (Industrial Consumers)

39. El Paso Electric Company

40. Enron Power Marketing, Inc. (Enron)

41. Entergy Services, Inc. (Entergy)

42. Environmental Action Foundation

(Environmental Action)

43. Environmental Law and Policy Center of

the Midwest

44. Florida Municipal Power Agency,

Michigan Municipal Cooperative Group

and Wolverine Power Supply

Cooperative (Florida and Michigan

Municipals)

45. Florida Power Corporation

46. Florida Public Service Commission

(Florida Commission)

47. Fuel Managers Association

48. Houston Lighting & Power Company

(Houston Lighting & Power)

49. Idaho Public Utilities Commission

50. Illinois Commerce Commission (Illinois

Commission)

51. Illinois Power Company

52. Indiana Office of Utility Consumer

Counselor

53. Indiana Utility Regulatory Commission

(Indiana Commission)

54. Iowa Utilities Board

55. Irrigation and Electrical Districts’

Association of Arizona

56. Land and Water Fund of the Rockies

57. Large Public Power Council

58. Long Island Lighting Company (Long

Island Lighting)

59. Louisiana Energy and Power Authority

60. Maryland Public Service Commission

61. Massachusetts Department of Public

Utilities

62. Metropolitan Edison Company,

Pennsylvania Electric Company and

Jersey Central Power & Light Company

63. Michigan Public Service Commission

Staff

64. Mid-Atlantic Energy Project

65. Municipal Resale Service Customers of

Ohio Power Company

66. National Association of Regulatory Utility

Commissioners (NARUC)

67. National Association of State Utility

Consumer Advocates (NASUCA)

68. National Black Caucus of State Legislators

69. National Independent Energy Producers

(NIEP)

70. National Rural Electric Cooperative

Association

71. New England Power Company

72. New York Mercantile Exchange

73. New York State Electric & Gas

Corporation

74. New York State Public Service

Commission (New York Commission)

75. North Carolina Electric Membership

Corporation

76. North Dakota Public Service Commission

77. Northern States Power Company

78. Nuclear Energy Institute

79. Oglethorpe Power Corporation

80. Ohio Office of the Consumers’ Counsel

81. Ohio Public Utilities Commission (Ohio

Commission)

82. Older Women’s League

83. Omaha Public Power District

84. Pace Energy Project

85. Pacific Gas and Electric Company

86. Pacific Gas and Electric Company and

Natural Resources Defense Council

87. PECO Energy Company

88. Pennsylvania and Massachusetts

Municipals

89. Pennsylvania Power & Light Company

90. Pennsylvania Public Utility Commission

(Pennsylvania Commission)

91. Public Power Council

92. Public Service Company of New Mexico

93. Public Service Electric and Gas Company

(Public Service Electric)

94. Rhode Island Division of Public Utilities

and Carriers and Jeffrey B. Pine, Attorney

General of the State of Rhode Island

95. Rural Utilities Service

96. Sacramento Municipal Utility District

97. San Diego Gas & Electric Company

98. Sierra Pacific Power Company

99. South Carolina Electric & Gas Company

100. Southern California Edison Company

101. Southern Company Services, Inc.

102. Stranded Cost Order Opponent Parties,

consisting of the Delaware Municipal

Electric Corporation, Village of Freeport,

New York, City of Jamestown, New York,

Town of Massena, New York, Modesto

Irrigation District, M–S–R Public Power

Agency, City of Santa Clara, California,

and Southern Maryland Electric

Cooperative, Inc. (SCOOP)

103. Suffolk County Electrical Agency

104. Sunflower Electric Power Corporation

(Sunflower)

105. Tampa Electric Company

106. Tennessee Valley Authority (TVA)

107. Public Utility Commission of Texas

(Texas Commission)

108. Texas Utilities Electric Company

109. Transmission Access Policy Study

Group (TAPS)
Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules 17725

1United Gas Pipeline Co. v. Mobile Gas Service

Corp., 350 U.S. 332 (1956); FPC v. Sierra Pacific

Power Co., 350 U.S. 348 (1956).

110. TDU Customers, consisting of Chicopee

Municipal Lighting Plant of the City of

Chicopee, Massachusetts, Golden Spread

Electric Cooperative, Inc., Holy Cross

Electric Association, Inc., Kansas Electric

Power Cooperative, Inc., Old Dominion

Electric Cooperative, Seminole Electric

Cooperative, Inc., South Hadley Electric

Light Department of the Town of South

Hadley, Massachusetts, and Westfield

Gas and Electric Department of the City

of Westfield, Massachusetts

111. Trigen Energy Corporation

112. United Illuminating Company

113. United States Department of Defense

114. United States Department of Energy

(DOE)

115. United Utility Shareholders Association

of America

116. Utility Investors and Analysts

117. Utility Working Group (consisting of

Dominion Resources, Inc., Duke Power

Company, Duquesne Light Company,

Entergy Corporation, General Public

Utilities Corporation, Niagara Mohawk

Power Corporation, Northern States

Power Company, Pacific Gas and Electric

Company, Portland General Electric

Company, Public Service Electric and

Gas Company, San Diego Gas & Electric

Company, Southern California Edison

Company, and Wisconsin Electric Power

Company)

118. Vermont Department of Public Service

(Vermont Department)

119. Virginia Electric and Power Company

120. Virginia State Corporation Commission

121. Washington Utilities and Transportation

Commission

122. Washington Water Power Company

123. Wheeled Electric Power Company

124. Wisconsin Electric Power Company

125. Wisconsin Power & Light Company

(Wisconsin Power)

126. Wisconsin Public Service Commission

127. Wisconsin Wholesale Customers

128. Wyoming Public Service Commission

Promoting Wholesale Competition Through

Open Access Non-Discriminatory

Transmission Services by Public Utilities

Docket No. RM95–8–000

Recovery of Stranded Costs by Public

Utilities and Transmitting Utilities

Docket No. RM94–7–001

Issued March 29, 1995.

Massey, Commissioner, concurring in part

and dissenting in part:

I. Concurring Opinion

Today, the Commission takes the logical

next step—a bold, aggressive and historic

step—toward full and robust competition in

the electric power industry. Our proposal

will change fundamentally the nature of this

industry, and the relationships among

transmission-owning utilities, their

customers and competing power suppliers.

Why now? An uninformed observer might

think it somewhat startling, at the very least

counterintuitive, that in the current political

climate, at the very same time Congress is

debating a regulatory moratorium, this

Commission issues the most profound

regulatory proposal for the electric utility

industry since the New Deal legislation. Why

now?

There are several compelling reasons. First,

now is always the best time to end undue

discrimination. Federal law ‘‘bristles’’ with

concern about undue discrimination. The

Federal Power Act does not allow this

Commission to tolerate it. There will never

be a better time than now to stop it.

Second, now is also an appropriate time to

eliminate the industry’s uncertainty over our

policy directions. Uncertainty is deeply

unsettling for this industry. Instead of

focusing on how to beat the competition,

industry participants must first speculate

about the future rules of the competition.

This is intolerable in the long term and, in

the short-term, stifles creativity, initiative

and investment. We believe industry

participants will applaud efforts to end the

uncertainty now.

Third, this Commission wants to move

boldly toward customer choice and lighthanded regulation of wholesale generation.

We believe it will bring lower rates. But we

are limited greatly by transmission market

power. We cannot move forcefully in these

directions if transmission owners are able to

skew the market and eliminate competition

by denying or delaying transmission access,

or by offering inferior terms and conditions

for transmission service. The current

patchwork of transmission access impedes

competition. We must move beyond

voluntary open access tariffs and timeconsuming and expensive case-by-case

rulings on wheeling requests. Now is the

time to eliminate the transmission market

power of the utilities over which we have

jurisdiction. How can there be truly robust

competition if buyers and sellers can’t reach

each other? Those who believe in

competition and lower rates will applaud

this step.

And, fourth, we cannot move to new rules

without assuring utilities that they will

recover the costs they prudently incurred

under the old rules. That is a fundamental

principle of our NOPR. We must strive to

eliminate the uncertainty in the industry over

the way in which this Commission will

address stranded cost issues. Now is the time

to speak clearly on this critical issue.

For these reasons, now is not only an

appropriate time, but may indeed be the best

time to take this bold step toward truly

robust competition. It is my fervent hope that

the market-based solutions this proposal

portends, and the giant step it takes toward

eliminating industry uncertainty over policy

directions and stranded cost recovery, will

strike a responsive chord among lawmakers,

other policy makers, and others who care

about the future of this important industry.

I strongly support virtually all of this

NOPR. The NOPR addresses dozens of open

access and stranded cost issues in ways that

have my wholehearted support.

For example, I agree strongly with the

proposed requirements of open access tariffs.

It is one thing to state somewhat blithely that

we favor the golden rule of transmission

access. That is about all we have said so far.

It is another thing entirely, and much more

valuable to industry participants, to put real

meat on the bones of comparability. The

extensive text of the order accomplishes this

objective, with unparalleled clarity. In fact,

this entire document is a persuasive,

compelling, technically brilliant work.

Let me highlight three specific issues. First

is the issue of the NOPR’s effect on regional

transmission groups. Some in the industry

may erroneously conclude that this

rulemaking will lessen the value of, and need

for, RTGs. The order emphatically disagrees.

As the order states:

RTGs are structures to reflect the interest

of all of the grid’s users, not just some. RTGs

allow for consensual solutions to local or

regional issues, instead of solutions imposed

by FERC. RTGs can function as regional

laboratories for experimentation on

transmission issues. And, RTGs will provide

a regional forum, a necessary predicate to

regional cooperation.

In short, RTGs remain a key part of our

vision of the future of this industry.

Second, the NOPR requires the new tariffs

to include a reciprocity provision. This

provision would ensure that a public utility

offering transmission access to others can

obtain similar service from its transmission

customers. If customers want access on a

public utility’s transmission wires, they must

be willing to offer access for the utility on

their own transmission wires. That is only

fair.

Third, the NOPR would require functional

unbundling of public utilities’ jurisdictional

services. That is, utilities would be required

to take transmission service (including

ancillary services) for new wholesale sales

and purchases of electric energy under the

open access tariffs. The tariffs also must state

separately the rates for each type of

transmission or ancillary service. This

requirement of functional unbundling will

give public utilities the incentive to offer

service on fair terms and conditions, since

the public utility will have to live with the

same terms and conditions it proposes for

others.

Now let me turn to an issue involving

symmetry of rights between customers and

utilities. Today’s order makes an explicit

generic finding that it is in the public interest

to allow utilities to make filings at FERC for

the recovery of stranded costs even if their

contracts contain so-called Mobile-Sierra

restrictions that would bar such filings. 1 I

fully agree with this conclusion. I believe the

policy rationale justifying the recovery of

stranded costs is so strong that the public

interest test is met and such a generic finding

is necessary.

I have some concern, however, about the

fact that today’s order does not sufficiently

explore making that same type of public

interest finding on behalf of customers. The

order spends many pages making a

persuasive case that the current environment,

in which no more than a handful of utilities

have filed open access tariffs, is rife with

undue discrimination and can no longer be

tolerated. This is the fundamental

philosophical and legal underpinning for the

order’s new open access requirements.
17726 Federal Register / Vol. 60, No. 67 / Friday, April 7, 1995 / Proposed Rules

2 16 U.S.C. 824h (1988).

But if the order’s perception of undue

discrimination is accurate, and I believe it is,

would it not suggest that some power supply

contracts negotiated in that environment

were infected with undue discrimination and

therefore unlawful? Would it not be

appropriate, and more symmetrical, to allow

such customers the right to make a filing

asking the Commission to determine whether

their current contract is unduly

discriminatory, unjust or unreasonable? We

would not, of course, allow such customers

to escape their stranded cost responsibility in

any event. Even if we allowed customers to

make such filings, they would remain fully

responsible for the costs reasonably incurred

on their behalf.

A more symmetrical approach to customers

and utilities during the transition to

competitive markets would be consistent

with the Commission’s Order 636. There, the

Commission granted all pipeline ‘‘sales’’

customers the right to choose other gas

suppliers but granted all pipelines 100

percent recovery of their eligible and prudent

transition costs. In granting ‘‘conversion

rights’’ to pipeline sales customers, the

Commission found that continued

enforcement of customers’ existing purchase

obligations, entered into when pipelines

provided bundled service and had a virtual

monopoly over certain aspects of interstate

service, was contrary to the requirements of

the Natural Gas Act.

I am not suggesting today that we mirror

precisely the natural gas model by granting

all customers, regardless of contracts, the

right to choose other suppliers. I am

suggesting, however, that during the

comment period we give full and fair

consideration to the argument that power

customers with contracts lacking explicit

stranded cost recovery provisions should

have the same right we grant utilities to make

filings seeking contract modifications

regardless of Mobile-Sierra restrictions. I am

confident that commenters will give us the

benefit of their thinking on this issue.

II. Dissenting Opinion

Finally, let me turn briefly to the sole issue

on which I will be dissenting in part from an

otherwise exceptionally strong order. That

issue involves this Commission’s role and

relationship with the states in making

determinations with respect to stranded costs

arising from retail competition and from

municipalizations.

There have been full and vigorous

discussions at the Commission about how to

handle this issue. My goal, which the entire

Commission shares, is to strike an

appropriate balance that ensures the recovery

of stranded costs, and ensures that the

legitimate rights of states are respected. We

have all struggled with these issues in good

faith. I simply disagree with the majority in

certain respects about how to accomplish

these goals.

First, I will address retail competition.

Under the NOPR, this Commission would

allow filings seeking recovery of stranded

costs related to retail competition only when

the state regulatory commission does not

have authority under state law to address

stranded costs at the time retail wheeling is

required.

I find this approach too narrow. I would

allow such filings when the state commission

lacks authority to decide the issue or when

the state commission has authority but does

not decide the issue. I would not secondguess the state decision, but I would not

allow retail stranded costs to ‘‘fall through

the cracks’’ merely because the state

commission has, but does not use, authority

to decide the issue.

On municipalization, the NOPR proposes

making this Commission the primary forum

for seeking recovery of stranded costs. The

NOPR says that, if a state has allowed

recovery of any stranded costs from

municipalized customers, this Commission

will deduct that amount from the amount we

determine to be recoverable. In other words,

even when states have and exercise the

authority to decide the recoverability of

stranded costs related to municipalization,

this Commission would take over and

federalize the issue.

I cannot support this approach. The

Federal Power Act does not constitute this

Commission as the court of appeals to

challenge unsatisfactory state decisions. It is

not this Commission’s role to stand in

judgment of policy choices and decisions

lawfully made by our state counterparts.

In my judgment, the following principles

should govern this Commission’s approach to

stranded costs arising from either retail

competition or municipalization. In either

case, utilities are entitled to a decision on the

recoverability of such costs. It would be

unfair, and would unduly jeopardize the

financial health of utilities, for stranded costs

to slip through because no regulatory

commission provides a forum and decides

the issue.

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.

My views on how we should handle

stranded costs arising from municipalization

are influenced by the fact that, according to

commenters, roughly 14 states have

municipalization statutes that do in fact

authorize states to deal with stranded cost

issues. Arkansas, for example, has a statute

enacted in 1987 that appears to give the

Arkansas Public Service Commission full

authority to deal with the stranded cost issue

in a way that protects both the remaining

customers and shareholders. It is an

extensive, thoughtful statute that deals with

a wide range of issues. It is, apparently, the

will of the sovereign state of Arkansas that

this state statute be enforced. I see no reason

to yank this issue from the Arkansas

Commission, or from any other state

commission that has statutory authority to

act.

In that vein, if this Commission were to

decide the recoverability of stranded costs for

either retail competition or muncipalization

(because the state lacked authority or did not

decide the issue), I believe we should adopt

procedures allowing the affected state

commissions to participate in our proceeding

in a meaningful way. Specifically, I propose

allowing state participation through one of

the procedures specified in section 209 of the

Federal Power Act. 2 These include joint state

boards, joint hearings, concurrent hearings

and technical conferences. I have no views at

this time on which of these tools could or

should be used in particular cases. The

decision on which of these tools to use can

be made in individual cases, as they arise.

But, clearly, they are useful mechanisms for

obtaining state input in proceedings

involving retail competition and

municipalization.

For all of these reasons, I will concur in

part and dissent in part. In virtually all

respects, this is an excellent order; except as

I have noted, it has my wholehearted

support.

William L. Massey,

Commissioner.

[FR Doc. 95–8534 Filed 4–6–95; 8:45 am]

BILLING CODE 6717–01–P

18 CFR Parts 141 and 388

[Docket No. RM95–9–000]

Real-Time Information Networks;

Notice of Technical Conference and

Request for Comments

March 29, 1995

AGENCY: Federal Energy Regulatory

Commission.

ACTION: Notice of Technical Conference

and request for comments.

SUMMARY: The Federal Energy

Regulatory Commission (Commission),

is issuing this notice to announce a

technical conference to be scheduled at

a later date, and, in preparation for that

conference, to request comments on:

whether real-time information networks

(RINs) or some other option is the best

method to ensure that potential

purchasers of transmission services

receive access to information to enable

them to obtain open access transmission

service on a non-discriminatory basis

from public utilities that own and/or

control facilities used for the

transmission of electric energy in

interstate commerce; and what