12274 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

DEPARTMENT OF ENERGY

Federal Energy Regulatory

Commission

18 CFR Part 35

[Docket Nos. RM95–8–001 and RM94–7–

002; Order No. 888–A]

Promoting Wholesale Competition

Through Open Access NonDiscriminatory Transmission Services

by Public Utilities; Recovery of

Stranded Costs by Public Utilities and

Transmitting Utilities

Issued March 4, 1997.

AGENCY: Federal Energy Regulatory

Commission.

ACTION: Final rule; order on rehearing.

SUMMARY: The Federal Energy

Regulatory Commission (Commission)

reaffirms its basic determinations in

Order No. 888 and clarifies certain

terms. Order No. 888 requires all public

utilities that own, control or operate

facilities used for transmitting electric

energy in interstate commerce to have

on file open access non-discriminatory

transmission tariffs that contain

minimum terms and conditions of nondiscriminatory service. Order No. 888

also permits public utilities and

transmitting utilities to seek recovery of

legitimate, prudent and verifiable

stranded costs associated with

providing open access and Federal

Power Act section 211 transmission

services. The Commission’s goal is to

remove impediments to competition in

the wholesale bulk power marketplace

and to bring more efficient, lower cost

power to the Nation’s electricity

consumers.

EFFECTIVE DATE: This rule is effective on

May 13, 1997.

FOR FURTHER INFORMATION CONTACT:

David D. Withnell (Legal Information—

Docket No. RM95–8–001), Office of

the General Counsel, Federal Energy

Regulatory Commission, 888 First

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

(202) 208–2063

Deborah B. Leahy (Legal Information—

Docket No. RM94–7–002), Office of

the General Counsel, Federal Energy

Regulatory Commission, 888 First

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

(202) 208–2039

Dan T. Hedberg (Technical

Information—Docket No. RM95–8–

001), Office of Electric Power

Regulation, Federal Energy Regulatory

Commission, 888 First Street, N.E.,

Washington, D.C. 20426, (202) 208–

0243

Joseph M. Power (Technical

Information—Docket No. RM94–7–

002), Office of Electric Power

Regulation, Federal Energy Regulatory

Commission, 888 First Street, N.E.,

Washington, D.C. 20426, (202) 208–

1242

SUPPLEMENTARY INFORMATION: In

addition to publishing the full text of

this document in the Federal Register,

the Commission also provides all

interested persons an opportunity to

inspect or copy the contents of this

document during normal business hours

in the Public Reference Room at 888

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

20426.

The Commission Issuance Posting

System (CIPS), an electronic bulletin

board service, provides access to the

texts of formal documents issued by the

Commission. CIPS is available at no

charge to the user and may be accessed

using a personal computer with a

modem by dialing 202–208–1397 if

dialing locally or 1–800–856–3920 if

dialing long distance. To access CIPS,

set your communications software to

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

2400, or 1200 bps, full duplex, no

parity, 8 data bits and 1 stop bit. The

full text of this order will be available

on CIPS in ASCII and WordPerfect 5.1

format. CIPS user assistance is available

at 202–208–2474.

CIPS is also available through the Fed

World system. Telnet software is

required. To access CIPS via the

Internet, point your browser to the URL

address: http://www.fedworld.gov and

select the ‘‘Go to the FedWorld Telnet

Site’’ button. When your Telnet software

connects you, log onto the FedWorld

system, scroll down and select

FedWorld by typing: 1 and at the

command line then typing: /go FERC.

FedWorld may also be accessed by

Telnet at the address fedworld.gov.

Finally, the complete text on diskette

in Wordperfect format may be

purchased from the Commission’s copy

contractor, La Dorn Systems

Corporation. La Dorn Systems

Corporation is also located in the Public

Reference Room at 888 First Street, N.E.,

Washington, D.C. 20426.

I. Introduction and Summary

II. Public Reporting Burden

III. Background

IV. Discussion

A. Scope of the Rule

1. Introduction

2. Functional Unbundling

3. Market-based Rates

a. Market-based Rates for New Generation

b. Market-based Rates for Existing

Generation

4. Merger Policy

5. Contract Reform

6. Flow-based Contracting and Pricing

B. Legal Authority

C. Comparability

1. Eligibility to Receive Non-discriminatory

Open Access Transmission

a. Unbundled Retail Transmission and

‘‘Sham Wholesale Transactions’’

b. Transmission Providers Taking Service

Under Their Tariff

2. Service that Must be Provided by

Transmission Provider

3. Who Must Provide Non-discriminatory

Open Access Transmission

4. Reservation of Transmission Capacity by

Transmission Customers

5. Reservation of Transmission Capacity for

Future Use by Utility

6. Capacity Reassignment

7. Information Provided to Transmission

Customers

8. Consequences of Functional Unbundling

a. Distribution Function

b. Retail Transmission Service

c. Transmission Provider

1. Taking Service Under the Tariff

2. Accounting Treatment

D. Ancillary Services

1. Specific Ancillary Services

a. Scheduling, System Control and

Dispatch Service

b. Reactive Supply and Voltage Control

from Generation Sources Service

c. Energy Imbalance Service

(1) Description of Energy Imbalance

(2) Energy Imbalance Bandwidth

2. Ancillary Services Obligations

a. Obligation of a Control Area Utility

b. Obligation to Provide Dynamic

Scheduling

c. Obligation As Agent

3. Miscellaneous Ancillary Services Issues

a. Transmission Provider as Ancillary

Services Merchant

b. QF Receipt of Ancillary Services

c. Pricing of Ancillary Services

E. Real-Time Information Networks

F. Coordination Arrangements: Power

Pools, Public Utility Holding Companies,

Bilateral Coordination Arrangements,

and Independent System Operators . . .

179

1. Tight Power Pools

2. Loose Pools

3. Public Utility Holding Companies

4. Bilateral Coordination Arrangements

G. Pro Forma Tariff

1. Tariff Provisions That Affect The Pricing

Mechanism

a. Non-Price Terms and Conditions

b. Network and Point-to-Point Customers’

Uses of the System (so called

‘‘Headroom’’)

c. Load Ratio Sharing Allocation

Mechanism for Network Service

(1) Multiple Control Area Network

Customers

(2) Twelve Monthly Coincident Peak v.

Annual System Peak

(3) Load and Generation ‘‘Behind the

Meter’’

(4) Existing Transmission Arrangements

associated with Generating Capacity

Entitlements (e.g., ‘‘preference power’’

customers of PMAs)

d. Annual System Peak Pricing for Flexible

Point-to-Point Service

e. Opportunity Cost Pricing
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12275

1Promoting Wholesale Competition Through

Open Access Non-discriminatory Transmission

Services by Public Utilities and Recovery of

Stranded Costs by Public Utilities and Transmitting

Utilities, Order No. 888, 61 FR 21,540 (May 10,

1996), FERC Stats. & Regs. ¶ 31,036, clarified, 76

FERC ¶ 61,009 and 76 FERC ¶ 61,347 (1996). Order

No. 889 is an accompanying rule and specific

rehearing arguments on that rule will be addressed

separately.

(1) Recovery of Opportunity Costs

(2) Redispatch Costs

f. Expansion Costs

g. Credit for Customers’ Transmission

Facilities

h. Ceiling Rate for Non-firm Point-to-Point

Service

i. Discounts

j. Other Pricing Related Issues Not

Specifically Addressed in the Final Rule

(1) Demand Charge Credits

(2) In-Kind Transactions

2. Priority For Obtaining Service

a. Reservation Priority for Existing Firm

Service Customers

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

c. Reservation Priorities for Non-firm

Service

3. Curtailment and Interruption Provisions

a. Pro-rata Curtailment Provisions

b. Curtailment and Interruption Provisions

for Non-firm Service

4. Reciprocity Provision

5. Liability and Indemnification

6. Umbrella Service Agreements

7. Other Tariff Provisions

a. Minimum and Maximum Service

Periods

b. Amount of Designated Network

Resources

c. Eligibility Requirements

d. Two-Year Notice of Termination

Provision

e. Termination of Service for Failure to Pay

Bill

f. Definition of Native Load Customers

g. Off-System Sales

h. Requirements Agreements

i. Use of Distribution Facilities

j. Losses

k. Modification of Non-rate Terms and

Conditions

l. Miscellaneous Tariff Modifications

(1) Ancillary Services

(2) Clarification of Accounting Issues

(a) Transmission Provider’s Use of Its

System (Charging Yourself)

(b) Facilities and System Impact Studies

(c) Ancillary Services

(3) Miscellaneous Clarifications

(a) Electronic Format

(b) Administrative Changes

8. Specific Tariff Provisions

9. Miscellaneous Tariff Administrative

Changes

10. Pro Forma Tariff Compliance Filings

H. Implementation

1. Group 1 Public Utilities

2. Group 2 Public Utilities

3. Clarification Regarding Terms and

Conditions Reflecting Regional Practices

4. Future Filings

5. Waiver

I. Federal and State Jurisdiction:

Transmission/Local Distribution

J. Stranded Costs

1. Justification for Allowing Recovery of

Stranded Costs

2. Cajun Electric Power Cooperative, Inc. v.

FERC

3. Responsibility for Wholesale Stranded

Costs (Whether to Adopt Direct

Assignment to Departing Customers)

4. Recovery of Stranded Costs Associated

With New Wholesale Requirements

Contracts

5. Recovery of Stranded Costs Associated

With Existing Wholesale Requirements

Contracts

6. Recovery of Stranded Costs Caused by

Retail-Turned-Wholesale Customers

7. Recovery of Stranded Costs Caused by

Retail Wheeling

8. Evidentiary Demonstration Necessary—

Reasonable Expectation Standard

9. Calculation of Recoverable Stranded

Costs

10. Stranded Costs in the Context of

Voluntary Restructuring

11. Accounting Treatment for Stranded

Costs

12. Definitions, Application, and Summary

K. Other

1. Information Reporting Requirements for

Public Utilities

2. Small Utilities

3. Regional Transmission Groups

4. Pacific Northwest

5. Power Marketing Agencies

a. Bonneville Power Administration (BPA)

b. Other Power Marketing Agencies

6. Tennessee Valley Authority

7. Hydroelectric Power

8. Residential Customers

9. Miscellaneous Issues

V. Environmental Statement

A. The Appropriate No-Action Alternative

B. Challenges to Modeling Assumptions

1. Appropriate Base Case

2. Challenge to the Use of Computer

Modeling

3. Transmission Assumptions

4. Plant Availabilities and Heat Rates

5. Reserve Margins

6. Northeast MOU

7. Natural Gas Prices

8. Expanded Transmission Analysis

C. Mitigation

D. Emissions Standards Disparity

E. Short-Term Consequences of the Rule

G. Cost Benefit Analysis

H. Socioeconomic Impacts

I. Coastal Zone Management Act

VI. Regulatory Flexibility Act Certification

A. Docket No. RM95–8–000 (Open Access

Final Rule)

1. Public Utilities

2. Non-Public Utilities

B. Docket No. RM94–7–000 (Stranded Cost

Final Rule)

1. Public Utilities

2. Non-Public Utilities

VII. Information Collection Statement

VIII.Effective Date

Regulatory Text

Appendix A—List of Petitioners

Appendix B—Pro Forma Open Access

Transmission Tariff

Statement of Commissioner Hoecker

Statement of Commissioner Massey

I. Introduction and Summary

On April 24, 1996, the Commission issued

Final Rules (Order Nos. 888 and 889)

intended to remedy undue

discrimination in the provision of

interstate transmission services by public

utilities and to address the stranded

costs that may result from the transition

to more competitive electricity markets.1

At the heart of these rules is a

requirement that prohibits owners and

operators of monopoly transmission

facilities from denying transmission

access, or offering only inferior access, to

other power suppliers in order to favor

the monopolists’ own generation and

increase monopoly profits—at the

expense of the nation’s electricity

consumers and the economy as a whole.

The electric utility industry today is

not the industry of ten years ago, or

even five years ago. While historically it

was assumed that local utilities would

be the only ones to generate and

transmit power for their customers,

today there is a broad array of potential

competitors to supply power and

widespread transmission facilities that

can carry power vast distances. But

competitors cannot reach customers if

they cannot have fair access to the

transmission wires necessary to reach

those customers. It is against this

industry backdrop that the Commission

in Order No. 888 exercised its public

interest responsibilities pursuant to

sections 205 and 206 of the Federal

Power Act (FPA), to reexamine undue

discrimination in interstate

transmission services and the effect of

that discrimination on the electricity

customers whom we are bound to

protect under the FPA.

We here reaffirm the legal and policy

bases on which Order No. 888 is

grounded. Utility practices that were

acceptable in past years, if permitted to

continue, will smother the fledgling

competition in electricity markets and

undermine the national policies

reflected in the Energy Policy Act of

1992 to encourage the development of

competitive markets. We firmly believe

that our authorities under the FPA not

only permit us to adapt to changing

economic realities in the electric

industry, but also require us to do so, as

necessary to eliminate undue

discrimination and protect electricity

customers. The record supports our

conclusion that, absent open access,

undue discrimination will continue to

be a fact of life in today’s and

tomorrow’s electric power markets. As

recent events clearly demonstrate,

unbundled electric transmission service

will be the centerpiece of a freely traded

commodity market in electricity in

which wholesale customers can shop for

competitively-priced power.
12276 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

2Under section 211 of the FPA, the Commission,

on a case-by-case basis upon application by an

eligible customer, may order both public utilities

and non-public utilities that own or operate

transmission facilities used for the sale of electric

energy at wholesale to provide transmission

services to the applicant if it finds it is in the public

interest to issue such order.

The only way to effectuate

competitive markets and remedy

discrimination is through readily

available, non-discriminatory

transmission access. The Commission

estimates the potential quantitative

benefits from such access will be

approximately $3.8 to $5.4 billion per

year in cost savings, in addition to the

non-quantifiable benefits that include

better use of existing assets and

institutions, new market mechanisms,

technical innovation, and less rate

distortion.

Order No. 888 has two central

components. The first requires all

public utilities that own, operate or

control interstate transmission facilities

to offer network and point-to-point

transmission services (and ancillary

services) to all eligible buyers and

sellers in wholesale bulk power

markets, and to take transmission

service for their own uses under the

same rates, terms and conditions offered

to others. In other words, it requires

non-discriminatory (comparable)

treatment for all eligible users of the

monopolists’ transmission facilities. The

non-discriminatory services required by

Order No. 888, known as open access

services, are reflected in a pro forma

open access tariff contained in the Rule.

The Rule also requires functional

separation of the utilities’ transmission

and power marketing functions (also

referred to as functional unbundling)

and the adoption of an electric

transmission system information

network.

The second central component of

Order No. 888 was to address whether

and how utilities will be able to recover

costs that could become stranded when

wholesale customers use the open

access tariffs, or FPA section 211

tariffs, 2 to leave their utilities’ power

supply systems and shop for power

elsewhere. Because of competitive

changes occurring at the retail level, as

numerous states have begun retail

transmission access programs, Order

No. 888 also clarifies whether and when

the Commission may address stranded

costs caused by retail wheeling and the

extent of the Commission’s jurisdiction

over unbundled retail transmission. The

Commission further addresses the

circumstances under which utilities and

their wholesale customers may seek to

modify contracts made under the old

regulatory regime, taking into account

the goals of reasonably accelerating

customers’ ability to benefit from

competitively priced power and at the

same time ensuring the financial

stability of electric utilities during the

transition to competition.

137 entities filed requests for

rehearing and/or clarification of Order

No. 888. While these parties raise a

variety of arguments—including legal,

policy, and technical arguments—the

majority (including a majority of public

utilities) agree that we need to harness

the benefits that competitive electricity

markets can bring to the nation. The

disagreements primarily focus on the

mechanics of how we should do this,

who should pay the costs of the

transition to competition, and how long

the transition should take.

First, parties disagree on what is

necessary to remedy undue

discrimination and to develop truly

competitive wholesale markets. Many

focus specifically on the tariff terms and

conditions of good transmission access

and seek changes in the Order No. 888

pro forma tariff. In response to these

types of rehearing arguments, the

Commission has fine-tuned or changed

some of the pro forma tariff terms and

conditions to better ensure that they do

not permit discrimination and that they

result in well-functioning markets.

Other petitioners focus on additional

structural changes which they believe

are necessary, such as mandatory

corporate restructuring (divestiture of

generation assets) or mandatory creation

of independent transmission system

operators (ISOs). With regard to

restructuring, the Commission

continues to believe that functional

unbundling of the utility’s business, not

corporate divestiture or mandatory

ISOs, is sufficient to remedy undue

discrimination at this time.

The most contentious arguments

raised on rehearing involve how we deal

with the transition costs associated with

moving to competition. Some utilities

have invested millions of dollars in

facilities and purchased power contracts

based on an explicit or implicit

obligation to serve customers and the

expectation that those customers would

remain on their systems for the

foreseeable future. These utilities face

so-called ‘‘stranded costs’’ which, if not

recovered from the customers that

caused the costs to be incurred, could be

shifted to other customers.

There are two basic categories of

rehearing arguments regarding stranded

cost recovery. Most utilities want a

guarantee from this Commission that

they will recover all stranded costs,

whether caused by losing retail

customers or wholesale customers.

Many customers, on the other hand,

want to be able to abrogate existing

power supply contracts so that they can

immediately leave their current

suppliers’ systems and shop for cheaper

power elsewhere, without paying the

sunk costs that their suppliers incurred

on their behalf.

In response to these diverse

arguments, the Commission has struck a

reasonable balance that, for certain

defined circumstances, permits utilities

the opportunity to seek extra-contractual

recovery of stranded costs from their

departing customers and permits

customers the opportunity to make a

showing that their contracts should be

shortened or terminated. Based on our

experience in the natural gas area, we

have learned that it is critical to address

these issues early, but we also have

chosen an approach different from that

taken in the gas area because of the

different circumstances facing the

electric industry.

In balancing the wide array of

interests reflected in the rehearing

petitions, we have made a number of

clarifications and granted rehearing on

some issues, but we reaffirm the core

elements and framework of Order No.

888. Since the time the final rules

issued, as discussed in Section III, the

pace of competitive change has

continued to escalate in the industry at

both the wholesale and retail levels as

competitors, customers and state

regulatory authorities aggressively seek

ways to lower the price of electricity.

We therefore believe it is all the more

critical that we remedy undue

discrimination in interstate

transmission services now, and that we

do so generically, if we are to fulfill our

responsibilities under the FPA to

protect consumers and provide a fair

and orderly transition to new

competitive markets.

Finally, with respect to environmental

issues associated with this rulemaking,

certain parties on rehearing continue to

challenge the adequacy of our Final

Environmental Impact Statement (FEIS).

The central issues are whether the Final

Rule will increase emissions of nitrogen

oxides (NOx) from certain fossil-fuel

fired generators, which could affect air

quality in downwind areas to which

these emissions may be carried, and the

Commission’s authority to mitigate

environmental consequences.

We deny rehearing on the

environmental issues raised and affirm

our conclusion that we have satisfied

our obligations under NEPA. As

discussed in detail in the Final Rule,

this rulemaking is expected to slightly

increase or slightly decrease total future
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12277

NOx emissions, depending on whether

competitive conditions in the electric

industry favor the utilization of natural

gas or coal as a fuel for the generation

of electricity. We also examined

mitigation options over the longer term,

and found that the preferred approach

for mitigating any adverse

environmental consequences would be

for the Environmental Protection

Agency (EPA) and the states to address

the problem through regulatory

authorities available under the Clean

Air Act. The petitions for rehearing have

not persuaded us to change this

approach. Indeed, we note that since the

issuance of Order No. 888, the EPA has

concluded that the Rule is unlikely to

have any immediate significant adverse

environmental impact and thus

concurred that the Commission’s

analysis is adequate under NEPA. We

further note that EPA has recently taken

steps under the Clean Air Act to address

NOx emissions as part of a

comprehensive emissions control

program, along the lines endorsed by

the Commission in the EIS.

In summary, the Commission believes

that our authorities under the FPA not

only permit us to adapt to changing

economic realities in the electric

industry, but also require us to do so to

eliminate undue discrimination and

protect electricity customers. The

measures required in Order No. 888 are

necessary to remedy undue

discrimination in interstate

transmission services and provide an

orderly and fair transition to

competitive bulk power markets.

To assist the reader, we provide below

a section-by-section summary of key

elements of this Order on Rehearing.

Scope of the Rule

In this section we discuss petitions to

rehear our requirement that

transmission and power sales services

be contracted for separately

(unbundled). We reaffirm that this

requirement is a reasonable and

workable means of assuring nondiscriminatory open access

transmission. In doing so we refuse

invitations to require that utilities under

our jurisdiction divest themselves of

generation or transmission assets. We

do, however, make an important

clarification involving how we will deal

with existing contracts that contain socalled Mobile-Sierra clauses (clauses

under which one or both parties agreed

not to seek modification of contract

terms unless they could show that it is

contrary to the public interest not to

permit the modification).

In Order No. 888 we concluded that

contracts would not be abrogated by

operation of the Rule. Instead,

preexisting contracts would continue to

be honored until such time as they were

revised or terminated. We also found

that those who were operating under

pre-existing requirements contracts

containing Mobile-Sierra clauses would

nonetheless be allowed to seek reform of

the contracts on a case-by-case basis. On

rehearing we affirm that public utilities

will be allowed to file to amend their

Mobile-Sierra contracts for the limited

purpose of providing an opportunity to

seek recovery of stranded costs, without

having to make a public interest

showing that such cost recovery should

be permitted. However, these utilities

will have the burden, on a case-by-case

basis, of showing that they had a

reasonable expectation of continuing to

serve the departing customer after the

contract term. We clarify that if the

utilities under such contracts seek to

modify provisions that do not relate to

stranded costs, they will have the

burden of showing that the provisions

are contrary to the public interest.

We here make clear that, in turn,

customers will be allowed to file to

amend their Mobile-Sierra contracts to

modify any contract term or to terminate

the contract, without having to make a

showing that the contract terms are

contrary to the public interest. Instead,

customers seeking modifications must

demonstrate that the provisions they

wish modified are no longer ‘‘just and

reasonable.’’ We reaffirm our conclusion

in the Final Rule that if a customer

seeks to shorten or eliminate the term of

its contract, however, any contract

modification approved by the

Commission will provide for

appropriate stranded cost recovery by

the customer’s supplying utility.

These various provisions meet the

two-fold need to deal with stranded

costs and the contracts under which

those costs were incurred. However, as

described in Order No. 888, the

opportunity to reform Mobile-Sierra

contracts extends only to a limited set

of contracts—those entered into on or

before July 11, 1994, for requirements

power.

Comparability

In this section we deal with those

requesting rehearing of our conclusions

regarding what ‘‘comparable’’ service is,

who is eligible for that service, and how

it is to be implemented. We reaffirm our

finding that, as a matter of law, we have

jurisdiction over the rates, terms and

conditions of unbundled transmission

service provided to retail customers. We

also clarify that we have authority to

order ‘‘indirect’’ unbundled retail

transmission services and that if such

transmission is ordered by us in the

future, or if it is provided voluntarily,

otherwise eligible customers may obtain

such service under the open access

tariff. We expect public utilities to

provide such service in the future and,

if they do not, we will not hesitate to

order it.

We modify in two respects the

definition of who is eligible for open

access transmission service. First, we

clarify that, with respect to service that

this Commission is prohibited from

ordering by section 212(h) of the Federal

Power Act (retail wheeling directly to an

ultimate consumer and ‘‘sham’’

wholesale wheeling), entities are

eligible for such service under the tariff

only if it is provided pursuant to a state

requirement or is provided voluntarily.

Second, we clarify that retail customers

taking unbundled service pursuant to a

state requirement (i.e., direct retail

service) are eligible for such service

only from those transmission providers

that the state orders to provide service.

These changes are made to make clear

that our rules cannot be used to

circumvent the proscriptions placed on

the Commission against ordering direct

retail wheeling.

Ancillary Services

In this section we deal with petitions

to rehear our definitions of ancillary

services—those services such as

scheduling, voltage control, and

supplemental reserve service that must

or can attend the providing of

transmission service—as well as the

provisions involving these services. We

reaffirm that tariffs must separately state

the charges for these services. We do

modify some of the definitions of these

services to conform to industry needs

and practices. Most importantly, we

make clear that the transmission

provider’s sale of ancillary services

associated with providing basic

transmission service is not a wholesale

merchant function and thus does not

violate the standards of conduct

imposed with Order No. 889.

Coordination Arrangements

The requirement to provide nondiscriminatory open access transmission

applies to any agreement between

utilities that contains transmission rates,

terms or conditions. This includes

pooling arrangements and agreements

between companies contracting to

provide each other mutually beneficial

transmission services. In Order No. 888

we laid out rules under which the open

access comparability requirements

would apply to tight and loose power

pools, public utility holding companies

and bilateral coordination agreements.
12278 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

We also set out principles that would

govern our approval of independent

system operator (ISO) agreements.

In this section we affirm the rules

governing coordination agreements. In

doing so we clarify the definition of

‘‘loose pool.’’ We also make clear that,

unlike in other situations where we

require utilities to provide not only the

services they provide themselves but

those they could provide themselves,

we will require members of loose pools

to offer to third parties only those

transmission services that they provide

themselves under their pool-wide

agreements.

We also reaffirm our strong

commitment to the concept of ISOs and

the ISO principles described in Order

No. 888. In doing so we reject arguments

that we should require that ISOs be

formed. At the same time, we emphasize

that while there is no ‘‘cookie-cutter’’

approach to forming an acceptable ISO,

the requirement of fair and nondiscriminatory rules of governance

(Principle One) and the requirement

that ISO employees have no financial

interest in the economic interests of

power marketers—backed by strict

conflict of interest provisions—

(Principle Two) are fundamental to our

approving any ISO.

Pro Forma Tariff Provisions

The pro forma tariff is the basic

mechanism implementing the

requirements of comparable open access

transmission. It provides the details of

the transmission service obligations

imposed on jurisdictional utilities by

the Rule. On rehearing we affirm most

of the provisions set out in Order No.

888 for the pro forma tariff. We do make

changes to conform the pro forma tariff

to changes adopted under other sections

(for example, the definition of ‘‘eligible

customer’’).

The rehearing petitions raised many

questions about how particular aspects

of the tariff will work. For the most part,

these questions cannot be answered

generically, but must be resolved on a

case-by-case basis in the context of

specific fact situations. However, the

petitions brought to light issues that

require clarifications and in some cases

revisions to the tariff. The most

significant of these involve discounting

practices, provisions governing priority

of service and curtailment, and the

reciprocity provision.

Discounting practices. Originally, we

provided different rules depending

upon whether the transmission provider

was offering a discount to itself or an

affiliate or offering a discount to a nonaffiliate. In response to the rehearing

petitions, we are making three

significant changes to the discounting

requirements to better permit the ready

identification of discriminatory

discounting practices while also

providing greater discount flexibility.

First, any discount offered on

transmission services (including

supporting ancillary services) by a

transmission provider or requested by

any customer must now be made only

over the OASIS. With this change, all

will have the same, timely access to

discounted services. In making this

change, we clarify that a transmission

provider may limit its discounted

service to particular time periods.

Second, once the provider and

customer agree on a discount, the

details of the discounted service—the

price, points of receipt and delivery,

and length of service—must be

immediately posted on the OASIS.

Third, we revise our Rule respecting

what other transmission paths must be

offered at a discount. Originally, in

Order No. 888, we required that when

a discount was offered over one path,

the transmission provider would have to

provide that discount over all other

unconstrained paths on its system. We

will no longer require this. Instead, the

discount will be limited to those

unconstrained paths that go to the same

point(s) of delivery as the discounted

service being provided on the

transmission provider’s system. The

discount will extend for the same time

period and must be offered to all

transmission service customers.

Priority and Curtailment. We affirm

the right of first refusal policy that

reservation priority continues for firm

service customers served under a

contract of one year or more. We also

affirm that curtailment must be made on

a pro-rata basis and clarify that non-firm

point-to-point service is subordinate to

firm service. However, we clarify that

the pro-rata curtailment requirement

extends to only those transactions that

alleviate the constraint.

Reciprocity. In Order No. 888 we

conditioned the use of a public utility’s

open access service on the agreement

that, in return, it is offered reciprocal

service by non-public utilities that own

or control transmission facilities. Such

reciprocal service does not have to be

through an open access tariff, i.e., a

tariff available to all eligible customers,

but may be limited to those public

utilities from whom the non-public

utility obtains open access service. We

affirm the reciprocity condition. In

doing so, however, we make several

clarifications.

First, a public utility is free to offer

transmission service to a non-public

utility without requiring reciprocal

service in return. In other words, it may

voluntarily waive the reciprocity

condition. However, if it chooses to do

so, transmission service must be

provided through the pro forma tariff.

Alternatively, bilateral agreements for

transmission service provided by the

public utility will not be permitted.

Second, we clarify that under the

reciprocity condition a non-public

utility must agree to offer the

Transmission Provider any transmission

service the non-public utility provides

or is capable of providing on its system.

This means that the non-public utility

undertaking reciprocity must have an

OASIS and must operate under the

standards of conduct imposed under

Order No. 889 unless it is granted a

waiver by the Commission or, where

appropriate, by a regional transmission

group (RTG) of which it is a member.

We also clarify that a non-public utility

cannot avoid its responsibilities by

obtaining transmission service through

other transmission customers. Further,

the seller as well as the buyer in the

chain of a transaction involving a nonpublic utility will have to comply with

the reciprocity condition.

Third, we adhere to our decision not

to treat generation and transmission

(G&T) cooperatives and their member

distribution cooperatives as a single

unit. Thus, the reciprocity provision

extends to the G&T Cooperative and not

to its member distribution cooperatives.

Fourth, we clarify the ‘‘safe harbor’’

provision under which a non-public

utility may get a Commission decision

that its transmission tariff suffices to

meet reciprocity. A non-public utility

may limit the use of any reciprocity

tariff that it voluntarily files at the

Commission to those transmission

providers from whom the non-public

utility obtains open access service. A

non-public utility also may satisfy

reciprocity through bilateral agreements

with a public utility. As a related

matter, if a public utility believes a nonpublic utility is violating the reciprocity

condition, it may file with the

Commission a petition to terminate its

service to the non-public utility.

Fifth, we clarify that non-public

utilities may include stranded cost

provisions in their reciprocity tariffs.

Sixth, the order on rehearing removes

the term ‘‘interstate’’ from the

reciprocity provisions. This is to make

clear that reciprocity applies even to

those who do not own or control

interstate transmission facilities; i.e.,

foreign utilities and those located in the

ERCOT region of Texas.

As to local furnishing bonds held by

some public utilities, we clarify that all

costs associated with the loss of tax-
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12279

3 61 FR 21540 at 21543; FERC Stats. & Regs.

¶ 31,036 at 31,638 (1996). No comments were filed

Continued

exempt status of those bonds caused by

providing open access transmission

service are properly considered costs of

providing that service. This includes

costs of defeasing, redeeming, and

refinancing those bonds.

Other Clarifications. In this order on

rehearing we take the opportunity to

clarify various other tariff provisions.

Among these: Transmission providers

do not have to take service under the

open access tariff for transmitting power

purchased on behalf of their bundled

retail customers. Also, the ability to

reserve capacity to meet the reliability

needs of a transmission provider’s

native load applies equally to present

transmission and transmission that is

built in the future.

Implementation

On rehearing, we make no substantive

changes to the implementation

provisions originally required under

Order No. 888. For the most part, the

implementation process has been

completed. Utilities have made the

requisite tariff and compliance filings

and public and non-public utilities

have, through other orders, been

provided guidance as to obtaining

waivers of Order No. 888 and Order No.

889 requirements.

We emphasize that we do not require

the abrogation of existing contracts.

Rather, the Rule requires only that

transmission providers offer

transmission under the open access

tariff in addition to existing service

obligations. Commitments made under

existing contracts will continue. Of

course, both transmission providers and

their customers may seek to revise the

terms and conditions of existing

contracts by making the necessary

filings, as appropriate, under Sections

205 or 206 of the Federal Power Act.

State and Federal Jurisdiction

On rehearing we reaffirm our decision

that when transmission service is

provided to serve retail customers apart

from any contract for the retail sale of

power, i.e., when it is provided on an

unbundled basis, that transmission

service is under our jurisdiction. In

today’s market, and increasingly in the

future as more states adopt retail

wheeling programs, retail transactions

are, and will be, broken down into

products that are sold separately—

transmission and generation—and sold

by different entities. The exercise of our

jurisdiction over the rates, terms and

conditions of unbundled retail

transmission will, therefore, become

more important. We also recognize that

states have jurisdiction over facilities

used for local distribution.

On rehearing we also reaffirm the

seven-factor test of Order No. 888 to

distinguish transmission under our

jurisdiction from state-jurisdictional

local distribution. In doing so, we

recognize that our test does not resolve

all possible issues. There may be other

factors that should be taken into

account. The test, therefore, is designed

for flexibility to include unique local

characteristics and usages. To that end,

we will continue to defer to state

findings on these matters. In addition, we clarify that states have

the authority to determine the retail

marketing areas of the electric utilities

within their respective jurisdictions. We

also recognize that states have the

concomitant authority to determine the

end user services these utilities provide.

Stranded Costs

On rehearing, we reaffirm our basic

decisions surrounding the recovery of

stranded costs. Utilities will be allowed

the opportunity to seek to recover

legitimate, prudent, and verifiable

wholesale stranded costs. This

opportunity is limited to costs

associated with serving customers under

wholesale requirements contracts

executed on or before July 11, 1994 that

do not contain explicit stranded cost

provisions; and costs associated with

serving retail-turned-wholesale

customers.

We clarify that we will consider on a

case-by-case basis whether to treat a

contract extended or renegotiated

without a stranded cost provision as an

existing contract for stranded cost

purposes.

In each case, the opportunity to seek

stranded costs is limited to situations in

which there is a direct nexus between

the availability and use of a

Commission-required transmission tariff

and the stranding of the costs. The Rule

does not allow the recovery of costs that

do not arise from the new, accelerated

availability of non-discriminatory

transmission access.

The Commission also reaffirms its

decision that stranded costs should be

recovered from the customer that caused

the costs to be incurred. The

Commission is not requiring other

remaining customers, or the utility, to

shoulder a portion of its stranded costs

that meet the requirements for recovery.

The Commission, as described in

Order No. 888, will be the primary

forum for addressing the recovery of

stranded costs caused by retail-turnedwholesale customers. With respect to

such cases, we have made several

changes. First, the Commission has

reconsidered its decision respecting

cases involving existing municipal

utilities that annex retail customer

service territories. Under Order No. 888,

we found that in such cases the

Commission should not be the primary

forum for determining stranded cost

recovery. On rehearing we now find that

such cases should fall within our

province.

Second, we clarify that the

opportunity for recovery of stranded

costs associated with retail-turnedwholesale customers applies regardless

of whether the customer or its new

supplier is the one requesting and

contracting for the transmission service.

To this end, we have revised the

definition of ‘‘wholesale stranded cost.’’

With respect to the recovery of

stranded costs caused by unbundled

retail wheeling, we affirm that the only

circumstance in which we will entertain

requests for these types of costs is when

the state regulatory authority does not

have authority under state law to

address stranded costs when the retail

wheeling is required. We clarify that if

a state regulatory authority has in fact

addressed such costs, regardless of

whether it has allowed full recovery,

partial recovery or no recovery, utilities

may not apply to the Commission to

recover stranded costs caused by the

retail wheeling.

Other

In this section we resolve questions

concerning our information reporting

requirements, regional transmission

groups, and the special situations posed

by utilities in the Pacific Northwest and

by federal power marketing and similar

agencies. Here we make some minor

clarifications but make no significant

changes to Order No. 888.

We are not persuaded that the

information reporting requirements

need to be changed at this time. Finally,

we reject arguments that would have us

fix generically any particular rate

methodology for providing open access

transmission service under the pro

forma tariff.

II. Public Reporting Burden

This order on rehearing issues a

number of minor revisions to the Final

Rule. We find, after reviewing these

revisions, that they do not, on balance,

increase the public reporting burden.

The Final Rule contained an

estimated annual public reporting

burden based on the requirements of the

Open Access Final Rule and the

Stranded Cost Final Rule.3 Using the
12280 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

in objection to the public burden estimate

contained in the Open Access Final Rule and the

Stranded Cost Final Rule.

4FERC Stats. & Regs. at 31,638–52; mimeo at 13–

51.

5As a condition of using a public utility’s open

access tariff, any user, including non-public

utilities, must offer reciprocal comparable

transmission access to the public utility in return.

Order No. 888 provides a voluntary mechanism

whereby non-public utilities can obtain

Commission confirmation that what they are

offering meets the tariff reciprocity condition. Nonpublic utilities also may seek a waiver of the

reciprocity condition.

burden estimate contained in the Final

Rule as a starting point, we evaluated

the public burden estimate contained in

the Final Rule in light of the revisions

contained in this order and assessed

whether this estimate needed revision.

We have concluded, given the minor

nature of the revisions, and their

offsetting nature, that our estimate of the

public reporting burden of this order on

rehearing remains unchanged from our

estimate of the public reporting burden

contained in the Final Rule. The

Commission has conducted an internal

review of this conclusion and has

assured itself that there is specific,

objective support for this information

burden estimate. Moreover, the

Commission has reviewed the collection

of information required by the Final

Rule, as revised by this order on

rehearing, and has determined that the

collection of information is necessary

and conforms to the Commission’s plan,

as described in the Final Rule, for the

collection, efficient management, and

use of the required information.

Persons wishing to comment on the

collections of information required by

the Final Rule, as modified by this order

on rehearing, should direct their

comments to the Desk Officer for FERC,

Office of Management and Budget,

Room 3019 NEOB, Washington, D.C.

20503, phone 202–395–3087, facsimile:

202–395–7285 or via the Internet at

hillierlt@a1.eop.gov. Comments must

be filed with the Office of Management

and Budget within 30 days of

publication of this document in the

Federal Register. Three copies of any

comments filed with the Office of

Management and Budget also should be

sent to the following address: Ms. Lois

Cashell, Secretary, Federal Energy

Regulatory Commission, Room 1A, 888

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

20426. For further information, contact

Michael Miller, 202–208–1415.

III. Background

In the Final Rule, we detailed the

events that led up to this rulemaking,

including the significant technical,

statutory and regulatory changes that

have occurred in the electric industry

since the FPA was enacted in 1935.4 In

particular, we focused on the

competitive influences of the Public

Utility Regulatory Policies Act of 1978,

the Congressional mandate in the

Energy Policy Act of 1992 to encourage

competition in electricity markets, and

the need for reform in the industry if

consumers are to achieve the benefits

that greater competition can bring.

In the ten months since the Final Rule

issued, competitive changes have

escalated at an even faster pace in

virtually all areas of the electric

industry. These changes are driven not

only by the Commission’s Final Rule,

but also by state restructuring initiatives

and by continuing pressures from

customers to take advantage of emerging

competitive markets and the lower

electricity rates they can bring.

All of the existing 166 public utilities

that own, control or operate interstate

transmission facilities (listed as Group 1

and Group 2 utilities in the Final Rule)

have filed the Order No. 888 pro forma

open access tariff or requested a waiver

of the requirement. Similarly, they

either have adopted an electronic

information network or requested a

waiver of the requirement. Five nonpublic utilities have submitted

reciprocal transmission tariffs and more

than 20 have requested a waiver of the

reciprocity condition in the pro forma

tariff.5

Significant competitive changes also

have accelerated with respect to power

pooling, state restructuring initiatives,

and Independent System Operators

(ISOs). Under Order No. 888 and

subsequent implementation orders, the

Commission required the filing of

revised pooling agreements and joint

pool-wide transmission tariffs by

December 31, 1996, in order to remedy

undue discrimination in transmission

services provided through interstate

power pooling arrangements. Among

the power pool filings were a New

England (NEPOOL) comprehensive

restructuring proposal, a New York

proposal, a Pennsylvania-New JerseyMaryland (PJM) compliance filing and a

Western Systems Power Pool filing.

In response to the Commission’s

encouragement in Order No. 888 of ISOs

as a possible means for accomplishing

comparable access, a number of utilities

and states are well underway in

developing this new institution. The

fundamental purpose of an ISO is to

operate the transmission systems of

public utilities in a manner that is

independent of any business interest in

sales or purchases of electric power by

those utilities. The Commission has

received several proposals for forming

ISOs, one as part of the multi-docketed

filing engendered by California’s

restructuring plan, and others relating to

power pool filings. A number of regions

are also developing ISO proposals.

Some regions previously considering

regional transmission groups (RTGs),

whose primary purpose is regional

planning of transmission facility

construction and upgrades, have now

broadened their discussions to include

an ISO.

Investor-owned utilities in California,

at the order of both the state

commission and the legislature, have

filed proposals with the Commission

that would transfer control of

transmission facilities to an ISO in

conjunction with the formation of a

state-wide power exchange to facilitate

both wholesale and retail access. While

the case presents many complex issues

for the Commission to resolve, the

California proposal is fundamentally

compatible with the pro-competitive

open-access requirements of Order Nos.

888 and 889. The Commission’s openaccess policies therefore have provided

a framework for California, and other

states, to explore customer choice

initiatives.

Other major regions of the country

also are instituting ISOs. Member

utilities of the PJM Power Pool filed

competing ISO proposals with the

Commission and are currently working

to reconcile the differences between

their proposals. The New York Power

Pool recently filed a proposal to create

an ISO and a power exchange for New

York. The New England Power Pool is

exploring a new industry structure for

its region that centers on the creation of

an ISO. Utilities and other market

participants in the Electric Reliability

Council of Texas have also formed an

ISO. Discussions are underway among

utilities from Virginia to Wisconsin in

an attempt to create a Midwestern ISO.

Members of the Mid-America Power

Pool are discussing an ISO proposal. In

the Pacific Northwest, utilities are

involved in negotiations intended to

lead to the formation of an independent

grid operator (Indego).

The combined available generation

resources of the utilities in these groups

is on the order of 428 GW out of a total

of approximately 732 GW for total U.S.

resources (as of the end of 1996). Thus,

assuming these ISO arrangements come

to fruition, about three-fifths of the

industry may have independent system

operators controlling their transmission

systems.

Moreover, every state but one has

proposed or is considering or

developing retail competition programs.

For example, New Hampshire, Illinois
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12281

6E.g., Nuclear Energy Institute, Southern, EEI. EEI

and Nuclear Energy Institute also argue that Order

No. 889 should not be severable.

7FERC Stats. & Regs. at 31,654–56; mimeo at 57–

61.

8E.g., American Forest & Paper, Nucor, NY

Municipal Utilities.

and Massachusetts began pilot programs

in the past year, and retail transmission

service for these pilot programs

currently is being taken pursuant to

tariffs approved by both the state

commissions and this Commission. The

Massachusetts Department of Public

Utilities has sent a proposal to the state

legislature calling for retail competition

to begin in January 1998. The New York

Public Service Commission has issued

an order proposing that retail

competition begin in early 1998. The

New Jersey Board of Public Utilities has

issued a proposal permitting customer

choice beginning in October of 1998.

The Vermont Public Service Board has

sent a plan to the legislature

recommending that full customer choice

begin by the end of 1998. The Arizona

Corporation Commission has adopted

rules to phase in competition over four

years, beginning in January 1999.

Recently, the Maine Public Utilities

Commission issued a final report and

recommendation to the legislature for

retail competition to begin in January

2000. In addition, Rhode Island and

Pennsylvania both have new laws

requiring customer choice. These are

only a few of the many state initiatives

that are under way that will

dramatically alter the structure of the

electric industry.

Since Order No. 888 was issued,

significant efforts also have been made

to ensure that reliability of the

transmission grid is maintained and that

reliability criteria are compatible with

competitive markets. The North

American Electric Reliability Council

(NERC) has continued its efforts to

broaden its membership and to fashion

reliability requirements to fit a more

competitive electric power industry. For

example, the NERC Board of Directors

voted to require mandatory compliance

by all power market participants with

its reliability standards. NERC is also

establishing new entities called regional

security coordinators to oversee the

stability of grid operations and to direct

the development of an extensive new

communications network. Various

NERC committees are considering ways

to improve the tracking of power

transactions, identify the network

impacts of transactions, and reflect the

actual flow of power over the network

when making reservations for

transmission service. These efforts are

likely to intensify as the industry

continues to adapt to competitive

changes occurring in the marketplace.

Thus, all segments of the electric

industry have taken significant steps in

the past year in response to the

emerging wholesale competitive

markets enabled by Order No. 888 as

well as state retail competition

initiatives. The competitive framework

established by Order No. 888, whose

centerpiece is non-discriminatory

transmission services and a fair and

orderly stranded cost recovery

mechanism, is critical to the successful

transition to, and full development of,

the industry restructuring proposals that

are well underway in all major regions

of the country.

IV. Discussion

A. Scope of the Rule

1. Introduction

Rehearing Requests

Severability of Rules

Several entities assert that the

Commission should find that the

requirements of open access

transmission and stranded cost recovery

are not severable.6 They argue that if

one of these provisions is invalidated by

a court or otherwise removed, the orders

in their entirety should be withdrawn or

stayed pending reconsideration by the

Commission, and public utilities should

be allowed to withdraw or file amended

transmission tariffs.

Commission Conclusion

The Commission will not, at this time,

make any determination whether or not

the open access transmission, stranded

cost recovery and OASIS provisions of

Order Nos. 888 and 889 are severable.

Accordingly, we make no finding

whether, if one of these provisions is

invalidated, Order Nos. 888 and 889

should be withdrawn or stayed in their

entirety. We believe that our decisions

in Order Nos. 888 and 889 will be

upheld by the courts. Moreover, it

would be premature to consider the

appropriateness of a stay or withdrawal

at this time. Circumstances at the time

of any court order would dictate how

we should proceed and we would

consider all such circumstances, and the

entirety of our policy decisions, before

determining how to respond to a court

decision.

2. Functional Unbundling

In the Final Rule, the Commission

found that functional unbundling of

wholesale generation and transmission

services is necessary to implement nondiscriminatory open access

transmission.7 At the same time, the

Commission recognized that additional

safeguards were necessary to protect

against market power abuses. Thus, the

Commission adopted a code of conduct,

discussed in detail in the final rule on

OASIS, to ensure that the transmission

owner’s wholesale power marketing

personnel and the transmission

customer’s power marketing personnel

have comparable access to information

about the transmission system. The

Commission also noted that section 206

of the FPA is available if a public utility

seeks to circumvent the functional

unbundling requirements.

As a further precaution against

unduly discriminatory behavior, the

Commission stated that it will continue

to monitor electricity markets to ensure

that functional unbundling adequately

protects transmission customers. The

Commission also indicated that it would

continue to observe both the evolution

of competitive power markets and the

progress of the industry in adapting

structurally to competitive markets. If it

subsequently becomes apparent that

functional unbundling is inadequate or

unworkable in assuring nondiscriminatory open access

transmission, the Commission indicated

that it would reevaluate its position and

decide whether other mechanisms, such

as ISOs, should be required.

The Commission concluded that

functional unbundling, coupled with

these safeguards, is a reasonable and

workable means of assuring that nondiscriminatory open access transmission

occurs. In the absence of evidence that

functional unbundling will not work,

the Commission indicated that it was

not prepared to adopt a more intrusive

and potentially more costly

mechanism—corporate unbundling—at

this time.

Rehearing Requests

Several entities disagree with the

Commission’s decision to require

functional unbundling of wholesale

generation and transmission as a means

of assuring non-discriminatory open

access transmission.8 American Forest &

Paper argues that utilities must be

required to divest or spin-off their

generating assets through operational

unbundling or divestiture. It alleges that

it was arbitrary and capricious, and not

supported by evidence, for the

Commission to rely on a monopolist’s

code of conduct to protect against

monopoly abuses. Nucor asserts that a

financial conflict of interest remains and

that the Commission cannot monitor the

exchanges of information between

utility generation and transmission

employees. It declares that a credible
12282 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

9 67 FERC ¶ 61,183 at 61,557 (1994).

10FERC Stats. & Regs. at 31,656–57; mimeo at 63–

66.

11E.g., American Forest & Paper, SC Public

Service Authority, TDU Systems, LEPA, San

Francisco.

12TDU Systems at 92.

information disclosure requirement is

needed that makes generation cost and

production data visible to all

participants on a same-time basis. NY

Municipal Utilities also believes that the

Commission did not go far enough and

argues that the Commission should have

required operational unbundling, at

least for tight power pools.

Commission Conclusion

The Commission reaffirms its finding

in the Final Rule that, based on the

information available at this time,

functional unbundling, along with the

flexible safeguards discussed in the

Final Rule, is a reasonable and workable

means of assuring non-discriminatory

open access transmission. We see no

need to adopt a more intrusive and

potentially more costly approach at this

time based on speculative allegations

that functional unbundling may not

work and that more severe measures

may be needed. Indeed, despite a

number of opportunities to do so, no

entity has submitted any evidence

suggesting that this less intrusive

approach would not work. We do

emphasize, however, that we have not

adopted a rigid approach, but have

indicated a willingness to monitor the

situation and, if events require,

reevaluate our decision and decide

whether another mechanism may be

more appropriate. Until we see evidence

that functional unbundling will not

work, we will continue to require

functional unbundling, with the

safeguards enumerated in the Final Rule

and in Order No. 889.

3. Market-Based Rates

a. Market-Based Rates for New

Generation

In the Final Rule, the Commission

codified its determination in Kansas

City Power & Light Company (KCP&L) 9

that the generation dominance standard

for market-based sales from new

capacity should be dropped.10 The

Commission explained that it had yet to

find an instance of generation

dominance in long-run bulk power

markets and no commenter had

presented any evidence to that effect.

However, the Commission emphasized

that it will not ignore specific evidence

presented by an intervenor that a seller

requesting market-based rates for sales

from new generation nevertheless

possesses generation dominance.

The Commission further clarified that

dropping the generation dominance

standard for new capacity does not

affect the demonstration that an

applicant must make in order to qualify

for market-based rates for sales from its

existing generating capacity.

Rehearing Requests

Several entities take issue with the

Commission’s determination to drop the

generation dominance standard for

market-based sales from new capacity.11

American Forest & Paper argues that the

Commission should delay its decision

until effective competition has been

demonstrated to exist in all markets. SC

Public Service Authority maintains that

the Commission must determine on a

case-by-case basis whether public

utilities have market power (for both

existing and new capacity). It further

argues that the Commission must

develop an analysis of structural

conditions to use in assessing the

potential for market power consistent

with that used by DOJ and FTC in

merger proceedings and that reflects the

conditions of the industry. SC Public

Service Authority also asserts that the

Commission must require as a condition

of market rates for sales in the bulk

power market, which it defines to be

limited to sales to integrated utilities,

that the selling utility file rate cases

with the Commission and the applicable

state commissions to avoid

subsidization by captive consumers.

TDU Systems alleges that the long-run

bulk power market upon which the

KCP&L decision was based is overly

broad and ignores the distinction

between firm power, which ‘‘entities

subject to others’ market power are most

commonly in need of’’ and other bulk

power services. TDU Systems take issue

with the Commission’s conclusion in

KCP&L that large numbers of capacity

offers from IPPs and QFs demonstrate

that the market abounds with

competitors. TDU Systems argues that

the Commission’s ‘‘assumption that

large numbers of offers of power equate

with large numbers of offers of firm

power is questionable at best, and very

likely incorrect.’’ 12 Similarly, LEPA

argues that the Commission ignored

evidence submitted by LEPA in

comments ‘‘that the transmission

dominant utility still retained monopoly

power over RQ [requirements] markets

on which LEPA’s members are

dependent for their bulk power supply.’’

Because the Commission ignored the RQ

market and the evidence of

concentration in that market, LEPA

asserts that the Commission’s decision

is reversible error. LEPA further argues

that the Commission ignored the

undisputed testimony of LEPA’s witness

that reliability requirements constrain

the geographic scope of the RQ market

severely.

San Francisco argues that the burden

to demonstrate affirmatively the absence

of capacity constraints as a precondition

to receiving authority to charge marketbased rates for sales from new capacity

should be upon public utility

applicants, who possess the information

concerning capacity constraints.

Commission Conclusion

We reaffirm our decision to codify the

determination in KCP&L that the

generation dominance standard for

market-based sales from new capacity

should be dropped. Petitioners have not

presented any evidence that

demonstrates generation dominance in

long-run bulk power markets and, as

discussed in Order No. 888, we have

found no such evidence of generation

dominance in any of the numerous

market-based rate cases decided by the

Commission since KCP&L. In addition,

as described in Order No. 888, the

Commission will consider evidence of

generation dominance, including

generation dominance that results from

transmission constraints, when such

evidence is presented by an intervenor

in a market-based rate case in which a

utility seeks market-based pricing

associated with new capacity.

American Forest & Paper’s argument

that the Commission should delay

codification of KCP&L until effective

competition has been demonstrated to

exist in all markets ignores the fact that

we have eliminated the generation

dominance standard for market-based

rates from new capacity only, and that

the generation standard still applies to

applications for market-based rates from

existing generation. Other entities

similarly argue that other markets in

which utilities may sell power from new

capacity may be highly concentrated

with respect to generation, or that these

utilities may otherwise be able to exert

market power. Specifically, TDU

Systems and LEPA express concern that

the new policy may result in the

exercise of market power over very

specific bulk power products.

To allay these concerns, we note that

eliminating the generation dominance

showing applies only to sales from new

capacity. It does not apply to entire

classes of service or to specific products.

In addition, the policy eliminates the

showing only as a matter of routine in

each filing. We reemphasize that the

Commission will consider specific

evidence of generation dominance
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12283

13We do not agree with entities that claim that

our decision to rely on evidence raised by

intervenors in particular cases with respect to

transmission constraints improperly shifts the

burden away from the utility, which has the greatest

access to information concerning those constraints.

Given that we have yet to see any evidence of

generation dominance in long-term bulk power

markets we do not believe that it is appropriate to

burden all market-based rate applicants with

significant information requirements as an initial

matter. However, if an intervenor raises a specific

factual concern with respect to a transmission

constraint that may result in the exercise of market

power in a particular case, we will examine those

facts in a paper or formal hearing. In that context,

the utility would be required to come forward with

information sufficient to permit a full examination

of the effect of the constraint on the applicant’s

ability to exercise market power.

14FERC Stats. & Regs. at 31,660; mimeo at 73–75.

15See, e.g., Southwestern Public Service

Company, 72 FERC ¶ 61,208 at 61,996 (1995), reh’g

pending.

16The Final Rule contained a typographical error

in which the word ‘‘not’’ was erroneously omitted.

17FERC Stats. & Regs. ¶ 35,531 (1996).

18FERC Stats. & Regs. at 31,661; mimeo at 77–78.

19Order No. 592, Policy Statement Establishing

Factors the Commission will Consider in Evaluating

Whether a Proposed Merger is Consistent with the

Public Interest, 77 FERC ¶ 61,263 (1996).

20FERC Stats. & Regs. at 31,663–66; mimeo at 84–

92.

21The Commission defined these as contracts

executed on or before July 11, 1994.

associated with new capacity at the time

the seller seeks market-based rates for

the new capacity, including whether the

addition of the new capacity, when

combined with existing capacity, results

in generation dominance. This clearly

includes situations where existing

sources of generation must be combined

with new resources to produce a firm

power supply. Where entry barriers are

a concern, intervenors are free to raise

the issue.

SC Public Service Authority also

raises a number of concerns relating to

the ability of utilities to exercise market

power if they are permitted to sell new

capacity at market-based rates. These

concerns generally include how the

Commission determines product and

geographic markets, and the standards

used to determine whether sellers can

exercise market power. In response to

these concerns, as noted above public

utility owners of new capacity must still

seek case-by-case approval before they

can sell power from new capacity at

market-based rates and, as stated in the

Final Rule, intervenors may present

specific evidence that a seller requesting

such market rates possesses generation

dominance or otherwise has market

power.13 These requirements include

considerations of transmission market

power, whether other barriers to entry

exist and whether there is evidence of

affiliate abuse or reciprocal dealing.

b. Market-based Rates for Existing

Generation

In the Final Rule, the Commission

found that there is not enough evidence

on the record to make a generic

determination about whether market

power may exist for sales from existing

generation.14 The Commission indicated

that it would continue its case-by-case

approach that allows market-based rates

based on an analysis of generation

market power in first tier and second

tier markets.15 The Commission further

indicated that while it will continue to

apply the first-tier/second-tier analysis,

it will allow applicants and intervenors

to challenge the presumption implicit in

the Commission’s practice that the

relevant geographic market is bounded

by the second-tier utilities. Finally, the

Commission stated that it would

maintain its current practice of allowing

market-based rates for existing

generation to go into effect not subject

to refund.16 To the extent that either the

applicant or an intervenor in individual

cases offers specific evidence that the

relevant geographic market ought to be

defined differently than under the

existing test, the Commission indicated

that it will examine such arguments

through formal or paper hearings.

Rehearing Requests

No rehearing requests were filed with

respect to this matter.

4. Merger Policy

In the Final Rule, the Commission

explained that it had issued a Notice of

Inquiry (NOI) on the Commission’s

merger policy in Docket No. RM96–6–

000.17 The Commission indicated that it

will review whether its criteria and

policies for evaluating mergers need to

be modified in light of the changing

circumstances, including the Final Rule,

that are occurring in the electric

industry. The Commission concluded

that it would review its merger policy in

the ongoing NOI proceeding.18

Rehearing Requests

No rehearing requests were filed with

respect to this matter.

Commission Conclusion

We note that on December 18, 1996,

the Commission issued, in the NOI

proceeding, a Policy Statement that

updates and clarifies the Commission’s

procedures, criteria and policies

concerning public utility mergers.19

5. Contract Reform

Requirements and Transmission

Contracts

In the Final Rule, the Commission

concluded that it was not appropriate to

order generic abrogation of existing

requirements and transmission

contracts, but concluded nonetheless

that the modification of certain

requirements contracts (those executed

on or before July 11, 1994) on a case-bycase basis may be appropriate.20 The

Commission further concluded that,

even if customers under such

requirements contracts are bound by socalled Mobile-Sierra clauses, they ought

to have the opportunity to demonstrate

that their contracts no longer are just

and reasonable.

The Commission found that it would

be against the public interest to permit

a Mobile-Sierra clause in an existing

wholesale requirements contract 21 to

preclude the parties to such a contract

from the opportunity to realize the

benefits of the competitive wholesale

power markets. Thus, it explained, a

party to a requirements contract

containing a Mobile-Sierra clause no

longer will have the burden of

establishing independently that it is in

the public interest to permit the

modification of such contract. The

party, however, still will have the

burden of establishing that such

contract no longer is just and reasonable

and therefore ought to be modified.

The Commission explained that this

finding complements the Commission’s

finding that, notwithstanding a MobileSierra clause in an existing

requirements contract, it is in the public

interest to permit amendments to add

stranded cost provisions to such

contracts if the public utility proposing

the amendment can meet the

evidentiary requirements of the Final

Rule. Accordingly, the Commission

required that any contract modification

approved under this Section must

provide for the utility’s recovery of any

costs stranded consistent with the

contract modification. Further, the

Commission concluded that if a

customer is permitted to argue for

modification of existing contracts that

are less favorable to it than other

generation alternatives, then the utility

should be able to seek modification of

contracts that may be beneficial to the

customer.

Coordination Agreements

The Commission concluded that to

assure that non-discriminatory open

access becomes a reality in the relatively

near future, it was necessary to modify

existing economy energy coordination

agreements. The Commission stated that

it would condition future sales and
12284 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

22The Commission defined ‘‘existing’’ as those

agreements executed prior to 60 days after

publication of the Final Rule in the FEDERAL

REGISTER.

23The Commission defined ‘‘new’’ as those

agreements executed 60 days after publication of

the Final Rule in the FEDERAL REGISTER.

24Accordingly, the Commission explained,

transmission service needed for sales or purchases

under all new economy energy coordination

agreements will be pursuant to the Final Rule pro

forma tariff.

25Utilities For Improved Transition, Union

Electric, PSE&G, Carolina P&L.

26Union Electric adds that there is no evidence

that any existing economy energy coordination

agreements are unduly discriminatory and require

modification.

27PSE&G at 6.

28See also PSE&G.

29See also Carolina P&L.

30Blue Ridge at 16.

purchase transactions under existing

economy energy coordination

agreements 22 to require that the

transmission service associated with

those transactions be provided pursuant

to the Final Rule’s requirements of nondiscriminatory open access, no later

than December 31, 1996. The

Commission also required that, for new

economy energy coordination

agreements 23 where the transmission

owner uses its transmission system to

make economy energy sales or

purchases, the transmission owner must

take such service under its own

transmission tariff as of the date trading

begins under the agreement.24

Finally, the Commission concluded

that it would not require the

modification of non-economy energy

coordination agreements. However, the

Commission noted that this does not

insulate such agreements from

complaints that transmission service

provided under such agreements should

be provided pursuant to the Final Rule

pro forma tariff.

Rehearing Requests

Various utilities oppose the

Commission’s finding that it is in the

public interest to permit the

modification of existing requirements

contracts that contain Mobile-Sierra

clauses. On the other hand, a number of

customers assert that the Commission

did not go far enough and seek

enhanced contract reformation rights.

Utilities Against Contract Reformation

Several utilities argue that the

Commission’s finding is not supported

by substantial evidence.25 Utilities For

Improved Transition asserts that the

Commission cannot rely on economic

theory as a substitute for substantial

evidence.26 It argues that the record in

this proceeding demonstrates that the

marketplace is becoming increasingly

competitive without mandatory tariffs,

which is evidence of market health, not

market problems. It further argues that

even if undue discrimination is proven,

the remedy is not needed because the

record shows that existing programs are

meeting the industry’s needs.

Southwestern argues that the

Commission has improperly chosen to

ignore the public interest standard and

has failed to make the contract specific

analysis here that it performed in

Northeast Utils. Serv. Co., 66 FERC ¶

61,332 (1994), aff’d, 55 F.3d 686 (1st

Cir. 1995). PSE&G and Carolina P&L

also argue that the Commission failed to

demonstrate the ‘‘unequivocal public

necessity’’ for generically abrogating the

Mobile-Sierra clauses and assert that the

Commission has presented no evidence

as to how the public interest will be

served by abrogating these contracts.

PSE&G and Carolina P&L further argue

that the Commission cannot avoid

making a public interest determination

‘‘by the simple expedient of asserting

that the public interest requires it to

ignore the Mobile-Sierra clauses that

required that public-interest

determination in the first place.’’ 27

Union Electric and PSE&G argue that

the Commission, in justifying its public

interest finding, inappropriately focused

on the interests of the parties to the

contract instead of on whether nonparties will be adversely affected by the

existing contracts.

Public Service Co of CO asserts that

the Commission should clarify the

definition of requirements contract to

include long-term block purchases of

electricity. It states that it purchases a

large percentage of its system

requirements under long-term block

purchase agreements, and that under the

Commission’s abrogation policy in

Order No. 888, its ability to abrogate

these supply arrangements would be

treated differently because its contracts

do not meet the definition of a

‘‘wholesale requirements contract,’’ as

defined in new section 35.26(b)(1) of the

Commission’s Regulations. Public

Service Co of CO further asserts that the

Commission has not adequately

explained why it is appropriate or in the

public interest to allow partial

requirements customers to abrogate

their contracts, but not similarly to

allow a public utility to abrogate its

supply arrangements.28

PSE&G and Carolina argue that the

availability of stranded cost recovery

cannot support allowing customers to

modify rates under Mobile-Sierra

clauses that required that public-interest

determination in the first place.

PSE&G and Carolina P&L also argue

that no Mobile-Sierra contracts entered

into after October 24, 1992 (the date

EPAct became law) should be subject to

the Rule because since that date

customers have been able to apply for

an order under section 211 to have

power transmitted to them from

suppliers other than the utility to whom

they are interconnected.

PSE&G requests that the Commission

clarify that the just and reasonable

standard used in considering a contract

abrogation claim will be limited to a

determination of whether the rate is just

and reasonable within the cost-based

zone of reasonableness of the selling

public utility. Such an analysis, PSE&G

asserts, should not include a

comparison to what other utilities offer

to their customers.29

Customers Seek Enhanced Contract

Reformation Rights

TAPS argues that the Commission

should apply a just and reasonable

standard to requests by all ‘‘victims’’ of

undue discrimination to seek

modifications of requirements or

transmission contracts, whether they are

subject to Mobile-Sierra or not. On the

other hand, TAPS asserts that utilities

should be bound to the bargain they

extracted from transmission customers.

Wisconsin Municipals request that the

Commission clarify that parties may

seek mandatory abrogation of

preexisting transmission contracts or

provisions and that the Commission

will apply a rebuttable presumption that

terms and conditions inferior to the pro

forma tariff are unjust and unreasonable

on their face.

CCEM argues that requirements

customers should receive blanket

conversion rights. At a minimum, CCEM

asserts, if a customer seeks conversion,

the burden of proof in the proceeding

should shift to the utility. CCEM also

emphasizes that the question remains

why conversion was deemed essential

in natural gas markets, but not in the

transition to competition in the electric

industry.

Blue Ridge argues:

In neither the power supply nor

transmission access case should a provider

be allowed to modify existing power supply

contracts under any but the Mobile Sierra

public interest burden of proof. In both the

power supply or transmission access cases,

the Commission should articulate the

suggested standards for what constitutes a

prima facia case. [30]

Commission Conclusion

Before responding to the rehearing

arguments raised, we wish to clarify our

Mobile-Sierra findings. We explained in

Order No. 888 that we were making two
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12285

31We note that the fact that a contract may bind

a utility to a Mobile-Sierra public interest standard

does not necessarily mean that the customer is also

bound to that standard. Unless a customer

specifically waives its section 206 just and

reasonable rights, the Commission construes the

issue in favor of the customer. See Papago Tribal

Utility Authority v. FERC, 723 F.2d 950, 954 (D.C.

Cir. 1983).

32 In situations in which a customer institutes a

section 206 proceeding to modify a contract that

binds the utility to a Mobile-Sierra public interest

standard, the utility may make whatever arguments

it wants regarding any of the contract terms,

including those unrelated to stranded costs, but will

be bound to a Mobile-Sierra public interest standard

for contract terms that do not relate to stranded

costs.

33Similarly, as discussed in Section IV.J, parties

have taken extreme positions as to stranded cost

recovery.

34As to existing economy energy coordination

agreements, the Commission concludes that the

evidence also supports its decision to condition

future sales and purchase transactions that may

occur under the ongoing umbrella coordination

agreements. Specifically, we are requiring that the

transmission service associated with these future

transactions be provided pursuant to the Final Rule

pro forma tariff. See Public Service Electric & Gas

Company, 78 FERC ¶61,119, slip op. at 4 and n.7

(1997).

35As discussed below, pre-July 11, 1994 contracts

were entered into during an era in which

transmission providers exerted monopoly control

over access to their transmission facilities. The

unequal bargaining power between utilities and

captive customers is the basis for our determination

that utilities that have pre-July 11 Mobile-Sierra

requirements contracts will have to satisfy the

public interest standard in order to effectuate any

non-stranded cost change to the contract, but that

customers to such contracts will be able to

effectuate any change by satisfying a just and

reasonable standard.

36We will not grant the request by PSE&G and

Carolina P&L that the just and reasonable standard

will be limited to a determination of whether the

rate is just and reasonable within the cost-based

zone of reasonableness of the selling utility and

should not include a comparison to what other

utilities offer their customers. Because stranded

costs will be taken into account when customers

seek contract termination or modification, it would

not be appropriate to limit customers in the

evidence they may present.

complementary public interest findings.

First, as discussed further in Section

IV.J, we found that it is in the public

interest to permit public utilities to seek

stranded cost amendments to existing

requirements contracts with MobileSierra clauses. Second, we found that a

‘‘party’’ to a requirements contract

containing a Mobile-Sierra clause no

longer will have the burden of

establishing independently that it is in

the public interest to permit the

modification of such contract, but still

will have the burden of establishing that

such contract no longer is just and

reasonable and therefore ought to be

modified. We clarify that, in making this

second finding, our reference to a

‘‘party’’ to a requirements contract

containing a Mobile-Sierra clause was

directed at modification of contract

provisions by customers. 31

Additionally, it applies to any contract

revisions sought, whether or not they

relate to stranded costs. 32

In response to the Mobile-Sierra

rehearing arguments described above, as

well as the Mobile-Sierra arguments

described in Section IV.J concerning our

determinations regarding stranded cost

amendments to contracts, the

Commission believes it is important to

first address the general context in

which our Mobile-Sierra determinations

have been made. In Order No. 888, the

Commission removed the single largest

barrier to the development of

competitive wholesale power markets

by requiring non-discriminatory open

access transmission as a remedy for

undue discrimination. This action

carries with it the regulatory public

interest responsibility to address the

difficult transition issues that arise in

moving from a monopoly, cost-based

electric utility industry to an industry

that is driven by competition among

wholesale power suppliers and

increasing reliance on market-based

generation rates.

There are two predominant,

overlapping transition issues that arise

as a result of our actions in this

rulemaking: first, how to deal with the

uneconomic sunk costs incurred, and

second, how to deal with the contracts

that were entered into, under an

industry regime that rested on a

regulatory framework and set of

expectations that are being

fundamentally altered. To address these

issues, the Commission has balanced a

number of important interests in order

to achieve what it believes will be a fair

and orderly transition to competitive

markets. These interests include the

financial stability of the electric utility

industry and permitting customers to

obtain the benefits of competitive

markets without undue disruption or

unfairness to other customers or

industry participants.

As the above rehearing arguments

demonstrate, there is no consensus on

how the Commission should manage the

transition. In fact, parties offer diverse

and conflicting views as to what the

Commission should do regarding

existing contracts. Some would have us

let all contracts run their course with no

opportunity for customers to modify or

terminate their contracts, no matter how

long the contracts or how onerous their

terms. Others advocate automatic

generic abrogation of all contracts. Yet

others want a guaranteed automatic

right to renew a contract if it happens

to contain favorable rates and terms.33

Rather than adopting one extreme

position or the other, the Commission

has taken a measured approach with

regard to contract modification,

including modification of contracts that

contain Mobile-Sierra clauses. Our goal

is to balance the desire to honor existing

contractual arrangements with the need

to provide some means to accelerate the

opportunity of parties to participate in

competitive markets. To accomplish this

balance, the Commission, first, has

made Mobile-Sierra public interest

findings (discussed further below) only

as to a limited set of contracts: those

wholesale requirements contracts

executed on or before July 11, 1994,

which is the date of our first stranded

cost proposed rulemaking and which

served to put the industry and

customers on notice that future

contracts should explicitly address the

rights, obligations and expectations of

parties, including stranded cost

obligations.34

Second, with regard to contract

modifications sought by utilities, as

discussed in more detail in Section IV.J,

utilities that seek to add stranded cost

provisions have a high evidentiary

burden to meet before they can add

contract provisions that permit stranded

cost recovery beyond the end of their

contract terms; the burden is

particularly high in the case of contracts

with notice provisions. With regard to

modifications of contract provisions that

do not relate to stranded costs, a utility

with a Mobile-Sierra contract clause will

have the burden of showing that the

provisions are contrary to the public

interest.35

Third, with regard to contract

modifications sought by customers, a

customer will have to show that the

provisions it seeks to modify are no

longer just and reasonable.36 If a

customer seeks to shorten or eliminate

the term of an existing contract, any

contract modification approved by the

Commission will take into account the

issue of appropriate stranded cost

recovery by the customer’s supplying

utility.

In permitting customers the

opportunity to seek these types of

modifications, even for contracts that

contain Mobile-Sierra clauses, the

Commission has based its public

interest findings on the unprecedented

industry changes facing utilities and

their customers. While, as we stated in

the Final Rule, there is no market failure

in the electric industry that would

justify generic abrogation of existing

contracts, nevertheless the industry is in

the midst of fundamental change. We

cannot conclude that it is in the public

interest to require all customers to be
12286 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

37We note that some of the very parties making

this challenge either do not object to the

Commission’s Mobile-Sierra findings permitting

utilities to add stranded cost amendments to their

contracts, or ask the Commission to broaden even

further the scope of extra-contractual stranded cost

recovery under the rule.

38We also reject arguments that a remedy is not

needed because existing programs, i.e., those prior

to Order No. 888, are meeting the needs of the

industry. This very rulemaking, with the substantial

comments filed by entities pointing out the failures

of the current system and the need for change, and

the extensive restructurings and state-initiated open

access programs occurring around the country, on

their face, refute these arguments.

39 It is also clear from the number of entities filing

comments on the NOPR and rehearing requests of

the Final Rule that many entities believe that their

contracts were the result of uneven bargaining

power and that they should be provided the

opportunity to seek to terminate their existing

contracts.

40 In an era that was not characterized by

competition in the generation sector, the

Commission’s response was to ensure that the rates

for such contracts were no higher than the seller’s

cost (including a reasonable return on equity). In

this way, the Commission sought to limit the

seller’s ability to reap the benefits of the seller’s

monopoly position.

41See FPC v. Sierra Pacific Power Company, 350

U.S. 348, 355 (1956); Northeast Utilities Service

Company, 66 FERC ¶ 61,332 (1994), aff’d, 55 F.3d

686, 691 (1st Cir. 1995); Mississippi Industries v.

FERC, 808 F.2d 1525, 1553 (D.C. Cir. 1987).

42We will not exclude Mobile-Sierra contracts

entered into after the effective date of EPAct, as

argued by PSE&G and Carolina P&L. As we

explained in the Final Rule, there are significant

time delays associated with section 211

proceedings. Accordingly, the availability of a

section 211 proceeding cannot substitute for readily

available service under a filed non-discriminatory

open access tariff. FERC Stats. & Regs. at 31,646;

mimeo at 35. We do not believe that EPAct created

the expectation of open access on such a broad

scale that we can assume that parties no longer

generally expected ‘‘business as usual’’ to continue,

and we will not presume that the exercise of market

power was not at work when Mobile-Sierra

contracts were entered into after EPAct. We also

note that these arguments are similar to those

proffered by opponents of stranded cost recovery,

who argue that after EPAct utilities had no

reasonable expectation of continuing to serve

customers beyond the terms of existing contracts. In

this context as well, we will not presume that, after

EPAct, utilities could have no reasonable

expectation of continuing to serve a customer

beyond the contract term.

43As the D.C. Circuit explained in Papago Tribal

Utility Authority v. FERC, 723 F.2d 950 (D.C. Cir.

1983) (Papago), there are essentially three

contractual arrangements for rate revision: (1) the

parties agree that the utility may file new rates

under section 205, subject to the just and reasonable

standard of review; (2) the parties agree to eliminate

the utility’s right to file rates under section 205 and

the Commission’s right to change pre-existing rates

under section 206’s just and reasonable standard

(leaving the Commission’s indefeasible right to

change pre-existing rates that are contrary to the

public interest); and (3) the parties agree to

eliminate the utility’s right to file new rates under

section 205, but leave unaffected the Commission’s

power to change pre-existing rates under section

206’s just and reasonable standard of review. 723

F.2d at 953. The same contractual arrangements

also would apply to non-rate terms and conditions.

We here address those contractual arrangements

that eliminate the rights of one or both parties to

modify a contract under the just and reasonable

standard. We note that the Commission always has

the indefeasible right under section 206 to change

rates, terms or conditions that are contrary to the

public interest. 723 F.2d at 953–55; see also Florida

Power & Light Company, 67 FERC ¶ 61,141 at

61,398 (1994) appeal dismissed, No. 94–1483 (D.C.

Cir. July 27, 1995) (unpublished); Southern

Company Services, Inc., 67 FERC ¶ 61,080 at

61,227–28 (1994); Mississippi Industries v. FERC,

808 F.2d 1525, 1552 n.112.

44We reject the arguments of PSE&G and Carolina

P&L that we have failed to demonstrate the

‘‘unequivocal public necessity’’ for generically

‘‘abrogating’’ Mobile-Sierra clauses and that we

have presented no evidence as to how the public

interest will be served by abrogating these contracts.

We have concluded that there is a public necessity

to permit the opportunity to seek contract changes

in light of fundamental industry changes. However,

we have not abrogated any contracts by this Rule.

45FERC Stats. & Regs. at 31,664; mimeo at 84.

held to requirements contracts that were

executed under the prior industry

regime, no matter what the

circumstances of those contracts.

In response to parties who challenge

the Commission’s finding that it would

be against the public interest to deny

customers an opportunity to seek

modification of wholesale requirements

contracts executed on or before July 11,

1994,37 these parties ignore the fact that

these contracts were entered into during

an era in which transmission providers

exercised monopoly control over access

to their transmission facilities.38 The

majority of customers under these types

of contracts were captive, i.e., they had

no realistic choice but to purchase

generation from their local utility

because they had no transmission to

reach another supplier. Many of these

contracts were the result of uneven

bargaining power between customers

and monopolist transmission

providers.39 While monopolist

transmission providers may not have

exercised monopoly power in all

situations,40 the unprecedented

competitive changes that have occurred

(and are continuing to occur) in the

industry may render their contracts to

be no longer in the public interest or

just and reasonable. These changed

circumstances, discussed at length in

the Final Rule, and the further changes

that will occur as a result of open access

transmission, may affect whether such

contracts continue to be just and

reasonable or not unduly discriminatory

both as to the direct customers of the

contracts, as well as to indirect, thirdparty consumers as well.41

We therefore reject arguments that

there is no ‘‘evidence’’ to support our

finding that it is in the public interest

to permit review of these contracts in

light of the specific circumstances

surrounding the contracts and in light of

dramatically changed industry

circumstances. We emphasize, however,

that our decision is to permit an

opportunity for review and that we will

require a case-by-case showing that any

modifications should be permitted. 42

As we explained in the Final Rule, this

decision complements our decision that

it is in the public interest to permit

amendments to add stranded cost

provisions to existing contracts if caseby-case evidentiary burdens are met.

As we discuss further in our detailed

stranded cost discussion in Section IV.J,

we do not interpret the Mobile-Sierra

public interest standard as practically

insurmountable 43 in the extraordinary

situation before us where historic

statutory and regulatory changes have

converged to fundamentally change the

obligations of utilities and the markets

in which both they and their customers

will operate. The ability to meet our

overarching public interest

responsibilities and to protect

consumers would be virtually precluded

if we were to apply a practically

insurmountable standard of review

before taking into account these

fundamental industry-wide changes.44

With respect to Public Service Co of

CO’s argument, we disagree that the

definition of a wholesale requirements

contract should be modified to include

a long-term block purchase of

electricity. In the majority of

circumstances, such long-term supply

contracts are voluntary arrangements in

which neither party had market power.

It would be inappropriate to make

generic Mobile-Sierra findings as to

these types of contracts. Parties can

avail themselves of the section 205 and

206 procedures already available to

them if they want to seek modification

of such contracts.

Finally, we reject CCEM’s argument

that all customers should receive

automatic conversion rights because

customers were provided such a right in

the restructuring of the natural gas

industry. We have taken, as is within

our discretion, a substantially different

approach here from that taken when we

restructured the natural gas industry. As

we stated in the Final Rule, and as

alluded to above, at the time the

Commission addressed this situation in

the natural gas industry it was faced

with shrinking natural gas markets,

statutory escalations in natural gas

ceiling prices under the Natural Gas

Policy Act, and increased production of

gas.45 Moreover, the natural gas industry

was plagued with escalating take-or-pay

liabilities.

There was a market failure in the

natural gas industry that required the
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12287

46FERC Stats. & Regs. at 31,665; mimeo at 88.

47The Commission explained that this right of

first refusal exists whether or not the customer buys

power from the historical utility supplier or another

power supplier. If the customer chooses a new

power supplier and this substantially changes the

location or direction of its power flows, the

customer’s right to continue taking transmission

service from its existing transmission provider may

be affected by transmission constraints associated

with the change. 48See also AEC & SMEPA.

49All transmission contracts with public utility

transmitters can only be terminated by a filing with

the Commission under FPA section 205. Thus, the

Commission has interpreted its section 205

authority as permitting it to suspend termination of

service for 5 months beyond the expiration of a

contract’s term if such action is necessary to protect

ratepayers. See, e.g., Kentucky Utilities Company,

67 FERC ¶ 61,189 at 61,573 (1994). (While the

termination procedures for power sales contracts

executed after July 9, 1996 were modified in Order

No. 888, there were no changes regarding

termination procedures for transmission contracts.).

extraordinary measure of generically

allowing all customers to break their

contracts with pipelines. In contrast,

market circumstances in the electric

industry today do not compel generic

abrogation of contracts. The more

moderate approach we have taken will

permit us to take into account the

fundamental industry changes that have

occurred (and will continue to occur), to

balance the interests of all affected

parties, and to help avoid drastic shocks

to industry participants.

Right of First Refusal

In the Final Rule, the Commission

concluded that all firm transmission

customers (requirements and

transmission-only), upon the expiration

of their contracts or at the time their

contracts become subject to renewal or

rollover, should have the right to

continue to take transmission service

from their existing transmission

provider.46 If not enough capacity is

available to meet all requests for service,

the right of first refusal gives the

existing customer who had

contractually been using the capacity on

a long-term, firm basis the option of

keeping the capacity. However, the

limitations imposed by the Commission

are that the underlying contract must

have been for a term of one-year or more

and the existing customer must agree to

match the rate offered by another

potential customer, up to the

transmission provider’s maximum filed

transmission rate at that time, and to

accept a contract term at least as long as

that offered by the potential customer.47

Moreover, the Commission indicated

that this right of first refusal is an

ongoing right that may be exercised at

the end of all firm contract terms

(including all future unbundled

transmission contracts).

Requests for Rehearing

On rehearing, most petitioners agree

with or do not contest the notion of

providing existing transmission

customers with a right of first refusal,

but many have requested modification

or clarification of the Commissionimposed limitations on such a right. A

variety of transmission customers assert

that the Commission’s right of first

refusal provision fails to adequately

protect existing transmission customers’

rights to continued service and seek

changes to the Commission’s provision.

On the other hand, a number of utilities

believe that the Commission should

provide additional restrictions on the

right of first refusal.

Customers’ Positions

APPA argues that (1) existing

customers should only have to agree to

service that matches the term of any

power supply contract for which it will

use the transmission arrangement or, in

the absence of a generation contract, one

year, and (2) the pricing provision

should be changed to reflect the current

just and reasonable rate, as approved by

the Commission, for similar

transmission service.

NRECA also argues that the term and

pricing provisions of section 2.2 need to

be changed. With respect to the term of

the contract the customer should be

required to match, NRECA asserts that

it should be one year, which

corresponds to the definition of longterm firm service in the tariff. With

respect to the rate, NRECA requests that

the Commission cap the obligation to

match the price offered by another

customer at the maximum transmission

rate the incumbent customer is

obligated to pay to the transmission

provider at the close of the prior

contract term.

TDU Systems argue that the right of

first refusal provision fails to take into

consideration amounts that TDUs have

contributed to the development of the

transmission systems through prior

transmission rates. TDU Systems are

concerned about the possibility of an

increase in the price of transmission

capped only by the cost of increasing

the capacity of the provider’s

transmission system.

TAPS requests that the Commission

clarify that the transmission provider

may only charge its then effective rates

for existing, non-constrained

transmission capacity because to allow

opportunity or expansion costs would

perpetually put the existing

transmission customers on the margin at

the end of their contract terms

subjecting them to higher rates than the

transmission provider.48

Blue Ridge raises a possible

discrepancy between the language in the

tariff and the language in the preamble.

It asserts that section 2.2 ‘‘requires the

existing customer to ‘pay the current

just and reasonable rate, as approved by

the Commission,’ while the Regulatory

Preamble requires the customer to

‘match the rate offered by another

potential customer, up to the

transmission provider’s maximum filed

transmission rate at that time.’ Order

No. 888, mimeo at 88.’’

Tallahassee asks the Commission to

clarify that the right of first refusal to

presently bundled transmission capacity

accrues to the power customer paying

the bundled rate and not to the

intermediary acting on behalf of the

customer.

AEC & SMEPA maintain that the price

and term limitations of section 2.2

would place TDUs at a competitive

disadvantage vis-a-vis the transmission

provider by subjecting TDUs to

incremental costs, including the costs of

system upgrades, if other new customers

are vying to use the transmission

system. They state that the Commission

must provide existing transmission

customers the same rights as the

transmission provider’s other native

load customers.

Utilities’ Positions

PSNM argues that imposing a right of

first refusal is inconsistent with the

Commission’s finding that contracts

should not be abrogated. In effect, it

argues that imposition of the right of

first refusal abrogates existing contracts

executed with the expectation that

capacity could be recalled for the

utility’s own use upon expiration of the

contracts. PSNM explains that it has a

constrained transmission system and

has been balancing specific contract

durations against projected future native

loads so that required capacity may be

made available for use by third parties

in the short-term, but not be committed

to those parties at the time it is needed

to be recalled. Moreover, PSNM asserts

that Order No. 888 is not supported by

the right of first refusal process of Order

No. 636 because the Commission does

not have abandonment authority under

the FPA and its authority to require

continuation of service is not welldefined and is controversial.49

Utilities For Improved Transition and

Florida Power Corp argue that section

2.2 of the pro forma tariff should be

modified by ‘‘restricting rollover rights

to the same points of receipt and

delivery as the terminating service and
12288 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

50We clarify that we did not intend the term ‘‘all

firm transmission customers’’ to include only

requirements and transmission-only customers, but

intended that it include all bundled firm customers

as well.

51We reject Tallahassee’s argument that the right

of first refusal should accrue to the power customer

paying the bundled rate and not to any

intermediary acting on its behalf. Our right of first

refusal mechanism is simply a tie-breaker that gives

priority to existing firm transmission customers.

52The proposal to restrict the right of first refusal

provision to exactly the same points of receipt and

delivery as the terminating service would

competitively disadvantage existing customers

seeking new sources of generation. However, as we

stated in Order No. 888, if the customer chooses a

new power supplier and this substantially changes

the location or direction of the power flows it

imposes on the transmission provider’s system, the

customer’s right to continue taking transmission

service from its existing transmission provider may

be affected by transmission constraints associated

with the change. FERC Stats. & Regs. at 31,666

n.176; mimeo at 89 n.176.

53As Order No. 888 indicates, they may be

required to pay the transmission provider’s

maximum transmission rate.

by providing the customer notice of a

competing application and 90 days in

which to file its own application for

service for a term at least as long as the

competing application.’’ (Florida Power

Corp at 11–13; Utilities For Improved

Transition at 50–53). Similarly, EEI

argues that to obtain a priority for

continuation of service, customers must

be seeking service that is substantially

similar to or a continuation of the

service they already receive and must be

subject to a time limit on the reservation

priority. CSW Operating Companies

assert that it is unclear how the right of

first refusal provision will be

implemented.

State Commission Position

VT DPS states that the right of first

refusal provision offers inadequate

protection: ‘‘While it is true that the

existing customer could secure a five

year transmission arrangement under a

new contract, its right to continuous

service is placed in jeopardy if it does

not match the six year offer of the

competing bidder.’’ VT DPS argues that

the Commission’s bare bones provision

opens the opportunity for competitive

mischief by the transmission provider.

VT DPS proposes that ‘‘the existing

customer should be able to renew its

contract by matching the highest

transmission price offered in the

marketplace (up to the tariff maximum

rate) and by offering to extend its

contract for seven years or the

prevailing length of firm transmission

contracts in the marketplace, whichever

is shorter.’’ (VT DPS at 17–21).

Commission Conclusion

In this order, the Commission

reaffirms its decision to give a

reservation priority to existing and

future firm transmission customers

served under a contract of one year or

more, and also addresses petitioner

arguments regarding the Commissionimposed limitations associated with the

exercise of that priority.

Rationale

Our policy rationale for giving an

existing firm transmission customer

(requirements and transmission-only),50

served under a contract of one year or

more, a reservation priority (right of first

refusal) when its contract expires is that

it provides a mechanism for allocating

transmission capacity when there is

insufficient capacity to accommodate all

requestors. If there are capacity

limitations and both customers (existing

and potential) are willing to pay for firm

transmission service of the same

duration, the right of first refusal

provides a tie-breaking mechanism that

gives priority to existing customers so

that they may continue to receive

transmission service.51

Contract Term Limitation

We reject arguments to modify the

requirement in section 2.2 that existing

long-term firm transmission customers

seeking to exercise their right of first

refusal must agree to a contract term at

least as long as that sought by a

potential customer. The objective of a

right of first refusal is to allow an

existing firm transmission customer to

continue to receive transmission service

under terms that are just, reasonable,

not unduly discriminatory, or

preferential. Absent the requirement

that the customer match the contract

term of a competing request, utilities

could be forced to enter into shorterterm arrangements that could be

detrimental from both an operational

standpoint (system planning) and a

financial standpoint.

Rate Limitation

We also reject the proposition that

either existing wholesale customers or

transmission providers providing

service to retail native load customers

should be insulated from the possibility

of having to pay an increased rate for

transmission in the future. The fact that

existing customers historically have

been served under a particular rate

design does not serve to ‘‘grandfather’’

that rate methodology in perpetuity.

Because the purpose of the right of first

refusal provision is to be a tie-breaker,

the competing requests should be

substantially the same in all respects.52

In response to Blue Ridge’s concern

regarding a discrepancy between the

language in section 2.2 of the tariff and

the preamble, we clarify that existing

customers who exercise their right of

first refusal will be required to pay the

just and reasonable rate, as approved by

the Commission at the time that their

contract ends.53

Mechanics of the Right of First Refusal

Process

CSW Operating Companies asked the

Commission to clarify the mechanics of

exercising the right of first refusal. We

have determined not to specify in this

order the mechanics by which the right

of first refusal mechanism will be

exercised for existing firm transmission

arrangements. Instead, we intend to

address such issues on a case-by-case

basis, if and when a dispute arises.

However, we encourage utilities and

their customers to include specific

procedures for exercising the right of

first refusal in future transmission

service agreements executed under the

pro forma tariff. And of course, utilities

are free to make section 205 filings to

propose additions to the pro forma tariff

to generically specify procedures for

dealing with the issues.

Existing Contracts

By providing existing customers a

right of first refusal, we are not, as

PSNM claims, abrogating contracts.

Moreover, PSNM’s concern that the

right of first refusal will prohibit

utilities from ‘‘recalling’’ existing

capacity to meet native load growth that

was anticipated at the time existing

third-party transmission contracts were

executed can be addressed in the

context of a specific filing by a utility

demonstrating that it had no reasonable

expectation of continuing to provide

transmission service to the wholesale

transmission customer at the end of its

contract. For future transmission

contracts, Order No. 888 permits

utilities to reserve existing transmission

capacity to serve the needs (current and

reasonably forecasted) of its existing

native load (retail) customers. Moreover,

if a utility provides firm transmission

service to a third party for a time until

native load needs the capacity, it should

specify in the contract that the right of

first refusal does not apply to that firm

service due to a reasonably forecasted

need at the time the contract is

executed.

Informational Filings

With respect to all existing

requirements contracts and tariffs that

provide for bundled rates, the

Commission, in the Final Rule, required

all public utilities to make informational
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12289

54FERC Stats. & Regs. at 31,665–66; mimeo at 89–

90.

55 77 FERC ¶ 61,025.

56FERC Stats. & Regs. at 31,665; mimeo at 87–88.

57 76 FERC ¶ 61,009 at 61,028 (1996).

58FERC Stats. & Regs. at 31,668; mimeo at 96–98.

59FERC Stats. & Regs. at 31,668–79 and 31,686–

87; mimeo at 98–129 and 148–51.

60Associated Gas Distributors v. FERC, 824 F.2d

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

1006 (1988) (AGD).

61Otter Tail Power Company v. FPC, 410 U.S. 366

(1974) (Otter Tail).

filings setting forth the unbundled

power and transmission rates reflected

in those contracts and tariffs.54

Requests for Rehearing

Utilities For Improved Transition and

VEPCO ask the Commission to clarify

whether the unbundled transmission

rate should be the current transmission

tariff rate (bundled rate likely not to

include the current price for

transmission service) or an

approximation of the rate at the time the

contract was executed (may be

impossible to determine).

Commission Conclusion

We previously addressed the

determination of the unbundled

transmission rate in informational

filings in an order issued October 16,

1996.55 In that order, we noted that

Order No. 888 does not prescribe any

specific method for calculating

separately-stated transmission and

generation rates and public utilities

have used different methods in their

informational filings. Because of the

general lack of controversy over the

informational filings and the fact that

they are for informational purposes as a

benefit to existing customers, the

Commission accepted the vast majority

of the informational filings. The

Commission added, however, that it did

not consider the informational rates

binding for any future transactions.

Accordingly, we need not now prescribe

a specific method to calculate the

unbundled transmission rate included

in informational filings.

Existing Contracts

In the Final Rule, the Commission

explained that because it was not

abrogating existing requirements and

transmission contracts generically and

because the functional unbundling

requirement applies only to new

wholesale services, the terms and

conditions of the Final Rule pro forma

tariff do not apply to service under

existing requirements contracts.56

Rehearing Requests

San Francisco asks that the

Commission clarify that nothing in

Order No. 888 is intended to affect

prices, or price-setting methodologies,

in existing contracts.

Commission Conclusion

By order issued July 2, 1996, we

clarified that

the filing of an open access compliance

tariff on or before July 9, 1996 does not

supersede an existing transmission

agreement that has been accepted by the

Commission unless specifically permitted in

the agreement on file. If a utility seeks to

modify or terminate an existing transmission

agreement, it must separately file to modify

or terminate such contracts under

appropriate procedures under section 205 or

206 of the Federal Power Act, consistent with

the terms of its contract.[57]

Thus, nothing in Order No. 888 affects

prices or price-setting methodologies in

existing contracts, unless specifically

permitted in the contract on file.

6. Flow-based Contracting and Pricing

In Order No. 888, the Commission

explained that it would not, at that time,

require that flow-based pricing and

contracting be used in the electric

industry.58 It recognized that there may

be difficulties in using a traditional

contract path approach in a nondiscriminatory open access transmission

environment. At the same time,

however, the Commission noted that

contract path pricing and contracting is

the longstanding approach used in the

electric industry and it is the approach

familiar to all participants in the

industry. Thus, the Commission was

concerned that to require a dramatic

overhaul of the traditional approach—

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

severely slow, if not derail for some

time, the move to open access and more

competitive wholesale bulk power

markets. In addition, the Commission

indicated its belief that it would be

premature to impose generically a new

pricing regime without the benefit of

any experience with such pricing.

Accordingly, the Commission welcomed

new and innovative proposals, but

determined not to impose some form of

flow-based pricing or contracting in the

Final Rule.

Rehearing Requests

American Forest & Paper argues that

contract path pricing should be

prohibited. American Forest & Paper

asserts that QFs and other independents

are being forced by contract path

wheeling utilities to indemnify them

from liability for third-party claims of

inadvertent flow costs resulting from the

transaction, while paying postage stamp

rates for the entire amount of contracted

transmission. American Forest & Paper

supports an average postage stamp rate

by region, with the utilities within the

region agreeing on a way to divide up

the rate appropriately.

Commission Conclusion

As the Commission explained in the

Final Rule, we are concerned that a

dramatic overhaul of the traditional

contract path approach could slow or

derail the move to open access and, in

any event, is premature without the

benefit of any experience with

alternative pricing regimes. The

Commission, however, welcomes new

and innovative proposals from the

industry. American Forest & Paper has

not presented a case-specific proposal of

any detail that would provide the

Commission and interested parties the

opportunity to test the appropriateness

of a change from the contract path

approach. Until the Commission has

such an opportunity, we are not

prepared to change generically the

traditional contract path approach with

which the electric industry is so

familiar.

Moreover, American Forest & Paper’s

proposal to prohibit contract path

pricing and mandate regional postagestamp rates would be inconsistent with

the rate flexibility that the Commission

provided in the Transmission Pricing

Policy Statement and embraced in the

Final Rule.

B. Legal Authority

In the Final Rule, the Commission

responded to commenters challenging

the Commission’s authority to require

open access and reaffirmed its

conclusion in the NOPR that it has the

authority under the FPA to order

wholesale transmission services in

interstate commerce to remedy undue

discrimination by public utilities.59

Rehearing Requests

Authority To Order Open Access Tariffs

Union Electric challenges the

Commission’s authority to require

wheeling based on arguments that: (1)

the Rule overlooks the fact that the AGD

case 60 pertained to voluntary actions by

the pipelines and the Commission’s

imposition of open access requirements

as a condition on permitting the desired

authorizations; (2) the Commission

incorrectly treats the Otter Tail case; 61

(3) the legislative histories of the NGA

and FPA are different and the legislative

history of the FPA does not support the

Commission’s authority to order

wheeling; (4) the Commission made

prior contrary statements to the U.S.
12290 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

62Richmond Power & Light Company v. FERC,

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

Florida Power & Light Company v. FERC, 660 F.2d

668 (5th Cir. 1981), cert. denied sub nom. Fort

Pierce Utilities Authority v. FERC, 459 U.S. 1156

(1983) (FPL).

63We note that Indianapolis P&L also has made

legal arguments regarding our authority to order

wheeling under Order No. 888. However, it did so

in a request for rehearing of a denial of its request

for waiver of the Order No. 888 requirements, not

in its request for rehearing of Order No. 888.

Accordingly, we will address its arguments when

we act on its request for rehearing of its waiver

denial.

64FERC Stats. & Regs. at 31,668–73; mimeo at 98–

112. Notice of Proposed Rulemaking and

Supplemental Notice of Proposed Rulemaking,

FERC Stats. & Regs. ¶32,514 at 33,053–56 (1995).

65FERC Stats. & Regs. at 31,673–79; mimeo at

112–129.

66See FERC Stats. & Regs. at 31,669–70; mimeo

at 101–03.

67 824 F.2d at 998.

68See FERC Stats. & Regs. at 31,676–78; mimeo

at 120–27.

69See FERC Stats. & Regs. at 31,668–73; mimeo

at 98–110.

Supreme Court [in its opposition to the

grant of certiorari to review the AGD

decision] about the nature of

Commission authority to order open

access and judicial construction of that

authority in AGD and Otter Tail;’’ (5) as

a matter of statutory construction, the

Commission cannot rely on sections 205

and 206, which are silent as to

wheeling, when sections 211 and 212

contain express wheeling provisions; (6)

the four relevant cases recognized by the

Commission indicate that the

Commission may not directly or

indirectly order a public utility to wheel

or transmit energy for another entity

under sections 205 and 206,

notwithstanding the Commission’s

circumscribed ability to order wheeling

under sections 211 and 212; (7) prior to

the issuance of the Final Rule the

Commission, with a full appreciation of

the legislative history behind Part II,

consistently held that it lacks the

authority to order wheeling under FPA

Part II; (8) the Rule fails to assign

‘‘considerable importance’’ to the

Commission’s ‘‘longstanding

interpretation of the statute in

accordance with its literal language;’’

and (9) in legislative hearings preceding

enactment of EPAct, the Office of the

General Counsel acknowledged the

limitations on the Commission’s

wheeling power.

Carolina P&L also challenges the

Commission’s authority to order open

access tariffs, arguing that: (1) Otter Tail

specifically states: ‘‘So far as wheeling

is concerned, there is no authority

granted the commission under Part II of

the Federal Power Act to order it,

* * *’’; (2) the Richmond and FPL

cases 62 prohibit the Commission from

doing indirectly what it cannot do

directly; (3) the AGD case does not

support the Commission’s authority to

order open access through the filing of

generic tariffs—in AGD the

Commission’s authority was based on

voluntary actions by the affected

pipelines and there are substantial

differences between the NGA and the

FPA; (4) the legislative history of EPAct

indicates that the Commission does not

have the authority to mandate open

access and can only order open access

if section 211 procedures are followed—

citing NYSEG and FPL; and (5) section

211 limits the Commission’s authority

to order open access on a generic

basis—where a specific statute

addresses an issue, a more general

statute should not be read in a manner

that conflicts with the specific statute.

PA Com argues that the Commission’s

reliance on AGD ‘‘impermissibly

expands the limited holding of AGD’’

and the Commission improperly relied

on sections 205 and 206 of the FPA to

require open access generically—the

Commission only has case-by-case

jurisdiction.

VA Com declares that the plain

meaning of the FPA and cases

interpreting sections 206 and 211 show

that the Commission does not have the

authority to order industry-wide open

access.

FL Com and El Paso argue that the

Commission only has limited authority

to order wheeling and that the

Commission has not made the required

findings under section 211.63

Group Two Section 205 Filings

Union Electric argues that the

requirement that Group 2 Public

Utilities make section 205 filings is

contrary to the voluntary filing scheme

inherent in section 205.

Commission Conclusion

Overview

The fundamental legal question before

us is the scope of the authority granted

to the Commission in 1935 to remedy

undue discrimination in interstate

transmission services and whether that

authority permits us sufficient

flexibility to define undue

discrimination in light of dramatically

changed industry circumstances, in

order to provide electricity customers

the benefits of more competitively

priced power. In the NOPR and Order

No. 888, the Commission

comprehensively examined case law

and legislative history relevant to our

authority to order open access

transmission services as a remedy for

undue discrimination.64 We also

responded at length in Order No. 888 to

arguments that questioned our authority

to take this step.65

On rehearing, as described above,

only a few parties continue to question

the Commission’s authority. As a

general matter their rehearings do not

raise any arguments, cases, or legislative

history not previously considered, and

they do not convince us that our action

in Order No. 888 is not within our

authority under sections 205 and 206 of

the FPA. We therefore reaffirm our

determination that we have not only the

legal authority, but the responsibility, to

order the filing of non-discriminatory

open access tariffs if we find such order

necessary to remedy undue

discrimination or anticompetitive

effects.

There are several broad points we

wish to emphasize in response to the

rehearings that have been filed:

First, there is no dispute that the FPA

does not explicitly give this Commission

authority to order, sua sponte, open

access transmission services by public

utilities. However, the fact remains that

the FPA does explicitly require this

Commission to remedy undue

discrimination by public utilities.66 The

finding of the D.C. Circuit in the AGD

case, with regard to sections 4 and 5 of

the NGA (which parallel sections 205

and 206 of the FPA), are equally

applicable here: the Act ‘‘fairly bristles’’

with concerns regarding undue

discrimination and it would turn

statutory construction on its head to let

the failure to grant a general power

prevail over the affirmative grant of a

specific one.67

Second, there also is no dispute that

before Congress enacted the FPA in

1935, it rejected provisions that would

have explicitly granted the Commission

authority to order transmission to any

person if the Commission found it

‘‘necessary or desirable in the public

interest.’’ However, the fact that

Congress rejected an extremely broad

common carrier provision does not limit

the remedies available to the

Commission to enforce the undue

discrimination provisions in the FPA.68

Third, entities on rehearing

understandably have focused on

statements in case law that indicate

limits on the Commission’s wheeling

authority. They particularly focus on

certain statements by the Supreme Court

in Otter Tail. The Commission in Order

No. 888 fully addressed and considered

all relevant case law of which we are

aware, including statements in Otter

Tail and other court cases indicating

limitations on our authority.69 We do

not dispute these statements and we
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12291

70See FERC Stats. & Regs. at 31,686–87; mimeo

at 148–49.

71The savings clause in section 212(e) originally

provided that no provision of section 210 or 211

shall be treated as ‘‘limiting, impairing, or

otherwise affecting any authority of the

Commission under any other provision of law.’’ In

1992, the 212(e) savings clause was amended to

provide that sections 210, 211 and 214 ‘‘shall not

be construed as limiting or impairing any authority

of the Commission under any other provision of

law.’’

72AGD, 824 F.2d at 996–999. See also FERC Stats.

& Regs. at 31,668–73, 31,676–78; mimeo at 98–110

and 120–27.

73We do not repeat our lengthy legal analyses in

Order No. 888, but discuss only those arguments

that warrant further discussion.

74See Union Electric and Carolina P&L.

75These authorizations are issued under section

7 of the Natural Gas Act and section 311 of the

Natural Gas Policy Act.

76While there is a difference in the statutes in

that natural gas transporters must obtain a

certificate from the Commission before they can

transport gas, there is no difference in the statutory

standard applied to the interstate service.

77 824 F.2d at 997–98. The court also noted the

Commission’s reliance on section 16 of the NGA.

recognize limitations on our authorities.

However, the fact remains that none of

the cases cited, including Otter Tail,

involved the issue of whether this

Commission can order transmission as a

remedy for undue discrimination and

none addressed industry-wide

circumstances such as those before us in

Order No. 888.

Fourth, while Congress in 1978 gave

the Commission certain case-by-case

authority to order transmission access

by both public utilities and non-public

utilities, and broadened this case-bycase authority in 1992, Congress also

specifically provided in section 212(e)

of the FPA that the case-by-case

authorities were not to be construed as

limiting or impairing any authority of

the Commission under any other

provision of law.70 Indeed, the

legislative history of EPAct shows that

when Congress amended the section

211–212 wheeling provisions and the

section 212(e) savings clause in 1992,71

it was well aware of arguments

regarding the scope of the Commission’s

wheeling authority as a remedy for

undue discrimination under section

206. Whereas Congress in 1992 decided

to add a flat prohibition on the

Commission ordering direct retail

wheeling under any provision of the

FPA, it did not add a prohibition on the

Commission ordering wholesale

wheeling to remedy undue

discrimination under section 206. It

instead retained and modified the

savings clause. The issue before us,

therefore, hinges on the scope of

authority given to this Commission to

remedy undue discrimination, not on

the scope of authority given to us in

1978 and 1992.

The Commission is significantly

influenced by the decision and case law

discussion by the D.C. Circuit in the

AGD case. This court opinion contains

the most recent and comprehensive

discussion of the Commission’s legal

authority to remedy undue

discrimination under NGA provisions

that mirror those in the FPA, including

the relevant case law concerning the

Commission’s authority to order

transmission under the FPA.72 The

rehearing arguments do not, and we

believe cannot, reconcile the AGD

court’s discussion and findings with a

conclusion that the Commission cannot

under any circumstances (as these

parties advocate) order wheeling under

sections 205 and 206 to remedy undue

discrimination.

In sum, we believe that the essential

question of the Commission’s legal

authority to impose the requirements of

Order No. 888 turns on the flexibility of

the Commission’s remedial authority

under sections 205 and 206 of the FPA

to remedy undue discrimination. As

was true with respect to the natural gas

industry, we acknowledge that

Commission precedent for many years

nurtured the expectation that we would

not, under our authority under the FPA,

preclude utilities from using their

monopoly power over the nation’s

transmission systems to secure their

monopoly position as power suppliers.

However, as described at length in

Order No. 888, these policies arose in

the context of practical, economic, and

regulatory circumstances that gave rise

to vertically integrated monopolies and

little, if any, competition among power

suppliers. In this kind of regime, the

interests of customers were most

effectively served by the kind of costbased regulatory regime that has

prevailed until very recently. The

evolution of third-party generation,

facilitated by PURPA and significant

technological advances, dramatically

altered the economics of power

production. The enactment of EPAct

recognized these changes and

established a national policy intended

to favor the development of a

competitive generation market, so that

the efficiencies of the new marketplace

will be available to customers in the

form of lower costs for electricity.

Utility practices that may have been

acceptable a few years ago would, if

permitted to continue, smother the

fledgling competitive wholesale markets

and undermine the efforts of customers

to seek lower-price electricity. We

firmly believe that our authorities under

the FPA not only permit us to adapt to

changing economic realities in the

electric industry, but also require us to

do so, if that is necessary to eliminate

undue discrimination and protect

electricity customers.

Specific Arguments 73

The Factual Circumstances Underlying

AGD Do Not Mandate A Different

Conclusion In This Proceeding

Both Union Electric and Carolina P&L

argue that the Commission cannot rely

on AGD in support of its actions in the

electric industry, and they attempt to

distinguish the legal basis on which the

Commission acted in requiring open

access transportation for gas pipelines.

Specifically, they argue that AGD (Order

No. 436) pertained to voluntary actions

by gas pipelines and that the

Commission’s imposition of open access

requirements was a condition of

certificate authorizations to transport

gas, whereas the Commission’s action in

Order No. 888 is a direct mandate.74 We

believe this is a distinction without a

difference. While it is true that the

Commission required open access as a

condition of granting blanket

authorizations for pipelines and

authorizations for pipelines authorizing

pipelines to transport natural gas,75 the

critical point is that in both Order No.

436 and Order No. 888 the

Commission’s actions hinged as a legal

matter on the parallel provisions of the

NGA (sections 4 and 5) and the FPA

(sections 205 and 206) that prohibit

undue discrimination. Whether persons

are seeking to transport natural gas or

wheel electric power in interstate

commerce, by law they must not unduly

discriminate or grant undue

preference.76

In AGD, the court upheld the

Commission’s reliance upon sections 4

and 5 of the NGA to impose an openaccess commitment on any pipeline that

secured a blanket certificate to provide

gas transportation under section 7 of the

NGA or provided transportation under

section 311 of the NGPA.77 Order No.

436 was not a simple order that relied

on the ‘‘voluntary actions’’ of affected

pipelines. As the court in AGD

understood:

The Order envisages a complete

restructuring of the natural gas industry. It

may well come to rank with the three great

regulatory milestones of the industry.* * *
12292 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

78 824 F.2d at 993–94.

79For example, as the AGD court explained with

regard to its discussion of Maryland People’s

Counsel v. FERC, 761 F.2d 780 (D.C. Cir. 1985), ‘‘we

made it clear that blanket-certificate transportation,

unconstrained by any nondiscriminatory access

provision, might well require remedial action under

§ 5.’’ 824 F.2d at 1000.

80We disagree with Union Electric that anything

in the Commission’s brief to the Supreme Court,

opposing certiorari of AGD, contradicts our

conclusion. We recognize, as the Commission

explained in that brief, that there is no equivalent

to section 7 of the NGA in the FPA. While this puts

Order No. 888 on a somewhat different factual basis

from AGD, it has no material effect on whether we

have the authority to remedy undue discrimination

by requiring non-discriminatory open access

transmission.

81See 824 F.2d at 993–94 (‘‘The Order envisages

a complete restructuring of the natural gas industry.

It may well come to rank with the three great

regulatory milestones of the industry. * * *’’).

82Parties have raised the legislative history of

sections 205 and 206, as well as the legislative

history of the EPAct amendments to sections 211

and 212.

83FERC Stats. & Regs. at 31,676–78; mimeo at

120–27. Notice of Proposed Rulemaking and

Supplemental Notice of Proposed Rulemaking,

FERC Stats. & Regs. ¶32,514 at 33,053–56 (1995).

Union Electric points to a statement in the

Commission’s 1987 brief to the U.S. Supreme Court,

opposing certiorari of the AGD case; in that brief the

Commission pointed out that the Supreme Court

had noted, in Otter Tail, that the legislative

histories of the FPA and NGA are ‘‘materially

different.’’ As we explained in Order No. 888, we

have thoroughly reexamined the legislative

histories of the NGA and FPA with respect to this

issue and now conclude that there is no material

difference as to this issue in the legislative histories

of the two statutes. Further, such a difference,

whether or not it exists, was not crucial to the

fundamental holdings of the AGD court and does

not preclude that decision from applying equally in

the electric industry. See FERC Stats. & Regs. at

31,676–78; mimeo at 121–26. We also note that in

its brief to the Supreme Court the Commission

explicitly stated that neither Otter Tail nor any of

the other electric cases cited ‘‘presented the

question whether the Commission could order

wheeling to remedy undue discrimination or

anticompetitive behavior. * * *’’ FERC Brief at 25

(footnote omitted).

84See discussion supra concerning AGD court’s

understanding that Order No. 436 was not a simple

order that relied on voluntary actions of affected

pipelines.

85Contrary to certain assertions, in Order No. 888

we viewed the statute as a whole and determined

that section 211 in no way limited the broad

authority Congress gave us to eradicate undue

discrimination in the electric power industry.

86See note 71 and related discussion, supra.

At stake is the role of interstate natural gas

pipelines. Although they are obviously

transporters of gas, they have until recently

operated primarily as gas merchants. They

buy gas from producers at the wellhead and

resell it, mainly to local distribution

companies (‘‘LDCs’’) but also to relatively

large end users. The Commission has

concluded that a prevailing pipeline

practice—particularly their general refusal to

transport gas for third parties where to do so

would displace their own sales—has caused

serious market distortions. It has found this

practice ‘‘unduly discriminatory’’ within the

meaning of § 5 of the NGA. Order 436 is its

response.

The essence of Order No. 436 is a

tendency, in the industry metaphor, to

‘‘unbundle’’ the pipelines’ transportation and

merchant roles. If it is effective, the pipelines

will transport the gas with which their own

sales compete; competition from other gas

sellers (producers or traders) will give

consumers the benefit of a competitive

wellhead market. [78]

Indeed, since Order No. 436 issued,

virtually all jurisdictional natural gas

pipelines became ‘‘open access’’

transporters of natural gas.

In analyzing the Commission’s

authority to remedy undue

discrimination, the court never made

the distinctions now being put forth by

Union Electric and Carolina P&L.

Rather, the court specifically focused on

the Commission’s authority under

section 5 of the NGA and upheld the

Commission’s authority to remedy

undue discrimination in the

transportation of natural gas by

requiring pipelines transporting natural

gas to do so on a non-discriminatory

basis.79 Similarly, the Commission in

Order No. 888 found undue

discrimination in the transmission of

electric energy and required, pursuant

to section 206 of the FPA (the FPA

provision that parallels section 5 of the

NGA), that if public utilities transmit

electric energy in interstate commerce,

they must do so on a non-discriminatory

basis (i.e., offer non-discriminatory open

access transmission).

Moreover, while the Commission may

have imposed a ‘‘condition’’ on

pipelines obtaining blanket certificates

or providing section 311 transportation

in Order No. 436, this does not detract

from the court’s core finding in AGD

that the Commission had the authority

under section 5 of the NGA to remedy

undue discrimination by requiring open

access transportation.80 The

Commission chose in Order No. 436 to

impose its open access remedy as a

condition to pipelines obtaining a

blanket certificate to transport natural

gas, but its authority was rooted in the

undue discrimination provisions of

section 5. Additionally, the practical

result of the conditioning was that all

jurisdictional pipelines would have to

provide open access transportation, a

result that was clearly anticipated by the

AGD court.81 Thus, there is no

distinction in the result intended, or the

result achieved, in either industry; in

both cases, the intent was to remedy

undue discrimination pursuant to the

statutes governing each industry, and in

both cases the result was that all

transporters/transmitters must agree to

open access non-discriminatory services

if they seek to continue owning,

controlling or operating monopoly

interstate transportation facilities.

Legislative History Behind the FPA and

EPAct Does Not Preclude Our Action

We disagree with the arguments that

the legislative history behind Part II of

the FPA establishes that the

Commission cannot under any

circumstance order wheeling under FPA

sections 205 and 206.82 We examined

the legislative history of sections 205

and 206 at length in the NOPR and

Order No. 888 and concluded that it

supports our authority to order open

access transmission as a remedy for

undue discrimination.83 We also have

examined the legislative history of the

EPAct amendments to sections 211 and

212 and conclude that Congress in

EPAct did not resolve the issue of our

authority under sections 205 and 206

and left untouched whatever preexisting authorities we had under these

sections. The parties have raised

nothing new on rehearing to persuade

us that our interpretation is wrong.

However, there are several arguments

that we believe warrant further

discussion.

Parties on rehearing argue that the

existence of sections 211 and 212 limit

the Commission’s wheeling authority

and, in effect, remove our authority

under section 206 to order any

transmission as a remedy for undue

discrimination.84 We disagree. In

enacting EPAct, Congress did not

resolve the extent of our wheeling

authority outside the context of sections

211 and 212.85 As we explained above,

while Congress in 1978 gave the

Commission certain case-by-case

authority to order transmission access, it

also specifically provided in section

212(e) of the FPA that the case-by-case

authorities were not to be construed as

limiting or impairing any authority of

the Commission under any other

provision of law. Congress retained a

similar savings clause when it amended

sections 211 and 212 in 1992. Moreover,

the legislative history of EPAct shows

that when Congress amended sections

211 and 212, it was well aware of

arguments regarding the scope of the

Commission’s remedial authority under

section 206.86 Whereas Congress added

an amendment prohibiting the

Commission from ordering direct retail

wheeling under any provision of the

FPA, it chose not to add a prohibition

on the Commission ordering wholesale

wheeling as a remedy for undue
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12293

87 In response to Carolina P&L’s argument that

Congress gave the Commission a specific remedy

under section 211 and the Commission should not

presume that it has additional remedies in such a

circumstance, we do not believe that section 211

can credibly be viewed either as a partial substitute

for, or as superseding, the sections 205–206 undue

discrimination remedial authority that is

fundamental to the Federal Power Act. Indeed,

section 211 is not written in terms of providing

remedial authority to address undue discrimination

but rather provides for case-by-case transmission

service on request if the service is in the public

interest and meets the other criteria in sections 211

and 212.

88FERC Stat. & Regs. at 31,686–87; mimeo at 148–

51.

89Most of the statements talk in terms of ‘‘The

Conference Report provides. . . .’’ and thus are

referring only to the section 211 and 212 provisions.

See, e.g., 138 Cong. Rec. 517616 (Oct. 8, 1992).

90FERC Stats. & Regs. at 31,676–78; mimeo at

120–27.

91FERC Stats. & Regs. at 31,670; mimeo at 103.

92Union Electric at 26.

93FERC Stats. & Regs. at 31,677; mimeo at 122.

94Union Electric at 27.

95Union Electric at 30.

96The only relevant case the AGD court did not

discuss was NYSEG. As we explained in Order No.

888, presumably this was because the case did not

concern whether the Commission could order

wheeling as a remedy for undue discrimination.

FERC Stats. & Regs. at 31,672 n.217; mimeo at 108

n.217.

97Union Electric at 33–37.

discrimination under sections 205 and

206.87

We are not persuaded that this

conclusion is wrong based on rehearing

arguments that we ignored other

legislative history of EPAct. Carolina

P&L argues that we ignored various

statements of Senator Wallop following

the enactment of EPAct, which it alleges

are counter to our claim of authority to

order open access transmission as a

remedy for undue discrimination. The

utility is simply in error that we ignored

these statements. We explicitly

mentioned Senator Wallop’s statements

in Order No. 888 and gave our rationale

for why section 211 does not limit our

authority to remedy undue

discrimination.88 However, we believe it

is important to elaborate on the context

in which those statements were made

and our interpretation of those

statements.

The primary focus of Senator

Wallop’s statements is on the

transmission authority given by the

EPAct amendments to sections 211 and

212. These statements emphasize

restrictions on our section 211 wheeling

authority, including the fact that section

211 does not give the Commission

authority to order transmission access

on its own motion or to order open

access transmission.89 We do not quarrel

with these statements because sections

211 and 212 clearly do place restrictions

on our authority to order access under

those provisions. The statements also

discuss the differences between the

House introduced amendments to

sections 211 and 212 (which would

have provided broader and in some

instances mandatory access authority)

and the amendments that finally passed

(which were more limited). We also do

not disagree that changes were made to

the bill that originally was introduced.

At issue here, however, is not whether

there are restrictions on our section 211

authority, but rather whether we have

authority outside the context of section

211 to order transmission as a remedy

for undue discrimination. The only

statement among Senator Wallop’s

remarks that addresses this specific

issue is one in which he says, ‘‘In my

opinion, neither the amendments made

by this Act nor existing law give the

FERC any authority to mandate open

access transmission tariffs for electrical

utilities.’’ (emphasis added). We do not

view one senator’s opinion as in any

way dispositive of the issue. As

discussed supra, when Congress

enacted the 1992 section 211

amendments it was well aware of the

outstanding legal issue of the

Commission’s authority to order access

as a remedy for undue discrimination

under section 206. It chose not to clarify

this issue by prohibiting the

Commission from ordering access, but

instead retained the savings clause in

section 212(e).

The issue of our legal authority thus

turns on the undue discrimination

authority given to us in 1935, and the

legislative history of sections 205 and

206. We discussed this at length in

Order No. 888.90 On rehearing, several

entities emphasize the Otter Tail case

and the legislative history referred to in

that case. In particular, Union Electric

recites Justice Stewart’s discussion of

the legislative history in his partial

dissent in Otter Tail. We do not

interpret that discussion to suggest that

we do not have the authority to remedy

undue discrimination by requiring open

access transmission under any

circumstance. As we explained in Order

No. 888:

In the FPA, while Congress elected not to

impose common carrier status on the electric

power industry, it tempered that

determination by explicitly providing the

Commission with the authority to eradicate

undue discrimination—one of the goals of

common carriage regulation. By providing

this broad authority to the Commission, it

assured itself that in preserving ‘‘the

voluntary action of the utilities’’ it was not

allowing this voluntary action to be

unfettered. It would be far-reaching indeed to

conclude that Otter Tail, which was a civil

antitrust suit that raised issues entirely

unrelated to our authority under section 206,

is an impediment to achieving one of the

primary goals of the FPA—eradicating undue

discrimination in transmission in interstate

commerce in the electric power industry.[91]

In response to Union Electric’s

arguments that Congress explicitly

rejected common carrier provisions in

1935, we do not disagree with Union

Electric’s statement that ‘‘the mandatory

wheeling language was not dropped

inadvertently.’’ 92 The point that we

made in Order No. 888 (quoting AGD)

in this regard was that

(1) ‘‘Congress declined itself to impose

common carrier status’’ (emphasis added)

and (2) there is no ‘‘support for the idea that

the Commission could under no

circumstances whatsoever impose obligations

encompassing the core of a common carriage

duty.’’ [93]

Nowhere did we ever suggest that the

mandatory wheeling language was

dropped inadvertently; we simply

distinguish a general common carrier

obligation imposed ‘‘in the public

interest’’ from an obligation to provide

transmission service deemed necessary

to eliminate undue discrimination.

Finally, we fully agree with Union

Electric’s statement that

[a]lthough this ‘‘first Federal effort’’ occurred

in 1935, the resulting FPA Sections 205 and

206 have not been modified in any relevant

respect since that time. Therefore, the range

of authority conveyed to the Commission in

such sections remains the same today as it

did then. [94]

We never suggested otherwise and our

conclusion in Order No. 888 is not

based on a finding to the contrary.

Case Law Does Not Prohibit Our

Ordering Wheeling Under Sections 205

and 206 of the FPA

Union Electric, discussing the very

cases cited by the Commission in Order

No. 888, asserts that ‘‘the Commission

fails to recognize their dispositive

results prohibiting it from ordering

wheeling under the Sections 205 and

206 of the FPA.’’ 95 We thoroughly

examined all of the case law cited by

Union Electric, as evidenced by our

discussions in the NOPR and Order No.

888, and disagree that any of those cases

prohibit the Commission from ordering

wheeling under sections 205 and 206 of

the FPA to remedy undue

discrimination. Indeed, the AGD court

reached the same conclusion.96

Union Electric further cites to a

variety of FPC cases that it claims

demonstrate that the Final Rule exceeds

the Commission’s statutory authority.97

It appears to have proffered every

negative Commission statement it could

find with respect to our authority to

order wheeling under Part II of the FPA.
12294 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

98Union Electric at 37–40.

99Union Electric at 38–39.

100Hearings on H.R. 1301, H.R. 1543, and H.R.

2224 before the Subcommittee on Energy and Power

of the House Committee on Energy and Commerce,

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

Statement of Cynthia A. Marlette, Associate General

Counsel, Federal Energy Regulatory Commission,

Report No. 102–60 at 60 (‘‘However, as discussed

below, there are strong legal arguments that the

Commission’s obligation to protect against undue

discrimination carries with it the authority to

impose transmission requirements as a remedy for

undue preference or discrimination.’’ ‘‘As discussed

below, although the case law in this area has been

uncertain, in OGC’s opinion there is a strong legal

argument that the Commission can require

transmission as a remedy for undue preference or

undue discrimination.’’); at 69–70 (‘‘The weight of

the limited case law, particularly the AGD opinion,

supports authority to order wheeling as a remedy

for undue discrimination where substantial

evidence exists.’’); at 106 (‘‘I believe that we have

substantial authority under the existing case law to

mandate access where necessary to remedy

anticompetitive effects.’’).

101The statement quoted was preceded by a legal

analysis of the Commission’s authorities under then

existing law, including section 206, and a statement

that an examination of the Commission’s full

authorities might further open up the industry.

Further, it was made in the context of case-by-case

industry proposals and the Commission’s inability

to require case-by-case wheeling on its own motion.

It did not address section 206 authority to remedy

undue discrimination.

102Union Electric at 39. We note that Union

Electric did not cite to any page or particular

language to support its assertion.

103Carolina P&L at 35–36.

104 824 F.2d at 1001. In this regard, we

acknowledge that our view of what constitutes

undue discrimination has evolved significantly in

light of the dramatic economic changes in the

industry, as described briefly above and more fully

in Order No. 888.

105FERC Stats. & Regs. at 31,682–84; mimeo at

136–42.

106E.g., El Paso, Union Electric, Carolina P&L, VA

Com, FL Com, PA Com.

As in the Commission cases cited, we

recognize that our authority to order

transmission service is not unbounded;

if we order transmission, it must be

within the scope of authority available

to us under the FPA. However, the fact

is that none of the cases cited as

establishing limits on the Commission’s

authority addresses the issue before us

now, i.e., the Commission’s authority to

order transmission as a remedy for

undue discrimination. Simply stated,

the Commission has never before been

faced with generic findings of undue

discrimination in the provision of

interstate electric transmission services,

and the extent of its authority to remedy

that undue discrimination.

The Commission’s General Counsel

Never Asserted, or Even Suggested,

That the Commission Does Not Have

the Authority to Order Wheeling as a

Remedy for Undue Discrimination

Union Electric spends several pages of

its rehearing request asserting that the

Commission’s own General Counsel has

acknowledged the limitations on the

Commission’s authority to order

wheeling. 98 In particular, it points to a

statement by a Commission OGC

witness that ‘‘if Congress intends for the

Commission to be able to deal with

transmission on its own motion and

thereby go further than simply dealing

with industry proposals,’’ Congress

would need ‘‘to include an affirmative

statement somewhere in the Act that the

Commission could require wheeling on

its own motion.’’ 99 This same statement

was previously raised by EEI and

previously addressed in Order No. 888.

We do not disagree that this statement

was made. However, it must be read in

the context of the witness’ entire

testimony in which the witness stated

four times the view that the case law

supports the argument that the

Commission has authority to order

wheeling as a remedy for undue

discrimination.100 Indeed, contrary to

Union Electric’s assertion, the extensive

legal analysis set forth by the

Commission’s witness supports the

position relied upon in this

proceeding.101 Thus, viewed in the

context of the witness’ entire testimony,

Union Electric’s arguments to the

contrary are unavailing. Moreover,

nowhere did the witness ever suggest, as

asserted by Union Electric, that FPA

sections 205 and 206 could only be used

‘‘to eliminate unduly discriminatory

terms in a wheeling arrangement

voluntarily filed with the

Commission.’’ 102

The Commission Has the Authority to

Order Public Utilities to Make Rate

Filings in This Proceeding

We reject Union Electric’s argument

that our requirement that Group 2

Public Utilities make section 205 filings

is contrary to the voluntary filing

scheme inherent in section 205. It is

true that the Commission ordinarily

cannot require a utility to make a

section 205 filing. However, in this

situation the section 205 filing was

required as a remedy under section 206

of the FPA to establish rates for nondiscriminatory open access

transmission. Acting pursuant to section

206 of the FPA, we found that undue

discrimination exists in the wholesale

transmission of electric power and

ordered the filing of non-discriminatory

open access transmission tariffs to

remedy this discrimination. Section 206

further requires that upon such a

finding the Commission ‘‘shall

determine the just and reasonable rate,

charge, classification, rule, regulation,

practice, or contract to be thereafter

observed and in force. * * *’’ Thus, we

had the authority to set the rates that

would be observed and in force

following the effectiveness of open

access transmission and initially

proposed to set rates for each public

utility. However, rather than take this

intrusive approach, which necessarily

would have required a number of

generic assumptions and resulted in less

than public utility-specific rates, upon

issuance of the Final Rule, we chose to

permit these public utilities to make

section 205 filings to propose their own

rates for the services provided in the pro

forma tariff.

The Commission’s Prior Failure to

Order Wheeling as a Remedy for Undue

Discrimination Is Not Dispositive

After discussing several cases that it

asserts address the Commission’s

authority to remedy undue

discrimination, Carolina P&L declares

that ‘‘[p]erhaps the strongest evidence

that the Commission lacks the power to

compel wheeling under FPA section 206

is the fact that the Commission has

never previously exercised this alleged

power, despite numerous opportunities

to do so.’’ 103 However, the court in AGD

succinctly dismissed a similar

argument:

It is finally argued that the Commission’s

not having imposed any requirements like

those of Order No. 436 in the period from

enactment in 1938 until the present

demonstrates the lack of any power to do so.

* * * But as our introductory review of the

economic background sought to illustrate, the

Commission here deals with conditions that

are altogether new. Thus no inference may be

drawn from prior non-use. [104]

Undue Discrimination/Anticompetitive

Effects 105

A number of utilities and state

commissions argue that the Commission

lacks evidence to support a finding of

undue discrimination.106

VA Com argues that the Commission

failed to make a legally supportable

finding of industry-wide undue

discrimination: ‘‘FERC apparently drew

a conclusion that there was undue

discrimination in the NOPR without

support and later accepted customers’

allegations, without further inquiry, and

relied on them in making its finding of

industry-wide undue discrimination.’’

(VA Com at 2–3).

PA Com and Carolina P&L assert that

allegations of undue discrimination do

not form a sufficient basis to compel a

generic rulemaking. Not coming forward

with specific accusations and the

identity of specific accusers, PA Com

asserts, is unconstitutional as a

deprivation of due process.
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12295

107 In response to PA Com’s and Carolina P&L’s

assertions that not coming forward with specific

accusations and identities of specific accusers is

unconstitutional and a deprivation of due process,

we emphasize that the Commission has not denied

due process to anyone. The Final Rule does not, nor

is it intended to, make specific findings as to any

particular utility or any particular allegation raised.

108FERC Stats. & Regs. at 331,682; mimeo at 136–

37.

109See AGD, 824 F.2d at 999–1000.

110New England Power Pool, 67 FERC ¶ 61,402

(1994) (NEPOOL); American Electric Power Service

Corporation, 64 FERC ¶ 61,279 (1993), reh’g

granted, 67 FERC ¶ 61,168, clarified, 67 FERC

¶ 61,317 (1994) (AEP).

111 67 FERC ¶ 61,042 at 61,132.

112 Id.

113Commonwealth Edison Co., 70 FERC ¶ 61,204

(1995); Wisconsin Electric Power Co., 70 FERC

¶ 61,074 (1995); and Wisconsin Public Service

Corp., 70 FERC ¶ 61,075 (1995)

With regard to specific allegations of

undue discrimination, SoCal Edison

argues that the Commission

inappropriately relied upon allegations

involving SoCal Edison as evidence of

undue discrimination. SoCal Edison

asks that the Commission declare that it

is not making a factual determination as

to any particular allegation especially

since prior to 1994 the Commission

defined discrimination differently.

Dalton similarly argues that the

Commission has no basis for finding

that Georgia Power Company is engaged

in unlawful undue discrimination as to

new or roll-over transmission services

in the operation of the Integrated

Transmission System in Georgia (ITS)

under the ITS agreement. Moreover,

Dalton argues, even if it is found that

GPC acted in unduly discriminatory

manner, it is not practical or lawful to

order open access tariff for new and rollover services.

Finally, Carolina P&L argues that the

comparability standard does not

eliminate the ‘‘requirement’’ that parties

must be similarly situated before

discrimination is present, and that the

Commission has not provided factual

support for its implicit finding that

public utilities and their native load

customers are similarly situated to third

parties. It cites City of Vernon v. FERC,

845 F.2d 1042 at 1045–46 (D.C. Cir.

1988), in support.

Commission Conclusion

As an initial matter, the Commission

grants SoCal Edison’s request for

clarification that in Order No. 888 we

did not make a factual determination as

to any particular allegation of past

discrimination described in the Final

Rule.107 However, we reject arguments

that the Commission cannot rely in part

on the array of allegations and

circumstances raised by customers in

individual cases over the years and

brought forth in response to the NOPR.

The specific allegations are illustrative.

However, they present examples of the

types of discriminatory incentives and

behavior inherent in ownership of

monopoly transmission facilities, and

also present credible examples of the

types of discriminatory behavior in

which public utilities could engage in

the future. We also reject arguments that

customers and the Commission must

litigate and make specific findings of

discrimination against each public

utility before we can take any action to

preclude discriminatory behavior that

will harm competition and, ultimately,

electricity consumers. This is

particularly true where the

discriminatory behavior clearly is in the

economic self-interest of a monopoly

transmission owner facing the markedly

increased competitive pressures that are

driving today’s electric utility industry.

As we recognized in Order No. 888,

[t]he inherent characteristics of monopolists

make it inevitable that they will act in their

own self-interest to the detriment of others by

refusing transmission and/or providing

inferior transmission to competitors in the

bulk power markets to favor their own

generation, and it is our duty to eradicate

unduly discriminatory practices. As the AGD

court stated: ‘‘Agencies do not need to

conduct experiments in order to rely on the

prediction that an unsupported stone will

fall.’’ 108

We believe that the same general

discriminatory circumstances that faced

us when we required open access

transportation in the natural gas

industry 109 are also before us today in

the electric industry. First, it is

uncontested that market power

continues to exist in the ownership and

operation of the monopoly-owned

facilities that comprise the nation’s

interstate transmission grid. Second,

utilities, as a general matter, did not in

the past offer comparable transmission

services to competitors or to customers.

Open access services simply were not

made available by utilities until the late

1980s when the Commission began to

impose open access as a condition of

approval of market-based rates and

utility mergers in order to mitigate

market power and remedy

anticompetitive effects. Rather, the vast

majority of utilities historically have

declined to transport electric energy that

would compete with their own sales or

have offered access that is inferior to

what they use for their own sales. Third,

discrimination in transmission services,

when viewed in light of utilities’ own

uses of their transmission systems

compared to what they offer third

parties, has denied and will continue to

deny customers access to electricity at

the lowest reasonable rates. The entities

on rehearing have raised nothing to

persuade us that it is in the interests of

consumers to maintain the self-evident

incentives for transmission owners to

exercise their monopoly power over

transmission to discriminate in favor of

their own generation sales—incentives

that will only increase in the future as

competitive pressures continue to

escalate.

The Commission addressed the same

argument as that being made by

Carolina P&L, that the Commission has

not made the requisite finding that

third-party transmission customers are

similarly situated to public utilities and

their native load customers, in 1994 in

the NEPOOL and AEP cases.110 In these

cases, we recognized that the traditional

focus of our undue discrimination

analysis had been whether factual

differences justify different rates, terms

and conditions for similarly situated

customers, but concluded that due to

changing conditions in the electric

utility industry, it was necessary to

reevaluate our traditional analysis. As

we stated in NEPOOL, the focal point of

undue discrimination claims has shifted

from claims of undue discrimination in

rates and services which the utility

offers different customers to claims of

undue discrimination in rates and

services which the utility offers when

compared to its own use of the

transmission system.111 ‘‘In this context,

framing the analysis in terms of how a

public utility treats similarly situated

customers is not applicable or

instructive.’’ 112 The Commission

concluded that it therefore must

reexamine its application of the

standard for undue discrimination

claims under sections 205 and 206 of

the FPA.

The Commission further elaborated

on its re-examination of undue

discrimination in AEP. The Commission

cited its NEPOOL discussion and set for

hearing the different uses that AEP

made of its transmission system and

whether there were any operational

differences between any particular use

that AEP made of the system and the

use third parties might need, and, in

particular, the degree of flexibility AEP

accorded itself in using its transmission

system for different purposes. The

Commission subsequently set the same

issue for hearing in several other

cases.113 In the NOPR, however, the

Commission concluded that based on

what it had learned in the ongoing

cases, it would address this issue

generically in this rulemaking. We

announced in the NOPR our belief that
12296 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

114FERC Stats. & Regs. ¶ 32,524 at 33,079.

115FERC Stats. & Regs. at 31,690; mimeo at 160.

116There is no ‘‘requirement’’ in the FPA that the

Commission apply a ‘‘similarly situated’’ test.

Carolina P&L’s reliance on City of Vernon is

misplaced. That case involved a claim of

discrimination in the type of service offered to a

wholesale customer versus that offered to retail

customers, and the Commission’s application of the

‘‘similarly situated’’ and ‘‘same service’’ test.

Contrary to Carolina P&L’s implication, the case

does not hold that the Commission is bound to

apply a ‘‘similarly situated’’ test in analyzing undue

discrimination claims under the FPA.

117 I.e., investor-owned utilities that owned

generation, transmission and distribution facilities

and most of whom had captive customers.

118 Very simply, the transmission owner was able

to prevent third parties from achieving the

maximum savings possible in the generation market

by withholding or delaying transmission service.

Alternatively, the transmission owner could

purchase the power and resell it to the third party

at a rate that reflected a mark-up from the first

power sale.

119FERC Stats. & Regs. at 31,688–90; mimeo at

154–58.

120E.g., SoCal Edison, PSE&G, Carolina P&L.

all utilities use their own systems in two

basic ways: to provide themselves pointto-point 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 load). 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, and the

Commission proposed that all public

utilities must offer both services on a

non-discriminatory open access basis.114

We affirmed this determination in the

Final Rule. We concluded that a public

utility must offer transmission services

that it is reasonably capable of

providing, not just those services that it

is currently providing to itself or others.

Because a public utility that is

reasonably capable of providing

transmission services may provide itself

such services at any time it finds those

services desirable, it is irrelevant that it

may not be using or providing that

service today.115 Thus, based on the

analysis in this record, the Commission

has determined that undue

discrimination in the provision of

transmission services in today’s

industry does not turn on whether

utilities and their native load customers

are similarly situated to third parties,

but instead turns on whether the utility

is providing comparable service, that is,

service that it is reasonably capable of

providing to other users of the interstate

transmission system.

In short, the Commission is not bound

to a static application of its undue

discrimination analysis under the FPA

and, indeed, has a public interest

responsibility to reexamine undue

discrimination in light of changed

circumstances in the industry.116 That is

what we began in NEPOOL and AEP and

have completed in this rulemaking. The

traditional ‘‘similarly situated’’ test,

while applicable to discrimination

among third-party customers, simply is

not applicable when analyzing

discrimination between third-party

transmission customers and

transmission owners. Under Carolina

P&L’s theory, presumably the only

customers that could be shown to be

similarly situated would be those who

own monopoly transmission facilities

and have native load (i.e., captive)

customers. This would preserve

customer captivity, perpetuate

monopoly power and profits, and deny

the lowest reasonable rates to

consumers. We therefore reject Carolina

P&L’s arguments.

Moreover, the fact that public utilities

and their native load customers have

been treated differently from third-party

transmission customers because they are

not among those traditionally

considered to be ‘‘similarly situated’’ is

precisely the target at which Order No.

888 takes aim. Historically,

competitively-priced power was not

broadly available to wholesale

customers because the industry was

dominated by vertically integrated

IOUs 117 and, to the extent cheaper

generation alternatives were available in

the marketplace, transmission owners

either took the cheaper power for their

own uses or purchased and re-sold it at

a profit.118 Prior to EPAct, most power

customers took power from the

vertically integrated utilities that

provided their transmission service.

Transmission-only transactions played a

secondary role in bulk power markets,

facilitating certain economy transactions

and coordination and pooling

arrangements that improved utility

operational efficiencies, largely as a

complement to bundled bulk power

transactions. Given the predominantly

vertically-integrated industry and

efficiencies that could be gained

through encouragement of coordination

and pooling transactions, the

Commission was willing to accept

utility practices that provided third

parties with transmission services that

were distinctly inferior to the utility’s

own uses of the transmission system.

In the future, however, unbundled

transmission service will be the

centerpiece of a freely traded

commodity market in electricity, in

which all wholesale customers can shop

for power. In a market characterized by

a significant increase in non-vertically

integrated power suppliers and

competitively priced power that is now

meaningfully available, it is no longer in

the interest of wholesale customers for

the Commission to tolerate the types of

practices that were previously accepted.

We cannot allow what have become

unduly discriminatory practices to erect

barriers between customers and the

rapidly emerging competitive electricity

marketplace. Accordingly, a primary

goal of Order No. 888 is to provide that

in the future transmission providers and

third-party transmission customers are

‘‘similarly situated’’ in the quality of

transmission service available to them.

C. Comparability

1. Eligibility to Receive Nondiscriminatory Open Access

Transmission

In the Final Rule, the Commission

modified the definition of ‘‘eligible

customer’’ and, among other things,

clarified that any entity engaged in

wholesale purchases or sales of electric

energy, not just those ‘‘generating’’

electric power, is eligible.119 The

Commission also clarified that entities

that would violate section 212(h) of the

FPA (prohibition on Commissionmandated wheeling directly to an

ultimate consumer and sham wholesale

transactions) are not eligible. Further,

the Commission clarified that foreign

entities that otherwise meet the

eligibility criteria may obtain

transmission services. The Commission

also provided for service to retail

customers in circumstances that do not

violate FPA section 212(h). Persons that

would be eligible section 211 applicants

also would be eligible under the open

access tariff.

a. Unbundled Retail Transmission and

‘‘Sham Wholesale Transactions’’

Rehearing Requests

Several entities assert that there is an

inconsistency between tariff language

and preamble language and argue that

section 1.11 of the tariff should be made

consistent with the preamble to ensure

that, absent a state-approved program,

retail wheeling is not available under

the tariff, no matter which party

requests service.120 They maintain that

the limitation in section 1.11 that the

transmission provider only must

provide retail transmission service

voluntarily or under a state-approved

program appears to apply only when a

retail customer is the purchaser, not

when the transmission purchaser is an

electric utility. They suggest the
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12297

121See also CSW Operating Companies.

122FERC Stats. & Regs. at 31,689–90; mimeo at

158.

123We also disagree with NYSEG’s assertion that

the right of first refusal provision would permit a

retail customer receiving wheeling service to

continue to receive service after the expiration of

its contract and could require the transmission

provider to continue wheeling beyond the scope of

its voluntary offer of service or beyond the scope

of a state-mandated retail access program. Section

Continued

following language to remedy the

problem: ‘‘however, such entity is not

eligible for transmission service that

would be prohibited by Sections

212(h)(1) and/or 212(h)(2) of the Federal

Power Act, unless such service is

provided pursuant to a state retail

access program or pursuant to a

voluntary offer of unbundled retail

transmission service by the

Transmission Provider.’’ (PSE&G at 22;

Carolina P&L at 8–9).

Detroit Edison argues that the

Commission should modify the

definition to exclude any reference to

transmission service provided to retail

customers so as to avoid confusion and

possible forum shopping. At the least,

Detroit Edison argues, the Commission

should modify the language to state that

transmission service is available to an

ultimate consumer to the extent, and

only to the extent, that the service is

authorized by a lawful state retail access

program or pursuant to a voluntary offer

of unbundled retail transmission service

by the transmission provider.

NYSEG asserts that the Commission

did not apply the section 212(h)

limitation to service to retail customers

under the tariff. NYSEG requests that

the Commission clarify that it will not

require retail wheeling beyond the

scope of state-mandated retail access

programs or beyond the terms of a

transmission provider’s voluntary offer

of retail wheeling service.

Oklahoma G&E asks the Commission

to clarify that the term eligible customer

differentiates between a customer

eligible to receive transmission service

and a customer whose transaction is a

sham or would result in mandatory

retail wheeling and would therefore be

prohibited by section 212(h).

NYSEG further asserts that the right of

first refusal provision would permit a

retail customer receiving wheeling

service to continue to take that service

upon expiration of its contract, which

could require the transmission provider,

in violation of section 212(h), to

continue retail wheeling beyond the

scope of its voluntary offer of service or

beyond the scope of a state-mandated

retail access program.

SoCal Edison argues that the

Commission cannot compel a utility to

supply retail transmission service if the

utility challenges the authority of the

state to require retail wheeling and

section 1.11 should be revised to reflect

this.

IL Com declares that it ‘‘does not

recognize FERC’s claim of jurisdiction

over retail transmission service

provided directly to a retail customer

and disputes that unbundled retail

wheeling directly to a retail customer is

a service provided in interstate

commerce.’’ (IL Com at 35). Thus, ‘‘if

FERC’s proposed ‘deference’ to states is

to be given any effect, states must be

allowed to determine whether the retail

transmission component of the retail

wheeling program will be provided

pursuant to the utility’s existing filed

wholesale tariff or whether the retail

transmission will be provided pursuant

to a ‘separate retail transmission tariff’

that is different from the wholesale

tariff.’’ (IL Com at 36). IL Com concludes

that it is inappropriate (and illegal if

FERC is overturned on its retail

transmission jurisdiction assertion) to

include retail customers taking final

delivery of unbundled power for their

own end uses under retail wheeling

programs as eligible customers.

PA Com argues that it is relevant

whether a customer is receiving retail or

wholesale service and redefining

transmission and local distribution

service does not automatically convey

jurisdiction to the Commission.

CCEM asks that the Commission

clarify that a retail customer eligible to

seek transmission service should be able

to seek transmission service not only

from the transmission provider, but

from any other transmission provider.

CCEM also asks that the Commission

add the word ‘‘ultimate’’ before the

word transmission provider in section

1.11 of the tariff.

EEI asks the Commission to ‘‘clarify

that the transmission service provider

should be allowed to supplement the

terms and conditions of the pro forma

tariff with additional provisions that

specifically relate to the totality of the

transmission service being provided,

including the use of distribution

facilities and any other transmission

facilities not currently included in

wholesale rates.’’ (EEI at 24 (emphasis

in original)).121

Union Electric argues that a literal

reading of the eligibility definition

could require retail wheeling by utilities

in states other than those required to

participate in a particular retail

wheeling program.

Commission Conclusion

The Commission agrees with those

entities that argue that section 1.11 of

the pro forma tariff does not explicitly

prohibit ‘‘sham wholesale transactions’’

that could currently be arranged under

the tariff by a utility applying for service

and designating the retail customer as a

point of delivery. We therefore have

modified section 1.11 to clarify that,

with respect to service that we are

prohibited from ordering by section

212(h) of the FPA (whether direct retail

wheeling or ‘‘sham’’ wholesale

wheeling), otherwise eligible entities

may obtain such service under the tariff

only if it is pursuant to a state

requirement that such service be

provided or pursuant to a voluntary

offer of such service. We also have

modified the language to clarify that

eligibility for unbundled direct retail

service required by a state applies only

to service from transmission providers

that the state orders to provide the

service. The modified language states:

Eligible Customer: (i) Any electric utility

(including the Transmission Provider and

any power marketer), Federal power

marketing agency, or any person generating

electric energy for sale for resale is an eligible

customer under the tariff. Electric energy

sold or produced by such entity may be

electric energy produced in the United

States, Canada, or Mexico. However, with

respect to transmission service that the

Commission is prohibited from ordering by

Section 212(h) of the Federal Power Act,

such entity is eligible only if the service is

provided pursuant to a state requirement that

the Transmission Provider offer the

unbundled transmission service, or pursuant

to a voluntary offer of such service by the

Transmission Provider. (ii) Any retail

customer taking unbundled transmission

service pursuant to a state requirement that

the Transmission Provider offer the

transmission service, or pursuant to a

voluntary offer of such service by the

Transmission Provider, is an eligible

customer under the tariff.

Regarding SoCal Edison’s argument,

the Commission stated in the Final

Rule:

Moreover, we are mindful of the fact that

we are precluded under section 212(h) from

ordering or conditioning an order on a

requirement to provide wheeling directly to

an ultimate consumer or sham wholesale

wheeling. We therefore clarify that our

decision to eliminate the wholesale customer

eligibility requirement does not constitute a

requirement that a utility provide retail

transmission service. Rather, we make clear

that if a utility chooses, or a state lawfully

requires, unbundled retail transmission

service, such service should occur under this

tariff unless we specifically approve other

terms.[122]

Therefore, the Commission is not

compelling a utility to provide unbundled retail transmission service.123

Rather, the Commission requires that
12298 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

212(h) of the FPA would override any provision,

including the right of first refusal provision, that

may be included in the pro forma tariff.

124FERC Stats. & Regs. at 31,780 and Appendix

G (31,966–81); mimeo at 428 and Appendix G.

125 75 FERC ¶ 61,356 at 62,141, order on reh’g, 77

FERC ¶ 61,135 (1996). In the order on rehearing, the

Commission permitted a separate retail tariff to

remain in effect for the duration of the retail electric

pilot programs established in Massachusetts by

Massachusetts Electric Company.

15See Open Access Rule, FERC Stats. & Regs. at

31,784; New Hampshire Interim Order, 75 FERC at

61,687 & n.3 (both noting that such a separate retail

tariff must be consistent with the Commission’s

open access policies and comparability principles).

* * *

126 76 FERC at 61,024.

127FERC Stats. & Regs. at 31,770 n. 514; mimeo

at 399 n. 514.

should such service be provided, either

pursuant to state mandate or

voluntarily, it must be provided

pursuant to the pro forma tariff unless

the Commission approves alternative

terms and conditions.

However, in light of CCEM’s request

that we clarify that a retail customer

eligible to seek transmission service

under the tariff should be able to seek

service not only from the transmission

provider, but also from any other

transmission provider, and in light of

Union Electric’s concerns regarding

retail service eligibility, we believe

certain clarifications of our jurisdiction

and of the statements made in Order No.

888 are necessary. The statements cited

above that were made in Order No. 888

and the eligible customer tariff

definition in (ii) above refer to direct

retail transmission, i.e., the transmission

of electric energy ‘‘directly’’ to an

ultimate consumer. The Commission is

prohibited by section 212(h)(1) of the

FPA from ordering this type of retail

transmission and that is why customers

are eligible for such transmission under

the tariff only if the transmission is

pursuant to a state order or is provided

voluntarily. However, on its face,

section 212(h) does not prohibit the

Commission from ordering public

utilities to provide ‘‘indirect’’

unbundled retail transmission in

interstate commerce, i.e., the

transmission necessary to transmit

unbundled electric energy to a utility

that ultimately will deliver the energy to

a customer that is purchasing the

unbundled energy at retail either

pursuant to a state retail access order or

pursuant to voluntary delivery by the

local utility.

We clarify that we believe we have

the jurisdiction under the FPA to order

indirect retail transmission to an

ultimate consumer and that if the

Commission under sections 205, 206 or

211 of the FPA orders such

transmission, entities that otherwise

qualify as eligible customers under the

tariff will take transmission service for

such indirect retail wheeling pursuant

to the pro forma tariff. We note that the

Commission may order such

transmission on a case-by-case basis or

may determine to do so generically in

the future. We expect public utilities to

provide such indirect retail access

under the pro forma tariff and, if they

do not, we will not hesitate to order

them to do so.

In response to IL Com’s argument that

it does not recognize this Commission’s

claim of jurisdiction over the rates,

terms and conditions of unbundled

retail transmission that is provided

directly to an ultimate consumer, the

Commission reaffirms its legal

conclusion set forth in the Final Rule.124

As to its claim that we should give

deference to the state as to whether such

service could be taken under the

wholesale tariff or a separate retail tariff

on file with the Commission, we

reaffirm our conclusion to address this

on a case-by-case basis. Since the Final

Rule issued, the Commission has

addressed this in several orders. In New

England Power Company, the

Commission stated: 125

As we explained in the Open Access Rule

and in the New Hampshire Interim Order, we

generally expect retail transmission

customers to take service under the same

Commission tariff that applies to wholesale

customers. While we generally will defer to

state requests for a separate retail tariff to

accommodate the design and special needs of

a state retail access program, the

Massachusetts Commission has made no

such request in this case. 15

Subsequently, in New England Power

Company, 76 FERC ¶ 61,008 (1996), the

Commission granted a limited waiver of

the Open Access Rule requirements for

the New Hampshire retail electric

competition pilot project. Specifically,

the Commission waived the requirement

for individual service agreements, and

the requirement for customer deposits.

The Commission further announced

that:

other public utilities that provide unbundled

retail service under a pro forma tariff do not

need to apply to retail customers the tariff

provisions regarding individual service

agreements or customer deposits, unless a

state retail program so requires. [ 126]

Concerning EEI’s request for

clarification, the Commission stated in

the Final Rule:

all tariffs need not be ‘‘cookie-cutter’’ copies

of the Final Rule tariff. Thus, under our new

procedure, ultimately a tariff may go beyond

the minimum elements in the Final Rule pro

forma tariff or may account for regional,

local, or system-specific factors. The tariffs

that go into effect 60 days after publication

of this Rule in the Federal Register will be

identical to the Final Rule pro forma tariff;

however, public utilities then will be free to

file under section 205 to revise the tariffs,

and customers will be free to pursue changes

under section 206.[127]

Utilities are free to include customerspecific terms and conditions or terms

and conditions limited to certain

customers (e.g., a distribution charge) in

the customer’s service agreement and/or

the network customer’s network

operating agreement.

b. Transmission Providers Taking

Service Under Their Tariff

Rehearing Requests

TAPS states that section 1.11 does not

seem to require a transmission provider

to take service for its purchases, but the

preamble does (citing mimeo at 57, 191,

266 and regulatory text in section

35.28(c)(2)). It argues that transmission

providers should be required to treat

their own usage of the transmission

system to serve retail customers under

the network service provisions of the

tariff. TAPS argues that this result could

be achieved through an ISO or by

requiring transmission providers to

abide by all non-price terms of Parts I

and III of the tariff. TAPS also argues

that the rates charged network

customers must be developed on the

same basis as the transmission

component of retail rates. It states that

the transmission provider’s purchases

would then be made under Part III of the

tariff to the extent they are made for

serving retail customers. It further

asserts that the Commission’s authority

and obligation to consider transmission

owners’ service to retail load in

establishing wholesale transmission

rates has been long established. At the

least, TAPS argues that the Commission

should require that a transmission

provider take its wholesale purchases

under some tariff.

Similarly, Coalition for Economic

Competition asks the Commission to

clarify that the requirement to use the

pro forma tariff for wholesale purchases

and to functionally unbundle wholesale

purchases and sales does not apply to

purchases made solely to serve retail

customers on a bundled basis. It asserts

that there is conflicting language in

Order No. 888 (citing mimeo at 191) and

Order No. 889 (citing mimeo at 12) and

the pro forma tariff. Coalition for

Economic Competition asserts that the

Commission does not have jurisdiction

over transmission that is part of a

bundled retail sale.
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12299

128To the extent the transmission takes place on

the interstate facilities of other public utilities, we

would have jurisdiction over such transmission.

129Native load means ‘‘[t]he wholesale and retail

power customers of the Transmission Provider on

whose behalf the Transmission Provider, by statute,

franchise, regulatory requirement, or contract, has

undertaken an obligation to construct and operate

the Transmission Provider’s system to meet the

reliable electric needs of such customers.’’ Section

1.19 of the pro forma tariff.

130All transmission in interstate commerce by a

public utility in conjunction with a sale for resale

of electric energy is jurisdictional and must be

taken under a FERC-jurisdictional tariff. The same

is true for all unbundled transmission in interstate

commerce to wholesale customers, as well as to

unbundled retail customers.

131Under the Order No. 888 pro forma tariff,

third-party wholesale customers have the ability to

obtain the identical service the transmission

provider provides itself when it engages in a sale

of electric energy for resale. This may include

network or point-to-point service.

132 69 FERC ¿ 61,145 at 62,300 (1994) (proposed

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

133FERC Stats. & Regs. at 31,690; mimeo at 160.

134FERC Stats. & Regs. at 31,690; mimeo at 160.

135FERC Stats. & Regs. at 31,691–92; mimeo at

162–65.

Commission Conclusion

Several parties have noted on

rehearing that there is conflicting

language among the Final Rule, Order

No. 889 and the pro forma tariff as to

whether and to what extent the

transmission provider must take service

for ‘‘wholesale purchases’’ under its

own tariff. As discussed below, we

clarify that a transmission provider does

not have to ‘‘take service’’ under its own

tariff for the transmission of power that

is purchased on behalf of bundled retail

customers.

In a situation in which a transmission

provider purchases power on behalf of

its retail native load customers, the

Commission does not have jurisdiction

over the transmission of the purchased

power to the bundled retail customers

insofar as the transmission takes place

over such transmission provider’s

facilities,128 and therefore the pro forma

tariff does not have to be used for such

transmission. Moreover, we recognize

that purchases made collectively on

behalf of native load 129 cannot

necessarily be identified as going to any

particular customer. However, the

Commission does have jurisdiction over

transmission service associated with

sales to any person for resale, and such

transmission must be taken under the

transmission provider’s pro forma

tariff. 130

Order No. 888, relying on the

principle of comparability, established

the terms and conditions for network

service provided to network customers

under the pro forma tariff. Network

customers may include the transmission

provider itself as well as any other

entity receiving Network Integration

Service. If the transmission provider

purchases energy from another power

supplier in order to make sales to its

wholesale native load customers, it

must take the transmission service

necessary to transmit the power from its

point(s) of receipt to its point(s) of

delivery under the same terms and

conditions as other Network

Customers.131 As we explained in AES

Power, Inc., network customers are

entitled to make economy energy

purchases from non-designated network

resources at no additional charge on a

basis comparable to the economy energy

purchases made by the transmission

provider on behalf of its bundled retail

customer.132 This applies to the

transmission provider as a network

transmission customer under its own

tariff as well as to other network

transmission customers that make

economy energy purchases on behalf of

their customers. Thus, insofar as all

wholesale transmission customer usage

is concerned, third-party network

customers are treated the same as the

transmission owner.

2. Service that Must be Provided by

Transmission Provider

In the Final Rule, the Commission

found that a public utility must offer

transmission services that it is

reasonably capable of providing, not just

those services that it is currently

providing to itself or others. 133 The

Commission explained that because a

public utility that is reasonably capable

of providing transmission services may

provide itself such services at any time

it finds those services desirable, it is

irrelevant that it may not be using or

providing that service today. However,

the Commission explained that if a

customer seeks a customized service not

offered in an open access tariff, a

customer may, barring successful

negotiation for such service, file a

section 211 application.

Rehearing Requests

Cleveland requests that the

Commission make explicit that

comparability will be evaluated not only

by reference to a transmission provider’s

wholesale services, but also by

comparison to the terms, conditions,

and prices applicable to its retail

services, whether bundled or

unbundled. Cleveland asserts that this is

needed so that TDUs are not at a

competitive disadvantage in competing

with the transmission provider for retail

customers. It maintains that this is

consistent with the Transmission

Pricing Policy and established

precedent.

Commission Conclusion

No clarification is necessary. In

determining what transmission services

a utility must offer for wholesale sales

of electric energy in interstate

commerce, the Final Rule explicitly

states that ‘‘a public utility must offer

transmission services that it is

reasonably capable of providing, not just

those services that it is currently

providing to itself or others.’’ 134

Further, the Final Rule requires that

network service customers receive

service comparable to the service

provided to the transmission provider’s

native load. Because the Rule applies to

retail transmission that is voluntarily

offered or pursuant to a state retail

access program, the requirements to

offer services that the utility is

reasonably capable of providing and

services comparable to those provided

to native load would also apply to retail

service in these limited retail

circumstances.

3. Who Must Provide Nondiscriminatory Open Access

Transmission

In the Final Rule, the Commission

explained that its authority under

sections 205 and 206 of the FPA permits

it to require only public utilities to file

open access tariffs as a remedy for

undue discrimination.135 The

Commission further explained that it

has no authority under those sections of

the FPA to require non-public utilities

to file tariffs with the Commission.

The Commission also discussed three

mechanisms that would help alleviate

the problems associated with not being

able to require non-public utilities to

provide open access: (1) Broad

application of section 211; (2) the

reciprocity requirement set forth in the

Final Rule; and (3) the formation of

RTGs.

The Commission also indicated that it

will not allow public utilities that

jointly own interstate transmission

facilities with non-jurisdictional entities

to escape the requirements of open

access. Thus, the Commission required

each public utility that owns interstate

transmission facilities jointly with a

non-jurisdictional entity to offer service

over its share of the joint facilities, even

if the joint ownership contract prohibits

service to third parties. The Commission

required the public utilities, in a section

206 compliance filing, to file with the

Commission, by December 31, 1996, a

proposed revision (mutually agreeable
12300 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

136See Policy Statement Regarding Regional

Transmission Groups, 64 FERC ¶ 61,139 at 61,993

(1993); Midwest Power Systems, Inc., 69 FERC

¶ 61,025 at 61,104–05 (1994). Nor does the form of

ownership of the joint facilities have any bearing on

the Commission’s jurisdiction over public utilities.

137Though the non-jurisdictional entity would

not become subject to Commission regulation.

138Cf. H.K. Porter Co., Inc. v. Central Vermont

Railway, Inc., 366 U.S. 272, 273–75 (1961).

139FERC Stats. & Regs. at 31,693; mimeo at 168–

70. 140FERC Stats. & Regs. at 31,694; mimeo at 172.

or unilateral) to their contracts with

non-jurisdictional owners.

Rehearing Requests

Jointly-Owned Facilities

Union Electric argues that the Final

Rule improperly requires a public utility

to unilaterally file a modification to

agreements that a non-jurisdictional

entity opposes, which amounts to a

litigation coercion provision. Union

Electric notes that it has been told by

Associated Electric Cooperative, Inc.

that it will oppose any modifications to

Union Electric’s agreements. Union

Electric further states that these

facilities are not commonly owned, but

rather each party wholly owns its

segment of the facilities.

Dalton asserts that Georgia Power

Company cannot comply with the

requirement to offer service over its

share of joint facilities because the ITS

is not owned by members as tenants in

common, but instead each member

owns specific segments of the

transmission grid. Dalton further argues

that it is unjust and unreasonable to

require Georgia Power Company to give

access to the ITS to new and roll-over

transmission customers under the Order

No. 888 tariff that are unwilling to

accept an investment responsibility and

an obligation to make balancing

payments.

Associated EC argues that the

Commission may modify nonjurisdictional contracts only under

section 211 of the FPA; the Commission

cannot simply modify the contract with

respect to the public utility.

NE Public Power District states that it

is party to an agreement with a public

utility involving jointly constructed

transmission facilities that prohibits use

of the transmission capacity by a nonparty. It asserts that ‘‘[t]he District’s

contractual rights under its contract

constitute valuable property, and the

summary annulment of those rights

constitutes a violation of Due Process.’’

(NE Public Power District at 18–20).

Moreover, it argues that blanket

invalidation of the terms and conditions

of the contracts is contrary to the SierraMobile doctrine.

Commission Conclusion

We reject those arguments that

maintain that the Commission cannot

properly require a public utility to file

unilaterally a modification to

agreements concerning joint

transmission facilities that a nonjurisdictional entity opposes. It is

without question that the Commission

has the exclusive authority to regulate

public utilities engaged in the sale for

resale and/or transmission of electric

energy in interstate commerce to assure

that rates, terms and conditions are just

and reasonable and not unduly

discriminatory. The fact that a public

utility may jointly own, with a nonjurisdictional entity, transmission

facilities through which it engages in

sales for resale and/or transmission of

electric energy in interstate commerce

does not alter the Commission’s

authority to regulate that public

utility.136 If the Commission finds that

a matter needs to be remedied, it may

issue an order directed at the public

utility. The fact that such an order may

affect a non-jurisdictional joint owner

does not undermine the validity of the

Commission’s order.137 Otherwise, a

public utility could simply enter into

joint agreements with non-jurisdictional

utilities to the frustration of the

Commission’s mandate to protect

consumers from undue

discrimination.138

Nor does the exercise of the

Commission’s powers under the FPA to

remedy undue discrimination by public

utilities constitute a violation of due

process vis-a-vis the non-jurisdictional

entity. When the contract was entered

into and filed with the Commission it

was with the explicit knowledge that

the Commission could regulate the

rates, terms and conditions of the

contract with respect to the

jurisdictional services provided

thereunder by the public utility. If and

when a public utility unilaterally files

either to amend or terminate the

agreement, the non-jurisdictional party

is free to raise any arguments it wishes

to support its position that no changes

are necessary to ensure that the contract

is just and reasonable and not unduly

discriminatory or preferential.

4. Reservation of Transmission Capacity

by Transmission Customers

In the Final Rule, the Commission

concluded that firm transmission

customers, including network

customers, should not lose their rights

to firm capacity simply because they do

not use that capacity for certain periods

of time.139

Rehearing Requests

No rehearing requests addressed this

matter.

5. Reservation of Transmission Capacity

for Future Use by Utility

In the Final Rule, the Commission

concluded that public utilities may

reserve existing transmission capacity

needed for native load growth and

network transmission customer load

growth reasonably forecasted within the

utility’s current planning horizon.140

However, the Commission determined

that any such capacity that a public

utility reserves for future growth, but is

not currently needed, must be posted on

the OASIS and made available to others

through the capacity reassignment

requirements, until such time as it is

actually needed and used.

Rehearing Requests

CCEM argues that it is discriminatory

to allow public utilities and network

transmission customers to reserve

existing transmission capacity for their

native load growth because it (1) limits

the determination of ATC, (2) is likely

to increase the cost of transmission for

other customers, and (3) is inconsistent

with a capacity reservation-based

system. CCEM argues, however, that if

the reservation feature is retained,

franchise utilities that reserve capacity

must pay the full reservation charges,

with no cost shifting to other customers.

CCEM further recommends that all

reservation payments should be credited

directly to firm transmission services

and the planning horizon should be

limited to a reasonable time into the

future.

American Forest & Paper argues that

to achieve comparability, utilities must

not be permitted to withhold capacity

from the market for the benefit of native

load. American Forest & Paper further

argues that the Commission must

establish mechanisms for evaluating the

reasonableness of the utilities’

requirements and projections, otherwise

they have an incentive to over-forecast

and to extend their planning horizons.

American Forest & Paper suggests that

requiring utilities to establish separate

entities to purchase transmission on

behalf of their native load would help

solve this problem.

VA Com requests that the

Commission clarify what will happen if

a utility’s forecast of load growth is too

low. It argues that native load should

not have to bear the burden of any

forecast errors and that utilities should

be required to reserve sufficient capacity

to serve the current and projected needs
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12301

141FERC Stats. & Regs. at 31,694; mimeo at 172.

142FERC Stats. & Regs. at 31,696; mimeo at 178–

179.

143FERC Stats. & Regs. at 31,696; mimeo at 179.

144FERC Stats. & Regs. at 31,696–97; mimeo at

179–80.

145FERC Stats. & Regs. at 31,697; mimeo at 180–

81.

146FERC Stats. & Regs. at 31,697; mimeo at 181.

of native load customers. VA Com

would also have the definition of native

load in section 1.19 of the tariff

expanded to include existing

distribution cooperatives and others

who currently provide service to end

users. With respect to reservation

priority, VA Com states that the

Commission should establish the

following reservation priority: native

load customers, firm contract customers,

and non-firm customers. Finally, VA

Com asserts that the calculation of ATC

must not include any capacity that may

be needed by native load customers.

Commission Conclusion

We will deny the requests of CCEM

and American Forest and Paper. We

continue to believe that public utilities

should be allowed to reserve existing

transmission capacity needed for native

load growth and network customer load

growth reasonably forecasted within the

utility’s current planning horizon.

We note that network service is

founded on the notion that the

transmission provider has a duty to plan

and construct the transmission system

to meet the present and future needs of

its native load and, by comparability, its

third-party network customers. In

return, the native load and third-party

network customers must pay all of the

system’s fixed costs that are not covered

by the proceeds of point-to-point

service. This means that native load and

third-party network customers bear

ultimate responsibility for the costs of

both the capacity that they use and any

capacity that is not reserved by point-topoint customers. In this regard, native

load and third-party network customers

face a payment risk that point-to-point

customers generally do not face. For

these reasons, we do not believe that it

is appropriate to require native load and

network customers to assume any

additional cost responsibility for the

capacity that is reserved for their future

use.

In response to CCEM’s concerns, we

recognize that offering load-based

network service and reservation-based

point-to-point service in one tariff may

have disadvantages in that it may result

in less than optimal use of the system

if a utility overestimates its load.

However, by requiring that available

capacity reserved for native load be

posted on OASIS and be available to

others except when actually needed to

serve native load, we believe Order No.

888 substantially relieves the incentive

to over-reserve for native load and goes

a long way toward assuring full and

efficient use of the system.

With regard to the concern raised by

VA Com, the transmission provider has

an ongoing duty to plan and construct

its system in a prudent manner in order

to meet all of its firm service

obligations. We also reiterate that

public utilities may reserve existing

transmission capacity needed for native load

growth and network transmission customer

load growth reasonably forecasted within the

utility’s current planning horizon.[141]

There is a risk of under-or overprojecting the transmission needs of

native load and network customers, and

the native load and network customers’

cost responsibilities reflect this

additional risk. In response to VA Com’s

request, we note that nothing in our

regulations prohibits a state commission

from overseeing a utility’s retail native

load growth projections. Finally,

concerns regarding the accuracy of load

growth projections for native load and

network customers may be raised when

a transmission service agreement is filed

with the Commission or in a separate

section 206 proceeding.

6. Capacity Reassignment

In the Final Rule, the Commission

concluded that a public utility’s tariff

must explicitly permit the voluntary

reassignment of all or part of a holder’s

firm transmission capacity rights to any

eligible customer.142

(1) Reassignable Transmission Services

The Commission concluded that

point-to-point transmission service

should be reassignable, but that network

transmission service is not

reassignable.143

(2) Terms and Conditions of

Reassignments

a. General

In effecting a reassignment, the

Commission found that the assignor

may deal directly with an assignee

without involvement of the

transmission provider.144 Alternatively,

the Commission explained that the

assignor may request the transmission

provider to effect a reassignment on its

behalf, in which case the transmission

provider must post the available

capacity on its OASIS and assure that

any revenues associated with the

reassignment are credited to the

assignor. The Commission further found

that, among other things, any

assignment must be posted on the

transmission provider’s OASIS within a

reasonable time after its effective date.

b. Contractual Obligations

The Commission concluded that

while assignors and assignees may

contract directly with each other, the

assignor will remain obligated to the

transmission provider and the assignee

will be liable solely to the assignor.145

The Commission, however, did permit

mutually agreeable alternatives to this

approach.

c. Price Cap

The Commission concluded that the

rate for any capacity reassignment must

be capped by the highest of: (1) the

original transmission rate charged to the

purchaser (assignor), (2) the

transmission provider’s maximum

stated firm transmission rate in effect at

the time of the reassignment, or (3) the

assignor’s own opportunity costs

capped at the cost of expansion (Price

Cap).146

Rehearing Requests

Scheduling Transmission Service by

Assignees

CCEM requests that the Commission

clarify that an assignee of transmission

capacity, or its agent, is permitted to

schedule transmission service directly

with the transmission provider.

Network Transmission Service

American Forest & Paper declares that

the Commission erred in finding that

network service is not reassignable.

American Forest & Paper argues that

there is no technical reason for the

Commission’s position. According to

American Forest & Paper, the

Commission merely perpetuates the

myth that in point-to-point transmission

the contract actually determines the

path of the flow of electrons. In fact,

American Forest & Paper argues, the

only issue is arriving at a

nondiscriminatory and equitable price.

VT DPS argues that there is no reason

network capacity rights cannot be

defined during the period of a

reassignment as VT DPS suggested in its

comments:

Section 2.6 of the NorAm NIS Rate

Schedule (Appendix B to the Initial NOPR

comments of VDPS) is a provision which

allows the reassignment of network service.

Reassignment under the NorAm tariff would

work this way: During the period of the

assignment, both the original and

replacement customers’ network service

entitlements are defined as specified contract

quantities, the sum of which is equal to the

original customer’s highest coincident peak

load during the 12 months preceding the
12302 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

147 VT DPS at 47–48; see also Valero at 29–31.

148CCEM makes this argument in its rehearing

request of Order No. 889.

149While portions of network transmission

service are not reassignable, we would permit the

reassignment of a particular network transmission

service in its entirety.

150We note that the question of how network

service may be converted into a service that is

reassignable is at issue in the Capacity Reservation

Tariff NOPR proceeding in Docket No. RM96–11–

000.

assignment. During the period of the

assignment, that contract quantity, not the

actual use of the system by the original and

replacement shipper, will be used to

determine the two customers’ load ratio share

responsibility. The original and replacement

customers are free to divide responsibility for

interim contract demand between them as

they see fit.[147]

PA Coops argue that the Commission

failed to explain why network

customers have no capacity rights and

points to a statement in Order No. 888

that network customers ‘‘should not lose

their rights to firm capacity’’ as being

inconsistent with the Commission’s

conclusion with respect to the

reassignment of network service.

AMP-Ohio asserts that absent an

ongoing pass-through to network

customers of the revenue credits

associated with sales of point-to-point

service, the Commission should permit

the reassignment of unused

transmission capacity by network

customers.

TDU Systems argue that the

Commission should permit the

assignment of a network customer’s

right to network transmission service for

certain specific purposes. In particular,

TDU Systems state that the Commission

should permit assignment to allow a

customer to coordinate, jointly operate,

or pool its system with the systems of

other local and regional network

customers. TDU Systems argue that this

provides an opportunity to maximize

efficiencies without presenting the

complication that the Commission has

perceived with respect to the

reassignment of point-to-point

transmission capacity.

Price Cap

EEI asserts that the Commission’s

price cap creates several problems: (1)

non-comparable treatment because

transmission providers must credit

revenues, but resellers can keep the

revenues; (2) allowing sale at a price

higher than paid could encourage

speculation and hoarding; and (3) the

transmitting utility’s maximum stated

rate should not include the utility’s

opportunity costs.

CCEM argues that transmission

customers that are not transmission

providers or affiliates of transmission

providers should be freed from the price

cap. CCEM claims that in a secondary

market at market-based prices,

opportunity costs can be communicated

and lost opportunity costs averted.

NRECA believes that the price cap

provision that permits an assignor to

assign capacity at its own opportunity

costs (capped at the cost of expansion)

may provide firm point-to-point

customers a strong economic incentive

to buy up substantial firm capacity for

speculative purposes and argues that

this provision should be eliminated.

NRECA also argues that this provision

presents difficult rate substantiation

questions when the assignor is not a

public utility. Further, NRECA and

SoCal Edison note that section 23.1 of

the tariff does not include the cap at the

cost of expansion.

Calculation of Assignor’s Opportunity

Costs

SoCal Edison asserts that the

Commission must indicate how an

assignor should calculate its own

opportunity costs with respect to

determining the price cap and should

indicate that an assignor must abide by

the same standard for recovering

opportunity costs as the transmission

provider. Carolina P&L also asserts that

assignors must be held to the same

standard as transmission providers

when calculating opportunity costs.

Carolina P&L further explains that if the

opportunity costs are based on the cost

of foregone transactions, the assignor

should be required to post the price on

OASIS.

Carolina P&L also asks that the

Commission clarify how an assignor is

to calculate its own opportunity costs.

In particular, Carolina P&L asks if an

assignor is limited to recovering the

opportunity costs to which it is subject

under the transmission provider’s tariff

or can the assignor forfeit the

transaction underlying the transmission

service and call the resulting difference

an opportunity cost?

Resellers Into the Secondary Market

CCEM argues that the Commission

should free resellers, ‘‘who but-for the

resell would not be public utilities,’’

from regulation as public utilities or

should minimize the regulatory burden

on them.148 It further asserts that

resellers that are not transmission

providers should be treated like

unaffiliated power marketers and

granted waivers from public utility

regulations.

Participation in the Secondary Market

CCEM argues that those customers

that are permitted to continue to take

service under existing agreements

‘‘should be excluded from participating

in the secondary market until such time

as they agree to comply with the pro

forma tariff.’’ (CCEM (889 rehearing

request) at 7).

Commission Conclusion

Scheduling Transmission Service by

Assignee

The pro forma tariff does not prohibit

the assignee of transmission capacity

from scheduling transmission service

with the transmission provider. In fact,

the tariff provides that ‘‘the Assignee

will be subject to all terms and

conditions of this Tariff’’ (tariff section

23.1), which would include the

scheduling provision of tariff sections

13.8 and 14.6.

Network Transmission Service

We reaffirm our conclusion that

network transmission service is not

reassignable in the secondary market.149

Parties have raised no new arguments

that would persuade us otherwise. PA

Coops are nevertheless correct in noting

that network customers do have rights

to firm capacity. However, a network

customer’s rights (as well as the

transmission provider’s planning

responsibilities) are defined only in

terms of the capacity needed to integrate

the network customer’s designated

resources and its designated loads.

These are usage- or load-based rights

that are not fixed; they vary as the

customer’s load varies. Thus, the

network customer’s capacity rights are

not well enough defined to be generally

reassignable in the secondary market.150

VT DPS proposes a formula for

defining a network customer’s

entitlement that would be operative

during the period of an assignment.

However, the proposed definition is

simply an artifice derived from the load

ratio share calculation. The formula

does not result in a reassignable

capacity right.

AMP–Ohio’s suggestion regarding the

proper treatment of the revenue credits

associated with point-to-point service

raises a rate issue that should be

addressed in a ratemaking proceeding.

However, we note that the proper

treatment of such credits does not turn

on the assignability of network service.

Finally, TDU Systems’

recommendation that network service

be reassignable only for pooling and

coordination purposes is without merit.

If customers wish to avail themselves of

network service in order to realize
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12303

151We note that if the assignor is a public utility

it will in any event have to file a rate schedule for

the re-sale (reassignment) of unbundled

transmission.

152We also reject as unsupported EEI’s

comparability argument that transmission providers

must treat any transmission service revenues as a

revenue credit, but the reseller may keep any

transmission resale revenues.

153 In response to Carolina P&L’s request, we

clarify that the assignor is not limited to recovering

the opportunity costs to which it is subject under

the transmission provider’s tariff, i.e., the

transmission provider’s opportunity costs.

154FERC Stats. & Regs. at 31,698; mimeo at 183–

84.

155FERC Stats. & Regs. at 31,699; mimeo at 186.

156FERC Stats. & Regs. at 31,699–700; mimeo at

188.

benefits associated with joint or

coordinated operations with other

systems, they can jointly request

network service from the transmission

provider. To allow customers to opt into

and out of network service arrangements

under the guise of capacity

reassignment would be an abuse of the

terms and conditions of the service,

which, among other things, requires the

transmission provider to plan for the

long-term needs of network customers.

Price Cap

We will also reaffirm our conclusions

regarding the price cap applicable to

capacity reassignment. We continue to

believe that customers must be given

limited pricing flexibility in order to

achieve the full efficiency and risk

management benefits of capacity

reassignment.

Contrary to the assertions of EEI and

NRECA, we are not persuaded that

allowing the customer to reassign

capacity at a rate higher than it paid, as

a result of charging its own opportunity

costs, will lead to speculation and

hoarding. As a condition of the open

access tariff, the Commission will

require customers reassigning

transmission capacity to fully develop

their method for calculating opportunity

costs and provide all information

necessary to their customers in order to

verify such costs. Further, we reiterate

that the potential for hoarding can be

mitigated by (1) allowing the

transmission provider to sell any

reserved but unscheduled point-to-point

transmission capacity on a non-firm

basis, and (2) having a price cap, which

allows the reseller to charge no more

than a cost-based rate, including its own

opportunity cost for reassigned capacity.

Therefore, the reseller will find that

reassigning transmission capacity to

others with higher valued uses will be

in its economic self interest. In addition,

any hoarding of capacity that has

anticompetitive effects can be addressed

under section 206.

We deny CCEM’s request to remove

the price cap for transmission customers

that are not transmission providers or

affiliates of transmission providers. As

we stated in the Final Rule, we are

unable to conclude that competition in

the market for reassigned transmission

capacity is sufficient to prevent

assignors from exerting market power.

Thus, we believe the opportunity cost

cap should be retained.151

Finally, in response to EEI’s request,

we clarify that ‘‘the transmission

provider’s maximum stated firm

transmission rate in effect at the time of

the reassignment’’ does not include the

transmission provider’s opportunity

costs.152 Also, as suggested by NRECA

and others, section 23.1 of the pro forma

tariff will be revised to indicate that the

assignor’s opportunity costs are capped

at the transmission provider’s cost of

expansion.

Calculation of Assignor’s Opportunity

Costs

In response to the requests of SoCal

Edison and Carolina P&L, we clarify that

the assignor’s opportunity costs should

be measured in a manner that is

analogous to that used to measure the

transmission provider’s opportunity

costs. That is, an assignor’s opportunity

costs include: (1) increased costs

associated with changes in power

purchases or in the dispatch of

generating units necessary to

accommodate a reassignment, and (2)

decreased revenues that arise from the

assignor having to reduce sales of power

in order to effect the reassignment.153

Regarding the calculation of

opportunity costs, we intend to hold

assignors to the same general standard

as transmission providers. Thus,

consistent with our treatment of

transmission providers, we will not

require assignors to post their

opportunity costs on the OASIS or to

make the costs routinely available to the

public. We will, however, require

assignors to describe to their assignees

their derivation of opportunity costs in

sufficient detail to satisfy the assignees

that the price charged does not exceed

the higher of (i) the original rate paid by

the reseller, (ii) the transmission

provider’s maximum rate on file at the

time of the assignment, or (iii) the

reseller’s opportunity cost, as set forth

in section 23.1 of the tariff.

Resellers Into the Secondary Market

The issues raised by CCEM with

respect to the regulation of resellers into

the secondary market are fact specific

and, accordingly, we will address such

issues on a case-by-case basis.

Participation in the Secondary Market

We reject CCEM’s argument that those

customers that are permitted by Order

No. 888 to continue to take service

under existing agreements should be

denied access to the secondary market

until they agree to comply with the pro

forma tariff. CCEM’s approach would

undermine our determination not to

generically abrogate existing

agreements, and would slow the growth

of the secondary market by limiting the

number of eligible participants.

7. Information Provided to Transmission

Customers

In the Final Rule, the Commission

concluded that all necessary

transmission information, as detailed in

the OASIS Final Rule, must be posted

on an OASIS.154

Rehearing Requests

No requests for rehearing addressed

this matter.

8. Consequences of Functional

Unbundling

a. Distribution Function

In the Final Rule, the Commission

concluded that the additional step of

functionally unbundling the

distribution function from the

transmission function is not necessary

at this time to ensure nondiscriminatory open access

transmission.155

Rehearing Requests

No requests for rehearing addressed

this matter.

b. Retail Transmission Service

In the Final Rule, the Commission

explained that although the unbundling

of retail transmission and generation, as

well as wholesale transmission and

generation, would be helpful in

achieving comparability, it did not

believe it was necessary.156 The

Commission further explained that the

matter raises numerous difficult

jurisdictional issues that are more

appropriately considered when the

Commission reviews unbundled retail

transmission tariffs that may come

before the Commission in the context of

a state retail wheeling program.

Rehearing Requests

CCEM argues that all transmission

must be unbundled, including currently

bundled retail transmission service,

because failure to do so is inconsistent

with the Commission’s assertion of

jurisdiction over the rates, terms, and

conditions of unbundled interstate

transmission to retail customers and
12304 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

157FERC Stats. & Regs. at 31,781; mimeo at 430–

31 (emphasis in original). As discussed in Section

IV.I., infra, we believe this jurisdictional

determination is supported by the statute and the

case law, including the D.C. Circuit’s recent

decision in United Distribution Companies v. FERC,

88 F.3d 1105 (1996).

158FERC Stats. & Regs. at 31,781; mimeo at 431.

159FERC Stats. & Regs. at 31,700–01; mimeo at

191. See also discussion infra at Section IV.G.

Section 1.11 (and Section 13.3).

160By notice issued September 27, 1996 in Docket

Nos. RM95–8–000 and RM94–7–001, the

Commission revised the compliance dates. It

required joint pool-wide section 206 compliance

tariffs to be filed no later than December 31, 1996,

and pool members to begin taking service under the

tariffs 60 days after the section 206 filing. It also

gave members of public utility holding companies

an extension of time to take service under their

system-wide tariff until no later than March 1, 1997.

161FERC Stats. & Regs. at 31,703; mimeo at 198.

162FERC Stats. & Regs. at 31,703–04; mimeo at

199.

163 In comments on the proposed rule, NERC

identified additional interconnected operations

services that it indicated may be necessary for

reliability. As discussed in the Final Rule, we do

not require the transmission provider to be the

default provider of these other services.

164FERC Stats. & Regs. at 31,716; mimeo at 238.

authority to address retail stranded costs

through its jurisdiction over such costs.

CCEM notes that the Commission found

it necessary in Order No. 636 to

unbundle the pipeline’s direct retail

sales to achieve comparability (CCEM

cites FPC v. Conway Corp., 426 U.S.

271, 273 (1976) and Mississippi River

Transmission Corp. v. FERC, 969 F.2d

1215 (D.C. Cir. 1992) for the proposition

that the Commission has jurisdiction

over all interstate transmission).

NY Municipal Utilities and American

Forest & Paper also argue that the

Commission erred in not requiring the

unbundling of the transmission

component of retail sales. American

Forest & Paper believes that such

unbundling will facilitate competition

by making the generation price

transparent to all participants.

Commission Conclusion

We disagree with those entities that

argue that the Commission erred in not

requiring the unbundling of all

transmission service, including the

unbundling of transmission from retail

service. As we explained in the Final

Rule:

when transmission is sold at retail as part

and parcel of the delivered product called

electric energy, the transaction is a sale of

electric energy at retail. Under the FPA, the

Commission’s jurisdiction over sales of

electric energy extends only to wholesale

sales. However, when a retail transaction is

broken into two products that are sold

separately (perhaps by two different

suppliers: an electric energy supplier and a

transmission supplier), we believe the

jurisdictional lines change. In this situation,

the state clearly retains jurisdiction over the

sale of the power. However, the unbundled

transmission service involves only the

provision of ‘‘transmission in interstate

commerce’’ which, under the FPA, is

exclusively within the jurisdiction of the

Commission. Therefore, when a bundled

retail sale is unbundled and becomes

separate transmission and power sales

transactions, the resulting transmission

transaction falls within the Federal sphere of

regulation.157

Nor is our decision not to unbundle

transmission from retail generation

service inconsistent with our assertion

of jurisdiction over unbundled interstate

transmission to retail customers. As we

explained in the Final Rule and

described further above, we have

exclusive jurisdiction under the FPA

over ‘‘transmission in interstate

commerce’’ by public utilities, which

includes the unbundled interstate

transmission component of a previously

bundled retail transaction.158 Our

assertion of jurisdiction in such a

situation arises only if the retail

transmission in interstate commerce by

a public utility occurs voluntarily or as

a result of a state retail program.

c. Transmission Provider

1. Taking Service Under the Tariff

In the Final Rule, the Commission

concluded that public utilities must take

all transmission services for wholesale

sales under new requirements contracts

and new coordination contracts under

the same tariff used by others (eligible

customers).159 For sales and purchases

under existing bilateral economy energy

coordination agreements, the

Commission gave an extension until

December 31, 1996 for public utilities to

take transmission service under the

same tariff used by others. The

Commission also gave an extension of

time to December 31, 1996 for certain

existing power pooling and other multilateral coordination agreements to

comply with this requirement.160

Rehearing Requests

This issue is discussed above in

Section IV.C.1.b.

2. Accounting Treatment

In the Final Rule, the Commission

directed utilities to account for all uses

of the transmission system and to

demonstrate that all customers

(including the transmission provider’s

native load) bear the cost responsibility

associated with their respective uses.161

Rehearing Requests

No requests for rehearing addressed

this matter.

D. Ancillary Services

In the Final Rule, the Commission

concluded that the following six

ancillary services must be included in

an open access transmission tariff: (1)

Scheduling, System Control and

Dispatch Service; (2) Reactive Supply

and Voltage Control from Generation

Sources Service; (3) Regulation and

Frequency Response Service; (4) Energy

Imbalance Service; (5) Operating

Reserve—Spinning Reserve Service; and

(6) Operating Reserve—Supplemental

Reserve Service.162 The Commission

adopted NERC’s recommendations for

ancillary service definitions and

descriptions with modifications.163

The Commission determined that the

transmission provider must provide and

the transmission customer must

purchase from the transmission

provider the first two services, subject to

conditions set out in the Rule. The

transmission provider must offer the

remaining four services to the

transmission customer serving load in

the transmission provider’s control area.

The transmission customer that is

serving load in the transmission

provider’s control area must acquire

these four services from the

transmission provider or a third party,

or self provide.

1. Specific Ancillary Services

a. Scheduling, System Control and

Dispatch Service

In the Final Rule, the Commission

concluded that Scheduling, System

Control and Dispatch Service is

necessary to the provision of basic

transmission service within every

control area.164 The Commission further

stated that this service can be provided

only by the operator of the control area

in which the transmission facilities used

are located.

Rehearing Requests

Wisconsin Municipals asks that the

Commission eliminate Schedule 1

(Scheduling, System Control and

Dispatch Service) as an ancillary service

and require transmission providers to

include these costs in the transmission

revenue requirement so the

transmission provider cannot recover

these costs twice. Alternatively,

Wisconsin Municipals asks that, if

customers do their own scheduling

through an electronic data link, the

charge for scheduling and dispatch be

waived.

Commission Conclusion

We disagree with Wisconsin

Municipals that we should eliminate

this ancillary service and include its
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12305

165FERC Stats. & Regs. at 31,716–17; mimeo at

239.

166See also Cajun. Cajun notes that it does and

could continue to provide at least a portion of

reactive power.

167See also APPA.

168The location and operating capabilities of the

generator will affect its ability to reduce reactive

power requirements.

costs with the transmission revenue

requirement. Scheduling requires action

by both the customer who provides

information about a transaction and the

control area that evaluates and accepts

(schedules) the transaction. If a

transmission provider allows a

transmission customer to supply its

schedules through an electronic data

link, it is merely offering an alternate

method of providing the transaction

information required. The control area

must still decide whether it can

schedule a transaction. Further,

scheduling a transaction is only one

aspect of Scheduling, System Control

and Dispatch Service. A control area

must also dispatch generating resources

to maintain generation/load balance and

maintain security during the

transaction. Only the control area

operator can perform these functions. A

transmission provider must unbundle

the cost of these functions, including

scheduling, from its base transmission

rate. This requirement to unbundle

ancillary services costs from the base

transmission rate ensures that double

recovery of scheduling costs will not

occur.

b. Reactive Supply and Voltage Control

From Generation Sources Service

In the Final Rule, the Commission

concluded that Reactive Supply and

Voltage Control from Generation

Sources Service is necessary to the

provision of basic transmission service

within every control area.165 Although a

customer is required to take this

ancillary service from the transmission

provider or control area operator, the

Commission stated that a customer may

reduce the charge for this service to the

extent it can reduce its requirement for

reactive power supply.

Rehearing Requests

NRECA and TDU Systems ask that

Schedule 2 of the tariff, Reactive Supply

and Voltage Control from Generation

Sources Service, be modified to reflect

that generation facilities outside a

control area can provide reactive power.

They argue that parties other than the

transmission provider and the

transmission customer are able to

supply reactive power. Similarly, Santa

Clara and Redding ask the Commission

to revise Schedule 2 to require the

transmission provider to offer this

service, but to allow the transmission

customer to arrange for this service

through a purchase from the

transmission provider, self-provision, or

purchases from third parties.166 Blue

Ridge also argues that the Commission

should permit self-supply or other local

supply when it is feasible and economic

to do so.

APPA, Santa Clara, Redding and

Cajun point out an inconsistency

between Schedule 2 and the preamble.

They assert that Schedule 2 of the tariff

should be revised to reflect the

preamble language that allows a

transmission customer to supply at least

a portion of its reactive power service.

California DWR says that it is capable of

providing Reactive Supply and Voltage

Control from Generation Sources

Service and that mandating that it

purchase this ancillary service makes no

sense. California DWR asks the

Commission to clarify that it is not

required to purchase this ancillary

service.

TAPS asks the Commission to make

clear that (1) customer-owned

generation facilities that are available to

supply reactive power to the

transmission provider’s transmission

system receive a credit, (2) the extent of

customer-supplied reactive power may

be sufficient to eliminate the need for a

separate reactive power charge paid to

the transmission provider, and (3)

customer-owned generation outside the

control area may be eligible for a credit

if it is located nearby where it can

provide reactive support for the

transmission provider’s transmission

system.167 TAPS further asserts that

reactive supply service should be

viewed not on a transaction basis but on

a gridwide or regionwide basis. Under

this approach, according to TAPS,

payments would be based on whether

the user supplies more than it uses or

uses more than it supplies.

Commission Conclusion

Control area operators use sources of

reactive support to control voltage and

maintain a stable power supply system.

Because of the limited ability to

transmit reactive power, these facilities

must be available at or near the point of

need. Therefore, reactive power support,

and hence the facilities able to provide

(or absorb) reactive power, must be

distributed throughout the transmission

system for the reliable operation of the

power system. Over- or under-supply of

reactive power at other points in the

network do not contribute to a stable

system and could harm the reliability of

the system.

Although we agree with NRECA and

TDU Systems that generation resources

just outside the boundaries of a control

area may provide some reactive support

within the control area, the control area

operator must be able to control the

dispatch of reactive power from these

generating resources. Accordingly, we

will modify Schedule 2 to refer to

generating facilities that are under the

control of the control area operator

instead of in the control area. The

transmission customer’s service

agreement should specify the generating

resources made available by the

transmission customer that provide

reactive support.

As noted in the Final Rule, a

transmission customer can reduce (but

not eliminate completely) the reactive

supply and voltage control needs and

costs that its transaction imposes on the

transmission provider’s system. For

example, a customer who controls

generating units equipped with

automatic voltage control equipment

may be able to use those units to help

control the voltage locally and reduce

the reactive power requirement of the

transaction.168 However, if these units

are not always available or are not

subject to the direction of the control

area operator, their occasional use may

not reduce the investment required by

the control area operator in reactive

power facilities. It merely reduces

temporarily the cost of operating these

facilities. Consistent with this

understanding, we will modify

Schedule 2 of the tariff to allow a

transmission customer to supply at least

part of the reactive power service it

requires. We will continue to require

reactive power service to be provided by

and purchased from the transmission

provider. However, a transmission

customer may satisfy part of its

obligation through self-provision or

purchases from generating facilities

under the control of the control area

operator. The transmission customer’s

service agreement should specify all

reactive supply arrangements.

We deny the California DWR and

TAPS request that customer-owned

generation facilities that are available to

supply reactive power should

automatically receive a credit. However,

as the Final Rule states, a customer may

reduce the charge for this service to the

extent it can reduce its requirement for

reactive power supply. We do not

believe a transmission customer can

satisfy all of its reactive requirements or

allow the transmission provider to avoid
12306 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

169FERC Stats. & Regs. at 31,717; mimeo at 240.

170Order No. 888 imposes no obligation on the

transmission provider to furnish replacement power

on a long-term basis if the customer loses its source

of supply.

171FERC Stats. & Regs. at 31,711; mimeo at 222.

172FERC Stats. & Regs. at 31,711; mimeo at 223.

investment in reactive power related

facilities. Concerning the other request

of TAPS, we will not require that the

supply of reactive power be on a

gridwide or regionwide basis. Because

reactive power must be supplied near

the point of need, we are not persuaded

that gridwide supply is feasible.

c. Energy Imbalance Service

In the Final Rule, the Commission

concluded that Energy Imbalance

Service must be offered for transmission

within and into the transmission

provider’s control area to serve load in

the area.169 However, the Commission

noted, a transmission customer can

reduce or eliminate the need for energy

imbalance service in several ways.

Energy Imbalance Service is provided

when the transmission provider makes

up for any difference that occurs over a

single hour between the scheduled and

the actual delivery of energy to a load

located within its control area. For

minor hourly differences between the

scheduled and delivered energy, the

transmission customer is allowed to

make up the difference within 30 days

(or other reasonable period generally

accepted in the region) by adjusting its

energy deliveries to eliminate the

imbalance. A minor difference is one for

which the actual energy delivery differs

from the scheduled energy by less than

1.5 percent, except that any hourly

difference less than one megawatt-hour

is also considered minor. Thus, the

Final Rule established an hourly energy

deviation band of ±/1.5 percent (with a

minimum of 1 MW) for energy

imbalance. The transmission customer

must compensate the transmission

provider for an imbalance that falls

outside the hourly deviation band and

for accumulated minor imbalances that

are not made up within 30 days.

(1) Description of Energy Imbalance

Rehearing Requests

North Jersey asserts that the

definitions of Energy Imbalance Service

and Backup Supply Service are

conflicting and need clarification. North

Jersey proposes that Energy Imbalance

Service be clarified to state that a

transmission provider will be required

to supply power to a customer ‘‘within

the dispatch period of the transmission

provider’s tariff.’’ It states that this

assures power when a customer is

unable to change its nominations to

match its generation capabilities. On the

other hand, North Jersey states that

Backup Supply Service should be the

supply of power for a period longer than

the tariff dispatch period.

NIMO asserts that the Commission

should recognize that there is another

type of Energy Imbalance Service. If a

generator is located in one control area,

but transfers the power to load in

another control area, there is a potential

mismatch between the amount of power

scheduled for delivery by the generator

and the amount it actually provides to

the operator of the control area where it

is located.

Nebraska Public Power District

(NPPD) states that allowing third parties

to provide Energy Imbalance Service

and Regulation and Frequency Response

Service could jeopardize system

reliability. It argues that the

transmission provider must have the

right to approve the third party provider

of these services and the right to

physically meter the loads located out of

the transmission provider’s control area

or otherwise monitor these services to

be assured that they are provided

satisfactorily.

NCMPA argues that because of the

potential for abuse, the Commission

should grant an exemption from an

energy imbalance charge if the source of

the energy shortfall is a generating

resource that has been turned over to

the transmission provider’s dispatching

control for meeting control area

requirements.

Commission Conclusion

We clarify that Energy Imbalance

Service is used to supply energy for

mismatches between scheduled

deliveries and actual loads that may

occur over an hour. We do not intend

it to be used as a substitute for operating

reserves when there is an outage of

generation supply or transmission. The

Final Rule states that if a customer uses

either type of operating reserve, it must

expeditiously replace the reserve with

backup power to reestablish required

minimum reserve levels.170

Order No. 888 specifies that there is

no obligation on the transmission

provider to provide power to the

customer for a ‘‘time longer than

specified in the tariff’’ for the customer’s

own backup supply to be made

available.171 The order also states that

‘‘any arrangements for the supply of

such service [i.e., Backup Supply

Service] by the transmission provider

should be specified in the customer’s

service agreement.’’ 172 We revise the

first statement to clarify that the

transmission customer’s service

agreement, not the tariff, should specify

any arrangements for backup service by

the transmission provider, including the

time within which backup power

supply will be made available. The time

should correspond to the time necessary

to restore operating reserves that is

generally accepted in the region and

consistently followed by the

transmission provider.

NIMO asserts that two types of energy

imbalance can occur if the generator and

the load are in different control areas.

These are (1) a mismatch between the

energy scheduled to be received in the

load’s control area and the actual hourly

energy consumed by the load, and (2) a

mismatch between energy scheduled for

delivery from the generator’s control

area and the amount of energy actually

generated in the hour. The Energy

Imbalance Service in the Final Rule

applies to the first case only. Although

we agree that the second type of

mismatch can occur, we will not

designate as Energy Imbalance Service a

mismatch between energy scheduled

and energy generated. Energy Imbalance

Service in this Rule applies only to the

obligation of the transmission provider

to correct the first type of energy

mismatch, one caused by load

variations.

In general, the amount of energy taken

by load in an hour is variable and not

subject to the control of either a

wholesale seller or a wholesale

requirements buyer. The Energy

Imbalance Service that we require as our

ancillary service has a bandwidth

appropriate for load variations and

should have a price for exceeding the

bandwidth that is appropriate for

excessive load variations. Although

NIMO states correctly that, where two

control areas are involved, there can

also be a mismatch between energy

scheduled and energy generated, NIMO

has not explained why this mismatch

should have the same bandwidth and

price as our Energy Imbalance Service.

Indeed, we believe it should not.

A generator should be able to deliver

its scheduled hourly energy with

precision. If we were to allow the

generator to deviate from its schedule by

1.5 percent without penalty, as long as

it returned the energy in kind at another

time, this would discourage good

generator operating practice. A

generation supplier could intentionally

generate less power when its generating

cost is high and make it up when its cost

is lower if the second type of mismatch

is included in our Energy Imbalance

Service. Instead, a generator will have

an interconnection agreement with its
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12307

173Many provisions regarding the reliable

operation and performance of both generation and

load will be included in supply interconnection

agreements and transmission customer service

agreements. The fact that we have designated six

services as necessary to prevent undue

discrimination in transmission service should not

be interpreted as our having set out a complete set

of interconnected operations services and

conditions necessary for reliable and orderly bulk

power system management.

174E.g., APPA, NRECA, Blue Ridge, Cooperative

Power, Wabash, TDU Systems, Redding, TAPS.

175See also TDU Systems.

176E.g., NRECA, Blue Ridge, Cooperative Power,

Wabash.

177E.g., TDU Systems, TAPS, NRECA, Wabash,

Redding.

178On the other hand, Wabash argues that

pursuant to industry practice, overdeliveries should

be treated differently than underdeliveries outside

Continued

transmission provider or control area

operator, and we expect that this

agreement will specify the requirements

for the generator to meet its schedule,

and for any consequence for persistent

failure to meet its schedule. This

agreement will be tailored to the parties’

specific standards and circumstances,

and, although such arrangements must

not be unduly preferential or

discriminatory (e.g., must be

comparable for all wholesale sellers,

including the transmission provider’s

own wholesale sales), we prefer not to

set these standards generically for all

parties.173

We disagree with NCMPA’s argument

regarding an exemption from Energy

Imbalance Service when the control area

operator controls the generating

resource. As discussed above and in the

Final Rule, energy imbalance results

from a mismatch between a scheduled

receipt and actual load in the control

area of the transmission provider.

Energy imbalance can occur if the actual

load differs from the scheduled receipt

regardless of who controls the

generating resource.

As specified in the Final Rule, to

ensure the reliability of the power

system, a transmission customer is

obligated to obtain Energy Imbalance

Service and Regulation and Frequency

Response Service for its transactions.

We clarify for NPPD that the

transmission customer may not decline

the transmission provider’s offer of

these ancillary services unless it

demonstrates to the transmission

provider that it has acquired the

services from another source. This

demonstration must show that the

customer’s alternative arrangement for

ancillary services is adequate and

consistent with Good Utility Practice.

The transmission customer’s service

agreement should specify any

alternative arrangements for the

provision of these (or any other)

ancillary services.

(2) Energy Imbalance Bandwidth

As explained above, Schedule 4

(Energy Imbalance Service) of the tariff

allows the transmission provider to

charge a transmission customer serving

load in its control area for taking an

amount of energy in any hour that is 1.5

percent more or less than the amount of

energy scheduled for that hour. In the

pro forma tariff, the minimum amount

of energy that can be assessed a charge

in an hour is one megawatt-hour.

Rehearing Requests

Several entities argue that this energy

imbalance bandwidth is too narrow and

should be increased.174 APPA asserts

that the narrow bandwidth imposes

obligations on the transmission

customer that the transmission provider

does not impose on itself.175 TAPS

argues that the 1.5 percent bandwidth

‘‘makes no sense because it simply

imposes a penalty for existence as a

small utility.’’ Redding states that the

1.5 percent energy imbalance

bandwidth is not appropriate for

transmission to a small utility that does

not operate a control area. In opposing

the narrow bandwidth, TDU Systems

notes that metering error is typically

within a range of ±2 percent. It further

argues that it is impossible for smaller

systems with low load factors, larger

load swings, and the need to change the

output quickly for a single unit to

operate within the narrow bandwidth.

Others assert that a too-narrow

bandwidth creates a burdensome level

of billings unless schedule changes are

permitted more frequently than

hourly.176 They fear that meeting the 1.5

percent bandwidth would require

expensive dynamic scheduling.

Some entities recommend a particular

alternative bandwidth.177 TDU Systems

suggests a sliding scale as follows. There

would be a bandwidth of ±5 percent of

scheduled energy for transactions of 500

MW or less, decreasing to ±1.5 percent

for transactions of 5,000 MW or more,

with a minimum bandwidth of ±5 MWh

in all cases. Alternatively, TDU Systems

says that network customers could be

entitled to a bandwidth equal to their

load ratio share of the amount (not

percentage) of their transmission

provider’s inadvertent interchange,

again subject to a minimum of 5 MWh.

TAPS recommends that the deviation

bandwidth be changed to 6 percent of

the transmission customer’s daily peak

demand, with a minimum bandwidth of

4 MWh.

NRECA proposes an alternative

approach (previously set forth in its

comments on the proposed rule): a

customer’s ‘‘energy compensation

balance’’ should be determined for each

hour based on the net energy deviation

from the ‘‘bandwidth base,’’ which

NRECA defines as the greater of (i) the

customer’s total on-line and available

generator capacity associated with the

generation dispatched, or (ii) the sum of

a customer’s maximum hourly demands

at each of its recipient interfaces.

NRECA states that its proposal sets forth

separate compensation based on

whether there is an overdelivery or an

underdelivery outside a five percent

bandwidth.

Wabash argues that the Commission

should use a deviation bandwidth based

on a period other than a single hour; for

example, use a known historical

number, such as the maximum hourly

load during the previous calendar year.

Wabash states that if a larger bandwidth

is not adopted, the Commission should

permit a transmission customer that is

purchasing spinning or supplemental

operating reserves as an ancillary

service to use those purchases as the

basis for an expanded deviation

bandwidth. In addition, Wabash asks

the Commission to clarify that an

imbalance resulting from a system

emergency situation caused by loss or

failure of facilities should be counted as

‘‘inadvertent loads’’ and repaid in like

hours at mutually agreed times and payback amounts.

Redding points out that the NERC (A2

Criterion) establishes a constant

bandwidth for every hour of the year

and should be used instead. For energy

imbalances of less than 1.5 percent,

Schedule 4 of the tariff allows the

energy to be returned in kind within 30

days, after which payment must be

made. Redding argues that the 30-day

period should be deleted. Instead the

Commission should follow current

industry practice of allowing reasonable

deviations to be carried forward into the

next month so as to avoid an accounting

nightmare. Finally, Redding argues that

the bandwidth for network service

should apply to the entire network load

and not to a ‘‘scheduled transaction.’’

Wisconsin Municipals asks the

Commission to clarify that if parties

have reached a settlement that

establishes a wider band, the

transmission provider may not use

Order No. 888 to avoid this settlement

obligation.

TAPS argues that any charges for

exceeding the bandwidth should be

cost-based and compensation should be

symmetrical for over-and underdeliveries.178 TAPS further argues that
12308 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

the deviation band. It adds that the rate for

underdeliveries should be cost-based. 179FERC Stats. & Regs. at 31,719; mimeo at 246.

180See Order on Non-Rate Terms and Conditions,

77 FERC ¶ 61,144 at 61,538 (1996). The Commission

explained:

Order No. 888 required all tariff compliance

filings to contain non-rate terms and conditions

identical to the pro forma tariff, with a limited

exception for regional practices, and with four

attachments where the utility could propose

specific inserts.

181FERC Stats. & Regs. at 31,770 n.514; mimeo at

399 n.514.

the bandwidth should not be applied by

transaction, and customers should not

have to pay for imbalances caused by

transmission provider dispatch

mistakes.

TDU Systems states that public

utilities should be placed on notice that

they will not be permitted to collect 100

mills per kWh for energy supplied by a

customer in excess of its schedules, as

some have sought in tariffs already filed.

Commission Conclusion

Energy Imbalance Service includes a

bandwidth to promote good scheduling

practices by transmission customers. It

is important that the implementation of

each scheduled transaction not overly

burden others.

We do not agree with APPA that the

bandwidth imposes an obligation on the

transmission customer that the

transmission provider does not impose

on itself. The Final Rule treats all

wholesale customers comparably. The

transmission provider must also use its

pro forma tariff and apply the same

bandwidth for sales to its wholesale

customers.

Many commenters assert that the

energy imbalance bandwidth of ±1.5

percent is too narrow and is difficult to

meet for small utilities. Several propose

an alternative bandwidth or a larger

minimum deviation. We believe that the

bandwidth included in the Final Rule

pro forma tariff is consistent with what

the industry has been using as a

standard and is as close to an industry

standard as anyone can set at this time.

However, we will set a larger minimum

deviation to meet the needs of small

customers. The minimum energy

imbalance is now two megawatt-hours

per hour (2 MW minimum in the pro

forma tariff). This adequately addresses

the concerns raised by small utilities

because they may exceed the bandwidth

without exceeding this minimum. For

example, a transmission customer that

transfers less than 133 MW (1.5 percent

of 133 MW is 2 MW, the minimum

energy imbalance) has a larger

percentage bandwidth than ±1.5

percent. The bandwidth set forth in the

pro forma tariff provides a needed

incentive for a transmission customer to

deliver an amount of energy each hour

that is reasonably close to the amount

scheduled, while at the same time

recognizing the needs of small utilities.

To help customers with the difficulty of

forecasting loads far in advance of the

hour, the Final Rule pro forma tariff

permits schedule changes up to twenty

minutes before the hour at no charge. By

updating its schedule before the hour

begins, a transmission customer should

be able to reduce or avoid energy

imbalance and associated charges.

However, we will allow the transmitting

utility and the customer to negotiate and

file another bandwidth more flexible to

the customer, subject to a requirement

that the same bandwidth be made

available on a not unduly

discriminatory basis.

We disagree with Wabash’s request to

require a transmission provider to

expand its energy imbalance bandwidth

for a transmission customer purchasing

spinning and supplemental reserves.

Unlike Energy Imbalance Service, which

treats deviations between scheduled and

actual hourly energy deliveries,

spinning and supplemental reserves

provide generating capacity that

responds to contingency situations (e.g.,

loss or failure of facilities). Order No.

888 requires a transmission customer to

obtain these operating reserve ancillary

services for its transactions. Therefore,

Wabash is simply requesting a larger

energy imbalance bandwidth. We have

selected the bandwidth to promote good

scheduling practices by transmission

customers. A larger bandwidth may

introduce poor operating practices that

could affect the reliability of the system.

If the Energy Imbalance Service

bandwidth were larger, energy supplied

within this expanded bandwidth could

be provided from reserve capacity.

Some reserve capacity may not then be

available when needed for system

reliability. However, as stated in the

Final Rule, we will allow a transmission

provider to assemble packages of

ancillary services (not bundled with

basic transmission service) that can be

offered at rates that are less than the

total of individual charges for the

services if purchased separately.179

In response to Wabash’s other

concern, we believe that emergency

situations caused by loss or failure of

facilities should be addressed in the

transmission customer’s service

agreement (or the generation supplier’s

separate interconnection agreement) and

not as part of Energy Imbalance Service.

In response to Redding’s statement

that the NERC (A2 criterion) establishes

a constant bandwidth for imbalances,

we note that NERC has set a standard for

a kind of deviation that is different from

our Energy Imbalance Service. NERC’s

bandwidth is for inadvertent

interchange between a control area and

all other control areas. Redding has

presented no reason that our Energy

Imbalance Service bandwidth should be

the same as NERC’s inadvertent

interchange bandwidth. Regarding its

concern about the in-kind repayment

period, we note that Schedule 4 does

not always require a 30-day period for

in-kind repayment of energy

imbalances; it also permits a term that

the transmission provider consistently

follows and is generally accepted in the

region. In addition, we clarify that the

bandwidth for network service applies

to the entire network load.

With respect to Wisconsin

Municipals’ request, we clarify that the

Final Rule does not require parties to a

contract that went into effect prior to

July 9, 1996 to stop using a wider

bandwidth established by settlement.

However, service provided pursuant to

a settlement that was expressly

approved subject to the outcome of

Order No. 888 on non-rate terms and

conditions must be revised in the

subsequent compliance filing to reflect

the language contained in the pro forma

tariff.180 Subsequent to the compliance

tariff filing, public utilities are free to

file under section 205 to revise the

tariffs (e.g., to reflect various settlement

provisions) and customers are free to

pursue changes under section 206.181

In response to arguments regarding

the price of Energy Imbalance Service,

we note that the Final Rule intentionally

does not provide detailed pricing

requirements. We require the

transmission provider to determine and

apply to the Commission for appropriate

rates for Energy Imbalance Service as

part of its transmission tariff.

Transmission customers may address

any disagreements with a specific

charge in the company’s transmission

rate case.

2. Ancillary Services Obligations

In the Final Rule, the Commission

distinguished two groups or categories

of ancillary services: (1) services that the

transmission provider is required to

provide to all of its basic transmission

customers under the tariff, and (2)

services that the transmission provider

is required to offer to provide only to

transmission customers serving load in

the provider’s control area. The

Commission required a transmission

provider that operates a control area to

provide the first group of ancillary

services and the transmission customer
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12309

182As NERC and others pointed out in their

comments on the proposed rule, this service can be

provided only by the operator of the control area

in which the transmission facilities used are

located. FERC Stats. & Regs. at 31,716; mimeo at

238.

to purchase these services from the

transmission provider. The Commission

required a transmission provider to offer

to provide the ancillary services in the

second group to transmission customers

serving load in the transmission

provider’s control area. The

Commission required the transmission

customer serving load in the

transmission provider’s area to acquire

these services, but allowed the

transmission customer to do so from the

transmission provider, a third party or

self-supply.

If the transmission provider is a

public utility providing basic

transmission service, but is not a control

area operator, the Commission allowed

the transmission provider to fulfill its

obligation to provide, or offer to

provide, ancillary services by acting as

the customer’s agent. In this case, if the

control area operator is a public utility,

the Commission required the control

area operator to offer to provide all

ancillary services to any transmission

customer that takes transmission service

over facilities in its control area whether

or not the control area operator owns or

controls the facilities used to provide

the basic transmission service.

a. Obligation of a Control Area Utility

Rehearing Requests

Carolina P&L asks the Commission to

clarify that the transmission provider is

not required to provide control area

services to another utility operating a

control area that simply chooses not to

provide for its own control area

obligations. It argues that this is not

justified in a competitive bulk power

market.

Maine Public Service asserts that a

transmission provider that is not a

NERC-recognized control area can

provide ancillary services from its own

facilities. It asks that the Commission

clarify that this is permissible. At a

minimum, Maine Public Service states

that the Commission must allow

transmission providers on a case-bycase basis to establish that they provide

ancillary services even if they are not

NERC-recognized control areas or do not

satisfy the Commission’s definition

(citing the initial decision in Maine

Public Service Company, 74 FERC

¶ 63,011 (1996)).

Similarly, California DWR states that

it has been operating since 1983 as a

quasi-control area, self-providing most,

if not all, of the ancillary services it

uses. It also notes that it provides such

services to its utility transmission

providers. California DWR argues that it

is entitled to appropriate compensation

for all ancillary services that it provides

to its transmission providers or other

parties.

Commission Conclusion

In response to Carolina P&L, we

clarify that the Final Rule does not

require a control area operator to

provide control area services within

another control area.

Except for the ancillary service called

Scheduling, System Control and

Dispatch,182 the Final Rule does not

preclude a transmission provider that is

not a control area operator from offering

ancillary services to its transmission

customers.

Order No. 888 requires that a

transmission customer obtain or provide

ancillary services for its transactions. If

a transmission customer can self-supply

a portion of its requirement for ancillary

services (other than Scheduling, System

Control, and Dispatch Service), it

should pay a reduced charge for these

services. As with the transmission

provider, a third party may offer

ancillary services voluntarily to other

customers if technology permits.

However, simply supplying some

duplicative ancillary services (e.g.,

providing reactive power at low load

periods or providing it at a location

where it is not needed) in ways that do

not reduce the ancillary services costs of

the transmission provider or that are not

coordinated with the control area

operator does not qualify for a reduced

charge. The transmission customer must

make separate arrangements with the

transmission provider or control area

operator to supply its own ancillary

services and specify such arrangements

in its service agreement.

b. Obligation to Provide Dynamic

Scheduling

Dynamic scheduling electronically

moves a generation resource or load

from the control area in which it is

physically located to a new control area.

In the Final Rule, the Commission

concluded that it would not require the

transmission provider to offer Dynamic

Scheduling Service to a transmission

customer, although a transmission

provider may do so voluntarily. If the

customer wants to purchase this service

from a third party, the Commission

stated that the transmission provider

should make a good faith effort to

accommodate the necessary

arrangements between the customer and

the third party for metering and

communication facilities.

Rehearing Requests

AMP-Ohio asks that the Commission

clarify that the transmission provider is

required to provide dynamic scheduling

‘‘to the extent a transmission customer

needs and is willing to pay for

reasonably priced dynamic scheduling

in order to support its operations,

including in order to integrate its loads

and resources located in more than one

control area.’’ Wisconsin Municipals

also asks the Commission to clarify that

dynamic scheduling must be provided if

technically feasible and permitted by

regional reliability practices.

Wisconsin Municipals further asks

that the Commission clarify that if the

transmission provider has agreed to

provide dynamic scheduling in a

settlement, it may not use its Order No.

888 implementation filing to void this

obligation.

EEI asks that the Commission clarify

the residual obligations of a control area

utility to an entity that electronically

leaves the control area via dynamic

scheduling.

Commission Conclusion

In response to Amp-Ohio and

Wisconsin Municipals, we note that

dynamic scheduling is not a required

ancillary service in Order No. 888, and

we do not require a transmission

provider to offer this service. However,

nothing in the Final Rule precludes a

transmission provider from offering it as

a separate service. Furthermore, offering

dynamic scheduling to integrate loads

and resources in more than one control

area is also not required.

Wisconsin Municipals’ argument with

respect to prior settlements has been

previously addressed in Section

IV.D.1.c.(2) (Energy Imbalance Service).

We clarify for EEI that, once dynamic

scheduling is arranged, each of the two

control areas has ancillary service

responsibilities under the Rule. The

reactive power obligations of the

original control area remain and cannot

be completely supplied by distant

sources. Order No. 888 requires, in the

case of dynamic scheduling, both

control areas to provide the first two

ancillary services in their respective

control areas, that is, (1) Scheduling,

System Control, and Dispatch Service

and (2) Reactive Supply and Voltage

Control from Generation Sources

Service, and the new control area to

offer the remaining ancillary services to

the dynamically scheduled entity. In

addition, the actual energy transfers

between the two control areas will

require basic transmission service. We
12310 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

183 In Docket No. ER95–791 the Commission

ruled that this issue was not part of the hearing and

that North Jersey should file for a declaratory order

to resolve the matter.

184FERC Stats. & Regs. at 31,720–21; mimeo at

250–52.

185 In brief, these are that (1) any offer of a

discount made by the transmission provider must

be announced to all potential customers solely by

posting on the OASIS, (2) any customer-initiated

requests for discounts (including requests for one’s

own use or for an affiliate’s use) must occur solely

by posting on the OASIS, and (3) once a discount

is negotiated, details must be immediately posted

on the OASIS. In addition to these three principal

requirements, we also require that a discount agreed

upon for a path must be extended to certain other

paths described in Section IV.G.1.h.

expect that any additional obligations of

a control area operator to an entity that

electronically leaves the control area via

dynamic scheduling, such as backup

procedures for the failure of

telemetering equipment, will be set out

in the transmission customer’s service

agreement.

c. Obligation As Agent

Rehearing Requests

A transmission provider must act as

an agent to help the customer acquire

ancillary services if the transmission

provider cannot provide them itself.

NRECA asks whether a non-public

utility may collect a reasonable fee for

its agency services in fulfilling its

reciprocity requirement.

Commission Conclusion

While the Final Rule does not allow

a public utility transmission provider

acting as an ancillary services agent to

collect a fee for its agency service, we

do not have similar authority to deny a

non-public utility the opportunity to

charge a fee for providing an agency

service. However, to the extent a nonpublic utility seeks to collect an agency

fee from a public utility, it must meet

our comparability requirements and

charge a comparable fee to its own

wholesale merchant function.

3. Miscellaneous Ancillary Services

Issues

a. Transmission Provider as Ancillary

Services Merchant

Rehearing Requests

Allegheny asserts that the sale of

power in connection with ancillary

services would make the transmission

provider a wholesale merchant under

the Commission’s standards of conduct

(citing section 37.3 of the Commission’s

Regulations). Allegheny asks that the

Commission clarify that a transmission

provider’s employee responsible for

providing ancillary services is not

engaged in a wholesale merchant

service that would trigger the functional

separation requirement.

Commission Conclusion

We clarify that the transmission

provider’s sale of ancillary services

associated with its provision of basic

transmission service is not a wholesale

merchant function for purposes of Order

No. 889. This is because the provision

of ancillary services is essential for

providing transmission service.

However, the sale of ancillary services

not associated with the transmission

provider’s provision of basic

transmission service is a wholesale

function for purposes of Order No. 889.

Thus, if an employee is marketing an

ancillary service independent of the

transmission provider’s obligations to

provide transmission service, i.e., as a

third party to another transmission

provider’s basic transmission service

customer, the employee would be

providing a wholesale merchant

function and the Order No. 889

Standards of Conduct apply.

b. QF Receipt of Ancillary Services

Rehearing Requests

North Jersey argues that the

Commission did not engage in reasoned

decisionmaking in ruling that Real

Power Loss Service is not an ancillary

service. It asserts that this service must

be provided by the transmission

provider. North Jersey further argues

that, because the Commission describes

the furnishing of real power loss as a

sale of power, this could prevent a

PURPA qualifying facility (QF) from

being a transmission service customer.

North Jersey states that a QF faces

power purchase and resell restrictions

under the Commission’s regulations.

North Jersey asks that the Commission

find that receipt of Real Power Loss

Service from a third party to complete

a transmission transaction is not a

purchase and resale of power. In

addition, North Jersey requests that the

Commission clarify that receipt of

ancillary services by a QF does not

constitute a purchase and resale of

electric power that would jeopardize its

status as a QF (clarification also

requested in ER95–791–000).183

Commission Conclusion

The Commission disagrees with North

Jersey’s assertion that Real Power Loss

Service should be an ancillary service

that must be provided by the

transmission provider. As stated in the

Final Rule, it is not necessary for the

transmission provider to supply Real

Power Loss Service to effect a

transmission service transaction.

Although the transmission customer is

responsible for losses associated with its

transmission service, supply of losses is

purely a generation service that can be

(1) self supplied; (2) purchased from the

transmission provider, if it offers this

service; or (3) purchased from a third

party.

We clarify that a QF arrangement for

receipt of Real Power Loss Service or

ancillary services from the transmission

provider or a third party for the purpose

of completing a transmission transaction

is not a sale-for-resale of power by a QF

transmission customer that would

violate our QF rules.

c. Pricing of Ancillary Services

In the Final Rule, the Commission

concluded that it would consider

ancillary services rate proposals on a

case-by-case basis and offered general

guidance on ancillary services pricing

principles.184

Rehearing Requests

NRECA and TDU Systems argue that

there should be truth in transmission

pricing so that the rate is clearly

identified as including or excluding

ancillary services.

AEP asserts that if a purchaser of

ancillary services has alternative

suppliers of these services, then either

the transmission provider should not be

required to provide those services or it

should be able to charge market rates for

them. Otherwise, according to AEP, the

market is skewed in favor of the

customer.

Illinois Power argues that if a

transmitting utility demonstrates that it

incurs incremental costs from its

obligation to offer to provide the

required ancillary services, it should be

permitted to recover such costs through

an adjustment to base transmission

rates.

Commission Conclusion

The Final Rule requires unbundling of

individual ancillary services from basic

transmission service. We point out to

NRECA and TDU Systems that the

transmission provider must post and

update prices for basic transmission and

each ancillary service on its OASIS. As

discussed below in Section IV.G.1.h.

(Discounts), the Commission is revising

its policy regarding the discounting of

the price of transmission services.

There, we establish three principal

requirements for discounting basic

transmission service.185 We clarify here

that these principal requirements apply

to discounts for ancillary services

provided by the transmission provider

in support of its provision of basic

transmission service. However, because

ancillary services are generally not path-
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12311

186 ’’Negotiation’’ would only take place if the

transmission provider or potential customer seeks

prices below the ceiling prices set forth in the tariff.

187FERC Stats. & Regs. at 31, 722; mimeo at 255–

56.

188FERC Stats. & Regs. at 31,725–27; mimeo at

266–70.

189FERC Stats. & Regs. at 31,727–28; mimeo at

270–72.

190By notice issued September 27, 1996, the

Commission extended the date by which public

utilities that are members of tight power pools must

take service under joint pool-wide open access

transmission tariffs from no later than December 31,

1996 to 60 days after the filing of their joint poolwide section 206 compliance tariff.

specific, a discount agreed upon for an

ancillary service must be offered for the

same period to all eligible customers on

the transmission provider’s system. In

addition, if a transmission provider

offers any rate or packaged ancillary

service discounts, it must post them on

its OASIS and make them available to

affiliates and non-affiliates on a basis

that is not unduly discriminatory. In

this manner, any discounting of

ancillary service prices is visible to all

market participants. We will require

that, as soon as practicable, any

‘‘negotiation’’ of discounts between a

transmission provider and potential

transmission (and ancillary) service

customers should take place on the

OASIS.186

We continue to require a transmission

provider to provide or offer to provide

the six ancillary services, even if the

transmission customer has some

alternative suppliers. We distinguished

these six services from others (e.g., Real

Power Loss Services) for which many

suppliers are typically available. In

some cases, only the transmission

provider can provide the ancillary

service; in other cases too few providers

are available to create a market for these

services. Further, we were persuaded by

the comments of NERC and others that

these services are essential for

reliability; if a customer must obtain

these services to obtain transmission

service there must be a default provider

of these services. However, marketbased rates for some of the ancillary

services may be appropriate if the seller

lacks market power for such services.

Market power issues regarding ancillary

services have to be addressed before

market-based rates for ancillary services

can be approved, as requested by AEP.

We will consider market-based rates for

ancillary services on a case-by-case

basis.

In reply to Illinois Power, we agree

that the transmission provider may

incur incremental costs from its

obligation to offer to provide ancillary

services. We believe, however, these

costs should be included in the price for

those services. Order No. 888 requires

the transmission provider to unbundle

the cost of ancillary services from the

base transmission rate. A rebundling of

these costs with the base transmission

rate, as Illinois Power requests, would

not satisfy the unbundling requirement.

E. Real-Time Information Networks

In the Final Rule, the Commission

concluded that in order to remedy

undue discrimination in the provision

of transmission services it is necessary

to have non-discriminatory access to

transmission information, and that an

electronic information system and

standards of conduct are necessary to

meet this objective.187 Therefore, in

conjunction with the Final Rule, the

Commission issued a final rule adding

a new Part 37 that requires the creation

of a basic OASIS and standards of

conduct.

Rehearing Requests

Rehearing requests raising arguments

with respect to specific aspects of

OASIS and standards of conduct are

addressed in Order No. 889–A, issued

concurrently with this order.

F. Coordination Arrangements: Power

Pools, Public Utility Holding

Companies, Bilateral Coordination

Arrangements, and Independent System

Operators

In the Final Rule, the Commission

explained that its requirement for nondiscriminatory transmission access and

pricing by public utilities, and its

specific requirement that public utilities

unbundle their transmission rates and

take transmission service under their

own tariffs, apply to all public utilities’

wholesale sales and purchases of

electric energy, including coordination

transactions.188 While the Commission

‘‘grandfathered’’ certain existing

requirements agreements and noneconomy energy coordination

agreements, it also determined that

certain existing wholesale coordination

arrangements and agreements must be

modified to ensure that they are not

unduly discriminatory. The

Commission then discussed (as set forth

further below) how and when various

types of coordination agreements will

need to be modified, and when public

utility parties to coordination

agreements must begin to trade power

under those agreements using

transmission service obtained under the

same open access transmission tariff

available to non-parties.

The Commission explained that it was

addressing four broad categories of

coordination arrangements and

accompanying agreements: ‘‘tight’’

power pools, ‘‘loose’’ power pools,

public utility holding company

arrangements, and bilateral coordination

arrangements.

In addition, the Commission

explained that ISOs may prove to be an

effective means for accomplishing

comparable access and, accordingly,

provided guidance on minimum ISO

characteristics.

1. Tight Power Pools

The Commission required public

utilities that are members of a tight pool

to file, within 60 days of publication of

the Final Rule in the Federal Register,

either: (1) an individual Final Rule pro

forma tariff; or (2) a joint pool-wide

Final Rule pro forma tariff.189 However,

the Commission required them to file a

joint pool-wide Final Rule pro forma

tariff no later than December 31, 1996,

and to begin to take service under that

tariff for all pool transactions no later

than December 31, 1996.190 The

Commission also required the public

utility members of tight pools to file

reformed power pooling agreements no

later than December 31, 1996 if the

agreements contain provisions that are

unduly discriminatory or preferential.

If a reformed power pooling

agreement allows members to make

transmission commitments or

contributions in exchange for

discounted transmission rates, the

Commission indicated that the pool may

file a transmission tariff that contains an

access fee (or file a higher transmission

rate) for non-transmission owning

members or non-members, justified

solely on the basis of transmissionrelated costs.

Rehearing Requests

Consumers Power asks the

Commission to clarify that Order No.

888 does not preclude the Michigan

Electric Coordinated Systems (MECS)

from being in compliance by removing

all transmission functions from pool

control and allowing pool members or

the pool to take transmission service

from transmission-owning pool

members under their open access tariffs.

It asserts that this would be an interim

placeholder alternative while retail

deliberations continue in Michigan.

Furthermore, as one of the two members

of MECS, Consumers Power indicates

that it would be willing to consider

further modifications that would

liberalize membership criteria during

the transition period if the Commission

otherwise clarifies that the MECS Pool

is in compliance with Order No. 888.
12312 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

191 It is not clear from the rehearing request

exactly how the current members of MECS are

proposing to remove all transmission functions

from pool control and to take transmission service

under their individual open access tariffs. For

example, this may preclude the continuation of

joint economic dispatch of generating facilities

belonging to Consumer Power and Detroit Edison,

which the rehearing request appears to assume

would continue. However, the Commission will

address the adequacy of any such proposal in the

context of the appropriate compliance filings.

192FERC Stats. & Regs. at 31,657; mimeo at 64–

65; section 35.27.

193FERC Stats. & Regs. at 31,660; mimeo at 73–

74.

194See FERC Stats. & Regs. at 31,727–28; mimeo

at 271–72.

195FERC Stats. & Regs. at 31,728; mimeo at 272–

74.

196By notice issued September 27, 1996, the

Commission extended the date by which public

utility members of loose power pools must take

service under joint pool-wide open access

transmission pro forma tariffs from no later than

December 31, 1996 to 60 days after the filing of

their joint pool-wide section 206 compliance tariff. 197See also Public Service Co of CO.

NY Municipals request that the

Commission clarify that, particularly if

generation services are to be provided at

market-based rates, monopoly

transmission services must continue to

be provided at cost-based rates (raised

in connection with the NYPP). They

also ask that the Commission clarify that

joint pool-wide tariffs must incorporate

transmission rates that are uniform

(non-pancaked) and strictly based on

the embedded costs of the transmission

facilities and related transmission

expenses. Moreover, NY Municipals

argue that transmission owners should

receive a credit based on the

depreciated costs of their transmission

facilities.

TAPS also asks the Commission to

clarify that pool-wide and system-wide

tariffs must contain non-pancaked rates.

Commission Conclusion

While Consumers Power’s proposal to

remove transmission functions from

pool control, if implemented in a nondiscriminatory fashion, would satisfy

the comparability requirements of Order

No. 888, the Commission encourages

Consumers Power to pursue a pool-wide

tariff.191

NY Municipal Utilities’ concern that

rates for transmission service will not be

priced at cost-based rates is ill-founded.

While Order No. 888 does not establish

any specific pricing methodology for

tariff transmission service, the

Commission expects all transmission

rate proposals filed on compliance to be

cost based and to meet the standard for

conforming proposals set out in the

Commission’s Transmission Pricing

Policy Statement. (See 18 CFR 2.22).

Regarding NY Municipal Utilities’

and TAPS’s requests for a uniform tariff

with non-pancaked rates, Order No. 888

does not require a non-pancaked rate

structure unless a non-pancaked rate

structure is available to pool members.

Although the Commission has

encouraged the industry to reform

transmission pricing, the Commission’s

current policy does not mandate a

specific transmission rate structure.

With regard to NY Municipal

Utilities’ concern about market-based

rates for generation, public utility

owners of existing NYPP generation are

not eligible to charge market-based

power sales rates absent Commission

approval. Order No. 888 allows marketbased rates only if the seller in a casespecific filing demonstrates it meets the

Commission’s well-established criteria

of showing that it and its affiliates do

not have or have adequately mitigated

transmission market power and

generation market power, that there are

no other barriers to entry, and there is

no evidence of affiliate abuse or

reciprocal dealing. With regard to

requests to make market-based sales

from new generation, the seller does not

have to submit evidence of generation

market power in long-run bulk power

markets (subject to challenge where

specific evidence can be presented); 192

however, for sales from existing

generation at market-based rates, the

applicant must demonstrate that it

lacks, or has fully mitigated, generation

market power.193

In response to NY Municipals’ request

that transmission owners that contribute

transmission facilities to a power pool

should receive a rate credit based on the

depreciated costs of those transmission

facilities, we agree that this is one

possible way of reflecting a pool

member’s contributions or commitments

of transmission facilities. However, NY

Municipals has provided no rationale as

to why we should limit the broader

approach we adopted in Order No. 888

to this single mechanism.194

2. Loose Pools

In the Final Rule, the Commission

found that public utilities within a loose

pool must file, within 60 days of

publication of the Final Rule in the

Federal Register, either: (1) an

individual Final Rule pro forma tariff; or

(2) a pool-wide Final Rule pro forma

tariff.195 However, the Commission

required that they file a joint pool-wide

Final Rule pro forma tariff no later than

December 31, 1996, and begin to take

service under that tariff for all pool

transactions no later than December 31,

1996. 196 The Commission also required

that the public utility members of loose

pools file reformed power pooling

agreements no later than December 31,

1996 if the agreements contain

provisions that are unduly

discriminatory or preferential. They also

must file a joint pool-wide tariff no later

than December 31, 1996.

If a reformed pooling agreement

allows members to make transmission

commitments or contributions in

exchange for discounted transmission

rates, the Commission determined that

the pool may file a transmission tariff

that contains an access fee (or a higher

transmission rate) for non-transmission

owning members or non-members,

justified solely on the basis of

transmission-related costs.

Rehearing Requests

Union Electric asserts that the

definition of loose pools is so vague that

many public utilities, regional

organizations and multi-lateral

arrangements, which are not actually

pools, may incorrectly be deemed loose

pools by third parties. Thus, Union

Electric asks the Commission to clarify

that members or parties to multi-lateral

arrangements only need to offer

transmission services pursuant to their

own individual company tariffs.

EEI asks the Commission to clarify the

nature of the tariffs that loose pools may

file to comply with the Rule to ensure

that the members are not required to file

tariffs for services that they do not now

provide. EEI also requests that, where

members of loose pools currently

provide transmission services to each

other, they may continue to provide

such services to each other under each

member’s individual pro forma tariff in

lieu of a pool-wide tariff (provided that

those services are made available to all

eligible entities on a non-discriminatory

basis). Similarly, Montana Power argues

that members of loose pools should be

allowed to meet comparability by filing

individual open access tariffs, without

having to file a pool-wide tariff.197

Public Service Co of CO asserts that

the primary purpose of the Inland

Power Pool is to provide for reserve

sharing during emergency conditions,

although the pool agreement also allows

for economy transactions. It argues that

another way to comply with the Rule

should be to eliminate the economy

energy schedule of the Inland Power

Pool Agreement. Moreover, Public

Service Co of CO argues that given the

number of non-jurisdictional entities

within the Inland Power Pool, it may be

impossible to agree on a pool-wide

tariff. El Paso adds that Inland Power

Pool should not be treated as a loose
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12313

198See FERC Stats. & Regs. at 31,728; mimeo at

273–74.

199See FERC Stats. & Regs. at 31,726; mimeo at

268–69 (filing of open access tariffs by public utility

pool members is not enough to cure undue

discrimination in transmission if those entities can

continue to trade with a selective group within a

power pool; the same holds true for certain bilateral

arrangements allowing preferential pricing or

access) and FERC Stats. & Regs. at 31,727–28;

mimeo at 270–272 (tight and loose pools must file

joint pool-wide tariffs).

200See FERC Stats. & Regs. at 31,730; mimeo at

278.

201FERC Stats. & Regs. at 31,728–29; mimeo at

274–77.

202By notice issued September 27, 1996, the

Commission extended the date by which public

utilities that are members of holding companies

must take service under their system-wide tariffs

from December 31, 1996 to no later than March 1,

1997.

pool because it functions as a reserve

sharing mechanism and not as a pool.

Utilities For Improved Transition asks

the Commission to clarify that pool

members or members of other entities

do not have to provide more

transmission services than they already

provide on a voluntary basis to each

other. It contends that there is no record

to support a broader obligation and

would cause massive disruption and the

disintegration of many existing pools.

Utilities For Improved Transition

maintains that pools should have

substantial leeway to develop

arrangements reflecting their diverse

memberships and the diverse

contributions made.

VEPCO seeks clarification whether

the Commission intended to impose the

single-system tariff requirement only

with respect to multilateral agreements

that provide for system-wide

transmission rates for the parties to the

agreements.

TAPS asks the Commission to clarify

that section 35.28(c)(3) includes all

pools and all holding company systems,

as well as any multi-lateral agreement so

long as the multi-lateral agreement

explicitly or implicitly addresses

transmission (e.g., by providing for a

transaction without assessing

transmission costs in connection with

that transaction).

Commission Conclusion

In response to parties seeking

clarification of the definition of a loose

pool, the Commission clarifies that a

loose pool is any multilateral

arrangement, other than a tight power

pool or a holding company arrangement,

that explicitly or implicitly contains

discounted and/or special transmission

arrangements, that is, rates, terms, or

conditions. The Commission requires

public utilities that are members of a

loose pool to either (1) reform their

pooling arrangements in accordance

with Order No. 888 or (2) excise all

discounted and/or special arrangements

transmission service from the pooling

arrangement. That is, in the latter case

the members could continue to provide

other services (e.g., generation), but

would cease to be a loose pool for

purposes of Order No. 888.

The primary goal of Order No. 888’s

requirements for pooling arrangements,

including ‘‘loose’’ pools, is to ensure

comparability regarding transmission

services that are offered on a pool-wide

basis. We believe comparability for

loose pools can be achieved if pooling

agreements are modified: (1) to allow

open membership and (2) to make the

transmission service in the loose pool

agreement available to others. While the

Commission encourages pool-wide

transmission tariffs that offer the full

range of transmission services included

in the pro forma tariff, we will not

require, under the comparability

principles of Order No. 888, that pool

members offer to third parties

transmission services that they do not

provide to themselves on a pool-wide

basis. For example, if existing loose pool

members do not offer network services

to each other, they do not have to

expand the pool services to offer

network services to themselves or any

third parties. Additionally, we do not

find it to be unduly discriminatory to

provide some pool-wide transmission

services to members under a pooling

agreement and to provide other

transmission services to members under

the individual tariff of each member, as

long as members and non-members have

access to the same transmission services

on a comparable basis and pay the same

or a comparable rate for transmission.198

The Commission notes that the Inland

Power Pool agreement provides for nonfirm transmission service (Service

Schedule D) for emergency service,

scheduled outage service, and economy

energy service. The Inland Power Pool

agreement provides members

preferential transmission rates for

deliveries of emergency service, i.e.,

members will provide free non-firm

transmission service at a higher priority

than any other non-firm transactions.

Such preferential service is not available

to non-members. We consider any rates,

terms or conditions of transmission

service that favor members over nonmembers to be unduly discriminatory

and preferential, whether embodied

explicitly or implicitly in a loose

pooling agreement. Pool members can

either amend the agreement to provide

comparable services to others and open

the pool to new members, or amend the

agreement to eliminate any preferential

transmission availability and/or pricing.

In response to TAPS, the Commission

agrees that Section 35.28(c)(3) applies to

any pool, holding company system or

multi-lateral agreement that contains

explicit or implicit transmission rates,

terms, or conditions.199 For example, if

a utility offers transmission without

charge as part of such an agreement, it

must offer transmission to all parties

requesting a similar service either

without charge or at an access fee or

other transmission rate that comparably

reflects transmission-related costs borne

by members of the agreement.200

3. Public Utility Holding Companies

In the Final Rule, the Commission

required that holding company public

utility members, with the exception of

the Central and South West (CSW)

System, file a single system-wide Final

Rule pro forma tariff permitting

transmission service across the entire

holding company system at a single

price within 60 days of publication of

the Final Rule in the Federal

Register.201

With respect to CSW, the Commission

directed the public utility subsidiaries

of CSW to consult with the Texas,

Arkansas, Oklahoma and Louisiana

Commissions and to file not later than

December 31, 1996 a system tariff that

will provide comparable service to all

wholesale users on the CSW System,

regardless of whether they take

transmission service wholly within

ERCOT or the SPP, or take transmission

service between the reliability councils

over the North and East

Interconnections.

The Commission gave public utilities

that are members of holding companies

an extension of the requirement to take

service under the system tariff for

wholesale trades between and among

the public utility operating companies

within the holding company system

until December 31, 1996—the same

extension it granted to power pools.202

In addition, the Commission indicated

that it may be necessary for registered

holding companies to reform their

holding company equalization

agreement to recognize the nondiscriminatory terms and conditions of

transmission service required under the

Final Rule pro forma tariff.

Rehearing Requests

FL Com asks the Commission to

clarify whether it intends to require

operating company members of a

registered holding company to charge

each other the same wheeling charge to

be charged to others even though others

pay nothing for transmission

construction. FL Com argues that such
12314 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

203AL Com at 1–4.

204The Commission notes that Order No. 888

requires that all third party tariff customers taking

network or point-to-point service pay a

transmission rate which reflects an appropriate

share of transmission costs, including those related

to transmission construction.

a charge would be inconsistent with the

Commission’s traditional treatment of

public utility holding companies as a

single entity.

AL Com asks the Commission to

clarify that ‘‘intra-holding company

transactions in support of economic

dispatch across a single integrated

system should not be subjected to

additional transmission charges, while

transactions between operating

companies for the benefit of wholesale

customers not included within the

definition of native load customer

require distinct transmission

charges.’’ 203

Southern asks the Commission to

clarify that transactions between public

utility operating subsidiaries within a

holding company system for the benefit

of native load customers fall within the

network service for which they are

assigned cost responsibility under the

Final Rule tariff.

AEP asserts that the Commission has

provided no reason for requiring

holding companies to use the pro forma

tariff for intra-pool transactions. AEP

asks the Commission to clarify whether

the Rule applies to AEP. It asserts that

the Preamble states that all members of

holding company systems must use the

pro forma tariff for intra-system

transactions, but the regulatory text

requires only a member of a public

utility holding company ‘‘arrangement

or agreement that contains transmission

rates, terms or conditions * * *.’’ AEP

explains that the AEP System

Interconnection Agreement and

Transmission Agreement do not contain

transmission rates, terms or conditions

and the members do not offer

transmission service to one another.

However, AEP argues that, if the Rule

applies to AEP, Order No. 888 contains

no explanation of why or how a

different intra-pool allocation of

transmission costs than would result

from the pro forma tariff prejudices

transmission users. It asserts that (1)

AEP’s allocation has been subject to

extensive review over the last few years,

(2) AEP treats itself as a single system,

not as a collection of individual

members, (3) each member carries its

fair share of transmission costs, and (4)

compliance with the Commission’s

requirement would be onerous. If the

Commission does not remove this

requirement, AEP requests waiver of the

requirement.

Similarly, Allegheny Power asserts

that its Power Supply Agreement (PSA)

does not provide for ‘‘wholesale trades.’’

It argues that the PSA is immaterial to

all transmission services, including

intra-company exchanges. Because the

PSA is an existing contract that the

Final Rule does not propose to abrogate,

Allegheny Power asserts that the PSA

need not be reformed under the Final

Rule. Allegheny states that it will

provide new wholesale service to itself

and others under its open access tariff

which was accepted for filing on

December 6, 1995 in Docket No. ER96–

58.

Union Electric assumes that the ‘‘rule

is intended solely to mean that a

holding company system would use the

network integration part of the tariff, for

its intra-system ‘wholesale trades.’

Indeed, if Union Electric and CIPS were

required to take point-to-point service

for their wholesale trades, they would

be placed in an inferior and noncomparable position vis-a-vis customers

on the Ameren tariff who will be

entitled to single-system transmission

service for a single or postage-stamp

charge.’’ (Union Electric notes that

Union Electric and CIPS are currently

seeking approval to merge, with the

combined facilities being operated as

the Ameren System.)

NU believes that Order No. 888 could

be construed to require NU System

Companies to charge each other as

separate entities for transmission service

in connection with intra-system cost

allocations as if off-system wholesale

sales had occurred. NU argues, however,

that this is inconsistent with

Commission precedent in treating the

NU System Companies as a single

integrated system and would give retail

native load customers service inferior to

that of wholesale native load (i.e.,

network) customers. NU further argues

that it will result in duplicative

transmission charges for energy flows

between the NU System Companies.

Moreover, NU asserts that viewing NU

as a single system for establishing

transmission rates, but as separate

companies with respect to energy flows

that result from economic dispatch of

their generation to native load is

inconsistent with the treatment of

multistate non-holding company

utilities and is thus discriminatory.

Blue Ridge seeks clarification that, to

avoid double payment for transmission,

‘‘CSW must file its compliance filing

resolving comparability issues and the

appropriate CSW ERCOT transmission

rate prior to September 1, 1996.’’ Blue

Ridge asserts that CSW must resolve a

potential conflict between its rate

structure and the new PUCT wheeling

rule by September 1, 1996

(contemplated effective date for interim

PUCT transmission rates).

Commission Conclusion

In requiring holding companies to file

a pool-wide tariff, the Commission does

not intend that transmission service

provided by the operating subsidiaries

to one another on behalf of their

respective native loads be subjected to

additional transmission charges. The

Commission recognizes that the

operating subsidiaries of a holding

company bear cost responsibility for

transmission facilities by virtue of

ownership of such facilities. In many, if

not all cases, transmission costs are

equalized among operating subsidiaries

through transmission equalization

agreements (e.g., AEP’s Transmission

Agreement).

However, the Commission does

intend, pursuant to Order No. 888, that

holding company operating subsidiaries

take transmission service under the

same tariff rates, terms, and conditions

as third-party customers that seek

transmission service over the holding

company system. This applies to all

holding company systems that rely

upon the transmission facilities of the

individual operating subsidiaries to

support central economic dispatch—

including AEP and Allegheny. However,

as suggested by Southern and Union

Electric, the Commission anticipates

that transmission service for an

operating subsidiary’s native load

would be treated as network service

under the pro forma tariff. Accordingly,

the CP demands of each operating

subsidiary’s native load would establish

each operating subsidiary’s transmission

cost responsibility related to network

service over the integrated transmission

facilities of the holding company

system.

Thus, in response to the AL and FL

Commissions, Southern, and NU, intraholding company transactions in

support of economic dispatch would not

be subjected to ‘‘additional’’

transmission charges.204 The load ratio

pricing mechanism of the network

portion of the tariff should ensure that

each operating company bears its

proportionate share of transmission

costs without jeopardizing or otherwise

penalizing these types of intra-system

transactions. Moreover, any off-system

sales would have to be taken under the

point-to-point provisions of the tariff.

As we noted in Order No. 888, ‘‘it may

be necessary for registered holding

companies to reform their holding
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12315

205FERC Stats. & Regs. at 31,729; mimeo at 277.

206FERC Stats. & Regs. at 31,729–30; mimeo at

277–78.

207Anaheim, in an answer opposing SoCal

Edison’s request for clarification regarding its

package agreements, requests that these agreements

be dealt with on a case-by-case basis ‘‘in context.’’

(Anaheim Answer). While answers to requests for

rehearing generally are not permitted, we will

depart from our general rule because of the

significant nature of this proceeding and accept the

Anaheim Answer.

208See also VEPCO.

209See also Florida Power Corp (if the

Commission requires an unbundled transmission

rate, it must allow transmission providers to

reformulate their unbundled economy energy

agreements to recover both their capacity and

energy costs and the costs of transmission).

210FERC Stats. & Regs. at 31,730; mimeo at 277.

company equalization agreement to

recognize the non-discriminatory terms

and conditions of transmission service

required under the Final Rule pro forma

tariff.’’ 205 However, nothing in Order

No. 888 mandates any change to the

method chosen for apportioning

transmission revenues among the

operating companies, which may be

based, for example, upon equalizing

transmission investment responsibility.

The concerns raised here by Blue

Ridge are resolved on an interim basis

because the PUCT has accepted the

filing of CSW’s Federal tariff as

adequate in the Texas proceeding until

differences between the Order No. 888

rate structure and the PUCT rate

structure are resolved. If, CSW

implements a new ERCOT transmission

tariff in response to actions of the PUCT,

then affected parties may bring any

remaining concerns to the Commission’s

attention at that time through a section

206 complaint.

We note that the issue raised here by

Blue Ridge is very similar to the one

raised by Tex-La and East Texas Electric

Cooperative, and addressed by the

Commission’s recent order, in Houston

Lighting & Power Co., 77 FERC ¶ 61,113

at 61,439 (1996). There, the Commission

found that it would be premature to

address this issue at that time, and

noted that parties would have an

opportunity to raise their concerns after

the PUCT finalizes its ERCOT tariff.

4. Bilateral Coordination Arrangements

In the Final Rule, the Commission

required that any bilateral wholesale

coordination agreements executed after

the effective date of the Final Rule

would be subject to the functional

unbundling and open access

requirements set forth in the Rule.206 In

addition, the Commission required that

all bilateral economy energy

coordination contracts executed before

the effective date of the Rule be

modified to require unbundling of any

economy energy transaction occurring

after December 31, 1996. Moreover, the

Commission permitted all non-economy

energy bilateral coordination contracts

executed before the effective date of the

Rule to continue in effect, but subject to

section 206 complaints.

To compute the unbundled

coordination compliance rate, the

Commission indicated that the utility

must subtract the corresponding

transmission unit charge in its open

access tariff from the existing

coordination rate ceiling. However, the

Commission noted, if a utility’s

transmission operator offers a

discounted transmission rate to the

utility’s wholesale marketing

department or an affiliate for the

purposes of coordination transactions,

the same discounted rate must be

offered to others for trades with any

party to the coordination agreement. In

addition, the Commission explained

that discounts offered to non-affiliates

must be on a basis that is not unduly

discriminatory.

Rehearing Requests

SoCal Edison seeks clarification as to

how Order No. 888 affects package

agreements (i.e., bilateral contracts that

provide some or all of requirements

service, coordination service, or

transmission service). In particular,

SoCal Edison asks (1) what specific

functions of each must be modified to

comply with Order No. 888; (2) whether

a sale of non-firm energy made pursuant

to a package agreement must comply

with the unbundling requirements for

coordination contracts; (3) whether the

requirement to remove preferential

transmission access or pricing

provisions applies to existing or future

transmission services provided pursuant

to package agreements; if so, what is the

deadline; and (4) whether the rulings

with respect to Mobile-Sierra apply to

package agreements.207

APPA argues that the Commission

should require all coordination

arrangements to be subject to Order No.

888. CCEM asserts that to the extent

non-economy energy coordination

agreements are allowed to remain

bundled, they should be identified in

connection with determinations of

available transfer capacity and, because

they should only be a transitional

matter, should be subject to a sunset

date of December 31, 1996.

According to Utilities For Improved

Transition, requiring the subtraction of

the current tariff transmission rate from

the current rate ceiling, without

increasing the residual sales price, will

force transmission providers to fail to

recover their full costs of providing

service because the Commission has

previously prohibited these rates from

including a transmission component

(citing Green Mountain, 63 FERC

¶ 61,071 at 61,307–08 (1993) and

Cleveland Electric, 63 FERC ¶ 61,244 at

62,277–78 (1993)).208

Union Electric also argues that the

Commission should delete the

requirement that the utility subtract the

corresponding transmission unit charge

in its open access tariff from the existing

coordination rate ceiling. According to

Union Electric, actual bilateral economy

sales do not include adders for recovery

of transmission costs, but are typically

limited to production or generation

costs. Union Electric further asserts that

the definition of economy energy

coordination agreement is so openended, it may apply to many types of

coordination transactions that are not

mere energy economy sales. Union

Electric argues that a split-the-savings

charge cannot be unbundled in the

manner described by the Commission

because it is an incorrect assumption

that the rate ceiling for every economy

energy coordination sales agreement

includes a transmission cost

component. If Union Electric is required

to arbitrarily subtract a transmission

charge for its economy sales, it argues

that it will be penalized. At a minimum,

it argues, a utility should be permitted

to submit a list of economy coordination

rate schedules that it believes to be

already unbundled and should not have

to subtract a transmission charge.

Alternatively, it argues that the

Commission should not require

unbundling unless the Commission

determines that the existing rate ceiling

has been cost justified on a basis that

includes an allowance for the full

recovery of transmission function

cost.209

Commission Conclusion

SoCal Edison represents that its

package agreements include

requirements services as well as

coordination services. For existing

bilateral economy energy coordination

agreements, Order No. 888, as clarified

by the Commission’s May 17 Order,

requires the unbundling of transmission

from generation for all such contracts on

or before December 31, 1996.210 Thus,

any economy energy service included in

existing package agreements must be

unbundled.

Regarding non-firm energy sales made

under a package agreement, SoCal

Edison provides no information

distinguishing that service from other
12316 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

211FERC Stats. & Regs. at 31,730; mimeo at 277.

212Approximately 300 filings to unbundle this

category were filed by December 31, 1996.

213FERC Stats. & Regs. at 31,666; mimeo at 90.

214Regarding CCEM’s request that non-economy

energy coordination agreements be identified in

determining available transfer capacity (ATC), we

note that all data used to calculate ATC and total

transfer capacity (TTC) must be made publicly

available upon request pursuant to section

37.6(b)(2)(ii) of the OASIS regulations.

215FERC Stats. & Regs. at 31,726; mimeo at 268–

69.

216See e.g., Illinois Power Company, 62 FERC

¶ 61,147 at 62,062 (1993).

217FERC Stats. & Regs. at 31,730–32; mimeo at

279–86.

economy energy coordination

transactions, which include all ‘‘if, as

and when available’’ services (see

section 35.28(b)(2)). Absent more

information, non-firm energy sales

should be unbundled.

We further note that our requirements

concerning unbundling of bilateral

coordination arrangements apply

regardless of whether such

arrangements are governed by the public

interest or just and reasonable standard

of review.

With respect to APPA’s concerns, the

Final Rule provides that all bilateral

economy energy coordination contracts

executed before the effective date of the

Final Rule must be modified to require

unbundling of any economy energy

transaction occurring after December 31,

1996. Non-economy energy bilateral

coordination contracts executed before

the effective date of the Final Rule,

however, were allowed to continue in

effect, but subject to complaints filed

under section 206 of the FPA.211 We

drew this distinction for both policy and

practical reasons. The ability to use

discounts on transmission in order to

favor short-term economy energy sales

made out of the transmission provider’s

own generation was of particular

concern to the Commission. Thus, in

order to eliminate the ability of

transmission providers to exercise

undue discrimination for short-term

coordination transactions under existing

umbrella-type agreements, we required

unbundling by December 31, 1996.212

However, non-economy energy

coordination agreements presented a

different situation.

In the Final Rule, we expressed a

particular concern with not abrogating

non-economy energy coordination

agreements, which we indicated may

reflect complementary long-term

obligations among the parties.213 Noneconomy energy coordination

agreements consist for the most part of

long-term reliability arrangements.

Providing for the abrogation of these

arrangements could cause special

problems for the reliable operation of

the grid. Examples include agreements

governing sales during emergency or

maintenance periods. These agreements,

unlike economy energy agreements

where trade is on an ‘‘as, if and when

available’’ basis, often have specified

terms governing the parties’

responsibilities. As a result, many noneconomy energy coordination

agreements are more akin to

requirements contracts than to economy

energy coordination agreements.

Therefore, we determined to permit this

category of contracts to run their course,

absent a case specific complaint. The

burden would be on the complainant to

demonstrate that the transmission

component of a non-economy energy

coordination agreement is unduly

discriminatory or otherwise unlawful.

The Commission would decide based on

the facts of the case whether unbundling

is the appropriate remedy. Neither

CCEM nor APPA have presented

evidence or convincing arguments as to

why these types of agreements should

be unbundled generically.214

The Commission affirms the

requirement in Order No. 888 that the

transmission rate for any economy

energy coordination service be

unbundled. The Commission states in

Order No. 888 that to adequately

remedy undue discrimination, public

utilities must remove preferential

transmission access and pricing

provisions from agreements governing

their transactions.215 In the cases cited

by Utilities For Improved Transition,

the Commission prohibited the utility

from charging a split-savings rate plus a

contribution to fixed costs. The

Commission has long allowed utilities

to set their coordination rates by

reference to their own costs (cost-based

ceilings) or by dividing the pool of

benefits (fuel cost differentials) brought

about by the transaction.216 Utilities

have been free to design a rate using

either method but not both. Regardless

of the method adopted to set a bundled

rate on file (a seller’s own costs or a

sharing of transaction benefits), a

bundled rate constitutes the total charge

for all components and must now be

unbundled.

A split-savings rate is set without

reference to the seller’s fixed costs and,

therefore, Union Electric’s argument is

not germane. We are not requiring that

the present rate be adjusted upward or

downward. Rather, we are requiring

disassembly of the existing rate into

component parts one of which

represents the rate being charged for

transmission service. If a utility is no

longer satisfied that an existing rate is

compensatory, with regard to either the

generation component or the

transmission component, it may file an

appropriate revision under section 205.

ISO Principles

In the Final Rule, the Commission set

out certain principles that will be used

in assessing ISO proposals that may be

submitted to the Commission in the

future.217 The Commission emphasized

that these principles are applicable only

to ISOs that would be control area

operators, including any ISO established

in the restructuring of power pools.

The Commission set forth the

following principles for ISOs:

1. The ISO’s governance should be

structured in a fair and nondiscriminatory manner.

2. An ISO and its employees should

have no financial interest in the

economic performance of any power

market participant. An ISO should

adopt and enforce strict conflict of

interest standards.

3. An ISO should provide open access

to the transmission system and all

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

unbundled, grid-wide tariff that applies

to all eligible users in a nondiscriminatory manner.

4. An ISO should have the primary

responsibility in ensuring short-term

reliability of grid operations. Its role in

this responsibility should be welldefined and comply with applicable

standards set by NERC and the regional

reliability council.

5. An ISO should have control over

the operation of interconnected

transmission facilities within its region.

6. An ISO should identify constraints

on the system and be able to take

operational actions to relieve those

constraints within the trading rules

established by the governing body.

These rules should promote efficient

trading.

7. The ISO should have appropriate

incentives for efficient management and

administration and should procure the

services needed for such management

and administration in an open

competitive market.

8. An ISO’s transmission and

ancillary services pricing policies

should promote the efficient use of and

investment in generation, transmission,

and consumption. An ISO or an RTG of

which the ISO is a member should

conduct such studies as may be

necessary to identify operational

problems or appropriate expansions.

9. An ISO should make transmission

system information publicly available

on a timely basis via an electronic
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12317

218Sithe, in a response to the NYPP’s request for

clarification, opposes the ‘‘transmission owners

only’’ ISO sought by NYPP. (Sithe Response).

Subsequently, NYPP filed an objection to Sithe’s

pleading and request that it be rejected. (NYPP

Objection). NYPP explains that its rehearing was a

request that the Commission refrain from setting

fixed rules for ISO governance in advance, not an

argument that the Commission should adopt one

particular mechanism or another for all ISOs. While

answers to requests for rehearing generally are not

permitted, we will depart from our general rule

because of the significant nature of this proceeding

and accept the Sithe Response and NYPP Objection.

information network consistent with the

Commission’s requirements.

10. An ISO should develop

mechanisms to coordinate with

neighboring control areas.

11. An ISO should establish an

alternative dispute resolution (ADR)

process to resolve disputes in the first

instance.

Rehearing Requests

General Comments

NY Municipal Utilities argue that if

the NYPP participants (or other tight

pools) elect to establish an ISO, the ISO

Principles should be made mandatory

for the protection of transmission

dependent utilities.

NY Com asks the Commission to

clarify that it will allow flexibility to

states and utilities in structuring

proposals that meet the goals underlying

the ISO principles. It explains that the

parties to New York’s electric

competition proceeding are discussing

the formation of an ISO in which

transmission owners control the system

operator, but would have to divest their

competitive generation. NY Com further

notes that it has not decided that matter

yet, but it does not want to see such

options foreclosed.

Minnesota P&L argues that certain

functions, particularly those involving

local area circumstances and safety, are

better handled at the local level. It

further argues that control area

responsibilities of an ISO should focus

on regional issues and operations, and

on establishing and enforcing uniform

criteria and guidelines for local control

area operations in order to assure nondiscriminatory treatment of all

transmission customers.

AMP-Ohio asserts that the

Commission should require the

separation of transmission, generation

and distribution through an ISO and, at

a minimum, the Commission should

include a Stage 3 of implementation to

bring ISOs to reality.

ISO Principle 1

NYPP argues that the Commission

should not include a rigid ban on

transmission owner leadership in ISO

governance because it is the

transmission owner that is ultimately

responsible for the reliability of the bulk

power system.218

ISO Principle 2

NYPP asks that the Commission

revise this principle to take a more

flexible approach to significant

employee issues. NYPP explains that it

has 81 management employees on the

payroll of individual member systems

and that pension rights (accrual rights

based on an average salary) and medical

insurance (preexisting conditions) are

through the individual member systems.

ISO Principle 3

SoCal Edison asks that this principle

be revised to permit a separate access

charge for each utility in order to avoid

cost shifting. Anaheim seeks revision of

this principle to require that an ISO

provide comparable compensation to all

transmission owners that make

transmission facilities available for use

by the ISO.

ISO Principle 5

Anaheim asks that this principle be

revised to make clear that ISO

arrangements should seek to encourage

participation by all transmission owners

within the region.

ISO Principle 6

NYPP seeks clarification that an ISO

needs control over more than some

generation facilities because the more

generating facilities operating under an

ISO the more reliability there is. Thus,

it asserts that the Commission should

clarify that its description of ISO control

of generation does not require only a

minimalist approach to ISO generation

control.

ISO Principle 8

SoCal Edison seeks revision of this

principle to remove the language linking

the ISO to performing studies necessary

to identify appropriate grid expansions.

According to SoCal Edison, an ISO

should not be a project sponsor or

should not conduct planning studies to

determine what facilities should be

constructed because those actions

would compromise its independence. In

addition, SoCal Edison seeks revision of

this principle to permit a transmission

usage charge that incorporates

locational marginal cost pricing for

managing transmission congestion.

Commission Conclusion

We reaffirm our strong commitment to

the concept of ISOs, and to the ISO

principles described in Order No. 888.

We continue to believe that properly

structured ISOs can be an effective way

to comply with the comparability

requirements of open access

transmission service. Nevertheless, we

do not believe at this time that it is

appropriate to require public utilities or

power pools to establish ISOs, as

suggested by AMP-Ohio. We think it is

appropriate to permit some time to

confirm whether functional unbundling

will remedy undue discrimination

before reconsidering our decision that

ISO formation should be voluntary.

A number of the above rehearing

requests on ISOs are from New York

parties and deal with ongoing efforts in

New York that would reform the New

York Power Pool pooling agreements,

restructure power markets, and possibly

form an ISO. Some of these arguments

are in apparent conflict; for example,

the NY Municipal Utilities argue that

the 11 ISO principles should be made

mandatory if the New York Power Pool

participants elect to establish an ISO,

while the NY Com argues that the

Commission should clarify Order No.

888 to state that it will allow flexibility

to states and utilities in structuring

proposals that meet the goals underlying

the ISO principles. We note that since

the time the rehearing requests were

filed, the NY Power Pool has filed

amendments to its pooling agreements

on December 30, 1996 and also has

filed, on January 31, 1997, various

agreements and tariffs designed to

implement an ISO and market exchange.

To the extent the rehearing requests

from New York parties deal with

matters that have been filed with the

Commission subsequent to the rehearing

requests, the Commission will address

the issues raised in the context of those

filings.

In response to NY Com’s request for

clarification that we provide flexibility

to states and their utilities in structuring

ISO proposals, the Commission at this

time clearly cannot, and does not intend

to, prescribe a ‘‘cookie cutter’’ approach

to ISOs. However, the Commission does

believe that certain basic principles

must be met to ensure nondiscriminatory transmission services.

We reaffirm our view that ISO

Principles 1 (independence with respect

to governance) and 2 (independence

with respect to financial interests) are

fundamental to ensuring that an ISO is

truly independent and would not favor

any class of transmission users. As the

Commission stated in its recent order on

the proposed PJM ISO:

The principle of independence is the

bedrock upon which the ISO must be built

if stakeholders are to have confidence that it
12318 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

219Atlantic City Electric Company, et al., 77 FERC

¶ 61,148 (1996) (mimeo at 36–41); see also Pacific

Gas & Electric Company, 77 FERC ¶ 61,204 (1996).

220 In making this finding, we are not suggesting

that an independent transmission company, which

owns only transmission, is undesirable. However,

an ISO, which separates ownership and operation,

is designed in large part to recognize that

transmission owners today have significant

generation or load interests that may bias their

operational decisions. 221FERC Stats. & Regs. at 31,731; mimeo at 283.

222FERC Stats. & Regs. at 31,733; mimeo at 288–

89.

223FERC Stats. & Regs. at 31,733; mimeo at 289.

224FERC Stats. & Regs. at 31,734–35; mimeo at

291–93.

will function in a manner consistent with

this Commission’s pro-competitive goals.[219]

ISO governance that is

disproportionately influenced by

transmission owners, unless they have

fully divested their interests in

generation, is not consistent with ISO

Principle 1. We remain concerned that

ISO proposals that do not include

governance by a fair representation of

all system users may not be

independent, although we reserve final

judgment on any specific governance

structure until we have an opportunity

to review a specific proposal.220

In response to the argument made by

NYPP that transmission owner

leadership in ISO governance may be

needed because transmission owners are

ultimately responsible for the reliability

of the bulk power system, we emphasize

that reliability is of primary importance

to this Commission and that the

formation and operation of an ISO

should not in any way impair reliability.

We believe that one of the main

purposes of an ISO is to make an

independent party, the ISO, responsible

for at least short-term reliability. Even if

both the transmission owners and the

ISO will be responsible for some aspects

of reliability, this does not affect our

finding that the governance of the ISO

must be independent of the

transmission owners so that the ISO can

carry out its own responsibilities in a

not-unduly discriminatory manner.

In response to arguments of the NYPP

that the Commission should revise

Principle 2 to take a more flexible

approach to employee issues, we

reaffirm the necessity of requiring the

employees of an ISO to be financially

independent of market participants and

note that Principle 2 suggests that a

short transition period should be

adequate for ISO employees to sever all

financial ties with former transmission

owners. We recognize that some

flexibility may be necessary regarding

the length of a transition period, but

believe that ISO employees must in

fairly short order be independent of all

financial ties to any market participants,

if we are to achieve not unduly

discriminatory practices in generation

and transmission markets.

A number of additional parties seek

other revisions to or clarifications of the

ISO Principles. For example, Minnesota

P&L requests clarification or rehearing

to ensure that the Commission provides

sufficient flexibility to permit local

operators, under the general supervision

and control of the ISO, to perform local

operational functions, such as

performing switching operations. In

response to this concern, we note that

Principle 3 (open access under a single

tariff) says that the portion of the

transmission grid operated by a single

ISO should be as large as possible. Our

view, as described above, is that an ISO,

which includes all affected users,

should be responsible for operation of

the system and ensuring reliability. The

ISO may use some combination of

actual physical control over facilities

and virtual control of facilities by others

(i.e., the ISO exercises control over

facilities by instructing the transmission

owners’ or generation owners’ staffs as

to the actions to be taken). The broad

range of interested parties that establish

the ISO must determine what services

the ISO will perform and what services

transmission owners or others will

perform under ISO supervision.

We deny the requests by Socal Edison

and Anaheim to revise ISO Principle 3

to permit separate access charges for

each utility to avoid cost shifting. We

think ISO Principle 3 already provides

sufficient flexibility to accommodate the

concerns of these parties with respect to

design of access charges and

compensation to owners for

transmission facilities under operational

control of the ISO.

Similarly, we see no reason to revise

Principle 5 (control of interconnected

operations) as requested by Anaheim.

We agree with Anaheim that wide

participation of transmission owners in

a region will help ensure open access

and increase efficient transmission

coordination. ISO Principle 3 says that

the portion of the transmission grid

operated by a single ISO should be as

large as possible. ISO Principle 5 says

that an ISO should have control over the

operation of interconnected

transmission facilities within its region.

These principles, as written, address

Anaheim’s concern.

With respect to NYPP’s request for

clarification of ISO Principle 6 (dealing

with constraints), we note that the

description of ISO Principle 6 in the

Final Rule says that the ISO may need

to exercise some level of operational

control over generation facilities in

order to regulate and balance the power

system.221 We do not think it is

appropriate for the Commission to give

further generic guidance now on what

constitutes the proper level of

operational control over generation. The

ISO, including all stakeholders, needs to

address this issue, based on the

structure of power markets and perhaps

other local considerations, in preparing

a specific proposal for our approval.

Finally, we deny SoCal Edison’s

request for revision of ISO Principle 8

(pricing). In response to SoCal Edison’s

concern, ISO Principle 8 allows the use

of appropriate locational marginal cost

pricing. The principle allows flexibility

regarding which regional organization of

market participants (ISO or RTG)

conducts the necessary studies to

identify the need for expansion. We are

unpersuaded by SoCal Edison’s

arguments that the fact that an ISO is

involved in planning for transmission

facility expansion would in any way

compromise the independence of the

ISO.

G. Pro Forma Tariff

In the Final Rule, the Commission

combined the requirements for point-topoint transmission service and network

transmission service into a single pro

forma tariff.222 The Commission

explained that this eliminates many of

the differences between the two NOPR

pro forma tariffs, provides a unified set

of definitions, and consolidates certain

common requirements such as the

obligation to provide ancillary services.

The Commission also noted that it was

issuing an accompanying Notice of

Proposed Rulemaking in Docket No.

RM96–11–000 in which it was seeking

comments on whether a different form

of open access tariff—one based solely

on a capacity reservation system—might

better accommodate competitive

changes occurring in the industry while

ensuring that all wholesale transmission

service is provided in a fair and nondiscriminatory manner. 223

1. Tariff Provisions That Affect The

Pricing Mechanism

a. Non-Price Terms and Conditions

In the Final Rule, the Commission

explained that the Final Rule pro forma

tariff is intended to initiate open access,

with non-price terms and conditions

based on the contract path model of

power flows and embedded cost

ratemaking.224 It emphasized that the

Final Rule pro forma tariff is not

intended to signal a preference for

contract path/embedded cost pricing for

the future. The Commission indicated
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12319

225FERC Stats. & Regs. at 31,751; mimeo at 342–

43.

226See Florida Municipal Power Agency v.

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

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

227E.g., FPL, Utilities For Improved Transition,

TDU Systems, Carolina P&L, AEC & SMEPA, VT

DPS, EEI.

that it will in the future entertain nondiscriminatory tariff innovations to

accommodate new pricing proposals.

The Commission further indicated

that, by initially requiring a

standardized tariff, it intends to foster

broad access across multiple systems

under standardized terms and

conditions. However, the Commission

emphasized that the tariff provides for

certain deviations where it can be

demonstrated that unique practices in a

geographic region require modifications

to the Final Rule pro forma tariff

provisions.

Finally, the Commission stated that it

will allow utilities to propose a single

cost allocation method for network and

point-to-point transmission services.

b. Network and Point-to-Point

Customers’ Uses of the System (so

called ‘‘Headroom’’)

In the Final Rule, the Commission

explained that it will not allow network

customers to make off-system sales

within the load-ratio transmission

entitlement at no additional charge.225

The Commission further explained that

use of transmission by network

customers for non-firm economy

purchases, which are used to displace

designated network resources, must be

accorded a higher priority than non-firm

point-to-point service and secondary

point-to-point service under the tariff. In

addition, the Commission found that

off-system sales transactions, which are

sales other than those to serve the

transmission provider’s native load or a

network customer’s load, must be made

using point-to-point service on either a

firm or non-firm basis. In rejecting the

‘‘headroom’’ concept (where a network

customer can make off-system sales as

long as its total use of the system does

not exceed its coincident peak demand),

the Commission explained that it was

not requiring any utility to take network

service to integrate resources and loads

and if any transmission user (including

the public utility) prefers to take flexible

point-to-point service,226 they are free to

do so. Further, the Commission

explained that any point-to-point

customer may take advantage of the

secondary, non-firm flexibility provided

under point-to-point service equally, on

an as-available basis.

Rehearing Requests

A number of entities argue that it is

unreasonable to permit firm point-topoint customers to receive non-firm

service, up to their contract demand, at

no additional charge, at secondary

receipt and delivery points, but to

require transmission providers and

network customers to purchase

transmission for all off-system sales,

including non-firm sales made in

competition with sales made by the

point-to-point customer.227 FPL asserts

that having built and paid for the entire

transmission network, the owner and

the network customer should have the

flexibility to use the network as they

need. Utilities For Improved Transition

declare that just as the firm point-topoint customer is permitted to

maximize the use of its contract

demand, the transmission provider and

network customer should be entitled to

maximize their long-term fixed cost

obligation (citing AES Power, Inc., 69

FERC ¶ 61,345 at 62,300 (1994) (AES)

for the proposition that the utility and

its native load customers are obligated

to pay all the costs of the transmission

system without regard to the amount of

energy actually scheduled).

FPL and Carolina P&L suggest two

possible solutions: (1) allow the

transmission provider and network

customer to have rights to the headroom

beneath their fixed cost obligations at no

additional charge, or (2) restrict the nocharge use of firm point-to-point

headroom to transmission service

associated with non-firm purchases to

serve load. Under either of these

options, they assert, the firm point-topoint customer’s rights to make nonfirm off-system sales would be on an

even competitive footing with the

transmission provider or network

customer.

PA Coops maintain that network

customers should have the right to

reassign/sell unused capacity below

their 12-month rolling average peak

demand at no additional charge. Cajun

argues that network customers should

be allowed to use the transmission

system for non-firm (and perhaps firm)

coordination transactions at no

additional cost, provided the network

customer’s total use of the transmission

system does not exceed its load ratio

share. Cajun notes that the Commission

seems to have determined elsewhere in

the Rule that a network customer has

already paid for the full use of its load

ratio share (citing mimeo at 332 and

338). In addition, Cajun states that

requiring the network customer to use

point-to-point service results in the

network customer paying twice for the

same capacity.

VT DPS argues that the Commission

should permit network users to make

limited use of their network capacity to

make off-peak off-system sales. It asserts

that UtiliCorp’s network tariff, filed in

Docket No. ER95–203, provides a useful

model: ‘‘the level of capacity utilized by

the company or the customer for its

combined network load and off-system

sales load would be fixed by the tariff

as the highest coincident peak load

experienced by the transmitting utility

in the three years preceding the offsystem sale.’’ According to VT DPS, this

places all firm users on a par. In

contrast, VT DPS argues that the

Commission’s solution is arbitrary and

patently inadequate. VT DPS claims that

concerned parties are not just

transmission providers, but include

state agencies and entities that need to

take network service. VT DPS further

argues that the lower priority for

secondary service under the point-topoint tariff may pose an unacceptable

risk to public utilities with firm

obligations to serve their load, and

having to agree to a fixed demand

quantity may be unsatisfactory for

public utilities with growing customer

loads and a statutory obligation to serve

those loads.

LEPA argues that:

[t]he Commission erred in not finding that in

order to compete, one must be able to utilize

base load units of 500MW size because entry

without the ability to employ such base load

units would make the putative entrant unable

to compete; that in order to employ such

units, or portions of them, the entrant had to

engage in the coordinated development of

base load units; that such coordinated

development requires use of transmission for

that purpose so as to be able to sell portions

of the output of a baseload unit off-system,

and that without ’headroom,’ the cost of

transmission for that purpose would not be

comparable with the cost of transmission for

the same purpose of the owner of the

transmission. (LEPA at 5).

Commission Conclusion

The requests for rehearing on this

issue present no arguments that were

not fully considered in Order No. 888.

Petitioners continue to claim that

transmission providers and network

customers are competitively

disadvantaged vis-a-vis point-to-point

transmission customers due to the

point-to-point customers’ ability to use

as available, non-firm service over

secondary points of receipt and delivery

at no additional cost. The Commission

attempted to strike a balance on this

issue in Order No. 888 by allowing both

network and point-to-point services to

be priced on the same basis (i.e., no

longer summarily rejecting the use of

the average of the 12 monthly system
12320 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

228FERC Stats. & Regs. at 31,751; mimeo at

342–43.

229FERC Stats. & Regs. at 31,736; mimeo at

296–97.

230Behind-the-meter generation means generation

located on the customer’s side of the point of

delivery. 231E.g., NRECA, TDU Systems, Blue Ridge.

peaks as the denominator for the rate for

point-to-point service). Additionally,

the Commission established a lower

priority for the non-firm secondary

point-to-point service than for either

economy purchases by network

customers or for stand-alone non-firm

point-to-point service, as discussed in

Section IV.G.3.b. Accordingly, we

believe that these concerns have been

sufficiently addressed.

Furthermore, these entities want to be

allowed to make off-system sales under

their network service at no additional

charge as long as their total use of the

system does not exceed their load ratio

share. They claim that it is inequitable

not to allow such ‘‘headroom’’ sales

under the network service while

allowing firm point-to-point customers

to use non-firm transmission service up

to their contract demands using

secondary receipt and delivery points at

no additional charge. As the

Commission stated in Order No. 888,

customers are not obligated to take

network transmission service.228 If

customers want to take advantage of the

as-available, non-firm service over

secondary points of receipt and delivery

through the point-to-point service, they

may elect to take firm point-to-point

transmission service in lieu of the

network service. We further note that

transmission providers must take pointto-point transmission service for their

own off-system sales, which results in

comparable treatment for both the

transmission provider and network

customers. Transmission providers and

other customers taking point-to-point

transmission service do not need to be

allowed to make ‘‘headroom’’ sales

because they have access to as-available,

non-firm service over secondary points

of receipt and delivery at no additional

charge through their point-to-point

service.

Cajun’s argument that a network

customer has already paid for the full

use of its load-ratio share of the system

ignores the fact that network service is

based on integrating a network

customer’s resources with its load, not

on making off-system sales. This is why

network customers pay for service on a

load-ratio basis. If Cajun is concerned

that it may need to pay for both network

service and point-to-point service, Cajun

can simply elect to take point-to-point

service for all of its transmission needs.

VT DPS’ claim that the lower priority

accorded to transmission service to

secondary points of receipt and delivery

under flexible point-to-point service

would present an ‘‘unacceptable risk’’ to

public utilities is unsubstantiated. If the

risk of having this secondary service

curtailed is too great, this customer has

the option to: (1) take stand-alone nonfirm point-to-point service (which has a

higher priority), (2) take this service on

a firm point-to-point basis, or (3) take

network service, which has a higher

priority for economy purchases than

either stand-alone non-firm or

secondary non-firm point-to-point

service.

With respect to LEPA’s argument, the

Commission has the goal of encouraging

competition in the generation market,

not discouraging generation competition

by erecting barriers to entry such as

arbitrary generator size. Furthermore,

LEPA’s argument that comparability is

not achieved without allowing

headroom is incorrect because both

network customers as well as the

transmission provider must obtain

point-to-point transmission service to

accommodate transmission for

wholesale sales.

c. Load Ratio Sharing Allocation

Mechanism for Network Service

In the Final Rule, the Commission

concluded that the load ratio allocation

method of pricing network service

continues to be reasonable for purposes

of initiating open access

transmission.229 The Commission also

reaffirmed the use of a twelve monthly

coincident peak (12 CP) allocation

method because it believed the majority

of utilities plan their systems to meet

their twelve monthly peaks. However,

the Commission stated that it would

allow utilities to file another method

(e.g., annual system peak) if they

demonstrate that it reflects their

transmission system planning.

With respect to concerns raised about

pancaked rates for network service

provided to load served by more than

one network service provider, the

Commission indicated that if a customer

wishes to exclude a particular load at

discrete points of delivery from its load

ratio share of the allocated cost of the

transmission provider’s integrated

system, it may do so. However,

customers that elect to do so, the

Commission explained, must seek

alternative transmission service for any

such load that has not been designated

as network load for network service.

The Commission indicated that this

option is also available to customers

with load served by ‘‘behind the meter’’

generation 230 that seek to eliminate the

load from their network load ratio

calculation.

(1) Multiple Control Area Network

Customers

Rehearing Requests

A number of entities argue that

excluding load from the designation of

Network Load does not solve the

pancaking problem and results in the

network customer paying even more

transmission charges. They contend that

a network customer must still pay two

network charges and point-to-point

charges to be able to operate its

resources across two control areas. The

Commission’s approach, they argue,

makes it impossible for a network

customer with loads and resources in

multiple control areas to integrate those

loads and resources on an economic

dispatch basis.231 In essence, these

entities state that a network customer

must frequently dispatch resources in

one transmission provider’s control area

(control area A) to serve that customer’s

load (in the case of a G&T cooperative,

the load of a member system or thirdparty requirements customer) located in

an adjacent control area of another

transmission provider (control area B).

As a result, they believe, the tariff

essentially requires that network load in

control area B, served by resources in

control area A, must be counted as load

in control area B. Alternatively, they

believe that the tariff allows the

transmission of resources in control area

A to load in control area B as point-topoint transmission that requires an

additional charge. These entities argue

that either of these situations produces

uneconomic results for multiple controlarea network customers.

To avoid these problems, these

entities propose that a network

customer be allowed to use its network

service to transmit power and energy

from resources in control area A to serve

load in control area B without

designating the control area B load as

network load for billing purposes. These

entities suggest that no additional

compensation should be required if

such transfers to load in adjacent

control areas plus other network

transactions on behalf of the

transmission customer in control area A

do not exceed the customer’s coincident

demand in control area A. They also

maintain that the ultimate solution is a

regional system operated by an ISO. At

the very least, TDU Systems contends,

the Commission should require

provision of service to network

customers with loads and resources
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12321

232FERC Stats. & Regs. at 31,736; mimeo at 297.

233These entities do not explain how the

Commission could force non-public utility control

area operators, of which there are approximately 62

out of 138 in the United States (as of October 1996),

to accede to these pricing policies.

234E.g., Utilities For Improved Transition, Florida

Power Corp, VEPCO.

235FERC Stats. & Regs. at 31,736; mimeo at 296–

97.

236FERC Stats. & Regs. at 31,770; mimeo at 398–

99.

located on multiple systems under a rate

that recovers the customer’s load ratio

share—but no more—of the

transmission owners’ collective

transmission investment in the control

areas that the customer straddles.

AMP-Ohio maintains that rational

economic transmission pricing policies

demand elimination of the pancaking of

rates caused by the arbitrary ownership

boundaries of individual utilities.

TAPS asks that the Commission

clarify that the Commission will look

closely at how to create and promote

region-wide rates when evaluating

mergers and market-based rate

proposals. It argues that the Commission

should be receptive to section 211

filings seeking non-pancaked rates and

should establish a Stage 3 for the

purpose of addressing directly the need

for transmission access on a nonpancaked, regional basis.

Commission Conclusion

In the Final Rule, the Commission

addressed concerns regarding pancaked

rates for network service for customers

with load in multiple control areas.232

Tariff section 31.3 allows a network

customer the option to exclude all load

from its designated network load that is

outside the transmission provider’s

transmission system, and to serve such

load using point-to-point transmission

service.

NRECA and TDU Systems, however,

argue that network customers located in

multiple control areas should not have

to pay for any additional point-to-point

transmission service to make sales to

non-designated load located in a

separate control area. We disagree.

Because the additional transmission

service to non-designated network load

outside of the transmission provider’s

control area is a service for which the

transmission provider must separately

plan and operate its system beyond

what is required to provide service to

the customer’s designated network load,

it is appropriate to have an additional

charge associated with the additional

service.

AMP-Ohio’s concerns regarding

‘‘arbitrary ownership boundaries of

individual utilities,’’ and TAP’s

proposal to require regional rates are

beyond the scope of Order No. 888.233

However, as the Commission explained

in the Final Rule, it encourages the

voluntary formation of regional

transmission groups, as well as the

establishment of regional ISOs, and will

address those matters on a case-by-case

basis.

(2) Twelve Monthly Coincident Peak v.

Annual System Peak

Rehearing Requests

Several utilities ask that the

Commission eliminate the requirement

that charges for network service be

calculated using a 12-month rolling

average load ratio share and allow

utilities discretion to determine the way

network customers pay. 234 They assert

that the requirement makes it

impossible to recover the full cost of

service when customers begin or

terminate service. They suggest a unit

charge based on a formula rate that is

trued up each year or a month-by-month

load ratio share calculation.

NE Public Power District states that

the definition of load ratio share in

section 1.16 of the pro forma tariff,

taken together with sections 34.2 and

34.3 of the pro forma tariff require the

use of the 12–CP method and the

inclusion of losses to the generator bus.

This, it argues, is inconsistent with the

Commission’s statement that ‘‘[u]tilities

that plan their systems to meet an

annual system peak * * * are free to

file another method if they demonstrate

that it reflects their transmission system

planning.’’ (NE Public Power District at

22–23). NE Public Power District argues

that utilities should be allowed to use

CP demands measured at delivery

points at some common specified

voltage. It further asks the Commission

to clarify whether the monthly peak

includes or excludes transmission

losses.

EEI and AEP argue that transmission

reservations for services of less than one

month’s duration and any discounted

firm transactions should not be counted

in the load ratio calculation when

determining the 12 CP on point-to-point

rates, but that the revenues from these

services should be credited to all firm

transmission users.

Montana Power argues that the

Commission’s pricing approach

discriminates against native load

customers because all non-network uses

of the system do not occur at full, nondiscounted prices for the entire month

and the effects of discounts will be

shouldered by native load customers.

According to Montana Power, this is a

disincentive to utilities to offer

discounts and creates a possibility of

gaming by network customers buying

one day firm point-to-point reservations

to reduce their network load ratio

shares.

Commission Conclusion

While the Commission reaffirmed the

use of a twelve monthly coincident peak

(12 CP) allocation method for pricing

network service in the Final Rule, the

Commission also stated:

[u]tilities that plan their systems to meet an

annual system peak * * * are free to file

another method if they demonstrate that it

reflects their transmission system

planning.235

Accordingly, utilities are free to propose

in a section 205 filing an alternative to

the use of the 12-month rolling average

(e.g., annual system peak) in the load

ratio share calculation, subject to

demonstrating that such alternative is

consistent with the utility’s

transmission system planning and

would not result in overcollection of the

utility’s revenue requirement. Any

proposed alternative would also be

subject to any future filing conditions

established by the Commission.236

We also are not convinced that we

should require the calculation of load

ratios using a particular method on a

generic basis. Any such proposals,

including those concerning the

treatment of discounted firm

transmission transactions in the load

ratio calculation and revenue credits

associated with such transactions, are

best resolved on a fact-specific, case-bycase basis.

Finally, the Final Rule does not

prohibit utilities from ‘‘us[ing] CP

demands measured at delivery points at

some common specified voltage’’ as

claimed by NE Public Power District.

Treatment of transmission losses can be

accomplished in different ways by

different transmission providers under

the pro forma tariff, such as adjustment

to a consistently applied voltage level.

Regarding NE Public Power District’s

allegation that certain sections of the

pro forma tariff do not allow the use of

the annual system peak method in the

load ratio share calculation, the

Commission recognizes that certain rate

methodologies may require minor

adjustments to the non-price terms and

conditions to be consistent with the

proposed rate methodology. However,

any modifications to the non-price

terms and conditions established in the

pro forma tariff must be fully supported

by the utility and the appropriateness of

such proposed changes will be

evaluated by the Commission for
12322 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

237E.g., AMP-Ohio, TAPS.

238See FERC Stats. & Regs. at 31,736 and 31,743;

mimeo at 297 and 317.

239E.g., TAPS, Central Minnesota Municipal.

240Utilities For Improved Transition argues that

a transmission dependent utility should be required

to serve its load using only network transmission

service. It asserts that such a utility should not be

allowed to avoid its full cost responsibility by using

point-to-point firm during peak periods and nonfirm service during non-peak periods. See also

VEPCO.

Moreover, FMPA filed an answer in opposition to

the requests for clarification of FP&L, Carolina P&L

and others concerning the definition of network

load and related issues. (FMPA Answer). Likewise,

Michigan Systems and TAPS filed answers

opposing these requests for rehearing. (Michigan

Systems Answer and TAPS Answer). While

answers to requests for rehearing generally are not

permitted, we will depart from our general rule

because of the significant nature of this proceeding

and accept the FMPA Answer, Michigan Systems

Answer and TAPS Answer.

241FERC Stats. & Regs. at 31,736; mimeo at 297.

consistency with the proposed rates or

rate methodologies. The remainder of

NE Public Power District’s concerns are

case-specific and should be raised by

NE Public Power District at such time as

a transmission provider makes a filing.

(3) Load and Generation ‘‘Behind the

Meter’’

Rehearing Requests

Several entities request

clarification 237 concerning the

definition of Network Load in pro forma

tariff section 1.22, which provides, in

pertinent part, that:

A Network Customer may elect to

designate less than its total load as Network

Load but may not designate only part of the

load at a discrete Point of Delivery.

These entities maintain that section

1.22 is too restrictive and is inconsistent

with the Final Rule’s treatment of load

served from ‘‘behind the meter’’

generation.238 Specifically, these

entities request that the Commission

clarify that a network customer can

exclude from its designated network

load a portion of load at a discrete point

of delivery, which is served from

generation behind the meter. In support

of this position, a number of petitioners

cite to FMPA v. FPL, 74 FERC ¶ 61,006

at 61,012–13, in which they claim the

Commission allowed network customers

to exclude load served by behind the

meter generation.239

TAPS asserts that there is no

operational or economic reason to

require the designation of all load at a

discrete point of delivery as network

load.

FMPA argues that network customers

should not be charged a network rate to

use their own transmission (or

distribution) system to serve loads that

are located beyond the transmission

owner’s system. FMPA interprets the

Final Rule on this issue as allowing a

network customer that has behind-themeter generation to serve part of its

behind the meter load from such

generation; thus, a customer can

exclude that load, which is served

without using the transmission

provider’s transmission system, from

the load ratio share. FMPA’s

interpretation of section 1.22 is that ‘‘a

network customer may not import

power using both point-to-point and

network transmission service at the

same delivery point, but that this

Section does not prevent a network

customer from serving load from

generation when both are behind the

delivery point and when the transaction

does not rely upon use of the

transmission provider’s transmission

system.’’ (FMPA at 5). FMPA requests

that the Commission clarify the

language in section 1.22 consistent with

its interpretation above.

Michigan Systems asks the

Commission to modify section 1.22

because the ‘‘clause may be interpreted

to require network integration

transmission service customers to pay a

second time for the transmission of

power that is already being transmitted

under other arrangements, such as

transmission ownership. The clause

could also be interpreted to allow the

transmission provider to charge

customers for the transmission of power

which does not use the transmitter’s

system, such as for transmission from

’behind the meter’ generation to ’behind

the meter’ load.’’ (Michigan Systems at

5–13).

Wisconsin Municipals ask the

Commission to ‘‘clarify that a partial

designation is appropriate if (1) only

part of the load behind a particular

delivery point relies upon the

transmission provider’s transmission

system for service or (2) a network

customer is responsible for serving only

a portion of the load behind a discrete

delivery point.’’ (Wisconsin Municipals

at 17–18).

Blue Ridge asks the Commission to

clarify that it intended to allow for

multiple ownership of resources by

customers who are not network

customers.

Utility Position

FPL and Carolina P&L ask the

Commission to clarify that section 1.22

and the Rule (see also Original Sheet

No. 94 and FMPA I, 67 FERC ¶ 61,167

at 61,481–82 (1994)) mean that

regardless of whether or not a customer

has behind the meter or local generation

at a delivery point, if a customer wants

to purchase network service to serve

load at a delivery point, it must

purchase network service for all such

load—the customer cannot split the load

into network and point-to-point

components at a specific point of

delivery.240 Otherwise, FPL states, there

would be a split system with the

potential to game the system and

problems with how it would work.

AEP argues that the option in section

1.22 of excluding load from network

load should be deleted. AEP states that,

as the Commission recognized in its

original FMPA v. FPL order, the

provision is contrary to the

comparability standard. Specifically,

AEP argues that transmission-owning

utilities do not and cannot offer

themselves partial integration service

electing to pay only a portion of the

network costs, but rather must pay for

the entire network, which integrates all

of the transmission-owning utility’s

resources and loads. According to AEP,

the load served by behind-the-meter

generation is not isolated from the

system, which is there to serve that load

when the behind-the-meter generation is

unavailable. Allowing a network

customer to use short-term non-firm

point-to-point transmission, AEP

asserts, allows customers to evade a

large portion of the network’s costs,

which they will do on an unconstrained

system such as AEP.

Commission Conclusion

We disagree that the prohibition in

tariff section 1.22 against a network

customer designating only part of a load

at a discrete point of delivery as

network load is either inconsistent with

the Final Rule’s treatment of generation

‘‘behind the meter’’ or is contrary to the

Commission’s decisions in FMPA I and

FMPA II.

The Commission addressed ‘‘behind

the meter’’ generation in the Final Rule

as follows:

if a customer wishes to exclude a particular

load at discrete points of delivery from its

load ratio share of the allocated cost of the

transmission provider’s integrated system, it

may do so. [citing Florida Municipal Power

Agency v. Florida Power & Light Company,

74 FERC ¶ 61,006 (1996), reh’g pending.]

Customers that elect to do so, however, must

seek alternative transmission service for any

such load that has not been designated as

network load for network service. This

option is also available to customers with

load served by ’behind the meter’ generation

that seek to eliminate the load from their

network load ratio calculation.241

Implicit in the Commission’s discussion

of this issue in the Final Rule and also

in FMPA I and FMPA II, in permitting
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12323

242 FMPA II at 61,012 (emphasis added).

243 FMPA II at 61,011.

244The load-ratio cost responsibility is based on

the network customer’s monthly contribution to the

transmission system peak (i.e., coincident peak

billing).

245FMPA at 3–4.

246While this customer could lower its

coincident peak use of the transmission system, it

could be making substantial use of the transmission

system during all other hours of the month but yet

have little or no load-ratio cost responsibility.

247Customers taking network integration

transmission service choose to have the

transmission provider integrate their generation

resources with their loads. Network service is a

service comparable to the service that the

transmission provider provides to its retail native

load, where the Transmission Provider includes the

network customers resources and loads (projected

over a minimum ten-year period) into its long-term

planning horizon. Because network service is usage

based, network customers pay on the basis of their

total load, paying a load-ratio share of the costs of

the transmission provider’s transmission system on

an ongoing basis. In contrast, point-to-point

transmission service is more transitory in nature.

Point-to-point service is frequently tailored for

discrete transactions for various time periods,

which may or may not enter into the transmission

provider’s planning horizon. A point-to-point

transmission service customer is only responsible

for paying for its reserved capacity on a contract

demand basis over the contract term.

the ‘‘exclusion of a particular load,’’ is

that the Commission will allow a

network customer to exclude the

entirety of a discrete load from network

load, but not just a portion of the load

served by generation behind the meter.

In its request for rehearing of FMPA

I, FMPA requested that the Commission

confirm its interpretation of the

Commission’s finding in FMPA I that:

[FMPA] can choose to serve an amount of

load in a city from generation in the city, so

long as FMPA does not sometimes serve that

level of load from external generation or use

that generation to serve member loads

outside the city.242

On rehearing in FMPA II, the

Commission did not grant FMPA’s

request to allow a partial designation of

network load. Furthermore, the

Commission provided an example of

how FMPA could request that certain of

its loads and resources be excluded

from network integration transmission

service. The Commission explained that

FMPA could choose to exclude the

loads of the cities of Ft. Pierce and Vero

Beach from the request for network

integrated transmission service and

alternatively request point-to-point

transmission service to transmit power

from resources in those cities to other

FMPA members or from FMPA member

cities to Ft. Pierce and Vero Beach.243

The Commission neither stated that it

would allow a partial designation of a

discrete load as network load nor

provided any examples of such

treatment.

Additionally, throughout the pro

forma tariff, network customers are

consistently prohibited from designating

only a portion of a discrete network

load. For example, tariff section 31.2

provides:

To the extent that the Network Customer

desires to obtain transmission service for a

load outside the Transmission Provider’s

Transmission System, the Network Customer

shall have the option of (1) electing to

include the entire load as Network Load for

all purposes under Part III of the Tariff and

designating Network Resources in connection

with such additional Network Load, or (2)

excluding that entire load from its Network

Load and purchasing Point-To-Point

Transmission Service under Part II of the

Tariff. [Emphasis added]

Accordingly, we find that no

inconsistency exists between the tariff

language and either the language in the

Final Rule or the Commission’s findings

in FMPA I or FMPA II.

In support of its position to allow a

partial designation of network load at a

point of delivery, TAPS claims that

there are no operational reasons to

require the designation of all load at a

discrete point of delivery as network

load. We disagree. Utilities, both

commenting on the NOPR and on

rehearing (e.g., AEP rehearing at 19–20

and Florida Power & Light at 14–18),

express concern that customers allowed

to divide a discrete load between pointto-point and network services would

create a ‘‘split system.’’ The concept of

allowing a ‘‘split system’’ or splitting a

discrete load is antithetical to the

concept of network service. A request

for network service is a request for the

integration of a customer’s resources

and loads. Quite simply, a load at a

discrete point of delivery cannot be

partially integrated—it is either fully

integrated or not integrated.

Furthermore, such a split system creates

the potential for a customer to ‘‘game

the system’’ thereby evading some or all

of its load-ratio cost responsibility for

network services.244

For example, FMPA asserts that if a

FMPA member city has a peak load of

100 MW and behind the meter

generation of 75 MW, FMPA should be

allowed to designate a portion of its

load as network load (e.g., 60 MW), and

to serve the remaining load (e.g., 40

MW) from its behind-the-meter

generation.245 However, as a number of

utilities note, this would lead to the

possibility of gaming the system. For

example, if at the time of the monthly

system peak the FMPA member city

generates more than 40 MW (or takes

short-term firm transmission service (or

a combination of the two)), it may be

able to lower its monthly coincident

peak load for network billing

purposes,246 and thereby reducing if not

eliminating its load-ratio cost

responsibility for network service.

Because network and native load

customers bear any residual system

costs on a load-ratio basis, any cost

responsibility evaded by a network

customer in this manner would be borne

by the remaining network customers

and native load.

FPL also raises several fundamental

operational problems associated with

allowing partial network service or

creating a ‘‘split system:’’

If all the loads are included in a single

control area, how does the transmission

provider know what portion of the power

delivered is serving the point-to-point load

(which presumably would not be counted

toward the network’s load ratio)?

Using the same 100 MW load example

previously mentioned where there is a 40/60

network/point-to-point split, there would

have to be a determination of how the split

would be done in non-peak situations. Are

the first 40 MW of load all network load, or

all point-to-point load, or split on a 40/60

basis?

If the system purchases economy power

from non-local resources, how is that

delivery allocated between the network

portion (for which there would be no pointto-point scheduling, curtailment, or

transmission charges) and the point-to-point

portion (which must be arranged and paid for

separately under a point-to-point tariff)?

The bottom line is that all potential

transmission customers, including those

with generation behind the meter, must

choose between network integration

transmission service or point-to-point

transmission service. Each of these

services has its own advantages and

risks.247

In choosing between network and

point-to-point transmission services, the

potential customer must assess the

degree of risk that it is willing to accept

associated with the availability of firm

transmission capacity. Customers

choosing point-to-point service, based

solely on the amount of transmission

capacity reserved (or contract demand),

may face a relatively higher risk

associated with the availability of firm

transmission capacity. For example, if a

customer with a peak load of 100 MW,

and behind the meter generation of 75

MW, chooses to serve a portion of its

load with point-to-point transmission

service (e.g., 60 MW) and the remaining

load (e.g., 40 MW) with its behind-themeter generation, this customer faces

the risk that, should its generation

behind the meter become unavailable,

the transmission provider may not have

firm transmission capacity available to

serve the remaining 40 MW of that
12324 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

248We also clarify that while the tariff prohibits

the designation of only part of the load at a discrete

point of delivery, this prohibition also applies to

network customers with a discrete load served by

multiple points of delivery. In other words, for the

same reasons explained above, a customer may not

choose to have part of a discrete load served under

network integration service at one or more delivery

points and at the same time have the remaining

portion of the same load served under point-topoint transmission service at other delivery points.

249An example of excluding the entirety of a

discrete load would be a municipal power agency

excluding the entire load of a member city with

generation behind the meter, while requesting

network service to serve the remaining member

cities’ loads. The excluded load of the member city

must be met using a combination of generation

behind the meter and any remote generation that

may be necessary. The member city would be

responsible for arranging any point-to-point

transmission service under the pro forma tariff that

may be necessary to import the power and energy

from any remote generation.

250E.g., NRECA, TDU Systems, AEC & SMEPA. 251NRECA at 78–79; TDU Systems at 32.

252 Clearly, any such modification of existing contracts would required

the agreement of all parties and a filing with the Commission.

customer’s load. One way to minimize

this risk would be for the customer to

reserve and pay for additional firm

point-to-point transmission service to

protect against the unavailability of its

behind-the-meter generation.

Alternatively, the customer could

choose network service in which the

transmission provider will plan and

provide for firm transmission capacity

sufficient to meet the customer’s current

and projected peak loads, including

integration of the customer’s behindthe-meter generation as a network

resource.

For the reasons stated above, a

network customer will not be permitted

to take a combination of both network

and point-to-point transmission services

under the pro forma tariff to serve the

same discrete load. Accordingly, the

requests for rehearing to modify tariff

section 1.22 are hereby rejected.

Moreover, the Commission will allow

a network customer to either designate

all of a discrete load 248 as network load

under the network integration

transmission service or to exclude the

entirety of a discrete load from network

service and serve such load with the

customer’s ‘‘behind-the-meter’’

generation and/or through any point-topoint transmission service.249

(4) Existing Transmission Arrangements

associated with Generating Capacity

Entitlements (e.g., ‘‘preference power’’

customers of PMAs)

Rehearing Requests

Several entities argue that section 1.22

of the pro forma tariff is arbitrary and

cannot be reconciled with the Final

Rule’s determination not to abrogate

existing agreements. 250

Specifically, several transmission

customers claim that the prohibition

against designating only part of the load

at a discrete point of delivery is

problematic for customers with existing

transmission arrangements for receiving

preference power or capacity

entitlements from power marketing

agencies (PMAs). For example, Central

Minnesota Municipal argues that the

limiting language of section 1.22 should

be eliminated as it would preclude

Mountain Lake (a member of Central

Minnesota Municipal) from using

network transmission and, at the same

time, point-to-point transmission for

WAPA power under a separate

arrangement. These transmission

customers assert that if they designate

all of the load at a discrete point of

delivery as network load, and pay for

such network load on a load-ratio basis,

then the transmission provider is paid

twice for the same transmission

service—once through the existing

transmission arrangement and a second

time through the network service.

NRECA and TDU Systems argue that

if a customer chooses to use network

service under the pro forma tariff to

supplement its existing arrangements to

meet future full requirements, the

Commission should amend section 1.22

so the transmission provider cannot

overcharge the customer:

A Network Customer may elect to

designate less than its total load as Network

Load. Where a Network Customer has elected

not to designate a particular load as a

Network Load, the Network Customer is

responsible for making separate arrangements

under Part II of the Tariff for any Point-toPoint Transmission Service that may be

necessary for such non-designated load,

unless such non-designated load is served

pursuant to other arrangements. [251]

Alternatively, the transmission

customer may choose not to designate

any load at a discrete point of delivery

as network load. However, these

transmission customers note that the

preference power allotments received

from PMAs typically do not equal the

total load of a customer at a discrete

point of delivery. Therefore, the

customer would need to acquire

additional point-to-point transmission

service for any remaining transmission

needs. Accordingly, these transmission

customers conclude that the existence of

their current transmission arrangements

precludes them from receiving network

service which they claim does not allow

the comparable use of the system that

the transmission provider enjoys.

Commission Conclusion

The Commission recognizes that

existing power and transmission

arrangements represent a transitional

problem as customers begin to take

service under the pro forma tariff.

Clearly, the Commission did not intend

for a transmission provider to receive

two payments for providing service to

the same portion of a transmission

customer’s load. Any such double

recovery is unacceptable and

inconsistent with cost causation

principles. Neither did the Commission

intend to allow a transmission customer

to designate less than its total load as

network load at a discrete point of

delivery even though a portion of that

load is served under a pre-existing

contract. We clarify that such a

transmission customer has several

alternatives it can pursue using either

point-to-point or network transmission

service.

Using network transmission service,

the network customer would designate

its existing generation supply contract(s)

as a network resource(s) and the

associated load served under such

contract(s) designated as network load.

The network customer then has two

options: pursue negotiations with the

transmission provider to obtain a credit

on its network service bill for any

separate transmission arrangements or

for the unbundled transmission rate

component of the existing generation

supply contract or (2) seek to have any

separate transmission or the unbundled

transmission rate component of its

generation supply contract eliminated

in recognition of the network

transmission service now being

provided and paid for under the

tariff.252

Using point-to-point transmission

service, the transmission customer

would identify the discrete points of

delivery being served under existing

generation supply and existing

transmission contracts and acquire

additional point-to-point transmission

service under the tariff for any

remaining load at those discrete points

of delivery.

Any of these three alternatives should

address concerns regarding the

possibility of double recovery.

Furthermore, a transmission customer

may file a complaint under section 206

with the Commission to address any

claims of double recovery that it is

unable to resolve with the transmission

provider.

d. Annual System Peak Pricing for

Flexible Point-to-Point Service

In the Final Rule, the Commission

indicated that it will allow a

transmission provider to propose a

formula rate that assigns costs
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12325

253FERC Stats. & Regs. at 31,737–38; mimeo at

301–04.

254FERC Stats. & Regs. ¶ 31,005 (1994).

255See also NE Public Power District.

256FERC Stats. & Regs. at 31,736; mimeo at 296–

97.

257FERC Stats. & Regs. at 31,738; mimeo at 303.

258Northeast Utilities Service Company

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

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

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

and dismissing request for rehearing, 59 FERC

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

remanded in part, Northeast Utilities Service

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

Pennsylvania Electric Company (Penelec), 58 FERC

¶ 61,278 at 62,871–75, reh’g denied, 60 FERC

¶ 61,034 (1992), aff’d, Pennsylvania Electric

Company v. FERC, 11 F.3d 207 (D.C. Cir. 1993).

consistently to firm point-to-point and

network services.253 The Commission

added that it will no longer summarily

reject a firm point-to-point transmission

rate developed by using the average of

the 12 monthly system peaks.

The Commission explained that it still

believed that it was appropriate for

utilities to use a customer-specific

allocated cost of service to account for

diversity, but based on the changed

circumstances since Southern Company

Services, Inc., 61 FERC ¶ 61,339 (1992)

(Southern), it indicated that it would

now permit an alternative. Thus, the

Commission indicated that it will allow

all firm transmission rates, including

those for flexible point-to-point service,

to be based on adjusted system monthly

peak loads.

In order to prevent over-recovery of

costs for those who use this approach,

the Commission explained that it will

require transmission providers to

include firm point-to-point capacity

reservations in the derivation of their

load ratio calculations for billings under

network service. In addition, the

Commission explained that revenue

from non-firm transmission services

should continue to be reflected as a

revenue credit in the derivation of firm

transmission tariff rates. The

Commission noted that the combination

of allocating costs to firm point-to-point

service and the use of a revenue credit

for non-firm transmission service will

satisfy the requirements of a conforming

rate proposal enunciated in our

Transmission Pricing Policy

Statement.254

Rehearing Requests

Blue Ridge maintains:

The sea change in the Commission’s

approach to the pricing of transmission

services is not warranted by any claimed

change in circumstances and Blue Ridge

accordingly requests rehearing and rejection

of the new approach. At a minimum, the

Commission should clarify that any deviation

from use of an annual peak divisor (or other

methodology based on system capability) for

setting point-to-point transmission rates will

be considered only on a case-by-case basis.

TAPS also argues that the use of the

same denominator for two different

services is inconsistent, unjust and

discriminatory. It asserts that the

Commission should use a system

capability divisor for allocating fixed

costs between reservation-based and

load-based firm service.

TAPS also asserts that most utilities

plan their transmission systems to cover

the annual system peak estimated

conservatively on the higher side in

order to meet unusually high loads

reliably, rather than planning on the

basis of the twelve monthly peaks as

stated in Order No. 888. Therefore,

TAPS asks that the Commission

maintain 1 CP pricing for point-to-point

service. TAPS argues that the

Commission should allow transmission

providers and customers to demonstrate

the appropriate measure for each

transmission system’s capability in

utility-specific proceedings.

If the Commission uses a 12 CP

denominator, TAPS requests that the

Commission clarify that capacity

reservations should be established

consistently with that denominator and

should recognize the inappropriateness

of using such rates as a cap for non-firm

rates. It asserts that non-firm rates

should be limited to actual variable

costs of transmission, plus losses, plus

a modest adder as a contribution toward

fixed costs. At the very least, TAPS

argues that the cap should be developed

using a more appropriate denominator,

e.g., system capability.

TAPS further argues that if the rate

divisor is based on experienced 12 CP,

the capacity reservations and the divisor

should be measured at the delivery

points (as it is for native load

customers), not the higher of the receipt

or delivery points, to avoid a mismatch

between the rate divisor and billing

determinants.255

Wisconsin Municipals and TAPS

argue that if a 12 CP divisor is used,

customers must have the flexibility to

vary their monthly nomination under

the point-to-point tariff.

Commission Conclusion

With respect to TAPS argument that

the annual system peak method would

be appropriate for most systems, the

Commission has determined in Order

No. 888 that this issue is best resolved

on a case-by-case basis and specifically

provided utilities the opportunity to

propose to use other allocation methods,

including the annual system peak

method sought by TAPS.256

The Commission already recognized

the potential for a mismatch between

the rate divisor and billing determinants

that TAPS now raises on rehearing. We

explicitly stated in the Final Rule that

[t]he adjusted system monthly peak loads

consist of the transmission provider’s total

monthly firm peak load minus the monthly

coincident peaks associated with all firm

point-to-point service customers plus the

monthly contract demand reservations for all

firm point-to-point service.[257]

Use of the adjusted system monthly

peak loads in the rate divisor for flexible

point-to-point transmission service

eliminates the mismatch concern raised

by TAPS.

We have also fully addressed in the

Final Rule those arguments objecting to

the use of the average of the 12 monthly

peaks in determining a firm point-topoint transmission rate and no further

discussion is required. The other

arguments raised with respect to this

section are fact specific and best

addressed in individual rate

proceedings where the use of an annual

system peak versus an average of the 12

monthly peaks in determining a firm

point-to-point transmission rate is more

appropriately evaluated.

e. Opportunity Cost Pricing

(1) Recovery of Opportunity Costs

The Commission emphasized in the

Final Rule that it had fully explained its

rationale for allowing utilities to charge

opportunity costs in Northeast Utilities

and Penelec.258 The Commission also

explained that transmission providers

proposing to recover opportunity costs

must adhere to the following

requirements:

(1) A fully developed formula

describing the derivation of opportunity

costs must be attached as an appendix

to their proposed tariff;

(2) Proposals must address how they

will be consistent with comparability;

and

(3) All information necessary to

calculate and verify opportunity costs

must be made available to the

transmission customer.

Rehearing Requests

VT DPS disputes the Commission’s

holding with respect to opportunity

costs and argues that rate filings seeking

recovery of opportunity costs should be

summarily rejected. It asserts that,

contrary to statements by the

Commission, courts have not endorsed

opportunity cost pricing for

transmission customers and maintains

that the Commission’s failure to

consider objections to opportunity cost
12326 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

259The Commission has effectively achieved this

result for opportunity sales by requiring separation

of the transmission provider’s wholesale merchant

from its transmission operation employees.

260These arguments include those made by VT

DPS concerning Northeast Utilities and alleged

inconsistencies with our natural gas policies.

261Under the Commission’s transmission pricing

policy, utilities are limited to charging the higher

of embedded costs or opportunity/incremental

costs. See Order on Reconsideration and Clarifying

Policy Statement, 71 FERC ¶ 61,195 (1995).

Opportunity costs are capped by incremental

expansion costs. Opportunity costs are viewed as a

form of incremental or marginal cost pricing and

include: (1) out-of-rate costs or costs associated

with the uneconomic dispatch of generating units

necessary to accommodate a transaction; and (2)

costs that arise from a utility having to reduce its

off-system purchases or sales in order to avoid a

potential constraint on the transmission grid. We

note that Order No. 888 requires that off-system

sales by the transmission provider must be made

under the point-to-point provisions of the pro forma

tariff.

If a utility expands its transmission system so that

it can provide the requested transmission service,

it can charge the higher of its embedded costs or

its incremental expansion costs. When a

transmission grid is constrained and a utility does

not expand its system, the Commission has allowed

a utility to charge transmission-only customers the

higher of embedded costs or legitimate and

verifiable opportunity costs (‘‘or’’ pricing), but not

the sum of the two (‘‘and’’ pricing).

pricing on the merits ‘‘directly flouts the

court’s ruling’’ in Northeast Utilities.

According to VT DPS, opportunity costs

are inherently unverifiable: ‘‘there are

insuperable difficulties in proving the

existence of lost opportunity costs in

any fashion which can readily and

objectively be applied.’’ At a minimum,

VT DPS asserts, opportunity costs

arising more than five years out are

unverifiable and should not be

permitted. Moreover, VT DPS argues

that the right to challenge the

verifiability of opportunity costs is not

adequate protection because it is

wasteful and burdensome (citing Cajun

Electric Power Cooperative v. FERC, 28

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

VT DPS also asserts that the

Commission’s treatment is inconsistent

with its treatment of gas pipeline

pricing policies, which do not permit

the assessment of opportunity costs in

gas pipeline transportation rates. In

addition, VT DPS asserts that

opportunity cost pricing for firm

transportation service would allow the

transmitting utility to charge more for

firm transmission of a third party’s

power supplies than it charges its own

native load for the transmission

component of native load service.

Finally, VT DPS claims that opportunity

cost pricing contravenes Cajun because

opportunity cost pricing has a chilling

effect on competition in New England

and nationally. VT DPS challenges

whether a tariff provision that permits

the imposition of opportunity costs

‘‘precludes the mitigation of [a utility’s]

market power.’’

CCEM asserts that there is no

justification for allowing opportunity

cost charges when such charges can be

eliminated in the secondary or released

capacity market, without the

discriminatory charge. It notes that

opportunity costs are not allowed in any

other industry and the Commission

should not allow recovery of lost profits.

American Forest & Paper argues that

the only way to ensure comparability is

to require that transmission services are

priced for all customers based upon

embedded cost principles (including

pricing for expansions). It opposes

opportunity cost pricing as being

discriminatory because wheeling

customers are required to compensate

the transmitting utility for its lost

opportunities to make economy

purchases or sales to benefit native load.

It further argues that transmission

capacity was not designed to facilitate

non-firm, unplanned economy

purchases or sales on behalf of native

load. American Forest & Paper also

asserts that allowing redispatch costs

incorrectly presupposes that native load

has a superior right to the transmission

system. According to American Forest &

Paper, neither of these costs

(opportunity/redispatch) should be

imposed on the former sales, now

transmission-only, customers—the

transmission customer is no more

responsible for the alleged transmission

constraint than the existing native load

customer who adds to its requirements

or the new customer locating in the

service territory. It maintains that firm

transmission contracts cannot by

definition displace opportunity sales

because there is no ‘‘opportunity’’ until

there is capacity in excess of the firm

transmission contractual commitments.

In addition, American Forest & Paper

asserts that opportunity cost pricing

may create difficulties for IPPs, i.e., a

lender may not finance projects because

of cost uncertainty related to varying

revenue flows caused by opportunity

cost pricing. It believes that utilities

should be required to establish a

separate subsidiary to make opportunity

purchases or sales on its behalf, which

may minimize self dealing.259 It further

asserts that expansions should be

subject to embedded cost pricing—

unlike in gas pipeline expansions,

electric transmission expansions

invariably affect an integrated network.

CCEM asserts that, if opportunity cost

pricing is maintained, transmission

customers should be given the

information they need to avert or

mitigate opportunity-cost exposure. In

particular, it argues that customers need

information on the run status and cost

of generating units that the transmission

provider controls in advance of any

proposed redispatch. In addition, CCEM

argues that transmission providers

should be required to inform customers

of a redispatch in advance.

Commission Conclusion

As an initial matter, many of the

arguments raised are collateral attacks

on Penelec, Northeast Utilities, and the

Commission’s Transmission Pricing

Policy Statement. These matters are not

the subject of this proceeding, but rather

Order No. 888 simply applies the policy

already in place. Therefore, these

arguments are not properly raised in

this proceeding.260

The Commission does not believe that

any changes are necessary to its policy

on opportunity cost recovery.261 In the

Final Rule, we fully explained our

rationale for allowing utilities to charge

opportunity costs and no arguments

have been presented on rehearing that

would persuade us otherwise.

As has been our policy, we will

continue to determine the

appropriateness of opportunity cost

pricing proposals on a case-by-case

basis. We continue to believe that

opportunity cost pricing will promote

efficient decision-making by both

transmission owners and users and will

not result in unduly discriminatory or

anticompetitive pricing. We have stated

that because any transmission pricing

proposal must meet the comparability

standard, we will have ample

opportunity to address any concerns

that opportunity cost pricing may be

unfair and anticompetitive or otherwise

inconsistent with the comparability

standard, including those concerns

raised by CCEM with respect to the need

for advance information as to any

proposed redispatch.

We note that in compliance filings

made pursuant to Order No. 888, most

utilities did not make the tariff changes

necessary to charge opportunity costs to

customers under the pro forma tariff.

Absent a subsequent section 205 filing,

these transmission providers will not be

able to charge opportunity costs under

their compliance tariffs. Where

transmission providers did modify their

tariff to allow for opportunity costs, the

Commission is reviewing the proposed

charges on a case-by-case basis.

(2) Redispatch Costs

In the Final Rule, the Commission

clarified that redispatch is required only

if it can be achieved while maintaining
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12327

262FERC Stats. & Regs. at 31,739–40; mimeo at

307–09.

263FERC Stats. & Regs. at 31,740; mimeo at 309.

264E.g., Utilities For Improved Transition, Florida

Power Corp, VEPCO.

265FERC Stats. & Regs. at 31,739; mimeo at 307–

08.

266FERC Stats. & Regs. at 31,767; mimeo at 388.

267FERC Stats. & Regs. at 31,741; mimeo at 312–

13.

reliable operation of the transmission

system in accordance with prudent

utility practice.262

The Commission further explained

that the recovery of redispatch costs

requires that: (1) a formal redispatch

protocol be developed and made

available to all customers; and (2) all

information necessary to calculate

redispatch costs be made available to

the customer for audit. The Commission

also noted that the rates proposed must

meet the standards for conforming

proposals in the Transmission Pricing

Policy Statement.

The Commission also explained in the

Final Rule that if the transmission

provider proposes to separately collect

redispatch costs on a direct assignment

basis from a specific transmission

customer, the transmission provider

must credit these revenues to the cost of

fuel and purchased power expense

included in its wholesale fuel

adjustment clause.263

Rehearing Requests

TAPS asserts that there is too much

uncertainty with respect to the

treatment of redispatch costs. It asserts

that the Commission should require a

section 205 filing for each corridor/

constraint for which redispatch costs are

intended to be shared among the

transmission provider and network

customers. Once there has been a

determination regarding a particular

corridor/constraint, TAPS argues that

‘‘it would be appropriate to charge

network customers for redispatch costs

through a mechanism with no fewer

protections than a fuel clause.’’ It

further argues that redispatch costs, like

opportunity costs, should be capped at

the cost of the upgrade and, at the least,

the Commission should clarify that

application of the redispatch sharing

provision should be adjudicated in

particular cases.

TDU Systems states that it does not

object to a redispatch obligation that is

necessary to ensure transmission system

reliability, but they object to the fact

that a transmission provider can

determine that a transmission constraint

will arise as a result of the sale of

additional firm transmission service by

the transmission provider. It asks the

Commission to clarify that the

transmission constraint that would

trigger a redispatch obligation cannot be

caused by a transmission provider’s sale

of additional firm transmission

capability.

Wisconsin Municipals asks the

Commission to clarify that recovery of

redispatch costs on a load ratio basis,

without a section 205 filing, is limited

to when such action is necessary for

reliability reasons alone (not for

economic reasons), and that in all other

circumstances a section 205 filing must

be made and costs directly assigned to

the customer receiving the economic

benefit of the redispatch. It further

asserts that if redispatch is allowed for

economic reasons, it must be offered on

a comparable, non-discriminatory basis

to all customers and the transmission

provider, provided the beneficiary

agrees to accept a direct assignment.

Several utilities argue that redispatch

costs are a subset of opportunity costs

and that the Commission should not use

both terms in the tariff because it

implies different standards apply to

transmission providers and their

customers (e.g., sections 23.1 and 27).264

They request that the Commission only

use the term ‘‘redispatch costs’’ in the

pro forma tariff and impose the same

redispatch obligations on network

customers as are imposed on

transmission providers.

No rehearing requests addressed the

subject of fuel adjustment clause

treatment for redispatch costs.

Commission Conclusion

The Commission believes that the

obligation to create additional

transmission capacity to accommodate a

request for firm transmission service

should properly lie with the

transmission provider, not a network

customer.

The Commission clearly established

in the Final Rule that utilities are to be

given ‘‘substantial flexibility * * * to

propose appropriate pricing terms,

including opportunity cost pricing [of

which redispatch costs are a subset], in

their compliance tariff.’’ 265 The

Commission further required that any

such rate proposals must meet the

standards for conforming proposals in

the Transmission Pricing Policy

Statement. Accordingly, TAPS is free to

pursue its concerns in any relevant

compliance filings.

Tariff sections 33.2 and 33.3 clearly

establish that redispatch of all Network

Resources and the transmission

provider’s own resources are only to be

performed to maintain the reliability of

the transmission system, not for

economic reasons. Such costs are to be

shared between network customers and

the transmission provider on a load

ratio basis. Similarly, the Commission

clarified in Order No. 888, in modifying

the transmission customer’s redispatch

obligation, that such change was ‘‘to

limit the redispatch obligation to

reliability reasons.’’ 266 Therefore, no

further clarification is necessary.

Other redispatching provisions under

the tariff (e.g., sections 13.5 and 27)

refer to situations where the

transmission provider can relieve a

system constraint more economically by

redispatching the transmission

provider’s resources than through

constructing Network Upgrades in order

to provide the requested transmission

service. However, in this circumstance,

redispatch is conditioned upon the

eligible customer agreeing to

compensate the transmission provider

for such redispatch costs. Section 13.5

of the pro forma tariff further requires

that any such redispatch costs to be

charged to the transmission customer on

an incremental basis must be specified

in the customer’s service agreement

prior to initiating service. These tariff

requirements would appear to satisfy

Wisconsin Municipals concerns because

a section 205 filing must be made to

directly assign costs to the customer

receiving the economic benefit of the

redispatch.

Regarding the argument that only the

term ‘‘redispatch costs’’ should be used

in the pro forma tariff, we note that the

Commission followed this suggestion in

drafting the pro forma tariff. The only

exception is the use of opportunity costs

in section 23.1 of the tariff, which caps

the compensation for resellers at the

higher of: (1) the original rate, (2) the

transmission provider’s maximum rate

on file at the time of the assignment or

(3) the reseller’s opportunity cost. We

further note that their concerns that

different standards may be applied to

transmission providers than to their

customers are addressed in section

IV.C.6 (Capacity Reassignment).

f. Expansion Costs

In the Final Rule, the Commission

allowed transmission providers to

propose any method of collecting

expansion costs that is consistent with

the Commission’s transmission pricing

policy.267 The Commission explained

that ‘‘or’’ pricing sends the proper price

signal to customers and promotes

efficiency and further indicated that

‘‘and’’ pricing will not be allowed.

The Commission also indicated that

any request to recover future expansion
12328 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

268E.g., Utilities For Improved Transition, Florida

Power Corp, VEPCO.

269FERC Stats. & Regs. at 31,742–43; mimeo at

316–18.

270Florida Municipal Power Agency v. Florida

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

reh’g pending. 271E.g., NRECA, Blue Ridge, TDU Systems.

costs will require a separate section 205

filing.

Rehearing Requests

Several entities argue that requiring

section 205 filings for all transmission

expansion costs would impose difficult

burdens on transmission providers that

use formula rates because they would

have to try to distinguish between

replacement costs, which are included

in formula rates, and expansion costs,

which are not.268 They assert that

section 205 filings should be required

only for system expansion costs that the

transmission provider proposes to

recover on a direct assignment or

incremental cost basis, but not for costs

to be recovered on an embedded cost

basis.

TDU Systems maintain that to the

extent Order No. 888’s provisions

concerning direct assignment of

transmission facilities indicate a change

in the historic policy of rolling

transmission investments into rate base,

there is a risk TDUs will bear a

disproportionate share of the

transmission burden relative to

transmission owners under the

Commission’s ‘‘or’’ pricing policy.

According to TDU Systems,

transmission owners should be required

to permit customers to substitute their

own lower cost capital for that of the

owner’s.

SoCal Edison and Carolina P&L ask

the Commission to clarify that a

transmission provider has no obligation

to build or upgrade its facilities for

short-term firm point-to-point

transmission customers (§§ 13.5, 15.4

and 1.13). SoCal Edison states that if a

transmission provider is required to

build, the Commission should clarify

that any costs must be directly assigned

to the requesting customer.

Commission Conclusion

The Final Rule does not change the

Commission’s filing requirements for

recovery of transmission expansion

costs or other transmission-related

expenses. The Rule does not impose a

section 205 filing requirement to the

extent that existing formula rates do not

require that such a filing be made to add

transmission investment. However,

consistent with the Commission’s

transmission pricing principles in effect

prior to Order No. 888, a decision to

price transmission on an incremental

cost basis, or to directly assign facilities,

are cost assignments that require a

section 205 filing.

The Final Rule also does not change

the Commission’s transmission pricing

policies. Under our transmission pricing

policy, a utility is still permitted to

charge the higher of incremental

expansion costs ‘‘or’’ a rolled-in

embedded cost rate. There is no bias in

the Final Rule that should cause TDU

customers or any other customer to pay

a disproportionate share of transmission

costs. Moreover, we note that we also

encourage joint planning/building

options and regional solutions such as

RTGs and ISOs.

We do not believe that any change is

necessary with regard to the obligation

to build or expand. While both sections

13.5 and 15.4 obligate the transmission

provider to expand or upgrade its

transmission system to accommodate an

application for firm point-to-point

transmission service, these sections are

conditioned upon the transmission

customer agreeing to compensate the

transmission provider for such upgrade.

In light of this compensation

requirement, we do not anticipate that

transmission providers will be

requested to upgrade facilities in order

to accommodate requests for short-term

point-to-point transmission service.

However, in the unlikely event that a

short-term firm point-to-point

transmission customer agrees to pay the

costs of such upgrades, we believe that

it is appropriate to require a

transmission provider to expand its

system to accommodate the request.

g. Credit for Customers’ Transmission

Facilities

In the Final Rule, the Commission

concluded that credits related to

customer-owned facilities are more

appropriately addressed on a case-bycase basis, where individual claims for

credits may be evaluated against a

specific set of facts.269 The Commission

stressed that while certain facilities may

warrant some form of cost credit, the

mere fact that transmission customers

may own transmission facilities is not a

guaranteed entitlement to such a credit.

The Commission further explained that

it must be demonstrated that a

transmission customer’s transmission

facilities are integrated with the

transmission system of the transmission

provider in order to establish a right to

credits. The Commission also noted that

consistent with its ruling in FMPA II,270

if a customer wishes not to integrate

certain loads and resources, and thereby

exclude them from its load ratio share

of the allocated cost of the integrated

system, it may do so by separately

contracting for point-to-point

transmission service.

Rehearing Requests

APPA asserts that several differences

between the treatment of transmission

customers’ and transmission providers’

facilities are not comparable and must

be corrected: (1) transmission providers’

facilities include those owned,

controlled or operated by the

transmission provider, but to obtain

credit, transmission customers must

own the facilities; (2) transmission

providers are under no obligation to

engage in joint planning and historically

have refused, thus putting the matter

beyond the control of the customer; and

(3) facilities of the customer must serve

all of the transmission provider’s power

and transmission customers, but a

transmission provider can include

facilities in rates that serve only certain

customers. APPA also maintains that

the Commission failed to provide

sufficient guidance to allow customers

to ascertain the type of transmission

facilities for which they can expect to

receive credit.

Several entities assert that the

standard as to existing customer-owned

facilities is inherently ambiguous—the

Final Rule preamble says integrated into

the ‘‘plans or operations’’ of the

transmitting utility, but section 30.9 of

the tariff says the ‘‘planning and

operations’’ of the transmission provider

(emphasis added).271 Further, they

assert, it is unreasonable to require, as

a key to integration, that ‘‘the

transmission provider is able to provide

transmission service to itself or other

transmission customers over those

facilities’’ because it may be that the

facilities are necessary to provide

network service to the customer that

owns the facilities and a credit would be

appropriate. They argue that if

transmission facilities serve load

included in the network customer’s

network load, the transmission

customer should get a credit.

Blue Ridge states that ‘‘[i]f the

Commission does intend to change its

standard or otherwise codify the result

of FMPA II, then Blue Ridge urges

rehearing and suggests a more

analytical, policy oriented approach to

the issue.’’ (Blue Ridge at 31). It

recommends adding the following

language to the end of section 30.9 of

the tariff concerning credit for new

facilities: ‘‘or if such facilities are

integrated with, and support the
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12329

272E.g., NRECA, TDU Systems, TAPS.

273E.g., IMPA, TAPS, AMP-Ohio, Michigan

Systems. 274FERC Stats. & Regs. at 31,742; mimeo at 316.

Transmission Provider’s Transmission

system.’’ (Blue Ridge at Attachment 1).

FMPA argues that a transmission

provider can avoid paying credits for

transmission that is functionally the

same as that of the transmission

provider simply by refusing to jointly

plan. It asserts that the Commission

should adopt either the Commission’s

integration test, without requiring joint

planning, or a functionality test that

considers whether the facilities of the

customer and transmission provider are

similar. Moreover, it argues that a more

inclusive definition of the grid would

better achieve comparability and

competitive generation markets and

would remove incentives to avoid joint

planning. It argues that crediting

customer-owned transmission also

promotes the establishment of regional

grids.

Several entities state that the standard

as to future network customer-owned

facilities should be modified to make

joint planning mandatory on the part of

the transmission provider, who

otherwise has little incentive to

cooperate and coordinate.272 They claim

that in joint planning, plans cannot be

developed by the transmission provider

alone. They further argue that the

Commission should not deem the lack

of joint planning dispositive of the

operation and planning issue.

TAPS asks the Commission to clarify

that credits will be provided for

existing, as well as future, facilities if

the integration requirement is met.

Wisconsin Municipals asks the

Commission to clarify that the level of

customer-owned credits is a rate issue

and that if parties have negotiated

provisions for credits, the Final Rule

cannot be used by transmission

providers to avoid the obligations

undertaken in a settlement.

NRECA and TDU Systems assert that

the Commission should not abandon its

historical practice of rolling in

transmission facilities for purposes of

transmission pricing; otherwise, the

Commission must examine the function

of all transmission facilities in a

transmission provider’s rate base and

exclude them if they are not

‘‘integrated’’ (referencing Order No. 888

at 317 n.452). They argue that because

customers would have to file section

206 filings to enforce this, the

Commission should require

transmission providers to file under

section 205 the identity of those

facilities that will be included in the

transmission rate base, those that will be

excluded, and the supporting data.

Turlock wants the Commission to

provide concrete guidelines as to the

eligibility of facilities for customer

credits. Moreover, Turlock asserts that

credits may be appropriate for point-topoint customers as well—especially in

Northern California where PG&E,

according to Turlock, encouraged

customers to build facilities. Turlock

finds this particularly important where

PG&E has proposed to switch from

subfunctionalized ratemaking to systemwide rolled-in ratemaking. It asserts

that, if there are system-wide rolled in

rates without a credit provision, there

may be a violation of the ‘‘or’’ pricing

policy.

Several entities ask the Commission

to clarify that the crediting provision

works on a comparable basis for

transmission customers and

providers.273 They ask the Commission

to clarify that the phrase ‘‘serve all of its

power and transmission customers’’ in

section 30.9 is to be measured by the

facilities that the transmission provider

rolls into rate base to determine

transmission rates and the transmission

component of requirements rates. For

example, they argue that because AEP

rolls radial lines into rate base,

comparable customer-owned lines

should receive a credit. They also ask

the Commission to clarify that the test

that facilities are integrated into the

planning and operations of the

transmission provider is an objective

standard that is satisfied by evidence

that the transmission provider’s load

flow studies take into account the

transmission customer’s facilities. They

assert that the standard should not be a

subjective one that depends on whether

the transmission provider says that it

includes customer facilities in its

planning and operations.

AMP-Ohio adds that the integration

requirement should also be satisfied by

evidence that the transmission provider

includes costs in its rate base or

transmission expenses that are

associated with transmission facilities of

utilities that it acquires. Michigan

Systems also asks that the Commission

clarify that the test in section 30.9 is a

functional test and not whether the

transmission owner says it is integrating

its operations.

Michigan Systems states that it has no

objection to leaving determinations of

credits to rate cases, as an abstract

matter, but asserts that the Commission

should make clear that it will not

implement newly-filed tariffs in a way

that imposes multiple or inconsistent

charges for transmission in the interim.

Otherwise, it asserts, transmission

dependent utilities may be out of

business if they must wait years to get

credit for grid transmission they already

own and that they must pay to finance.

Michigan Systems also states that it

would be illegal to require systems to

pay for transmission by applying a load

ratio share based on total loads when

they have made investments under

contracts for transmission to serve a

portion of those loads.

TAPS states that the Commission

must define what it means by

‘‘integrated.’’ TAPS asserts that the term

should mean grid facilities used to

integrate the network customer’s

resources and loads. It further asserts

that the Commission should continue to

use the test whether the facilities serve

a comparable function. Unless a proper

credit is provided, TAPS maintains,

network customers could pay twice for

transmission. TAPS adds that without

proper crediting, the Commission

cannot require load ratio pricing of

network service.

TAPS asks the Commission to clarify

the method it will use to calculate the

credit in individual cases and suggests

that the Commission adopt the method

TAPS proposed in its initial comments

in this proceeding.

With respect to joint ownership of

transmission facilities or ownership of

transmission facilities through a joint

exercise of powers agency (JPA) or a

Generation and Transmission

Cooperative, TANC asks that the

Commission provide for proportionate

entitlement to a credit among those who

have invested in, and are entitled to the

use of, such facilities. TANC also argues

that the credit should apply to facilities

used to complete a transaction under

the transmission provider’s point-topoint tariff. Further, TANC asserts that

upon a showing that the facilities are

integrated, the credit in section 30.9

should be mandatory and asks that the

Commission provide guidance as to the

method of either calculating or applying

the credit.

Commission Conclusion

The Commission reaffirms its finding

in Order No. 888 that the question of

credits for customer-owned facilities is

best resolved on a fact-specific, case-bycase basis.274 Accordingly, the

Commission does not believe that the

rehearing requests seeking specific

guidance regarding various aspects of
12330 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

275Wisconsin Municipals’ argument with respect

to prior settlements has been previously addressed

in Section IV.D.1.c.(2) (Energy Imbalance

Bandwidth).

276See FERC Stats. & Regs. at 31,742–43; mimeo

at 316–17.

277As we noted in FMPA II, this fundamental cost

allocation concept applies to the transmission

provider as well. Just as the customer cannot secure

credit for facilities not used by the transmission

provider to provide service, the transmission

provider cannot charge the customer for facilities

not used to provide transmission service. 74 FERC

¶ 61,006 at 61,010 n.48 (1996).

278FERC Stats. & Regs. at 31,742–43; mimeo at

317.

279FERC Stats. & Regs. at 31,743–44; mimeo at

319–20.

280All offers or agreements to provide rate

discounts to affiliates (including the Transmission

Provider’s wholesale merchant) on a particular path

must be posted immediately on the OASIS and be

available for a long enough period to allow nonaffiliates to obtain the same discounted service on

that path and on other paths for which the

transmission provider must provide the same

discount. We modify below our requirement

regarding which other paths must receive the same

discount.

281The Commission also stated that the same

requirements will apply to discounts for firm

transmission service. The Commission added that if

a transmission provider offers an affiliate a discount

for ancillary services, or attributes a discounted

ancillary service rate to its own transactions, it must

offer at the same time the same discounted rate to

all eligible customers. The Commission noted that

discounted ancillary services rates must be posted

on the OASIS pursuant to Part 37 of the

Commission’s regulations.

282E.g., SoCal Edison, Entergy, Southwestern,

PacifiCorp, Montana Power, AEP, Utilities For

Improved Transition, EEI.

customer credits are appropriate for

resolution at this time.275

In order to conform the Final Rule

preamble language with the tariff

provisions of Order No. 888,276 we will

modify section 30.9 of the pro forma

tariff to provide that a customer may

receive a credit for its own facilities if

it demonstrates that ‘‘its transmission

facilities are integrated into the plans or

operations (instead of ‘‘planning and

operations’’) of the transmission

provider to serve its power and

transmission customers.’’ 277 The intent

of section 30.9 of the pro forma tariff is

that, for a customer to be eligible for a

credit, its facilities must not only be

integrated with the transmission

provider’s system, but must also provide

additional benefits to the transmission

grid in terms of capability and

reliability, and be relied upon for the

coordinated operation of the grid.

Indeed, in the Final Rule we explicitly

stated that the fact that a transmission

customer’s facilities may be

interconnected with a transmission

provider’s system does not prove that

the two systems comprise an integrated

whole such that the transmission

provider is able to provide transmission

service to itself or other transmission

customers over these facilities.278

The Commission further stated in the

Final Rule that where disputes over

credits for customer-owned facilities

arise, it encourages all parties not to

seek formal resolution at the

Commission, but to first pursue

alternative dispute resolution. In this

regard, the customer at the time it is

requesting network service could also

request that a study be undertaken by

the company to analyze the impact and

benefit of the customer’s facilities

provided to the integrated transmission

network.

We share the concern of APPA and

others that transmission providers have

not allowed transmission customers to

participate in the planning process for

new transmission projects. Allowing

potential transmission customers the

opportunity to participate in

transmission projects is important in

ensuring that regional transmission

needs are met efficiently. One way of

accomplishing this goal is through an

RTG, ISO, or other regional entity that

has an open planning process. Where

such entities do not exist, we strongly

encourage public utilities to hold an

open season for all transmission

expansion projects, including those in

response to a service request, so that all

entities in the region have an

opportunity to identify their future

needs and participate in the project.

Finally, requests for the Commission

to mandate joint-planning are addressed

below in the discussion of section 1.12

of the pro forma tariff.

h. Ceiling Rate for Non-firm Point-toPoint Service

In the Final Rule, the Commission

stated that it is important to continue to

allow pricing flexibility.279 The

Commission explained that, in

accordance with its current policies, the

rate for non-firm point-to-point

transmission service may reflect

opportunity costs. The Commission

further explained that, if a utility

chooses to adopt opportunity cost

pricing, the non-firm rate is effectively

capped by the availability of firm

service and is not subject to a

separately-stated price cap. On the other

hand, the Commission explained that, if

a utility chooses not to adopt

opportunity cost pricing, the non-firm

rate is capped at the firm rate.

Rehearing Requests

Duquesne asks the Commission to

clarify that the phrase ‘‘the non-firm rate

is capped at the firm rate’’ does not

mean that the Commission is deviating

from its principles that non-firm

transmission service must be priced in

a manner that (i) reflects the

interruptibility of the service, and (ii) is

economically efficient.

Commission Conclusion

With regard to Duquesne’s request, we

clarify that the firm transmission rate

simply represents a maximum rate or

price cap for non-firm transmission

prices. We emphasize that non-firm

transmission prices should reflect the

interruptibility of the service and

should promote efficient use of the

transmission system, subject to this

price cap. Accordingly, while in some

circumstances non-firm transmission

rates may be set at the firm transmission

rate level, the Commission expects that

non-firm transmission rates would, in

most instances, be priced below the

price cap.

i. Discounts

In the Final Rule, the Commission

stated that if a transmission provider

offers a rate discount to its affiliate, or

if the transmission provider attributes a

discounted rate to its own wholesale

transactions, the same discounted rate

must also be offered at the same time to

non-affiliates on the same transmission

path and on all unconstrained

transmission paths.280 In addition, the

Commission required that discounts

from the maximum firm rate for the

provider’s own wholesale use or its

affiliate’s wholesale use must be

transparent, readily understandable, and

posted on the transmission provider’s

OASIS in advance so that all eligible

customers have an equal opportunity to

purchase non-firm transmission at the

discounted rate.281 Finally, the

Commission explained that discounts

offered to non-affiliates must be on a

basis that is not unduly discriminatory

and must be reported on the OASIS

within 24 hours of when available

transmission capability (ATC) is

adjusted in response to the transaction.

Rehearing Requests

Utility Position

A number of utilities assert that the

affiliate discounting provision is too

broad.282 SoCal Edison asserts that if the

affiliate discounting provision is kept,

the requirement to discount similarly

for non-affiliates on unconstrained

paths should be limited to offers on the

same day only for new transmission

services and only for the duration of the

service offered to the affiliate.

Entergy and Southwestern assert that

the Commission should change the

discount language, which provides that
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12331

283See also Washington Water Power.

284E.g., Montana Power, Allegheny, Puget. 285See also Florida Power Corp.

286We clarify that own use/affiliate transactions

include all transactions where the transmission

provider or any of its affiliates is either the buyer,

seller, marketer, or broker of wholesale power.

287 ’’Negotiation’’ would only take place if the

transmission provider or potential customer seeks

prices below the ceiling prices set forth in the tariff.

whenever the transmission provider

offers a discount to an affiliate, or

attributes a discount to its own

transaction, it must offer a comparable

discount to all similarly situated

transmission customers. Southwestern

believes that the Commission does not

justify its different treatment of

discounts to affiliates and discounts to

non-affiliates—section 205(b) of the FPA

states that a public utility may not give

any undue preference or advantage to

any person. Southwestern also notes

that for gas pipelines, the Commission

required that affiliate discounts be

available to similarly situated shippers

(citing 18 CFR 161.3(h)(1)).

PacifiCorp suggests replacing the last

sentence of section 37.6(c)(3) of the

OASIS regulations with the following

sentence: ‘‘With respect to any discount

offered to its own power customers or

its affiliates, the Transmission Provider

must, at the same time, post on the

OASIS an offer to provide the same

discount to all Transmission Customers

on the same transmission path and on

all other unconstrained transmission

paths parallel thereto for deliveries to

the same Point of Delivery.’’ It argues

that the Commission’s approach of

requiring the same discount to all

transmission customers on the same

path and on all unconstrained

transmission paths would discourage

discounting, even when done to attract

counter-wheeling to relieve

constraints.283

Several utilities argue that the

discount language should be changed to

require only that the same discount be

offered to all customers on the same

path.284 Otherwise, Montana Power

asserts, transmission providers will be

reluctant to offer discounts to its own

marketers so as to protect revenues on

other paths.

AEP suggests that the discount

language be changed to require that the

discount be made available for all

unconstrained paths terminating at the

same interface.

Illinois Power argues that the

Commission should require discounts

for equivalent (i.e., similarly situated)

service requests, on the basis of

location, term and time of service,

which it asserts conforms to the

Commission’s standards for natural gas

pipelines (citing 18 CFR 161.3(h)).

Otherwise, it asserts, the Commission’s

approach will result in inefficient use of

scarce transmission capacity and

thereby discourage efficient bulk power

trading.

VEPCO asserts that transmission

providers must be given more flexibility

to accommodate differences in regional

wholesale markets and to maximize the

movement of economical capacity and

energy. It states that a transmission

provider will provide discounts only if

they are not detrimental to existing

committed agreements or potential

future revenue—revenue from

additional sales must offset the decrease

in revenues from making discounts. It

suggests that preferential treatment can

be reduced by the following constraints:

(1) offer the same discount to all

transmission requests to the same points

of delivery for the same time, and (2) a

discount should not apply to service

already agreed to but not yet provided

at that point. Utilities For Improved

Transition adds the following

constraint: evaluate request for discount

on whether it would increase volume

without reducing total revenues.285

Florida Power Corp asserts that because

communications regarding discounts

must be posted on OASIS, preferential

treatment would be readily apparent.

EEI states that the discount

requirement has the potential to

arbitrarily reduce the revenue that the

transmission provider may be able to

obtain over alternative paths that may

be unconstrained, but of greater

potential value than the path(s)

identified as appropriate for

discounting. It adds that the

requirements for posting discounts

should be the same regardless of

affiliation and should be limited to the

specific transmission path(s) discounted

by the transmission provider.

Carolina P&L argues that the

Commission should permit selective

discounting of non-firm transmission

service on a posted-in-advance (on

OASIS) basis that will not create a most

favored nations situation merely

because the transmission provider or an

affiliate availed itself of the posted

discount.

Customer Position

Tallahassee asks the Commission to

clarify that the transmission provider

must automatically apply the discount

to any eligible customer or, at the

minimum, provide actual and timely

notice of the discount’s availability.

Similarly, PA Coops asserts that ‘‘[i]f

transmission service is being discounted

to any customer, affiliated or not, for a

specific level of service at a specific

point in time, it should be equally

discounted to all customers receiving

the same transmission service. To do

otherwise is unduly discriminatory.’’

(PA Coops at 11).

TAPS asserts that all discounts must

be posted in advance, the reasons for the

discounts should be transparent, the

transmission provider should keep all

requests for discounts in a log, and

short-lived discounts should not be

permitted.

Commission Conclusion

In response to the arguments raised

with respect to discounting, we will

revise our policy on discounting

transmission service. This revised

policy will assure consistency with our

standards of conduct requirements,

which preclude a utility’s wholesale

merchant function from having access to

its transmission system information

(including price) not posted on the

OASIS that is not otherwise also

available to the general public or that is

not also publicly available to all

transmission users. The revised policy

also should result in less opportunity

for affiliate abuse and enable better

monitoring of potential abuse.

Additionally, we have concluded that

the same policy should apply regardless

of whether the discount is for the

transmission provider’s own wholesale

use (i.e., wholesale merchant function),

for the transmission provider’s affiliate,

or for a non-affiliate.

A transmission provider should

discount only if necessary to increase

throughput on its system. While the

potential for abuse is most obvious in

situations involving the transmission

provider’s own wholesale use or use by

an affiliate (own use/affiliate),286 we

must also be concerned with a

transmission provider agreeing to

discount to non-affiliates in any unduly

discriminatory manner. To satisfy these

dual concerns, we believe that any

‘‘negotiation’’ 287 between a transmission

provider and potential transmission

customers should take place on the

OASIS. Toward this end, we believe

three principal requirements are

appropriate. (These requirements would

remain even after negotiation takes

place on the OASIS.)

First, any offer of a discount for

transmission services made by the

transmission provider must be

announced to all potential customers

solely by posting on the OASIS. This

requirement, which will ensure that all

potential transmission customers under
12332 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

288For example, requiring the transmission

provider to wait to see if an offered 5% discount

clears the market would appear to be less efficient

than permitting the customer to advise the

transmission provider (via the OASIS) of its need

for a higher discount in order to take service.

289Thus, there is no need to revise contracts to

reflect later offered discounts. 290See also Valero.

the pro forma tariff will have equal

access to discount information, will

guard against own use/affiliate

customers gaining an unfair timing

advantage concerning the availability of

discounts.

Second, we will require that any

customer-initiated requests for

discounts occur solely by posting on the

OASIS, regardless of whether the

customer is an own use/affiliate or a

non-affiliate. We have considered, and

rejected at least for now, a more

restrictive approach which would

require that all discounts be initiated

solely through offers by the

transmission provider. Under such an

arrangement, negotiations for discounts

would effectively take place by

customers accepting or not accepting

the offered discount. While such an

arrangement could better protect against

affiliate abuse, it might be less

efficient.288 Accordingly, we will permit

customer-initiated requests for

discounts but will require that such

requests be visible (via posting on the

OASIS) to all market participants.

Finally, we will require that, once the

transmission provider and customer

agree to a discounted transaction, the

details (e.g., price, points of receipt and

delivery, and length of service) be

immediately posted on the OASIS. This

requirement will be equally applicable

regardless of whether the customer is an

own use/affiliate or non-affiliate.

We will also revise our policy with

respect to the transmission paths on

which a discount must be offered. Many

petitioners argue that the policy in

Order No. 888, particularly that the

discount rate must be offered over all

unconstrained paths, is too broad, and

may provide disincentives for the

efficient operation of the transmission

grid. Their concerns include, for

example, the possibility that the policy

would inhibit the transmission provider

from offering discounts that would

relieve line constraints. For example,

PacifiCorp argues that it would be

reluctant to offer a discount on

northbound power flows that would

relieve transmission constraints on

transmission paths that are normally

used for southbound flows, if by virtue

of discounting northbound flows, it

would also be required to discount all

unconstrained southbound flows.

Another concern is that while requiring

discounts on all unconstrained paths

could conceivably result in more service

being provided, it may not have that

effect. Since the level of transmission

revenues will decline if the discount

applies to all unconstrained paths and

this, in turn, could reduce the credit to

firm transmission users for non-firm

service revenues, transmission

providers may simply decide not to

discount a particular unconstrained

path. In light of these persuasive

arguments, we will no longer require the

transmission provider to provide the

same discount over all unconstrained

paths.

Under our revised policy, if the

transmission provider offers a discount

on a particular path, i.e., from a point

of receipt to a point of delivery, the

transmission provider must offer the

same discount for the same time period

on all unconstrained paths that go to the

same point(s) of delivery on the

transmission provider’s system. In this

regard, a point of delivery includes an

interconnection with another control

area. Also, if a power purchaser can take

delivery at more than one point of

delivery (such as two substations

serving a municipality), we would

consider these to be the same point of

delivery for discounting purposes.

This change provides some flexibility

to transmission providers to set prices

for transmission service efficiently and

at the same time maintains the

requirement that public utilities provide

comparable service at rates that are not

unduly discriminatory or preferential.

The change is designed to ensure that

the transmission owner will provide the

same discounted service to its

competitors that it provides to itself or

its affiliates for their wholesale sales.

The Commission considered requiring

the transmission provider offering a

discount on a particular path to offer

discounts on all unconstrained paths

that go from the same points of receipt

on the transmission provider’s system

and decided that such a requirement

was not necessary to ensure

comparability.

We further clarify that a transmission

provider may limit its offers of

discounts over the OASIS to particular

time periods. There is nothing per se

unduly discriminatory in offering a

discount in one period and not in

another.289

Finally, we recognize that even with

this revised policy utilities may engage

in affiliate abuse by offering discounts

only at times or along paths that are of

advantage to it or its affiliates. While

requiring the posting of discount

information on the OASIS does not

completely eliminate the possibility of

affiliate abuse, these procedures will

allow ready identification of unduly

discriminatory or preferential

transactions, and thus make easier the

preparation of complaints that the

transmission provider is engaging in a

pattern of discounting that indicates

affiliate abuse, such as offering

discounts preferentially at times or on

paths that only the transmission

provider or its affiliate can take

advantage of, without offering discounts

at times or on paths that its competitors

can take advantage of.

We will require that all ‘‘negotiation’’

take place on the OASIS as soon as

practicable, as explained in Order No.

889–A.

j. Other Pricing Related Issues Not

Specifically Addressed in the Final Rule

(1) Demand Charge Credits

Rehearing Requests

VT DPS argues that demand charge

credits for curtailments or interruptions

are needed to provide an incentive to

utilities to provide high quality service.

It points out that the Commission has

allowed demand charge credits in the

gas pipeline context (citing Tennessee

Gas Pipeline Co., 71 FERC ¶ 61,399 at

62,580).290

Commission Conclusion

The Commission does not believe that

electrical systems will be less reliable as

a result of our initiatives on competition

and open access in the Final Rule. As

such, the Commission does not intend

to require demand charge credits on a

generic basis to encourage reliable

transmission service. However, because

the Commission has not mandated any

particular rate design methodology

under the Final Rule pro forma tariff,

customers are free to argue in the

compliance filing proceedings or

subsequent section 205 proceedings that

demand charge credits are reasonable in

the context of a particular rate design

method.

(2) In-Kind Transactions

Rehearing Requests

CCEM asserts that in-kind

transactions in reformed power pool

agreements should be abolished because

of the uncertainty of valuing non-cash

transactions and the potential for cross

subsidizing the utilities’ generation

sales. It contends that a cash equivalent

transaction for all formerly in-kind

transactions among transmission owners

is needed.
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12333

291Arizona Public Service Company, Order

Addressing Functional Unbundling Issues, 78 FERC

¶ 61,016 (slip op. at 11) (1997) (Arizona).

292FERC Stats. & Regs. at 31,745; mimeo at 323–

24.

293FERC Stats. & Regs. at 31,746–47; mimeo at

326–29.

294FERC Stats. & Regs. at 31,694; mimeo at 172.

295FERC Stats. & Regs. at 31,665 and 31,694;

mimeo at 88 & 172.

296FERC Stats. & Regs. at 31,748; mimeo at 332–

33.

297 In the Final Rule pro forma tariff, the

Commission defines curtailment as: ‘‘A reduction in

firm or non-firm transmission service in response

to a transmission capacity shortage as a result of

system reliability conditions.’’ (pro forma tariff

section 1.7). The pro forma tariff defines

interruption as: ‘‘A reduction in non-firm service

due to economic reasons pursuant to Section 14.7.’’

(pro forma tariff section 1.15). The distinction

between curtailment and interruption may have

been blurred in Order No. 888 and this order

attempts to clarify that distinction.

Commission Conclusion

To satisfy CCEM’s concerns, the

Commission concludes that in-kind

transactions must be provided on a nondiscriminatory basis. The Commission

recently found that in-kind transactions

(i.e., transactions with payment by

energy returned in kind instead of by a

monetary charge) with no unbundling

requirement ‘‘could hide and, thereby,

mask unduly preferential terms and

rates,’’ which is precisely one of the

practices that the Final Rule is intended

to remedy.291 While we will now require

that all in-kind transactions be provided

on an unbundled basis, we stress that

we are not prohibiting in-kind

transactions. Utilities are free to enter

into contracts that contain in-kind

compensation for the wholesale

generation component, as long as it

unbundles such transactions. Consistent

with Arizona, unless the other party to

the transaction contracts for

transmission service under that utility’s

open access pro forma tariff, that utility

must obtain the necessary transmission

and ancillary services under the terms

of its open access transmission tariff and

must separately state the transmission

and ancillary service prices that it will

recover from the customer.

2. Priority For Obtaining Service

a. Reservation Priority for Existing Firm

Service Customers

In the Final Rule, the Commission

indicated that a transmission provider

may reserve in its calculation of ATC

transmission capacity necessary to

accommodate native load growth

reasonably forecasted in its planning

horizon.292

Rehearing Requests

This issue is discussed in Section

IV.C.5. (Reservation of Transmission

Capacity for Future Use by Utility).

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

In the Final Rule, in response to

concerns that network service should

have a reservation priority over point-topoint service because of pricing

differences, the Commission allowed

utilities the opportunity to eliminate the

differences in pricing between network

and point-to-point services by

permitting utilities to adopt point-topoint reservations as the customer

load.293 The Commission explained that

utilities are free to propose a single cost

allocation method for the two services.

In addition, the Commission provided

that reservations for short-term firm

point-to-point service (less than one

year) will be conditional until one day

before the commencement of daily

service, one week before the

commencement of weekly service, and

one month before the commencement of

monthly service. According to the

Commission, these conditional

reservations may be displaced by

competing requests for longer-term firm

point-to-point service. The Commission

explained that after the deadline, the

reservation becomes unconditional, and

the service would be entitled to the

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

Moreover, the Commission explained

that the Final Rule pro forma tariff does

not propose point-to-point or network

service with various degrees of firmness

beyond the simple categories of firm

and non-firm. It explained that when a

customer requests firm transmission

service, reservation priorities are

established based first on availability,

and in the event the system is

constrained, based on duration of the

underlying firm service request—

customers may choose the ‘‘firmness’’ of

service they want by electing to take

non-firm service, or by reserving and

paying for firm service.

Rehearing Requests

NRECA and TDU Systems declare that

provisions making reservations for

short-term firm point-to-point service

conditional will not reduce the

incentive to cream skim, i.e., a customer

has an incentive to submit reservations

for very short terms without fear of not

getting service because it can always

increase its request to match another

longer request. They suggest an

alternative: all native load, network, and

long-term firm (one year or more)

requests would be given priority over

short-term firm requests, which would

have priority over non-firm requests.

Commission Conclusion

The Final Rule has sufficiently

minimized the potential for cream

skimming. Further, we note that the

alternative proposed by NRECA & TDU

Systems has substantially been adopted

in Order No. 888. Specifically, Order

No. 888 provides: (1) public utilities the

right to reserve existing transmission

capacity needed for native load growth

and network transmission customer

load growth,294 and (2) existing

transmission customers the right of first

refusal.295 The only entities not covered

above—potential long-term firm

customers—must submit their service

applications as far in advance as

practicable.

c. Reservation Priorities for Non-firm

Service

In the Final Rule, the Commission

found that network economy purchases

should have a reservation priority over

non-firm point-to-point and secondary

point-to-point uses of the transmission

system.296

Rehearing Requests

North Jersey argues that non-firm

service should be allocated on a firstcome, first-served basis, and where

multiple customers request service at

the same time, available capacity should

be allocated on a pro rata basis. It asserts

that the proposed priority system based

on duration of non-firm service would

simply encourage non-firm customers to

request service for longer durations than

needed.

Commission Conclusion

We reject North Jersey’s argument that

the proposed priority system based on

duration of non-firm service would

encourage non-firm customers to

request service for longer durations than

needed. North Jersey ignores the fact

that section 14.2 of the pro forma tariff

establishes a right for eligible customers

with existing non-firm reservations to

match any longer term reservation

before being preempted.

A related matter is discussed in

Section IV.G.3.b below.

3. Curtailment and Interruption

Provisions 297

a. Pro-Rata Curtailment Provisions

In the Final Rule, the Commission

found that curtailment on a pro-rata

basis is appropriate for curtailing

transactions that substantially relieve a
12334 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

298FERC Stats. & Regs. at 31,749; mimeo at 

335–36.

299E.g., Santa Clara, Redding, TANC. 300FERC Stats. & Regs. at 31,749; mimeo at 335.

301We note that in Order No. 888 we partially

modified existing economy energy coordination

agreements. FERC Stats. & Regs. at 31,666; mimeo

at 91.

302 69 FERC ¶ 61,145 at 62,300 (1994) (proposed

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

303FERC Stats. & Regs. at 31,750; mimeo at 338–

39.

constraint.298 The Commission

explicitly allowed the transmission

provider discretion to curtail the

services, whether firm or non-firm, that

substantially relieve the constraint.

The Commission also indicated that it

would consider granting deference to an

alternative curtailment method to avoid

hydro spill if such a regional practice is

generally accepted and adhered to

across the region.

The Commission further found that

under network and point-to-point

service, the transmission provider may

propose a rate treatment (penalty

provision) to apply in the event a

customer fails to curtail service as

required under the Final Rule pro forma

tariff and indicated that such proposals

will be evaluated on a case-by-case basis

on compliance.

Rehearing Requests

PA Com asserts that pro rata

curtailment fails to hold native load

harmless to the extent practical as

required by the FPA. PA Com points out

that on January 19, 1994, PJM initiated

pro-rata load shedding, in part to

preserve economic transactions, leaving

customers in Pennsylvania without

power during a record cold spell.

VA Com argues that pro rata

curtailment may harm native load

customers and section 206 complaints

are after the fact and of little assistance

to native load. VA Com argues that

curtailment priority (in order of

curtailment) should be: non-firm,

contract firm, and then native load, and

that utilities should have flexibility to

curtail on a pro-rata basis within

classes, subject to state curtailment

policy.

Several entities argue that provision

must be made for preference in

curtailment priorities obtained through

settlement, through payment of good

and valuable consideration, or under

existing transmission contracts.299

Turlock argues that customers should be

able to obtain a variation from the pro

rata scheme if they can show that they

have made either past or future

investments to improve constrained

facilities and that the quid pro quo for

their investment is improved

curtailment priority.

Allegheny asks the Commission to

clarify that it did not intend to require

public utilities to shed (through pro rata

curtailment) native transmission load

customers in order to preserve some

portion of service to through system

users of the grid. According to

Allegheny, the FPA mandates that

service reliability to franchise customers

must be maintained and through-system

users are not similarly situated to native

transmission load customers and should

not be treated the same in an emergency

because through system customers can

protect themselves, but native

transmission load customers cannot.

Allegheny adds that failure to maintain

system reliability would violate section

211 of the FPA.

CCEM asserts that hard and fast

priority rules are needed to prevent

inconsistent rules from developing for

different utilities, pools, or control

areas.

Commission Conclusion

Assertions that the pro-rata

curtailment provision in the tariff may

harm native load customers are

misplaced. The Commission clarified in

the Final Rule that it was not requiring

a pro-rata curtailment of all transactions

at the time of a constraint, but rather

curtailment of those transactions,

whether firm or non-firm, that

effectively relieve the constraint.300 The

Commission also required that such

curtailments be made on a nondiscriminatory basis, including the

transmission provider’s own wholesale

use of the system. The Commission

further explained that the pro-rata

curtailment provision was intended to

apply to situations where multiple

transactions could be curtailed to

relieve a constraint. Of course, if

curtailment of multiple transactions is

necessary, non-firm service would be

curtailed prior to firm service. However,

the Commission established that, in

emergencies, the transmission provider

had the discretion to interrupt firm

service under the tariff to ensure the

reliability of its transmission system.

In terms of reliability, we believe that

sufficient safeguards have been

established to protect native load. In

particular, the transmission provider is

responsible for planning and

maintaining sufficient transmission

capacity to safely and reliably serve its

native load. Order Nos. 888 and 889

permit the transmission provider to

reserve, in its calculation of ATC,

sufficient capacity to serve native load.

Allegations that a utility did not

curtail on a non-discriminatory basis,

but instead favored a certain class of

customer or type of transaction should

be filed in a section 206 complaint

proceeding to be reviewed on a casespecific basis. While it is true that such

complaints will be processed on an

after-the-fact basis, it is only on a factspecific basis that such complaints can

be fully and adequately reviewed.

Additionally, tariff section 14.7 does

in fact establish that for curtailment

purposes, non-firm point-to-point

transmission shall be subordinate to

firm transmission service and non-firm

service may also be interrupted for

economic reasons. However, adopting

curtailment schemes based solely on

classes of service, as proposed by the

VA Com, is inappropriate. Specifically,

VA Com’s proposal to curtail all nonfirm transmission transactions prior to

firm transactions could exacerbate an

emergency situation. For example, a

curtailment could be necessary due to a

constraint affecting northbound

transactions. However, curtailing all

non-firm transactions, including

southbound transactions (or

counterflows), could worsen the

situation. Accordingly, the Commission

believes the approach established in the

Final Rule of allowing nondiscriminatory curtailments of the

transaction(s) that effectively relieve(s)

the constraint is appropriate.

In response to CCEM’s concerns

regarding the potential for inconsistent

rules for different utilities, pools or

control areas, the Commission

explained in the Final Rule that any

proposed deviations from the non-price

terms and conditions of the pro forma

tariff, such as regional practices, must

be adequately supported by the utility

proposing the change.

Finally, Order No. 888 did not

abrogate existing contracts; 301 therefore,

customers with unique curtailment

priorities established by pre-existing

contracts would not have these

priorities eliminated for the term of the

existing contract.

b. Curtailment and Interruption

Provisions for Non-firm Service

In the Final Rule, the Commission

explained that it had clarified in the pro

forma tariff that a network customer’s

economy purchases have a higher

priority than non-firm point-to-point

transmission service (citing AES Power,

Inc. 302). 303

The Commission also revised the pro

forma tariff to allow the transmission

provider to curtail non-firm service for

reliability reasons or to interrupt the

service for economic reasons (i.e., in

order to accommodate (1) a request for
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12335

304A firm point-to-point customer has a right to

change its receipt points if capacity is available.

These changed receipt points are known as

secondary receipt points. The issue addressed here

is the priority that is assigned to those secondary

receipt points.

305See also Tallahassee.

306FERC Stats. & Regs. at 31,750; mimeo at 338.

307FERC Stats. & Regs. at 31,769–70; mimeo at

395–99.

308We note that CCEM has pursued these

arguments (raised on rehearing) in utility-specific

rate cases and its objections will be addressed there.

309See FERC Stats. & Regs. at 31,750; mimeo at

338, and AES Power, Inc., 69 FERC ¶ 61,145 at

62,300 (1994) (proposed order), 74 FERC ¶ 61,220

(1996) (final order).

310This is comparable to the service a utility

provides its native load.

firm transmission service, (2) a request

for non-firm service of greater duration,

(3) a request for non-firm transmission

service of equal duration with a higher

price, or (4) transmission service for

economy purchases by network

customers from non-designated

resources). The Commission further

explained that a firm point-to-point

customer’s use of transmission service

at secondary points of receipt and

delivery will continue to have the

lowest priority.

Rehearing Requests

For comparability, CCEM asserts that

secondary receipt points should be

made subordinate to other firm

services, 304 but should have priority

over non-firm point-to-point

transactions. CCEM also argues that

non-firm point-to-point service, once

scheduled, should not be interrupted to

accommodate non-firm service for a

network service economy purchase.

VT DPS argues that firm flexible

point-to-point service over secondary

points of receipt and delivery should

have a priority over non-firm point-topoint service (citing sections 14.2 and

14.7 of the pro forma tariff). It argues

that this priority is necessary to reflect

the fact that point-to-point customers

pay for firm service and to be consistent

with the treatment of network

customers. VT DPS notes that in the

natural gas industry the Commission

has found that such priority is essential

to reflect the fact that firm customers are

paying for firm service (citing Order No.

636–B).

APPA asks the Commission to clarify

the conditions under which the

Commission will allow non-firm service

to be interrupted by the transmission

provider solely for economic reasons.

APPA claims that this clarification is

needed so as to prevent interruption of

service on a discriminatory basis.

CCEM states that non-firm point-topoint transmission service does not

provide the user with a specific capacity

reservation, and therefore such service

should bear no reservation or demandlike charges and the customer should

pay a commodity-only charge only for

when the service is being provided. 305

It contends, for example, that if a

customer schedules one week of weekly

non-firm transmission service and is

interrupted on the second day of

service, the customer should only pay

for the service it used and should have

no responsibility to take or to pay for

service for the remainder of the week.

Alternatively, it argues that if there are

reservation charges and the non-firm

customer pays for service on a ‘‘take-or

pay basis’’ regardless of use, non-firm

service should not be subject to being

bumped once service is scheduled and

power is flowing. Moreover, if the nonfirm point-to-point transmission

customer does pay reservation charges

on a ‘‘take-or-pay basis,’’ the non-firm

reserved capacity should be tradeable in

a secondary market.

Commission Conclusion

We reject CCEM’s proposal to prevent

scheduled non-firm transmission

service from being interrupted to

accommodate economy purchases for

network customers. Non-firm service is

provided on an interruptible basis. To

the extent CCEM wishes to obtain

service that cannot be interrupted to

accommodate other transactions, it has

the option of requesting firm service in

the form of either network or point-topoint transmission service.

APPA’s concerns have already been

addressed by the Commission. In the

Final Rule, the Commission specifically

listed the economic reasons that a

transmission provider could interrupt

non-firm point-to-point transmission to

include:

accommodat[ing] (1) a request for firm

transmission service, (2) a request for nonfirm service of greater duration, (3) a request

for non-firm transmission service of equal

duration with a higher price, or (4)

transmission service for economy purchases

by network customers from non-designated

resources.[306]

CCEM’s arguments are misplaced in

that they focus on the specific rate

(including any potential credits for

service interruption) that utilities may

propose for non-firm point-to-point

transmission service. Order No. 888 did

not mandate any pricing methodology to

be used for non-firm point-to-point

transmission service. Rather, the

Commission established the minimum

non-price terms and conditions

necessary to ensure comparable service.

As the Commission explained in the

Final Rule, utilities are free to propose

any rates for non-firm point-to-point

transmission in a section 205 filing

consistent with the Commission’s

Transmission Pricing Policy

Statement.307 However, the Commission

will evaluate the appropriateness of

such proposed rates against the nonprice terms and conditions established

in the pro forma tariff or other non-price

terms and conditions proposed and

fully supported by the utility.308

The Commission has previously

addressed VT DPS’ point.309 Non-firm

point-to-point customers pay for nonfirm service as their service. Firm pointto-point customers, on the other hand,

contract and reserve a specified amount

of service over designated points of

receipt and delivery. The Commission

permitted these firm point-to-point

customers to use secondary non-firm

service (from points of receipt/delivery

other than those designated in their

service agreement) on an as-available

basis at no additional charge. Because

the firm point-to-point customers taking

secondary non-firm are accorded this

scheduling flexibility at no additional

charge, they are properly accorded a

lower priority than stand alone, nonfirm transmission. In contrast, network

customers are responsible for paying for

a percentage of total system

transmission costs in order to serve their

designated network loads whether the

energy is from designated network

resources or from non-designated

resources on an as-available basis.310

Because the network customer pays a

load-ratio share of total transmission

costs, it receives a higher priority.

Significantly, if any firm point-to-point

customer wants to avail itself of the

higher priority associated with economy

energy purchases under the network

tariff, it is free to do so by undertaking

the cost responsibilities associated with

network service.

Finally, in response to VT DPS, we

note that we have chosen different

approaches in the electric and natural

gas areas. In this regard, we recognize

that there is a trade-off between

encouraging tradable capacity rights

versus maximizing revenues that can be

credited against the transmission

provider’s costs of providing

transmission service. On the electric

side, fully developed transmission

capacity trading rights simply do not

exist at this time, and so we have

chosen to emphasize an approach that

maximizes revenues to be credited to

transmission customers. However, we

will continue to evaluate our approach

in the context of any future transmission

rate proposal that is based on the

concept of tradable capacity rights.
12336 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

311FERC Stats. & Regs. at 31,760–63; mimeo at

370–378.

312See 26 U.S.C. § 141. Interest on private activity

bonds is taxable unless the bonds are qualified

bonds for which a specific exception is included in

the Internal Revenue Code.

313See 26 U.S.C. § 142.

314The Commission also clarified that reciprocal

service will not be required if providing such

service would jeopardize a G&T cooperative’s taxexempt status.

315 26 U.S.C. § 142(f)(2)(A).

316E.g., NRECA, Oglethorpe, AEC & SMEPA,

TANC.

317E.g., Redding, Tallahassee, TANC, Dairyland.

4. Reciprocity Provision

In the Final Rule, the Commission

concluded that it was appropriate to

require a reciprocity provision in the

pro forma tariff.311 The Commission

explained that this provision will be

applicable to all customers, including

non-public utility entities such as

municipally-owned entities and RUS

cooperatives, that own, control or

operate interstate transmission facilities

and that take service under the open

access tariff, and any affiliates of the

customer that own, control or operate

interstate transmission facilities.

The Commission developed a

voluntary safe harbor procedure under

which non-public utilities would be

allowed to submit to the Commission a

transmission tariff and a request for

declaratory order that the tariff meets

the Commission’s comparability (nondiscrimination) standards. The

Commission explained that if it finds

that a tariff contains terms and

conditions that substantially conform or

are superior to those in the Final Rule

pro forma tariff, it will deem it an

acceptable reciprocity tariff and require

public utilities to provide open access

service to that non-public utility.

If a non-public utility chooses not to

seek a Commission determination that

its tariff meets the Commission’s

comparability standards, the

Commission declared that a public

utility could refuse to provide open

access transmission service. However,

any such denial must be based on a

good faith assertion that the non-public

utility has not met the Commission’s

reciprocity requirements.

In support of its decision to adopt a

reciprocity provision, the Commission

explained that it was not requiring nonpublic utilities to provide transmission

access, but was conditioning the use of

public utilities’ open access services on

an agreement to offer open access

services in return. The Commission

noted that non-public utilities can

choose not to take service under public

utility open access tariffs and can

instead seek voluntary service from the

public utility on a bilateral basis.

The Commission further explained

that the reciprocity requirement strikes

an appropriate balance by limiting its

application to circumstances in which

the non-public utility seeks to take

advantage of open access on a public

utility’s system. However, the

Commission recognized that Congress

has determined that certain entities in

the bulk power market can use taxexempt financing by issuing bonds that

do not constitute ‘‘private activity

bonds’’ 312 or by financing facilities with

‘‘local furnishing’’ bonds.313 The

Commission stated that it was not its

purpose to disturb Congress’ and the

IRS’s determinations with respect to taxexempt financing. Therefore, the

Commission clarified that reciprocal

service will not be required if providing

such service would jeopardize the taxexempt status of the transmission

customer’s (or its corporate affiliates’)

bonds used to finance such transmission

facilities.314

With respect to local furnishing

bonds, which are available to a handful

of public utilities, the Commission

noted that Congress, in section 1919 of

the Energy Policy Act, amended section

142(f) of the Internal Revenue Code to

provide that a facility shall not be

treated as failing to meet the local

furnishing requirement by reason of

transmission services ordered by the

Commission under section 211 of the

FPA if ‘‘the portion of the cost of the

facility financed with tax-exempt bonds

is not greater than the portion of the cost

of the facility which is allocable to the

local furnishing of electric energy.’’ 315

So that any local furnishing bonds that

may exist do not interfere with the

effective operation of an open access

transmission regime, the Commission

required any public utility that is

subject to the Open Access Rule that has

financed transmission facilities with

local furnishing bonds to include in its

tariff a similar provision that it will not

contest the issuance of an order under

section 211 of the FPA requiring the

provision of such service, and will,

within 10 days of receiving a written

request by the applicant, file with the

Commission a written waiver of its

rights to a request for reciprocal service

from the applicant under section 213(a)

of the FPA and to the issuance of a

proposed order under section 212(c).

In addition, the Commission limited

the reciprocity requirement to the

applicant and corporate affiliates. The

Commission explained that if a G&T

cooperative seeks open access

transmission service from the

transmission provider, then only the

G&T cooperative, and not its member

distribution cooperatives, would be

required to offer transmission service.

However, if a member distribution

cooperative itself receives transmission

service from the transmission provider,

then it (but not its G&T cooperative)

must offer reciprocal transmission

service over any interstate transmission

facilities that it may own, control or

operate.

Furthermore, the Commission

explained that a non-public utility, for

good cause shown, may file a request for

waiver of all or part of the reciprocity

requirement.

The Commission also explained that

the reciprocity requirement will apply

to any entity that owns, controls or

operates interstate transmission

facilities that uses a marketer or other

intermediary to obtain access. The

Commission added that it would apply

the same criteria to waive the

reciprocity condition for small nonpublic utilities as for small public

utilities.

Rehearing Requests

Reciprocity Provision—Public Power

Position

A number of public power entities

argue that the reciprocity provision

should be eliminated because the

Commission cannot require indirectly

what it cannot require directly.316

Several other public power entities add

that the reciprocity obligation is beyond

the jurisdiction of the Commission

because the transmission obligations of

non-public utilities (e.g., municipal

utilities) are established and limited to

those required by sections 211 and 212

of the FPA.317 Tallahassee asserts that

the Commission’s conditioning

approach has the effect of excluding an

entire class of transmission customer

from open access, i.e., those unable to

grant reciprocal service. This,

Tallahassee asserts, is discriminatory

and contrary to the purpose of the Final

Rule and the requirements of sections

205, 206 and 212 of the FPA. TANC

argues that the Commission does not

have the discretion to grant or withhold

open access transmission on the

condition that the customer consent to

doing something that the Commission

admits it cannot directly order: ‘‘The

Commission has never ‘conditioned’ its

duty to allow only just and reasonable

rates on any action by the customer.’’

(TANC at 16).

A number of entities challenge the

Commission’s assertion that the

reciprocity requirement for non-public
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12337

318E.g., NRECA, Dairyland, TDU Systems, AEC &

SMEPA.

319NRECA at 29. NRECA specifically lists the

following: reliability of electric service; impairment

of contracts; ability to cease service; all costs

associated with the service must be recovered; retail

marketing areas; and prohibitions on retail

wheeling and sham wholesale transactions. See also

Oglethorpe.

320E.g., EEI, Entergy, Montana-Dakota Utilities,

Southwestern, Oklahoma E&G, Southern. 321See also Oklahoma E&G. 322E.g., Montana-Dakota Utilities, Southern, EEI.

utilities is voluntary.318 Dairyland

contends that the alternative of seeking

a bilateral agreement is illusory—even if

it could be obtained—because Order No.

888 provides that any bilateral

wholesale coordination agreement

executed after July 9, 1996 will be

subject to open access requirements.

Dairyland argues that the phrase

‘‘subject to open access requirements’’

presumably would include the

reciprocity requirement for non-public

utilities.

AEC & SMEPA assert that there is no

record support for the contention that

non-public utilities are responsible for

closed systems or that such systems, if

any, have an impact on the market.

NRECA asserts that if the reciprocity

provision is retained, the Commission

should ‘‘modify its terms to incorporate

the statutory standards and protections

which FPA sections 211 and 212

contain.’’ 319

Umatilla Coop asks the Commission

to clarify that distribution cooperatives

will not become subject to the

reciprocity requirements merely because

they purchase power from affiliated

cooperatives that are acting as power

marketers. TDU Systems assert that a

cooperative should not have to render

reciprocal service if it would interfere

with its ability to obtain RUS loan

financing.

TAPS declares that the transmission

provider alone should not have access

to third-party systems through

reciprocity. It maintains that the utility’s

long-term transmission customers

should also be afforded access to those

third-party systems so that the

transmission provider does not have a

competitive advantage. TAPS argues

that a third-party should be required to

have an open access tariff available.

Reciprocity Provision—Utility Position

A number of utilities argue that the

exemption from reciprocity for

distribution cooperatives should be

eliminated.320 EEI and Montana-Dakota

Utilities assert that G&Ts could

eliminate their reciprocity obligation by

selling or transferring their transmission

facilities to their distribution owner/

members. Southwestern argues that the

exception for distribution cooperatives

puts public utilities at a competitive

disadvantage in that distribution

cooperatives can use a public utility’s

system to compete with the public

utility, but a public utility cannot use

the distribution cooperatives’ systems to

compete to sell power to their

customers.321 It adds that the exception

allows distribution cooperatives to hide

behind shell G&Ts. For example,

Southwestern argues that Golden

Spread Electric Cooperative is a shell

G&T because it owns only small

amounts of facilities. It concludes that

reciprocal access may become especially

important if a state implements a retail

access plan because section 211 cannot

be used to obtain transmission for retail

access over a distribution cooperative’s

system.

Southern claims that cooperatives

have argued in courts and in Congress

that a G&T cooperative and its

distribution cooperative owners are

unified economic interests in which the

interest of the whole is equal to the sum

of the parts, and that federal courts have

upheld this view (citing one case—City

of Morgan City v. South Louisiana

Electric Cooperative Ass’n, 49 F.3d 1074

(5th Cir. 1995) (Morgan City)).

EEI claims that clarification of certain

aspects of reciprocity is needed: (1)

public utilities may not be able to

determine if reciprocal service is

comparable because non-public utilities

do not have to provide Form 1 data, and

thus non-public utilities should be

required to submit additional data; (2)

non-public utilities should be required

to functionally unbundle, charge rates to

themselves and others that reflect the

cost of using the system themselves,

comply with the standards of conduct,

and establish an OASIS; (3) non-public

utility members of an RTG should be

required to offer reciprocal service

comparable to that provided by public

utility members; and (4) a non-public

utility should be required to provide all

services it is reasonably capable of

providing. Carolina P&L adds that a

customer should be required to provide

the full panoply of transmission services

that it is capable of providing because

the customer has a right to take any type

of service from the transmission

provider even though it may only

choose one particular service.

Tucson Power asks the Commission to

clarify how it will determine the

comparability of a non-public utility’s

tariff. It asserts that first, under the safe

harbor option, the Commission should

clarify (1) that non-public utilities must

comply with the Commission’s rules of

practice and procedure, and (2) how it

will determine that the rates, terms and

conditions of the reciprocal service are

comparable to the service the nonpublic utility provides itself (Tucson

Power argues that this could require

submittal of data comparable to that

contained in Form 1). Second, the

Commission should eliminate the

option that would require the public

utility to determine whether the request

by the non-public utility is consistent

with the tariff. Finally, under the RTG

option, the Commission should clarify

that the evidentiary requirements for

non-public utilities that are members of

an RTG will be the same as for nonpublic utilities using the safe harbor

procedure, i.e., any disputes regarding

compliance should be resolved by the

Commission, not the RTG.

A number of utilities assert that the

Commission should not limit the right

to obtain reciprocity only to the public

utility that provides the transmission

service because power could actually

flow over other public utilities’

transmission lines. They argue that the

Commission should ensure that open

access transmission is as widely

available as possible.322 EEI asserts that

Federal power marketing agencies,

including BPA, should be required to

provide comparable open access

transmission.

Oklahoma G&E argues that Order No.

888 violates the Constitution’s equal

protection principles because it does not

require universal open access. It asserts

that the Commission has created an

arbitrary distinction between classes of

utilities that is unrelated to the

Commission’s objective and therefore is

constitutionally invalid. Oklahoma G&E

contends that the proper approach is to

proceed under EPAct for all transmitting

utilities on a case-by-case basis.

Detroit Edison asks the Commission

to clarify that the supplier and the

recipient of power are direct

beneficiaries and must be considered

transmission customers for reciprocity

purposes. Otherwise, Detroit Edison

contends, parties from jurisdictional

transmission transactions may be able to

evade reciprocity.

Reciprocity Provision—Other

Arguments

CCEM argues that reciprocity should

be expanded to require a transmission

customer obtaining open access service

also to provide open-access

transmission service to all eligible

customers. Otherwise, CCEM maintains,

transmission owners will be able to

penetrate into wholesale markets

controlled by non-public utilities, but

power marketers will not.
12338 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

323FERC Stats. & Regs. at 31,762; mimeo at 374.

324As discussed infra, non-public utilities may

seek a waiver of the reciprocity condition. We

therefore reject Tallahassee’s argument that we are

excluding an entire class of transmission customer

from open access, i.e., those unable to grant

reciprocal service. If the Commission determines

that a particular customer truly is not able to

reciprocate, the reciprocity condition can be

waived. These situations are obviously different

from situations involving entities that do not wish

to provide reciprocal service.

325See Public Service Electric & Gas Company, 78

FERC ¶ 61,119, slip op. at 4 and n.7 (1997).

326With regard to the basic substantive

protections such as reliability, opportunity to

recover costs, and the standards for rates, terms and

conditions of transmission service, we see no

relative distinctions between sections 211 and 212

and sections 205 and 206 of the FPA.

327 In response to Southern’s citation to Morgan

City, while this case provides some background as

to the relationship between G&T cooperatives and

distribution cooperatives, it in no way suggests that

the relationship rises to the level of a corporate

affiliation.

328However, in response to Umatilla Coop, we

clarify that to the extent a distribution cooperative

purchases power from an affiliated cooperative that

is acting as a power marketer, the distribution

cooperative will be subject to the reciprocity

condition because of the marketing affiliate

relationship between the two. Moreover, as we

explained in the Final Rule, the reciprocity

condition also applies to any entity that owns,

controls or operates transmission facilities and that

uses a marketer or other intermediary to obtain

access. FERC Stats. & Regs. at 31,763; mimeo at 378.

329FERC Stats. & Regs. at 31,760; mimeo at 370.

330See South Carolina Public Service Authority

(Santee Cooper), 75 FERC ¶ 61,209 (1996); Central

Electric Cooperative, Inc., 77 FERC ¶ 61,076 (1996).

Of course, the non-public utility can always seek a

waiver of the OASIS and standard of conduct

requirements. Such a waiver request will be

CCEM asks the Commission to clarify

that when a non-public utility obtains

open access from a power pool, member

of a power pool, or parties to some form

of bilateral coordination agreement, its

reciprocity obligation extends to all

eligible customers, including all

members of the pool or parties to the

agreement.

Commission Conclusion

We continue to believe that it is

appropriate to condition the use of

public utility open access tariffs on the

agreement of the tariff user to provide

reciprocal access to the transmission

provider. No eligible customer,

including a non-public utility, that takes

advantage of non-discriminatory open

access transmission tariff services

should be allowed to deny service or

otherwise discriminate against the open

access provider. As we explained in the

Final Rule,

[n]on-public utilities, whether they are

selling power from their own generation

facilities or reselling purchased power, have

the ability to foreclose their customers’

access to alternative power sources, and to

take advantage of new markets in the

traditional service territories of other

utilities. While we do not take issue with the

rights these non-public utilities may have

under other laws, we will not permit them

open access to jurisdictional transmission

without offering comparable service in

return. We believe the reciprocity

requirement strikes an appropriate balance

by limiting its application to circumstances

in which the non-public utility seeks to take

advantage of open access on a public utility’s

system.[323]

Contrary to arguments raised on

rehearing, we are not requiring nonpublic utilities to provide transmission

access. Instead, we are conditioning the

use of public utility open access tariffs,

by all customers including non-public

utilities, on an agreement to offer

comparable (not unduly discriminatory)

services in return.324 It would not be in

the public interest to allow a non-public

utility to take non-discriminatory

transmission service from a public

utility at the same time it refuses to

provide comparable service to the

public utility. This would restrict the

operation of robust competitive markets

and would harm the very ratepayers that

Congress has charged us to protect. Very

simply, we refuse to take a head-in-thesand approach and order a remedy for

undue discrimination that will permit

the beneficiaries of the remedy to

engage in unduly discriminatory

actions.

Moreover, non-public utilities are free

to seek from a public utility a waiver of

the open access tariff reciprocity

condition. We note that this is a

modification of our statements in Order

No. 888, in which we said that nonpublic utilities could seek a voluntary

offer of transmission service from a

public utility on a bilateral basis. Since

the time Order No. 888 issued, we have

concluded that except in unusual

circumstances, public utility services

should be provided pursuant to the

open access tariff and not pursuant to

separate bilateral agreements.325 This

applies to all customers, including nonpublic utilities. Therefore, rather than

requesting a bilateral agreement in order

to avoid the reciprocity condition, nonpublic utilities instead may ask a utility

for a waiver of the reciprocity condition

in the utility’s open access tariff. We

disagree with Dairyland that this type of

alternative approach is illusory. If the

public utility chooses voluntarily to

grant a waiver, the reciprocity condition

would not apply.

We reject NRECA’s request that we

incorporate in the reciprocity condition

the statutory standards and protections

of FPA sections 211 and 212. NRECA

states on rehearing that mandated

services to third parties would endanger

cooperatives’ ability to provide service

to members, or increase members’ costs.

It further states that sections 211 and

212 provide substantive protections to

ensure continued service to the

transmitting utility’s own customers,

and to avoid their subsidization of

services to third parties. NRECA appears

to believe that these substantive

protections are not provided outside the

context of sections 211 and 212. We

disagree. We believe the protections that

NRECA is seeking are contained in the

pro forma tariff and, as required by

section 6 of the tariff, the non-public

utility must offer its service on similar

terms and conditions.326

We also reject requests that we not

grant the exception to reciprocity

provided in the Final Rule for

distribution cooperatives and joint

action agencies. We continue to believe

that if a G&T cooperative seeks open

access transmission service from the

transmission provider, then only the

G&T cooperative, and not its member

distribution cooperatives, should be

required to offer transmission service.327

Without a corporate affiliation between

G&T cooperatives and their member

distribution cooperatives, we do not

believe it is appropriate to apply the

reciprocity condition to the member

distribution cooperatives. To do so

would result in the member distribution

cooperatives being bound by their G&T

cooperatives.328

Carolina P&L has brought to our

attention a possible misunderstanding

as to the meaning of comparable

transmission service that a non-public

utility must agree to provide as a

condition of using an open access tariff.

Because a non-public utility may choose

any type of service from a public utility

transmission provider that the

transmission provider provides or is

capable of providing, we clarify that a

non-public utility seeking to take

service under the transmission

provider’s open access tariff must

likewise agree to offer to provide the

transmission provider any service that

the non-public utility provides or is

capable of providing on its system in

order to satisfy reciprocity. We note that

in the Final Rule we explained that

‘‘[a]ny public utility that offers nondiscriminatory open access transmission

for the benefit of customers should be

able to obtain the same nondiscriminatory access in return.’’ 329 In

this regard, because a public utility

must have an OASIS and a standard of

conduct for employee separation, so

must a non-public utility that seeks

open access transmission from a public

utility.330
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12339

evaluated under the same criteria applicable to a

waiver requests by a public utility.

331 In reaching this conclusion, we note that the

electric industry currently conducts business using

contract path pricing. If we are presented with a

regional proposal for flow-based pricing, we will

reconsider whether there is a need to expand

reciprocity as requested by certain entities.

332NRECA raises comparable questions with

respect to waiver procedures.

333See also TANC.

334WRTA supports NWRTA in NWRTA’s

rehearing request.

At the same time, however, we deny

requests to expand the reciprocity

condition.331 Although we believe that

non-public utilities should provide

open access transmission as a matter of

policy, to require non-public utilities to

offer transmission service to entities

other than the public utility

transmission providers increases the

chances that they could lose tax-exempt

status. Accordingly, we have adopted a

policy that recognizes the statutory tax

restrictions placed on non-public

utilities but also balances the

fundamental unfairness of requiring a

utility to make its facilities available to

someone who could use that access to

the competitive disadvantage of the

utility. Ultimately the public interest is

best served by nationwide open access

and, if the tax issue is favorably

resolved, we may revisit the matter.

Moreover, in response to Detroit

Edison, we take this opportunity to

clarify that reciprocity would apply to a

wholesale purchaser if a generation

seller obtains transmission service from

a public utility to sell to such purchaser

and such purchaser owns, operates or

controls interstate transmission

facilities. The same would be true where

the seller owns, operates and controls

interstate transmission facilities and the

buyer arranges for the transmission

service. Just as with marketers or other

intermediaries, we do not intend to

allow reciprocity to be defeated simply

on the basis of whether the seller or

buyer requests transmission. Such a

result would elevate form over

substance.

With respect to TDU System’s

assertion that reciprocal service should

not have to be rendered if it would

interfere with RUS loan financing, we

note that we have already indicated that

reciprocal service need not be provided

if tax-exempt status would be

jeopardized. If TDU Systems is arguing

that we should not require reciprocal

service if RUS attaches such a condition

in its regulation of RUS-financed

cooperatives, we reject such an

argument. Such cooperatives have the

option to seek bilateral service

agreements.

We reject EEI’s and Tucson Power’s

argument that non-public utilities must

provide Form 1 data in order to provide

comparable service. The Form 1 data

would be relevant only if the

Commission were setting non-public

utilities’ rates. Such a detailed review is

not necessary, however. See Santee

Cooper, 75 FERC ¶ 61,209 (1996).

Similarly, there is no need to have nonpublic utilities follow our Rules of

Practice and Procedure to satisfy

reciprocity.

Rehearing Requests

Safe Harbor/Waiver Provisions

NRECA states that the following

issues related to safe harbor status and

declaratory order requests need

clarification: (1) under what statutory

authority is the Commission considering

such petitions? (2) what rights do nonpublic utilities have to obtain review of

Commission determinations with which

they disagree? (3) how closely will a

reciprocal tariff have to conform to

Order No. 888 to win approval? (4) will

non-public utilities have to pay the

standard fee (now $11,550) with a

declaratory order petition? 332 and (5)

will the Commission allow non-public

utilities to include a stranded cost

recovery provision similar to section 26

of the pro forma tariff? 333

Oglethorpe asserts that the

Commission should not use these

procedures to assert jurisdiction over

non-public transmitting utilities.

Dairyland contends that requiring nonpublic utilities to invoke declaratory

order or waiver proceedings just to

assert the clear statutory protections

contained in sections 211 and 212 is

unwarranted.

TANC declares that the safe harbor

provisions do not cure the problems

created by reciprocity. It argues that the

safe harbor provision expands the

transmission access that must otherwise

be offered by non-public utilities, i.e.,

rather than just providing reciprocal

service to the transmission provider,

under the safe harbor provision, the

non-jurisdictional entity must offer

open access to any eligible customers.

Blue Ridge alleges that the safe harbor

and waiver provisions face practical

administrative problems. It asserts that

a waiver itself will result in disputes

and that the application of the waiver

principle to non-public utilities is based

on questionable statutory authority. It

requests that the Commission add the

following language to section 6 of the

tariff: ‘‘If the Transmission Customer is

a non-public utility, the Transmission

Provider must demonstrate a need for

transmission service from such entity.’’

(Blue Ridge at 39).

TAPS asks that the Commission

accord the filing of a waiver application

by a small non-public utility system, or

inclusion in an application of a sworn

statement of inapplicability, the same

protections afforded larger non-public

utility systems that file under the safe

harbor mechanism.

Arkansas Cities ask the Commission

to clarify that ‘‘utilities like Arkansas

Cities’ members, which do not operate

a control area, do not own

‘transmission’ facilities and primarily

purchase energy for resale at retail are

not subject to the transmission

reciprocity condition contained in

Order 888, and are also not required to

file a request for a waiver from the

requirements of Order 888 and 889.’’

(Arkansas Cities at 18–19)

SWRTA and NWRTA ask the

Commission to clarify that RTGs have

the authority to issue limited waivers of

the reciprocity requirements of Order

Nos. 888 and 889 to qualifying nonpublic utility members of RTGs, and

that the Commission will accord

deference to an RTG’s determination

with respect to a non-public utility

member’s request for waiver of, or

exemption from, these requirements.334

They note that SWRTA’s bylaws have a

Commission-approved waiver process

and disputes would go to arbitration or

to the Commission.

Southern and EEI argue that public

utilities should have a parallel ‘‘safe

harbor’’—the right to seek a declaratory

order as to whether the transmission

service being offered by a non-public

utility satisfies its reciprocity obligation.

Tallahassee asks that the Commission

clarify the good faith assertion a public

utility must make that the non-public

utility has not met the reciprocity

requirements. It asserts that the section

211 good faith request rules form an

appropriate standard by which to

measure a good faith assertion.

Commission Conclusion

Several entities raise procedural and

jurisdictional concerns with respect to

our safe harbor and waiver provisions.

At the outset, we emphasize that this

Commission does not have jurisdiction

over non-public utilities under sections

205 and 206 and that the safe harbor

mechanism and waiver provisions do

not, and indeed cannot, give us such

jurisdiction. Rather the safe harbor and

waiver procedures are voluntary means

for non-public utilities to obtain a

Commission determination that they

meet the reciprocity condition in the

open access tariffs and thereby avoid
12340 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

335 75 FERC at 61,694–95 (citing 18 CFR 381.108).

336 75 FERC at 61,701.

337 Id.

338Because we have not extended the reciprocity

condition to rate aspects of a non-public utility’s

tariff, we would not evaluate any stranded cost

recovery mechanism and, as with respect to all

terms and conditions of non-jurisdictional tariffs,

the Commission is without jurisdiction to enforce

such a charge.

339E.g., Santee Cooper, Omaha Public Power

District (filed petition for declaratory order on

October 17, 1996, which was docketed as NJ97–2–

000), Southern Illinois Power Cooperative (filed

petition for declaratory order on October 8, 1996,

which was docketed as NJ97–1–000).

340 76 FERC ¶ 61,009 at 61,027 (1996).

341FERC Stats. & Regs. at 31,761; mimeo at 372.

342For the same reason, we deny Tallahassee’s

request that we clarify the good faith assertion a

public utility must make that the non-public utility

has not met the reciprocity condition.

potential delays or denials of open

access service based on allegations that

the transmission requestor does not

meet reciprocity. In Santee Cooper,

issued subsequent to the Final Rule, the

Commission recognized that it lacks

jurisdiction under sections 205 and 206

over transmission rates, terms and

conditions offered by non-public

utilities, but explained that it has the

authority to evaluate non-jurisdictional

activities to the extent they affect the

Commission’s jurisdictional

responsibilities.

We clarify that non-public utilities

that disagree with a Commission

determination are free to request

rehearing of a Commission order, as

occurred in Santee Cooper. If aggrieved

by the Commission’s final order, they

may appeal under section 313 of the

FPA. Also, with respect to the filing fee

a non-public utility entity would have

to pay in making a declaratory order

request, the Commission in Santee

Cooper explained that its regulations

specifically exempt states,

municipalities and anyone who is

engaged in the official business of the

Federal Government from filing fees.335

Because of the nature of the safe harbor

and waiver provisions, we will also

waive the filing fee for declaratory

orders for all other non-public utilities

in these circumstances.

As to the question of how closely a

reciprocal tariff will have to conform to

Order No. 888, the Commission

determined in Santee Cooper that:

As part of its compliance filing * * * the

Authority must submit a single tariff that

conforms to the Open Access Rule pro forma

tariff.[336]

The Commission further explained that

‘‘[t]he Open Access Rule requires that

reciprocity tariffs contain terms and

conditions which substantially conform

or are superior to those in the Open

Access Rule pro forma tariff.’’ 337 We

clarify, however, that in that case the

utility chose to offer an open access

tariff, whereas Order No. 888 provides,

as a condition of service, that reciprocal

access be offered to only those

transmission providers from whom the

non-public utility obtains open access

service. Therefore, a non-public utility

may so limit the use of any voluntarily

offered tariff, as long as the tariff

otherwise substantially conforms to the

pro forma tariff. We also note that nonpublic utilities are free to enter into

bilateral agreements to satisfy the

reciprocity condition. With respect to

such bilateral reciprocal agreements, we

must leave these agreements to case-bycase determinations. Which terms and

conditions may be necessary for a nonpublic utility to provide reciprocal

service to the public utility in a bilateral

agreement is necessarily a fact-specific

matter not susceptible to resolution in a

generic rulemaking proceeding.

Additionally, we clarify that non-public

utilities may include stranded cost

recovery provisions in any reciprocity

tariffs that they may file.338

In response to TANC’s concern that

the safe harbor provision expands the

transmission access that must otherwise

be offered by non-public utility entities,

and Blue Ridge’s concern that the safe

harbor and waiver provisions raise

practical administrative problems, we

emphasize that both of these procedures

are purely voluntary and a non-public

utility can avoid any perceived

problems simply by not taking part in

either process. We note that several

entities have voluntarily availed

themselves of these procedures without

any apparent hardships.339

Arkansas Cities’ various waiver

requests are best addressed on a case-bycase basis that permits a full airing of

the factual circumstances surrounding

each entity seeking a waiver. As we

explained in a recent order, ‘‘the

Commission will not address waiver

requests in a generic rulemaking

proceeding, but will require entities

seeking waiver of all or part of Order

Nos. 888 and 889 to submit separate,

fact-specific requests. * * *’’ 340

EEI’s and Southern’s request that

public utilities be provided a parallel

‘‘safe harbor’’ (i.e., the right to seek a

declaratory order as to whether the

transmission service being offered by a

non-public utility satisfies its

reciprocity obligation) is denied. In the

Final Rule, we explained that a public

utility may refuse to provide open

access transmission service to a nonpublic utility if its denial is based on a

good faith assertion that the non-public

utility has not met the Commission’s

reciprocity requirements. 341 Moreover, a

public utility can file a petition to

terminate transmission service if a nonpublic utility is violating the reciprocity

condition of its open access service

agreement with the public utility.342

In response to SWRTA and NWRTA’s

request to clarify that RTGs have the

authority to issue limited waivers of the

reciprocity conditions of the Order No.

888 pro forma tariffs, we recognize that

RTGs have procedures in place to

resolve disputes that may arise

concerning a non-public utility

member’s request for service from a

public utility member. Because RTGs

have these dispute resolution

procedures in place, we clarify that

RTGs, which are in themselves

reciprocal voluntary arrangements, may

determine whether to apply reciprocity

between and among member public

utilities and member non-public

utilities, subject to the RTG dispute

resolution procedures authorized by this

Commission.

Rehearing Requests

Retail Wheeling

Dairyland contends that the

Commission improperly requires a nonpublic utility to provide retail wheeling

if it uses the open access tariff of a

public utility that allows retail access

either voluntarily or as part of a statemandated program.

Commission Conclusion

Contrary to Dairyland’s contention,

nothing in the Final Rule requires a

non-public utility to provide retail

wheeling. Section 212(h) of the FPA

explicitly prohibits the Commission

from ordering retail transmission

directly to an ultimate consumer. If a

non-public utility offers reciprocal

service, its tariff would have to include

the same explicit provision contained in

the pro forma tariff, which states that an

eligible customer cannot obtain

transmission that would violate section

212(h) of the FPA, unless pursuant to a

state program that requires the

transmission provider to offer such

wheeling.

Rehearing Requests

OASIS

Southern argues that the Commission

should explicitly require that nonpublic utilities must comply with Order

No. 889 as part of the reciprocity

obligation.

Commission Conclusion

We agree with Southern and, as

discussed above, absent a waiver, will
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12341

343FERC Stats. & Regs. at 31,689; mimeo at 156.

344FERC Stats. & Regs. at 31,761; mimeo at 373.

345 32–3 Int’l Legal Materials 682 (1993); 19

U.S.C.A. § 3301 et seq. (1995 Supp.)(legislation

implementing NAFTA).

346Ontario Hydro at 4–7.

347Ontario Hydro at 5.

348Ontario Hydro at 5, 3.

349NAFTA Article 301, citing GATT, 61 Stat. A5,

A18–A19 (1947). ‘‘Goods’’ under NAFTA include

transmission service. NAFTA, Articles 606, 609.

350 Iroquois Gas Transmission System, L.P., et al.,

53 FERC ¶61,194 at 61,700–01 (1990), aff’d sub

nom. Louisiana Association of Independent Power

Producers and Royalty Owners v. FERC, 958 F.2d

1101 (D.C. Cir. 1992), quoting United States-Canada

Free Trade Agreement Implementation Act of 1988,

Report of the Committee on Energy and Commerce,

House of Representatives, H.R. Rep. No. 100–816,

Part 7, 100th Cong., 2d Sess. at p. 7 (1988). The Free

Trade Agreement is a predecessor to NAFTA.

351We have no section 205–206 jurisdiction over

non-public United States utilities, just as we have

no jurisdiction over foreign entities. Ontario

Hydro’s claim that the Open Access Rule ‘‘makes

open access the law of the land for wholesale

transmission service within the United States’’ is

wrong; open access is not the law of the land for

United States non-public utilities, since we have no

section 205–206 jurisdiction over them.

352United States public utilities, of course, are

separately required by Order No. 888 to have on file

open access tariffs and thus meet reciprocity

through the separate, more stringent open access

requirement.

353Ontario Hydro also complains that the

reciprocity obligation of domestic non-public

utilities is subject to various limitations and waiver

provisions. These provisions apply to foreign

entities as well.

354 In recent cases involving the mitigation of

transmission market power of Canadian utilities

that are affiliates of power marketers that seek to

sell power at market-based rates in the United

States, the Commission has explicitly

acknowledged the sovereign authority of Canadian

governments over Canadian entities and has said

that we will be ‘‘amenable to a variety of

approaches’’ for foreign utilities to mitigate

Continued

require non-public utilities to comply

with Order No. 889 as part of the

reciprocity obligation.

Rehearing Requests

Foreign Entities

In the Open Access Rule, we decided

that a foreign entity that otherwise

meets the eligibility criteria should be

able to obtain service under a United

States public utility’s open access tariff.

However, like United States non-public

utilities (which also are not under our

section 205–206 jurisdiction), a foreign

entity that owns or controls

transmission facilities and that takes

transmission service under a United

States public utility’s open access tariff

must comply with the reciprocity

provision in the tariff.343 The reciprocity

provision ensures that when a public

utility provides service under its open

access tariff to a transmission-owning

entity that is not subject to the open

access requirement, the public utility

will be able to receive service in turn

from that entity. In our discussion of the

reciprocity provision, we pointed out

that if a non-jurisdictional entity that

owns or controls transmission does not

wish to provide service to the public

utility, it can choose not to use the

public utility’s open access tariff and

can instead seek voluntary service from

the public utility on a contractual

basis.344

On rehearing, Ontario Hydro argues

that the Commission has ‘‘unilateral[ly]

impos[ed]’’ the reciprocity requirement

on foreign entities in violation of the

North American Free Trade Agreement

(NAFTA).345 It declares that

[u]nder the principle of national treatment,

the citizens of each party to NAFTA * * *

are allowed the same market access within

another treaty party’s market as is provided

to the citizens of such other party. A party

to these agreements cannot withhold access

to its market by conditioning it upon receipt

of equal access into the market of another

party, because the result would be market

access less favorable for the other party

* * * than that accorded the party’s own

citizens. 346

Ontario Hydro claims that the Open

Access Rule ‘‘makes open access the law

of the land for wholesale transmission

service within the United States * * *’’

and that Canadian entities are thus

entitled to such access on an

unconditional basis.347 Next, it accuses

the Commission of trying to ‘‘coerce’’

Canada to ‘‘conform its market access

policy’’ to United States policy and of

‘‘impos[ing] U.S. regulatory policies’’ on

Canadian markets.348 Finally, Ontario

Hydro argues that even aside from the

NAFTA issue, under the FPA the

Commission does not have jurisdiction

over foreign entities and thus cannot

require reciprocity.

Commission Conclusion

We disagree with Ontario Hydro’s

claim that NAFTA’s national treatment

principle requires us to allow a

Canadian transmission-owning entity

(or its corporate affiliate) to take

advantage of a United States public

utility’s open access tariff—a tariff we

have required the utility to adopt—

while simultaneously refusing to allow

the United States utility to use the

Canadian entity’s transmission facilities.

NAFTA’s national treatment principle

requires that each signatory ‘‘accord

national treatment to the goods’’ of other

signatories in accordance with Article

III of the General Agreement on Tariffs

and Trade (GATT).349 National

treatment means that the United States

‘‘must not discriminate between foreign

and domestic energy on the basis of

nationality * * *’’ and that Canadian

electricity must be treated ‘‘no less

favorabl[y] than U.S. electricity, under

all U.S. laws and rules respecting the

sale, * * * distribution, and use of

* * * electricity.’’ Thus, this

Commission must accord Canadian

energy supplies treatment that is no less

favorable than the treatment accorded

United States supplies.350 Ontario

Hydro’s interpretation, however, would

twist this principle into a requirement

that Canadian entities be treated better

than United States entities, including

United States non-public utilities that

are subject to the reciprocity

condition.351

Under Order No. 888, all public

utility open access tariffs contain a

reciprocity condition that applies to all

users of the tariff within the United

States, including United States nonpublic utilities, unless the condition is

waived either by the Commission or the

public utility provider. Under the

reciprocity condition, non-public

utilities do not have to offer an open

access tariff (i.e., a tariff that offers

transmission service to any eligible

customer), but rather must offer

comparable transmission services only

to those transmission providers whose

open access tariffs the non-public utility

uses.352 The same condition applies to

foreign utilities. Thus, Ontario Hydro is

in plain error in arguing that application

of the reciprocity condition to foreign

entities would result in less favorable

treatment than that accorded to United

States citizens. Ontario Hydro’s reading

of NAFTA would place transmissionowning Canadian entities (or their

corporate affiliates) in a better position

than any domestic entity; not only

would Canadian entities not be subject

to the open access requirement, but,

unlike domestic non-public utilities,

they would be able to use the open

access tariffs we have mandated without

providing any reciprocal service.

Ontario Hydro has cited no precedent

demonstrating that NAFTA imposes

such an unreasonable requirement.353

Moreover, we are not ‘‘coercing’’

Canada into adopting our policies or

‘‘imposing’’ open access on Canadian

entities; we are simply placing the same

condition on a Canadian entity’s use of

a United States utility’s open access

tariff as on a domestic non-public

utility’s use of that tariff. However,

consistent with the approach we have

taken in other contexts involving foreign

utilities seeking to transact in United

States electricity markets, we are

amenable to a variety of approaches for

Canadian utilities to meet the

reciprocity condition.354
12342 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

transmission market power. British Columbia

Power Exchange Corporation, 78 FERC ¶61,024

(1997); accord, TransAlta Enterprises Corporation,

75 FERC ¶61,268 (1996) and Energy Alliance

Partnership, 73 FERC ¶61,019 (1995).

355EEI and Ontario Hydro note that section 6 of

the tariff limits the obligation of foreign utilities to

provide reciprocal service to ‘‘facilities used for

transmission of electric energy in interstate

commerce owned, controlled or operated by the

Transmission Customer. . . .’’ (EEI at 14). This is

inconsistent with the preamble, which says that the

reciprocity provision applies to foreign entities

(whose transmission facilities may not be

‘‘interstate’’). We recognize that the language in

section 6 of the pro forma tariff conflicts with the

preamble language of the Final Rule. We are

modifying section 6 of the tariff accordingly.

356We do have jurisdiction over many non-public

utilities under certain sections of the FPA, e.g.,

sections 210, 211 and 212.

357Oxbow Power Marketing, 76 FERC ¶ 61,031 at

61,179 (1996), reh’g pending. We did note,

however, that the QF would become a public utility

to the limited extent it provides transmission

service over its line on behalf of others.

358See Order Clarifying Order Nos. 888 and 889

Compliance Matters, 76 FERC ¶ 61,009 at 61,027

(1996).

Ontario Hydro is also wrong in its

claim that even aside from NAFTA, we

lack authority under the FPA to require

reciprocity when a foreign entity wishes

to use a domestic utility’s open access

tariff. Just as we are not asserting

jurisdiction over domestic non-public

utilities under sections 205 or 206 of the

FPA, we also are not asserting

jurisdiction over foreign entities. Rather,

we are simply placing the same

reasonable and fair condition on both

types of entities’ uses of the

transmission ordered in the Final

Rule.355

Rehearing Requests

Unconstitutional as Applied to NE

Public Power District

NE Public Power District asserts that

the reciprocity provision as applied to

NE Public Power District (a public

corporation and political and

governmental subdivision under

Nebraska law) is unconstitutional. It

argues that reciprocity would intrude

into the sovereignty of Nebraska and

would negate the decision of Nebraska’s

citizens to use their own governmental

institutions to provide electric service.

Moreover, contrary to the Commission’s

assertion, NE Public Power District

states that it does not have a real choice

in deciding whether to use the

transmission service of public utilities.

Because it is beyond the power of

Congress to compel Nebraska to adopt a

federally prescribed program for

providing its citizens with electric

utility services, NE Public Power

District argues that it must follow that

a federal agency lacks the constitutional

and statutory authority to compel a

Nebraska state instrumentality to adopt

a FERC-drafted tariff and to modify its

contracts.

NE Public Power District states that

section 201(f) of the FPA exempts stateowned utilities from the jurisdiction of

the Commission and that sections 211–

213 are the exclusive means by which

the Commission can require non-public

utilities to perform involuntary

transmission service. It asserts that the

Commission should exempt publiclyowned utilities from application of the

Final Rule and notes that virtually all

non-public utility entities are, or soon

will be, voluntary participants in power

pools, RTGs, or other similar

organizations. Thus, NE Public Power

District argues that there is no

compelling public interest to require

these entities now to submit to the

reciprocity provision.

In addition, NE Public Power District

argues that compliance would conflict

with Nebraska law and bond covenants,

i.e., Nebraska law, for example, does not

permit a public entity to agree in

advance of a dispute to submit to

binding arbitration. NE Public Power

District states that it is bound by a bond

covenant that prohibits it from

rendering service free of charge and

requires that a customer’s default must

be cured within a specific time. It also

argues that these requirements are in

conflict with section 7.3 of the pro

forma tariff.

Commission Conclusion

Under the Supremacy Clause of the

Constitution, Nebraska law cannot and

does not override this Commission’s

authorities and responsibilities under

the FPA. Rather, this Commission has

exclusive jurisdiction over the rates,

terms and conditions of transmission in

interstate commerce by public utilities,

including reciprocity conditions

contained in the tariffs of public

utilities. Nothing in Order No. 888

compels Nebraska to adopt a ‘‘federally

prescribed program.’’ While we do not

have full jurisdiction over non-public

utilities,356 our actions in regulating

jurisdictional matters may impact those

who wish to use jurisdictional services

or to enter into agreements with public

utilities. The Commission’s obligation is

to ensure that public utilities’ services

are just and reasonable and not unduly

discriminatory or preferential and nonpublic utilities can choose to comply or

not regarding matters within our

exclusive jurisdiction. Moreover, as we

explained above, NE Public Power

District can seek waiver of the

reciprocity condition on a case-by-case

basis.

Rehearing Requests

QF Position

American Forest & Paper asks the

Commission to clarify that QFs are

exempted from the reciprocity

requirement or, in the alternative, grant

them a blanket waiver. It states that QFs

are not allowed to provide transmission

service for third parties. Moreover, it

asserts that there are unlikely to be

many requests for transmission service

over a QF’s interconnection line and

such cases should be handled on a caseby-case basis.

Commission Conclusion

We will not grant QFs an exemption

from the reciprocity condition or grant

them a blanket waiver, but will address

this issue on a case-by-case basis if and

when it arises. Because most QFs own

little transmission, it is not likely that

they will be asked to provide reciprocal

service.

Furthermore, in a proceeding

involving a QF, we explained that use

of a QF’s transmission line by a non-QF

would not affect its QF status:

It would not fail the ownership test for QF

status because, consistent with the

requirements of the Public Utility Regulatory

Policies Act of 1978 (PURPA), the Oxbow

Geothermal facility would continue to be

‘‘owned by a person not primarily engaged in

the generation or sale of electric power (other

than electric power solely from cogeneration

facilities or small power production

facilities).’’ 16 U.S.C. § 796(18)(B)(1994).[357]

If a QF that owns, controls or operates

interstate transmission facilities seeks

open access transmission from a public

utility, it must agree to provide

reciprocal service to that public utility.

Of course, the QF could file a waiver

request in a separate proceeding, as set

forth in the Final Rule and clarified in

a subsequent order.358

Rehearing Requests

Tax-Exempt Financing Issues

Reciprocity and Private Activity Bonds

EEI asks the Commission to require

non-public utilities claiming that their

tax status is a bar to granting reciprocity

to substantiate such claim in a safe

harbor proceeding and to take

reasonable measures to request the IRS

to allow them to provide reciprocal

service while retaining their tax status.

If the Commission decides not to require

a safe harbor proceeding, EEI requests

that the Commission require non-public

utilities to substantiate their tax

concerns and to demonstrate to each

public utility from which they seek

service that they are actively pursuing
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12343

359See also Tucson Power.

360See also SoCal Edison. It asserts that the

Commission should require publicly-owned

utilities to provide open access on the same terms

as other utilities after a short transitional period

that provides an opportunity for the IRS and/or

Congress to address the interrelationship between

open access transmission and tax-exempt financing.

361We note that on January 10, 1997, the IRS

issued final regulations on the definition of privateactivity bonds applicable to tax-exempt bonds

issued by state and local governments, but reserved

section 1.141–7 dealing with output contracts to

further consider the issues raised by regulatory

changes in the electric power industry. 62 FR 2275

(January 16, 1997).

the issue with the IRS.359 It also urges

that the Commission require any request

for exemption from the reciprocity

requirement that is based on jeopardy to

tax-exempt status be filed with the

Commission as part of a request for

declaratory order in a safe harbor

proceeding. Moreover, it requests that

the Commission require a non-public

utility to specifically identify the

facilities it cannot use without

jeopardizing its tax-exempt financing

and to provide copies of, and

specifically reference the tax provisions

in, the related financing agreements that

embody this restriction.

Centerior asks that the Commission

condition receipt of open access

transmission service by municipal

utilities upon the elimination or

mitigation of tax subsidies and

regulatory inequities. Southern

maintains that tax-exempt status can

remain undisturbed if non-public

utilities do not seek open access

transmission service from public

utilities. Thus, Southern asserts, nonpublic utilities can weigh the benefits of

transmission service under the Final

Rule against the potential threat to their

tax benefits, and make the choice that

serves their best interest. At a minimum,

it argues, the Commission should await

the determinations of the IRS before

finalizing this aspect of the reciprocity

provision, rather than confer yet another

unique benefit on non-public

utilities.360

CAMU asks that the Commission

defer reciprocity obligations until the

IRS has clarified the status of private

use limitations within the context of

transmission access. Otherwise, CAMU

asserts, innocent investors could suffer

penalties because the Commission

moved too quickly on this sensitive

issue.

Local Furnishing Bonds

Local Furnishing Utilities and ConEd

state that section 5.1 of the pro forma

tariff applies to ‘‘Transmission Service,’’

which is defined in section 1.48 to

include point-to-point service, but not

network service. They ask the

Commission to clarify that the phrase

‘‘transmission service’’ also applies to

network service.

Local Furnishing Utilities and ConEd

ask that the Commission confirm that all

costs associated with the loss of taxexempt status, including defeasing,

redeeming, and refinancing tax-exempt

bonds, will be considered costs of

providing transmission that must be

borne by the customer for whom the

transmission is provided. They state

that defeasance and refinancing costs

are just as attributable to the particular

transmission service causing such

defeasance or redemption as the costs of

expanding the system are attributable to

the service that cause the need for such

expansion. They ask that the

Commission clarify that a transmission

provider may include in its tariff a

provision permitting the recovery of

such costs, even if a filing under section

205 of the FPA is required. ConEd

asserts that if a customer does not want

to pay costs associated with the loss of

tax-exempt status on the bonds, the

Commission should allow the

transmission provider to decline to

provide the requested service.

Local Furnishing Utilities and ConEd

also assert that section 5.2 of the pro

forma tariff should be clarified to state

that issuance of a section 211 order by

the Commission is a condition

precedent to the provision of

transmission service. Local Furnishing

Utilities states that there is a question

whether the Commission should insist

on waiver of the issuance of a proposed

order under section 212(c). According to

Local Furnishing Utilities, the

negotiations that normally would follow

the issuance of a proposed order are

likely to provide the only opportunity to

demonstrate and review the costs

associated with the loss of tax-exempt

status.

Local Furnishing Utilities and ConEd

assert that sections 5.1 and 5.2(i) of the

pro forma tariff improperly limit the

safe harbor protection of section 1919 of

EPAct to transmission providers that

financed ‘‘transmission facilities’’ with

local furnishing bonds. Because of this,

they assert, the safe harbor is not

available to ConEd, all of whose local

furnishing bonds have been used to

finance its distribution system. They

argue that section 5.1 should apply to

service that would jeopardize the taxexempt status of bonds that finance

distribution or generation, as well as

transmission, facilities. NE Public

Power District contends that section

5.2(ii) should be amended ‘‘to make it

clear that interim service need not be

begun if rendering the service would

endanger the tax-exempt status of the

provider’s bonds, unless the customer

agrees to bear the financial

consequences of such loss of tax-exempt

status and has the wherewithal to do

so.’’ (NE Public Power District at 22–23).

SoCal Edison argues that local

furnishing utilities should be required

to comply with the Final Rule without

any exception based upon their taxexempt bonds.

Commission Conclusion

Private Activity Bonds

As we explained in Order No. 888, it

is not our purpose to disturb Congress’s

and the IRS’s determinations with

respect to tax-exempt financing. With

respect to private activity bonds, we

reaffirm our finding that reciprocal

service will not be required if providing

such service would jeopardize the taxexempt status of the transmission

customer’s (or its corporate affiliates’)

bonds used to finance such transmission

facilities. We remain hopeful that the

IRS in its private activity bond

rulemaking will, to the maximum extent

possible, remove regulatory

impediments that limit the ability of

industry participants to provide

reciprocal open access. As we indicated

in Order No. 888, after the IRS acts, we

will reexamine our policy to ensure that

the reciprocity condition is applied

broadly to achieve open access without

jeopardizing tax-exempt financing.361

We will reject the request of EEI and

Tucson Power that the Commission

require non-public utilities to

substantiate in a safe harbor proceeding

a claim that their tax status is a bar to

granting reciprocity. As we stated in

Order No. 888, if a non-public utility

has sought a declaratory order on a

voluntarily-filed tariff, we request that it

identify the services, if any, that it

cannot provide without jeopardizing the

tax-exempt status of its financing.

However, we cannot require that a nonpublic utility use the safe harbor

mechanism, whether to file a reciprocal

tariff with the Commission or to

substantiate a claim as to loss of taxexempt status. As we explain above, the

safe harbor procedure is a voluntary

means for non-public utilities to obtain

a Commission determination that they

meet the reciprocity condition in the

open access tariffs and thereby avoid

potential delays or denials of open

access service based on allegations that

the transmission requestor does not

meet reciprocity.

Nevertheless, just as we believe that it

is appropriate to condition the use of

public utility open access tariffs on the
12344 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

362 In response to EEI’s request that the

Commission require a non-public utility to provide

copies of, and specifically reference the tax

provisions in, the related financing agreements, we

note that the level of detail needed to substantiate

a non-public utility’s claim that providing

reciprocal transmission service would jeopardize

the tax-exempt status of its financing is likely to

depend on the facts of each case. As a result, what

will constitute adequate substantiation is properly

determined on a case-by-case basis. Additionally,

we will reject EEI’s request that the Commission

require non-public utilities to demonstrate that they

are actively pursuing the issue with the IRS. As we

explain above, the IRS is currently examining these

issues; we in turn will reexamine our policy after

the IRS acts to ensure that the reciprocity condition

is applied broadly to achieve open access without

jeopardizing tax-exempt financing.

363We will reject Centerior’s request that the

Commission condition receipt of open access

transmission service by non-public utilities upon

the elimination or mitigation of tax subsidies. As

we stated in Order No. 888, Congress has entrusted

the IRS with the responsibility for implementing

laws governing tax-exempt financing, and it is not

this Commission’s purpose to disturb Congress’s

and the IRS’s determinations in that regard.

364 In response to CAMU, we note that the

Commission has, in effect, deferred—pending IRS

action—a non-public utility’s reciprocity obligation

in cases in which the provision of reciprocal service

would jeopardize the tax-exempt status of the nonpublic utility’s financing.

365Of course if the transmission provider can

provide part of the requested service without

jeopardizing tax-exempt status, it should offer to

provide such service.

366Pro Forma Open Access Transmission Tariff,

Section 5.2(ii).

367We will reject Local Furnishing Utilities’

request that the Commission reconsider whether it

should insist on the transmission provider’s waiver

of the issuance of a proposed order under section

212(c). As Order No. 888 indicates, this aspect of

the local furnishing provision of the tariff is similar

to a provision included in the transmission tariff of

San Diego G&E, one of the Local Furnishing

Utilities. Waiver of the issuance of a proposed order

enables a transmission provider to expeditiously

provide service under section 5.2 of the pro forma

tariff, thereby ensuring that any local furnishing

bonds that may exist do not interfere with the

effective operation of an open access transmission

regime. Although Local Furnishing Utilities now

apparently support the issuance of a proposed order

on the basis that the negotiations that normally

would follow are likely to provide an opportunity

to review the costs associated with the loss of taxexempt status, we believe that any dispute as to

costs subsequently can be resolved without causing

any delay in the provision of the requested

transmission service. For example, the service

could be provided at the maximum rate allowed by

the Commission, subject to refund.

agreement of the tariff user to provide

reciprocal access to the transmission

provider, we also believe it is

appropriate to condition the use of

public utility open access tariffs on the

agreement of the non-public utility tariff

user to substantiate any claim that

providing reciprocal transmission

service would jeopardize the tax-exempt

status of its financing. The non-public

utility can provide such substantiation

by identifying for the customer the

services that it cannot provide without

jeopardizing its tax-exempt financing.362

Southern suggests that tax-exempt

status can remain undisturbed if nonpublic utilities do not seek open access

transmission service from public

utilities and, therefore, that non-public

utilities can weigh the benefits of

transmission service under the Rule

against the potential threat to their tax

benefits. We believe it is important to

remember why we required open access

in the first place—as a remedy for

undue discrimination in transmission

services in interstate commerce.

Southern would force a non-public

utility to give up a Congressionallymandated right as a condition to taking

open access transmission. Clearly

Southern’s suggestion is misplaced and

overbroad.363 For this reason, we

believe that our decision not to require

reciprocal service if providing such

service would jeopardize the non-public

utility’s tax-exempt financing—pending

action by the IRS in its private activity

bond rulemaking—is appropriate for the

time being.364 We reiterate that we will

reexamine our policy after the IRS acts.

As we state above, we believe that

ultimately the public interest is best

served by nationwide open access.

Local Furnishing Bonds

We clarify, in response to Local

Furnishing Utilities and ConEd, that the

reference to ‘‘Transmission Service’’ in

section 5.1 of the pro forma tariff was

intended to be to ‘‘transmission

service,’’ and thereby to apply to pointto-point service as well as network

service. We have revised section 5.1

accordingly.

We further clarify that all costs

associated with the loss of tax-exempt

status, including the costs of defeasing,

redeeming, and refinancing tax-exempt

bonds, are properly considered costs of

providing transmission services.

Therefore, a customer that takes service,

understanding that such service will

result in loss of tax-exempt status, shall

be responsible for such costs to the

extent consistent with Commission

policy, and a transmission provider may

include in its tariff a provision

permitting it to seek recovery of such

costs. We clarify that if the transmission

customer is not willing to pay the costs

associated with the transmission

provider’s loss of tax-exempt status, the

transmission provider will not be

required to provide the requested

service.365

Local Furnishing Utilities and ConEd

also ask the Commission to revise

section 5.2 of the pro forma tariff to state

that issuance of a section 211 order by

the Commission is a condition

precedent to the provision of

transmission service. Under the tariff

provision adopted by Order No. 888 to

address situations in which the

provision of transmission service would

jeopardize the tax-exempt status of any

local furnishing bonds used to finance

a local furnishing utility’s facilities, the

customer requesting transmission

service would tender an application

under section 211 of the FPA. Within

ten days of receiving a copy of the

section 211 application, the

transmission provider ‘‘will waive its

rights to a request for service under

Section 213(a) of the [FPA] and to the

issuance of a proposed order under

Section 212(c) of the [FPA] and shall

provide the requested transmission

service in accordance with the terms

and conditions of this Tariff.’’ 366 We

clarify that the Commission, upon

receipt of the transmission provider’s

waiver of its rights to a request for

service under section 213(a) and to the

issuance of a proposed order under

section 212(c), shall issue an order

under section 211.367 Upon issuance of

the order under section 211, the

transmission provider shall be required

to provide the requested transmission

service in accordance with the terms

and conditions of the tariff. Section 5.2

of the pro forma tariff has been revised

accordingly.

Local Furnishing Utilities and ConEd

also contend that the language of

sections 5.1 and 5.2(i) of the pro forma

tariff improperly limits the safe harbor

protection of section 1919 of EPAct to

transmission providers that financed

transmission facilities with local

furnishing bonds. ConEd expresses

concern that although all of its electric

local furnishing bonds have been used

to finance its distribution system, the

test as to whether those bonds have

been used for the ‘‘local furnishing’’ of

electricity is based in part on whether

ConEd has been a ‘‘net importer’’ of

energy into its service territory. As a

result, ConEd argues that the use of its

transmission system to wheel power

from a generating source located inside

ConEd’s service territory to a customer

located outside its service territory

could cause ConEd to violate the net

importer rule and thereby lose the tax

exemption for the bonds used to finance

its distribution system. ConEd asks the

Commission to modify sections 5.1 and

5.2 of the pro forma tariff to make clear

that those provisions apply to

transmission providers that have

financed any ‘‘facilities’’ (i.e.,

distribution and generation, not just

transmission, facilities) with local

furnishing bonds.

As we explained in Order No. 888, we

believe the local furnishing bonds
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12345

368ConEd suggests that this might occur if, for

example, the provision by ConEd of transmission

service were to cause it to violate the net importer

rule and thereby lose the tax exemption for bonds

used to finance its local distribution system.

Although we clarify above that section 5 of the pro

forma tariff would apply to this situation, we note

that it is not clear that wheeling required by the

Commission would be counted for purposes of

determining whether a public utility is a ‘‘net

importer.’’ In its committee report on the bill that

became the Energy Policy Act, the House Ways and

Means Committee stated:

The committee believes further that, in applying

the IRS ruling position that a local furnishing utility

that is interconnected with other utilities (other

than for emergency transfers of electricity) must be

a net importer of electricity, the determination of

whether the utility is a net importer should be made

without regard to electricity generated by another

party that is wheeled by the utility to a point

outside its service area pursuant to a FERC order

authorized under the bill.

H.R. Rep. No. 102–474(VI), 102d Cong., 2d Sess.

25 (1992), reprinted in 1992 U.S.C.C.A.N. 2232,

2236.

369FERC Stats. & Regs. at 31,763; mimeo at 377.

370NE Public Power District is a public

corporation and a political subdivision of the State

of Nebraska that generates, transmits and delivers

electric energy to wholesale and retail customers

throughout the state.

371NE Public Power District at 2. NE Public

Power District asserts that the Commission failed to

respond to this issue as raised by NE Public Power

District in its comments.

372Executive Order No. 12875, 3 CFR 699–71

(1994); 58 Fed. Reg. 58,093–094 (1993). The

Executive Order provides that, unless required by

statute, no Executive department or agency shall

promulgate any regulation that creates a mandate

upon state, local or tribal governments unless it

either: (a) provides the funds necessary to carry out

the obligations; or (b) before promulgating the

regulation, provides to the Director of the Office of

Management and Budget: (1) a description of its

consultation with the affected governments; (2) a

statement of their concerns and copies of

communications it has received from them; and (3)

the reasons why it thinks the regulations should

issue.

373The Unfunded Mandates Reform Act is Pub. L.

No. 104–4, 109 Stat. 48 (1995) (to be codified at 2

U.S.C. §§ 602, 632, 653, 658, 1501–1504, 1511–

1516, 1531–1538, 1551–1556 and 1571).

374 3 CFR at 670; 58 FR 58093 (1993).

375 3 CFR at 671; 58 FR at 58094 (1993) (emphasis

supplied).

376 90 Stat 50 (to be codified at 2 U.S.C. § 658).

377 42 U.S.C.A. § 7176 (1995) (Department of

Energy Organization Act) (P.L. 95–91, 91 Stat. 586)

(1977). See also Pub. L. No. 104–13, the Paperwork

Reduction Act of 1995 § 3502(5), 109 Stat. 165

(1995) (to be codified at 44 U.S.C. § 3502(5)), which

provides that ‘‘the term ‘independent regulatory

agency’ means [among other agencies] * * * the

Federal Energy Regulatory Commission.’’

378 109 Stat. 70 (to be codified at 2 U.S.C. § 1555)

(emphasis supplied).

379 I.e., those that own, operate or control

interstate transmission facilities and do not obtain

a waiver from the Commission.

provision in section 5 of the pro forma

tariff is necessary and appropriate so

that any local furnishing bonds that may

exist do not interfere with the effective

operation of an open access

transmission regime. If the provision of

transmission service pursuant to Order

No. 888 would result in the loss of taxexempt status for local furnishing

bonds, regardless of whether the

facilities financed with those bonds are

transmission, distribution, or generation

facilities, it is our intent that the

provisions of section 5 would apply.

Thus, we clarify in response to ConEd

and Local Furnishing Utilities that, to

the extent the provision of transmission

under an open access tariff would

jeopardize the tax-exempt status of local

furnishing bonds used to finance

distribution or generation facilities

(even if no transmission facilities were

financed with such bonds), 368 such

situation would fall within the reference

to ‘‘facilities that would be used in

providing . . . transmission service’’

contained in sections 5.1 and 5.2(i).

This is so because the loss of tax-exempt

status in such circumstances would be

directly attributable to the provision of

transmission services under the Rule.

Further, we said in Order No. 888 that

‘‘we will require any public utility that

is subject to the Open Access Rule that

has financed transmission facilities with

local furnishing bonds to include in its

tariff’’ a provision similar to section 5 of

the pro forma tariff.369 We clarify that

we did not intend by this statement that

the section 5 local furnishing bonds

provision would only apply to public

utilities that have financed transmission

facilities with local furnishing bonds,

and not those that have financed

generation and distribution facilities

with such bonds. As we explain above,

it is our intent that the provisions of

section 5 apply if the provision of

transmission service pursuant to an

open access tariff would result in the

loss of tax-exempt status for local

furnishing bonds, regardless of whether

the facilities financed with those bonds

are transmission, distribution, or

generation facilities.

Rehearing Requests

Unfunded Mandates Reform Act

NE Public Power District 370 argues

that the final regulations adopted in this

proceeding ‘‘constitute[] an unfunded

mandate under the Unfunded Mandates

Reform Act of 1995 * * * .’’ 371 It

declares that Order No. 888 imposes

significant costs upon local

governments and that the Commission

was required under the Unfunded

Mandates Reform Act to consider the

financial impact of its rulemaking upon

state and local governments and to

prepare and issue as part of its

rulemaking process a statement

containing certain specified analyses

and estimates concerning this matter

and a description of its pre-issuance

consultations with state and local

government authorities. To support its

argument NE Public Power District

relies upon: (a) Executive Order No.

12875, Enhancing the

Intergovernmental Partnership

(Executive Order); 372 and (b) the

Unfunded Mandates Reform Act of 1995

(the Act). 373

Commission Conclusion

We disagree with NE Public Power

District. The Executive Order applies to

every ‘‘executive department * * *

[and] agency. * * * ’’ 374 It defines

‘‘executive agency’’ as ‘‘any authority of

the United States that is an ‘agency’

under 44 U.S.C. § 3502(1), other than

those considered to be independent

regulatory agencies, as defined in 44

U.S.C. § 3502 (10).’’ 375 In section

3502(10), the Federal Energy Regulatory

Commission is defined as an

independent regulatory agency. As a

result, the Executive Order does not

apply to the Commission.

The Act similarly applies to federal

agencies, but, as with the Executive

Order, does not apply to independent

regulatory agencies. 376 Although the Act

does not define ‘‘independent regulatory

agency,’’ there is no indication that

Congress intended to exclude the

Commission from the definition. In fact,

in all instances in which Congress has

defined the term ‘‘independent

regulatory agency’’ of which we are

aware, the Commission has been

included.

As noted, the Commission is defined

as an independent regulatory agency in

Title 44 U.S.C. Also, Title 42 U.S.C.

§ 7176 provides that:

For the purposes of chapter 9 of title 5,

United States Code * * * [Executive

Reorganization], the [Federal Energy

Regulatory] Commission shall be deemed to

be an independent regulatory agency. [377]

Accordingly, we find that the

Commission is an independent

regulatory agency as used in the Act;

therefore, it is not covered by the Act.

Moreover, even if the Act applied to

the Commission, the Final Rule will not

impose a Federal mandate on state, local

or tribal governments.

Section 305 of the Act defines a

‘‘Federal mandate’’ as:

any provision in [a] statute or regulation or

[in] any Federal court ruling that imposes an

enforceable duty upon State, local, or tribal

governments[,] including a condition of

Federal assistance or a duty arising from

participation in a voluntary Federal

program.[378]

The Open Access Final Rule imposes

requirements only on certain public

utilities 379 and, pursuant to section

201(f) of the FPA, state and local
12346 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

380 Dayton Hudson Corp. v. Eldridge, 742 S.W. 2d

482, 485–86 (1987); Kerrigan v. Errett, 256 N.W. 2d

394, 399 (1977); Huey v. King, 415 S.W. 2d 136, 138

(1967); Black’s Law Dictionary 505 (6th ed. 1990).

381A state or municipal power authority, such as

NE Public Power District, does not have to agree to

reciprocity, and the Commission cannot force it to

do so. The Commission is not requiring state or

municipal power authorities to provide

transmission access. If non-public utilities elect not

to take advantage of open access services because

they don’t want to meet the tariff reciprocity

provision, they can still seek voluntary, bilateral

transmission service from public utilities.

382FERC Stats. & Regs. at 31,765–66; mimeo at

384–85.

383Coalition for Economic Competition, EEI,

KCPL, Florida Power Corp.

384See also EEI at 26 (suggesting ‘‘except in cases

of a finding by a trier of fact of gross negligence or

intentional wrongdoing by the Transmission

Provider’’).

governments, and their agencies,

authorities and instrumentalities, are

not public utilities. Additionally,

although the Final Rule will allow

public utilities’ transmission tariffs to

contain reciprocity provisions in order

to ensure that public utilities offering

open access transmission to others can

obtain similar service from open access

users, the reciprocity provision is not an

enforceable duty. A duty is mandatory;

it is an obligation to perform and is

compulsory. 380 The reciprocity

provision is merely a condition of

receiving a benefit, i.e., open access

transmission service from a public

utility. 381 There is no requirement that

NE Public Power District promulgate an

open access tariff and apply to FERC for

a declaratory order. Moreover, as we

explained above, non-public utilities,

such as NE Public Power District, are

free to seek from a public utility a

waiver of the open access tariff

reciprocity condition.

With regard to the Stranded Cost

Final Rule, while it applies to nonpublic utilities as well as public

utilities, it does not impose a duty on

any entity since it merely permits public

utilities and transmitting utilities to

seek recovery of certain costs. As a

result, since the Open Access and

Stranded Cost final rules will not

impose an enforceable duty on state,

municipal or tribal power agencies such

as NE Public Power District, the rules

are not Federal mandates as defined in

the Act.

Because the Unfunded Mandates

Reform Act of 1995 does not apply to

the Commission and, in any event, the

Open Access/Stranded Cost final rules

do not impose Federal mandates on

state, local or tribal governments, we

reject NE Public Power District’s

argument that the Unfunded Mandates

Reform Act of 1995 is applicable here.

5. Liability and Indemnification

In the Final Rule, the Commission

explained that the indemnification

provision was broken into two parts (set

forth in section 10.1 (Force Majeure)

and section 10.2 (Indemnification) of

the pro forma tariff).382 The Commission

explained that the first part is a force

majeure provision which provides that

neither the transmission provider nor

the customer will be in default if a force

majeure event occurs, but also provides

that both the transmission provider and

customer will take all reasonable steps

to comply with the tariff despite the

occurrence of a force majeure event.

The Commission explained that the

second portion of the provision

provides for indemnification against

third party claims arising from the

performance of obligations under the

tariff. The Commission limited the

indemnification portion of the provision

so that it is only the transmission

customer who indemnifies the

transmission provider from the claims

of third parties. The Commission

explained that the revised provision

provides that the customer will not be

required to indemnify the transmission

provider in the case of negligence or

intentional wrongdoing by the

transmission provider.

Rehearing Requests

A number of utilities argue that the

Commission has expanded transmitter

liability beyond the existing standard in

the industry, i.e., gross negligence.383

They assert that the Commission has

provided no basis to subject

transmission providers to liability,

including consequential damages, due

to ordinary negligence. KCPL points out

that 21 of 25 states addressing this issue

hold that a utility should not be liable

for ordinary negligence. It declares that

society will be worse off in litigation

expenses and wasted human resources

if utilities are held liable for simple

negligence. It adds that the electric

industry is much more susceptible to

liability from interruptions of service

than gas pipelines (refuting the

Commission’s reliance on Pacific

Interstate Offshore Company, which it

states is traceable to United Gas Pipeline

Co. v. FERC, 824 F.2d 417 (5th Cir.

1987)). Florida Power Corp asks the

Commission to modify section 10.2 to

provide that a customer must indemnify

the transmission provider except where

a finder of fact determines that the

transmission provider has committed

gross or intentional wrongdoing. It also

argues that the Commission should

eliminate liability of both the

transmission provider and the customer

to the other for consequential damages.

Southern argues that the exception

language in section 10.2 should be

changed to ‘‘except where a court has

determined that the Transmission

Provider has engaged in intentional

wrongdoing or has been grossly

negligent.’’ (Southern at 20–21).

Southern also argues that the

Commission should limit consequential

damages arising from negligence in the

operation of the transmission system.

Puget asserts that the exception

language in section 10.2 should be

changed to ‘‘except in cases of and to

the extent of comparative or

contributory negligence or intentional

wrongdoing by the Transmission

Provider.’’ (Puget at 18). It also asserts

that the Commission should exclude

liability for special, incidental,

consequential, or indirect damages.

EEI argues that the Commission

should add a new section 10.3: ‘‘If the

Transmission Provider is found liable

for any damages associated with this

Tariff, those damages shall be limited to

direct damages, and the Transmission

Provider shall not be liable for any

special, indirect or consequential

damages of any nature by virtue of the

transactions conducted under this

Tariff.’’ (EEI at 26).

Coalition for Economic Competition

argues that the Commission should

modify section 10.2 to provide that the

transmission provider will not be liable

to a transmission customer or any third

party for damages caused by

interruptions or irregular or defective

service, except if gross negligence or

wilful misconduct caused such

damages.384 Coalition for Economic

Competition asserts that the definition

of force majeure should include

ordinary negligence and asks that the

Commission clarify that a utility is not

liable for force majeure events.

CCEM also argues that transmission

customer indemnity in section 10.2

should attach only to legal actions

brought by customers of the

transmission customer or third-party

beneficiaries of those customers.

On the other hand, TDU Systems

argues that the indemnity provision

unfairly provides the transmission

provider with virtually total

indemnification for acts on its side of

the delivery point, but provides no

reciprocal protection to the transmission

customers for damage incurred on the

customers’ system in connection with

purchasing the transmission provider’s

services.
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12347

385See Tex-La Electric Cooperative of Texas, Inc.,

69 FERC ¶ 61,269 (1994) (requiring clarification that

force majeure clause in electric transmission

agreement does not excuse negligence); Avoca

Natural Gas Storage, 68 FERC ¶ 61,045 (1994)

(requiring modification of force majeure provision

to ensure that parties would be liable for negligence

or intentional wrongdoing).

386The Commission notes that in the past it may

have accepted agreements containing gross

negligence in force majeure and indemnification

provisions. Consistent with the Commission’s

general policy of not abrogating existing contracts,

we leave those provisions undisturbed.

387See, e.g., Pacific Interstate Offshore Company,

62 FERC ¶ 61,260 at 62,733–734 (1993) (requiring

amendment of indemnification provisions that

required indemnification except in cases of ‘‘gross

negligence’’).

388See, e.g., Texas Eastern Transmission

Corporation, 62 FERC ¶ 61,015 at 61,107 (1993).

389To date, the Commission has only issued a

suspension order in this proceeding.

CSW Operating Companies asks the

Commission to revise the pro forma

tariff to provide that a transmission

provider will not be liable for errors in

an estimate made in good faith and in

accordance with its published

procedure. They propose the following

language:

Information posted on the OASIS

concerning the availability of transfer

capability will be based on the Transmission

Provider’s best estimates given the

information readily and actually available to

the transmission provider. No such estimate

will be binding on the Transmission Provider

for any purpose.

Alternatively, they ask the Commission

to clarify that as long as a transmission

provider in good faith follows its

published methodology for determining

ATC and TTC it will be deemed not to

be negligent.

Commission Conclusion

The purpose of the force majeure

provision in the pro forma tariff is to

ensure that neither the customer nor the

transmission provider is held in default

in the event of an unpredictable and

uncontrollable force majeure event. It

was not the Commission’s intention that

the force majeure clause provide an

avenue for a party to claim that it is

excused from liability for its own

negligence. A force majeure event does

not include an act of negligence or

intentional wrongdoing. The pro forma

tariff will be changed accordingly.385

The purpose of the indemnification

provision is to allocate the risks of a

transaction, and the costs associated

with those risks, to the party on whose

behalf the transaction has been

conducted, the transmission customer.

As the tariff does not obligate the

customer to perform services on behalf

of the transmission provider, there is no

comparable basis for imposing an

indemnification obligation on the

transmission provider.386

As is explained in the Final Rule, the

Commission does not believe it

appropriate to extend the

indemnification obligation so that it

would apply even in cases where the

transmission provider has been

negligent. The contention that electric

transmission outages are either more

frequent or more costly than gas outages

does not serve to distinguish the electric

transmission situation from the gas

pipeline cases in which the Commission

has found that indemnification clauses

should not protect the pipeline owner

from its own negligence.387 In either

case, it would be inappropriate to

require the customer to indemnify the

transmission provider from damages

arising from the transmission provider’s

own negligence. We note, however, that

liability is a separate issue from

indemnification. Despite the absence of

indemnification protection, there is

nothing in the indemnification

provision that would preclude

transmission providers from relying on

the protection of state laws, when and

where applicable, protecting utilities or

others from claims founded in ordinary

negligence.

With respect to the issue of

consequential and indirect damages, the

indemnification provision already

provides protection to the transmission

provider from consequential and

indirect damage claims by third parties

except in cases of negligence or

intentional wrongdoing by the

transmission provider. The Commission

sees no need to further extend this

protection. Again, we note that liability

is a separate issue from indemnification,

and that nothing in these provisions

precludes transmission providers or

customers from relying, when and

where such law is applicable, on the

protection of statutes or other law

protecting parties from consequential or

indirect damages.

Furthermore, we will not revise the

pro forma tariff, as requested by CSW

Operating Companies, to provide that a

transmission provider will not be liable

for errors in an estimate made in good

faith or in accordance with its published

procedure. We believe that a utility

should have no different a liability

standard for operating an OASIS than

for its other operations.388

6. Umbrella Service Agreements

The Commission received requests for

clarification regarding this issue, which

was not specifically addressed by the

Commission in the Final Rule.

Rehearing Requests

SoCal Edison argues that it is too

burdensome to require a separate

Completed Application and a separate

Service Agreement to be executed for

each individual service transaction for

short-term firm and non-firm

transmission service (and filed with the

Commission). SoCal Edison contends

that requiring a separate service

agreement for each short-term firm

transaction to be filed with the

Commission will stifle transactions in

the short-term market. It indicates that

it suggested a simpler approach in

Docket No. ER96–222–000 that would

establish a non-transaction specific

Service Agreement and a Completed

Application that would contain the

specific transaction information, but

would not be filed with the

Commission, but would be made

available for audit.389

Commission Conclusion

SoCal Edison misinterprets the tariff

provisions regarding service agreements

for non-firm point-to-point transmission

service. Tariff section 14.5 details the

treatment of service agreements for nonfirm transmission service:

The Transmission Provider shall offer a

standard form Non-Firm Point-To-Point

Transmission Service Agreement

(Attachment B) to an Eligible Customer when

it first submits a Completed Application for

Non-Firm Point-To-Point Transmission

Service pursuant to the tariff. (Emphasis

added)

Moreover, in tariff section 18

(Procedures for Arranging for Non-Firm

Point-To-Point Transmission Service)

requires that a separate service

agreement be executed for each

individual service transaction as

claimed by SoCal Edison. In the pro

forma tariff, the Commission established

a non-transaction specific (or

‘‘umbrella’’) service agreement in an

attempt to streamline the application

procedures for non-firm point-to-point

transmission service. Therefore, the

service agreement for non-firm point-topoint transmission service need only be

executed and filed with the Commission

once, when the transmission customer

first applies for non-firm point-to-point

transmission service. Subsequent nonfirm transactions by the same customer

only require the submission of a

completed application (as provided in

tariff sections 18.1 and 18.2) by that

customer, which will be submitted via

the transmission provider’s OASIS

(when the OASIS is fully implemented).

Accordingly, no changes are required to
12348 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

390See changes to tariff sections 1.33, 1.34, 13.4,

13.7 and 17.3.

391FERC Stats. & Regs. at 31,752–53; mimeo at

346–47. 392FERC Stats. & Regs. at 31,752; mimeo at 346.

393FERC Stats. & Regs. at 31,753–54; mimeo at

349–50.

394E.g., NRECA, Blue Ridge, TDU Systems,

Cleveland, AEC & SMEPA, Wisconsin Municipals,

TAPS.

the application procedures for non-firm

point-to-point service.

However, we do find SoCal Edison’s

arguments persuasive that streamlined

procedures should also be applied to

applications for firm point-to-point

transmission service with a duration of

less than one year (short-term firm). We

agree that there is no compelling reason

to require the submission of separate

service agreements for every short-term

firm transaction. Accordingly, we will

adopt an ‘‘umbrella’’ service agreement

approach (as is currently used for nonfirm point-to-point transactions) and

require a service agreement of general

applicability to be filed with the

Commission when the first short-term

firm transaction is arranged between the

transmission provider and customer.

In order to facilitate an umbrella

service agreement approach for shortterm firm transmission service, minor

modifications have been made to several

sections of the pro forma tariff 390 as

well as to Attachment A (Form of

Service Agreement For Firm Point-ToPoint Transmission Service). Notably,

pages 3 and 4 of the service agreement,

containing transaction specific

information, is now required only for

long-term firm point-to-point

transmission service.

7. Other Tariff Provisions

a. Minimum and Maximum Service

Periods

In the Final Rule, the Commission

adopted a one-day minimum term for

firm point-to-point service.391 The

Commission also concluded that it will

not specify a maximum term for either

firm point-to-point or network

transmission service. However, the

Commission modified the tariff to

require that an application for

transmission service specify the length

of service being requested.

Rehearing Requests

CCEM states that a competitive

market for hourly trades should be

allowed to develop (transmission and

ancillary services). It argues that

contrary to the Commission’s goal of

comparability, the Rule effectively

allows only incumbent utilities to

participate in hourly markets on behalf

of their own or network loads (citing

section 13.1 of the pro forma tariff).

American Forest & Paper argues that

firm and non-firm service should be

made available on an hourly basis and

that the Commission should assure that

utilities make non-firm service

available.

Commission Conclusion

It is unclear as to what hourly

‘‘trades’’ CCEM is referring. If CCEM is

referring to off-system sales, the

transmission provider is obligated to

take transmission for any off-system

sales under point-to-point transmission

service under its tariff. Inasmuch as the

tariff does not require the provision of

hourly firm transmission, in order to

provide itself with hourly firm

transmission, the transmission provider

would either: (1) reserve firm point-topoint service on a daily basis in order

to participate in the hourly market or (2)

propose in a section 205 filing to modify

its tariff to voluntarily provide hourly

firm point-to-point service. Under either

circumstance, comparability would be

maintained as all point-to-point

customers would have equal access to

the hourly market.

If CCEM is referring to purchases,

hourly economy purchases by the

transmission provider on behalf of its

native load customers are also available

on a comparable basis to network

customers. However, if CCEM is

referring to specific purchases made on

behalf of a particular wholesale

customer, this resale must be provided

under point-to-point transmission

service, as described above.

The Commission has rejected hourly

firm point-to-point transmission service

as a mandatory service to be provided

under the Tariff.392 Many entities would

not oppose hourly firm service if

afforded a lower priority, i.e., if they

were curtailed before longer-term firm

services. However, with this lower

priority there may be little or no

difference between the pro forma tariff

non-firm service and curtailable firm

hourly service. The Commission

adopted the one-day minimum term for

firm service to address concerns that

customers would engage in ‘‘cream

skimming’’ by taking firm service only

during the hours at the daily peak while

taking non-firm service for other hours,

and thereby avoiding paying a fair share

of the costs of the transmission system.

However, this does not mean that the

Commission would not allow such

services if voluntarily proposed by a

transmission provider.

Finally, in response to American

Forest & Paper, the transmission

provider has every incentive to make

non-firm service available to all eligible

customers in order to benefit native load

customers, as the revenues generated by

this service are typically used as a

revenue credit to offset the costs of

providing firm service. In addition,

parties may raise concerns with the

Commission in a section 206 complaint

if the transmission provider offers nonfirm transmission service in a noncomparable, i.e., unduly discriminatory

fashion.

b. Amount of Designated Network

Resources

In the Final Rule, the Commission

indicated that it will not change the

limitation on the amount of resources a

network customer may designate. 393

The Commission explained that a

transmission provider is required to

designate its resources and is subject to

the same limitations required of any

other network customer.

The Commission further explained

that limiting the amount of resources to

those that the customer owns or

commits to purchase will protect a

utility from having to incur costs that

are out of proportion to the customer’s

load.

With respect to the allocation of

interface capacity under network

service, the Commission clarified that a

customer is not limited to a load ratio

percentage of available transmission

capacity at every interface. It explained

that a customer may designate a single

interface or any combination of interface

capacity to serve its entire load,

provided that the designation does not

exceed its total load.

Rehearing Requests

A number of entities state that section

30.8 of the pro forma tariff should be

clarified to conform to the Final Rule

preamble. The preamble states that a

network customer should not be limited

to a load ratio percentage of available

transmission capacity at every interface,

but may designate a single interface or

any combination of interface capacity to

serve its entire load, provided that the

designation does not exceed its total

load. However, they point out that

section 30.8 of the pro forma tariff

provides that a network customer’s use

of the transmission provider’s total

interface capacity with other

transmission systems may not exceed

the network customer’s load ratio

share.394

TAPS and Wisconsin Municipals ask

the Commission to clarify the

inconsistency by deleting the phrase

‘‘Ratio Share’’ at the end of the section

30.8. TAPS argues that section 30.8 of
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12349

395TAPS filed a response opposing these requests

for rehearing. (TAPS Response). As we explained

above, we will accept the TAPS Response.

396 74 FERC at 61,018.

397FERC Stats. & Regs. at 31,754; mimeo at 351.

398FERC Stats. & Regs. at 31,754–55; mimeo at

353.

399FERC Stats. & Regs. at 31,794; mimeo at 467.

400E.g., to protect wholesale purchasers—and, by

extension, ultimate consumers—from losing service

unjustly; to provide the Commission an opportunity

to ensure that the termination is just and

reasonable. 77 FERC at 61,171.

401 Id.

the tariff conflicts with the preamble,

other sections of the tariff itself (see

section 28), and recent Commission

orders (Wisconsin Public Service

Corporation, 74 FERC ¶ 61,022 at 61,064

and FMPA v. FPL, 67 FERC 61,167 at

61,484). It further argues that load ratio

restrictions on total interface usage

would expand the market power of

transmission providers.

EEI and Southern state that under

section 30.8 and the related preamble

language, it is unclear how the concept

of load ratio share should be applied in

the context of interface capacity, (i.e., is

the network customer entitled to a load

ratio share of available transmission

capacity or total transmission capacity

for an interface?). They argue that ATC

is the appropriate basis for calculating

shares of interface capacity and state

that the Commission should specify that

network service entitles the user to a

load ratio share of the available capacity

of each interface. EEI adds that if

sufficient interface capacity is available,

a request by a network customer to use

available interface capacity to bring in

resources for network load in excess of

its load ratio share of the interface

should be accommodated under the

point-to-point tariff and treated on a

first-come, first-served basis.395

Florida Power Corp states that ‘‘[i]n

order to clarify that network customers

may obtain transmission service over

the transmission provider’s interfaces in

excess of their load ratio shares, the

Commission should clarify that

additional interface capability may be

purchased (subject to availability) as

firm point-to-point transmission

service.’’ (Florida Power Corp at 29).

Commission Conclusion

We agree that the pro forma tariff

should be conformed to the preamble

language in the Final Rule so that the

interface capacity is limited to the

customer’s total load, not a load ratio

share. This is consistent with the

Commission’s recent rehearing order in

FMPA v. FPL:

We clarify that the phrase ‘‘that is, up

to its share of the load, 3%’’ was not

intended to limit FMPA’s use of each

interface to a discrete ratio (3%). Rather,

FMPA, as well as Florida Power, can

use each interface, if capacity is

available, to service its entire network

load. If the interface is [constrained]

[sic], they will either pay redispatch

costs or expansion costs based on their

load ratio share.[396]

c. Eligibility Requirements

In the Final Rule, the Commission

found that a non-discriminatory open

access transmission tariff must be made

available, at a minimum, to any entity

that can request transmission services

under section 211 and to foreign

entities. 397

Rehearing Requests

VT DPS and Valero state that the

Final Rule does not appear to

contemplate that marketers will buy

network service or that one network

service customer might serve a portion

of the requirements of another network

customer. Thus, they argue that network

load can be double counted. To resolve

this problem, they argue, service should

be made available to suppliers rather

than load, as provided in the NorAm

NIS tariff, Section 1.5.

Commission Conclusion

Power marketers are specifically

named in the definition of Eligible

Customer (Section 1.11), and nothing in

the Network Integration Transmission

Service prohibits marketers from serving

customers and designating those

customers’ loads (or portions thereof) as

the marketers’ Network Loads.

Additional rehearing requests

regarding eligibility are addressed in

Section IV.C.1. (Eligibility to Receive

Non-discriminatory Open Access

Transmission).

d. Two-Year Notice of Termination

Provision

In the Final Rule, the Commission

deleted the notice of termination

provision from the tariff.398

Rehearing Requests

No requests for rehearing addressed

this matter.

e. Termination of Service for Failure to

Pay Bill

In the Final Rule, the Commission

stated that section 7.3 of the Final Rule

pro forma tariff provides that in the

event of a customer default, the

transmission provider may, in

accordance with Commission policy,

file and initiate a proceeding with the

Commission to terminate service.399

Rehearing Requests

El Paso asserts that the Commission

does not have the authority to prohibit

a transmission provider from

terminating service to a customer that

has failed to pay its bill until permission

from the Commission has been

obtained. It argues that the Commission

does not have abandonment authority

under the FPA.

Commission Conclusion

El Paso is not correct. Under section

205 of the FPA, public utilities are

allowed to effectuate changes in rates,

charges, classification or service only

after providing 60 days notice to the

Commission and the public. Because a

termination of service is clearly a

change in service, public utilities must

file notice of a termination 60 days prior

to the proposed effective date.

In Portland General Electric

Company, 75 FERC ¶ 61,310, reh’g

denied, 77 FERC ¶ 61,171 (1996), we

denied a requested waiver of section

35.15 of the Commission’s Rules of

Practice and Procedure to permit the

utility to terminate service in the event

of customer default. We indicated that

we had previously explained the

reasons for requiring public utilities to

file notices of termination when seeking

to discontinue service 400 and further

explained that

electricity is not just any commercial good or

service. Rather, Congress in the Federal

Power Act has charged us with ensuring that

sales for resale or transmission of electricity

in interstate commerce by public utilities

take place at rates, terms and conditions that

are just and reasonable.[401]

f. Definition of Native Load Customers

The Commission defined the term

‘‘Native Load Customers’’ in section

1.19 of the pro forma tariff as:

The wholesale and retail power customers

of the Transmission Provider on whose

behalf the Transmission Provider, by statute,

franchise, regulatory requirement, or

contract, has undertaken an obligation to

construct and operate the Transmission

Provider’s system to meet the reliable electric

needs of such customers.

Rehearing Requests

The pro forma tariff defines native

load customers as ‘‘[t]he wholesale and

retail power customers of the

Transmission Provider. * * *’’

Cooperative Power argues that the

definition of native load customers

should recognize that joint planning is

a sufficient criterion, and that

construction and operation by the
12350 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

402 Dairyland filed a supplemental request for

rehearing raising similar arguments. (Dairyland

Supplement). We will accept this pleading as a

motion for reconsideration, not as a request for

rehearing, because it was not filed within the 30-

day statutory period for rehearing requests. See 16

U.S.C. § 8251(a).

403FERC Stats. & Regs. at 31,700; mimeo at 191.

404FERC Stats. & Regs. at 31,738; mimeo at 304. 405FERC Stats. & Regs. at 31,700; mimeo at 191.

transmission provider should not be

necessary for native load status to be

conferred. It asserts that under joint

planning, the loads of transmission-only

customers are considered native,

therefore the Commission should

eliminate the word power from the

definition.402

NRECA and TDU Systems state that

traditional wholesale customers that

have long been on the system, have

assisted in paying for past expansions,

and will likely continue to be captive to

a provider’s monopoly transmission

service, should have ‘‘native load

equivalent’’ rights if they take network

or long-term firm service. If the

transmission provider has planned and

will plan in the future for a customer’s

full or partial needs, they argue that the

customer should be treated as the

equivalent of native load. They point

out that section 1.19 of the tariff limits

native load status only to wholesale

power customers of the transmission

provider.

VA Com argues that the definition of

native load in section 1.19 of the tariff

should include existing distribution

cooperatives and others who currently

provide service to end users.

Commission Conclusion

We reject Cooperative Power’s

suggestion to include transmission-only

point-to-point customers in the

definition of native load. We note that

network customers are provided with

rights comparable to native load

customers because the transmission

provider includes their network

resources and loads in its long-term

planning horizon. However, a point-topoint transmission service customer is

not similarly situated to native load and

Network Customers. The Network

service formula rate requires the

Network customer to pay a load-ratio

share of the costs of the transmission

provider’s transmission system on an

ongoing basis, while a point-to-point

transmission service customer is only

responsible for paying on a contract

demand basis over the contract term.

The network customer and the native

load of the transmission provider pay all

the residual costs of the transmission

system and face greater risks of rate

fluctuations due to facility additions

and variations in load of both its and

other customers. In contrast, the pointto-point transmission service customer

may be more transitory in nature

electing shorter terms of service and

specific forms of service tailored for

discrete services over specific time

periods that do not necessarily enter

into the transmission provider’s

planning horizon. To the extent a

transmission customer desires similar

rights and cost responsibilities to a

native load customer, it can always elect

to take network service.

We further note that, in granting a

right of first refusal to existing

customers, we afforded existing

transmission only point-to-point

customers a priority to continue to use

the transmission provider’s system.

VA Com’s proposed change to the

definition of native load was made in

conjunction with its proposed change in

the reservation priority (highest priority

for ‘‘native load’’, followed by firm

contract customers and lastly, non-firm

customers). Because we are rejecting VA

Com’s proposed reservation priority (see

Section IV.G.3.a. above), we will also

reject its proposed conforming change to

the definition of native load as proposed

by VA Com.

g. Off-System Sales

Regarding the unbundling of offsystem sales, the Final Rule required

that all bilateral economy energy

coordination contracts executed before

the effective date of Order No. 888 must

be modified to require unbundling of

any economy energy transaction

occurring after December 31, 1996.403

Concerning the treatment of revenues

from transmission associated with offsystem sales, the Commission stated in

the Final Rule that revenue from nonfirm services should continue to be

reflected as a revenue credit in the

derivation of firm transmission tariff

rates.404

Rehearing Requests

Montana Power asserts that the

Commission should clarify that offsystem sales that originate from

generating plants or power purchases

outside the transmission provider’s

system and do not use the transmission

provider’s transmission system should

not be automatically assessed point-topoint charges.

Maine Public Service asks the

Commission to clarify that revenues

from off-system sales are not to be

credited where the sales do not use the

transmission provider’s system

(referencing sections 1.44 and 8.1 of the

pro forma tariff). Maine Public Service

states that it makes sales from Maine

Yankee (which is not located on Maine

Public Service’s system) to customers

not on its system and that it should not

have to credit these sales revenues to its

transmission customers.

Wisconsin Municipals asks the

Commission to clarify that the provision

and level of revenue credits are rate

issues and that if parties have negotiated

provisions for revenue credits, the Final

Rule cannot be used to avoid obligations

undertaken in a settlement.

Commission Conclusion

Utilities must take all transmission

services for wholesale sales under new

requirements contracts and new

coordination services under the same

tariff used by eligible customers. The

Commission provided an extension

until December 31, 1996, for utilities to

take transmission service under the

same tariff for their economy energy

transactions, certain power pooling

arrangements, and other multi-lateral

arrangements.405 The above criteria,

however, only apply when a utility

transmission system is being used to

accommodate off-system sales.

Therefore, a utility would not be

required to take point-to-point

transmission service if its transmission

system is not being used for the

transaction.

Maine Public Service’s concern is

misplaced. Maine Public Service states

that certain of its sales do not use its

own transmission system and that it

pays other utilities for such

transmission service. However, Section

8.1 only specifies the treatment of

revenues the transmission provider

receives from transmission service it

provides itself when making third-party

sales using point-to-point transmission

service under its tariff. If Maine Public

Service is not the transmission provider

for these third-party sales, then Section

8.1 does not apply to such transactions.

Wisconsin Municipals’ argument with

respect to prior settlements has been

previously addressed in Section

IV.D.1.c.(2) (Energy Imbalance

Bandwidth).

h. Requirements Agreements

A detailed description of the

Commission’s unbundling requirements

pertaining to requirements agreements

is described below.

Rehearing Requests

Blue Ridge requests that the

Commission clarify the definitions of

requirements, economy and noneconomy energy coordination

agreements. In addition, Blue Ridge
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12351

406FERC Stats. & Regs. at 31,729–30; mimeo at

277–78.

407 Mimeo at 769.

408FERC Stats. & Regs. at 33,110 and 31,804–05;

mimeo at 85 and 497–98.

seeks clarification regarding which

dates are to be used to distinguish

between existing and new contracts

(July 11, 1994 or July 9, 1996).

Commission Conclusion

The definitions of economy and noneconomy energy coordination

agreements are addressed in section

IV.F.4. (Bilateral Coordination

Arrangements). With respect to Blue

Ridge’s concern regarding requirements

agreements, we defined requirements

contracts broadly in section 35.28(b)(1)

of the Commission’s regulations as ‘‘any

contract or rate schedule under which a

public utility provides any portion of a

customer’s bundled wholesale power

requirements.’’ The definition is

intended to encompass partial

requirements service, since that service

is intended to meet the bundled load

requirements of a customer that is not

provided from other sources such as

self-generation or unit power purchases.

In contrast, a non-economy energy

coordination agreement is not intended

to meet, by itself, the entirety of a

customer’s bundled power requirement

or the residual partial power

requirement of a customer. For example,

a 50 MW unit power purchase or a longterm firm power purchase would supply

long-term firm power but a customer

would likely need an additional partial

requirements agreement to supply the

residual amount of its load requirement.

Regarding Blue Ridge’s request for

clarification of the dates for new and

existing agreements, the Commission

explicitly stated in Order No. 888 that

any bilateral wholesale coordination

agreements executed after July 9, 1996

would be subject to the functional

unbundling and open access

requirements set forth in the Rule.406 In

addition, the Commission required that

all bilateral economy energy

coordination contracts executed on or

before July 9, 1996 be modified to

require unbundling of any economy

energy transaction occurring after

December 31, 1996. The Commission

permitted all non-economy energy

bilateral coordination agreements

executed before July 9, 1996 to continue

in effect subject to section 206

complaints.

For the purpose of distinguishing

between existing and new wholesale

requirements contracts and for stranded

investment recovery provisions, the

Commission established July 11, 1994 as

the applicable date.407 For a utility to

recover stranded investment costs in

new requirements contracts, it must

include explicit provisions in the

contract for stranded investment

recovery. Existing requirements

contracts would not need a similar

provision to be eligible for stranded

investment recovery.408 Utilities are

required to unbundle all new

requirements contracts. The

requirement that utilities unbundle

existing wholesale requirements

contracts is for informational purposes

and will enable existing requirements

customers to evaluate and compare the

transmission component of existing

contracts to alternative contracts prior to

the existing contracts’ expiration dates.

i. Use of Distribution Facilities

The Commission received requests for

clarification regarding this issue which

was not specifically addressed by the

Commission in the Final Rule.

Rehearing Requests

CSW Operating Companies asks the

Commission to make clear that to the

extent a transmission provider makes

available to transmission customers the

use of distribution facilities, the terms

governing the use of and the charges for

such use should be set forth in the

customer’s service agreement.

Commission Conclusion

Utilities are free to include customerspecific terms and conditions or terms

and conditions limited to certain

customers (e.g., a distribution charge) in

a customer’s service agreement and/or

the network customer’s network

operating agreement.

j. Losses

The Commission received requests for

clarification regarding this issue which

was not specifically addressed by the

Commission in the Final Rule.

Rehearing Requests

VT DPS asserts that network

customers should not have to bear

losses twice—the tariffs allow collection

of losses over all network load, even

that supplied by behind the meter

generation. It argues that losses should

only be paid on power actually

transmitted over the company’s system.

Commission Conclusion

The pro forma tariff neither specifies

the applicable Real Power Loss factors

(see tariff section 28.5) nor the demand

levels to which the loss factors should

be applied. Accordingly, concerns

regarding the loss calculation for a

customer should be raised when the

transmission provider files with the

Commission a service agreement for a

network customer.

k. Modification of Non-Rate Terms and

Conditions

The Commission’s requirements

pertaining to modification of non-rate

terms and conditions is described

below.

Rehearing Requests

TAPS asserts that the language of

section 35.28(c)(1)(v) and the preamble

of Order No. 888 are inconsistent. TAPS

argues that the Commission should

require a demonstration of consistency

with and superiority to the terms and

conditions of the pro forma tariff and

indicate that it will not allow deviations

that seek to withdraw the minimum

terms and conditions of nondiscriminatory transmission. According

to TAPS, the Commission should also

clarify that the Commission will not let

onerous tariff terms creep in through the

back door, i.e., through service

agreements. TAPS also maintains that

the Commission should not allow

transmission providers to use

conformity as an excuse to evade

commitments.

Commission Conclusion

Order No. 888 allows a utility the

flexibility to propose, after the

compliance tariffs go into effect, to

modify non-rate terms and conditions of

the tariff if it can ‘‘demonstrate[] that

such terms * * * are consistent with, or

superior to, those in the compliance

tariff.’’ These are the same principles

that are referenced in the regulation

language (deviations allowed if the

transmission provider can demonstrate

the deviation is consistent with the

principles of Order No. 888). While

utilities are free to file revised tariffs

after their compliance filings, any filing

including service agreements will be

carefully reviewed by the Commission

to assure that the revised tariffs and

service agreements are just and

reasonable and consistent with the

principles of Order No. 888.

With regard to TAPS’ concern about

transmission providers evading

commitments, we reiterate that we will

not require abrogation of existing

contracts (and the commitments

reflected therein) except on a casespecific basis.

l. Miscellaneous Tariff Modifications

(1) Ancillary Services

The Commission explained that the

pro forma tariff incorporates conforming

revisions consistent with the
12352 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

409FERC Stats. & Regs. at 31,763; mimeo at 378.

410FERC Stats. & Regs. at 31,763–64; mimeo at

379–80.

411FERC Stats. & Regs. at 31,764; mimeo at 380–

81.

412FERC Stats. & Regs. at 31,764; mimeo at 381–

82.

413FERC Stats. & Regs. at 31,764–65; mimeo at

382–83.

414FERC Stats. & Regs. at 31,766; mimeo at 386.

415FERC Stats. & Regs. at 31,766–67; mimeo at

386–88.

determinations discussed in the Final

Rule.409

(2) Clarification of Accounting Issues

In the Final Rule, the Commission

offered clarifications on the Final Rule

pro forma tariff requirements and

certain other accounting issues related

to the Final Rule.410

(a) Transmission Provider’s Use of Its

System (Charging Yourself)

In the Final Rule, the Commission

stated that the purpose of functional

unbundling is to separate the

transmission component of all new

transactions occurring under the Final

Rule pro forma tariff, thereby assisting

in the verification of a transmission

provider’s compliance with the

comparability requirement. With respect

to off-system sales, the Commission

stated that the transmission provider

would book to operating revenue

accounts those revenues received from

the customer to whom it made the offsystem sale.411 The Commission

required that the transmission service

component and energy component of

those revenues be recorded in separate

subaccounts of Account 447, Sales for

Resale.

Rehearing Requests

APPA argues that the revenue from

the transmission component of all offsystem uses must be included in the

credit if comparability is to be achieved.

APPA also argues that booking

revenue credits to Account 447 for a test

year reduction does not ensure timely

receipt by customers. It asserts that a

monthly pass-through to all firm

transmission customers is needed.

APPA further argues that a properly

functioning revenue credit does away

with the perception of disparate

treatment of network and point-to-point

customers. Similarly, TDU Systems

argues that comparability requires that

revenues attributable to transmission

owners’ use of their transmission

systems be flowed through to customers’

benefit immediately so that

transmission owners and customers

receive comparable price signals with

regard to their uses of the system.

Commission Conclusion

The precise methodology to be used

to credit revenues from off-system sales

for the benefit of the tariff customers

should be addressed in the compliance

filing proceedings and will depend on

the particular rate design methodology

that is ultimately employed. APPA’s

proposed monthly pass-through of

revenue credits raises potential issues

including: (1) use of estimates versus

actuals; (2) the appropriate time period

to be utilized; and (3) firm versus nonfirm distinctions. Accordingly, the issue

of determining appropriate revenue

credits is properly left for case-by-case

determinations. However, we agree with

APPA that revenue from the

transmission component of all offsystem uses of the transmission system

(whether by the transmission provider

or a transmission customer) must be

treated on a comparable basis, whether

through rate design or through revenue

credits.

(b) Facilities and System Impact Studies

In the Final Rule, the Commission

explained that comparability mandates

that to the extent a transmission

provider charges transmission

customers for the costs of performing

specific facilities studies or system

impact studies related to a service

request, the transmission provider also

must separately record the costs

associated with specific studies

undertaken on behalf of its own native

load customers, or, for example, for

making an off-system sale.412

Rehearing Requests

No requests for rehearing addressed

this matter.

(c) Ancillary Services

In the Final Rule, the Commission

indicated that, at this time, it was not

convinced that the amounts involved or

the difficulty associated with measuring

the cost of ancillary services warrants a

departure from our present accounting

requirements.413

Rehearing Requests

No requests for rehearing addressed

this matter.

(3) Miscellaneous Clarifications

(a) Electronic Format

In the Final Rule, the Commission

required that public utilities, in addition

to complying with the requirements of

Part 35, submit a complete electronic

version of all transmission tariffs and

service agreements in a word processor

format, with the diskette labeled as to

the format (including version) used,

initially and each time changes are

filed.414

Rehearing Requests

No requests for rehearing addressed

this matter.

(b) Administrative Changes

In the Final Rule, the Commission set

forth a number of tariff modifications

that it indicated needed no further

explanation.415

8. Specific Tariff Provisions

The Commission attached a pro forma

tariff to the Final Rule as Appendix D.

A number of entities have sought

rehearing of various sections of that pro

forma tariff. Their arguments and the

Commission’s responses are set forth

below.

Rehearing Requests

Oklahoma G&E asks that the

Commission add a definition for

‘‘Interconnection’’ that would be an

interface where one or more points of

delivery or points of receipt are located.

Commission Conclusion

We disagree with Oklahoma G&E that

there is a need to add a definition for

‘‘Interconnection’’ to the Final Rule pro

forma tariff. Oklahoma G&E has not

supported its need for the proposed

change and has failed to identify any

potential problems that may result if its

definition is not included.

Sections 1.12, 15.4 and 32.4

Rehearing Requests

Cajun argues that the Commission

should mandate joint planning in the

development of Facilities Studies. It

alleges that a transmission provider’s

independent long-range plans

frequently include longer, higher

voltage facilities than are needed for the

transmission customers’ requirements. It

further alleges that absent mandatory

joint transmission planning, the

transmission customers will always be

paying for the incremental capacity cost

of transmission enhancements that only

fit into the Transmission Provider’s

independent long-range plans.

Commission Conclusion

A joint planning mandate as

recommended by Cajun, NRECA and

others is beyond the scope of this

proceeding. However, the Commission

encourages utilities to engage in joint

planning with other utilities and

customers and to allow affected

customers to participate in facilities

studies to the extent practicable.

Moreover, on a regional basis, the

Commission encourages the formation
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12353

416FERC Stats. & Regs. at 31,770; mimeo at 397–

98. The Commission has applied its approach to

regional practices in filings made in compliance

with Order No. 888. See, e.g., American Electric

Power Service Corporation, et al., 78 FERC ¶ 61,070

(1997); Allegheny Power System, Inc., et al., 77

FERC ¶ 61,266 (1996); Atlantic City Electric

Company, et al., 77 FERC ¶ 61,144 (1996).

417Order On Non-Rate Terms and Conditions, 77

FERC ¶ 61,144 (mimeo at 15–16) (1996).

418FERC Stats. & Regs. at 31,770 n. 514; mimeo

at 399 n. 514.

of RTGs and ISOs to represent the needs

of all participants in a region in the

planning process.

Section 1.14

Rehearing Requests

CCEM asserts that the term Good

Utility Practice is vague. It argues that

the Commission should delete the

reference to regional practices, but if it

does not, the term should be clearly

defined in each utility’s tariff.

Commission Conclusion

The Commission recognizes that

unique operating practices and

conditions exist on a regional basis

throughout the industry. Accordingly,

the Commission permits certain

deviations to the non-price terms and

conditions of the tariff. In the Final

Rule, we stated that any proposed

modifications by the utility to the tariff

to recognize regional operations and

practices must be demonstrated to be

reasonable, generally accepted in the

region, and consistently adhered to by

the transmission provider.416

Sections 1.22 and 1.25

Rehearing Requests

Blue Ridge requests clarification that

a portion of a designated network

resource need not consist of the entirety

of a generating unit.

Commission Conclusion

Blue Ridge’s request for clarification

in the definition of ‘‘Network Load’’ in

Tariff Section 1.22 and ‘‘Network

Resource’’ in Tariff Section 1.25 is not

necessary. Blue Ridge’s concerns are

based on the mistaken premise that a

designated network resource must

consist of the entirety of a generating

unit. Tariff sections 1.25 and 30.1

explicitly specify that a network

resource can be a portion of a generating

resource or unit. Indeed, the

Commission recently emphasized this

point:

Ohio Cooperatives have disregarded the

fact that a designated resource can be a part

of a unit. In this example, Ohio Cooperatives

would make two network designations for

the 300 MW unit: a 100 MW designation for

the 100 MW load on one system and a 200

MW designation for the 200 MW on the other

system.417

Sections 1.25 and 30.1

Rehearing Requests

TDU Systems asserts that these

sections should not be read to require

assignment of specific Network

Resources to specific control areas. They

state that multiple control area network

customers need to be able to dispatch

their resources economically to serve

their loads. They argue that the

Commission would be in error to

require that a transmission customer’s

resources be segmented if they are being

dispatched to serve network load in one

of several control areas and once so

segmented, sales from such units be

considered either third-party sales or

become interruptible as to network load

in a second control area and thus are not

deemed Network Resources. They

further argue that TDU systems with

loads and resources in multiple control

areas must be allowed to designate as

Network Resources for each control area

the totality of their resources which

meet the owned or purchased

requirements of section 1.25.

TDU Systems argues that these

sections should be revised to include

resources that are leased by a network

customer on terms tantamount to

ownership, or which, at a minimum,

afford the network customer a first call

right to that generating resource.

Commission Conclusion

TDU Systems’ proposed revision to

recognize leased resources appears

reasonable and we revise these sections

of the pro forma tariff, in relevant part,

as follows (new text underlined, deleted

text in brackets):

1.25 Network Resource: Any

designated generating resource

owned, [or] purchased or leased by

a Network Customer under the

Network Integration Transmission

Service Tariff.

30.1 Designation of Network

Resources: Network Resources shall

include all generation owned, [or]

purchased or leased by the Network

Customer designated to serve

Network Load under the Tariff.

Sections 1.33 and 1.34

Rehearing Requests

CCEM states that sections 1.33 and

1.34 should be changed to facilitate

umbrella service agreements that

include all points of receipt and

delivery on a transmission provider’s

system.

Commission Conclusion

Consistent with our ruling in section

IV.G.6 (Umbrella Service Agreement)

regarding umbrella type service

agreements for short-term firm point-topoint transmission service, we will

modify sections 1.33 and 1.34 to require

that Points of Receipt and Points of

Delivery be specified in the service

agreement for only Long-Term (more

than one year) Firm Point-to-Point

Transmission service.

Section 1.47

Rehearing Requests

Wisconsin Municipals asks the

Commission to clarify that a utility is

not prevented from including the load

of interruptible customers in the

denominator of the fraction used to

perform the load ratio calculation. It

claims that this is important in

Wisconsin where the transmission

system is planned without regard to the

distinction between firm and

interruptible power customers

(interruptible customers are not subject

to interruption for transmission

reasons).

Commission Conclusion

The treatment of interruptible loads in

the planning and operation of the

Wisconsin transmission grid present a

unique, case-specific situation that is

best addressed on a case-by-case basis.

As the Commission stated in the Final

Rule:

all tariffs need not be ‘‘cookie-cutter’’ copies

of the Final Rule tariff. Thus, under our new

procedure, ultimately a tariff may go beyond

the minimum elements in the Final Rule pro

forma tariff or may account for regional,

local, or system-specific factors. The tariffs

that go into effect 60 days after publication

of this Rule in the Federal Register will be

identical to the Final Rule pro forma tariff;

however, public utilities then will be free to

file under section 205 to revise the tariffs,

and customers will be free to pursue changes

under section 206.[418]

Section 1.48

Rehearing Requests

Oklahoma G&E asks the Commission

to clarify that the term ‘‘Transmission

Service’’ as used in the pro forma tariff

includes service provided on a network

basis as well as on a point-to-point

basis.

Commission Conclusion

The Commission used the term

‘‘Transmission Service’’ throughout the

pro forma tariff to refer only to point-topoint service and not network service.

We also note that the term

‘‘transmission service’’ (in lower case),

which is also used throughout the pro
12354 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

419E.g., Santa Clara, Redding, TANC.

forma tariff, was used to refer to both

point-to-point and network service.

Oklahoma G&E has not identified any

problems associated with our use of

these terms and therefore has not

supported its proposed modification.

Section 1.49

Rehearing Requests

Santa Clara and Redding state that the

transmission system is defined as

facilities owned, controlled or operated

and that this could result in the same

transmission facilities being the part of

the transmission system of two entities

(e.g., COTP, which is owned by TANC,

but operated by Western Area Power

Administration (WAPA)). They ask the

Commission to clarify that only one

such entity should have the obligation

to provide transmission service.

Commission Conclusion

This presents a fact-specific situation

that is best addressed on a case-by-case

basis. This situation would appear to

arise for WAPA and TANC only if either

utility receives a request for reciprocal

transmission service or if either utility

files a voluntary tariff. The appropriate

entity to include the COTP facility in its

transmission system for purposes of a

transmission tariff may depend upon

the circumstances of the transmission

request. Therefore, a resolution of this

question is appropriately deferred until

such time as reciprocal service using the

COTP facility is requested.

Section 3

Rehearing Requests

CCEM asks the Commission to clarify

that a transmission customer may

switch its supplier of ancillary services.

Commission Conclusion

The Final Rule requires that

transmission customers obtain all

necessary ancillary services for their

transactions. They must purchase

certain of these services from the

transmission provider, but can self

supply or obtain certain services from a

third party. Consistent with these

requirements, a transmission customer

may switch suppliers of ancillary

services not required to be provided by

the transmission provider if it continues

to demonstrate that it satisfies its

ancillary service obligations.

Section 5.1

Rehearing Requests

ConEd points out that this section

applies to Transmission Service, which

the tariff defines to mean point-to-point

service only. It requests that this section

be clarified to include network service.

Commission Conclusion

The use of the term ‘‘Transmission

Service’’ in section 5.1 of the pro forma

tariff was an inadvertent error. We will

change the term ‘‘Transmission Service’’

used in section 5.1 to ‘‘transmission

service’’ so as to include both point-topoint and network transmission service.

Section 6

Rehearing Requests

CCEM asks the Commission to require

that the text of the required sworn

statement by non-transmission owning

entities that they are not assisting an

Eligible Customer be included in the

tariff.

Commission Conclusion

We will deny CCEM’s request as

unnecessary. The Commission does not

believe that it must mandate the precise

text of the required sworn statement.

Rather, the entity requesting

transmission service properly has the

burden of explaining in a sworn

statement the circumstances of its

service request, including on whose

behalf it may be requesting service (for

itself or for another party).

Section 8

Rehearing Requests

CCEM argues that, consistent with

Commission policy for natural gas

pipelines, transmission providers

should be required to refund all

‘‘penalties’’ that are in excess of the

costs incurred to balance transmitting

system operations (citing Transco, 55

FERC ¶ 61,446 at 62,372 (1991) and

TETCO, 62 FERC ¶ 61,015 at 61,117

(1993)).

Commission Conclusion

CCEM’s argument is premature. Order

No. 888 did not establish a rate or a

penalty for Energy Imbalance Service.

CCEM is free to raise this concern at

such time as utilities file their proposed

rates for Energy Imbalance Service.

Section 11

Rehearing Requests

CCEM contends that an unconditional

and irrevocable letter of credit is

extremely costly to obtain and could be

used as subterfuge for discriminatorily

denying service. CCEM argues that if an

irrevocable letter of credit is used, a

transmission provider should not be

able to draw on it until it tenders a bill

that has been improperly refused.

(CCEM attached a proposed conditional

letter of credit to its rehearing request).

Several entities argue that a letter of

credit should not be required for

existing customers with a satisfactory

credit history and should only apply to

new customers or those with a history

of payment delinquency.419

Commission Conclusion

While a transmission provider may

require an unconditional and

irrevocable letter of credit, if a customer

believes that the transmission provider

unreasonably rejected an alternative

security proposal, it may seek relief

through the dispute resolution

procedures established in Tariff Section

12. Moreover, if a customer believes a

transmission provider is attempting to

use the unconditional and irrevocable

letter of credit in an unduly

discriminatory manner, it may file a

complaint raising such concern in a

section 206 filing.

Section 12

Rehearing Requests

According to Public Service Co of CO,

the dispute resolution procedures: (1)

Should allow a party to appeal an

arbitration award on the basis that

arbitrators have misinterpreted the

requirements of the pro forma tariff and

(2) where a utility is a member of an

RTG, should allow the RTG dispute

resolution procedures to be exclusive.

Otherwise, Public Service Co of CO

argues, entities may perceive that the

Commission’s procedures are more

favorable than the RTG’s and decide not

to join. Moreover, it asserts that when a

utility that is a member of an RTG has

a dispute with a customer that is a nonmember, the customer’s forum should

be the Commission, or the RTG’s

procedures if those procedures apply to

non-members.

Dispute Resolution Associates asks

the Commission to require that prior to

submission of disputes for arbitration or

Commission disposition, disputants

should be required to pursue a mediated

resolution with a qualified individual. If

unsuccessful, it states that parties can

elect arbitration or Commission

disposition. If successful, it states that

parties will have avoided litigation

related costs and will not have

jeopardized their ongoing business

relationship. Dispute Resolution

Associates also argues that

representatives at all negotiating

sessions should be authorized to enter

into an agreement and asks that the

Commission clarify that dispute

resolution is one of the minimum

requirements of the Final Rule. It also

asks that the Commission require that

any filed separate retail transmission
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12355

420E.g., Florida Power Corp, Utilities For

Improved Transition, VEPCO.

tariffs must include section 12 type

dispute resolution procedures.

Commission Conclusion

Concerning the first issue raised by

Public Service Co of CO, even if the

arbitrator misinterprets the

requirements of the pro forma tariff, the

dispute resolution procedures require

such decision (as it affects terms and

conditions of service) to be filed with

the Commission. Section 12.2 provides:

The final decision of the arbitrator must

also be filed with the Commission if it affects

jurisdictional rates, terms and conditions of

service or facilities.

As to Public Service Co of CO’s

second concern, a utility’s membership

in an RTG with its own Dispute

Resolution Procedures presents a fact

specific situation to which a generic

response is not appropriate. Whether

both parties to a dispute are members of

the RTG or only one of the parties is a

member may have some bearing on

which set of Dispute Resolution

Procedures should apply.

Regarding Dispute Resolution

Associates concerns, a utility is free to

propose an initial process using

‘‘mediated resolution with a qualified

individual’’ prior to using the Dispute

Resolution Procedures. However, we see

no need to modify the tariff to introduce

such a proposed requirement as the

Commission is not aware of other

parties similarly claiming excessive

costs or the threat of ‘‘jeopardizing

ongoing business relationship[s]’’ due to

the present Dispute Resolution

Procedures. Finally, any attempts to

delete the Dispute Resolution

Procedures from any tariff on file with

the Commission would require the

transmission provider to demonstrate

that its proposed modifications are

consistent with or superior to the pro

forma tariff terms and conditions.

Section 13.2

Rehearing Requests

CCEM asserts that the term ‘‘reserved

service’’ should be changed to

‘‘requested service.’’ Utilities For

Improved Transition and Florida Power

Corp assert that the limitations on

unconditional reservations are too

stringent and that the Commission

should modify the third sentence of

section 13.2 to provide: ‘‘If the

Transmission System becomes

oversubscribed, requests for longer-term

service may preempt requests for

shorter-term service up to a time period

before the requested commencement of

service that is equal to the requested

term of service.’’

Commission Conclusion

We will deny CCEM’s request to

replace the term ‘‘reserved service’’ in

tariff section 13.2 with ‘‘requested

service.’’ CCEM has not attempted to

identify any uncertainties caused by the

current wording of this section or

explain any improvements that its

proposed change would make.

Utilities For Improved Transition and

Florida Power Corp’s proposal to revise

the deadline for when reservations for

short-term firm transmission become

unconditional is contrary to the

Commission’s intent in adopting the

conditional reservation approach for

short-term firm transmission and is

rejected. Specifically, for service

requests greater than a single day, week

or month, Utilities For Improved

Transition and Florida Power Corp’s

proposal decreases the period of time

that such request is conditional; in other

words, such request increases the

unconditional reservation period, thus

reducing the amount of longer-term

transactions that the transmission

provider can accommodate.

Sections 13.2 and 14.2

Rehearing Requests

CCEM notes that short-term firm

point-to-point transmission service

customers that have already reserved

service have a right to match any longerterm requests for service before being

preempted pursuant to section 13.2.

However, CCEM states that these tariff

sections do not establish a deadline for

when such right must be exercised.

Because the tariff established a

conditional reservation period for shortterm firm transmission service (during

which time longer-term firm

transmission requests can preempt

shorter-term conditional reservations)

CCEM suggests that a shorter-term firm

transmission customer should be

allowed to exercise its right to match

longer-term service requests up until the

end of the conditional reservation

period. CCEM requests a similar

clarification for non-firm transmission

service but does not propose specific

modification.

Commission Conclusion

While we agree with CCEM regarding

the need to establish a deadline for

exercising the right to match longerterm service requests for both short-term

firm and non-firm transmission services,

we will reject CCEM’s proposed

deadline for short-term firm

transmission service. CCEM’s proposed

deadline would create market

inefficiency by allowing the holder of

the shorter-term firm transmission

service an excessive amount of time to

exercise its right to match the longerterm service. We feel that such a

proposal could constitute a form of

hoarding that would stifle the

consummation of potential transactions

and should not be allowed. CCEM’s

proposal would work to the detriment of

any and all potential customer(s)

requesting longer short-term firm

transmission service. By allowing the

original transmission customer to delay

its response, the subsequent potential

customer will be disadvantaged and

may be required to make last minute

alternative arrangements.

We believe that an especially quick

response time is necessary for hourly

non-firm transmission service customers

to match longer-term service requests.

Hourly non-firm transmission customers

must exercise their right to match

longer-term service requests

immediately upon notification by the

transmission provider of a longer-term

competing request for non-firm

transmission service. For non-firm

transmission service other than hourly

transactions and short-term firm

transmission service, we believe a

customer should exercise its right to

match longer-term service requests as

soon as practicable. The prompt

exercising of such right is particularly

critical where scheduling deadlines for

such transactions are imminent.

However, even for transactions with

longer lead-times before service is to

commence, we believe a response

deadline of no more than 24 hours from

being informed by the transmission

provider of a longer-term competing

request for transmission service is

appropriate. Accordingly, the customer

will be required to respond to the

transmission provider as soon as

practicable after notification of a longerterm request for service, but no longer

than 24 hours from being notified or

earlier if required to comply with the

scheduling requirements for such

services in tariff section 13.8 and 14.6.

Tariff sections 13.2 and 14.2 will be

modified accordingly.

Section 13.5

Rehearing Requests

Several utilities argue that section

13.5 is too broad because it also applies

to costs that are included in rates on an

embedded cost basis (which they claim

can be evaluated when the transmission

provider makes a rate filing).420 They

recommend that the Commission
12356 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

modify the last sentence of the section

as follows:

If redispatch costs or Network Upgrade

costs are to be charged to the Transmission

Customer on an incremental basis or costs

relating to Direct Assignment Facilities that

are to be charged to the Transmission

Customer, the obligation of the customer to

pay such costs shall be specified in the

Service Agreement prior to the initiation of

service.’’ (Utilities For Improved Transition

at 74–75).

Commission Conclusion

The Commission’s intent in tariff

section 13.5 was to require that any

proposal to assess incremental charges

to a customer must be specified in that

customer’s service agreement. Florida

Power Corp and VEPCO correctly note

that tariff section 13.5 inadvertently

requires that any redispatch, network

upgrade or direct assignment facilities,

whether assessed on an incremental

basis or included in embedded cost

rates, must be specified in a customer’s

service agreement. To eliminate this

unintended result, tariff section 13.5 is

revised in relevant part as follows (new

text underlined):

Any redispatch, Network Upgrade or Direct

Assignment Facilities costs to be charged to

the Transmission Customer on an

incremental basis under the Tariff will be

specified in the Service Agreement prior to

initiating service.

Section 13.6

Rehearing Requests

CCEM asserts that the term ‘‘Good

Utility Practice’’ should be deleted.

CCEM claims that the inclusion of

regional practices in Good Utility

Practice makes the phrase vague and

unpredictable. CCEM proposes that the

Commission replace this phrase with a

qualifier that pertains only to reliability

and safety. According to PA Coops,

equal priority places inordinate and

unwarranted pressure on state siting

and regulatory authorities to approve

transmission projects required to

provide service that may primarily

benefit out of state parties. NYSEG

argues that the Commission is not

authorized to require curtailment of

bundled retail service because it does

not have jurisdiction over the rates,

terms, and conditions of such service. It

asserts that transactions subject to

proportional curtailment should not

include a transmitting utility’s own use

of its system to transmit its owned and

purchased generation to native load

customers as part of bundled retail

service or services under rate schedules

that are grandfathered. For transactions

subject to proportional curtailment,

NYSEG argues that allocation of

curtailments will be comparable only if

those multiple transactions being

curtailed are of the same type of service

and if each of the multiple transactions

is for the same duration—these

curtailments should be made on the

same basis as required for non-firm PTP

service. It asks the Commission to

clarify that the curtailment requirements

are not applicable to existing

transmission contracts.

Commission Conclusion

CCEM’s concerns center on the

inclusion of the phrase regional

practices in the definition of Good

Utility Practice in section 1.14 of the pro

forma tariff. These concerns are

answered in section 1.14 above.

PA Coops’ argument that long-term

firm point-to-point transmission

customers should be curtailed before

network service customers and native

load ignores the fact that the

transmission provider has an obligation

under the pro forma tariff to expand or

upgrade its transmission system in

response to requests for such long-term

point-to-point transmission requests. In

turn, such long-term firm point-to-point

transmission customers undertake an

obligation to pay for any transmission

facility additions necessary for the

provision of service pursuant to the

tariff. Comparability requires that all

long-term firm transmission customer be

treated on a not unduly discriminatory

basis in terms of curtailment priority.

Regarding NYSEG’s arguments, the

purpose of the curtailment provisions of

the pro forma tariff is not to ‘‘requir[e]

curtailment of bundled retail service’’ as

NYSEG claims. Rather, the provision

simply requires the transmission

provider to curtail network and pointto-point transmission services on a basis

comparable to the curtailment of the

transmission provider’s service to its

native load. Indeed, we have repeatedly

indicated that we do not have

jurisdiction over bundled retail sales.

NYSEG’s concerns regarding

curtailment provisions in existing

contracts are addressed above in Section

IV.G.3.a. (Pro-rata Curtailment

Provisions).

Section 13.7

Rehearing Requests

Utilities For Improved Transition and

Florida Power Corp state that section

13.7 of the pro forma tariff makes it

uneconomic to engage in system sales

transactions on a firm basis because it

requires the transmission provider to

impose a separate charge for

transmission from each generating

station. They ask that the Commission

clarify that if there is a sale from

multiple generators, a reservation of

transmission from each point of receipt

will be required only in the amount of

the expected relative contribution of

each generating station to the energy

that is sold. If it is not so clarified, they

argue that the Commission should make

one of the following modifications: (1)

permit the customer to designate more

than one generating station as a single

point of receipt if it provides likely

loadings of the units to the transmission

provider; (2) provide that where the

customer takes service from a group of

generating stations on an economic

dispatch basis, the reserved capacity is

the sum of the reservations at the points

of delivery (must also provide likely

loadings); or (3) add a new subsection

to Article 31 that provides that a

network integration transmission

customer may also reserve service on a

contract demand basis for periods as

short as one day (but do not reduce the

one-year minimum term for load-based

network service).

CSW Operating Companies asserts

that the Commission should permit

sales of power from multiple points of

receipt, but such multiple generating

units should be considered a single

point of receipt. According to CSW

Operating Companies, this provides

maximum flexibility, lessens the need to

establish secondary points of receipt,

and is consistent with FMPA v. FPL, 74

FERC ¶ 61,006 at 61,014 (1996). They

ask that the Commission revise section

13.7(b) to provide: ‘‘The Transmission

Customer may purchase transmission

service to make sales of capacity and

energy from multiple generating units

that are on the Transmission Provider’s

Transmission System. Such multiple

generating units shall be considered a

single Point of Receipt when the

underlying sale is to be made on a

system basis and not from specific

generating units.’’ (CSW Operating

Companies at 10–11). TAPS requests

that the Commission clarify that a

network customer may make system

sales to third parties using the point-topoint provisions without designating

each generating resource as a point of

receipt. Moreover, it asks that if the

Commission intends to depart from

FMPA v. FPL, that transmission

providers be held to the same burden.

Commission Conclusion

Several utilities request rehearing on

the tariff’s requirement that sales of

capacity and energy from multiple

generating units must be designated as

multiple points of receipt under pointto-point transmission service. These

parties generally claim that this tariff

requirement makes system sales
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12357

421FERC Stats. & Regs. at 31,770 n. 514; mimeo

at 399 n. 514.

422See Commonwealth Edison Company and

Commonwealth Edison Company of Indiana, Inc.,

78 FERC ¶ 61,090 (January 31, 1997).

transactions uneconomical and is

contrary to the Commission’s

determination in FMPA v. FPL, 74 FERC

¶ 61,006 at 61,014 (1996).

As the Commission stated in the Final

Rule:

all tariffs need not be ‘‘cookie-cutter’’ copies

of the Final Rule tariff. Thus, under our new

procedure, ultimately a tariff may go beyond

the minimum elements in the Final Rule pro

forma tariff or may account for regional,

local, or system-specific factors. The tariffs

that go into effect 60 days after publication

of this Rule in the Federal Register will be

identical to the Final Rule pro forma tariff;

however, public utilities then will be free to

file under section 205 to revise the tariffs,

and customers will be free to pursue changes

under section 206.[421]

Utilities that advocate modifying the pro

forma tariff to accommodate system

sales are free to file their specific

proposals with the Commission in a

section 205 filing.422 Such proposals are

best reviewed on a case-specific basis

where the type of system sales engaged

in by the transmission provider or

transmission customer can be identified

and described in detail. In order to

ensure comparability, any proposed

tariff modifications submitted in order

to facilitate system sales of the

transmission provider must also apply

for sales by transmission customers as

well.

Section 13.7(b)

Rehearing Requests

Blue Ridge argues that because units

at the same geographic location can be

connected to the system at different

electrical locations, such as connections

at different voltage levels (e.g., one unit

connected at 500 kV and another unit

connected at 230 kV), the Commission

should replace the phrase ‘‘at the same

generating plant’’ with ‘‘at the same

electrical location.’’ (Blue Ridge at 

23–24).

Commission Conclusion

Blue Ridge’s proposed change is

unsupported. The rationale supporting

the need for such change and its

intended result is unclear and

unexplained and appears to be

unnecessary and overly restrictive.

Many generating units at a single plant

are connected to the transmission grid at

multiple voltages. Therefore, taking

Blue Ridge’s proposal to its logical end,

a customer could face an additional

charge at a single unit for every voltage

level connection. In contrast, the intent

of section 13.7(b) of the pro forma tariff

is to treat multiple units at a single plant

as a single point of receipt to avoid

charging a customer an unnecessary

additional charge.

Section 13.8

Rehearing Requests

CCEM asks the Commission to clarify

that permissible scheduling changes

extend to changes in the amount of

power scheduled, the generation source,

and delivery and receipt points. AMPOhio asserts that if the transmission

provider can accommodate a change,

the customer should be able to change

its schedule less than 20 minutes before

the hour or during the hour, and during

an emergency or when the customer is

attempting to remain within the 1.5%

deviation band. It also asks the

Commission to clarify that customers

should be allowed to aggregate multiple

points of delivery of less than a whole

megawatt to be stated in whole

megawatts (as is allowed for points of

receipt). Otherwise, AMP-Ohio asserts,

this would preclude small utilities from

receiving service under a transmission

provider’s open access tariff.

Commission Conclusion

We agree with CCEM that permissible

scheduling changes include the amount

of power scheduled (up to the amount

of capacity reservation stated in the

customer’s service agreement).

However, a proposed modification to

the generation source or to receipt and

delivery points on a firm basis under the

pro forma tariff is not simply a

scheduling change, as maintained by

CCEM, but is a new request for service,

as set forth in pro forma tariff section

22.2.

AMP-Ohio’s request regarding

scheduling changes ignores the optional

language in section 13.8 of the pro

forma tariff, which permits a reasonable

time limitation (other than the stated

twenty minute deadline) that is

‘‘generally accepted in the region and is

consistently adhered to by the

transmission provider.’’ Accordingly,

the pro forma tariff may be amended by

the transmission provider to reflect the

prevailing practice in the region.

AMP-Ohio’s request regarding

scheduling changes to allow the

customer to stay within the deviation

band of 1.5 percent may not be feasible

depending upon the ramping rates of

the particular generating units and may

allow erratic scheduling by customers

that could interfere with the

transmission provider’s ability to

provide load following service.

AMP-Ohio’s request for clarification

that customers should be allowed to

aggregate multiple points of delivery of

less than a whole megawatt is

unnecessary. Tariff section 17.2(viii)

specifically allows customers to

combine their requests for service for

either points of receipt or points of

delivery in order to satisfy the minimum

transmission capacity requirement.

Section 14.2

Rehearing Requests

Tallahassee asks the Commission to

clarify that a non-firm customer facing

possible interruption for economic

reasons will be allowed to match the

duration and price of the surviving

transaction and that once a non-firm

transaction begins, it will not be

preempted without whatever notice is

sufficient and appropriate in the region,

but the time period should be no shorter

than 1–2 hours.

Commission Conclusion

The pro forma tariff does allow a

customer to match a longer term

reservation before being preempted.

Moreover, non-firm transmission

transactions, by definition, are

interruptible for economic reasons (on a

non-discriminatory basis) at any time.

To the extent a prevailing regional

practice exists regarding advance notice

of interruption, the transmission

provider may incorporate such a

provision in its tariff.

Section 14.4

Rehearing Requests

CCEM asks the Commission to clarify

that a non-firm point-to-point service

agreement is an Umbrella Agreement

and a non-firm point-to-point customer

should be able to schedule a transaction

at different primary and secondary

receipt points and schedule changes in

primary points with no filing

requirement.

Commission Conclusion

The form of service agreement for

non-firm transmission service is a nontransaction specific umbrella service

agreement (See Attachment B to the pro

forma tariff). Therefore, the service

agreement does not require a

specification of receipt and delivery

points for non-firm point-to-point

transmission service. However, we note

that changes to the receipt or delivery

points for non-firm transmission service

other than those points reserved by the

transmission customer in its service

request are not ‘‘schedule’’ changes as

claimed by CCEM, but will require the
12358 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

423On December 27, 1996, the Commission issued

an order that found that

During Phase 1, a request for transmission service

made after 2:00 p.m. of the day preceding the

commencement of such service, will be ‘‘made on

the OASIS’’ if it is made directly on the OASIS, or,

if it is made by facsimile or telephone and promptly

(within one hour) posted on the OASIS by the

Transmission Provider.

77 FERC ¶ 61,335 (1996).

424We further note that CCEM’s reference to the

Commission’s Policy Statement Regarding Good

Faith Request for Transmission Services does not

support its position. As we there stated,

[a] good faith request for transmission service

should also contain a specific, technical description

of the requested services in sufficient detail to

permit the transmitting utility to model the

additional services or its transmission system.

FERC Stats. & Regs. ¶ 30,975 at 30,863.

submission of a new application for

service pursuant to Tariff Section 18.

Section 14.6

Rehearing Requests

CCEM asks the Commission to clarify

that ‘‘scheduling changes’’ for non-firm

transmission include changes in the

amounts scheduled, changes in receipt

and delivery points, or changes in

primary points.

Commission Conclusion

This issue is addressed in Section

13.8 above.

Sections 17, 18 and 29.2

Rehearing Requests

The EPRI/NERC Working Group

(formerly the ‘‘What and How Industry

Working Group’’) identifies certain areas

in the pro forma tariff ‘‘where the

perceived scope of OASIS has grown

beyond that which is feasible in Phase

1’’ of OASIS. (EPRI/NERC Working

Group at 2). EPRI/NERC Working Group

references various information required

in the application process under the pro

forma tariff that is required to be

submitted via OASIS to the

transmission provider. EPRI/NERC

Working Group explains that a

substantial amount of information

required under the pro forma tariff

‘‘cannot be provided via the OASIS in

Phase 1’’ (e.g., service agreements,

requests for (A) non-firm point-to-point

transmission service in the next hour,

(B) multiple receipt and delivery points,

(C) addition of new network loads or

resources, loadflow and stability data).

The EPRI/NERC Working Group also

claims that tariff section 17.1 creates

confusion as it first requires that ‘‘[a]

request for Firm Point-To-Point

Transmission Service * * * must

contain a written Application * * *’’ to

the transmission provider, but then

requires ‘‘[a]ll Firm Point-To-Point

Transmission Service requests should

be submitted by entering the

information listed below on the

Transmission Provider’s OASIS.’’

(Emphasis added). The EPRI/NERC

Working Group asserts that the above

language confuses the process of an

‘‘application for service agreement’’

versus the process of ‘‘a request for

transmission service’’ by a customer

who already has a service agreement.

Commission Conclusion

The Commission recognizes that

implementation of the OASIS is being

accomplished in phases. In recognition

of this fact, section 17.1 of the pro forma

tariff provides:

Prior to implementation of the

Transmission Provider’s OASIS, a Completed

Application may be submitted by (i)

transmitting the required information to the

Transmission Provider by telefax, or (ii)

providing the information by telephone over

the Transmission Provider’s time recorded

telephone line.

Moreover, we clarify that if Phase 1 of

OASIS implementation does not

support the submission of certain

information over the OASIS, such

information may be submitted by

telephone or telefax (facsimile), as

provided in the pro forma tariff, and

promptly (within one hour) posted on

OASIS by the Transmission Provider.423

Concerning the EPRI/NERC Working

Group’s apparent confusion regarding

service application processes, we

previously explained in Section IV.G.6

that the Commission is modifying the

application process for firm point-topoint transmission transaction of less

than one year (short-term firm

transactions). The Commission will

permit an ‘‘umbrella service agreement’’

approach where all of a customer’s

short-term firm transactions can be

arranged under a single non-transaction

specific umbrella service agreement

rather than requiring a new service

agreement for each short-term firm

transaction. In contrast, service

agreements for firm point-to-point

transmission transactions of one year or

more (long-term firm transactions) are

transaction specific and require a

separate service agreement for each

transaction.

Section 17.1

Rehearing Requests

CCEM states that the 60 days in

advance to request service should be

shortened to 6 days. For service shorter

than one year, it argues that the

procedures should not be left to

negotiation with a monopolist. For

service greater than one month but less

than one year, it asserts that a request

should be submitted 3 days in advance;

for weekly service, schedules should be

submitted by some specific hour the day

before service is to commence; and for

hourly or daily service, schedules

should be submitted no later than 20

minutes in advance.

Commission Conclusion

CCEM has provided no support for its

proposal to shorten the lead time for

requests for firm service from sixty days

to six days. Sixty days in advance of the

commencement of long-term (greater

than one year) firm service is not an

unreasonable time period. It provides

transmission providers time to conduct

security analyses, as well as perform

system impact studies and facility

studies that may be necessary.

Accordingly, CCEM’s request is denied.

Section 17.2

Rehearing Requests

CCEM argues that information

concerning the location of the

generating facility and the load

ultimately served is not required in

connection with a good faith request

under the Policy Statement Regarding

Good Faith Request for Transmission

Services and should not be required in

a Completed Application. However, if it

is required, CCEM argues that it should

remain confidential and not be

disclosed. It further asks the

Commission to clarify that a point-topoint customer can designate all receipt

and delivery points in order to obtain

umbrella-type service and can schedule

receipt and delivery points as primary

or secondary and can change primary

points by filing another schedule.

Commission Conclusion

We will deny CCEM’s proposed

changes in part as unnecessary. The

locations of generating facilities and

loads are needed by the transmission

provider to allow it to analyze whether

the requested transmission service can

be accommodated over the existing

transmission system, as well as to plan

upgrades and transmission facility

additions.424

Tariff section 17.2 already requires

that ‘‘the transmission provider shall

treat this [confidential] information

consistent with the standards of conduct

contained in Part 37 of the

Commission’s regulations.’’

With respect to CCEM’s request to

permit umbrella-type service, we note

that we have adopted an umbrella-type

service agreement approach for shortterm firm transmission service, as
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12359

425E.g., Utilities for Improved Transition, Florida

Power Corp, VEPCO. 426FERC Stats. & Regs. at 31,694; mimeo at 172.

discussed in Section IV.G.6 (Umbrella

Service Agreements).

Section 17.3

Rehearing Requests

CCEM asserts that a customer

determined to be creditworthy should

not have to submit a deposit for firm

point-to-point transmission service.

CCEM would limit this section to those

customers found not to be creditworthy

and asks the Commission to clarify that

only the costs of system impact studies

or facilities studies can be deducted

from the deposit.

Commission Conclusion

Section 17.3 reflects a standard

requirement in many existing tariffs and

other agreements on file with this

Commission. CCEM provides no

compelling reason to revise this tariff

provision.

We also deny CCEM’s request

regarding deductions from the deposit.

We will not preclude a utility from

demonstrating that it incurs costs other

than system impact studies or facilities

studies in processing a service

application and arguing that these costs

should be deducted from a deposit.

Section 17.4

Rehearing Requests

CCEM argues that a deficiency

determination should be made in, at

most, one day.

Commission Conclusion

CCEM provides no compelling reason

to revise this tariff provision. CCEM’s

argument also ignores the fact that

certain applications involve more

complex unique transactions and

associated arrangements which may

require more time to review than other

more standard applications. CCEM’s

apparent concern regarding deficient

applications should be mitigated by the

pro forma tariff requirement that the

transmission provider must attempt to

remedy minor deficiencies in the

application informally with the

transmission customer.

Section 17.5

Rehearing Requests

CCEM asserts that a transmission

provider should respond to a completed

application for firm transmission service

within 10 minutes for hourly service, 10

minutes for daily service, 4 hours for

weekly service, 1 day for monthly

service, 2 days for service longer than

one month but less than one year, and

5 days for service one year or longer.

Commission Conclusion

Section 17.5 requires the transmission

provider to notify the eligible customer

as soon as practicable, but no later than

30 days after receipt of a completed

application if it can provide the service

or if a system impact study will be

required. We do not believe that further

specificity in establishing deadlines for

each type of service and duration of

service is necessary. However, we are

clarifying section 17.5 to require that all

responses be made on a nondiscriminatory basis. If CCEM believes

the transmission provider is engaging in

discriminatory behavior by delaying

responses to service requests (or by

responding to service requests by its

wholesale merchant function more

quickly than it responds to service

requests by unaffiliated customers), it

can file a section 206 complaint with

the Commission.

Section 17.7

Rehearing Requests

Several utilities ask the Commission

to clarify that, if transmission facilities

have been constructed to accommodate

a request for transmission service,

delays by the customer in commencing

service should be prohibited or the

customer should pay the full carrying

charges on the facilities during the

period of delay (less any revenues

received).425 Similarly, EEI and

Southern argue that if new facilities are

constructed, but the customer postpones

service by paying a reservation fee,

fairness requires that the customer bear

its cost responsibility for the new

construction at the time the facilities are

ready to be used.

Commission Conclusion

Because different factual

circumstances could exist that may lead

to alternative solutions to the problem,

we will not adopt a generic resolution.

Rather, the Commission believes it

appropriate to allow each utility to

propose solutions in subsequent section

205 filings with the Commission.

Section 19

Rehearing Requests

VA Com asks the Commission to

clarify that determining the necessity of

a transmission facility upgrade or

addition remains a state prerogative. It

asserts that native load customers may

face reduced reliability, or may incur

costs associated with premature

additions, if calculations of ATC are

incorrect. In addition, it asserts that

generating facilities can also be used to

relieve regional capacity constraints—

‘‘For example, a current proposal by

Virginia Electric and Power Company

(‘‘Virginia Power’’) seeks the Virginia

Commission’s approval of a major new

transmission line. Virginia Power

alleges that the line is needed since it

would increase the availability of

emergency off-system supplies and

allow it to lower its capacity reserve

requirements. If the Virginia

Commission were to approve the line, it

is conceivable that FERC could direct

Virginia Power to use this additional

interchange capability to facilitate

wholesale wheeling transactions. In

such an event, native load customers

may be adversely affected since the

utility would be forced to suffer

diminished reliability or build

additional generation or transmission

facilities.’’ (VA Com at 10–12). CCEM

asks the Commission to require studies

for short-term firm point-to-point

service or requests for capacity that are

posted on the OASIS.

Commission Conclusion

In the Final Rule, the Commission

explicitly stated that

public utilities may reserve existing

transmission capacity needed for native load

growth and network transmission customer

load growth reasonably forecasted within the

utility’s current planning horizon. However,

any capacity that a public utility reserves for

future growth, but is not currently needed,

must be posted on the OASIS and made

available to others through the capacity

reassignment requirements, until such time

as it is actually needed and used.426

This ability to reserve capacity to meet

the reliability needs of native load

would apply equally to transmission

built in the future.

VA Com requested clarification of the

intended treatment by the Commission

in the ATC calculation of a transmission

line built in lieu of generation for

purposes of lowering reserve

requirements for native load. If it seeks

to withhold capacity in response to a

request for service by an eligible

customer, the transmission provider

will have the burden of proof to

demonstrate that any reserved capacity

is needed for meeting native load and

network customers’ load growth or for

purposes of meeting a reserve

requirement level that is reasonable.

CCEM’s request is unnecessary

because system impact studies and

facilities studies are required pursuant

to tariff section 19 for both long-term

and short-term firm point-to-point

transmission service.
12360 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

Sections 19.2 and 32.2

Rehearing Requests

Utilities For Improved Transition and

VEPCO ask the Commission to modify

these sections to require that a system

impact study agreement specify the

estimated charge instead of the

maximum charge so that the

transmission provider may collect all

prudently incurred study costs.

Commission Conclusion

Utilities For Improved Transition and

VEPCO correctly note that the use of the

phrase ‘‘maximum’’ in the language of

tariff sections 19.2 and 32.2 may prevent

a utility from collecting the full costs of

conducting a system impact study

despite acting in a prudent manner.

Accordingly, the relevant portion of

these sections are modified as shown

below to eliminate this potential

inequity (deleted text in brackets):

(i) The System Impact Study Agreement

will clearly specify [the maximum charge,

based on] the Transmission Provider’s

estimate of the actual cost, and time for

completion of the System Impact Study. The

charge shall not exceed the actual cost of the

study.

Sections 19.3 and 19.4

Rehearing Requests

TAPS asserts that the 15-day periods

for customers to execute a service

agreement after completion of a system

impact study are too short and should

be lengthened to 30 days or the

transmission provider should be

allowed to provide an extension for

cause (with public notice) while the

customer is pursuing an agreement in

good faith.

Commission Conclusion

TAPS’ proposed changes are not

necessary because the eligible customer

is provided a sufficient response time

considering the situation to which the

eligible customer is responding.

Specifically, the 15-day period in

section 19.3 refers to the situation where

the transmission provider has

conducted a system impact study and

concluded that the requested service

can be provided without the need to

modify its transmission system. TAPS

provides no reason why the eligible

customer requesting the service should

not be prepared to immediately accept

the offer to provide service at the

transmission provider’s standard rate

(without the need for upgrades, the

eligible customer would not be assessed

incremental transmission charges).

Similarly, the 15-day period in

section 19.4 refers to the time in which

the eligible customer has to execute a

facilities study agreement in which it

agrees to pay the transmission provider

for the costs of conducting a facilities

study. In contrast, when the facilities

study is completed and the eligible

customer is provided with a good faith

estimate of any direct assignment

facilities and/or share of any network

upgrades, section 19.4 provides the

eligible customer with 30 days to

respond.

Section 22.1(d)

Rehearing Requests

Utilities For Improved Transition and

Florida Power Corp ask the Commission

to modify this section to require that a

request for modification of service on a

non-firm basis be made by submitting a

modification to the original application

with an OASIS posting. Otherwise, they

assert, this section implies that such

modifications would occur without

using the transmission provider’s

OASIS.

Commission Conclusion

Utilities For Improved Transition and

Florida Power Corp misinterpret this

section of the tariff. The Commission’s

intention is simply to clarify that the

customer’s request to modify its firm

transmission service to receive service

over secondary receipt and delivery

points on a non-firm basis would not

require a separate application for nonfirm transmission service. The concerns

expressed with respect to posting on the

OASIS are addressed in Order No. 889–

A.

Section 23.1

Rehearing Requests

CCEM asserts that the Commission

sHhould specify the filings necessary for

assignment of service referenced in this

section or delete the clause. In addition,

CCEM asks the Commission to clarify

that the identical services will be

provided at no additional cost to the

assignee or the reseller.

Commission Conclusion

The pro forma tariff is a tariff of

general applicability. For administrative

reasons, the listing of every conceivable

situation in which an assignment or

transfer of service from one entity to

another may require a separate filing is

not feasible. For example, if the

Commission lists only a single situation

that requires a separate filing and

subsequently determines another

situation would also require a filing, all

of the pro forma tariffs on file with the

Commission would need to be revised

to reflect the change.

CCEM’s request that the Commission

clarify that reassigned services will be

provided at no extra cost is also denied.

CCEM ignores the fact that nothing in

the pro forma tariff prevents the

transmission provider from seeking a

change in rates pursuant to a section

205 filing whether such filing relates to

a general increase in rates to all

transmission customers or to additional

costs the transmission provider asserts it

incurs due to providing service to an

assignee. As always, the transmission

provider bears the burden of proof of

demonstrating that its proposal is just

and reasonable.

Section 23.2

Rehearing Requests

CCEM asks the Commission whether

an assignee can change primary points

if there is only a partial assignment.

Commission Conclusion

Whether the assignment is full or

partial is immaterial. If an assignee

wishes to change its receipt or delivery

points on a firm basis (full or partial),

the request will be treated as a new

request for service as required under

tariff sections 22.1 and 23.1. However,

if an assignee wishes to change receipt

or delivery points on a non-firm (full or

partial) basis, such change can be

accomplished without the need for a

new service agreement as provided in

pro forma tariff section 22.1.

Sections 25 and 34

Rehearing Requests

VT DPS asks the Commission to

revise these sections to state that ‘‘all

firm customers should share in non-firm

revenues’’ consistent with the language

of the preamble.

Commission Conclusion

VT DPS’ request is denied. The

Commission did not intend to mandate

the rate methodology used to reflect any

cost reductions that may be associated

with the provision of non-firm

transmission service. While the

Commission would generally expect all

firm customers to share in non-firm

revenues, the use of revenue credits is

not the only acceptable method of

reflecting non-firm system usage. The

transmission provider’s method of

reflecting revenues from non-firm

service should be addressed on a caseby-case basis.

Section 29.1

Rehearing Requests

TAPS contends that, to avoid

improper use of operating agreements

by transmission providers, the
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12361

427While firm resources can also go off line, the

probability of this happening is less than that for

interruptible resources. 428See also NRECA.

Commission should either permit

network operating agreements to be

filed in unexecuted form or include a

network operating agreement as part of

the pro forma tariff.

Commission Conclusion

The network operating agreement is

expected to be a highly detailed

agreement between the transmission

provider and network customer that

establishes the integration of the

network customer within the

transmission provider’s transmission

system. Due to the unique

characteristics of network customers’

systems and the level of customerspecific information and arrangements

required under a network operating

agreement, it is likely that each network

operating agreement will be different for

each customer. Accordingly, the

Commission does not believe it

appropriate to mandate a particular

form of network operating agreement for

inclusion in the pro forma tariff.

However, if a transmission provider

wishes to include a generic form of

network operating agreement in its pro

forma tariff (to be modified as required

and as mutually agreed to on a

customer-specific basis), it may propose

to do so in a section 205 filing or it may

file an unexecuted network operating

agreement in a section 205 filing.

To the extent a customer believes a

transmission provider is engaging in

unduly discriminatory practices via the

network operating agreement, the

customer may file a section 206

complaint with the Commission.

Section 29.4

Rehearing Requests

TDU Systems asserts that this section

does not identify who should determine

what facilities are ‘‘necessary to reliably

deliver capacity and energy. * * *’’ It

asks the Commission to clarify that this

is solely the responsibility of the

transmission customer.

Commission Conclusion

TDU Systems’ argument ignores tariff

section 35.1, which specifies:

[t]he Network Customer shall plan, construct,

operate and maintain its facilities in

accordance with Good Utility Practice and in

conformance with the Network Operating

Agreement. (emphasis added)

Accordingly, the determination of what

network customer facilities are

‘‘necessary to reliably deliver capacity

and energy * * *’’ is to be agreed upon

by both the transmission provider and

network customer and specified in the

network operating agreement. To the

extent the parties do not agree, the

transmission provider will file an

unexecuted network operating

agreement with the Commission and we

will resolve the dispute.

Section 30.1

Rehearing Requests

VT DPS argues that, consistent with

section 30.7, section 30.1 should not

require that a network resource be

available on a strictly non-interruptible

basis.

Commission Conclusion

VT DPS’ request is denied. The

Commission believes that a network

customer should only be allowed to

designate non-interruptible network

resources. To allow otherwise would

interfere with the planning process as

well as the day-to-day operation of the

transmission system to integrate

resources with customer’s loads (e.g.,

the transmission provider will be unable

to plan for what generation resource

will be available to meet a customer’s

load in the event its designated resource

is subject to interruption). Similarly, for

operational purposes on a day-to-day

basis, an interruption of a network

customer’s designated resource could

cause a transmission constraint.427

Because constraints affecting reliability

may lead to curtailment or redispatch of

all network resources, other network

customers would be affected by such

interruptions on a load-ratio basis.

However, to the extent a network

customer wishes to use an interruptible

generation source, it can still use this

generation source on an as-available

basis to import energy to serve its load

pursuant to pro forma tariff section 28.4.

Section 30.4

Rehearing Requests

PA Coops ask the Commission to

modify this section ‘‘to permit the

Network Resources to be operated at

outputs that exceed the Network

Customer’s designated Network Load

plus losses when the Network

Resource’s output is being sold to a

third party or the Network Resource is

called upon to be operated by the

Network Customer’s power pool, ISO or

control area operator.’’ (PA Coops at 8–

9). Similarly, Santa Clara and Redding

ask the Commission to modify the last

sentence to state: ‘‘* * * exceeds its

designated Network Load, plus non-firm

sales delivered under Part II, plus

losses’’ so that network resources will

not remain idle when they could

otherwise generate non-firm power and

energy for sale at competitive prices.

In addition, TDU Systems argues that

the arbitrary limits on the ability of

network customers to operate Network

Resources prevents economic dispatch

or the use of resources to meet load

requirements and limits the ability to

schedule the output of Network

Resources between and among control

areas, effectively preventing the network

customer from operating an integrated

system.428 TDU Systems asserts that the

Commission should not presume that a

network customer’s economic dispatch

will burden a transmission provider, but

should require a transmission provider

to demonstrate that such a burden will

occur. TAPS asks the Commission to

clarify this section so as to bar not the

operation of network resources in excess

of network load, but rather the usage of

network service in connection with

operation of such resources in excess of

network load. TAPS adds that section

30.4 is contrary to FMPA v. FPL, 74

FERC at 61,014–15. AEC & SMEPA

argues that the Commission should

provide the necessary latitude for such

resources to be used across multiple

control areas to service the total load of

transmission users.

Commission Conclusion

Preliminarily, TDU Systems and

others’ argument that a designated

network resource must consist of the

entirety of a generating unit is mistaken,

as we explained in sections 1.22 and

1.25 above. The Commission’s intent in

requiring that the output of network

resources not exceed network load plus

losses is to prevent designated network

resources from being used to make firm

sales to third parties. This is consistent

with the pro forma tariff’s requirement

in sections 1.25 and 30.1 that:

Network Resources may not include

resources, or any portion thereof, that are

committed for sale to non-designated third

party load or otherwise cannot be called

upon to meet the Network Customer’s

Network Load on a non-interruptible basis.

Absent a requirement that network

resources always be available to meet a

customer’s network loads, reliability of

service to the network customer as well

as to native load and other network

customers could be affected, as we

describe in detail in section 30.1 above.

If a network customer desires to enter

into a firm sale from its designated

network resources or use such network

resources for meeting reserve

requirements, it must eliminate the

appropriate resources or portions

thereof from its designated network
12362 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

429FERC Stats. & Regs. at 31,694; mimeo at 172.

resources pursuant to pro forma tariff

section 30.

Santa Clara, Redding and others

contend that this limitation improperly

restricts the use of network resources for

non-firm sales. It was not the

Commission’s intent to prohibit the

network customer from engaging in nonfirm sales from idle designated network

resources. We find that the non-firm

operation of network resources will not

affect the availability of such resources

on a firm basis because such non-firm

uses are subject to interruption.

Accordingly, the Commission’s

concerns regarding the reliable

provision of network service are

satisfied.

Furthermore, as noted by

Pennsylvania Coops, emergencies could

arise in which the transmission provider

may request that a network customer

alter the operation of its network

resources in response to a contingency,

which action could result in a violation

of the limitation in section 30.4.

Therefore, the Commission believes an

exception to the network resources

output limitation is also appropriate for

such emergency situations. Accordingly,

tariff section 30.4 is revised, in relevant

part, consistent with the above findings,

as shown below (emphasis added):

The Network Customer shall not operate its

designated Network Resources located in the

Network Customer’s or Transmission

Provider’s Control Area such that the output

of those facilities exceeds its designated

Network Load, plus non-firm sales delivered

pursuant to Part II of the Tariff, plus losses.

This limitation shall not apply to changes in

the operation of a Transmission Customer’s

Network Resources at the request of the

Transmission Provider to respond to an

emergency or other unforeseen condition

which may impair or degrade the reliability

of its Transmission System.

The remaining concerns expressed by

TDU Systems with respect to the

economical operation of a network

customer’s loads and resources located

in multiple control areas are addressed

above in Section IV.G.1.b. (Network and

Point-to-Point Customers’ Uses of the

System (so-called ‘‘Headroom’’)).

Section 30.6

Rehearing Requests

CSW Operating Companies asks the

Commission to clarify that a customer

has the obligation to replace the loss of

a resource that is not physically

interconnected with the transmission

provider’s transmission system within

the time that is customary in the region

or be subject to curtailment and suggests

language to be included as section 33.8.

CSW Operating Companies indicates

that it intends to include a provision

addressing this issue in the form of a

network operating agreement included

in the individual companies’ Final Rule

compliance tariffs.

Commission Conclusion

The Commission agrees with CSW

Operating Companies that the

appropriate place to address detailed

operational requirements such as this is

the Network Operating Agreement. If

disputes arise, they can be addressed on

a case-by-case basis.

Section 30.7

Rehearing Requests

Wisconsin Municipals asks the

Commission to clarify that, for purposes

of comparability between network and

point-to-point customers, a customer

may not reserve capacity for firm pointto-point transmission service until the

customer can show that it owns or has

committed to purchase generation under

an executed contract that it intends to

use over the reserved transmission

contract path. Wisconsin Municipals

claims that without the requirement to

demonstrate ownership or contractual

rights to the output of a generation

resource, the point-to-point customers

will have the advantage over network

customers of being able to reserve

transmission service over facilities with

limited available transmission capacity

earlier than network customers.

Wisconsin Municipals also argues, in

essence, that a single or a few point-topoint customers would be able to engage

in hoarding of transmission capacity by

reserving all available transmission

capacity over certain transmission

facilities.

Commission Conclusion

The arguments presented by

Wisconsin Municipals in support of its

proposal are misplaced. Wisconsin

Municipals’ assertion that point-to-point

customers would be able to reserve

transmission service over facilities with

limited available transmission capacity

earlier than network customers

overlooks the fact that the Final Rule

allows transmission providers to reserve

existing transmission capacity needed

for native load growth and network

transmission customer load growth

reasonably forecasted within the

transmission provider’s current

planning horizon.429 Wisconsin

Municipals’ concerns regarding

hoarding of transmission capacity are

answered in Section IV.C.6. (Capacity

Reassignment). Finally, Wisconsin

Municipals’ argument that

comparability requires that both

network and point-to-point customers

be required to demonstrate ownership

or contractual rights to the output of a

generation resource is not persuasive.

Network and firm point-to-point

transmission service are different

services. Firm point-to-point

transmission service is available for

periods as short as one day, whereas

network service is designed to

accommodate a longer term of service

with a minimum term of service of one

year. The requirement to demonstrate

ownership or contractual rights to

generation for network service is

necessary because the transmission

provider must be able to serve the

network load from any of the designated

resources. In contrast, point-to-point

service is a capacity reservation service

between specified points of receipt and

points of delivery. Accordingly, this

network requirement does not need to

be extended to firm point-to-point

service under the guise of

comparability.

Section 31.2

Rehearing Requests

TDU Systems asks the Commission to

clarify that an application for new

network load for an existing network

customer need only address the

additional network service needed to

serve the new Network Load and does

not in any way implicate the existing

network service for which the network

customer has already contracted.

Commission Conclusion

No clarification is necessary. Tariff

section 31.2 explicitly states in relevant

part:

A designation of new Network Load must

be made through a modification of service

pursuant to a new Application. (Emphasis

added)

Section 32.3

Rehearing Requests

TDU Systems asserts that this section

requires too short a time for customers

to evaluate a system impact study. It

argues that, at a minimum, customers

should have 60 days to evaluate a study

and, in the event of a dispute, the

application should remain viable until

the dispute is resolved (also argues that

the time periods set forth in sections

19.1, 19.4, 32.1, 32.3 and 32.4 are too

short).

Commission Conclusion

TDU Systems’ proposed changes are

not necessary as the pro forma tariff

provides an eligible customer sufficient

time to respond to a system impact
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12363

430E.g., Utilities For Improved Transition, Florida

Power Corp, VEPCO (asserts that rates for firm

point-to-point service should be developed in the

same way).

431FERC Stats. & Regs. at 31,738; mimeo at 304.

432See FERC Stats. & Regs. at 31,768–70; mimeo

at 394–99.

study. Specifically, the 15-day period in

section 32.3 refers to a situation where

the transmission provider has

conducted a system impact study and

concluded that the requested service

can be provided without the need to

modify its transmission system. TDU

Systems provides no reason why the

eligible customer should not be

prepared to immediately accept the offer

of providing service at the transmission

provider’s standard rate (without the

need for upgrades, the eligible customer

would not be assessed incremental

transmission charges).

Similarly, the 15 day period in

sections 19.1, 19.4, 32.1 and 32.4 refer

to the time in which the eligible

customer has to agree to execute an

agreement to pay the transmission

provider for costs of conducting studies

(a system impact study in sections 19.1

and 32.1 and a facilities study in

sections 19.4 and 32.4). TDU Systems

provides no reason why it should not be

prepared to accept or reject the

relatively minor costs of further studies

to determine whether its requested

transmission service can be

accommodated by the transmission

provider.

In contrast, when the facilities study

is completed and the eligible customer

is provided with a good faith estimate

of any direct assignment facilities and/

or share of any network upgrades, the

eligible customer is given 30 days to

respond, which is more than a sufficient

time.

Sections 33.2 and 34.4

Rehearing Requests

TAPS asserts that the Commission

cannot shunt aside the need for ongoing

revenue crediting to reduce

transmission charges as a rate issue,

while allowing monthly redispatch

costs to be collected monthly in charges

under the tariff. It contends that the

Commission must require revenues to

be shared on an ongoing, load-ratio

basis.

Commission Conclusion

As discussed above, redispatch of all

Network Resources and the

transmission provider’s own resources

is only to be performed to maintain the

reliability of the transmission system,

not for economic reasons. As a result,

the frequency of redispatch charges

being assessed to network customers is

expected to be infrequent. In addition,

the Commission is according substantial

flexibility to public utilities to propose

appropriate pricing terms in their

compliance tariff, which includes the

treatment of revenue credits. As

mentioned above, there are several

methods that utilities can use to

properly reflect a benefit from non-firm

transmission service to firm

transmission customers. We do not

believe it appropriate to mandate a

specific method, such as automatic

monthly flow through of revenue

credits, at this time. However, TAPS

may pursue this issue when utilities file

their compliance rates or subsequent

205 rate filings.

Section 34.3

Rehearing Requests

Several utilities assert that because

the monthly transmission system load is

composed in part of the contract

demands of all firm point-to-point

transmission customers and under the

Rule the charge for firm point-to-point

service may be derived by dividing the

transmission cost of service by the sum

of the transmission provider’s 12

monthly peak firm transmission loads,

the transmission provider is prevented

from recovering its entire cost of

service.430

Maine Public Service states that

parties should be allowed to argue on a

case-by-case basis that firm transmission

revenues should be credited instead of

including the demands in the

denominator (it indicates that this issue

is pending in Docket No. ER95–836). It

asserts that the revenue credit method

would prevent transmission providers

that offered discounts from unjustly

being penalized for that decision and is

the only method that permits utilities to

have an opportunity to recover their

costs. It adds that the Commission

established procedures to keep gas

pipelines whole in this same situation.

Commission Conclusion

While the Commission established

one method of calculating load ratios

and allocating costs in Order No. 888,431

utilities are free to propose alternative

pricing methodologies in a section 205

filing consistent with the Commission’s

Transmission Pricing Policy

Statement.432 We note, however, such

utilities will have the burden of

demonstrating that these methods

would not result in over-collections of

their revenue requirement.

Section 34.4

Rehearing Requests

TDU Systems asks the Commission to

clarify, as a matter of comparability, that

any mechanism proposed by a

transmission provider to collect charges

based on opportunity costs associated

with redispatch must provide for the

collection of other customers’ like costs

and payments to those customers.

Commission Conclusion

This issue is addressed in Section

IV.G.1.e. (Opportunity Cost Pricing).

Schedules 7 and 8

Rehearing Requests

TAPS asks the Commission to clarify

that these schedules do not approve

‘‘heightened’’ charges for short-term

services.

Commission Conclusion

The Commission did not specify

transmission rates for any tariff services

in Order No. 888. The rates for longterm firm transmission, short-term firm

transmission and non-firm transmission

services are to be proposed by the

transmission provider, as listed on

Tariff schedules 7 and 8, and filed with

the Commission. TAPS’ argument

regarding ‘‘heightened’’ charges for

these services is therefore premature.

TAPS is free to raise this concern at

such time as utilities file their proposed

transmission rates.

Attachment G

Rehearing Requests

Santa Clara and Redding ask the

Commission to modify Attachment G so

that, where interconnection/operational

standards are in place and working

effectively, additional standards are not

imposed simply as a result of switching

to the pro forma tariff from its current

interconnection service.

Commission Conclusion

The pro forma tariff does not

specifically require that the network

operating agreement between the

transmission provider and network

customer must be a new agreement.

However, the network operating

agreement is expected to be a highly

detailed agreement between the

transmission provider and network

customer establishing the integration of

the network customer within the

transmission provider’s transmission

system. Existing agreements between

the customer and transmission provider

may not provide all of the information

required or make all of the technical

arrangements required under the pro
12364 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

433To the extent a public utility has been granted

a waiver of the Order No. 888 tariff filing

requirements (or a non-public utility for reciprocity

purposes), it need not submit a request for a

separate waiver of the requirements of this order on

rehearing.

434FERC Stats. & Regs. at 31,768–70; mimeo at

393–400.

435FERC Stats. & Regs. at 31,768–69; mimeo at

394–96.

436As described in the Transmission Pricing

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

that meets the traditional revenue requirement and

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

at 31,141.

437 Given the brief comment period on the

compliance filings, the Commission required public

utilities to serve copies of their compliance filings

(via overnight delivery) on: all participants in their

current open access rate proceedings (if applicable);

all customers that have taken wholesale

transmission service from the utility after the date

of issuance of the Open Access NOPR; and the state

agencies that regulate public utilities in the states

of those participants and customers. By order

issued July 2, 1996, the Commission extended the

comment period from 15 days to 30 days.

438FERC Stats. & Regs. at 31,769; mimeo at 396–

97.

439The Commission held that Group 2 public

utilities must serve a copy of their filings (via

overnight delivery) on all customers that have taken

wholesale transmission service from them since

March 29, 1995 (the date of issuance of the Open

Access NOPR) and on the state agencies that

regulate public utilities in the states where those

customers are located. By order issued July 2, 1996,

the Commission extended the comment period from

15 days to 30 days.

forma tariff (e.g., redispatch and

ancillary services information and

arrangements.) Nevertheless, to the

extent the transmission customer is

currently receiving network integration

transmission service or similar service

and its present interconnection

agreement fully comports with the

requirements of the terms and

conditions of the tariff including the

informational requirements specified in

tariff sections 33 and 35, then the

present interconnection/operations

agreement can be substituted for a

network operating agreement or

modified appropriately.

9. Miscellaneous Tariff Administrative

Changes

Due to administrative oversight,

certain tariff sections require minor

corrections or modifications. Because of

the administrative nature of these

changes, we believe that no further

discussion is needed.

Section 12.1 Internal Dispute

Resolution Procedures

—Changes ‘‘Transmission Service’’ to

‘‘transmission service’’

Section 13.6 Curtailment of Firm

Transmission Service

—Changes the description regarding

curtailment of multiple transactions

to:

the Transmission Provider will curtail

service to Network Customers and

Transmission Customers taking Firm PointTo-Point Transmission Service on a basis

comparable to the curtailment of service to

the Transmission Provider’s Native Load

Customers.

10. Pro Forma Tariff Compliance Filings

Absent a waiver, all public utilities

must submit, no later than July 14, 1997,

a compliance filing that reflects the

tariff changes set forth in this order on

rehearing.433

A conforming pro forma tariff,

containing all the revisions and

clarifications contained in this order on

rehearing, is attached as Appendix B. In

addition, an electronic version of the

conforming pro forma tariff will be

made available on the Commission’s

electronic bulletin board service

(Commission Issuance Posting System

(CIPS)) in redline/strikeout form in

WordPerfect 5.1 format.

H. Implementation

In the Final Rule, the Commission set

forth the details of the implementation

procedures and included special

implementation requirements for

coordination arrangements (power

pools, public utility holding companies,

and bilateral coordination

arrangements).434

The Revised Procedures

The Commission adopted slightly

different implementation procedures for

Group 1 public utilities (tendered for

filing open access tariffs before the date

of issuance of the Rule) and for Group

2 public utilities (did not tender for

filing open access tariffs before the date

of issuance of the Rule).

1. Group 1 Public Utilities

In the Final Rule, the Commission

required Group 1 public utilities, within

60 days following publication of the

Final Rule in the Federal Register, to

make section 206 compliance filings

that contain the non-rate terms and

conditions set forth in the Final Rule

pro forma tariff and identify any terms

and conditions that reflect regional

practices, as discussed below.435

As to rates, the Commission noted

that a transmission tariff rate is already

in effect for all Group 1 public utilities,

except for the few with recentlytendered applications that have not yet

been accepted for filing.

The Commission noted, however, that

if a Group 1 public utility determined

that certain rate changes are

necessitated by the revised non-rate

terms and conditions, it may file a new

rate proposal under FPA section 205.

The Commission indicated that such

filings must be ‘‘conforming’’ 436 under

the Transmission Pricing Policy

Statement and must be made no later

than 60 days after publication of the

Final Rule in the Federal Register and

intervenors may raise any concerns with

the filings within 15 days after such

filings. 437 The Commission imposed a

blanket suspension for any filings by

Group 1 public utilities proposing rate

changes necessitated by the new nonrate terms and conditions. The

Commission further indicated that these

rates will go into effect, subject to

refund, 60 days after publication of this

Rule in the Federal Register (the same

day on which the non-rate terms and

conditions of the Final Rule pro forma

tariff go into effect).

2. Group 2 Public Utilities

In the Final Rule, the Commission

indicated that Group 2 public utilities

will be treated the same as Group 1

public utilities with regard to non-rate

terms and conditions, but will be treated

slightly differently from Group 1 as to

rates, since Group 2 utilities have not

filed any proposed rates.438 The

Commission required these utilities to

either: (i) within 60 days following

publication of the Final Rule in the

Federal Register, make section 206

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

the Final Rule pro forma tariff and

identify any terms and conditions that

reflect regional practices, as discussed

below; and (ii) within 60 days following

publication of the Final Rule in the

Federal Register, make section 205

filings to propose rates for the services

provided for in the tariff, including

ancillary services; or (iii) make a ‘‘good

faith’’ request for waiver. The

Commission added that the rates must

meet the standards for conforming

proposals in the Commission’s

Transmission Pricing Policy Statement

and comply with the guidance

concerning ancillary services set forth in

this order.

The Commission explained that

intervenors may raise any concerns with

these filings within 15 days after the

filing.439 The Commission imposed a

blanket suspension for all such rate

filings and indicated that they will go

into effect, subject to refund, 60 days

after the publication of this Rule in the

Federal Register (the same day on

which the terms and conditions of the

compliance tariffs go into effect).
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12365

440FERC Stats. & Regs. at 31,769–70; mimeo at

397–98.

441FERC Stats. & Regs. at 31,770; mimeo at 398–

99.

442FERC Stats. & Regs. at 31,770; mimeo at 399–

400.

443FERC Stats. & Regs. at 31,768–69; mimeo at

394–96.

444FERC Stats. & Regs. at 31,665; mimeo at 87–

88.

445See also discussion of prior settlements in

Section IV.D.1.c.(2) (Energy Imbalance Bandwidth).

3. Clarification Regarding Terms and

Conditions Reflecting Regional Practices

In the Final Rule, the Commission

explained that it had built a degree of

flexibility into the tariffs to

accommodate regional and other

differences. 440 It explained that certain

non-rate Final Rule pro forma tariff

provisions specifically allow utilities

either to follow the terms of the

provision or to use alternatives that are

reasonable, generally accepted in the

region, and consistently adhered to by

the transmission provider (e.g., time

deadlines for scheduling changes, time

deadlines for determining available

capacity). In addition, it explained that

other tariff provisions require utilities to

follow Good Utility Practice (section

1.14 of the Final Rule pro forma tariff).

4. Future Filings

In the Final Rule, the Commission

indicated that once the compliance tariff

and conforming rates go into effect,

which would be 60 days after

publication of the Rule in the Federal

Register, a public utility (either Group

1 or Group 2) may file pursuant to

section 205 a tariff with terms and

conditions that differ from those set

forth in this Rule, provided that, among

other things, it demonstrates that such

terms and conditions are consistent

with, or superior to, those in the

compliance tariff.441 However, the

Commission emphasized that the public

utility may not seek to litigate

fundamental terms and conditions set

forth in the Final Rule. In addition, the

Commission explained that the public

utility may file whatever rates it

believes are appropriate, consistent with

the Transmission Pricing Policy

Statement.

5. Waiver

In the Final Rule, the Commission

found that it is reasonable to permit

certain public utilities for good cause

shown to file, within 60 days after the

Rule is published in the Federal

Register, requests for waiver from some

or all of the requirements of this Rule.442

The Commission explained that the

filing of a request in good faith for a

waiver from the requirement to file an

open access tariff will eliminate the

requirement that such public utility

make a compliance filing unless

thereafter ordered by the Commission to

do so. The Commission emphasized,

however, that it will not exempt such

public utility from providing, upon

request, transmission services consistent

with the requirements of the Final Rule.

Rehearing Requests

Wisconsin Municipals asserts that the

Commission should ‘‘require utilities (if

requested by their customers) to honor

the settlements to which they have

agreed and to file the pro forma tariff,

modified to incorporate settlement

provisions that exceed the minimum

provisions of the pro forma tariff, as

their implementational filing.’’

Alternatively, it asks that the

Commission ‘‘require parties with

settlements to make a Section 205 filing

one day following their implementation

filing, change any rates, terms and

conditions in the pro forma tariff as

necessary to incorporate any superior

provisions from their settlement tariffs

into the pro forma tariff, and seek any

waivers necessary to make the

settlement tariff effective immediately.’’

(Wisconsin Municipals at 7–10).

Blue Ridge requests rehearing of the

‘‘unbalanced tariff implementation

process that rolls over the due process

rights of transmission customers.’’ It

asserts that utilities should not have the

right to file a ‘‘‘Good Utility Practices,’

blank check variance for regional

practices in the compliance docket.’’

(Blue Ridge at 33–35). Blue Ridge

further requests that Group 1 utilities

file compliance tariffs in the same

docket as their pending open access

dockets and asks that subsequent

changes be in a separate docket as a new

general rate case. Blue Ridge also states

that the Commission should explicitly

mention that customers have the right to

file section 206 requests to change the

tariffs.

Indianapolis P&L argues that the

pricing requirements are unjust,

unreasonable, unlawful, confiscatory

and an abuse of discretion as to

Indianapolis P&L. It asserts that its rates

are not based on embedded, original

cost, but, as a matter of Indiana law, its

utility property is valued at the ‘‘fair

value,’’ which exceeds the embedded

original cost of such property. It

declares that it is impossible for

Indianapolis P&L to comply with both

the comparability requirement and the

requirement that transmission rates be

based on original cost. It states that the

requirement to provide transmission

service and generation-based ancillary

services at rates based on original cost

is not comparable to Indianapolis P&L’s

own use of its assets. Accordingly, it

argues that the Commission should

allow Indianapolis P&L to set its initial

open access rates on a fair value, longrun marginal cost basis. Alternatively, it

states that the Commission could grant

Indianapolis P&L a waiver from the

requirements of the Open Access Rule.

Indianapolis P&L further argues that

the imposition of an obligation to

enlarge generation to provide ancillary

services is beyond the Commission’s

statutory authority. It explains that

Indianapolis P&L is an incidental

transmission owner and a relatively

small public utility and asks that the

Commission grant it waiver from the

requirements of open access and OASIS.

In deciding whether to grant a waiver,

it asserts that the Commission should

also consider system size and

configuration, the amount of wholesale

revenues or MWH sales, or the

availability of competing transmission

paths.

Union Electric argues that the final

rules violate procedural due process and

that the implementation schedule is

unrealistically ambitious. It argues that

where the final rules call for changes

from the NOPRs that could not be

reasonably anticipated, they amount to

deprivation of due process and rights to

fairness in the administrative process.

Indeed, it points out, the Commission

itself has not even completed its

promulgation of the OASIS Final Rule.

Union Electric is concerned that it has

not had an adequate time to comply

with and comment on the rules.

Commission Conclusion

Wisconsin Municipals has

misinterpreted the Commission’s

findings in Order No. 888, and thus its

concerns are without merit. While it is

true that Order No. 888 requires all

public utilities to make compliance

filings containing the non-price terms

and conditions set forth in the Final

Rule pro forma tariff,443 Order No. 888

also states that ‘‘we are not abrogating

existing requirements and transmission

contracts generically. * * *’’ 444 In

short, the Commission is not requiring

(or even generically allowing) the

abrogation of existing transmission

contracts, but is only requiring that

jurisdictional transmission providers

must also offer transmission service

under the Final Rule pro forma tariff in

addition to whatever commitments the

provider will continue to have under its

existing contracts. 445

As to Wisconsin Municipals’

assertions that prior individual

settlement provisions may exceed the
12366 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

446See IES Utilities, Inc., et al., 78 FERC ¶ 61,023

(1997).

447We do note that most of these concerns have

been addressed in our orders dealing with the

compliance filings on non-rate terms and

conditions. See, e.g., Atlantic City Electric

Company, et al., 77 FERC ¶ 61,144 (1996);

Allegheny Power System, Inc., et al., 77 FERC

¶ 61,266 (1996).

448 76 FERC ¶ 61,009 at 61,026–27 (1996) (July 2

Order).

449We also note that utilities were required in

Order No. 888 to explicitly identify any regional

practices in their compliance filings.

450By order issued September 11, 1996, the

Commission denied Indianapolis P&L’s requested

waiver of all the requirements of Order No. 888. On

October 8, 1996, Indianapolis P&L sought rehearing

of that order and a stay of the requirements of Order

No. 888. These pleadings are now pending before

the Commission.

451FERC Stats. & Regs. at 31,780–85; mimeo at

427–42.

minimum provisions of the pro forma

tariff, the Commission believes that

such arguments should be addressed on

a case-by-case basis. 446

Two additional points are pertinent.

First, we note that although we are not

generically abrogating existing

transmission contracts, utilities retain

whatever existing rights they had to

propose unilateral changes under

section 205 of the FPA if they want to

convert a customer to service under the

tariff, and customers retain their section

206 right to seek reformation of existing

transmission contracts if they are unjust,

unreasonable, unduly discriminatory or

preferential. Second, where a utility has

treated similarly-situated customers

differently—serving one under a more

favorable bilateral contract and another

under a less favorable tariff provision—

traditional undue discrimination

remedies may be available.

We deny Blue Ridge’s rehearing

requests because the Commission does

not intend to assume the regulatory

responsibility of identifying in the first

instance all of the regional practices

around the country that could (and

should) properly be reflected in the

compliance tariffs. Transmission

customers opposed to deviations related

to regional practices not only had the

opportunity to protest the compliance

filings when they were tendered, 447 but

these customers also have the right to

file section 206 requests to change these

tariffs at any time. In addition, Blue

Ridge’s request that customers be given

45 days to respond to compliance filings

instead of 15 days is moot. In an order

issued July 2, 1996,448 we took three

actions to address this concern: (1) we

gave entities 30 days, instead of 15 days,

to respond to Order No. 888 compliance

filings; (2) we agreed to post an

electronic version of all Order No. 888

compliance filings on the Commission’s

Electronic Bulletin Board; and (3) we

required all public utilities making a

compliance filing to also serve a copy of

their filing on electronic diskette to any

eligible customer or state regulatory

agency requesting a copy. We believe

that these actions not only provided all

interested parties with access to the

compliance filings more quickly, but

also provided these parties sufficient

time to analyze the information once

they received it.449 Moreover, the time

periods provided for making and

responding to Order No. 888

compliance filings have expired.

With regard to Blue Ridge’s first

clarification request, we provide the

following guidance. Utilities that had

pending open access filings at the time

that the Final Rule was implemented

had the non-price terms and conditions

of those pending tariffs superseded by

their Order No. 888 compliance filings.

Any customer concerns about the nonrate tariff terms and conditions in the

compliance filing should be raised in

the compliance docket, and any future

customer concerns should be raised in

a separate, future section 206 complaint

filed by the customer.

Furthermore, we reject Indianapolis

P&L’s rate issue because, if this utility

believes that it operates under special

circumstances that require it to use

‘‘non-conforming’’ pricing methods, it is

free to file such a proposal under

section 205. The merits of Indianapolis

P&L’s arguments are more appropriately

addressed in such a section 205

proceeding. The Commission will not

alter its generic policy (which is the

subject of this rulemaking) merely to

address the particular needs of one

party.

In addition, with regard to both of

Indianapolis P&L’s concerns, we note

that pursuant to the Commission’s July

2 Order, the Commission indicated that

it would not address waiver requests in

a generic proceeding and that parties

would have to file such requests

separately for separate docketing. We

further note that Indianapolis P&L filed

a separate waiver request on July 9,

1996, which was docketed as OA96–

81.450

We also reject Union Electric’s

argument that the final rules violate

procedural due process. Union Electric

has had every opportunity to raise

arguments with regard to every step in

the Commission’s derivation and

implementation of the final rules.

Moreover, with regard to Union

Electric’s claim that it was given an

inadequate amount of time to

comprehend and implement the final

rules, we note that virtually every

public utility, including Union Electric,

complied with the Open Access Rule on

a timely basis, and there have been very

few complaints that the rules are hard

to comprehend.

I. Federal and State Jurisdiction:

Transmission/Local Distribution

In the Final Rule, the Commission

explained that after reviewing the

extensive analysis of the FPA,

legislative history, and case law

contained in both the initial Stranded

Cost NOPR and in the Open Access

NOPR, and the comments received on

that analysis, it reaffirmed its assertion

of jurisdiction over the transmission

component of an unbundled interstate

retail wheeling transaction.451 The

Commission also reaffirmed and

clarified its determinations regarding

the tests to be used to determine what

constitute Commission-jurisdictional

transmission facilities and what

constitute state-jurisdictional local

distribution facilities in situations

involving unbundled wholesale

wheeling and unbundled retail

wheeling.

The Commission also explained that

where states unbundle retail sales, it

will give deference to their

determinations as to which facilities are

transmission and which are local

distribution, provided that the states, in

making such determinations, apply the

seven criteria discussed in the NOPR

and reaffirmed by the Commission. In

addition, the Commission clarified that

there is an element of local distribution

service in any unbundled retail

transaction, and further clarified other

aspects of its jurisdictional ruling to

preserve state jurisdiction over matters

that are of local concern and will remain

subject to state jurisdiction if retail

unbundling occurs.

The Commission reaffirmed its legal

determination that if unbundled retail

transmission in interstate commerce

occurs voluntarily by a public utility or

as a result of a state retail access

program, this Commission has exclusive

jurisdiction over the rates, terms, and

conditions of such transmission. The

Commission found compelling the fact

that section 201 of the FPA, on its face,

gives the Commission jurisdiction over

transmission in interstate commerce (by

public utilities) without qualification.

The Commission further explained

that when a retail transaction is broken

into two or more products that are sold

separately, the jurisdictional lines

change. In this situation, the

Commission emphasized that the state

clearly retains jurisdiction over the sale

of the power, but the unbundled
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12367

452 324 U.S. 515 (1945) (CL&P); 376 U.S. 205

(1964) (Colton).

453The Commission included a detailed legal

analysis in Appendix G to Order No. 888. The

Commission explained that it was particularly

persuaded by the Supreme Court’s statement that

whether facilities are used in local distribution is

a question of fact to be decided by the Commission

as an original matter. See CL&P, 324 U.S. at 534–

35).

454 In order to give such deference, the

Commission noted its expectation that state

regulators will specifically evaluate the seven

indicators and any other relevant facts and make

recommendations consistent with the essential

elements of the Rule.

455The Commission noted that such a tariff could

be different from the tariff that applies to wholesale

customers, but that such tariff would still be filed

with the Commission under FPA section 205.

transmission service involves only the

provision of ‘‘transmission in interstate

commerce’’ which, under the FPA, is

exclusively within the jurisdiction of

the Commission.

The Commission recognized that in

asserting jurisdiction over unbundled

retail transmission in interstate

commerce by public utilities, it was in

no way asserting jurisdiction to order

retail transmission directly to an

ultimate consumer. It explained that its

assertion of jurisdiction is that if

unbundled retail transmission in

interstate commerce by a public utility

occurs voluntarily or as a result of a

state retail wheeling program, the

Commission has exclusive jurisdiction

over the rates, terms, and conditions of

such transmission and public utilities

offering such transmission must comply

with the FPA by filing proposed rate

schedules under section 205.

The Commission further clarified that

nothing in its jurisdictional

determination changes historical state

franchise areas or interferes with state

laws governing retail marketing areas of

electric utilities. It explained that while

its jurisdiction cannot affect whether

and to whom a retail electric service

territory (marketing area) is to be

granted by the state, and whether such

grant is exclusive or non-exclusive,

neither can state jurisdiction affect this

Commission’s exclusive jurisdiction

over transmission in interstate

commerce by public utilities.

The Commission also adopted a new

section 35.27(b) as follows:

Nothing in this part (i) shall be construed

as preempting or affecting any jurisdiction a

state commission or other state authority may

have under applicable state and federal law,

or (ii) limits the authority of a state

commission in accordance with state and

federal law to establish (a) competitive

procedures for the acquisition of electric

energy, including demand-side management,

purchased at wholesale, or (b) nondiscriminatory fees for the distribution of

such electric energy to retail consumers for

purposes established in accordance with

state law.

With respect to the Commission’s

adoption of the Open Access NOPR’s

functional/technical tests for

determining what facilities are

Commission-jurisdictional facilities

used for transmission in interstate

commerce and what facilities are statejurisdictional local distribution

facilities, the Commission concluded

that it could not divine a bright line for

unbundled retail transmission by the

public utility that previously provided

bundled retail service to the end user.

The Commission added that the limited

case law, including Connecticut Light &

Power Company v. FPC (CL&P) and

Federal Power Commission v. Southern

California Edison Company (the Colton

case),452 supports a case-by-case

determination.453 Accordingly, the

Commission stated that its technical

test, with its seven indicators, will

permit reasoned factual determinations

in individual cases.

The Commission made two

clarifications regarding local

distribution in the context of retail

wheeling. First, it explained that even if

its technical test for local distribution

facilities were to identify no local

distribution facilities for a specific

transaction, states have authority over

the service of delivering electric energy

to end users. Second, the Commission

explained that through their jurisdiction

over retail delivery services, states have

authority not only to assess retail

stranded costs but also to assess charges

for so-called stranded benefits, such as

low-income assistance and demand-side

management.

Thus, under this interpretation of

state/federal jurisdiction, the

Commission explained, customers have

no incentive to structure a purchase so

as to avoid using identifiable local

distribution facilities in order to bypass

state jurisdiction and thus avoid being

assessed charges for stranded costs and

benefits.

The Commission further determined

that it is appropriate to provide

deference to state commission

recommendations regarding certain

transmission/local distribution matters

that arise when retail wheeling occurs.

In instances of unbundled retail

wheeling that occurs as a result of a

state retail access program, the

Commission indicated that it will defer

to recommendations by state regulatory

authorities concerning where to draw

the jurisdictional line under the

Commission’s technical test for local

distribution facilities, and how to

allocate costs for such facilities to be

included in rates, provided that such

recommendations are consistent with

the essential elements of the Final

Rule.454 Moreover, the Commission

indicated that it will consider

jurisdictional recommendations by

states that take into account other

technical factors that the state believes

are appropriate in light of historical uses

of particular facilities.

As a means of facilitating

jurisdictional line-drawing, the

Commission stated that it will entertain

proposals by public utilities, filed under

section 205 of the FPA, containing

classifications and/or cost allocations

for transmission and local distribution

facilities. However, the Commission

explained that, as a prerequisite to filing

transmission/local distribution facility

classifications and/or cost allocations

with the Commission, utilities must

consult with their state regulatory

authorities. If the utility’s classifications

and/or cost allocations are supported by

the state regulatory authorities and are

consistent with the principles

established in the Final Rule, the

Commission indicated that it will defer

to such classifications and/or cost

allocations.

Furthermore, the Commission stated

that deference to state commissions

with regard to rates, terms, and

conditions may be appropriate in some

circumstances. The Commission

explained that when unbundled retail

wheeling in interstate commerce occurs,

the transaction has two components for

jurisdictional purposes—a transmission

component and a local distribution

component. It again emphasized that the

Commission has jurisdiction over

facilities used for the transmission

component of the transaction, and the

state has jurisdiction over facilities used

for the local distribution component.

Thus, the Commission stated, the rates,

terms and conditions of unbundled

retail transmission by a public utility

must be filed at the Commission.

However, the Commission added, if the

unbundled retail wheeling occurs as

part of a state retail access program, it

may be appropriate to have a separate

retail transmission tariff 455 to

accommodate the design and special

needs of such programs. In such

situations, the Commission indicated

that it will defer to state requests for

variations from the FERC wholesale

tariff to meet these local concerns, so

long as the separate retail tariff is

consistent with the Commission’s open

access policies and comparability

principles reflected in the tariff

prescribed by the Final Rule. In

addition, the Commission indicated that
12368 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

456 In applying the principles of the Final Rule to

retail transmission tariffs, the Commission

emphasized that it clearly cannot order retail

wheeling directly to an ultimate consumer. (citing

FPA section 212(h)).

457E.g., NARUC, WI Com, WY Com.

458See also IA Com (use of a utility’s transmission

system to serve its own retail customers is a

bundled part of the retail sale transaction, which

supports a simpler jurisdictional test holding that

a movement of power by the last utility in any

chain of delivery to a retail customer is a

distribution transaction). 459See also PA Com.

the rates must be consistent with its

Transmission Pricing Policy Statement,

and the guidance set forth in Order No.

888 concerning ancillary services. 456

The Commission also expressed

concern, just as it did with buy-sell

arrangements in the gas industry, that

buy-sell arrangements can be used by

parties to obfuscate the true transactions

taking place and thereby allow parties to

circumvent Commission regulation of

transmission in interstate commerce.

Thus, the Commission reaffirmed its

conclusion that it has jurisdiction over

the interstate transmission component

of transactions in which an end user

arranges for the purchase of generation

from a third-party. Moreover, the

Commission indicated that it will

address these transactions on a case-bycase basis.

Rehearing Requests

Oppose Commission Assertion of

Jurisdiction Over Unbundled Retail

Transmission

Several state commissions indicate

that, recognizing that the case law is not

dispositive concerning the question of

unbundled retail transmission services

(either because the cases do not involve

the transmission of power to retail

customers or ‘‘fence off’’ local

distribution from federal regulation), at

least one court (Wisconsin-Michigan

Power Company v. FPC, 197 F.2d 472

(7th Cir. 1952), cert. denied, 345 U.S.

934 (1953)) explicitly applied the

wholesale/retail distinction to

distinguish transmission and local

distribution services. 457 Thus, they

argue, the Commission should apply the

wholesale versus retail analysis to the

question of unbundled retail

transmission.

IL Com asserts that retail transmission

by a public utility directly to an end

user has always (even before the FPA

was enacted) been subject to regulation

by the states. It contends that no change

in law has occurred which justifies the

Commission’s claim of expanded

jurisdiction. Moreover, it disagrees with

the Commission’s conclusion that the

unbundled delivery by the previous

public utility generation supplier

directly to an end user is in interstate

commerce. It argues that the FPA was

never intended to disturb the

jurisdiction of state regulators that

existed prior to its passage and that

retail transmission of electric energy by

a public utility to an end user was under

state jurisdiction before the Attleboro

decision and has remained under state

jurisdiction in the over sixty years

following Attleboro. Even after

unbundling, according to IL Com,

transmission to a retail customer still

involves a retail sale of transmission.

NARUC and VA Com assert that the

legislative history provides little

support for the Commission’s

conclusion that the act of unbundling

generation from delivery serves to shift

jurisdiction from a state commission to

the Commission. If anything, they

contend, the jurisdictional structure of

the FPA is predicated on the distinction

between retail and wholesale

transactions, not bundled and

unbundled services. They assert that the

Commission should conclude that the

rates, terms and conditions of service for

delivery of power by a utility to an enduse customer are subject to the

jurisdiction of the state commission

regulating the utility, regardless of the

identity of the party generating or

reselling the power or the facilities used

to transport the power.

NARUC asserts that the Commission

did not address a point raised in

NARUC’s reply comments as to how the

removal of generation serves to

unbundle the retail delivery function

into separate transmission and

distribution services. It maintains that

the Commission simply assumes that a

resulting transmission transaction is

created when power is sold to a retail

consumer by someone other than the

utility delivering the power. 458

MI & NH Coms ask the Commission

to vacate those portions of the Rule that

find that the Commission has

jurisdiction over the transmission

component of an unbundled retail sale

in a local retail wheeling transaction.

They assert that the Commission should

confine its activity to wholesale

transactions or those interstate

transactions that do not implicate

matters of local concern. They argue

that the dual federal/state regulatory

scheme establishes that Congress’ intent

is that state regulation of retail wheeling

is not preempted by federal law as

established in FPA section 201. They

oppose unnecessary federal intrusion

into local matters under a one-size-fitsall approach and assert that the retail

wheeling initiatives in New Hampshire

and Michigan are tailored to the unique

utility environment in each state.

Central Illinois Light argues that

unbundling of retail electric service

does not change the states’ longstanding

jurisdiction over retail electric service

and local distribution, even when that

service involves the use of transmission

in interstate commerce. It asserts that

201(b)(1) (‘‘transmission of electric

energy in interstate commerce’’) cannot

be read in a vacuum.

MN DPS & MN Com and OH Com

assert that the Commission should have

no role in the regulation of retail

services, be they bundled or unbundled.

They argue that, in refusing to grant the

Commission authority over retail

wheeling, Congress left jurisdiction over

retail electric service to the states. They

conclude that the Final Rule contains

insufficient legal and/or policy

justification for the Commission’s

assertion of jurisdiction over unbundled

retail transmission services.

MN DPS & MN Com assert: ‘‘FERC

bases its usurpation of state authority

over retail transmission rates on its

claim that balkanization would occur

without the assertion of FERC authority.

Therefore, the parties are entitled to

rehearing so that this essential issue can

be further analyzed.’’ (MN DPS & MN

Com at 1–3).

FL Com argues that the Commission

has not justified why the act of

unbundling prices expands the

Commission’s jurisdiction into retail

marketing areas. It argues that Section

212(g) of the FPA has the effect of

prohibiting the Commission from

usurping existing state jurisdiction over

retail transmission service, whether

bundled or unbundled. According to FL

Com, FERC’s jurisdiction over

transmission terminates at the territorial

boundary of each electric utility in

Florida. It supports wheeling in

jurisdiction for state commissions and

wheeling out and wheeling through

jurisdiction for the Commission.

IN Com opposes federalization of

retail wheeling transactions within a

state’s boundaries as contrary to the

FPA’s legislative history and case law.

NJ BPU asserts that by claiming

jurisdiction over unbundled retail

transmission, the Commission is

creating a disincentive for states to

implement retail access because, by

ordering retail access, the states may be

relinquishing their jurisdiction over

unbundled retail transmission terms

and conditions—jurisdiction that they

would maintain under a bundled

scenario. 459 PA Com argues that the

Commission does not have the authority
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12369

460 88 F.3d 1105, 1152–53 (1996) (United

Distribution Companies).

461Public Utilities Commission v. Attleboro

Steam & Electric Co., 273 U.S. 83 (1927).

462The case law is addressed extensively in

Appendix G to the Final Rule and will not be

repeated here.

463On rehearing, several parties argue that at least

one court case, Wisconsin-Michigan Power Co. v.

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

U.S. 934 (1953) explicitly applied the wholesale/

retail distinction to distinguish transmission and

local distribution services. The Commission

discussed this case in detail in Appendix G to the

Final Rule, FERC Stats. & Regs. at 31,974–75;

mimeo at 22–25. As we stated there, the court’s

interpretation of the legislative history of the FPA

was at odds with both the plain words of the statute

as well as the language of the House Report on the

FPA (H.R. Rep. No. 1318 at 27). It also did not

mention the Senate Report on the FPA, which

clearly recognized jurisdiction over all interstate

transmission lines, whether or not a sale of energy

is carried by those lines (S. Rep. No. 621 at 48). We

therefore reject arguments that this single case is in

any way dispositive of the issue before us.

to order retail wheeling and that the

jurisdictional formula is challengeable

on engineering and legal grounds. It

concludes that the Commission does not

have jurisdiction over unbundled

interstate retail transmission service. PA

Com notes that the 1996 House and

Senate hearings have raised the question

whether the Commission has the

statutory authority to restructure the

electric industry. PA Com questions the

Commission’s definition of the

‘‘traditional tasks of state and federal

regulators’’ on the basis of section

201(b) of the FPA, the Supremacy

Clause, and the Tenth Amendment of

the U.S. Constitution.

Support Broader Assertion of

Jurisdiction by the Commission Over

Retail Wheeling

NY Utilities declare that the

Commission has jurisdiction over retail

wheeling from the source to the load,

but does not have jurisdiction over

transmission in bundled retail service.

They assert that the Commission’s

reliance on state jurisdictional local

distribution as a predicate to abstain

from allowing retail wheeling stranded

cost recovery is without foundation.

They further assert that a unique

element that sets local distribution apart

from transmission is not the size of the

facility or the length of travel, but that

transportation is bundled with a retail

sale. According to NY Utilities, the

plain meaning of the FPA shows that

local distribution is bundled retail

service. They claim that the legislative

history, to the extent necessary, and

court cases support FERC jurisdiction

over all aspects of retail wheeling, but

makes clear that the Commission cannot

regulate bundled retail service. They

add that the NGA also demonstrates that

local distribution means bundled retail

service.

Commission Conclusion

In concluding that this Commission

has exclusive jurisdiction over the rates,

terms and conditions of unbundled

retail transmission by public utilities in

interstate commerce, the Commission in

Order No. 888 thoroughly examined the

statutory language of the FPA and its

legislative history, and relevant FPA

and NGA case law. While the state

commissions on rehearing would like us

to draw a bright line that gives them, to

varying degrees, jurisdiction over retail

interstate transmission by public

utilities, no party on rehearing has

raised any legislative history or case law

that was not previously considered and

that would support the proposition that

states have jurisdiction over any

unbundled transmission in interstate

commerce. As explained below, we

reaffirm our jurisdictional interpretation

on rehearing and believe that it is

supported by the recent decision in

United Distribution Companies v.

FERC.460

Many of the rehearing arguments

focus on the fact that states historically

(even prior to the FPA) regulated retail

transmission insofar as it was a

component of bundled electric service

to an end user, and they argue that by

asserting jurisdiction over unbundled

retail transmission, the Commission is

somehow ‘‘taking away’’ jurisdiction the

states previously had. The flaw in these

arguments is their inherent assumption

that jurisdiction over transmission

service turns upon the question of

whether the transmission service is

being provided for ‘‘wholesale’’ or

‘‘retail’’ power sales. That is not the

case. The question of jurisdiction rather

turns upon the extent of the

Commission’s exclusive jurisdiction

over transmission in interstate

commerce under the FPA. The fact that

states historically regulated most retail

transmission service as a part of a

bundled retail power sale is not the

result of a legal requirement; it is the

practical result of the way electricity has

historically been bought and sold.

However, the shape of power sales

transactions is rapidly changing. Rather

than claiming ‘‘new’’ jurisdiction, the

Commission is applying the same

statutory framework to a business

environment in which, as discussed

below, retail sales and transmission

service are provided in separate

transactions.

In the past, retails ales occurred

almost exclusively on a bundled basis

(i.e., the same entity provided a

delivered product called electric energy

and transmission was part and parcel of

that product). The FPA clearly reserves

the right to regulate retail sales of

electric energy to the states. As we

explained in the Final Rule, however, in

today’s markets, and increasingly in the

future as more states adopt retail

wheeling programs, retail transactions

are being broken into products that are

being sold separately: transmission and

generation. Moreover, these products

are being sold increasingly by two or

more different entities. For example, a

transaction may involve transmission

service from one or more transmission

providers who move power from a

distant generation supplier, over the

interstate transmission grid, to an end

user. Because these types of products

and transactions were not prevalent in

the past, the jurisdictional issue before

us did not arise and, contrary to IL

Com’s argument, the Commission

cannot be viewed as ‘‘disturbing’’ the

jurisdiction of state regulators prior to

and after the Attleboro case.461

As we also explained in the Final

Rule, the legislative history of the FPA

and the relevant case law similarly

reflect the historical market structure in

which electricity and transmission

generally were bought on a bundled

basis.462 Today’s unbundled world

simply was not contemplated and the

cases do not resolve dispositively this

jurisdictional issue. The case law

focuses primarily on the bright line

between wholesale sales and retail sales

of energy, and transmission in interstate

as opposed to intrastate commerce. It

does not address unbundled retail

interstate transmission.463 We therefore

have interpreted the case law in light of

changed circumstances and have relied

in the first instance on the plain

wording of the statute. We find

compelling that section 201 of the FPA,

on its face, gives the Commission

jurisdiction over transmission in

interstate commerce without

qualification; unlike our jurisdiction

over sales of electric energy, which

section 201 specifically limits to sales at

wholesale, the statute does not limit our

transmission jurisdiction over public

utilities to wholesale transmission.

Since the time Order No. 888 issued,

the D.C. Circuit has addressed a similar

issue in interpreting section 1(b) of the

NGA, the provision that parallels

section 201(b) of the FPA. Under section

1(b), the Commission’s jurisdiction does

not apply ‘‘to the local distribution of

natural gas or to the facilities used for

such distribution.’’ Similarly, under

section 201(b) of the FPA, the

Commission shall not have jurisdiction,

except as specifically provided, ‘‘over
12370 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

464See FPC v. Southern California Edison Co., 376

U.S. 205 (1964) (Colton case). IN Com makes a

similar argument and opposes ‘‘federalization’’ of

retail wheeling within a state’s boundaries. We

reject this argument on the same basis.

465See also WI Com (criteria do not appropriately

reflect the mixed nature of many facilities in

systems that are closely integrated and the

application of the criteria to the electric system in

Wisconsin would supplant state jurisdiction over a

large number of facilities whose primary functions

are local reliability and retail service).

facilities used for the generation of

electric energy or over facilities used in

local distribution * * *’’ In responding

to arguments regarding the scope of

state authority over ‘‘local distribution’’

of natural gas, the court distinguished

between bundled and unbundled sales:

States have been—and are still—permitted

to regulate LDCs’ bundled sales of natural gas

to end-users because those transactions

include transportation over local mains and

the retail sales of gas. In contrast, states have

never regulated the terms and conditions of

interstate pipeline transportation. When the

gas sales element is severed—i.e.,

unbundled—from the transactions, FERC

retains jurisdiction over the interstate

transportation component.’’ [United

Distribution Companies, 88 F.3d at 1153

(footnote omitted) (emphasis in original).]

The court’s reasoning is also applicable

to and supports our jurisdictional

determination in Order No. 888.

Several state commissions point to

section 212(h) of the FPA and argue that

Congress, in refusing to grant the

Commission authority to order retail

wheeling, left all jurisdiction over retail

transmission to the states. We disagree.

What Congress did in section 212(h)

was to prohibit us from ordering

transmission directly to an ultimate

consumer. We readily recognize and

respect this prohibition. However, the

ability to order retail wheeling is a

separate issue from whether we have

jurisdiction over the rates, terms and

conditions of retail wheeling in

interstate commerce that is ordered by

a state or that is provided voluntarily.

Congress, in enacting section 212(h), did

nothing to modify our jurisdiction

under sections 201, 205 and 206 over

the rates, terms and conditions of

interstate transmission by public

utilities.

Similarly, we reject FL Com’s

arguments that section 212(g) of the FPA

prohibits the Commission from asserting

any jurisdiction over unbundled retail

transmission. Section 212(g) prohibits

the Commission from issuing an order

that is inconsistent with any state law

that governs retail marketing areas of

electric utilities. As we stated in the

Final Rule, while our jurisdiction

cannot affect whether and to whom a

retail electric service territory

(marketing area) is to be granted by the

state, and whether such grant is

exclusive or non-exclusive, neither can

state jurisdiction affect this

Commission’s exclusive jurisdiction

over the rates, terms and conditions of

transmission in interstate commerce by

public utilities. We also reject

arguments by the FL Com that this

Commission’s jurisdiction over

transmission terminates at the territorial

boundary of each electric utility in

Florida. This argument is flatly contrary

to the longstanding interpretation of the

FPA by the United States Supreme

Court.464

Commission’s Seven Factor Test

IL Com argues that the Commission

should withdraw its technical test. It

contends that retail wheeling

jurisdiction should follow function and

that the function served by public utility

facilities in providing retail service does

not change upon the unbundling of

service to retail customers. According to

IL Com, Commission jurisdiction would

extend to the service of delivering

electric energy by a public utility to

wholesale customers, regardless of the

nature and extent of the public utility’s

facilities used to make that delivery.

Similarly, it asserts, state jurisdiction

would extend to the service of

delivering electric energy by a public

utility directly to retail customers,

regardless of the nature and extent of

the public utility’s facilities used to

make that delivery.

NARUC argues that the seven-factor

test does not result in the bright line

discussed in FPC v. Southern California

Edison Company, 376 U.S. 205 (1964).

The facility-by-facility categorization of

utility systems on a company-specific

basis, it asserts, is hardly consistent

with the Court’s decision to make caseby-case analysis unnecessary.

OH Com asserts that the seven factors

provide no useful insight into the nature

of local distribution service. It adds that

reliance upon technical tests to

determine local distribution lacks legal

foundation. It further contends that the

jurisdictional bright line established by

Congress focuses upon the nature of the

transaction, not the functional or

technical characteristics of a particular

wire, in determining whose

jurisdictional authority attaches to a

particular transaction and facilities. It

concludes that the Commission should

adopt the Ohio-proposed retail

marketing area ‘‘wheeling in’’

jurisdictional approach.

PA Com contends that the

Commission’s seven indicia are not

acceptable measures of local

distribution and challenges each factor.

NH & MI Coms declare that the

criteria for distinguishing transmission

facilities from local distribution

facilities should not be limited to the

seven given in the Rule, but should

allow consideration of any other

relevant criteria for separating local

concerns from matters legitimately

federal in nature.

NJ BPU argues that the engineeringdriven definition does not resolve many

of the hazy areas. To the extent that the

seven factors do not reflect or cannot be

reconciled with the particular

circumstances, it contends that the

states may be hamstrung in their ability

to make reasoned decisions that

comport with Order No. 888.465

Similarly, NY Com argues that five of

the seven factors (1, 2, 4, 6, and 7) are

not accurate when applied to large

metropolitan areas and remote rural

areas. It asserts that local distribution

facilities are not necessarily close to

retail customers and the assumption

that local distribution facilities are

primarily radial in character fails to

account for network systems. It adds

that reconsignment or transportation of

power to different markets can and does

occur at the local distribution level. It

further adds that the presence of meters

is not a discerning characteristic of

where interstate transmission ends and

local distribution begins; meters are

frequently not part of the transmission/

local distribution interface. Nor,

according to NY Com, are local

distribution systems necessarily of

reduced voltage. Instead of the 7

criteria, NY Com argues that the

Commission should adopt a functional

measure of local distribution based on

factors 3 and 5 (interstate transmission

ends and local distribution begins

where electricity flows into a

comparatively restricted geographic area

and does not flow back out of that area

and the power is consumed in that area)

and on the traditional classification of

the facilities by the state regulatory body

(or what the utility has traditionally

classified as local distribution).

Commission Conclusion

Several parties on rehearing do not

like the seven-factor technical test for

local distribution facilities that was set

forth in Order No. 888. That test takes

into account both technical and

functional characteristics of the

transaction involved. The parties on

rehearing propose instead a variety of

bright line tests. For example, IL Com

wants state jurisdiction to extend to the

‘‘service’’ of delivering electric energy to

retail customers, which it would define

to give it jurisdiction regardless of the
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12371

466See Colton, 376 U.S. at 210 n.6; CL&P, 324 U.S.

at 531–36.

467Pacific Gas and Electric Company, et al., 77

FERC ¶ 61,325 at 61,325 (1996).

nature and extent of the facilities used

to make the delivery. OH Com proposes

that the Commission adopt a retail

marketing area ‘‘wheeling in’’

jurisdictional approach which would

give it jurisdiction over facilities within

territorial boundaries.

In response, we do not interpret the

FPA to permit us in effect to rewrite the

statute to give states jurisdiction over

interstate transmission services.

Moreover, we reject arguments of OH

Com that our seven-factor test lacks

legal foundation, and arguments of

NARUC that we are somehow bound to

develop a bright line test. While

Congress established a jurisdictional

bright line between wholesale and retail

sales of energy, there is no such bright

line that we can divine with regard to

transmission and local distribution

facilities. The Supreme Court, in both

Colton and CL&P,466 has instructed us

that whether facilities are used in local

distribution is a question of fact to be

decided by the Commission as an

original matter. The seven factors will

permit us to undertake this fact-specific

determination.

We acknowledge the concerns raised

by several state commissions that the

seven-factor test does not, as NJ BPU

puts it, resolve many of the hazy areas,

and that there may be other factors that

should be taken into account in

particular situations. The seven-factor

test is intended to provide sufficient

flexibility to take into account unique

local characteristics and historical usage

of facilities used to serve retail

customers. We specifically stated in the

Final Rule that we will consider

jurisdictional recommendations by

states that take into account other

technical factors that states believe are

appropriate in light of historical uses of

particular facilities. Moreover, we will

defer to facility classifications and/or

cost allocations that are supported by

state regulatory authorities. For

example, in the ongoing California

electric utility restructuring proceeding,

the Commission deferred to the State

PUC’s recommendations regarding the

split between state jurisdictional local

distribution facilities and Commissionjurisdictional transmission facilities.467

Oppose Transmission of Public Utility

Purchases for Sale at Retail

IL Com objects to the transmission

unbundling requirement if it is intended

to require public utilities to take

transmission services under their own

FERC tariffs for purchases of power

intended for distribution by the public

utility to retail customers. According to

IL Com, a distinction must be made

between the public utility’s use of its

transmission system in cases in which

the public utility purchases wholesale

power for sale for resale, and cases in

which the public utility purchases

wholesale power to serve native load

retail customers. It argues that the

Commission cannot legally regulate, or

place conditions on, the manner in

which a utility uses its transmission

system to make sales of electric energy

at retail. It contends that the

Commission must exempt public utility

power purchases for sale at retail from

the unbundling requirement. It

recommends that the Commission insert

the words ‘‘for sale for resale’’ after the

word ‘‘purchases’’ in section 35.28(c)(2)

and after the word ‘‘purchase’’ in

section 35.28(c)(2)(i).

Commission Conclusion

The Commission rejects arguments of

IL Com that if unbundled retail

wheeling occurs either voluntarily or as

a result of a state retail program, we

cannot require the utility to take service

under its own transmission tariff for

sales to retail customers. This

requirement is a term and condition of

unbundled retail interstate transmission

service and, as explained above,

therefore is within our exclusive

jurisdiction. Additionally, this should

not in any way infringe on state retail

programs or service to retail customers.

Rather, it ensures that nondiscriminatory transmission services are

provided to all potential retail power

competitors.

Further, as stated previously in

Section IV.C.1.b (Transmission

Providers Taking Service Under Their

Tariff), we clarify that a transmission

provider does not have to ‘‘take service’’

under its own tariff for the transmission

of power that is purchased on behalf of

bundled retail customers.

Oppose Buy-Sell Transaction Analysis

PA Com asserts that there is a

potential for jurisdictional conflict with

respect to buy-sell transactions that is a

direct consequence of the technicalfunctional test (which PA Com

challenges).

IL Com argues that states have

exclusive authority to regulate buy-sell

arrangements as bundled retail sales. It

further argues that the Commission

cannot make a bundled retail sale into

an unbundled retail sale simply by

characterizing it as the functional

equivalent of an unbundled retail sale;

by re-characterizing them the

Commission is effectively ordering the

unbundling of buy-sell arrangements. It

asserts that buy-sell arrangements on the

electric side are not an end run around

clear federal jurisdiction and that the

Commission should withdraw its

assertion of jurisdiction over the retail

transmission component of unbundled

retail sales.

VT DPS contends that the

Commission’s rationale is flawed:

‘‘FERC’s analysis rests on the same very

shaky ground as its similar claim of

jurisdiction over buy-sell arrangements

by local gas distribution companies.’’

According to VT DPS, all retail

transactions are subject to state

jurisdiction and asks the Commission to

clarify that the Commission defines buysell as it did in the NOPR, but also

acknowledge that it has no jurisdiction

over such arrangements.

IN Com asserts that in the absence of

any record of abusive and undermining

actions by states under the guise of buysell arrangements, there is not even a

remedial justification to touch buy-sell

transactions. It contends that a

difference between the FPA and the

NGA warrants different treatment—the

FPA exempts from FERC jurisdiction

local distribution and transmission of

electric energy in intrastate commerce.

By redefining interstate transmission, IN

Com claims that the Commission

proposes to do away with the meaning

history has accorded to a variety of

transactions previously considered

wholly intrastate in nature. According

to IN Com, states should be allowed to

experiment with and allow different

forms of buy-sell transactions as part of

the evolving marketplace.

Commission Conclusion

Four parties (PA Com, IL Com, VT

DPS and IN Com) have raised concerns

regarding the Commission’s

determination that it has jurisdiction

over the interstate transmission

component of transactions in which an

end user arranges for the purchase of

generation from a third party. The

Commission reiterates that we will have

to address these situations on a case-bycase basis. We disagree with IL Com that

States have exclusive authority to

regulate the interstate transmission

component of buy-sell transactions.

Similarly, we deny the VT DPS request

that we acknowledge no jurisdiction

over such arrangements. The fact

remains that these arrangements could

be used by parties to obfuscate the true

transactions taking place and thereby

allow parties to circumvent Commission

regulation of transmission in interstate

commerce. We reserve our authorities to

ensure that public utilities and their
12372 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

468United Distribution Companies, 88 F.3d at

1154–57.

469See also AK Com (should not create a fictional

concept of delivery service—the legal reality is that,

under retail competition, state law will establish a

customer’s right to be served and a generation

owner’s right to produce power. AK Com asserts

that the state can then attach conditions to those

rights).

470MO/KS Coms at 1–13.

471See Colton and Connecticut Light and Power,

supra.

customers are not able to circumvent

non-discriminatory transmission in

interstate commerce. In response to VT

DPS’ contention that the Commission’s

analysis here rests on the same shaky

ground as its similar claim of

jurisdiction over buy-sell arrangements

by local gas distribution companies, we

note that the D.C. Circuit recently

affirmed the Commission’s assertion of

jurisdiction over buy/sell arrangements

under the Natural Gas Act.468

State Jurisdiction Over the Service of

Delivering Electric Energy to End Users

Rehearing Requests

IL Com states that it is far from clear

what FERC contemplates by the

‘‘service’’ of delivery of electric energy

by a delivering utility in the retail

wheeling transaction. It is equally

unclear to IL Com whether the ‘‘service’’

to which Order No. 888 refers is a

public utility activity over which state

regulators would have jurisdiction. IL

Com argues that it is the Illinois

legislature, not FERC, that determines

whether IL Com can regulate something

called ‘‘delivery service.’’ 469

MO/KS Coms ask the Commission to

clarify the meaning of the statement that

even when the test for local distribution

facilities identifies no local distribution

facilities, the Commission believes that

states have authority over the service of

delivering electric energy to end users.

According to MO/KS Coms:

The authority to shop at retail and to sell

at retail do not exist in the FPA. If the

Commission’s goal is to recognize the States’

authority to establish conditions on retail

competition, it need only acknowledge the

State jurisdiction to establish the opportunity

to shop and sell at retail. If this is what the

Commission is seeking to accomplish by its

discussion of ‘delivery service,’ then we

support the Commission.470

Coalition for Economic Competition

asserts that the Commission failed to

consider that the sale of electric energy

may take place outside of the state into

which the energy is transmitted, and

that the local regulatory commission

may have no jurisdiction over either the

sale or the transmission of the energy.

Commission Conclusion

Several parties ask us to clarify our

conclusion that even when the sevenfactor test for local distribution facilities

does not identify local distribution

facilities, we believe states have

authority over the ‘‘service’’ of

delivering electric energy to end users.

We clarify that states have the authority

to determine the retail marketing areas

of electric utilities within their

jurisdictions, and the end user services

that those utilities must provide, but we

did not in Order No. 888 intend to opine

on the extent of authority given by state

legislatures to their state commissions.

Rather, our statement regarding state

authority over the ‘‘service’’ of

delivering electric energy is intended to

recognize the historical and local nature

of delivering power to end users and the

states’ legitimate concerns and

responsibilities in regulating local

matters.

Deference to States

Rehearing Requests

Support Broader Deference

NARUC and IL Com argue that the

Commission should not simply defer to

state recommendations concerning the

application of the seven-factor test or

the recovery of stranded costs, but

should conclusively rely on the findings

by state commissions.

NY Com argues that the Commission

should not limit deference to instances

in which states order retail wheeling,

but should defer to all state commission

recommendations regarding the

definition of local distribution facilities.

FL Com asserts that the Rule fails to

say where deference will be given. It

argues that the Rule should state that

when a state commission has held a

proceeding on matters related to the

requirements of the Rule, the

Commission shall give deference to the

state commission decisions. Moreover,

it asserts that the Commission should

codify the deference standard: ‘‘When a

state commission has held a proceeding

on matters related to the requirements of

this rule, the Commission shall give

deference to the state commission

decisions.’’ (FL Com at 7–9).

The commitment to defer to a state

regulatory commission or agency, argues

NE Public Power District, should be

clarified with respect to utilities located

in Nebraska, which has no such

commission or agency. NE Public Power

District assumes that deference will be

accorded to decisions of NE Public

Power District’s Board of Directors; if

not, it asks the Commission to clarify.

PA Com asks the Commission to

clarify what a state regulatory agency

must demonstrate to secure deference

and to define the term ‘‘consult.’’ PA

Com states that, in discussing the seven

indicia, the Commission states that it

will ‘‘consider’’ jurisdictional

recommendations by states, which PA

Com asserts is much different from

deference. It also asserts that the

Commission must clarify what it will do

if a utility’s classifications and/or cost

allocations are not supported by state

regulatory authorities.

Oppose Deference to State Authorities

TANC argues that the Commission

erred in deferring to state regulatory

authorities in drawing jurisdictional

lines for local distribution facility

classifications and/or cost allocations.

According to TANC, the Commission

unlawfully and unnecessarily abdicated

its jurisdiction under the FPA (citing

New England Power Co. v. New

Hampshire, 455 U.S. 331, and

Nantahala Power and Light Co. v.

Thornburg, 476 U.S. 953). With respect

to ISOs, it asserts that the Commission

should not defer to state authority in

making determinations with respect to

classifications of facilities.

Commission Conclusion

In response to NARUC and IL Com’s

arguments that this Commission should

not simply defer to state commissions

regarding application of the seven-factor

test but instead should conclusively rely

on the findings of state commissions, we

believe this is inconsistent with the case

law which states that local distribution

it is a matter of fact for the Commission

to determine as an original matter.471

Additionally, we have an independent

obligation to ensure that we are

fulfilling our responsibilities under the

FPA to regulate facilities that are used

in interstate commerce. We cannot

delegate our jurisdiction. However, we

intend to provide broad deference to

states in determining what facilities are

Commission-jurisdictional transmission

facilities and what facilities are statejurisdictional local distribution

facilities, so long as our comparability

principles are not compromised and we

are able to fulfill our responsibilities

under the statute.

We reject FL Com’s suggestion that we

codify the deference standard. This is

neither necessary nor appropriate. In

response to NE Public Power District’s

request that we clarify to whom we

would give deference in Nebraska, we

clarify that because Nebraska does not

have an electric regulatory commission

or agency, there is no appropriate

regulatory entity to whom our deference

standard would apply; accordingly, we

will address the transmission/local
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12373

472Associated Gas Distributors v. FERC, 824 F.2d

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

(1988) (AGD).

473United Distribution Companies v. FERC, 88

F.3d 1105 (1996) (United Distribution Companies).

474Such access may be the open access required

under this Rule or case-by-case transmission access

ordered pursuant to FPA section 211.

475We note that the regulations implementing this

Rule use ‘‘wholesale stranded cost’’ and ‘‘retail

stranded cost’’ as shorthand terms to refer to the

different situations in which a utility may

experience stranded costs. However, as the

definitions of those terms make clear, it is not the

nature of the costs (wholesale vs. retail) that is

controlling for purposes of stranded cost recovery

under this Rule. Rather, the controlling factors are

the status of the customer (wholesale transmission

services customer vs. retail transmission services

customer) with whom the costs are associated, and

whether the transmission tariffs used by the

customer to escape its former power supplier (thus

causing the stranding of costs to occur) were

required by this Commission or by a state

commission. As a result, ‘‘retail stranded costs’’

refers to stranded costs associated with retail

wheeling customers.

distribution issue for Nebraska without

giving deference to any particular entity.

In response to PA Com’s request that we

clarify what we will do if a utility’s

classifications and/or cost allocation

proposals are not supported by state

regulatory authorities, we will make a

determination based on the factual

record before us in a particular case,

taking into account the views of the

state regulatory authority.

TANC has argued that we have

unlawfully abdicated our jurisdiction by

deferring to state recommendations.

TANC confuses delegation of

jurisdiction, which we cannot do, with

willingness to defer to states based on

their application of criteria that we have

provided. Even in the cases in which

the Commission defers to states’ views,

we will still independently evaluate all

material issues and proceed only where

substantial evidence supports the states’

views. The Commission clearly can

entertain requests for deference in these

circumstances.

J. Stranded Costs

As indicated in our prior discussion

in Section IV.A.5, there are two major

overlapping transition issues that arise

as a result of this rulemaking: stranded

cost recovery and how to deal with

contracts entered into under the prior

regulatory regime. We here address

stranded cost recovery and, as in the

prior discussion, we believe it is

important to explain the general context

in which our stranded cost

determinations have been made before

addressing the various rehearing

requests on this issue.

In Order No. 888, the Commission

removed the single largest barrier to the

development of competitive wholesale

power markets by requiring nondiscriminatory open access transmission

as a remedy for undue discrimination.

This action carries with it the regulatory

public interest responsibility to address

the difficult transition issues that arise

in moving from a monopoly, cost-based

electric utility industry to an industry

that is driven by competition among

wholesale power suppliers and

increasing reliance on market-based

generation rates. The most critical

transition issue that arises as a result of

the Commission’s actions in this

rulemaking is how to deal with the

uneconomic sunk costs that utilities

prudently incurred under an industry

regime that rested on a regulatory

framework and a set of expectations that

are being fundamentally altered.

The Commission determined in Order

No. 888 that it must address stranded

costs, and that it must do so at an early

stage—particularly in light of the

lessons learned from our experience

with similar issues in the natural gas

area. We noted that when we did a

similar restructuring in the gas industry,

the D.C. Circuit invalidated the

Commission’s efforts precisely because

the Commission had failed to deal with

the stranded cost problem in a

satisfactory manner.472 We explained

that, based on the lesson of AGD, the

Commission cannot change the rules of

the game without providing a

mechanism for recovery of the costs

caused by such regulatory-mandated

change.

Since the time Order No. 888 issued,

we have been provided with additional

guidance from the court in the natural

gas area, which has further helped to

inform our decisions here. In its

decision on review of Order No. 636,473

the D.C. Circuit upheld the

Commission’s decision to allow the

recovery of gas supply realignment

costs. In so doing, the court, while

questioning a specific feature of the

stranded cost recovery mechanism

employed in Order No. 636, has

nevertheless again reaffirmed the basic

principle that stranded cost recovery is

an appropriate component of a

regulatory policy aimed at

accomplishing a fair and reasonable

transition to competitive markets. The

question as to the Commission’s ability

to allow the recovery of stranded costs

has been laid to rest.

The task before the Commission in

this rulemaking is thus to determine

how best to meet its responsibility to

address the costs of the transition to a

competitive industry, particularly

insofar as those costs are stranded, or in

effect rendered unrecoverable, as a

result of the transmission access

required by us under the FPA.474 As the

rehearing arguments demonstrate, there

is no consensus on how the Commission

should address the stranded cost issue.

In fact, petitioners are at polar extremes

as to what the Commission should do

regarding stranded costs. Some argue

that the Commission has gone too far in

permitting utilities to seek recovery of

stranded costs, whether such costs are

associated with wholesale requirements

contracts, with retail-turned-wholesale

customers, or with retail customers that

obtain retail wheeling.475 Others argue

that the Commission has not gone far

enough and that it must broaden the

scope of stranded cost recovery

permitted under the Rule. Indeed, some

would have us be the guarantor for

recovery of all uneconomic costs that

might be stranded in the move to more

competitive markets, no matter how

tenuous the nexus to this Rule, and

irrespective of state-Federal

jurisdictional complexities. Some

support the Commission’s decision to

recover stranded costs directly from the

departing customers. Others would

prefer that the Commission require

utilities to absorb a portion of their

stranded costs or that the Commission

spread the burden of stranded costs

among all of the utility’s customers.

Some object that the Commission’s

approach to stranded costs in the

electric industry is different from that

adopted in the gas industry. Some

entities support the Commission’s

revenues lost approach for measuring a

departing customer’s stranded cost

obligation. Others propose different

methods for computing stranded costs.

Given the plethora of positions that

entities have raised both initially and on

rehearing concerning stranded costs, the

Commission has taken a careful,

measured approach with regard to

stranded cost recovery. The Commission

has balanced a number of important

interests in order to achieve what it

believes will be a fair and orderly

transition to competitive markets. These

interests include the financial stability

of the electric utility industry,

upholding the regulatory bargain under

which utilities made major capital

investments, and not shifting costs to

customers that had no responsibility for

causing those costs to be incurred. The

Commission also has adopted an

approach that, for purposes of stranded

cost recovery from wholesale

transmission customers, relies on the

nexus between stranded costs and the

use of transmission tariffs required by

this Commission and, for purposes of

stranded cost recovery from retail

customers, recognizes state commission
12374 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

476We reaffirm below our basic determinations,

but make certain clarifications on limited issues

and grant rehearing on the municipal annexation

issue.

477As we explain below, by ‘‘Commissionrequired transmission access’’ we mean the open

access transmission required under this Rule or

required pursuant to a section 211 order, as well as

transmission provided prior to Order No. 888 (and

not pursuant to a section 211 order) where such

transmission was provided on a case-by-case basis

to comply with the Commission’s comparability

requirement. See note 484 infra.

478We have made a minor revision to the

regulatory text, section 35.26(c)(2), to conform the

language of that section with sections 35.26(b) (1)

and (5). A conforming revision has been made to

section 35.26(d)(2)(i).

jurisdiction but fills potential regulatory

gaps that could arise in the transition to

new market structures.

The balancing of interests and

considerations described above is

reflected in the following central

components of the Rule’s stranded cost

provisions, which are reaffirmed

herein.476 First, the Commission has

determined that the most reasonable,

legally supportable approach is one that

permits utilities to seek recovery of

wholesale stranded costs under this

Rule (whether the stranded costs are

associated with a departing wholesale

requirements customer or with a retailturned-wholesale customer) only in

those cases in which there is a direct

nexus between the availability and use

of Commission-required transmission

access 477 and the stranding of costs. In

order for the utility to be eligible to seek

recovery of stranded costs from a

departing customer, the customer must

have obtained access to a new

generation supplier through the use of

the former supplying utility’s

Commission-required transmission tariff

(i.e., its open access tariff or a tariff

ordered pursuant to FPA section 211),

not through the use of another utility’s

transmission system.

Other cost recovery issues are more

appropriately addressed outside the

context of this Rule. For example, the

Rule is not intended to apply to costs

associated with the normal risks of

competition, such as self-generation,

cogeneration, or loss of load, that do not

arise from the new, accelerated

availability of Commission-required

transmission access. If a customer leaves

its utility supplier by exercising options

that could have been undertaken prior

to mandatory transmission under Order

No. 888 or the Energy Policy Act, or that

do not rely on access to the former

seller’s transmission, there is no direct

nexus to Commission-required

transmission access and thus no

opportunity for stranded cost recovery

under the Rule.

Second, the Commission has limited

the opportunity to seek stranded cost

recovery under the Rule primarily to

two discrete situations: (1) Costs

associated with customers under

wholesale requirements contracts

executed on or before July 11, 1994

(referred to in the Rule as ‘‘existing

wholesale requirements contracts’’) that

do not contain an exit fee or other

explicit stranded cost provision; and (2)

costs associated with retail-turnedwholesale customers. With regard to the

existing wholesale requirements

contracts, the Commission also has

made a finding that it is in the public

interest to permit amendments to add

stranded cost provisions to these

contracts, even if they contain MobileSierra clauses, if case-by-case

evidentiary burdens are met. We do not

interpret the Mobile-Sierra public

interest standard as practically

insurmountable in extraordinary

situations such as this one where

historic statutory and regulatory

changes have converged to

fundamentally change the obligations of

utilities and the markets in which they

and their customers will operate.

Third, Order No. 888 does not

guarantee that a utility will be allowed

to recover stranded costs. Rather, it

provides an opportunity for such

recovery. To be eligible to recover

stranded costs from a departing

customer in a particular case, the utility

must demonstrate that it incurred costs

to provide service to the customer based

on a reasonable expectation of

continuing service to that customer

beyond the contract term.478 In the case

of stranded costs associated with

wholesale requirements contracts

customers, if the contract contains a

notice of termination provision, that

provision is strong evidence that the

parties were aware that at some point in

the future the customer might seek to

find another supplier. Therefore, there

is a rebuttable presumption of no

reasonable expectation, and therefore no

opportunity for stranded cost recovery

unless the utility can overcome the

presumption.

The Commission has concluded that

direct assignment of stranded costs to

the departing customer (through either

an exit fee or a surcharge on

transmission) is the appropriate method

for recovery of stranded costs under the

Rule. In reaching this conclusion, the

Commission carefully weighed the

arguments supporting direct assignment

of stranded costs against those

supporting a more broad-based

approach, such as spreading stranded

costs to all transmission users of a

utility’s system, and also took into

account the fact that we applied a

different approach in the natural gas

area. The central considerations that

support a direct assignment approach in

the electric industry are that the

approach follows the traditional

regulatory concept of cost causation, it

avoids shifting costs to customers that

had no responsibility for causing them

to be incurred or for causing them to be

stranded, and it is still possible to apply

such an approach at this stage of the

industry’s evolution.

There is no question that, without the

stranded cost recovery mechanism,

some customers would be far more

likely to switch to lower-cost suppliers

and enjoy sooner the benefits of a

competitive power market. But, as

detailed in Order No. 888, such an

approach may result in higher costs for

other customers. We thus have had to

balance the potential for earlier benefits

for some customers against other public

interest considerations, most

particularly the need to provide a fair

mechanism by which utilities can

recover the costs of past investments

under traditional regulatory concepts of

prudently incurred costs and cost

causation. The result is not to deny

competitive advantages, but only to

delay their full realization for some

customers so that all customers

ultimately will benefit.

While Order No. 888’s cost causation

approach is different from the Order No.

636 cost spreading approach that was

affirmed in the United Distribution

Companies case, we believe it is the

preferable approach given the early

stage of the electric utility’s competitive

transition. We do not read the court’s

opinion as precluding the Commission

from adopting a direct assignment

approach in Order No. 888, particularly

where, as here, the Commission has

fully explained and justified the reasons

for following traditional cost causation

principles. In addition, although the

United Distribution Companies court

remanded for further consideration (in

light of Order No. 636’s cost spreading

approach) the decision not to require

any pipeline absorption of gas supply

realignment costs, the Commission has

fully explained how its decision in

Order No. 888 not to require any utility

absorption of stranded costs is

consistent with its decision to follow

traditional cost causation principles.

With respect to the fundamental

conclusion that utilities should be

permitted an opportunity to recover

their prudently incurred costs, Order

No. 888 is fully consistent with Order

No. 636. Although the Commission in

Order No. 888 chose a direct assignment

method (rather than the cost-spreading
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12375

479 In Order No. 888 and here, we sometimes use

the shorthand expression ‘‘retail-turned-wholesale’’

customer. By this we do not mean that a retail

customer who is an ultimate consumer ceases to be

an ultimate consumer, or that this customer begins

to purchase electric energy for resale. Rather, in a

‘‘retail-turned-wholesale customer’’ situation, such

as the creation of a municipal utility system, a

newly-created entity becomes a wholesale power

purchaser on behalf of retail customers who were

formerly bundled customers of the historical local

utility power supplier. The new municipal utility

is the conduit by which retail customers, if they

cannot obtain direct retail access, can reach power

suppliers other than their historical local utility

power supplier. Although the retail customers

remain bundled retail customers, in that they

become the bundled customers of the new entity,

we call this a ‘‘retail-turned-wholesale customer’’

situation because the new entity in effect ‘‘stands

in the shoes’’ of the retail customers for purposes

of obtaining wholesale transmission access and new

power supply.

480Exceptions would be self-generation or

construction by the new entity of its own

transmission line, in which case, as noted earlier,

the stranded cost provisions of Order No. 888

would not apply because such options have always

been available as alternatives to purchasing power

from the historical supplying utility and do not

involve the use of the utility’s transmission

facilities under an open access tariff. Thus the

departure of customers under these circumstances

cannot be linked to the open access requirements

of this Rule.

481As discussed in greater detail in Sections IV.J.6

and IV.J.12 below, we clarify that the opportunity

for recovery of stranded costs in a retail-turnedwholesale situation is limited to cases in which the

former bundled retail customer subsequently

becomes, either directly or through another

wholesale transmission purchaser, an unbundled

wholesale transmission services customer of its

former supplier. We have revised section

35.26(b)(1)(i) of the Commission’s regulations

accordingly.

482Unbundled retail transmission services

required by a state commission could be taken

under the same pro forma open access tariff used

by wholesale customers or, if determined

appropriate by the Commission, under a separate

retail tariff filed at the Commission. The critical

point, however, is that in either case, the

unbundled services are required by the state and

not by this Commission.

483FERC Stats. & Regs. at 31,788–91; mimeo at

451–58.

approach in Order No. 636) for purposes

of allocating stranded cost responsibility

among customers, the approach used by

the Commission in Order No. 888 is not

governed by decisions in Order No. 636,

but in either event the Commission

must demonstrate that its choice of

methods is based on reasoned decisionmaking.

In considering the stranded cost

issues that may arise in the transition to

competitive markets, the Commission

also has taken cognizance of significant

changes involving retail customers and

the stranded cost issues that arise as

retail customers convert to wholesale

customer status (e.g., through

municipalizations) in order to obtain the

open access afforded by Order No. 888,

or as they obtain retail wheeling

required by state commissions. These

situations involve new and complex

jurisdictional issues and represent the

bulk of potential stranded costs facing

the industry. We believe it is important

to clarify the Commission’s decisions as

to when it will entertain requests for

stranded cost recovery in these

situations, and our reasons for doing so.

The Commission’s determination that

it, rather than the states, should be the

primary forum for addressing stranded

costs associated with a retail-turnedwholesale customer 479 is limited to

those cases in which there is a direct

nexus between the availability and use

of Commission-required transmission

access and the stranding of costs. We

believe we have both the authority and

the obligation to provide an opportunity

for stranded cost recovery in these

situations because the bundled retail

customer would not be able to obtain

access to the new supplier but for the

Commission’s order requiring

transmission. The creation of a new

wholesale entity to purchase power on

behalf of retail customers would not, by

itself, trigger stranded costs. In the

absence of transmission access from the

historical supplier of the retail

customers, the new entity would have to

remain on the historical supplier’s

generation system because it would

have no way to reach other power

suppliers, and stranded costs would not

occur.480 Therefore, there is a causal

nexus between the stranded costs and

the availability and use of the tariff

services required by the Commission.481

Moreover, because of this causal nexus

between the use of a jurisdictional

utility’s Commission-required

transmission tariff and the potential for

foregone revenues by that jurisdictional

utility as a result of the Commissionrequired access, the stranded costs

associated with a retail-turnedwholesale customer are properly viewed

as economic costs that are jurisdictional

to this Commission.

In contrast, in the situation in which

a bundled retail customer obtains retail

wheeling, stranded costs are directly

caused by the availability and use of

unbundled retail services required by

the state commission, not this

Commission. 482 Thus, the Commission

believes that states, not the Commission,

should be the primary forum for costs

associated with a bundled retail

customer that obtains retail wheeling.

The Commission’s decision to entertain

requests to recover stranded costs

caused by retail wheeling in only a

limited circumstance (where the state

regulatory authority does not have

authority under state law to address

stranded costs when the retail wheeling

is required) is based on a policy

decision by this Commission that it will

step in to fill a regulatory ‘‘gap’’ that

could result in no effective forum in

which utilities would have an

opportunity to seek recovery of

prudently incurred costs.

Finally, after considering various

proposals regarding how stranded costs

should be calculated, and reviewing the

arguments of petitioners on rehearing,

the Commission continues to believe

that the revenues lost approach is the

fairest and most efficient way to

determine the amount of stranded cost

assigned to a departing customer during

the transition to a competitive

wholesale bulk power market. The

Commission has rejected an asset-byasset approach as overly complicated

and costly.

We respond below to the specific

arguments raised on rehearing and

elaborate on the above determinations.

1. Justification for Allowing Recovery of

Stranded Costs

In Order No. 888, the Commission

concluded that utilities should be given

the opportunity to seek recovery of

legitimate, prudent and verifiable

stranded costs associated with a limited

set of wholesale requirements contracts

executed on or before July 11, 1994. 483

We stated that utilities that entered into

contracts to make wholesale

requirements sales under an entirely

different regulatory regime should have

an opportunity to recover stranded costs

that occur as a result of customers

leaving the utilities’ generation systems

through Commission-jurisdictional open

access tariffs or FPA section 211 orders

to reach other power suppliers. We

explained that utilities that made large

capital expenditures or long-term

contractual commitments to buy power

years ago to supply their customers

should not now be held responsible for

failing to foresee the actions this

Commission would take to alter the use

of their transmission systems in

response to the fundamental changes

that are taking place in the industry. We

found that recent significant statutory

and regulatory changes are central to the

circumstances that now place at risk the

recovery of past investment decisions of

utilities. We indicated that we will not

ignore the effects of these changes as we

fashion policies that will govern

possible recovery of these costs in the

transition to an open access regulatory

regime.

We stated that while there has always

been some risk that a utility would lose

a particular customer, in the past that

risk was smaller. It was not
12376 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

484 In Order No. 888, we explained that by ‘‘new

open access’’ or ‘‘open access transmission’’ we

were referring to Commission-jurisdictional open

access tariffs or to a tariff ordered pursuant to FPA

section 211. Although we generally refer in the text

of Order No. 888 and the text of this order to the

open access tariffs required under this Rule and to

tariffs required pursuant to a section 211 order, we

clarify that the ‘‘new open access’’ or ‘‘open access

transmission’’ described in this Rule also includes

transmission provided prior to Order No. 888 (and

not pursuant to a section 211 order) where such

tariff filings were made on a case-by-case basis to

comply with the Commission’s comparability

requirement. To avoid any confusion on this point,

we refer in this order to all such open access

transmission as ‘‘Commission-mandated

transmission access’’ or ‘‘Commission-required

transmission access.’’

485E.g., American Forest & Paper, Blue Ridge,

TDU Systems, IN Consumer Counselor, IN

Consumers, IL Com.

486 IN Consumer Counselor at 9 (citing Order No.

888, mimeo at 452–53); IN Consumers at 10 (same).

487E.g., APPA, IN Consumer Counselor, IN

Consumers, Suffolk County, TDU Systems,

Specialty Steel, Occidental Chemical, Central

Illinois Light, American Forest & Paper, Nucor, Blue

Ridge.

488E.g., APPA, IN Consumer Counselor, IN

Consumers, Suffolk County, TDU Systems,

Specialty Steel.

489E.g., American Forest & Paper, Nucor, Blue

Ridge.

490E.g., ELCON, TDU Systems, Central Illinois

Light, American Forest & Paper.

491See also American Forest & Paper (unless a

utility agrees not to seek stranded costs under the

Rule, the utility should not be found to have

mitigated its transmission market power for

purposes of charging market-based rates, merging

with other utilities or otherwise, simply by filing an

open access tariff).

unreasonable for the utility to plan to

continue serving the needs of its

wholesale requirements customers and

retail customers, and for those

customers to expect the utility to plan

to meet their future needs. We

concluded that with the new open

access transmission, 484 the risk of

losing a customer is radically increased.

If a former wholesale requirements

customer or a former retail customer

uses the new open access to reach a new

supplier, the utility is entitled to seek

recovery of legitimate, prudent and

verifiable costs that it incurred under

the prior regulatory regime to serve that

customer. The utility, however, would

have the burden of demonstrating that it

had a reasonable expectation of

continuing to serve the departing

customer.

Rehearing Requests Opposing, or

Seeking Limitations on, Stranded Cost

Recovery

Several entities challenge the

Commission’s decision to give utilities

an opportunity to recover legitimate,

prudent and verifiable stranded costs.

NASUCA argues that the transition to

wholesale competition was underway

before and apart from the NOPR. It

asserts that the drivers of the developing

competition include voluntary open

access filings by utilities seeking

mergers or market-based rate authority

and section 211 of the FPA, as amended

by the Energy Policy Act of 1992

(Energy Policy Act). According to

NASUCA, stranded investment results

from legislative, not regulatory action,

and the stranded cost issue does, and

would, exist without the Open Access

Rule. It contends that an acceleration of

the competitive wholesale

transformation does not change its

nature or origins. NASUCA also

contends that the issuance of the Open

Access Rule does not justify stranded

cost recovery on ‘‘regulatory compact’’

grounds because it is not a fundamental

change.

Other entities object that there is no

basis for the Commission to impute an

extra-contractual obligation to serve

wholesale requirements customers.485

These entities argue, for example, that

utilities could and should have

protected themselves from any potential

stranded costs through individual

customer contracts.

IN Consumer Counselor and IN

Consumers object that Order No. 888

attempts to transform the obligation to

provide a utility with an ‘‘opportunity’’

for a fair return when prices are

regulated into an ‘‘entitlement’’ to

‘‘recover legitimate, prudent and

verifiable costs that it incurred under

the prior regulatory regime.’’ 486

Several entities submit that the

Commission has not adequately

addressed the potential anticompetitive

impact of stranded cost recovery.487

Some argue that giving utilities the

opportunity to recover wholesale

stranded costs will delay the

opportunity for historically captive

customers to benefit from competitive

alternatives.488 Central Illinois Light

contends that the Rule is arbitrary and

capricious because it will have different

impacts on different customers, which

Central Illinois Light asserts will be due

to accidents of circumstance rather than

the conscious application of rational

policy choices. IN Consumers objects

that two similarly-situated customers of

the utility for identical transmission

services will be required to pay

substantially different rates for the same

service (where one previously

purchased its power requirements from

the utility, while the other used an

alternate source of supply).

Central Illinois Light also objects that

even a partial allowance of stranded

costs will likely encourage predatory

pricing. It says that the Commission has

failed to adequately address the harm

that stranded cost ‘‘subsidies’’ pose to

low-cost utilities with little or no

stranded costs. Others contend that the

Rule would subvert economic efficiency

by unjustly enriching utilities that have

not attempted to meet the new market

demands, to the detriment of those

utilities that have.489 According to

Occidental Chemical, the Commission

has made no finding that the procompetitive goals of Order No. 888 can

be accomplished in light of the costs

and uncertainties presented by stranded

cost recovery.

Several entities also challenge the

adequacy of the factual record for

allowing wholesale stranded cost

recovery and argue that utilities have

not provided the hard data on wholesale

stranded costs that the Commission

needs to justify Order No. 888.490

Central Illinois Light objects that the

Commission failed to note or to discuss

data presented by commenters showing

that only a small group of high-cost

utilities need some stranded cost

protection. American Forest & Paper

argues that the Commission has failed to

demonstrate on the record the existence

of any stranded wholesale investment

that was or could be caused by the

transition to open access transmission.

SC Public Service Authority repeats

its earlier request that the Commission

deny market-based rate authority to any

utility that elects to recover stranded

costs from departing customers.491 It

objects that the Commission failed to

specifically respond to its previous

comments on this issue.

American Forest & Paper objects that

utilities that voluntarily filed open

access tariffs cannot use the stranded

cost rule because their loss of customers

cannot be said to have occurred only

because of the Rule. It submits that only

those utilities who had to be forced to

offer open access transmission are being

rewarded.

San Francisco asks that the

Commission include ‘‘exercise of preexisting contract rights for transmission

and designation of wholesale loads’’ or

similar language as one of the examples

(listed in footnote 718) of situations for

which stranded costs may not be sought.

San Francisco explains that it wants to

ensure that PG&E would not have any

basis to argue that any load loss PG&E

suffers as a result of San Francisco’s

designation of municipal loads would

be eligible for stranded cost recovery.

Commission Conclusion

We will deny the requests for

rehearing of our decision to allow
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12377

492AGD, 824 F.2d at 1021.

493United Distribution Companies, 88 F.3d 1105

(1996). Although the court remanded that aspect of

Order No. 636 that allows pipelines to recover 100

percent of their gas supply realignment costs

without requiring any pipeline absorption, we

explain in Section IV.J.3 below how Order No. 888

is fully consistent with that remand.

494See FERC Stats. & Regs. at 31,789; mimeo at

453–54.

495As we explain above, Commission-mandated

transmission tariffs is meant to include all open

access tariffs filed pursuant to Commission order,

including tariffs filed under this Rule, tariffs

ordered pursuant to FPA section 211, and tariffs

that were filed on a case-by-case basis to comply

with the Commission’s comparability requirement.

496As a result of the Open Access Rule, 47 Group

2 public utilities, which had no open access

transmission tariff available prior to Order No. 888,

submitted and had available on July 9, 1996 nondiscriminatory open access transmission tariffs. In

addition, 101 Group 1 public utilities, which had

some version of open access available prior to Order

No. 888, filed new open access tariffs effective July

9, 1996 in order to conform to the terms and

conditions of non-discriminatory open access

service specified in the pro forma tariff. Thus, as of

July 9, 1996, 148 of the 166 public utilities had filed

Order No. 888 open access tariffs. At least ten

others filed open access tariffs after July 9, 1996

(e.g., after the Commission dealt with their waiver

requests). This, in the Commission’s view,

represents an unprecedented acceleration of the

transition to competitive bulk power markets. From

the issuance of the Open Access NOPR in March

1995 until the effective date of Order No. 888 on

July 9, 1996 is only a little more than one year.

497NASUCA and other petitioners offer no

persuasive evidence that meaningful competition

took root prior to the availability of the new

transmission access requirements. The few utilities

that did provide transmission service under open

access tariffs prior to the announcement of the

Commission’s comparability requirement did not

offer third parties comparable service. To the

contrary, such tariffs contained numerous

disparities in the transmission service that the

utilities provided to third parties in comparison to

their own uses of the transmission system. See, e.g.,

Entergy Services, Inc., 58 FERC ¶ 61,234, order on

reh’g, 60 FERC ¶ 61,168 (1992), remanded, sub

nom., Cajun Electric Power Cooperative, Inc. v.

FERC, 28 F.3d 173, 179–80 (D.C. Cir. 1994) (tariff

contained limitations on point-to-point service and

did not provide network service; tariff reserved

transmission provider’s right to cancel service in

certain instances, even where a customer had paid

for transmission system modifications). While the

desire of customers for competitive power markets

may have preceded Commission-mandated open

access, customers had no assurance they could

reach alternative suppliers until the Commission

required utilities to provide transmission service on

a comparable basis.

utilities an opportunity to seek recovery

of legitimate, prudent, and verifiable

stranded costs. As we indicated in

Order No. 888, we learned from our

experience with natural gas that, as both

a legal and a policy matter, we cannot

ignore these costs. The U.S. Court of

Appeals for the District of Columbia

Circuit invalidated the Commission’s

first open access rule for gas pipelines

because the Commission failed to deal

with the uneconomic take-or-pay

situation that many pipelines faced as a

result of regulatory changes beyond

their control.492 That same court has

subsequently affirmed the Commission’s

decision to allow the recovery of costs

that are stranded in the transition to a

competitive natural gas industry, most

recently by upholding the Commission’s

decision in Order No. 636 to allow the

recovery of gas supply realignment

costs.493

Here we are faced, once again, with an

industry transition in which there is the

possibility that, as a result of statutory

and regulatory changes beyond their

control, certain utilities may be left with

large unrecoverable, legitimate and

prudent costs or that those costs will be

unfairly shifted to other (remaining)

customers. Thus, in order to satisfy our

regulatory responsibilities, we must

directly and timely address the costs of

the transition by allowing utilities to

seek recovery of legitimate, prudent and

verifiable stranded costs.494 While the

transition to wholesale competition may

have begun before the NOPR, we

strongly disagree with NASUCA’s claim

that the Open Access Rule does not

justify stranded cost recovery because

an acceleration of the transition does

not change its nature or origins. The

driving force behind the development of

wholesale competitive markets is the

widespread transmission access made

available through Commissionmandated transmission tariffs,495

including transmission tariffs ordered

pursuant to FPA section 211 and the

transmission tariffs required by the

Commission’s Open Access Rule.496

Furthermore, as explained in the Rule

and as further discussed below, it is the

ability of customers to obtain readily

available Commission-mandated

transmission access that significantly

increases the potential for wholesale

stranded costs.

Order No. 888 requires the functional

unbundling of a public utility’s

wholesale services. Under the Rule, all

public utilities that own, control or

operate facilities used for transmitting

electric energy in interstate commerce

were required by July 9, 1996 to file

open access transmission tariffs that

contain minimum terms and conditions

of non-discriminatory service (or to seek

waiver), and to take transmission

service (including ancillary services) for

their own new wholesale sales and

purchases of electric energy under the

open access tariffs. As a result of Order

No. 888, wholesale requirements

customers that previously were captive

customers of their public utility

suppliers (i.e., they had no choice but to

take bundled sales and transmission

services from their suppliers) will be

able at the expiration of their contracts

to take unbundled transmission service

(i.e., transmission-only service) from

their former suppliers in order to reach

new suppliers. While in the past there

has been some risk of stranded costs due

to customers ‘‘leaving’’ a supplier’s

system through self-generation or

perhaps municipalization, there was

little or no ability to shop for alternative

power such as that which will occur as

a result of readily available

Commission-mandated transmission

access. Contrary to NASUCA’s claims,

Order No. 888, coupled with section 211

of the FPA, creates the opportunity, as

a matter of law, for an existing

wholesale requirements customer to use

the transmission owner’s facilities to

reach a new supplier.497 This leaves the

former supplying utility with significant

risk that it will be unable to recover

costs that the utility incurred based on

a reasonable expectation that it would

continue to serve the departing

customer.

Thus, the regulatory and statutory

changes contained in Order No. 888 and

in amended section 211, which will act

in tandem to provide the transmission

access necessary to develop the

competitive wholesale markets

envisioned by Congress in the Energy

Policy Act, have a direct nexus to the

potential for wholesale stranded costs.

This nexus makes it critical that the

Commission address this transition

issue responsibly and equitably. Having

balanced the goals of competition, the

nexus between potential stranded costs

and transmission access, and the

regulatory bargain under which utilities

invested billions of dollars in reliance

on the prior regulatory regime, we

believe that utilities are entitled to an

opportunity to seek recovery of stranded

costs and that our actions in Order No.

888 are not only legally supportable, but

also represent sound public policy.

In response to those entities who

argue that there is no basis for imputing

an extra-contractual obligation to serve

wholesale requirements customers, as

we explained in Order No. 888, we

believe there previously has been an

implicit obligation to serve at wholesale

in many cases. Such obligation is based,

in large part, on the recognition that

historically most wholesale

requirements customers were captive

and had no means of reaching

alternative suppliers. The local utility

supplied bundled generation and

transmission services to these customers

on the assumption that they would

remain as customers. Accordingly, the

utility had a concomitant obligation to

plan to supply these customers’
12378 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

498The Rule requires that the utility notify the

Commission of the date of termination for this class

of contracts within 30 days after the termination

takes place. The Rule retains the prior notice of

cancellation or termination requirement for power

sales contracts executed on or after July 9, 1996 if

termination is on grounds other than expiration of

the contract by its terms at the end of the contract.

See Portland General Electric Company, 75 FERC ¶

61,310, reh’g denied 77 FERC ¶ 61,171 (1996)

(Commission authorization required for termination

of power sales contract in the event of the

commencement of a bankruptcy proceeding, failure

to perform any obligation under the contract, or

failure to provide adequate assurance of the ability

to perform).

499To the extent there is any misunderstanding,

we clarify that the intent of the Rule to permit the

‘‘opportunity’’ to recover stranded costs is not an

‘‘entitlement’’ to recover such costs. As a result, the

passage in Order No. 888 to which IN Consumer

Counselor and IN Consumers object (FERC Stats. &

Regs. at 31,789, mimeo at 452–53) should read ‘‘we

believe that the utility is entitled to an opportunity

to recover legitimate, prudent and verifiable costs

that it incurred under the prior regulatory regime

to serve that customer’’ (emphasis to show added

language).

500FERC Stats. & Regs. at 31,794; mimeo at 468–

69.

501As we indicate in Section IV.J.9 below, we

disagree that the Rule’s definition of stranded costs

artificially and unjustifiably improves the

competitive position of an inefficient utility.

continuing needs, and planned its

system taking account of the wholesale

load. In many cases the wholesale

customers participated by supplying

load forecasts. Consistent with this

practical obligation to serve, the

Commission viewed the supplying

utility as the supplier of first resort, and

did not allow a utility to terminate

service without prior Commission

approval. Before Order No. 888, the

Commission’s regulations required prior

notification and approval of the

proposed cancellation or termination of

a wholesale requirements contract. We

note that although Order No. 888

eliminates the prior notice of

cancellation or termination requirement

for power sales contracts executed on or

after July 9, 1996 (the effective date of

the Open Access Rule) that are to

terminate by their own terms,498 it

expressly retains the prior notice of

cancellation or termination requirement

for any power sales contract executed

before that date.

It is important to note, however, that

while the stranded cost recovery

provisions of the Rule are based on the

implicit obligation to serve, the Rule

does not guarantee any extracontractual wholesale stranded cost

recovery, much less across-the-board

recovery of such costs by all public

utilities. To the contrary, it provides an

opportunity for such recovery only for a

discrete set of requirements contracts

(those executed on or before July 11,

1994 that do not contain an exit fee or

other explicit stranded cost provision),

and the Rule requires that a utility must

meet a heavy burden of proving

eligibility to recover costs in a particular

case: before a departing customer is

required to pay a stranded cost exit fee

or transmission surcharge, the utility

must demonstrate that it incurred costs

to provide service to a customer based

on a reasonable expectation of

continuing service to that customer

beyond the end of the contract.499

We believe that we adequately

address in both Order No. 888 and in

Section IV.J.2 below the concerns

various entities have expressed as to the

potential anticompetitive impact of

stranded cost recovery. Although we

recognize that stranded cost recovery

may delay some of the benefits of

competitive bulk power markets for

some customers, we believe that

customers as a whole will benefit from

a fair and orderly transition. Indeed, we

are particularly concerned that the

failure to assign stranded cost

responsibilities to customers that have

access to alternative suppliers will leave

captive customers exposed to the risk of

greater cost burdens, thereby shifting to

captive customers the costs that were

originally incurred for the benefit of the

(typically larger) customers who have

the flexibility to take early advantage of

competing power suppliers. Avoiding

this potential cost shifting problem is an

important goal of our decision to

address the stranded cost problem as

part and parcel of the decision to

mandate open access. As we said in

Order No. 888:

such transition costs must nevertheless be

addressed at an early stage if we are to fulfill

our regulatory responsibilities in moving to

competitive markets. The stranded cost

recovery mechanism that we direct here is a

necessary step to achieve pro-competitive

results. In the long term, the Commission’s

Rule will result in more competitive prices

and lower rates for consumers.[500]

We do not believe that allowing

utilities an opportunity to seek stranded

cost recovery will prevent us from

achieving the pro-competitive goals of

Order No. 888. To the contrary, as

discussed below in Section IV.J.3, we

think that it is necessary to provide

utilities the opportunity to seek to

recover stranded costs if we are to have

a fair and orderly transition to more

competitive bulk power markets. The

opponents of Order No. 888’s stranded

cost approach argue that the transition

to fully competitive bulk power markets

will be slower if we allow utilities an

opportunity to seek to recover stranded

costs from departing customers, and

with respect to some customers that

may well be true. As noted earlier, some

customers because of their size and

limited contractual obligations with

their current utility suppliers have the

ability immediately to leave the system.

If they are allowed to do so without

paying the costs incurred to provide

them expected future service, the

economic attractiveness of departing the

system is obviously enhanced and the

benefits of competition, for these

customers, obviously come sooner

rather than later. However, the pace at

which fully competitive markets are

achieved, while important, is not the

only consideration. It is the

Commission’s responsibility to ensure

that the costs of open access are fairly

assigned and that the benefits of Order

No. 888’s open access requirements will

be fairly available to all customers.

These dual goals compel us toward a

balanced approach that, although

perhaps delaying somewhat the benefits

of competition, nevertheless ensures

that all customers will share in those

benefits without undermining historic

principles of cost recovery upon which

utilities were entitled to rely in

planning their systems.

Moreover, as we explain in Section

IV.J.3 below, we have carefully

examined different methods of

allocating stranded costs that are found

to be properly recoverable, including

assigning the costs directly to the

departing customer or spreading the

costs to all transmission users of a

utility’s system. We recognize that the

direct assignment approach to stranded

cost recovery delays competition for

some customers because it attaches a

price tag for customers who have the

immediate ability to leave the system.

However, we have identified the

advantages and disadvantages of each

approach and have concluded, on

balance, that direct assignment is the

preferable approach for both legal and

policy reasons.

In response to the concerns of some

entities that stranded cost ‘‘subsidies’’

may harm low-cost utilities with little or

no stranded costs, or otherwise may

unjustly enrich utilities that have not

attempted to meet the new market

demands to the detriment of those that

have, we again emphasize the limited

and transitional nature of the stranded

cost recovery opportunity allowed

under Order No. 888.501 It is clearly not

the Commission’s intent that utilities

with little or no stranded cost exposure

be competitively disadvantaged by the

Open Access Rule. Those utilities with

little or no stranded costs will be

similarly situated with other new

suppliers in the sense that they will all
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12379

502As the AGD court noted: ‘‘Agencies do not

need to conduct experiments in order to rely on the

prediction that an unsupported stone will fall.’’ 824

F.2d at 1008.

503As we noted in Order No. 888, there is no

question that it is within the Commission’s

discretion to decide whether to act through rule or

through case-by-case adjudication. FERC Stats. &

Regs. at 31,679; mimeo at 127–28.

504See AGD, 824 F.2d at 1008.

505 Indeed, we are somewhat puzzled by the

argument that we may not act in the absence of

‘‘hard data’’ that the potential stranded cost

problem is widespread and huge. Here we provide

only the opportunity to seek stranded cost recovery

for a concededly narrow subset of cases that we

believe may give rise to a valid claim for

extracontractual recovery. If as petitioners suggest

the problem is modest and confined to a small

number of utilities, the evidentiary process will sort

that out, and the potential effect on departing

customers and on the pace of competition will be

similarly modest.

face the potential of not being able to

compete immediately for certain

wholesale customers who are

determined to have an obligation to pay

stranded costs. These customers may

find it to be uneconomic to shop from

new power suppliers because they may

have to pay costs they caused to be

incurred under the prior industry

regime before they are able to switch

suppliers. However, this will be during

a transition period only, and only with

respect to a discrete set of contracts and

only where the utility meets its burden

of proof with respect to a particular

departing customer.

We reject as misplaced IN Consumers’

argument that the Open Access Rule is

discriminatory because two ‘‘similarlysituated’’ customers for ‘‘identical’’

transmission services (one who

previously purchased transmission

bundled with its power requirements

from the utility and now seeks to

purchase only unbundled transmission,

and the other who previously used an

alternative source of supply and seeks to

purchase unbundled transmission from

the utility) will pay substantially

different rates for the same service. The

error in this argument is that the two

customers in the example are not

‘‘similarly-situated’’ precisely because

one of them was a former bundled

wholesale requirements customer of the

utility for whom the utility may have

incurred costs to meet reasonably

expected customer demand, whereas the

other was never a generation customer

of the utility and thus appropriately

bears no cost responsibility for stranded

generation costs incurred by that utility.

Indeed, this example illustrates

precisely the reason underlying the

Commission’s stranded cost mechanism.

If a utility had previously served a

customer as a seller of generation as

well as a transmitter, it is allowed an

opportunity to show that it incurred

costs based on a reasonable expectation

of continuing to serve the power needs

of that customer beyond the contract

term. Similarly, contrary to Central

Illinois Light’s claim, if different

treatment of different customers were to

occur, it would not be due to ‘‘accidents

of circumstance’’—it would be the result

of the conscious application by the

Commission of its decision to give a

utility the opportunity to recover

stranded costs from a wholesale

requirements customer if the utility can

demonstrate that it incurred costs to

provide service to the customer based

on a reasonable expectation that it

would continue to serve the customer

after the contract term.

In response to the claims of those

entities that challenge the factual record

for allowing wholesale stranded cost

recovery, we believe that the record in

this proceeding clearly demonstrates the

need to give utilities the opportunity to

recover wholesale stranded costs. We

have shown that the Rule’s open access

requirement will significantly alter

historical relationships among

traditional utilities and their customers.

Indeed, that is one of its objectives. In

the longer term, we seek to have all

power supply arrangements priced by

the competitive marketplace. However,

utilities prudently incurred costs under

a prior regulatory regime that created an

expectation of an opportunity for

recovery of those costs. Common sense

indicates that a utility that historically

supplied bundled generation and

transmission services to a wholesale

requirements customer and that

reasonably expected to continue to serve

the customer may have incurred costs to

provide service to that customer that

could be stranded if the customer uses

open access transmission to reach a new

generation supplier.502 As we learned

from our experience in restructuring of

the natural gas industry, open access

and unbundling did in fact exacerbate

the take-or-pay problems in the gas

industry because it gave customers more

options. That is what we are doing in

the electric industry as well. As a result,

we have concluded that utilities should

be permitted to seek recovery of

stranded costs in certain limited and

defined circumstances.

We disagree with those entities that

argue that utilities have not provided

sufficient data on the existence of

wholesale stranded costs to justify the

approach adopted by the Commission in

Order No. 888. Presumably these

entities would require us to calculate

specific stranded cost estimates for

every public utility before we could act

to address this critical issue. However,

where the Commission decides to act by

means of a generic rule,503 the

Commission is not required to make

individual findings on a utility-byutility basis.504 Moreover, the Rule does

not say that all utilities with wholesale

contract customers will be allowed to

recover stranded costs, only that those

utilities that have requirements

contracts that were executed on or

before July 11, 1994 that do not contain

an exit fee or explicit stranded cost

provision and that can meet the

required evidentiary showing would be

allowed such recovery. On this basis,

our decision to give utilities the

opportunity to seek stranded cost

recovery for certain wholesale

requirements contracts is not dependent

on a showing that any particular utility

will actually be eligible to recover

stranded costs as a result of the open

access requirement.505

We also will reject SC Public Service

Authority’s request that the Commission

deny market-based rate authority for all

utilities seeking stranded cost recovery.

SC Public Service Authority has failed

to demonstrate that the ability to seek

stranded cost recovery would, by

definition, eliminate the potential for

mitigation of any generation or

transmission market power. If an entity

believes that a utility seeking marketbased rate authority does not satisfy the

Commission’s criteria for the grant of

market-rate authority (e.g., because the

utility has, or has failed to mitigate,

market power in generation or

transmission), that entity will have

ample opportunity to present its case in

the market-based rate proceeding.

American Forest & Paper’s objection

that utilities that voluntarily filed open

access tariffs cannot utilize the stranded

cost provisions and therefore that only

utilities who were forced to offer open

access transmission are being rewarded

is misplaced. First, there is nothing in

Order No. 888 that prohibits a utility

that voluntarily filed an open access

transmission tariff from seeking

recovery of stranded costs if it can

demonstrate a reasonable expectation of

continuing to serve a particular

wholesale customer beyond the term of

its existing contract. Second, many of

the ‘‘open access’’ tariffs accepted prior

to Order No. 888, while an improvement

upon the status quo of no access, did

not contain the minimum terms and

conditions of non-discriminatory

service, including functional

unbundling. Order No. 888 required

utilities that tendered for filing open

access tariffs prior to the issuance of the

Rule (Group 1 public utilities) to make

section 206 compliance filings that
12380 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

506 In making this determination we do not decide

whether such situations demonstrate the presence

or lack of a reasonable expectation of continuing to

serve a customer after the expiration of an existing

wholesale requirements contract (i.e., one that was

executed on or before July 11, 1994).

507San Francisco will have sufficient opportunity

to raise the argument in any PG&E stranded cost

recovery case.

508E.g., EEI, Coalition for Economic Competition,

Puget, Centerior, Southern. The issue of expanding

the rule to encompass municipal annexations and

expansions is discussed in greater detail in section

IV.J.6 below.

509Puget submits that the potential for customers

not taking unbundled transmission services from

their former suppliers is particularly acute in the

Pacific Northwest due to BPA’s ownership of much

of the region’s transmission facilities.

510NIMO contends that the Commission erred by

failing to address the extent to which Order No.

888’s exceptions to the general policy of full

stranded cost recovery (e.g., no recovery for

customer use of new transmission provider or

municipal annexations) create an opportunity for

customers to avoid payment of part or all of their

share of utility stranded costs, will enable

customers to take advantage of such opportunities

in ways that will reduce rather than enhance overall

economic efficiency, and will deprive utilities of a

reasonable opportunity to recover their prudently

incurred costs or will shift costs unfairly among

customers. See also Puget.

511E.g., Puget, Coalition for Economic

Competition, NIMO. These parties make a similar

argument in the case of stranded costs that result

from retail wheeling. See section IV.J.7 below.

512Puget cites in support Stone v. Farmers’ Loan

& Trust Company, 116 U.S. 307, 331 (1886); Federal

Power Commission v. Hope Natural Gas Company,

320 U.S. 591, 602 (1944); and Duquesne Light

Company v. Barasch, 488 U.S 299, 307–08 (1989).

Puget objects that the stranded cost recovery

mechanism in Order No. 888 is too narrow and too

easy to circumvent; it can be denied for failure to

satisfy the reasonable expectation test or based on

a finding that costs are not legitimate and verifiable.

Puget argues that stranded cost recovery is

constitutionally required and that the recovery

mechanism must be amended to ensure full

recovery of prudently incurred stranded costs,

including PURPA contract costs.

contain the non-rate terms and

conditions set forth in the Open Access

Rule pro forma tariff. That tariff

expressly includes provisions allowing

a transmission provider to seek to

recover stranded costs in accordance

with the terms, conditions and

procedures set forth in Order No. 888.

Of the 101 public utilities that had some

version of open access available prior to

Order No. 888, all now have open access

tariffs on file that contain provisions

that expressly allow the transmission

provider to seek to recover stranded

costs as provided in Order No. 888.

We also will decline San Francisco’s

request that the Commission include

‘‘exercise of pre-existing contract rights

for transmission and designation of

wholesale loads’’ or similar language as

an example of a situation for which

stranded costs may not be sought.506 We

are not prepared to make individual

factual determinations in the context of

this Rule.507 As specific requests for

stranded cost recovery are presented to

the Commission, they will be addressed

based on the facts presented and the

merits of the particular request.

Rehearing Requests Seeking Broader

Stranded Cost Recovery

In sharp contrast to the entities

seeking rehearing of the Commission’s

decision to allow stranded cost

recovery, other entities ask the

Commission to expand the scope of the

stranded cost recovery allowed by Order

No. 888. Various entities ask that the

scope of stranded cost recovery be

expanded to include situations in which

the departing customer does not take

unbundled transmission from the

former supplier and in which

previously existing municipal utilities

annex additional territory or otherwise

expand.508 These entities disagree with

the Commission’s analysis in Order No.

888 that the opportunity to seek

recovery should be precluded in

situations in which the departing

wholesale customer ceases to purchase

power from the utility but does not use

the utility’s transmission system to

reach another supplier. The

Commission excluded these situations

because the costs would not be stranded

as a result of the Commission’s open

access transmission requirement, but

rather as a result of the exercise of a

preexisting competitive option. The

entities argue on rehearing that such

costs are attributable to the

Commission’s efforts to restructure the

wholesale power market. Several argue

that there is no good policy reason for

addressing stranded costs only where

linked directly to the Open Access Rule

or section 211 orders because a variety

of federal actions, not just the Open

Access Rule and section 211 orders,

have created a competitive wholesale

power market and the specter of

stranded costs caused by customers

departing their traditional utility. They

contend that, but for the Commission’s

creation of a vibrant power market,

EPAct, and other pre-Order No. 888

efforts by the Commission to expand

transmission access, the preexisting

options would not have been (and

historically were not) exercised.

Puget argues that even when a

departing customer can import its new

power supply without using its former

supplier’s transmission system, it

frequently will be the case that the

power supply would not be available to

the customer if open access

transmission rules were not in place to

permit that power to move from distant

generators over intervening utilities’

transmission facilities.509

EEI expresses concern that strict

application of the ‘‘but for open access’’

test would create new incentives to

evade stranded cost recovery.510

According to EEI, the Rule would deny

recovery for costs stranded pursuant to

a voluntarily negotiated transmission

service agreement, but would permit

recovery if such agreement were ordered

pursuant to FPA section 211. In this

manner, EEI contends that the Rule will

discourage parties from settling

transmission disputes. It says that any

transmission agreement negotiated

under ‘‘the threat’’ of section 211 should

be entitled to stranded cost recovery if

providing service results in the

stranding of legitimate and prudent

costs.

PSE&G and Carolina P&L express

concern that denying stranded cost

recovery where the departing customer

does not use the former supplier’s

transmission system will create an

artificial incentive to build ‘‘contract

path’’ lines designed to thwart stranded

cost recovery. They maintain that the

existence of alternative transmission

paths should not be a bar to stranded

cost recovery where the departing

customer avails itself of the

Commission’s Mobile-Sierra finding

permitting customers to challenge the

terms of their contracts under the just

and reasonable standard. They assert

that, notwithstanding the availability of

alternative transmission, the only way

that the customer could have availed

itself of the Mobile-Sierra finding was as

a result of the Commission’s Open

Access Rule.

Several entities contend that the

FPA’s requirement of just and

reasonable rates and the Fifth

Amendment’s requirement to avoid

confiscation require the Commission to

address stranded costs that result when

a departing customer does not use the

former supplier’s transmission system

or that result from municipal

annexation.511 According to Puget, the

ultimate Constitutional test will be

whether Order No. 888 will afford a fair

overall return on all prudent utility

investments under the Constitutional

standards set forth by the Supreme

Court.512 Coalition for Economic

Competition submits that, as was the

case in the context of the unbundling of

natural gas pipelines, the Commission

cannot ignore stranded costs resulting

from the unbundling of electric services

and should acknowledge its

Constitutional obligations to address the

recovery of all stranded costs, including

those that result from municipal

expansion and those that result when a
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12381

513E.g., EEI, Oklahoma G&E, Nuclear Energy

Institute, Southern. Southern requests that the

Commission add a section 35.29 to the regulatory

text providing: ‘‘Sections 35.26 and 35.28 of this

part constitute unseverable portions of a unitary

action of the Commission.’’

514E.g., Carolina P&L, PSE&G.

515We discuss in Section IV.J.6 below our

disposition of the rehearing requests that support

recovery of costs stranded as a result of municipal

annexation or expansion. In response to EEI’s

argument that the Rule would deny recovery for

costs stranded pursuant to a voluntarily-negotiated

transmission service agreement and would

discourage parties from settling transmission

disputes, we find EEI’s arguments in support of its

position to be vague and cursory. However, we do

not interpret the Rule in any way as precluding

parties from addressing stranded cost issues

through settlement, including settlement of a

transmission dispute. To the contrary, we fully

expect that the renegotiation of contracts, including

transmission agreements, would provide parties

with a useful means for resolving stranded cost

issues without litigation. We believe that a

negotiated rate that includes an amount for

stranded cost recovery could be found to be just and

reasonable.

516FERC Stats. & Regs. at 31,849–50; mimeo at

624–26.

customer does not obtain transmission

services from its former supplier.

SC Public Service Authority also asks

the Commission to allow the recovery of

stranded costs that result from the loss

of indirect customers (e.g., customers of

wholesale requirements customers). It

argues that if such indirect customers

can get access to a new source of power

through open access tariffs, the

requirements of the utility’s direct

customer will decrease, and the

supplying utility will suffer stranded

costs. SC Public Service Authority states

that because of the nexus between open

access and the departure of the indirect

customer, utilities that suffer stranded

costs in the event of the loss of an

indirect customer should have an

opportunity to recover those costs under

the reasonable expectation standard.

A number of entities also ask the

Commission to find that open access

transmission and stranded cost recovery

are necessary to accomplish the remedy

ordered by the Commission and thus are

not severable.513 To this end, they

submit that if the Commission’s ability

to provide for stranded cost recovery is

reduced or substantially modified,

public utilities should be able to

withdraw filed tariffs or to file amended

tariffs. It is their position that deletion

or substantial change of the open access

or stranded cost provisions by the

Commission or by a court would vitiate

the basis on which the Commission

premised the Rule.

In an effort to ensure that stranded

cost recovery procedures do not become

a vehicle for lengthy and expensive

litigation over whether there is a

sufficient nexus to open access, several

entities ask the Commission to place on

the departing generation customers the

burden to demonstrate the absence of a

nexus between their actions and the

availability of open access transmission

under the Rule in those cases where: (i)

the contract has no term or termination

provision; (ii) the Commission issues an

order under section 206 reducing the

term of the contract; or (iii) there is

legitimate municipalization.514

Commission Conclusion

We will deny the requests for

rehearing that ask us to expand the

scope of stranded cost recovery to

include situations in which the

departing customer does not take

unbundled transmission from its former

supplier but instead obtains

transmission from another utility or

obtains power from a third party

supplier who is located in the

customer’s service territory and thus

requires no transmission from the

former supplier.515 As the Commission

stated in Order No. 888, the premise of

the Rule is that where the former

requirements supplier had a reasonable

expectation of serving beyond the

contract term and the customer uses the

open access transmission tariff of its

former requirements supplier to obtain

power from a new generation supplier,

the customer must pay the costs that

were incurred on its behalf under the

prior regulatory regime. The Rule is not

intended, however, to apply to the

recovery of costs associated with the

normal risks of competition, such as

self-generation, cogeneration, or loss of

load, that do not arise from the new,

accelerated availability of nondiscriminatory open access

transmission. If a customer leaves its

utility supplier by exercising options

that could have been undertaken prior

to mandatory transmission under Order

No. 888 or the Energy Policy Act, or that

do not rely on access to the former

seller’s transmission (such as access to

another power supplier through another

utility’s transmission system or selfgeneration), there is no direct nexus to

Commission-mandated transmission

access.

For example, if a customer is able to

obtain power from a new supplier by

using the transmission system of

another utility, it is likely that the

customer could have made these

arrangements in the absence of the new

open access rules. The new

transmission provider would have had

little incentive to deny transmission

services to the customer in order to

protect another utility’s existing power

supply arrangement, since it was not the

customer’s power supplier in the first

place. As Order No. 888 suggested, it is

likely that the neighboring utility would

have a positive incentive to provide the

transmission service in order to increase

its transmission revenues, and that this

incentive is unchanged by open access

transmission.516

Although EEI and others argue that

EPAct and the Commission’s pre-Order

No. 888 efforts to expand transmission

access have facilitated the exercise of

pre-existing competitive options, the

fact remains that such options

historically were available before open

access. For this reason, we conclude

that costs incurred as a result of the

exercise of pre-existing competitive

options do not fall within the scope of

Order No. 888.

A number of entities argue that, even

where the departing customer obtains

access to another power supplier

through the transmission system of

another utility (i.e., not that of its former

supplier), the power supply would not

have been available to the customer if

open access transmission rules were not

in place to permit that power to move

from distant generators over intervening

utilities’ transmission facilities. Some

argue that there is no good policy reason

for addressing stranded costs only

where linked directly to the Open

Access Rule (or to a section 211 order)

because a variety of federal actions have

created a competitive wholesale power

market and the specter of stranded costs

caused by customers departing their

traditional utility. While these

arguments may have superficial appeal,

the effective result would be to provide

for recovery of stranded costs from

departing customers under the Rule no

matter how tenuous the nexus to

Commission-mandated transmission

access. The Commission has to exercise

reasonable judgment and reasonable

line drawing regarding the link between

its actions in this Rule and the decision

to allow an opportunity for extracontractual stranded cost recovery from

the departing customer. The

Commission believes that requiring a

direct nexus between Commissionmandated transmission access (namely,

requiring that the departing customer

obtain access to another power supplier

through the use of its former supplier’s

Commission-required tariff—i.e., an

open access tariff or a tariff ordered

pursuant to section 211) and the special

stranded cost recovery procedures of

this Rule is the most reasoned and

supportable approach because it

establishes a clear link between

availability of the transmission tariff
12382 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

517 488 U.S. at 307.

518These parties appear to refer to a situation in

which a customer is able to modify or terminate its

contract, but would use the transmission system of

a utility other than that of its former supplier in

order to reach a new generation supplier. In this

circumstance, the Rule would not permit the former

supplier to seek stranded costs.

519FERC Stats. & Regs. at 31,789–90; mimeo at

454–55.

520 In addition, the proposal would not eliminate

lengthy litigation. It would only change the burden

of proof in whatever litigation occurs.

521We note, however, that in a section 206

proceeding brought by a customer seeking to

shorten or terminate a contract, the customer has

the burden (as it would in any section 206 case that

it initiates) of presenting sufficient evidence that

the contract is no longer just and reasonable. As we

stated in the Rule, the utility must present any

stranded cost claim at that time. See FERC Stats. &

Regs. at 31,664, 31,813; mimeo at 86–87, 521–22.

and the decision of the customer to seek

an alternative supplier.

With regard to potential stranded

costs associated with situations that

could have occurred prior to the Open

Access Rule and prior to the Energy

Policy Act (such as self-generation),

under traditional ratemaking such costs

(albeit not previously labeled as

potential ‘‘stranded’’ costs) would in

most cases be reallocated in the next

rate case to remaining customers. The

fact that this Rule does not permit a

utility to seek recovery of these types of

costs from the departing customer does

not mean that the Commission may not,

in appropriate circumstances, permit

their recovery through traditional

ratemaking means. However, many

factors will influence cost recovery in

the future, including whether the utility

is selling at cost-based or market-based

rates and the transitional period to more

competitive bulk power markets. The

Commission will address these matters

on a case-by-case basis.

We do not agree with those

commenters who contend that the

Commission’s failure in Order No. 888

to allow for the recovery of costs

incurred by a utility when a departing

customer does not use the former

supplier’s transmission system to reach

a new supplier would be confiscatory in

violation of the Constitution. As the

Supreme Court explained in Duquesne,

‘‘[t]he guiding principle has been that

the Constitution protects utilities from

being limited to a charge for their

property serving the public which is so

‘unjust’ as to be confiscatory.’’517

However, Order No. 888 addresses only

the recovery of legitimate, prudent and

verifiable costs that are stranded if a

former wholesale requirements

customer or a former retail customer

uses a Commission-mandated

transmission tariff to reach a new

supplier. As discussed above, Order No.

888 does not by its terms bar the

recovery of costs that do not result from

the use of Commission-required

transmission access (i.e., costs that

result when a departing customer does

not use the former supplying utility’s

open access tariff). Utilities may, as

before, seek recovery of such non-open

access-related costs on a case-by-case

basis in individual rate proceedings.

The Commission will not prejudge those

issues here. As a result, the argument

that the Commission’s treatment of

stranded costs in Order No. 888 (i.e., its

failure to treat certain costs as costs for

which recovery may be sought under

the Rule) will result in rates that will be

so unjust as to be confiscatory is

misplaced.

We deny SC Public Service

Authority’s request that the Commission

allow a utility to seek recovery of

stranded costs that result from the loss

of indirect customers (i.e., the loss of the

utility’s customer’s customers). The

Commission does not believe it is

appropriate or feasible to allow a public

utility (or a transmitting utility under

section 211 of the FPA) to seek recovery

of stranded costs from an indirect

customer (i.e., a customer of a wholesale

requirements customer of the utility).

The reasonable expectation analysis

would apply only to the direct

wholesale customer of the utility, not to

the indirect customer. A utility may

seek to recover stranded costs from a

direct wholesale customer (subject to

the requirements of the Rule), but it is

up to the direct wholesale customer,

through its contracts with its customers

or through the appropriate regulatory

authority, to seek to recover stranded

costs from its customers.

We also deny PSE&G’s and Carolina

P&L’s request that a utility be allowed

to seek stranded cost recovery in cases

where the departing customer uses the

Commission’s Mobile-Sierra finding to

get out of the contract under the just and

reasonable standard and uses alternative

suppliers and alternative

transmission.518 We disagree with their

argument that the only way that the

customer could have availed itself of a

Mobile-Sierra finding was as a result of

the Commission’s open access rules and

thus the necessary nexus is met. A

customer to a Mobile-Sierra contract

always has the option of instituting a

proceeding under section 206 of the

FPA and making a showing of why,

under Mobile-Sierra, it is in the public

interest to modify the contract.

We will not, at this time, make any

determination whether or not the

requirements of open access

transmission and stranded cost recovery

are severable. As we indicated in Order

No. 888, we issued the Stranded Cost

Final Rule simultaneously with the

Open Access Rule because we believe

that the recovery of legitimate, prudent

and verifiable stranded costs is critical

to the successful transition of the

electric industry to a competitive, open

access environment.519 We believe that

our decision to allow stranded cost

recovery will be upheld by the courts.

Moreover, as we discuss in Section

IV.A.1 above, it would be premature to

consider at this time what the

Commission would do if one or more of

the provisions of the Rule are not

upheld. Circumstances at the time of

any court order would dictate how we

should proceed and we would consider

all such circumstances, and the entirety

of our policy decisions, before

determining how to respond to a court

decision.

Further, we decline to place on

departing generation customers the

burden of demonstrating that no nexus

exists between their actions and the

availability of open access transmission

under the Rule in cases involving no

term or termination provision, an order

under section 206 reducing the term of

the contract, or municipalization. The

proponents of such a proposal, Carolina

P&L and PSE&G, attempt to justify it as

a means to ensure that stranded cost

recovery procedures do not become a

vehicle for lengthy and expensive

litigation over whether there is a

sufficient nexus to open access in the

three identified situations. However,

Order No. 888 places the burden on the

utility seeking stranded cost recovery to

demonstrate that the costs for which it

seeks recovery fall within the scope of

the Rule and that it had a reasonable

expectation of continuing service. In

this regard, the Rule tracks the

requirement of sections 205 and 206 of

the FPA that a public utility

demonstrate the justness and

reasonableness of its proposed rates.

Carolina P&L and PSE&G fail to explain

why it would be appropriate for

customers (as opposed to the utilities

seeking recovery) in the three identified

situations to bear the initial burden of

demonstrating why costs should not be

recovered from them under the Rule.520

As a result, we reject their proposal.521

Rehearing Requests—Stranded Cost

Recovery By Transmitting Utilities That

Are Not Public Utilities

A number of entities contend that the

Commission’s decision to limit stranded

cost recovery for transmitting utilities

that are not public utilities to section
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12383

522E.g., NRECA, TDU Systems, Dairyland Coop.

523Stranded costs could also conceivably arise as

a result of an ordered interconnection under section

210. However, the rates for such an interconnection

would be established pursuant to section 212 and

could therefore also include stranded costs.

524FERC Stats. & Regs. at 31,791; mimeo at 458.

If such a transmitting utility seeks stranded cost

recovery in a proceeding under sections 211 and

212, it would, consistent with the provisions of the

Rule, be limited to recovery associated with

requirements contracts executed on or before July

11, 1994 that do not contain an exit fee or other

explicit stranded cost provision.

525FERC Stats. & Regs. at 31,691; mimeo at 162.

526FERC Stats. & Regs. at 31,760–62; mimeo at

370–74.

527Although the Commission would not

determine the rate, including the stranded cost

component of the rate, of a non-public utility, we

would review a public utility’s claim that it is

entitled to deny service to a non-public utility

because the stranded cost component of the nonpublic utility’s transmission rate is being applied in

a way that violates the principle of comparability.

528We note that in the case of stranded cost

claims presented to the Commission by BPA or one

of the other PMAs, our review would be limited to

that set forth in the applicable statutes and any

relevant delegation of authority from the Secretary

of Energy. See, e.g., Pacific Northwest Electric

Power Planning and Conservation Act, 16 U.S.C.

§ 839–839h (1985) (Northwest Power Act);

Department of Energy Delegation Order No. 0204–

108, as amended, 48 FR 55,664 (1983), amended, 51

FR 19,744 (1986), amended, 56 FR 41,835 (1991),

amended, 58 FR 59,716 (1993) (delegation order

relating to Western Area Power Administration).

211 proceedings is inconsistent with its

decision to impose the reciprocity

requirement on those utilities, violative

of the principle of comparability, and

unduly discriminatory and

anticompetitive.522 NRECA submits that

if the Commission has the statutory

authority to require non-public utilities

to render transmission service outside of

a section 211 proceeding through the

reciprocity, RTG and power pool

provisions of the Rule, then it must

exercise that authority to ensure

stranded cost recovery by such nonpublic utilities. Noting that the Rule

does not address how a non-public

utility that chooses voluntarily to

provide an open access tariff can

recover its stranded costs, SC Public

Service Authority asks the Commission

to confirm on rehearing that nonjurisdictional utilities can include a

provision for recovery of stranded costs

in their tariffs provided pursuant to the

Final Rule.

Commission Conclusion

The Commission’s jurisdiction over

the recovery of stranded costs by nonpublic utilities, and thus our ability to

permit an opportunity for recovery of

such costs, is limited by statute. While

we have the statutory authority to

ensure that non-public utilities have the

opportunity to seek recovery of stranded

costs in proceedings under sections 211

and 212 of the FPA,523 we do not have

such authority under sections 205 and

206 of the FPA. However, we clarify that

nothing in the Final Rule was intended

to preclude non-public utilities from

including stranded cost provisions in

voluntary reciprocity tariffs or from

otherwise recovering stranded costs

under applicable law. We discuss these

matters in detail below.

As we stated in Order No. 888 in

response to commenters’ objections that

the Rule would give public utilities a

greater opportunity than other

transmitting utilities to recover stranded

costs, our jurisdiction over transmitting

utilities that are not also public utilities

is limited. If the selling utility is a

transmitting utility that is not a public

utility, its power sales contracts are not

subject to this Commission’s

jurisdiction under sections 205 and 206

of the FPA. Thus, we can provide such

a transmitting utility an opportunity to

recover stranded costs only through

Commission-jurisdictional transmission

rates fixed under sections 211 and 212

of the FPA.524

The open access tariff reciprocity

provision, which applies to all open

access customers that own, operate, or

control transmission facilities or are

affiliates of entities that own, operate or

control such facilities, and that do not

obtain a waiver of the provision, does

not create jurisdiction for the

Commission to fix the rates for these

utilities. Contrary to the suggestions of

some, the tariff reciprocity provision is

not based on any statutory authority of

the Commission to require non-public

utilities to render transmission service

outside of a section 211 proceeding. As

we make clear in Order No. 888, we do

not have authority under sections 205

and 206 of the FPA to require nonpublic utilities to file tariffs (or rate

schedules for that matter) with the

Commission.525 In permitting a public

utility to deny transmission service to

any person that requests service under

an open access tariff unless that person

provides reciprocal non-discriminatory

transmission services to the

transmission provider, we are not acting

under any statutory authority to require

non-public utilities to provide

transmission access. Rather, out of

fairness, we are conditioning the use of

open access services by all customers,

including non-public utilities, on an

agreement to offer comparable

transmission services in return to the

public utility transmission provider.526

We clarify that a non-public utility

that chooses voluntarily to offer an open

access tariff for purposes of

demonstrating that it meets the

reciprocity provision can include a

stranded cost provision in its tariff.

However, adjudication of any stranded

cost claims under that tariff is not

subject to the Commission’s

jurisdiction.527 With the exception of

our section 210 interconnection and

sections 211–212 transmission rate

jurisdiction, we do not have jurisdiction

over the rates of non-public utilities. If

a non-public utility wishes to recover

stranded costs pursuant to a tariff or

otherwise, it can seek to do so subject

to the review of the appropriate

regulatory authority.528

Rehearing Requests—Stranded Cost

Recovery for Transmission Dependent

Utilities

NRECA and TDU Systems challenge

the Commission’s decision not to

guarantee a transmission dependent

utility that is not a public utility

stranded cost recovery when the

transmission dependent utility’s

customers leave its system by using the

open access tariff of another utility.

They submit that the ability of

transmission dependent utilities to

compete with public utility

transmission providers in an open

access environment would be severely

affected by their inability to recover

stranded costs on a basis comparable to

those transmission providers. They

argue that the open access provisions of

Order No. 888 will result in the

stranding of costs incurred by nontransmission owning, non-public

utilities to serve customers that depart

to other suppliers. They contend that

these customers are already located in

close proximity to, and interconnected

to, public utilities; thus it is likely that

they would use the open access tariffs

of these public utilities to obtain their

new power supplies. NRECA and TDU

Systems argue that this situation should

meet the ‘‘but for open access’’ nexus.

On this basis, they assert that Order No.

888 is no less the proximate cause of the

departure of customers of transmission

dependent utilities than it is of the

departure of public utility transmission

owners’ customers. They object that the

Commission takes no account of the

anticompetitive effects of disregarding

costs stranded on transmission

dependent utilities’ systems as a result

of open access.

Dairyland Coop asks the Commission

to recognize a generation and

transmission (G&T) cooperative and its

member distribution cooperatives as a

single economic unit for purposes of

stranded cost recovery (such that

conversion of a distribution
12384 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

529FERC Stats. & Regs. at 31,790; mimeo at 456–

57.

530FERC Stats. & Regs. at 31,790; mimeo at 456–

57.

531Unless these entities own some transmission

used in interstate commerce or are engaged in sales

for resale, and are not otherwise exempt under FPA

section 201(f), they would not be public utilities

under sections 205 and 206. Most transmission

dependent utilities are not public utilities.

532A G&T cooperative that is a transmitting utility

could seek recovery of stranded costs if it is ordered

to provide transmission services that permit its

distribution cooperative to reach another supplier

and if it had a requirements contract with the

distribution cooperative that was executed on or

before July 11, 1994.

533FERC Stats. & Regs. at 31,763; mimeo at 377–

78.

cooperative’s retail customer to a

wholesale customer may result in

stranded costs for the G&T cooperative).

It objects that the Commission

implicitly rejected comments to this

effect without discussion in Order No.

888.

Commission Conclusion

We deny the requests for rehearing of

our decision not to permit transmission

dependent utilities and electric

cooperatives to seek stranded cost

recovery unless they are public utilities

or transmitting utilities that would

otherwise qualify under the Rule. With

regard to transmission dependent

utilities, as we indicated in Order No.

888, the limited opportunity for

stranded cost recovery contained in the

Rule would not likely apply in the case

of transmission dependent utilities, who

own little or no transmission and the

majority of whom would not be public

utilities or transmitting utilities subject

to the Commission’s jurisdiction.529 The

opportunity for extra-contractual

wholesale stranded cost recovery is

allowed only where the departing

customers use open access (or section

211 access) on the transmission systems

of their former generation suppliers and

only for a discrete set of requirements

contracts executed on or before July 11,

1994 that do not contain explicit

stranded cost provisions (involving the

bundled provision of generation and

transmission) and retail-turnedwholesale situations for which the

utility can demonstrate that it had a

reasonable expectation of continuing

service. Even though it may be the case

that transmission dependent utilities

lose generation customers that are able

to use open access tariffs of other

utilities to reach new suppliers, there

was nothing to keep these other utilities

from offering such transmission service

before Order No. 888. These other

utilities had no economic incentive to

deny such service before Order No. 888.

Thus, in the scenario posited in the

rehearings, the transmission dependent

utilities do not meet the fundamental

premise of the Rule: that a utility that

historically has supplied bundled

generation and transmission services to

a wholesale requirements customer and

incurred costs to meet reasonably

expected customer demand should have

an opportunity to recover legitimate,

prudent and verifiable costs that may be

stranded because open access use of the

utility’s transmission system enables a

generation customer to shop for

power.530

However, this is not to say that a

transmission dependent utility that is

not a public utility, or other non-public

utility entities (such as RUS-financed

cooperatives), cannot seek recovery of

the cost of any resulting uneconomic

assets through their contracts with their

customers or through the appropriate

regulatory authority. The Commission

has no objection to these entities being

able to seek such cost recovery through

the appropriate regulatory channels.

However, because the Commission does

not have jurisdiction over these entities

(other than through sections 211 and

212 in the case of non-public utility

transmitting utilities), it does not have

authority to allow them to recover these

costs.531

We also deny Dairyland Coop’s

request that the Commission recognize a

G&T cooperative and its member

distribution cooperatives as a single

economic unit for purposes of stranded

cost recovery. If a cooperative obtains its

financing through RUS, it is not a public

utility subject to our jurisdiction under

sections 205 and 206 of the FPA.

Although the Commission has no

objection to these G&T cooperatives

being able to seek cost recovery

(including recovery of costs on behalf of

their distribution cooperatives) through

the appropriate regulatory channels, this

Commission does not have authority to

allow them to seek recovery of stranded

costs unless access is obtained through

a section 211 order.532

In the case of a G&T cooperative that

is a public utility (of which there are

just a handful at the present time), such

a cooperative would have to have a

jurisdictional wholesale requirements

contract with its distribution

cooperative in order to be able to seek

recovery of stranded costs under the

Rule. In the case of a jurisdictional G&T

cooperative, the request that the G&T be

treated as a single economic unit with

the distribution cooperative (such that

departure of a distribution cooperative’s

retail customer would be treated as

resulting in stranded costs for the G&T

cooperative for which the G&T could

seek recovery) is, in effect, a request for

recovery of stranded costs from an

indirect customer. As we discuss above,

the Commission does not believe it is

appropriate or feasible to allow a public

utility (or a transmitting utility under

section 211 of the FPA) to seek recovery

of stranded costs from an indirect

customer (i.e., a customer of a wholesale

requirements customer of the utility)

under this Rule. The reasonable

expectation analysis would apply only

to the direct wholesale customer of the

utility, not to the indirect customer. It

is up to the direct wholesale customer

of the utility, through its contracts with

its customers or through the appropriate

regulatory authority, to seek to recover

such costs from its customers.

Commenters have provided no basis

for making an exception in the case of

cooperatives. Moreover, to treat a G&T

cooperative and its member distribution

cooperatives as a single economic unit

for stranded cost purposes would be

inconsistent with the Commission’s

decision not to treat cooperatives as a

single unit for purposes of Order No.

888’s reciprocity provision.

In Order No. 888, in response to

arguments raised by cooperatives, the

Commission agreed to limit the

reciprocity requirement to corporate

affiliates. In other words, if a G&T

cooperative seeks open access

transmission service from the

transmission provider, only the G&T

cooperative (not its member distribution

cooperatives) would be required to offer

transmission service. If a member

distribution cooperative itself receives

transmission service from the

transmission provider, then it (but not

its G&T cooperative) must offer

reciprocal transmission service over its

interstate transmission facilities, if

any.533 Dairyland has provided no basis

to support treating cooperatives

differently for stranded cost purposes

and reciprocity purposes. We

accordingly will deny Dairyland’s

request for rehearing on this issue.

Rehearing Requests Opposing

Limitation of Recovery to Wholesale

Requirements Customers

PA Munis argues that it is inequitable

and anticompetitive for ‘‘wholesale

requirements customers’’ but not other

‘‘wholesale customers’’ to have to pay

stranded costs, repeating an argument

that it made in its comments on the

supplemental stranded cost NOPR. It

says that there is no difference in the

firm power provided by public utilities
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12385

534 Maryland People’s Counsel v. FERC, 761 F.2d

780 (D.C. Cir. 1985) (Maryland People’s Counsel I).

See also Maryland People’s Counsel v. FERC, 761

F.2d 768 (D.C. Cir. 1985) (Maryland People’s

Counsel II).

535FERC Stats. & Regs. at 31,790–91; mimeo at

457–58.

536We clarify, however, that a contract may meet

our definition of wholesale requirements contract

even though it does not carry the label

‘‘requirements contract.’’ The definition refers to a

contract that provides any portion of a customer’s

bundled wholesale power requirements. As

discussed above, whether or not a contract meets

this definition hinges upon whether the customer

depended upon the wholesale supplier for all or

part of its power because it could not obtain

transmission access to reach other suppliers, i.e., it

was captive to the historical local supplier.

to ‘‘wholesale requirements customers’’

and to ‘‘wholesale customers’’ and no

difference in the generating facilities

required and the costs of operation

between the production of firm capacity

and energy required for ‘‘wholesale

requirements sales’’ and ‘‘wholesale

sales.’’ PA Munis submits that the total

amount of wholesale requirements

power purchased in the United States is

less than two percent of the total

amount of firm power sales. It argues

that requiring only wholesale

requirements customers to pay stranded

costs would restrict the ability of such

customers to switch suppliers while not

similarly restricting large firm wholesale

customers. It contends that wholesale

firm requirements customers therefore

will not have equal access under the

Rule because of the increased

transmission rates for stranded costs

that would not be levied on other large

wholesale firm customers. Pa Munis

says this produces the same result found

unlawful in the Maryland People’s

Counsel case 534—equal access to all

wholesale customers is virtually denied

by the chilling effect of stranded costs

borne only by wholesale requirements

customers.

Commission Conclusion

In Order No. 888, the Commission

fully addressed the concerns of PA

Munis. We again address below the

major distinctions between

requirements and other customers and

deny rehearing.

In Order No. 888, we explained that

the historical and practical relationship

between a utility and its wholesale

requirements customers, including the

expectation of continued service,

justifies allowing public utilities the

opportunity to seek to recover the

stranded costs covered by this Rule from

only those customers and not from nonrequirements customers that contract

separately for transmission services to

deliver their purchased power or from

wholesale customers that purchase nonrequirements power. Requirements

customers historically were long-term

customers who by definition depended

upon their local suppliers because they

were captive customers. Utilities had no

obligation to provide transmission

service that would allow these

customers to reach other suppliers, and

there were no other transmission

facilities in proximity to those of the

supplying utility. And the service

involved requirements power; that is,

these customers were dependent upon

the wholesale supplier for all or part of

their power. Utilities thus assumed they

would continue serving these customers

and may have made significant

investments based on that long-term

expectation. These same assumptions

cannot be made for short-term, non-firm

transactions and other wholesale nonrequirements firm transactions. Unlike

requirements customers, these

customers had other options. Thus, the

supplying utility could not assume that

these customers would remain on its

system.

With regard to short-term

transactions, utilities did not (and do

not today) generally make investments

for short-term economy-type

transactions. Rather, such transactions

were entered into only when the utility

temporarily had available capacity or

energy that could be provided to the

buyer at a price higher than the seller’s

incremental cost and lower than the

buyer’s decremental cost. The utility

was not obligated in any way—either

explicitly or implicitly—to provide for

the needs of coordination customers.

Because coordination transactions were

not the cause of stranded investment

decisions, it would be inappropriate to

allocate such costs to non-requirements

customers.535

With regard to long-term, nonrequirements firm transactions, such as

unit power sales contracts, we note that

there was no implied obligation to serve

customers to these transactions as there

was for requirements customers.

Generating units were not built for the

purpose of entering into these

arrangements. Therefore, because

utilities did not incur costs on behalf of

non-requirements firm power sales

customers, such customers have not

caused costs to be stranded and should

not be required to pay stranded cost

charges. Accordingly, we reaffirm

limiting the opportunity for stranded

cost recovery to costs associated with

wholesale requirements contracts.536

We recognize PA Munis’ concern that

if a utility meets the evidentiary

requirements of the Rule and is allowed

to recover stranded costs from

wholesale requirements customers, such

customers may see little or no savings

in the short-term by switching power

suppliers, since a stranded cost charge

(in the form of either an exit fee or a

surcharge on transmission) would be

paid in addition to the power price paid

a new supplier. However, as we discuss

above and in Section IV.J.2 below, we

believe that stranded costs are transition

costs that must be addressed at an early

stage if we are to fulfill our regulatory

responsibilities in moving to

competitive markets. Further, as we

explain in Section IV.J.3 below,

although spreading the costs to all

transmission users of a utility’s system

(rather than imposing them directly on

the departing wholesale requirements

customer) might enable the customer to

see earlier power cost savings than

would result if stranded costs were

directly assigned to the customer, we

have concluded that this potential

benefit to a broad-based approach is

outweighed by a significant

countervailing disadvantage—namely,

the violation of the cost-causation

principle of ratemaking. The

Commission rejects a broad-based

approach for the electric industry

primarily because the potential power

cost savings to the departing generation

customer would be realized only by

shifting costs that are directly

attributable to the departing generation

customer to the other users of the

utility’s transmission system.

Contrary to PA Munis’s claim, we

believe that the circumstances

surrounding the opportunity to seek

stranded cost recovery from wholesale

requirements customers that is

permitted in Order No. 888 are

distinguishable from the issues that

were before the court in the Maryland

People’s Counsel cases. Those cases

involved challenges to Commission

orders that permitted pipelines to

transport gas at lowered prices to ‘‘noncaptive consumers’’ (large industrial

end users capable of switching to

alternative fuels) without any obligation

to provide the same service to ‘‘captive

consumers’’ such as local distribution

companies and their residential

customers. In Maryland People’s

Counsel I, the court invalidated the

Commission’s authorization of a

‘‘special marketing program’’ under

which a pipeline and its producer

would agree to amend their high-priced

gas purchase contract to permit the

producer to sell the committed gas

elsewhere at market prices and to credit

the volume of such sales against the

pipeline’s high-priced purchase

obligations. Eligibility to purchase the
12386 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

537See 761 F.2d 768.

538See 761 F.2d at 781–82.

539Pro Forma Open Access Transmission Tariff,

section 1.11.

540TX Com’s request for rehearing was filed outof-time on May 29, 1996 with a request that the

Commission accept the rehearing request for filing

as of May 24, 1996. TX Com explains it had made

arrangements with a courier company to pick up its

rehearing request on May 23, 1996 and deliver and

file the rehearing request with the Commission

before 5 p.m. on May 24, 1996. TX Com states that

the courier company failed to pick up the rehearing

request on May 23 as previously arranged. TX Com

says that when it became aware on May 24 that its

rehearing request was not enroute to the

Commission, it faxed a copy of the rehearing

request to a copier and delivery service in

Washington, D.C. The pleading, which was not

signed, was delivered to the Commission prior to

5 p.m. on May 24. TX Com states that Commission

personnel rejected the filing apparently because it

was not signed. TX Com asks that the Commission

find good cause under Rule 2001 of the

Commission’s Rules of Practice and Procedures, 18

CFR 385.2001 (1996), to accept its rehearing request

for filing as of May 24, 1996. Under the

circumstances, we will accept the rehearing request

for filing as of May 24, 1996.

541Texas Utilities Electric Company filed on June

21, 1996 a motion for leave to file and response to

TX Com’s rehearing request. Texas Utilities opposes

TX Com’s positions on rehearing. While answers to

requests for rehearing generally are not permitted,

18 CFR 385.213(a)(2) (1996), we will depart from

our general rule because of the significant nature of

this proceeding and will accept Texas Utilities’

response.

542 ‘‘Wholesale stranded cost’’ is defined as ‘‘any

legitimate, prudent and verifiable cost incurred by

a public utility or a transmitting utility to provide

service to: (1) 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.’’ Order No.

888, mimeo at 768.

543 ‘‘Wholesale transmission services’’ is defined

as ‘‘ha[ving] the same meaning as provided in

section 3(24) of the Federal Power Act (FPA): the

transmission of electric energy sold, or to be sold,

at wholesale in interstate commerce.’’ Order No.

888, mimeo at 768.

544 76 FERC ¶ 61,138 (1996).

545Section 212(k), added by EPAct, provides as

follows: (1) RATES.—Any order under section 211

requiring provision of transmission services in

whole or in part within ERCOT shall provide that

any ERCOT utility which is not a public utility and

the transmission facilities of which are actually

used for such transmission service is entitled to

receive compensation based, insofar as practicable

and consistent with subsection (a), on the

transmission ratemaking methodology of the Public

Utility Commission of Texas. 16 U.S.C. § 824k(k)

(1994).

546To clarify that the Order No. 888 stranded cost

provisions apply to the intrastate utilities within

ERCOT, solely in the context of a section 211

proceeding, we will revise the definition of

‘‘wholesale transmission services’’ in section

35.26(b)(3) to read: ‘‘Wholesale transmission

services means the transmission of electric energy

sold, or to be sold, at wholesale in interstate

commerce or ordered pursuant to section 211 of the

Federal Power Act (FPA).’’

cheaper released gas was limited to

industrial users. The court found that

the Commission had failed to provide a

reasonable basis for its decision to

exclude ‘‘captive customers’’ from

eligibility to purchase the cheaper

released gas.537 In Maryland People’s

Counsel II, the court invalidated the

Commission’s approval of blanket

authority for interstate transportation of

natural gas sold directly by producers to

fuel-switchable end users. The court

held that the Commission had failed to

consider the anticompetitive effects of

failing to require the pipelines to

provide the same service to captive

consumers on nondiscriminatory

terms.538

In contrast to the Maryland People’s

Counsel cases, the Commission in Order

No. 888 is not discounting services for

one class of customers to the exclusion

of another, nor is it ordering that public

utilities provide transmission access to

only a specified customer group. To the

contrary, Order No. 888 requires all

public utilities that own, control or

operate facilities used for transmitting

electric energy in interstate commerce to

provide open access transmission to any

‘‘eligible customer,’’ with ‘‘eligible

customer’’ defined broadly to include

‘‘any electric utility (including the

Transmission Provider and any power

marketer), Federal power marketing

agency, or any person generating

electric energy for sale for resale.’’ 539

Among other things, Order No. 888

gives wholesale requirements customers

that previously were captive customers

of their public utility suppliers the

opportunity at the expiration of their

contracts to take unbundled

transmission service from their former

suppliers in order to reach new

suppliers. At the same time, the

Commission recognizes that the

departure of a wholesale requirements

customer in this circumstance may

strand costs that the former supplying

utility incurred based on a reasonable

expectation that it would continue to

serve the customer beyond the contract

term. As a result, Order No. 888 gives

the former supplying utility the

opportunity to seek recovery of costs

stranded by the wholesale requirements

customer’s departure.

In further contrast to the Maryland

People’s Counsel cases, the Commission

addresses in this Order (above) PA

Munis’ claim that it is inequitable and

anticompetitive that only wholesale

requirements customers and not other

wholesale customers are subject to the

stranded cost provisions of Order No.

888. The Commission has explained in

detail the rationale for its decision that

public utilities should be allowed an

opportunity to seek to recover the

stranded costs covered by this Rule only

from wholesale requirements customers.

The Commission has also addressed in

Section IV.J.2 below the concerns

expressed by some as to the potential

anticompetitive effect of stranded cost

charges.

Rehearing Request—ERCOT

The TX Com 540 asks the Commission

to clarify that ERCOT utilities may not

use a section 211 proceeding as a

vehicle to obtain wholesale or retail

stranded cost recovery. 541 It notes that

based on the definitions in section 35.26

of ‘‘wholesale stranded cost’’ 542 and

‘‘wholesale transmission service,’’ 543

the Rule applies only to interstate

service and does not apply to the

intrastate service provided by the

utilities within ERCOT, yet the

Commission suggests that it might

permit a utility in ERCOT to recover

stranded costs in a section 211

proceeding. Even if the Commission

concludes that it has the authority to

resolve stranded cost issues for ERCOT

utilities, TX Com asks the Commission

to establish a preference for resolution

of transmission and stranded cost issues

in ERCOT by TX Com. It suggests that

uncertainty and gaming as to the choice

of a forum could be avoided by

executing a Memorandum of

Understanding between TX Com and

the Commission that would require

interested persons to submit disputes to

TX Com. Further, to the extent that the

new ERCOT transmission access rules

adopted by the TX Com may be deemed

as the cause of stranded costs in ERCOT,

TX Com asserts that it should be

allowed to resolve issues related to such

stranded costs.

Commission Conclusion

In City of College Station, Texas,544

the Commission repeated its view, first

articulated in 1979, that sections 211

and 212 of the FPA clearly give the

Commission jurisdiction to order

transmission services within ERCOT,

subject to the special rate provision for

ERCOT utilities in section 212(k).545 The

Commission indicated that if it issues a

final order in that case setting rates for

transmission services within ERCOT, it

will comply with section 212(k) and

give deference to the TX Com’s

ratemaking methodology insofar as

practicable and consistent with section

212(a).

Our jurisdiction to order transmission

services within ERCOT includes the

authority to address costs that are

stranded by a section 211 transmission

order.546 Consistent with the special rate

provision in section 212(k), we clarify
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12387

547 28 F.3d 173 (D.C. Cir. 1994) (Cajun).

548FERC Stats. & Regs. at 31,793–95; mimeo at

464–70.

549See, e.g., ELCON, Suffolk County, Central

Illinois Light, American Forest & Paper, TDU

Systems, Blue Ridge, Nucor, IN Consumer

Counselor, IN Consumers, APPA, PA Munis, VT

DPS, Valero.

550E.g., Central Illinois Light, American Forest &

Paper.

551E.g., American Forest & Paper, PA Munis.

552E.g., American Forest & Paper, Occidental

Chemical, PA Munis.

553E.g., Arkansas Cities, IN Consumer Counselor,

IN Consumers, Occidental Chemical, PA Munis.

554E.g., APPA, Arkansas Cities.

555 72 F.3d 147 (D.C. Cir. 1995) (Western

Resources).

556The Commission’s power under the FPA

carries with it the responsibility to consider, in

appropriate circumstances, the anticompetitive

effects of regulated aspects of interstate 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

(1973). While the Commission lacks principal

responsibility for implementing antitrust policy, it

retains an obligation to give reasoned consideration

to the bearing of antitrust policy on matters within

its jurisdiction. Alabama Power Company, et al. v.

FPC, 511 F.2d 383 (D.C. Cir. 1974).

that we will give deference to the TX

Com’s ratemaking methodology,

including any provisions or procedures

related to stranded cost recovery, insofar

as it is practicable and consistent with

section 212(a) and consistent with the

principle of comparability set out in

Order No. 888.

2. Cajun Electric Power Cooperative,

Inc. v. FERC 547

In Order No. 888, the Commission

explained why it does not interpret the

Cajun court decision as barring the

recovery of stranded costs and why the

record developed in this generic

proceeding fully addresses the court’s

concerns regarding meaningful access to

alternative suppliers.548

We also addressed the court’s concern

that the method of recovery in that case

(a charge in the departing customer’s

transmission rate) might constitute an

anticompetitive tying arrangement. We

explained that the stranded cost

recovery procedure we prescribe in the

Open Access Rule is only a transitional

mechanism that is intended to enable

utilities to recover costs prudently

incurred under a different regulatory

regime. The purpose and effect of the

stranded cost recovery mechanism that

we approved in the Rule is to facilitate

the transition to competitive wholesale

power markets. We concluded that

while stranded cost recovery may

temporarily delay some of the benefits

of competitive bulk power markets for

some customers, such transition costs

must be addressed at an early stage if we

are to fulfill our regulatory

responsibilities in moving to

competitive markets.

In reaching these conclusions, the

Commission applied the traditional

regulatory concept of cost causation. We

stated that it is not an illegal tying

arrangement to hold a customer

accountable for the cost consequence of

leaving an incumbent supplier if, under

our rules, the incumbent supplier must

show a reasonable expectation of

providing continuing service to that

customer before it can recover stranded

costs from the customer.

In addition, in response to the Cajun

court and commenters in this

proceeding as to the need to provide as

much certainty as possible for departing

customers concerning their potential

stranded cost obligation, the

Commission included a formula for

calculating a departing customer’s

potential stranded cost obligation. We

explained that the revenues lost formula

is designed to provide certainty for

departing customers and to create

incentives for the parties to address

stranded cost claims between

themselves without resort to litigation.

Rehearing Requests Arguing That the

Commission Has Not Resolved the

Cajun Court’s Concerns

Several entities submit that the

Commission has not resolved the Cajun

court’s tying concerns. They argue that

tying arrangements are still the essence

of the stranded cost recovery method

mandated by Order No. 888, and that a

tying arrangement is a per se antitrust

violation that is not subject to

justification by reference to the reasons

for the restraint or the expected

ancillary benefits.549 A number of these

entities object that the Commission does

not address the court’s substantive

concern that a stranded cost provision is

the antithesis of competition.550 Several

object that the Commission brushes

aside the acknowledged anticompetitive

effects of the rule as being ‘‘transitional

only,’’ suggesting that short-term

anticompetitive impacts are acceptable

as long as the Commission is doing

something that will be good for

customers in the long term.551 They also

contend that the anticompetitive effects

would not be limited to a transitional

period, or that the transitional period

could last indefinitely, thereby diluting

or even nullifying the benefits of

competition for years to come.552

Several entities submit that the

Commission erred in concluding that

the stranded cost rules contained in

Order No. 888 would allow customers

‘‘meaningful’’ access to alternative

power suppliers.553 Among other things,

these entities contend that there is no

showing in the Order that transmission

providers will not continue to exercise

monopoly power over their

transmission systems and that

competition in generation will not be

stifled by the stranded cost recovery

mechanism.

Some entities also object that the

stranded cost procedures contained in

Order No. 888 fail to provide certainty

in the computation of recoverable

stranded costs. They argue that the

prospect of stranded cost liability and

related litigation add costs of potential

deal-killing magnitude to any power

supply acquisition considered by a

customer.554

APPA and ELCON challenge the

Commission’s description of Western

Resources, Inc. v. FERC555 as affirming

the Commission’s ability to allow

stranded cost recovery. APPA argues

that Western Resources does not justify

the stranded cost provisions of Order

No. 888 because it was a filed rate

doctrine case, not a stranded cost case.

APPA says that Western Resources

involved no consideration of any

allegation of anticompetitive conduct

and no allegation that the utilities’

proposal constituted an illegal tying

arrangement.

Commission Conclusion

We will deny the requests for

rehearing advanced on the basis of the

Cajun case. We disagree with those

entities that contend that the

Commission has not resolved the Cajun

court’s tying concerns. As an initial

matter, we note that the parties that

have raised this issue on rehearing

ignore the fact that while this

Commission has a responsibility to

consider the anticompetitive effects of

regulated aspects of interstate utility

operations,556 it has other statutory and

regulatory public interest considerations

which it must balance in order to engage

in reasoned decisionmaking. In this

proceeding, we have carefully balanced

our responsibilities to remedy undue

discrimination and to consider

anticompetitive effects, our goal to

eliminate market power of utilities and

anticompetitive effects in the long run,

and the need to provide a transition to

competitive markets that is fair, that

maintains a stable electric utility

industry, and that recognizes the

obligations incurred in a past, noncompetitive regulatory regime. As

discussed below, we do not believe that

the stranded cost proposal adopted in

the Rule results in an illegal tying

arrangement, as argued on rehearing.

We believe we have given reasoned

consideration to any potential transitory
12388 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

557 In contrast to the situation in Order No. 888,

the Cajun court did not have before it a generic,

Commission-imposed recovery mechanism for

distinguishing stranded costs associated with the

Commission’s ordering of industry-wide open

access from all uneconomic costs.

558See AGD, 824 F.2d at 1021.

559Cf. Eastman Kodak Company v. Image

Technical Services, Inc., 504 U.S. at 486–87 (Scalia,

J. dissenting) (‘‘Per se rules of antitrust illegality are

reserved for those situations where logic and

experience show that the risk of injury to

competition from the defendant’s behavior is so

pronounced that it is needless and wasteful to

conduct the usual judicial inquiry into the balance

between the behavior’s procompetitive benefits and

its anticompetitive costs.’’).

560 In effect, we recognize that we may have to

endure some short-term delay in the transition from

monopoly suppliers to competitive suppliers.

However, this is not anticompetitive; it is a

necessary part of a scheme that is procompetitive

overall. See American Gas Association v. FERC, 888

F.2d 136, 149 (D.C. Cir. 1989) (‘‘If conditioning

access is a necessary part of a scheme that is

procompetitive overall, however, then it does not

violate the NGPA [Natural Gas Policy Act] even if

it may seem to be anticompetitive when viewed in

isolation.’’).

561Eastman Kodak Company v. Image Technical

Services, 504 U.S. 451, 461 (1992).

562A ‘‘service’’ can constitute a ‘‘product’’ for

purposes of a tying analysis. See Eastman Kodak

Company v. Image Technical Services, Inc., 504

U.S. at 462.

563The Rule requires all transmission customers

to purchase at least some reactive supply and

voltage control service from the transmission

provider. However, the Commission found that the

cost of such services is ‘‘part of the cost of basic

transmission service.’’ FERC Stats. & Regs. at

31,706; mimeo at 209. That is, it is a necessary part

of providing the service and thus, by definition, not

a ‘‘tying.’’

anticompetitive effects of our stranded

cost policy and that we have met the

directives of the court in Cajun.

In considering the Cajun decision, it

is important to note that the Cajun court

assumes the presence of a competitive

market in the electric utility industry,

but such a competitive market does not

now exist. Instead, the Commission is in

the process of trying to bring about a

competitive market and to manage the

transition thereto.557 When the

Commission undertook a similar

restructuring in the gas industry, the

D.C. Circuit invalidated the

Commission’s efforts precisely because

the Commission had failed to deal with

the stranded cost problem in a

satisfactory manner.558

As we indicated in Order No. 888, we

do not believe it is an illegal tying

arrangement to hold a customer

accountable for the consequences of

leaving an incumbent supplier if, before

the incumbent supplier can recover

legitimate, prudent and verifiable

stranded costs from the departing

customer, it must show that it incurred

costs to provide service to the customer

based on a reasonable expectation of

continuing to serve the customer. Order

No. 888 provides no guarantee of

stranded cost recovery. Moreover, Order

No. 888 provides the opportunity to

recover stranded costs only for a

discrete set of wholesale requirements

contracts—those executed on or before

July 11, 1994 that do not contain an exit

fee or other explicit stranded cost

provision—and for retail-turnedwholesale customers. Thus, it is not

necessarily the case that customers will

have to pay stranded costs when they

leave their current suppliers. To the

contrary, before a utility can recover

stranded costs from a customer, the

utility must overcome certain

evidentiary hurdles (including a

rebuttable presumption of no reasonable

expectation of continuing service if the

contract contains a notice of termination

provision). Particularly given the

narrowly tailored circumstances under

which stranded cost recovery is

permissible under the Rule, we do not

view it as the antithesis of competition.

We dismiss as misplaced the claims

that Order No. 888’s stranded cost

recovery mechanism is a tying

arrangement that is a per se antitrust

violation that cannot be justified by

reference to the reasons for the restraint

or the expected ancillary benefits. Any

‘‘tying’’ that might result from the Rule

is by regulatory order, not through

monopoly power, and is justified as a

means to avoid unfair cost shifting and

to achieve the pro-competitive benefits

of the Rule. As we stated in Order No.

888, the purpose and effect of the

stranded cost recovery mechanism that

we approve are to facilitate the

transition to competitive wholesale

power markets, not to prevent a

generation customer of a utility from

being able to reach alternative suppliers

through its former supplier’s

transmission.559

To be sure, imposing a stranded cost

charge might, in the short run, make

some customers indifferent to whether

they stay with their current suppliers

and avoid stranded costs, or go with

new suppliers but pay stranded costs to

the former suppliers.560 There is no

question that, without the stranded cost

recovery mechanism, some customers

would be far more likely to switch to

lower-cost suppliers and enjoy sooner

the benefits of a competitive power

market. But, as detailed in Order No.

888, such an approach may result in

higher costs for other customers. We

thus have had to balance the potential

for earlier benefits for some customers

against other public interest

considerations, most particularly the

need to provide a fair mechanism by

which utilities can recover the costs of

past investments under traditional

regulatory concepts of prudently

incurred costs and cost causation. The

result is not to deny competitive

advantages, but only to delay their full

realization for some customers.

In any event, we do not believe that

the Commission-imposed mechanism of

allowing the utility to recover stranded

costs from the departing customer

through its transmission rates falls

within the category of an illegal tying

arrangement under the antitrust laws.

As the Supreme Court has defined it,

‘‘[a] tying arrangement is ‘an agreement

by a party to sell one product but only

on the condition that the buyer also

purchases a different (or tied) product,

or at least agrees that he will not

purchase that product from any other

supplier.’’’ 561

Here there is no ‘‘tying’’ of

‘‘products.’’ 562 Instead, the Rule

provides a mechanism for recovering

costs associated with a prior contract.

We have not adopted a rule under

which a customer may purchase

transmission from a utility only on the

condition that the customer also

purchases a different product, namely,

power, from the utility.563 To the

contrary, the Commission, through the

Order No. 888 open access transmission

requirement, is attempting to provide

the customer with the opportunity to

obtain unbundled transmission from a

former supplying utility as a means to

reach a new generation supplier.

Whatever else, the stranded costs are

not charges for ‘‘products’’ and thus

there is no ‘‘tying’’ in the conventional

sense. At best, there is only a condition:

in obtaining unbundled transmission,

the customer must also pay appropriate

costs stranded by its use of Commissionrequired transmission access.

Finally, it is not clear how often

departing customers will be obligated to

pay stranded costs. Stranded cost

recovery is by no means guaranteed

under the Rule, nor is it clear what

portion of a utility’s uneconomic

investment will be recoverable as

stranded costs. Even when a utility is

able to meet the evidentiary standard

and the Commission approves

imposition of a stranded cost charge, the

customer is free to pay off its obligation

immediately. If it chooses to pay off the

stranded cost obligation over time, that

charge would not be imposed

indefinitely on the customer. We have

limited the scope of contracts and costs

for which utilities may seek stranded

cost recovery. This limitation—to

certain contracts and demonstrated

costs—in our judgment fairly allocates

between utility and customer the
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12389

564Such tariff is a condition, but not the sole

condition, for market-based rates. See, e.g.,

Delmarva Power & Light Company, et al., 76 FERC

¶ 61,331 (1996); accord Southern Company

Services, Inc., 71 FERC ¶ 61,392 at 62,536 (1995);

Heartland Energy Services, Inc., et al., 68 FERC

¶ 61,223 at 62,059–60 (1994).

565A seller requesting market-based rates is not

required to demonstrate any lack of generation

market power with respect to sales from capacity

for which construction commenced on or after the

effective date (July 9, 1996) of the Rule. 18 CFR

35.27(a). However, if specific evidence is presented

by an intervenor that a seller requesting marketbased rates for sales from new generating capacity

nevertheless has generation dominance, the

Commission will evaluate whether the seller has

generation dominance with respect to the new

capacity. FERC Stats. & Regs. at 31,657; mimeo at

65–66.

566See FERC Stats. & Regs. at 31,797–800; mimeo

at 477–85.

567Under the revenues lost approach, a

customer’s stranded cost obligation is calculated by

subtracting the competitive market value of the

power the customer would have purchased (on an

average annual basis) from the average annual

revenues that the customer would have paid had it

remained on the utility’s generation system, and

multiplying the result by the period of time the

utility reasonably could have expected to serve the

customer beyond the contract termination but for

the open access required under Order No. 888. See

FERC Stats. & Regs. at 31,839–45 for a detailed

explanation of the various components of the

formula.

568FERC Stats. & Regs. at 31,841; mimeo at

600–01.

569FERC Stats. & Regs. at 31,793; mimeo at

464–65.

570 88 F.3d at 1129, 1182–83.

571We defined ‘‘exit fee’’ as the charge that will

be payable by a departing generation customer upon

the termination of its requirements contract with a

utility (if the utility is able to demonstrate that it

reasonably expected to continue serving the

customer beyond the term of the contract), whether

payable in a lump-sum payment or an amortization

of a lump-sum payment. (The same charge also can

be paid as a surcharge on the customer’s

transmission rate.)

572FERC Stats. & Regs. at 31,797–800; mimeo at

477–85.

burdens and benefits of open access

transmission.

Nor is it true that the Rule does not

allow customers ‘‘meaningful’’ access to

alternative power suppliers. The Final

Rule pro forma tariff contains terms and

conditions ensuring the provision of

non-discriminatory transmission

service. The requirements that a public

utility take service under its own tariff

for wholesale sales and purchases,

adopt a non-discriminatory

transmission information network, and

separate power marketing and

transmission functions further ensure

non-discrimination and remove

constraints to fair competition. The

result is meaningful access to alternative

suppliers that goes far beyond what was

offered in the transmission tariff under

review in Cajun.

Contrary to the claims of some, the

Open Access Rule does not guarantee

that a utility may sell its power at

market-based rates. The open access

compliance tariff required by Order No.

888 does mitigate transmission market

power.564 However, the Commission’s

Rule does not generically grant marketbased rate authority to utilities that file

compliance tariffs. Utilities must still

demonstrate on a case-by-case basis that

they not only have mitigated

transmission market power but also do

not have market power in generation 565

or other barriers to entry.

Notwithstanding the objections by

some commenters that the stranded cost

procedures of Order No. 888 fail to

provide certainty in the computation of

stranded cost charges, we believe that

directly assigning stranded costs to

departing generation customers using

the revenues lost formula is the fairest

and most efficient way to balance the

competing interests of those involved.

The alternatives that we considered (an

up-front broad-based approach or an asrealized broad-based approach) have

significant disadvantages and are

extensively discussed in Order No.

888.566 Following a careful evaluation of

the alternatives, we concluded that a

revenues lost formula to calculate a

customer’s stranded cost obligation is

more reasonable and provides greater

certainty than would other approaches,

such as those that rely on broad-based

surcharge schemes that impose costs

that may never be incurred or those that

result in widely fluctuating

transmission rates.567 As we stated in

Order No. 888, while we recognize that

some commenters oppose the revenues

lost approach as imprecise, any

ratemaking method that relies on

estimates will be subject to forecasting

error.568 Nevertheless, we have gone to

great lengths to provide specificity with

respect to the calculation of the

components of the formula.

In response to those commenters that

argue that Order No. 888’s stranded cost

procedures will add costs of potential

deal-killing magnitude to any power

supply acquisition considered by a

customer, we believe that, to the

contrary, use of the formula will narrow

the scope of disputes over the

calculation of stranded costs, lend

precision to the stranded cost amount it

produces, and provide certainty to

departing generation customers with

respect to their stranded cost

obligations.

APPA and ELCON object to the

Commission’s reference to Western

Resources as a case affirming the

Commission’s ability to allow stranded

cost recovery. Notwithstanding their

efforts to distinguish Western Resources

(for example, as a filed rate doctrine

case, not a stranded cost case, and as a

case involving no allegation of

anticompetitive conduct), they have

failed to make a convincing argument

that our description of that case as

‘‘confirm[ing] the validity of

Commission-imposed stranded cost

recovery mechanisms in the transition

to competitive markets’’ 569 is not

accurate. The case depends upon the

validity of the Commission’s decision to

allow the recovery of costs stranded in

the transition of the natural gas industry

to a competitive market and supports

the Commission’s ability to allow

stranded cost recovery in general. The

same court, in United Distribution

Companies, has recently confirmed the

Commission’s ability to allow the

recovery of costs stranded in the

transition to competitive markets,

limiting its concerns to issues about

‘‘how’’ stranded costs should be

recovered and from whom.570

3. Responsibility for Wholesale

Stranded Costs (Whether To Adopt

Direct Assignment to Departing

Customers)

In Order No. 888, the Commission

concluded that direct assignment of

stranded costs to the departing

wholesale generation customer through

either an exit fee 571 or a surcharge on

transmission is the appropriate method

for recovery of such costs. We

concluded that the departing generation

customer (and not the remaining

generation or transmission customers or

shareholders) should bear the legitimate

and prudent obligations that the utility

undertook on that customer’s behalf. In

reaching this decision, we carefully

weighed the arguments supporting

direct assignment of stranded costs

against those supporting the broadbased approach of spreading stranded

costs to all transmission users of a

utility’s system. After a detailed review

of the advantages and disadvantages of

each approach, we concluded that, on

balance, direct assignment is the

preferable approach for both legal and

policy reasons.572 Our primary

considerations were that direct

assignment is consistent with the wellestablished principle that the one who

has caused a cost to be incurred should

pay that cost and that it will result in

a more accurate determination of a

utility’s stranded costs than would an

up-front, broad-based transmission

surcharge.

The Commission also acknowledged

that the direct assignment approach

adopted in Order No. 888 is different

from the approach taken for the natural
12390 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

573FERC Stats. & Regs. at 31,800–802; mimeo at

485–90.

574FERC Stats. & Regs. at 31,802–03; mimeo at

490–92.

575E.g., ELCON, IL Industrials, San Francisco,

Nucor. Other entities that urge the Commission to

require shareholders to shoulder a portion of the

utility’s stranded costs include Central Illinois

Light, AR Com, American Forest & Paper, Nucor,

and Occidental Chemical. American Forest & Paper

and Nucor suggest that full recovery destroys

incentives to mitigate. Several entities also support

spreading the costs to all of the utility’s customers.

E.g., American Forest & Paper, Central Illinois

Light, AR Com.

576 IL Industrials at 4–6 (citing Order No. 888,

mimeo at 491–92).

577FERC Stats. & Regs. at 31,802; mimeo at 490.

578NASUCA cites in support of its position

Covington & Lexington Turnpike Road Company v.

Sandford, 164 U.S. 578 (1896); Market Street

Railway Company v. Railroad Commission, 324

U.S. 548 (1945) (Market Street); Duquesne Light

Company v. Barasch, 488 U.S. 299, 315–16 (1989).

579NASUCA cites in support of its position New

England Power Company, 8 FERC ¶ 61,054 (1979),

aff’d sub nom. NEPCO Municipal Rate Committee

v. FERC, 668 F.2d 1327 (D.C. Cir. 1981), cert.

denied, 457 U.S. 1117 (1982). NASUCA states that

in that case, prudently incurred plant investment

was abandoned because changing circumstances

rendered the investment uneconomic; the

Commission provided for a ten-year amortization of

the plant investment, with no return on the

unamortized balance. NASUCA says that this

precedent demonstrates that the ‘‘regulatory

compact’’ does not require full cost recovery.

580E.g., Central Illinois Light, Occidental

Chemical.

581FERC Stats. & Regs. at 31,802; mimeo at 491.

582Occidental Chemical argues that requiring gas

customers to choose their suppliers during an open

season enabled the pipelines to place a dollar value

on their take-or-pay obligations. Shippers thus

knew at the outset what their gas supply

realignment (GSR) surcharge would be and could

negotiate with other suppliers accordingly.

Occidental Chemical says that most pipelines have

already recouped their GSR costs and have made

the transition to a competitive supply market in

under three years. It argues that, on the other hand,

allowing electric stranded costs to be recovered

over an indefinite period will blunt the procompetitive effect of Order No. 888.

583Central Illinois Light supports a recovery

mechanism that would allow utilities to allocate

stranded costs to requirements customers on a

demand basis and to all transmission customers on

a commodity basis. It argues that this would

recognize the greater cost responsibility of

requirements customers, recognize the benefits

obtained by all transmission customers from open

access, and reduce the charges to all customers to

a more reasonable level.

584We will accept this pleading as a motion for

reconsideration, not as a request for rehearing,

because it was not filed within the 30-day statutory

period for rehearing requests. See 16 U.S.C.

§ 825l(a).

gas industry. We explained why we

believe that difference to be justified by

pointing out a number of differences

between the transition of the electric

industry to an open transmission access,

competitive industry and the transition

of the natural gas industry to open

access transportation service by

interstate natural gas pipelines.573 We

also declined to require a utility seeking

stranded cost recovery to shoulder a

portion of its stranded costs on the basis

that such a requirement would be a

major deviation from the traditional

principle that a utility should have a

reasonable opportunity to recover its

prudently incurred costs, and explained

why we applied a different approach in

the gas area.574

Rehearing Requests Opposing Full

Recovery From Departing Customers

A number of entities submit that the

Commission has not adequately

explained its decision not to require

some utility sharing of stranded costs

when the utility can satisfy the

reasonable expectation criteria. They

object that the Commission did not

meaningfully consider the arguments

made by commenters concerning utility

responsibility (such as poor

management decisions) for stranded

costs.575

ELCON argues that departing

customers are not the sole cause of

stranded costs. IL Industrials submits

that the statement in the Rule that

utility shareholders ‘‘’had no

responsibility for causing the legitimate,

prudent and verifiable costs to be

incurred’’’ is untrue.576 It argues that

although utilities may have had a legal

obligation to serve and meet projected

demands, how the utility chose to meet

those obligations was under the utility’s

control. IL Industrials asserts that

shareholders should bear some of the

risk associated with the decisions of

their management that were less than

optimal. At a minimum, IL Industrials

argues that the Commission should

consider on a case-by-case basis (when

it determines whether a utility has

incurred legitimate and verifiable

stranded costs) whether some amount of

stranded costs should be shared with

shareholders.

NASUCA challenges the

Commission’s statement in Order No.

888 that requiring a utility to shoulder

a portion of its stranded costs ‘‘would be

a major deviation from the traditional

principle that a utility should have a

reasonable opportunity to recover its

prudently incurred costs.’’ 577 It

contends that there is no

constitutionally guaranteed right of

recovery of all prudent investment.578

NASUCA further asserts that full

recovery of uneconomic investment is

not the norm. It submits that the

Commission has rejected utility

demands for full recovery of cancelled

electric generation facilities.579

San Francisco cites Market Street as

support for the proposition that the risk

of unmarketability should fall, in whole

or in part, on utility shareholders who

knew of competitive risks and who have

been compensated for those risks

through rates of return.

A number of parties object that the

Commission, in declining to require

some shareholder sharing of stranded

costs, is allowing the electric utility

industry to claim more generous

recoveries under Order No. 888 than it

allowed the gas industry, and that it has

provided no adequate rationale for this

difference in treatment.580 San Francisco

states that although the Rule attempts to

distinguish shareholder sharing in the

natural gas industry ‘‘as an

extraordinary measure given the nature

of the take-or-pay problem and the

prevailing environment at that time,’’ 581

the Commission has not identified how

the nature of the take-or-pay problem

was any more ‘‘extraordinary’’ than the

nature of stranded costs in electric

restructuring, or explain its reference to

‘‘the prevailing environment at that

time.’’

Occidental Chemical submits that the

Commission’s decision not to allocate a

portion of stranded costs to utilities on

cost causation grounds contradicts the

Commission’s actions in Order No. 636,

in which it required interruptible and

new shippers, as beneficiaries of open

access, to share in the costs of the

transition.582 Central Illinois Light states

that the Commission should allow

partial recovery of stranded costs and

thereby correct key differences in the

Commission’s responses to gas and

electric transition costs.583

Occidental Chemical also objects that

the Commission failed to address the

merits of its suggestion that the

Commission grant a utility a

presumption of prudence in return for

absorbing a percentage of its stranded

costs.

ELCON, in a supplement to its

rehearing request,584 submits that the

D.C. Circuit’s remand in United

Distribution Companies of the aspect of

Order No. 636 that allocated 100 percent

of gas supply realignment costs to

customers and none to pipelines has

implications for the Commission’s

decision in Order No. 888 to allocate

100 percent of stranded costs to

departing customers without any

shareholder sharing of the costs. ELCON

suggests that although the D.C. Circuit

indicated that a finding of threat to the

financial viability of the pipeline sector

might justify such allocation, there is no

evidence in the record in the Order No.

888 proceeding, and the Commission

has made no finding, that wholesale

stranded cost recovery jeopardizes the

financial viability of the utility sector. It
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12391

585FERC Stats. & Regs. at 31,802; mimeo at 

490–91.

586 In response to ELCON’s argument that it is not

clear how departing wholesale customers who

signed contracts in 1985 could have ‘‘caused’’

utilities to incur uneconomic assets such as

expensive nuclear facilities that were planned and

ordered in the 1970s, we note that customers taking

requirements service generally pay an allocated

share of total embedded costs, including the cost of

investments made before the customer began

service. This pricing principle is consistent with the

method that Order No. 888 adopts for calculating

a departing customer’s stranded cost obligation. The

revenues lost approach is not an asset-by-asset

approach. Instead, it is an approach that looks at a

utility’s current rates, which are based on all the

utility’s assets, which may include both high cost

and low cost generating facilities of various ages,

and relies on the presumption that the fixed costs

allocated to departing customers under their current

rates are properly assignable to them. Thus, if a

utility is able to demonstrate that it had a

reasonable expectation of continuing to serve the

customer after the contract term, the customer’s

stranded cost obligation would be computed based

on the average annual revenues that the customer

would have paid had it remained a customer of the

utility; the calculation of stranded costs would not

be tied to any particular investments that the utility

made in a particular unit. As we explain in Section

IV.J.9 below, the use of present annual revenues as

the basis for the stranded cost calculation is based,

among other things, on the presumption that

present rates include all just and reasonable costs

of providing service. 587FERC Stats. & Regs. at 31,850; mimeo at 626.

588Whether poor management decisions or other

actions are imprudent would be decided on a caseby-case basis. See, e.g., New England Power

Company, Opinion No. 231, 31 FERC ¶ 61,047 at

61,081–84, reh’g denied, Opinion No. 231–A, 32

FERC ¶ 61,112 (1985), aff’d sub nom., Violet v.

FERC, 800 F.2d 280 (1st Cir. 1986); Minnesota

Power & Light Company, Opinion No. 86, 11 FERC

¶ 61,312 at 61,644–45, order on reh’g, 12 FERC

¶ 61,264 (1980). However, a utility’s costs are

presumed prudent and a person challenging such

costs would have the burden of going forward with

evidence that raises a serious doubt as to prudence.

Id., 11 FERC at 61,645.

589See, e.g., Maryland v. Louisiana, 451 U.S. 725,

748 (1981); Office of Consumers’ Counsel v. FERC,

914 F.2d 290, 292 (D.C. Cir. 1990); City of New

Orleans, Louisiana v. FERC, 67 F.3d 947, 954 (1st

Cir. 1995).

590See New England Power Company, Opinion

No. 295, 42 FERC ¶ 61,016, reh’g denied in part and

granted in part, Opinion No. 295–A, 43 FERC

¶ 61,285 (1988). We note that the Supreme Court

case on which NASUCA relies to support its

argument that there is no constitutionally

guaranteed right of recovery of all prudent

investment, Duquesne, also involved electrical

generating facilities that were planned but never

built. See 488 U.S. 299 (1989).

591See Yankee Atomic Electric Company,

Opinion No. 390, 67 FERC ¶ 61,318, (Yankee

Atomic), reh’g denied, 68 FERC ¶ 61,364 (1994),

remanded on other grounds, Town of Norwood,

Massachusetts v. FERC, 80 F.3d 526 (D.C. Cir.

1996), offer of settlement accepted, letter dated

January 30, 1997, Docket No. ER92–592–005. This

case involved a nuclear plant that had been in

operation for over 30 years. In affirming the

Commission’s decision to allow full recovery and

not to apply Opinion No. 295’s recovery rule for

Continued

adds that, to the extent the Commission

relies on strict cost causation principles

in Order No. 888, it is not clear how

departing wholesale customers who

signed contracts in 1985 could have

‘‘caused’’ utilities to incur uneconomic

assets such as expensive nuclear

facilities that were planned and ordered

in the 1970s.

Commission Conclusion

As we explained in Order No. 888, we

decided not to require a utility meeting

the requirements for stranded cost

recovery to shoulder a portion of its

stranded costs because such a

requirement would be a major deviation

from the traditional principle that a

utility should have a reasonable

opportunity to recover its prudently

incurred costs.585 Our decision (which

allows assignment of legitimate, prudent

and verifiable stranded costs to

departing requirements generation

customers, not to shareholders or other

customers of the utility) also follows the

cost causation principle that has been

fundamental to our regulation since

1935.586 It is important, in this regard,

to distinguish between assuring

recovery of all uneconomic costs (which

Order No. 888 does not do) and

providing an opportunity for recovery

where the evidentiary requirements of

the Rule are met.

Allowing full recovery of stranded

costs under Order No. 888 is not

equivalent to allowing 100 percent

recovery of the costs of all uneconomic

assets. A utility may have uneconomic

assets for a variety of reasons, including

a decline in load, customer shifts to

natural gas, customer energy

conservation, loss of a large industrial

customer, customer self-generation, and

a customer gaining transmission access

through another utility’s transmission

system. The Rule does not provide for

the recovery of the costs of such

uneconomic assets.

Instead, the Rule defines a discrete set

of uneconomic costs that are stranded

by FPA section 211 or Order No. 888

transmission service (when a customer

uses the former supplying utility’s

transmission system to reach a new

supplier) for which utilities may seek

recovery. However, even as to this set of

costs the Rule does not guarantee 100

percent recovery. To be eligible to

recover such costs, a utility must satisfy

the reasonable expectation test set forth

in Order No. 888. Even then, the utility

will be eligible to recover only costs that

are legitimate, prudent and verifiable.

In response to those entities that argue

that departing customers are not the sole

cause of stranded costs and that poor

management decisions may be partly to

blame, we reiterate that a determination

that a utility has a reasonable

expectation of continuing to serve a

customer would not, in all

circumstances, mean that costs incurred

by the utility were prudent. As we said

in Order No. 888, we cannot make a

blanket assumption that all claimed

stranded costs were prudently incurred.

We explained that prudence of costs,

depending upon the facts in a specific

case, may include different things, such

as prudence in operation and

maintenance of a plant, and the utility’s

ongoing obligation to exercise prudence

in retaining existing investments and

power purchase contracts and in

entering into new ones.587 We clarified,

however, that we do not intend to

relitigate the prudence of costs

previously recovered.

Thus, to the extent that costs have not

been previously recovered by a utility,

and depending upon the facts

presented, a customer from whom a

utility is seeking to recover stranded

costs may be able to challenge the

prudence of those costs. If such

prudence challenge is successful, then

the utility would not be entitled to

recovery of the imprudently incurred

costs, through stranded cost recovery or

otherwise. We believe that this fully

addresses the concerns of those entities

that contend that departing customers

should not be responsible for costs that

result from poor management decisions

or other actions by the utility.588

As we explained in Order No. 888,

our decision not to require utilities to

shoulder a portion of their stranded

costs is based on the traditional

principle that a utility should have a

reasonable opportunity to recover its

prudently incurred costs. 589 NASUCA’s

reliance on the Commission’s cancelled

plant policy to support its argument that

full recovery of uneconomic investment

is not the norm is misplaced. The

Commission’s cancelled plant policy,

which allows a utility to recover 50

percent of its prudently-incurred

investment in a cancelled or abandoned

plant, relates only to plants that are

cancelled or abandoned prior to

entering commercial service and thus

prior to becoming used and useful.590

The Commission has taken a different

approach in the case of electric

generating plants that are prematurely

shut down after having been in

commercial operation for a number of

years. In the latter instance (which more

closely resembles the type of costs for

which a utility might seek recovery

under Order No. 888 than does the

cancelled plant before operation

scenario), the Commission has allowed

100 percent recovery of prudentlyincurred unamortized investment.591
12392 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

plants abandoned before operation, the court

explained:

Although ratepayers generally ‘bear the expense

of depreciation’ and although investors generally

‘are entitled to recoup from consumers the full

amount of their investment in depreciable assets

devoted to public service,’ [citations omitted]

Opinion No. 295 makes a logical exception to this

full recovery rule for plants abandoned before

operation; in such cases, ratepayers have not

benefitted from the plant. The situation here is

quite different. Because customers have benefitted

from the operation of the plant for over 30 years,

and because ceasing plant operations will benefit

customers by lowering rates, such an exception is

unwarranted. Moreover, applying Opinion No.

295’s recovery rule would not, as it would in the

case of a plant that never began operations, promote

economic efficiency.’’ 80 F.3d at 532.

In Yankee Atomic, the Commission also allowed

recovery of 100 percent of construction work in

progress and of post-shutdown O&M expenditures.

592Order No. 500–H, Regulations Preambles

1986–1990, FERC Stats. & Regs. ¶ 30,867 at 31,509

(1989).

593 Id. at 31,509–10.

594 Id. at 31,513.

595 Id.

596Regulatory Treatment of Payments Made in

Lieu of Take-or-Pay Obligations, Regulations

Preambles 1982–85, FERC Stats. & Regs. ¶ 30,637 at

31,301 (1985).

597 In Order No. 500–H, the Commission found

that, although pipelines incurred total take-or-pay

exposure over the period January 1, 1983 through

June 30, 1987 of over $24 billion, they made takeor-pay payments totalling only $.7 billion. Order

No. 500–H, Regulations Preambles 1986–1990

¶ 30,867 at 31,514.

598Regulatory Treatment of Payments Made in

Lieu of Take-or-Pay Obligations, Regulations

Preambles 1982–85, FERC Stats. & Regs. ¶ 30,637

(1985). 599 968 F.2d 1295, 1301 (D.C. Cir. 1992).

San Francisco’s and NASUCA’s

reliance on Market Street is also

distinguishable. That case involved an

industry (street railway) that had been

rendered economically obsolete by

market forces. The electric industry

today, in contrast, is clearly not

obsolete. Moreover, the costs that Order

No. 888 gives a utility an opportunity to

recover even in the face of market forces

would not become stranded but for

statutory and regulatory changes.

A number of parties contend that the

Commission has not provided an

adequate rationale for its different

treatment of shareholder sharing in the

natural gas industry. ELCON also relies

on the D.C. Circuit’s remand in United

Distribution Companies of Order No.

636’s holding that pipelines could

recover 100 percent of their gas supply

realignment (GSR) costs. After further

review of this matter in light of the

Court’s decision in United Distribution

Companies, we reaffirm that, even

though the Commission permitted

pipelines to recover take-or-pay costs

based on ‘‘cost spreading’’ and ‘‘value of

service’’ principles, stranded electric

utility costs should be recovered based

on traditional cost causation principles.

This is because, despite the fact that

both sets of costs are incurred in

connection with a transition to

unbundled, open access service, there

are also substantial differences between

the circumstances surrounding the two

industries’ incurrence of their respective

transition costs.

The pipelines’ take-or-pay problems

began before the Commission initiated

open access transportation in Order No.

436. The severe gas shortages of the

1970s led to enactment of the Natural

Gas Policy Act (NGPA), which initiated

a phased decontrol of most new gas

prices and established ceiling prices for

controlled gas, including incentive

prices for price-controlled new gas

higher than the ceiling prices previously

established by the Commission under

the NGA.592 To avoid future shortages,

pipelines then entered into long-term

take-or-pay contracts at the high prices

made possible by the NGPA, and those

high prices stimulated producers to

greatly increase exploration and

drilling.593 When demand unexpectedly

fell and supply increased, the pipelines

found themselves contractually bound

to take or pay for high-priced gas which

they could not sell. Even before Order

No. 436 issued in October 1985,

pipeline take-or-pay exposure was

approaching $10 billion.594 In 1986, as

pipelines were just beginning to

implement open access transportation

under Order No. 436 and before the

August 1987 issuance of Order No. 500,

the pipelines’ outstanding unresolved

take-or-pay liabilities peaked at $10.7

billion.595

The Commission and the industry had

never previously faced a take-or-pay

problem of this nature or magnitude. In

earlier times, pipelines had made takeor-pay payments to particular

producers, and the Commission had a

policy of permitting such payments to

be included in rate base and then

recovered as a gas cost when the

pipeline later took the gas under makeup provisions in the contract.596 By

1983, however, the pipelines could not

manage their take-or-pay problems, and

stopped honoring the bulk of their takeor-pay liabilities.597 They then sought

settlements with the producers to

reform or terminate the uneconomic

take-or-pay contracts and to resolve

outstanding take-or-pay liabilities.

Because pipelines had never previously

incurred significant take-or-pay

settlement costs, the Commission had

no policy concerning whether and how

pipelines were to recover those costs.

The Commission commenced

establishing such a policy in an April

1985 policy statement,598 just six

months before Order No. 436. When

Order No. 500 issued, few take-or-pay

settlement costs had yet been included

in pipelines’ rates. However, since the

pipelines’ outstanding take-or-pay

liabilities were in the neighborhood of

$10 billion, it was clear that pipelines

would incur massive costs in their

settlements with producers.

In short, when the Commission first

addressed the issue of how to allocate

take-or-pay settlement costs in Order

No. 500, it did so under the shadow of

the pipelines’ vast outstanding take-orpay exposure. The essential problem,

therefore, was to decide which

customers’ rates should be raised to

reflect the billions of dollars of take-orpay settlement costs that the pipelines

were incurring, but that the pipelines

had still not filed to recover. To have

allocated those costs solely to any one

segment of the industry would have

imposed a crushing new burden on that

segment. For example, if the

Commission had allocated the take-orpay settlement costs entirely to bundled

sales customers who chose to convert to

transportation-only service, those

customers would have ended up far

worse off than if they remained as

bundled sales customers.

As a result of all these facts, the

fundamental premise of Order No. 500

was, as the Court expressed it in KN

Energy, that ‘‘the extraordinary nature of

this problem requires the aid of the

entire industry to solve it.’’ 599 In order

to accomplish this result, Order No. 500

established an equitable sharing

mechanism for pipelines to use in

recovering their take-or-pay settlement

costs as an alternative to recovery

through their commodity sales rates.

Relying on ‘‘cost spreading’’ and ‘‘value

of service’’ principles, the Commission

permitted pipelines to allocate their

take-or-pay settlement costs among all

the pipelines’ customers. The

Commission also required the pipelines

using the equitable sharing mechanism

to absorb a portion of the costs in return

for the ability to recover an equal

portion through a fixed charge.

Importantly, pipelines using the

equitable sharing mechanism and

agreeing to absorb a portion of the costs

were given a presumption that their

take-or-pay settlement costs were

prudent. Those who did not choose to

avail themselves of the sharing/

absorption mechanism could still file

for recovery of take-or-pay costs

pursuant to the traditional ratemaking

methodology. Because the pipelines’

cash flow problems were so severe and

they could not reasonably expect to

recover their costs through their sales
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12393

600By contrast, Order No. 888 does not provide

a presumption of prudence for utilities’ stranded

cost recovery proposals. Once again, the more

traditional concept that the utility must prove costs

were prudently incurred will apply.

601The Court did not review the Order No. 500/

528 requirement that pipelines absorb a share of the

take-or-pay costs. See AGA v. FERC, 888 F.2d 136,

152 (D.C. Cir. 1989), and AGA v. FERC, 912 F.2d

1496, 1519 (D.C. Cir. 1990), cert. denied, 498 U.S.

1084 (1991), both holding the absorption

requirement not ripe for review.

602KN Energy, 968 F.2d at 1301.

603 Id. at 1302.

604FERC Stats. & Regs. at 31,664; mimeo at 84. 605See, e.g., AGD, 824 F.2d at 1026.

606United Distribution Companies, 88 F.3d at

1189.

607Order No. 528–A, 54 FERC ¶ 61,095 at 61,303–

05 (1991).

rates, they readily availed themselves of

the special mechanism, with its

presumption of prudence, rather than

the more protracted traditional

ratemaking option.600

The Court in KN Energy upheld the

Commission’s use of cost spreading in

connection with the allocation of takeor-pay costs among a pipeline’s open

access customers.601 The Court held that

‘‘the ratemaking rationales of Order No.

500 can be reconciled with the NGA,

given the unusual circumstances

surrounding the take-or-pay problem,

and the limited nature—both in time

and scope—of the Commission’s

departure from the cost-causation

principle.’’ 602 The Court emphasized

that ‘‘[w]e hold only—and quite

narrowly—that in the context of Order

No. 500 the Commission has not

betrayed its obligations to the NGA or

precedent by employing these

ratemaking principles in its attempt to

bring closure to the take-or-pay

drama.’’ 603

The unusual circumstances that

justified the departure from cost

causation principles in Order Nos. 500/

528 are not present in the electric

industry. In Order No. 888’s discussion

of the Commission’s decision not to

order any generic abrogation of existing

requirements and transmission contracts

between electric utilities and their

customers, we have already pointed out:

At the time the Commission addressed this

situation in the natural gas industry, it was

faced with shrinking natural gas markets,

statutory escalations in natural gas prices

under the Natural Gas Policy Act, and

increased production of gas. In other words,

there was a market failure in the industry.

* * * In contrast, there is no such market

failure in the electric industry.[604]

The electric utility costs potentially

stranded by Order No. 888 are fixed

costs arising from the utility’s electric

generation business, including, for

example, depreciation expense

associated with the utilities’ own

generation facilities and a return on the

original cost of its investment in those

facilities. They also include costs

associated with mandatory QF purchase

contracts. Unlike take-or-pay settlement

costs, these costs are not an

extraordinary expense that the

Commission has never previously

encountered. Rather, the stranded

electric costs that are subject to the

direct assignment provisions of Order

No. 888 are ordinary costs that have

always been, and are currently,

included in the utility’s rates for electric

generation approved by the

Commission. And there is no preexisting industry-wide market failure.

Thus, we are not confronted at the start

of the electric open access program with

a vast outstanding cost not currently

reflected in the electric utilities’ rates, as

we were at the start of the natural gas

open access program.

Therefore, unlike the situation with

the natural gas industry, stranded

electric utility costs can be allocated

among customers based upon traditional

cost causation principles without

imposing inequitable and unreasonable

burdens on particular customer classes.

Direct assignment to departing

requirements generation customers

through the stranded cost recovery

mechanism contained in the Rule is

consistent with the traditional cost

causation principle because it

recognizes the link between the

incurrence of stranded costs and the

decision of a particular generation

customer to use open access

transmission on the utility’s system to

leave the utility’s generation system and

shop for power, and bases the utility’s

ability to recover stranded costs on its

ability to demonstrate that it incurred

costs with the reasonable expectation

that the customer would remain on its

generation system beyond the term of

the contract. The stranded costs are

measured as the difference between

revenues the utility would have

recovered from the customer and the

market value of the utility’s power.

In essence, therefore, all that the

direct assignment provisions of Order

No. 888 require is that certain customers

(those whom a utility is able to

demonstrate it reasonably expected to

continue serving beyond the contract

term) who convert to transmission-only

service continue, for a period, to bear

certain generation costs that they were

previously bearing. This helps to

minimize immediate cost shifts to the

remaining generation customers, and is

thus consistent with the Court’s

concerns in AGD about cost shifts due

to open access transportation.605 At the

same time, it does not impose any

crushing new burden on the converting

generation customers, as would have

happened if in the natural gas industry

the Commission had allocated the takeor-pay settlement costs entirely to

pipeline sales customers who converted

to transportation-only service.

On the issue of utility absorption of

stranded costs, as ELCON points out,

the D.C. Circuit in United Distribution

Companies remanded Order No. 636 to

the Commission for further explanation

as to why the Commission had

exempted pipelines from sharing in

Order No. 636 GSR costs in light of: (1)

Its reliance on ‘‘cost spreading’’ and

‘‘value of service’’ principles in

allocating GSR costs among the

pipelines’ customers, and (2) the

absorption requirement in Order Nos.

500/528. As the Court explained:

If the Commission intends to assign GSR

costs according to these ‘cost spreading’ and

‘value of service’ principles, it must do so

consistently or explain the rationale for

proceeding in another manner. We approved

the invocation of those principles in KN

Energy because FERC had concluded that the

take-or-pay crisis could be resolved only by

spreading costs throughout the ‘entire

industry’ 968 F.2d at 1301 (emphasis added),

and because we recognized that ‘all segments

of the industry’ * * * will benefit, id.

(emphasis added), from restructuring.[606]

For the reasons discussed above and

in Order No. 888, we have chosen to use

traditional cost causation principles

both in allocating stranded electric costs

to certain electric utility customers and

in finding that the utilities should be

given an opportunity for full recovery of

certain legitimate, prudent, and

verifiable stranded costs. Thus, Order

No. 888 does not present the issue of

whether the Commission inconsistently

applied ratemaking principles to the

recovery of stranded costs that was of

concern to the court in United

Distribution Companies when it

remanded the analogous portion of

Order No. 636.

Moreover, based on the facts

summarized above, the Commission

concludes that the rationale we used to

support the Order Nos. 500/528

absorption requirement is not valid for

electric utility costs stranded by Order

No. 888. Order No. 528–A, where the

Commission gave its fullest justification

for that absorption requirement, did not

rely on either the ‘‘cost spreading’’ or

‘‘value of service’’ rationales to support

the absorption requirement.607 Order

Nos. 500/528 consistently recognized

that the Commission must ‘‘provide a

pipeline a reasonable opportunity to
12394 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

608Order No. 500–H, Regulations Preambles

1986–1990, FERC Stats. & Regs. at 31,575. Those

orders permitted all pipelines to seek full recovery

of their take-or-pay settlement costs through their

sales commodity rates. The Commission required

pipelines to absorb a share of their Order No. 500/

528 take-or-pay costs only if they chose to use the

alternative, equitable sharing recovery mechanism.

609Order No. 528–A, 54 FERC at 61,303–05.

610A number of entities (e.g., VT DPS, Valero,

Occidental Chemical) challenge the Commission’s

suggestion that, after Order No. 436, many of the

former bundled sales customers of the pipeline had

departed. To the extent that Order No. 888

suggested that many pipelines’ sales customers had

terminated their sales service before Order No. 636

issued, we note that, as the Commission indicated

in Order No. 636, pipeline sales constituted less

than 20 percent of total annual throughput on major

pipelines. FERC Stats. & Regs. ¶30,939 at 30,400.

However, the Commission also found that in 1991

over 60 percent of peak day capacity on major

pipelines that made bundled sales was reserved for

pipeline firm sales service. Id. at 30,399. Thus, we

clarify that although on an annual basis customers

were buying most of their gas from other suppliers,

pipelines were making significant sales of gas,

particularly on peak days.

611El Paso Natural Gas Company, 72 FERC

¶61,083 (1995) (El Paso).

recover its prudently incurred costs.’’ 608

However, Order No. 528–A reasoned

that, because the take-or-pay problem

was caused more by general market

conditions than by any regulatory action

of the Commission, it was appropriate to

require the pipelines to share in the

losses arising from those market

conditions as a condition to using the

alternative recovery mechanism.609

In these circumstances, the

Commission concludes that it would not

be reasonable to require electric utilities

to bear costs that, unlike the Order Nos.

500/528 take-or-pay costs, arise as the

direct result of Congress’ and the

Commission’s change in the regulatory

regime through FPA section 211 and

Order No. 888. This is particularly the

case since the electric utilities’ potential

stranded costs relate to large capital

expenditures or long-term contractual

commitments (some mandated by

federal law) to buy power made many

years ago in reliance on the preexisting

regulatory regime.

Moreover, in a separate order, the

Commission is responding to the United

Distribution Companies remand by

reaffirming the policy established in

Order No. 636 that pipelines should be

permitted full recovery of their

prudently incurred GSR costs. In that

order, the Commission finds that the

rationale Order No. 528–A used to

support the Order Nos. 500/528

absorption requirement is inapplicable

to GSR costs. The remand order

explains that, in the face of

extraordinary market conditions, Order

Nos. 500/528 adopted extraordinary

measures. However, as we are finding

here with respect to stranded electric

utility costs, the remand order holds

that the extraordinary market

circumstances that gave rise to the

requirement for pipeline absorption of

gas supply costs in Order Nos. 500/528

were not present at the time of Order

No. 636. Even before the Commission

initiated open access transportation in

Order No. 436, the market was

preventing pipelines from recovering

costs incurred under their take-or-pay

contracts. The Order Nos. 500/528

absorption requirement reflected the

preexisting effect of the market, which

would have required absorption even

without open access transportation

under Order No. 436. The remand order

finds that, contrary to the situation

when Order No. 436 issued, at the time

of Order No. 636, pipelines were

generally able to take gas under their

few remaining high-priced take-or-pay

contracts from the late 1970s and early

1980s and were no longer accumulating

significant additional take-or-pay

obligations. This was because the

pipelines were still performing a

significant sales service and had

reformed most of their uneconomic

take-or-pay contracts.610

The remand order accordingly holds

that the Commission’s regulatory

actions in Order No. 636 have caused

the pipelines to incur the GSR costs.

This is particularly the case because

Order No. 636 required the pipelines to

unbundle their natural gas and

transportation sales and forbade the

pipelines from making sales unless they

were made by a separate sales or

marketing entity. Order No. 888 also

requires generation or commodity sales

to be unbundled from sales of

transmission. In these circumstances,

traditional ratemaking principles

require the Commission to allow the

pipelines an opportunity to recover the

full amount of the expenses caused by

its actions. Thus, the Commission’s

approach to Order No. 636 GSR costs is

similar to its approach in Order No. 888

to stranded electric generation costs.

Rehearing Requests Citing Other

Inconsistencies Between Commission

Treatments of the Gas and Electric

Industries

VT DPS and Valero submit that Order

No. 888 does not satisfactorily

distinguish the Commission’s rejection

of gas pipelines’ attempts to impose exit

fees on departing customers. They argue

that the Commission opposed the

imposition of such exit fees in the gas

context as anticompetitive because it

would force customers desiring to

switch suppliers when their contracts

expired to pay the supply costs of both

the new and former suppliers.

VT DPS and Valero take issue with

the Commission’s attempt to distinguish

a recent El Paso case 611 as a ‘‘postrestructuring’’ case under Order No.

636. They contend that the Commission

consistently applied the same policy

(rejection of gas pipeline attempts to

impose exit fees) before restructuring

under Order No. 636. They further claim

that the Commission cannot articulate a

plausible basis for permitting utilities

with notice provisions to file for exit

fees, having denied El Paso’s proposal

outright without giving it an

opportunity to rebut the presumption.

VT DPS and Valero also state that the

‘‘stranded’’ costs for which the

Commission allowed recovery under

Order No. 636 were costs that would be

rendered unrecoverable because the

costs would not be incurred to provide

transportation service and because there

would be no wholesale load from which

to recover the costs. They indicate that

the Commission has held that such gas

costs are stranded only if rendered

unrecoverable as a direct result of the

restructuring required under Order No.

636. They submit that when a utility

loses wholesale load or a municipality

establishes a new distribution system

and the utility cannot resell the capacity

left unused, the utility’s costs are not

necessarily ‘‘stranded’’—i.e., rendered

unrecoverable—any more than if the

utility’s load declines because of

conservation, an economic downturn or

an increase in self-generation. They

argue that the Commission should limit

utility stranded cost claims solely to

those cases where the utility can

demonstrate that its costs have been

rendered unrecoverable as a direct

result of the Rule.

Commission Conclusion

We explained in Order No. 888 why

we disagree with the argument that the

Commission cannot impose an exit fee

to recover stranded costs because the

Commission did not allow gas pipelines

to do so. We noted that the Rule

establishes procedures for providing a

potential departing generation customer

advance notice (before it leaves its

existing supplier) of the stranded cost

charge (whether it is to be paid as an

exit fee or a transmission surcharge) that

will be applied if the customer decides

to buy power elsewhere and the

Commission decides the utility has

satisfied the stranded cost recovery

criteria of the Rule, e.g., the reasonable

expectation criterion. We indicated that

in the natural gas context, in contrast,

the Commission has prohibited
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12395

612FERC Stats. & Regs. at 31,802; mimeo at 489.

613Transwestern Pipeline Company, 44 FERC ¶

61,164 at 61,536 (1988) (Transwestern).

614El Paso Natural Gas Company, 47 FERC ¶

61,108 at 61,314, reh’g denied, 48 FERC ¶ 61,202

(1989).

615Order No. 500, Regulations Preambles (1986–

1990), FERC Stats. & Regs. ¶30,761 at 30,793–94

(1987).

616CPUC v. FERC, 988 F.2d 154, 168 (D.C. Cir.

1993), quoting, Transwestern Pipeline Company, 55

FERC ¶61,157 at 61,509 (1991).

617Transwestern, 44 FERC at 61,536. The 1989 El

Paso order cited by VT DPS and Valero (47 FERC

¶61,108) reiterated the policy established in

Transwestern concerning exit fees in the context of

GICs. The El Paso order is distinguishable from our

approach to exit fees in Order No. 888 for the same

reasons as Transwestern.

618Natural Gas Pipe Line Company, 46 FERC

¶ 61,335 at 62,013 (‘‘Consistent with the court’s

holding in AGD, that Part 284 transportation and

CD conversion must be accompanied by take-or-pay

relief, the Commission finds that a pipeline’s sales

customers who convert to transportation must

continue to be liable for the take-or-pay costs

allocated to them without regard to the fact that

they are no longer sales customers but only

transportation customers.’’), reh’g denied, 47 FERC

¶61,247 (1989); Transwestern Pipeline Company,

65 FERC ¶61,060 at 61,473 (1993), reh’g denied, 66

FERC ¶61,287 at 61,827–828 (1994), aff’d sub nom.

Western Resources, Inc. v. FERC, 72 F.3d 147 (D.C.

Cir. 1996).

619Transwestern Pipeline Company, 64 FERC

¶61,145 at 62,166 (1993), reh’g denied, 66 FERC

¶61,287 (1994). However, as illustrated by the

situation described in the cited Transwestern order,

some sales customers had departed altogether from

the systems of their historical pipeline suppliers

before the Commission recognized the need for

continued allocation of Order No. 500 take-or-pay

costs to those customers. In these circumstances,

the filed rate doctrine prevented such continued

allocation.

620 72 FERC ¶61,083 (1995).

621 In Order Nos. 636–A and 636–B, the

Commission not only rejected exit fees where the

Continued

pipelines from developing and charging

an ‘‘exit fee’’ after a customer had

implemented its gas purchase decision,

noting that otherwise, the customer

would not know in advance the full cost

consequences of its nomination

decision.612

We continue to believe that the

Commission’s decisions concerning

natural gas pipeline exit fees, relied on

by VT DPS and Valero, are not

inconsistent with Order No. 888’s

limited approval of exit fees for the

recovery of certain stranded electric

utility costs. VT DPS and Valero point

first to two cases decided by the

Commission in 1988 and 1989 involving

Gas Inventory Charges (GICs) proposed

by Transwestern Pipeline Company

(Transwestern) 613 and El Paso Natural

Gas Company (El Paso) 614 pursuant to

our Order No. 500 policy statement.

However, those cases are not relevant

here, essentially because the exit fees at

issue in those cases were not designed

to recover costs arising from the

transition to open access transportation,

unlike the stranded electric utility costs

at issue here.

In the Transwestern case cited by VT

DPS and Valero, Transwestern included

in its proposal to implement a GIC a

request for permission to assess an exit

fee. The exit fee would have been

charged to its largest local distribution

company customer if that customer

initially chose to nominate purchases

under the GIC but then subsequently

reduced its nominations. The

Commission found the proposed exit fee

inconsistent with both (1) its policy that

GIC customers know in advance the full

cost consequences of their nomination

decisions and (2) its objective that

prices under the GIC be constrained by

market forces.

However, this holding was not

applicable to Transwestern’s recovery of

costs incurred as part of its transition to

open access transportation, since the

Commission did not intend the GIC as

a vehicle for recovery of such transition

costs. The GIC was intended solely as a

forward-looking charge that would

recover costs the pipeline would incur

in the future under its reformed, market

responsive gas supply contracts.615 The

Commission’s intent was that, before

implementing GICs, pipelines would

negotiate settlements of their existing

uneconomic take-or-pay contracts and

file to recover the resulting settlement

costs under the Order No. 500 equitable

sharing mechanism.616 Indeed, in the

Transwestern order cited by VT DPS

and Valero, the Commission suggested

that Transwestern postpone

implementation of its GIC until it had

renegotiated its supply contracts and

filed to recover the resulting costs under

the Order No. 500 equitable sharing

mechanism.617

That mechanism included a fixed

take-or-pay charge analogous to the

direct assignment provisions of Order

No. 888. The Commission permitted

pipelines to allocate to sales customers

who converted from sales to

transportation the same fixed take-orpay charge that those customers would

have been allocated had they not

converted.618 Moreover, in a later order

involving Transwestern’s recovery of

take-or-pay settlement costs under its

Order No. 500 equitable sharing

mechanism, the Commission expressly

held:

In appropriate circumstances, the

Commission may approve exit fees for

departing customers, either through a

condition on the abandonment of the

purchase obligation of customers subject to

the Commission’s jurisdiction or through

tariff language giving appropriate notice of

such a fee before the departure.[619]]

As discussed in the preceding section

of this order, the direct assignment

provisions of Order No. 888, in essence,

require that certain electric generation

customers who convert to transmissiononly service continue, for a period, to

bear certain generation costs that they

were previously bearing. That

requirement is similar to the

Commission’s requirement, in

connection with its Order No. 500

program, that pipeline sales customers

who convert to transportation-only

service continue to pay the same Order

No. 500 fixed take-or-pay charge as they

would have paid had they not

converted.

VT DPS and Valero also claim that

permitting electric utilities to recover

stranded generation costs through exit

fees to customers converting to

transmission-only service is

inconsistent with our 1995 order in El

Paso,620 rejecting that pipeline’s exit fee

proposal. We see no inconsistency. El

Paso proposed, several years after its

restructuring pursuant to Order No. 636,

to impose an exit fee on its firm

transportation customers who

terminated or reduced their firm

transportation service. The fee was

designed to require the departing firm

transportation customer to continue to

pay a portion of El Paso’s fixed

transmission costs for a period of time

after the customer’s departure. The fee

bore no relationship to El Paso’s prerestructuring merchant function, since it

was designed to recover El Paso’s costs

of performing open access

transportation service after its

restructuring.

In both Order No. 888 and this order,

we are acting consistently with El Paso.

Similar to our refusal in El Paso to

permit a pipeline to impose an exit fee

on customers departing its

transportation system altogether

(whether for all or a portion of their firm

service), so also here we are refusing to

permit electric utilities to recover

stranded costs from customers who

depart their transmission systems

altogether. We believe that, in that

situation, there is no direct nexus

between the customer’s departure (and

the stranding of costs) and Commissionrequired transmission access, since the

customer is not using its former

supplier’s open access tariff to reach an

alternative power supplier.

Order No. 888 thus permits an exit fee

only to electric generation customers

who, although they stop purchasing

power from the utility, become

transmission-only customers of the

former supplying utility.621 By contrast,
12396 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

customer left the system altogether, but also found

exit fees unnecessary for the recovery of GSR costs

in the circumstance in which a bundled sales

customer converts to transportation-only service.

See Order No. 636–B, 61 FERC ¶ 61,272 at 62,041

(1992). Exit fees were unnecessary in the latter

circumstance because under the Commission’s

method of allocating GSR costs to all firm

transportation customers based on their contract

demands, a former bundled sales customer would

pay the same GSR costs after terminating its sales

service (through the volumetric surcharge on

transportation) as it would if it had remained as a

sales customer.

622As we explained in Order No. 888, the

Commission did not treat a notice of termination

provision in El Paso’s contract as a conclusive

presumption that El Paso had no reasonable

expectation of continuing to serve certain

customers, as VT DPS and Valero contend. FERC

Stats. & Regs. at 31,802, note 639; mimeo at 489,

note 639. Instead, the July 1995 El Paso order

acknowledged that the April 1995 Supplemental

Stranded Cost NOPR had proposed that the

existence of a notice of termination provision in a

contract be treated as a ‘‘rebuttable’’ presumption of

no reasonable expectation. On that basis, the

Commission suggested in dicta that ‘‘[e]ven if the

rules proposed in [the Supplemental Stranded Cost]

NOPR were applied here [which they were not], El

Paso would have difficulty justifying’’ its exit fee

proposal under the NOPR’s reasonable expectation

standard given the existence of a notice of

termination provision in the contract. 72 FERC at

61,441 (emphasis added).

623Under their proposal, it appears that costs

would be ‘‘unrecoverable’’ only if there were no

wholesale load from which to recover the costs.

This would result in shifting costs to customers that

had no responsibility for causing them to be

incurred or for causing them to be stranded. In

Order No. 888, we rejected such an approach as

fundamentally unfair and as inconsistent with the

well-established principle of cost causation.

624 In support of this argument, they cite CPUC v.

FERC, 894 F.2d 1372, 1380–81 (D.C. Cir. 1990) as

standing for the proposition that, in a cost-based

transmission rate, there is no logical basis for

including gas-supply related expenses or savings in

the rates for customers who take only transmission

service. See also American Forest & Paper (no

justification for including excess generation costs in

transmission rates).

625E.g., TX Com, APPA, IN Consumer Counselor,

IN Consumers, PA Munis, AR Com, MO/KS Coms.

626E.g., APPA, PA Munis, IN Consumer

Counselor, IN Consumers.

627PA Munis at 28. PA Munis also argues that the

last sentence of section 212(a) makes it clear that

the ‘‘rates, charges * * * for transmission services

provided pursuant to an order under section 211

shall ensure that to the extent practicable, costs

incurred in providing the wholesale transmission

services, and properly allocable to the provision of

such services are recovered * * *. ’ ’’ (emphasis

added by PA Munis).

628See also IN Consumers, IN Consumer

Counselor.

629PA Munis cites in support the following

excerpt from House Report No. 102–474, Part I: This

section [211] also provides that FERC shall permit

the transmitting utility to recover all prudent costs

incurred in connection with providing transmission

services, plus a reasonable return on investment,

including an appropriate share of the costs of any

enlargement of transmission facilities necessary to

provide such service. H.R. Rep. No. 102–474, Part

I, 102d Cong., 2d Sess. 194 (1992), reprinted in 1992

U.S.C.C.A.N. 1959, 2017 (emphasis supplied by PA

Munis).

El Paso proposed an exit fee to

transmission customers terminating

their transmission service. In short, the

exit fee we have found acceptable in

Order No. 888 is related to the electric

utility’s pre-restructuring generation

service, unlike El Paso’s rejected exit

fee, which bore no relationship to El

Paso’s pre-restructuring merchant

service.622

Finally, VT DPS’s and Valero’s

comments concerning the Commission’s

treatment of Order No. 636 ‘‘stranded

costs’’ attempt to make distinctions that

do not make a difference for purposes of

the Commission’s treatment of Order

No. 888 stranded costs. We have

explained above that the electric

industry’s transition to an open

transmission access, competitive

industry is different in a number of

respects from the natural gas industry’s

transition to open access transportation

service by interstate natural gas

pipelines. We also have explained why

a different approach to recovery of

legitimate, prudent and verifiable

stranded costs in the electric industry is

justified. On this basis, the

Commission’s definition and treatment

of ‘‘stranded’’ costs under Order No. 636

need not dictate our definition and

treatment of stranded costs under Order

No. 888. In any event, in response to VT

DPS’s and Valero’s request that the

Commission limit utility stranded cost

claims solely to those cases where the

utility can demonstrate that its costs

have been rendered unrecoverable as a

direct result of the Rule,623 we note that

Order No. 888 does require a causal

nexus between the availability and use

of Commission-required transmission

access and the stranding of costs.

Rehearing Requests Opposing Recovery

of Stranded Costs in Transmission

Rates

VT DPS and Valero submit that

although the Commission has not

proposed to depart from cost-based

ratemaking methodologies in

establishing transmission rates, Order

No. 888 contravenes cost causation

principles by recovering generating

costs in transmission rates.624 They

argue that although the court in KN

Energy held that the Commission might

depart from strict cost-causation

principles to permit pipelines to recover

gas supply costs from transportation

customers in extraordinary

circumstances, the ‘‘extraordinary

circumstances’’ were that the pipelines

had no remaining sales customers and

thus were left with no vehicle for

recovering gas supply costs. On this

basis, the court approved a mechanism

under which gas supply costs were

spread over virtually all transmission

users. They describe as incongruous the

Commission’s claim in Order No. 888

that permitting direct assignment of

stranded power costs in a transmission

rate is a cost-based approach.

VT DPS and Valero further argue that

even if the Commission were inclined to

justify stranded cost recovery from

departing customers on non-cost

grounds, the Commission cannot show

that the circumstances justifying similar

cost recovery from gas pipeline

transportation customers exist at the

wholesale level in the electric industry

because: (1) unlike its approach to gas

pipelines, the Commission has not

proposed to allow existing wholesale

electric customers to get out of their

contracts early; (2) there is no industrywide problem; wholesale sales account

for only a small fraction of the total

business of regulated electric utilities,

while gas pipelines had virtually all

wholesale sales; and (3) direct

assignment of generating costs only to

departing customers is the antithesis of

the cost-spreading rationale that

provided the justification for the limited

departure from cost-causation principles

permitted in KN Energy. They contend

that, in any event, the Commission

cannot spread costs broadly even if they

are recovered from all transmission

customers because the largest users are

retail customers that would be exempt

from wholesale stranded cost

surcharges.

A number of other entities also

oppose the recovery of stranded

generation costs in transmission rates.625

Some of them contend that section

212(a) of the FPA limits the transmitting

utility to the recovery of transmissionrelated costs.626 PA Munis contends that

the plain language of section 212, as

amended by EPAct, limits the rates that

can be charged under a section 211

order to those ‘‘ ‘which permit the

recovery by such utility of all the costs

incurred in connection with the

transmission services and necessary

associated services * * * ’’’627 PA

Munis contends that Congress would

not have limited recovery to the costs

incurred in connection with the

transmission services and necessary

associated services if it had intended to

allow the transmission rates to include

part of a utility’s costs for unused

generation facilities completely

unrelated to the cost of the transmission

facilities.628 PA Munis asserts that the

legislative history of EPAct supports its

position that there is no authorization

for the Commission to include unused

generation costs as part of the

transmission costs that are allocable to

transmission under section 212.629
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12397

630They cite in support of this proposition

Farmers Union Central Exchange, Inc. v. FERC, 734

F.2d 1486 (D.C. Cir.), cert. denied, Williams Pipe

Line Company v. Farmers Union Central Exchange,

Inc., 469 U.S. 1034 (1984).

631 88 F.3d at 1188–89.

632Additionally, we note that a stranded cost

surcharge to transmission is merely a vehicle for

collecting the exit fee. The surcharge would be in

effect only until the stranded cost obligation is met.

It is not a component of the transmission rate in the

sense that a transmission customer who uses a very

large amount of transmission while the rate is in

effect would pay more than its stranded cost

obligation.

633See Pennsylvania Electric Company v. FERC,

11 F.3d 207 (D.C. Cir. 1993) (Penelec). As the

Commission explained, opportunity costs are the

actual costs that a utility incurs by providing

transmission service to a customer instead of using

the transmission itself to reduce its generation costs

on behalf of its native load (i.e., the foregone

economy energy transfers). Pennsylvania Electric

Company, 60 FERC ¶61,034 at 61,120, 61,126

(1992), aff’d, Penelec, 11 F.3d 207.

634Technically, the costs in the latter situation

were previously incurred as a result of investment

by the utility on behalf of the departing customer.

However, the costs are ‘‘incurred’’ in the sense of

becoming stranded when the customer leaves the

utility’s system. In both situations, recovery of the

costs is permitted through transmission rates in

order to keep the utility (and its other customers)

from unfairly suffering economic losses as a result

of providing transmission to others.

635Moreover, we note that, in addressing the

natural gas industry’s transition costs, the

Commission did rely on traditional cost causation

principles in approving pipeline proposals to

allocate fixed take-or-pay charges to sales customers

converting to transportation-only service. See

Transwestern Pipeline Company, 65 FERC ¶61,060

at 61,473 (1993), reh’g denied, 66 FERC ¶61,287 at

61,825–28 (1994). The Commission found that the

pipelines entered into their take-or-pay contracts to

serve their sales customers. The conversion of those

customers to open access transportation required

pipelines to enter into settlements with producers

to shed gas supplies. Therefore, there was a causal

connection between the customer’s conversion and

the pipeline’s incurrence of the take-or-pay

settlement costs. Here, there is a similar causal

connection between the stranding of generation

investment made on behalf of a wholesale customer

and that customer’s decision to use Commissionmandated open access transmission to reach a new

supplier.

636The case on which VT DPS and Valero rely,

CPUC v. FERC, involved the disposition of a

pipeline’s production-related deferred tax reserve

when the switch to NGPA pricing mooted

application of tax normalization (which sought to

match the timing of a customer’s contribution

toward a cost with enjoyment of any offsetting tax

benefit). The Commission’s decision not to credit

the deferred tax reserve to current users of the

pipeline’s transmission service was based, among

other things, on a determination that the deferred

tax fund was completely unrelated to the pipeline’s

transmission service. See 894 F.2d at 1378–80. In

contrast, as discussed below, the costs for which

this Rule provides an opportunity for recovery

would not have been stranded but for Commissionmandated transmission access.

637We also reject AR Com’s argument that the

Farmers Union case prohibits the Commission from

allowing the recovery of non-transmission costs in

a transmission rate in the limited circumstances

proposed in Order No. 888. The issues before the

court in that case are distinguishable from the

recovery of stranded generation costs in

transmission rates. Farmer’s Union involved the

court’s review of a Commission order establishing

maximum rate ceilings to be applied to oil pipelines

in which the Commission invoked non-cost factors

(the need to stimulate additional oil pipeline

capacity) as one reason for setting high maximum

rates. The use of non-cost factors was itself not at

issue. Rather, the court found that the Commission

had ‘‘failed to specify in any detail how ‘non-cost’

factors, such as the need to stimulate additional

pipeline capacity, might justify its decision to set

maximum rates at such high levels.’’ 734 F.2d at

1501. In Order No. 888, in contrast, the Commission

has fully explained the basis for giving utilities an

opportunity to recover stranded costs from

departing customers through a surcharge to the

customers’ transmission rates.

AR Com and MO/KS Coms argue that

the FPA does not allow the Commission

to include costs in a transmission rate

that are not caused by the provision of

transmission service.630 MO/KS Coms

contend that retail stranded costs are

largely generation costs that were not

caused by any request to use

transmission service or by any actual

transmission usage, and are not an

opportunity cost of providing

transmission service. Citing the

language in section 212 of the FPA

allowing the transmitting utility to

recover ‘‘all costs incurred in

connection with the transmission

services and necessary associated

services,’’ AR Com contends that

nowhere does the Energy Policy Act or

any other relevant statute authorize the

collection of retail, non-transmission

costs through transmission rates.

Commission Conclusion

We disagree with VT DPS’s and

Valero’s argument that Order No. 888

contravenes cost causation principles by

recovering generating costs in

transmission rates. As the court in

United Distribution Companies stated:

‘‘ ‘Cost causation’ correlates costs with

those customers for whom a service is

rendered or a cost is incurred.’’ 631

Whether stranded costs are recovered

through a surcharge on the transmission

rates of a departing generation customer,

or through an exit fee, the point is that

under Order No. 888 they are recovered

from the customer that caused them to

be incurred. The only distinction is the

mechanism by which they are recovered

from that customer.

The Commission is not aware of any

prohibition on permitting recovery

through a transmission rate of what has

traditionally been recovered through the

generation component of a rate, so long

as the utility does not double recover

and the customer does not pay more

than the costs that it caused to be

incurred.632 Indeed, the Commission has

been upheld in permitting opportunity

costs (foregone economic savings) to be

charged as a transmission rate when

they are higher than a traditional

embedded cost transmission rate.633

There is no significant difference

between an ‘‘opportunity cost’’

component of a transmission rate and a

stranded cost charge imposed through

transmission rates. Both concern the

recovery of generation costs. To be sure,

in the former case these generation costs

are incurred by reason of using high cost

generation instead of substituting lower

cost generation, and in the latter case

the costs are ‘‘incurred’’ by reason of the

loss of a customer.634 But, for purposes

of cost recovery, these are distinctions

without a difference. In both situations,

the transmission rate is used to recover

something other than the capital,

operating, and maintenance costs of

facilities used to provide the

transmission service at issue. If the

Commission were without authority to

provide for cost recovery of these other

types of costs in transmission rates, the

court would not have affirmed the

volumetric surcharge on transportation

in KN Energy, nor would it have

affirmed the opportunity cost charge in

Penelec.

As we note above, we are not

proposing a departure from strict costcausation principles such as that

allowed in KN Energy, where the

pipeline was allowed to recover 50

percent of its take-or-pay settlement

costs through a volumetric surcharge on

all transportation customers, including

those that had never purchased gas from

the pipeline.635 Because we disagree

with VT DPS’s and Valero’s position

that recovery of stranded costs through

a surcharge on transmission constitutes

recovery on non-cost grounds,636 we

will reject their requests for rehearing

on this issue.637

We also reject the argument that

section 212 of the FPA prohibits the

recovery of stranded generation costs in

transmission rates. There is nothing on

the face of the statute or in its legislative

history to support this position. In fact,

section 212(a) permits recovery of

‘‘legitimate, verifiable and economic

costs’’ of providing transmission

service. Stranded costs clearly are an

economic cost of providing transmission

when the stranding results from the

ordered transmission service. By

definition, the costs for which this Rule

provides an opportunity for recovery

would not have been stranded but for

Commission-mandated transmission

access. Stranded costs under this Rule

are the costs that a utility incurred to

provide service to a customer based on

a reasonable expectation that the utility

would continue to serve the customer

beyond the term of their contract, and

that become stranded when the

customer uses Commission-mandated
12398 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

638See note 633 supra.

639See Orange and Rockland Utilities, Inc., 76

FERC ¶ 61,037 (1996).

640FERC Stats. & Regs. at 31,804–06; mimeo at

497–501.

641FERC Stats. & Regs. at 31,805; mimeo at 497.

642E.g., TDU Systems, OH Consumers’ Counsel.

TDU Systems proposes that the Commission give a

requirements customer the choice of extending its

existing contract at existing rates for a period

corresponding to the customer’s expectation of

continued service or receiving a payment from the

utility consisting of the difference between what the

customer must pay for new supplies and what it

paid under the contract. TDU Systems describes the

latter option as a ‘‘benefits lost’’ approach modeled

after the ‘‘revenues lost’’ approach of Order No. 888.

643FERC Stats. & Regs. at 31,805; mimeo at 498

(emphasis added by OH Consumers’ Counsel).

transmission access to reach a new

generation supplier. In this respect,

stranded costs, like opportunity costs,638

are not costs associated with the actual

facilities used to provide transmission

service. Rather, they are an ‘‘economic

cost’’ of providing the transmission

service at issue.

4. Recovery of Stranded Costs

Associated With New Wholesale

Requirements Contracts

In Order No. 888, we concluded that

future wholesale requirements contracts

should explicitly address the mutual

obligations of the seller and buyer,

including the seller’s obligation to

continue to serve the buyer, if any, and

the buyer’s obligation, if any, if it

changes suppliers. This means that

utilities must address potential stranded

cost issues when negotiating new

contracts or be held strictly accountable

for the failure to do so.

We stated that we will allow recovery

of wholesale stranded costs associated

with any new requirements contract

(executed after July 11, 1994, or

extended or renegotiated to be effective

after July 11, 1994) only if explicit

stranded cost provisions are contained

in the contract. We defined ‘‘explicit

stranded cost provision’’ (for contracts

executed after July 11, 1994) as a

provision that identifies the specific

amount of stranded cost liability of the

customer(s) and a specific method for

calculating the stranded cost charge or

rate. However, for purposes of

requirements contracts executed after

July 11, 1994 but before May 10, 1996

(the date on which Order No. 888 was

published in the Federal Register), we

clarified that a provision that

specifically reserved the right to seek

stranded cost recovery consistent with

what the Commission permits in the

Final Rule (without identifying the

specific amount of stranded cost

liability of the customer(s) and

calculation method) nevertheless will be

deemed an ‘‘explicit stranded cost

provision.’’ On the other hand, a

provision in a requirements contract

executed after July 11, 1994 but before

May 10, 1996 that merely postpones the

issue of stranded cost recovery without

specifically providing for such recovery

will not be considered an ‘‘explicit

stranded cost provision.’’ We said that,

after May 10, 1996, a provision must

identify the specific amount of stranded

cost liability of the customer(s) and a

specific method for calculating the

stranded cost charge or rate in order to

constitute an ‘‘explicit stranded cost

provision.’’ 639

We also concluded that a

requirements contract that is extended

or renegotiated for an effective date after

July 11, 1994 becomes a ‘‘new’’

requirements contract for which

stranded cost recovery will be allowed

only if explicitly provided for in the

contract.

We decided not to impose a

regulatory obligation on wholesale

requirements suppliers to continue to

serve the power needs of their existing

requirements customers beyond the end

of the contract term. The only exception

to this would be if the customer decides

to remain a requirements customer for

the period for which the Commission

finds that the supplying utility

reasonably expected to continue serving

the customer. In such a case, the

supplying utility will be obligated to

offer continuing service to the

requirements customer for the period

the utility reasonably expected to

continue serving the customer.

We also decided to no longer require

prior notice of termination under

section 35.15 for any power sales

contract executed on or after July 9,

1996 (the effective date of the Final Rule

pro forma tariff) that is to terminate by

its own terms (such as on the contract’s

expiration date), but to require written

notification of the termination of such

contract within 30 days after

termination takes place. We said that we

will continue to require prior notice of

the proposed termination of any power

sales contract executed before July 9,

1996 (even if the contract is to terminate

by its own terms) as well as any

unexecuted power sales contract that

was filed before that date.

Further, we decided to retain the

section 35.15 filing requirement for all

transmission contracts because the

Commission must be assured that

transmission owners are not exerting

market power in negotiating or

terminating transmission contracts. This

filing requirement will provide the

customer an opportunity to notify the

Commission if the termination terms are

disputed or if the customer was not

given adequate opportunity to exercise

its limited right of first refusal under the

Final Rule (see Section IV.A.5).640

Requests for Rehearing

Utilities For Improved Transition asks

the Commission either to clarify that it

will enforce stranded cost provisions as

agreed to by the parties and accepted for

filing by the Commission (presumably

even if they do not meet the definition

of ‘‘explicit stranded cost provision’’

contained in the Preamble 641), or to

modify the definition contained in the

Preamble (and add the term to the list

of definitions in section 35.26(b)) to give

contracting parties the option of

specifying either a specific amount of

stranded cost liability or a formula for

calculating the stranded cost charge or

rate. Utilities For Improved Transition

contends that, particularly in the case of

long-term contracts, the parties may not

be able to quantify what the stranded

cost liability will be at the time they

enter into a contract.

Several entities assert that if the

Commission is to permit recovery for

stranded costs, it should include a

symmetrical mechanism to permit

customers with below-market rates or

net undervalued assets a means to

continue to receive power at belowmarket rates if the customer had a

reasonable expectation of continued

service.642 OH Consumers’ Counsel

objects that the only exception in Order

No. 888 to the Commission’s decision

not to impose a regulatory obligation on

a utility to continue to serve existing

requirements customers beyond the end

of the contract ‘‘would be if the

customer decides to remain a

requirements customer for the period for

which the Commission finds that the

supplying utility reasonably expected to

continue serving the customer.’’ 643

According to OH Consumers’ Counsel,

this language nullifies the customer’s

reasonable expectation of continuation

of service under its existing contractual

arrangement.

TDU Systems similarly says that the

Commission has not explained why the

suppliers’ expectations are to be

honored, but the customers’

expectations are not. TDU Systems

objects that the Commission failed to

explain why it rejected allowing

requirements customers to demonstrate

a reasonable expectation that they

would continue to be able to obtain

supplies of power at rates based on

embedded cost after the expiration of
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12399

644 If the customer under a contract has not

waived its rights to seek changes to the contract, it

may exercise its procedural rights under section 206

to show that failure to extend the contract at the

existing contract rate would not be just and

reasonable. If the customer has waived its rights to

challenge the contract (i.e., it is bound by a MobileSierra standard), it may exercise its rights under

section 206 to show that it would be contrary to the

public interest not to extend the contract at the

existing rate. Although OH Consumers’ Counsel

objects that a section 206 proceeding is an

inadequate remedy because it places the burden of

proof on the customer, we believe that it is

appropriate that the customer, as the complainant

in such a case, bear the burden of proof.

their supply contracts. TDU Systems

submits that the case for providing

extra-contractual relief to wholesale

purchasers is more compelling than the

case for providing extra-contractual

relief to wholesale suppliers. It argues

that it is likely that some cooperatives

and municipal utilities would not

survive the drastic impact to their

businesses that the elimination of costbased rates could bring.

OH Consumers’ Counsel submits that

the filing of a section 206 complaint by

customers of utilities with rates below

market does not provide adequate

protection or symmetry for the

customers. It contends that a section 206

case is an inadequate remedy because:

(1) the utility holds all of the necessary

information for analyzing such a case,

but the procedure shifts the burden of

proof from the utility to the customer;

and (2) it provides only delayed relief

for parties who could be irreparably

harmed by the imposition of the marketbased rates.

TDU Systems argues that eliminating

the prior notice of termination

requirement in section 35.15 for postJuly 9, 1996 wholesale requirements

contracts will result in discrimination

and monopolization. It contends that

the Commission closes its eyes to the

fact that termination of a requirements

contract can affect 100 percent of a

customer’s power supply, while it is

likely to affect less than 10 percent of a

large public utility’s load. It submits

that eliminating the prior notice of

termination requirement is tantamount

to finding that termination of all such

contracts by their terms will be just and

reasonable, but that no such finding can

presently be supported. TDU Systems

maintains that there remains significant

market power in the markets in which

transmission dependent utilities,

especially small transmission

dependent utilities, operate. It

recommends that the Commission use

section 35.15 to require that wholesale

contracts not be terminated unless such

termination is just and reasonable.

PA Munis objects that the

Commission did not specifically address

in Order No. 888 its proposal that

contracts approved after July 11, 1994

(but executed before that date) be

treated as new contracts. It submits that

under the Commission’s reasoning in

setting the July 11, 1994 cut-off date,

utilities that executed requirements

contracts after that date had no

reasonable expectation that they would

be permitted to recover costs by seeking

to amend the contract. It argues that the

same reasoning applies where the

contract was executed but not approved

or accepted by the Commission by the

July 11, 1994 notice date.

Commission Conclusion

We will clarify the definition of

‘‘explicit stranded cost provision’’ for

requirements contracts executed after

July 11, 1994. As long as the contracting

parties are in agreement, a provision in

a post-July 11, 1994 requirements

contract will be considered an ‘‘explicit

stranded cost provision’’ if it identifies

either the specific amount of stranded

cost liability of the customer or a

specific method for calculating the

stranded cost charge or rate.

We will reject the arguments of TDU

Systems and OH Consumers’ Counsel

that ‘‘symmetry’’ requires that the

Commission provide a generic

mechanism in this Rule to allow

existing requirements customers with

below-market rates a means to continue

to receive power beyond the contract

term at the pre-existing contract rate if

the customer had a reasonable

expectation of continued service. Unlike

the generic findings we have made with

respect to extra-contractual recovery of

stranded costs associated with

requirements contracts executed on or

before July 11, 1994, we do not have a

sufficient basis on which to make

generic findings that customers under

such contracts may be entitled to extend

a contract at the existing rate. Utilities’

expectations may have resulted in

millions of dollars of investments on

behalf of certain customers and the

possibility of shifting the costs of those

investments to other customers that did

not cause the costs to be incurred. In the

case of customers’ expectations,

however, even if customers generally

expected to stay on a supplier’s system

beyond the contract term, it is not likely

that most customers could have

expected to continue service at the

existing rate unless specified in the

contract. Moreover, the consequences of

customers’ expectations as a general

matter would not have the potential to

shift significant costs to other

customers.

Nevertheless, our conclusion that we

cannot make generic findings or provide

a generic formula for addressing this

issue does not mean that a customer

under a contract may not exercise its

procedural rights under section 206 to

show that the contract should be

extended at the existing contract rate,644

or to make such a showing in the

context of a utility’s proposed

termination of a contract pursuant to the

section 35.15 notice of termination

(approval) requirement, which we have

retained for power supply contracts

executed prior to July 9, 1996 (the

effective date of the Rule).

We believe that while the relationship

between utilities and their wholesale

requirements customers may have given

rise to an inference or expectation on

the part of the wholesale requirements

customer that the contract would

continue beyond the stated term, it is

not clear to what extent a customer

could demonstrate a reasonable

expectation that such continued service

would be at the existing contract rate

(which may be below the market price).

This is particularly the case for

contracts in which the utility has not

waived its unilateral right to make

section 205 filings to change the rates.

Even in contracts where rates were fixed

for the contract term, however, if the

utility were to agree to extend such a

contract for a new term, the rates under

that contract would not necessarily have

remained the same. On this basis, a

customer may be able to demonstrate

that it had a reasonable expectation of

continued service beyond the contract

term, but not necessarily at the same

rate level. It is for this reason that we

believe this issue must be addressed on

a case-by-case basis and that this Rule

is not the proper mechanism for

granting the relief sought by TDU

Systems and OH Consumers Counsel.

Nevertheless, we do not intend to

prejudge whether a requirements

customer could ever make a showing

that it reasonably expected service

beyond the contract term at the existing

contract price. Nor do we intend to

preclude a customer from attempting to

make such a showing in appropriate

circumstances.

We also believe that we adequately

addressed in Order No. 888 TDU

Systems’ argument that elimination of

the prior notice of termination

requirement in section 35.15 for postJuly 9, 1996, wholesale requirements

contracts will result in discrimination

and monopolization. As we stated in

Order No. 888, we believe that the

concerns of TDU Systems can be fully

addressed without retaining the section
12400 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

645FERC Stats. & Regs. at 31,809–814; mimeo at

510–24.

646We explained that if an existing requirements

contract includes an explicit provision for payment

of stranded costs or an exit fee, we will assume that

the parties intended the contract to cover the

contingency of the buyer leaving the system, and

we will reject a stranded cost amendment to such

a contract unless the contract permits renegotiation

of the existing stranded cost provision or the parties

to the contract mutually agree to a new stranded

cost provision. Similarly, we said that we will reject

a stranded cost amendment to an existing

requirements contract if the contract prohibits

stranded cost recovery (or precludes recovery for

termination or reduction of service) or prohibits

renegotiation of an existing stranded cost or exit fee

provision, unless the parties to the contract

mutually agree to a new stranded cost provision.

647See 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).

648As a complement to our finding that,

notwithstanding a Mobile-Sierra clause in an

existing requirements contract, it is in the public

interest to permit amendments to add stranded cost

provisions to such contracts if the public utility

proposing the amendment can meet the evidentiary

requirements of this Rule, we concluded that

customers under Mobile-Sierra contracts ought to

have the opportunity to demonstrate that their

contracts no longer are just and reasonable.

649Citing Motion Picture Association of America

v. Oman, 969 F.2d 1154 (1992); Bowen v.

Georgetown University Hospital, 488 U.S. 204

(1988).

35.15 prior notice of termination

requirement for post-July 9, 1996

contracts. While we have agreed to

provide for extra-contractual stranded

cost recovery as a transition matter, it is

our objective that, prospectively, parties

should address their mutual

expectations clearly through contract

terms that explicitly address the mutual

obligations of the seller and buyer at

contract expiration. This would include

the seller’s obligation to continue to

serve the buyer after contract expiration,

if any. If the customer believes that

termination of its contract at the end of

the term would not be just and

reasonable (or, in the case of a MobileSierra contract, would not be in the

public interest), it can file a complaint

with the Commission under section 206

of the FPA.

We will reject PA Munis’ request that

contracts approved after July 11, 1994

(but executed before that date) be

treated as ‘‘new’’ contracts for purposes

of stranded cost recovery because

modifying the notice date at this point

in the proceeding would work an

inequitable result. Beginning with the

initial stranded cost NOPR, the

Commission put entities on notice that

contracts ‘‘executed’’ on or before July

11, 1994 would constitute ‘‘existing’’

contracts. Although a utility arguably

could have amended such an existing

contract to include an explicit stranded

cost provision prior to its (post-July 11,

1994) approval by the Commission, the

NOPR did not require the utility to do

so. As a result, it would be unfair for the

Commission to change the cut-off terms

now.

5. Recovery of Stranded Costs

Associated With Existing Wholesale

Requirements Contracts

In Order No. 888,645 the Commission

concluded that it would permit utilities

the opportunity to seek recovery of

legitimate, prudent and verifiable

stranded costs for ‘‘existing’’ wholesale

requirements contracts (executed on or

before July 11, 1994) that do not already

contain exit fees or other explicit

stranded cost provisions.646 We

explained why we believe that July 11,

1994—the date on which the initial

Stranded Cost NOPR was published

and, thus, on which the industry was

put on notice of the proposal to disallow

prospectively extra-contractual recovery

of stranded costs—is the appropriate

date for distinguishing ‘‘existing’’

requirements contracts from ‘‘new’’

requirements contracts.

We noted our desire that utilities

attempt to renegotiate with their

customers existing requirements

contracts that do not contain exit fees or

other explicit stranded cost provisions.

If a contract is not renegotiated to add

such a provision, we explained that,

before the expiration of the contract: (1)

A public utility or its customer may file

a proposed stranded cost amendment to

the contract under sections 205 or 206;

or (2) a public utility in a section 205

proceeding, or a transmitting utility in

a section 211 proceeding, may file a

proposal to recover stranded costs

associated with any such existing

contract through its transmission rates

for a customer that uses the utility’s

transmission system to reach another

generation supplier.

We also concluded that, even if an

existing requirements contract contains

an explicit Mobile-Sierra 647 provision, it

is in the public interest to permit the

public utility to seek a unilateral

amendment to add stranded cost

provisions if the contract does not

already contain exit fees or other

explicit stranded cost provisions.648 We

explained why our determination that it

is in the public interest to give public

utilities a limited opportunity to

propose contract changes unilaterally to

address stranded costs if their contracts

do not already explicitly do so satisfies

the public interest standard of the

Mobile-Sierra doctrine. We also

indicated that customers with MobileSierra contracts that do not explicitly

address stranded costs may file

complaints under section 206 of the

FPA to propose to address stranded

costs in existing requirements contracts.

We concluded that a public utility or

its customer should be allowed to file a

proposed stranded cost amendment, or

a public utility or transmitting utility

should be allowed to file a proposal to

recover stranded costs through a

departing generation customer’s

transmission rates, at any time prior to

the expiration of the contract.

Rehearing Requests—July 11, 1994 CutOff Date

Utilities For Improved Transition,

repeating an argument raised in

previous comments in this proceeding,

objects to the Commission’s July 11,

1994 cut-off date for distinguishing

between ‘‘existing’’ and ‘‘new’’

requirements contracts. It argues that

stranded cost recovery should be

assured for all contracts executed before

the effective date of the Rule (i.e., July

9, 1996), not just those executed before

July 11, 1994. It asserts that parties to

contracts executed after July 11, 1994

but before July 9, 1996 should have the

same opportunity as parties to pre-July

11, 1994 contracts to offer evidence as

to their reasonable expectations.

Utilities For Improved Transition asserts

that agencies may not promulgate

retroactive rules without express

statutory authority,649 and that the FPA

does not give the Commission such

statutory authority.

Puget raises a somewhat different

point. It notes that the definition of a

‘‘new’’ requirements contract as ‘‘any

wholesale requirements contract * * *

extended or renegotiated to be effective

after July 11, 1994’’ (emphasis added)

was not proposed until March 29, 1995

(in the supplemental stranded cost

NOPR). Puget states that the initial

stranded cost NOPR proposed to give a

utility three years from the date of

Federal Register publication of the final

stranded cost rule to negotiate or to file

for stranded cost recovery. According to

Puget, the March 1995 supplemental

stranded cost NOPR proposed a

retroactive change by defining a contract

executed prior to July 11, 1994 but

extended or renegotiated to be effective

after that date as a ‘‘new’’ contract and

by removing the three-year window for

negotiating stranded cost recovery. By

this change, Puget argues that the

extension of a contract between the date

of Federal Register publication of the

initial NOPR (July 11, 1994) and the

issuance of the supplemental NOPR

(March 29, 1995) may have converted it

into a ‘‘new’’ rather than an ‘‘existing’’
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12401

650Puget notes that it executed a letter agreement

with the Port of Seattle on January 12, 1995 to

continue in place the terms of an existing contract

until February 2, 1996, or the execution of a new

agreement, whichever was earlier. It says that the

parties were working within the context of the

initial stranded cost NOPR, which would have

given Puget three years from the date of the

publication of the final rule to negotiate or file for

stranded cost recovery. However, based on the

definition of ‘‘new’’ contract in the Supplemental

NOPR, the extension of the Puget/Port of Seattle

contract may have converted it into a ‘‘new’’ rather

than an ‘‘existing’’ contract for stranded cost

recovery purposes. Puget states that it filed an

amendment to the contract on December 28, 1995,

that included stranded cost recovery provisions.

Those provisions are pending in Docket Nos. ER96–

714–000 and ER96–697–000. On January 10, 1997,

the presiding judge issued an Initial Decision in

Docket No. ER96–714–001 finding that Puget, by

executing the January 1995 letter agreement, had

not waived its eligibility to recover stranded costs.

See Puget Sound Power & Light Company, 78 FERC

¶ 63,001 (1997).

651As discussed in note 650, supra, the presiding

judge in Docket No. ER96–714–001 recently issued

an Initial Decision finding that Puget did not waive

its eligibility to recover stranded costs when it

entered into a January 1995 letter agreement with

the Port of Seattle extending the term of the parties’

25-year sales contract for up to one year to

accommodate further negotiations. Puget Sound

Power & Light Company, 78 FERC ¶ 63,001 (1997).

652See, e.g., ELCON, PA Munis, APPA.

653See also ELCON.

654 824 F.2d at 1019.

contract for stranded cost recovery

purposes. Puget asks the Commission to

revise the definition of ‘‘existing

wholesale requirements contract’’ in

Order No. 888 and 18 CFR 35.26 to

include contracts executed on or before

July 11, 1994 that were extended prior

to the issuance of the supplemental

stranded cost NOPR (March 29, 1995)

and for which stranded cost provisions

were filed with the Commission prior to

issuance of Order No. 888. Puget

submits that failure to do so would be

arbitrary and capricious and would

deprive utilities with such contracts of

adequate notice of a proposed rule.650

Commission Conclusion

We will reject Utilities For Improved

Transition’s rehearing request because

we believe that we adequately explained

in Order No. 888 why adoption of the

July 11, 1994 cut-off date is appropriate

and does not constitute retroactive

rulemaking. We said in Order No. 888

that because all parties were put on

notice in the initial stranded cost NOPR

that July 11, 1994 would be the operable

date for the ‘‘existing’’/‘‘new’’ contract

distinction, utilities that executed

requirements contracts after that date

could have had no reasonable

expectation that they would be

permitted to recover any costs extracontractually. Moreover, we explained

that because the costs at issue are extracontractual costs, the Commission’s

notice to all parties that contracts

executed after July 11, 1994 (the date

that the initial NOPR was published in

the Federal Register) will be enforced

by their terms as far as stranded cost

recovery is concerned does not

constitute ‘‘retroactive rulemaking.’’ The

Commission has merely put all parties

on notice that the opportunity for extracontractual stranded cost recovery

would not be available for any

requirements contracts executed after

July 11, 1994.

The July 11, 1994 date is appropriate

because it is the date on which all

interested parties were given notice in

the Federal Register that the

recoverability of stranded costs for

contracts executed on or before that date

that did not provide for such recovery

was at issue. The parties to

requirements contracts executed after

July 11, 1994 have been free to provide

for stranded cost recovery in the

contract, or not. The point is that, for

requirements contracts executed after

the cut-off date, stranded cost recovery

will be governed solely by the terms of

the contract.

We believe that Puget has raised a

valid point concerning the potential

impact of the Commission’s decision in

the March 29, 1995 supplemental

stranded cost NOPR to treat extensions

or renegotiations of existing contracts as

‘‘new’’ contracts for stranded cost

purposes on parties that extended or

renegotiated an existing contract prior to

March 29, 1995. However, we expect

that the situation described by Puget

may be an isolated instance. On this

basis, we do not believe it necessary to

modify the definition of ‘‘existing

wholesale requirements contracts’’ in

Order No. 888 and 18 CFR 35.26 as

requested by Puget. Nevertheless, we

clarify that we will consider on a caseby-case basis whether to waive the

provisions of 18 CFR 35.26 and to treat

a contract extended or renegotiated

(without adding a stranded cost

provision) to be effective after July 11,

1994 but before March 29, 1995 as an

existing contract for stranded cost

purposes.651

Rehearing Requests—Mobile-Sierra

Several entities challenge the

Commission’s generic Mobile-Sierra

public interest finding. According to

APPA, the Commission cannot make the

public interest determination in a

generic rulemaking, whether for

stranded cost or non-stranded cost

modifications.

A number of entities object that the

Commission does not identify any

utilities whose existence is jeopardized

without full wholesale stranded cost

recovery.652 PA Munis and APPA assert

that vague allegations of harm if utilities

do not recover stranded costs do not

satisfy the public interest standard

which they view to be ‘‘practically

insurmountable.’’ 653 American Forest &

Paper contends that there is not one fact

to support the Commission’s

assumption about threats to the

financial stability of the electric utility

industry. ELCON submits that

significant retail stranded cost exposure

does not justify the rule on wholesale

stranded cost recovery.

VT DPS and Valero submit that the

Commission has not explained how

allowing utilities to abrogate their

contracts to extract exit fees from former

customers vindicates any public

interest. They argue that even assuming

that wholesale customers depart en

mass, the customers can only do so as

their contracts expire; thus, the exodus,

if it occurs, will be a trickle, not a flood.

VT DPS and Valero maintain that even

if some utilities were put at risk, it

would not justify a generic rule. They

contend that based on AGD v. FERC,654

a generic solution is not proper for a

problem existing only in ‘‘isolated

pockets.’’

PA Munis submits that, even

assuming that the financial integrity of

some utilities may be threatened, the

missing link in the Commission’s logic

for a generic rule is that there is no

protection for customers having MobileSierra contracts with public utilities

that are not faced with financial

problems or cost shifting to third parties

as a result of the open access

requirements. PA Munis asserts that, at

a minimum, each utility having MobileSierra contracts should be required to

show on an individual basis that the

public interest standard has been

satisfied.

American Forest & Paper argues that

Order No. 888 is not made even-handed

by allowing requirements customers to

also challenge fixed-rate, fixed-term

contracts. It submits that letting a

customer file to amend a contract only

as long as that amendment also

addresses stranded costs is a ‘‘heads you

win, tails I lose’’ proposition for the

customer.

APPA and TDU Systems request

clarification of the scope of the

Commission’s decision to allow a utility

‘‘to seek modification of contracts that

may be beneficial to the customer’’ if the

customer is permitted to argue for

modification of existing contracts that

are less-favorable to it than other

generation alternatives. APPA expresses

concern that this language could be

interpreted to mean that once a
12402 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

655Northeast Utilities Service Company v. FERC,

55 F.3d 686 (1st Cir. 1995) (Northeast Utilities).

656See Order No. 888, FERC Stats. & Regs. at

31,679; mimeo at 127–28.

657Because the Commission’s public interest

finding only applies to utilities that would seek to

amend their contracts to add stranded cost

provisions (not to those that face no stranded cost

exposure and thus no need to amend their contracts

to add stranded cost provisions), we reject as

misplaced PA Munis’ claim that there is no

protection for customers having Mobile-Sierra

contracts with public utilities that are not faced

with financial problems or cost shifting to third

parties as a result of the open access requirements.

658As noted above, this finding applies only to

wholesale requirements contracts with MobileSierra clauses if the contracts were executed on or

before July 11, 1994 and do not contain an exit fee

or other explicit stranded cost provision.

customer seeks modification of stranded

cost provisions in an existing contract,

the utility may be able to challenge its

entire contract with the customer. If this

means the utility can modify contract

provisions unrelated to stranded costs,

APPA submits that the Commission has

failed to address the Mobile-Sierra

public interest issues associated with

modifying non-stranded cost provisions

in an existing contract. If not, APPA

contends that the Commission should

clarify the language. APPA objects that

the Commission has not placed any

limits on the types of modifications that

a selling utility can make, nor specified

the types of changes that it thinks a

utility will likely make. It states that the

Commission needs to explain why joint

modification by both the seller and the

purchaser can meet the public interest

standard. According to APPA, the

Commission has not explained the need

for symmetrical treatment of contracts

negotiated at a time when the

Commission has found that the

supplying public utilities were

exercising their monopoly over

transmission facilities in an unduly

discriminatory manner.

APPA also contends that the

Commission’s reliance on Northeast

Utilities 655 is misplaced because that

case involved the Commission’s review

of a newly-filed contract, as opposed to

subsequent review of a contract

previously accepted and approved by

the Commission. APPA further asserts

that Northeast Utilities involved an

affiliate transaction, whereas this

rulemaking is targeted at arm’s-length

agreements between unrelated selling

and purchasing utilities. According to

APPA, this rulemaking does not present

any of the concerns at issue in an

affiliate transaction, and the

Commission should have applied the

‘‘practically insurmountable’’ public

interest standard doctrine from Papago,

the classic ‘‘low-rate’’ case.

Commission Conclusion

We disagree with those entities that

argue that the Commission cannot make

the public interest determination in a

generic rulemaking. It is well

established that it is within the

Commission’s discretion to decide

whether we act through rule or through

case-by-case adjudications.656 As we

explained in Order No. 888, we believe

it is appropriate that our public interest

finding be made on a generic basis given

the fact that, by this Rule, we are

requiring full open access that could

significantly affect historical

relationships among traditional utilities

and their customers and the ability of

utilities to recover prudently incurred

costs.

At the same time, however, we are not

eliminating the need for case-by-case

demonstrations that stranded cost

recovery should be allowed. Our public

interest finding is that utilities be

permitted to seek extra-contractual

recovery of stranded costs in certain

defined circumstances and that they be

allowed to recover stranded costs only

if they make a case-specific

demonstration.

Our holding applies only to wholesale

requirements contracts (with MobileSierra clauses) executed on or before

July 11, 1994 that do not contain an exit

fee or other explicit stranded cost

provision. We will not permit

modification of any contract that

addresses the stranded cost issue

explicitly, unless the contract

specifically permits such modifications.

Instead, we are examining requirements

contracts that do not clearly address the

issue in the context of the traditional

regulatory regime under which they

were signed—a regulatory environment

in which it was assumed as a matter of

course that the great majority of

requirements customers would stay

with their original suppliers and that

these suppliers had a concomitant

obligation to plan to supply these

customers’ continuing needs.

Further, utilities with Mobile-Sierra

contracts that seek recovery of stranded

costs will have the burden, on a caseby-case basis, of showing they had a

reasonable expectation of continuing to

serve the departing generation customer.

Although we have decided on a generic

basis that it is in the public interest to

permit public utilities with MobileSierra contracts to make unilateral

filings, we are not automatically

approving any amendment that a

particular utility might file. If a public

utility unilaterally files a proposed

stranded cost amendment under either

section 205 or 206 of the FPA, this does

not necessarily mean that the

Commission will find it appropriate to

allow such amendment. In addition,

customers with Mobile-Sierra contracts

that do not explicitly address stranded

costs may also file complaints under

section 206 of the FPA to propose to

address stranded costs in existing

requirements contracts. The

Commission will analyze any proposed

stranded cost amendment to a MobileSierra contract, whether proposed by

the utility or by its customer, based on

the particular circumstances

surrounding that contract. Thus, the

case-by-case findings that some

commenters seek will, in effect, be made

when the Commission determines

whether to approve a proposed stranded

cost amendment to a particular

contract.657

Although several entities have raised

various challenges to the sufficiency of

the Commission’s public interest

finding, we believe that we have

satisfied the public interest standard by

showing how third parties may

ultimately bear the burden if public

utilities with Mobile-Sierra contracts are

not given any opportunity to propose

contract changes to address stranded

costs.658 As we explained in Order No.

888, if the Commission fails to give a

public utility this opportunity, and the

utility’s financial ability to continue the

provision of safe and reliable service is

impaired, third parties (customers

relying on the public utility for their

electric service) will be placed at risk.

Similarly, if the Commission fails to

give a public utility the opportunity to

directly assign costs to the customers on

whose behalf they were incurred, and

some of the utility’s customers leave the

utility’s generation system for that of

another supplier without paying such

costs, third parties (the utility’s

remaining customers) may be harmed by

having to bear costs that were not

incurred to serve them and that are

stranded by the other customers’

departures via open access

transmission. We believe that protective

action in the public interest is

particularly necessary where, as here, a

utility’s rates could become insufficient

because of fundamental changes in the

industry that largely result from

legislative or regulatory changes that

could not be anticipated.

In response to those entities that

contend that speculation of financial

jeopardy or generalized statements of

what may occur without reference to

particular public utilities is not

sufficient to satisfy the public interest

standard, we disagree. The Commission

need not make findings about particular

utilities because the Rule does not
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12403

659 824 F.2d at 1019.

660 Id. at 1019–20.

661We note that the fact that a contract may bind

a utility to a Mobile-Sierra standard does not mean

that the customer is also bound to that standard.

Unless a customer specifically waives its section

206 just and reasonable rights, the Commission

construes the issue in favor of the customer.

662 In situations in which a customer institutes a

section 206 proceeding to modify a contract that

binds the utility to a Mobile-Sierra standard, the

utility may make whatever arguments it wants

regarding any of the contract terms, including those

unrelated to stranded costs, but will be bound to a

Mobile-Sierra standard for contract terms that do

not relate to stranded costs.

663FERC Stats. & Regs. at 31,664, 31,813; mimeo

at 86, 521.

664FERC Stats. & Regs. at 31,814; mimeo at 522–

23.

award stranded costs—it simply sets out

generic criteria for determining recovery

in a particular case. If a utility does not

meet the criteria, there will be no

stranded cost recovery. The public

interest determination rests on the

obvious conclusion that the failure of a

utility to recover costs prudently

incurred and financed based on investor

expectation of traditional cost recovery

clearly adds regulatory risk that

investors reasonably did not expect.

VT DPS’s and Valero’s reliance on

AGD as support for the proposition that,

even if some utilities were put at risk,

a generic solution is not proper for a

problem existing only in ‘‘isolated

pockets’’ is misplaced. The AGD court

found that the Commission had not

adequately justified its decision to give

all bundled firm sales customers of a

pipeline that decided to offer service

under Order No. 436 the option to

reduce their contract demand by 100

percent. In noting the lack of support for

‘‘an industry-wide solution for a

problem that exists only in isolated

pockets,’’ the court expressed concern

that the remedy adopted by the

Commission (‘‘such drastic action as

100% CD reduction’’ 659) was too broad.

In Order No. 888, in contrast, the

Commission has determined that it is in

the public interest to give a limited class

of utilities—those that are parties to

wholesale requirements contracts that

were executed on or before July 11, 1994

that do not contain an exit fee or other

explicit stranded cost provision and that

contain Mobile-Sierra clauses—an

opportunity to seek to add a stranded

cost provision to the contract. Thus, the

narrow scope of the Commission’s

Mobile-Sierra public interest finding is

a far cry from the broad remedy (100

percent CD reduction) that the court

remanded in AGD. Indeed, it more

closely resembles the type of limited

generic action that the AGD court

suggested would be proper when it

stated: ‘‘This is not to say, of course,

that the Commission could not use

generic rules to identify a limited class

of LDCs to be entitled to reduce CD

when special conditions are present.’’660

We explained in Order No. 888 that

we were making two complementary

public interest findings. First, as

described above, is our decision that it

is in the public interest to permit public

utilities to seek stranded cost

amendments to existing requirements

contracts with Mobile-Sierra clauses.

Second, we found that a ‘‘party’’ to a

requirements contract containing a

Mobile-Sierra clause no longer will have

the burden of establishing

independently that it is in the public

interest to permit the modification of

such contract, but still will have the

burden of establishing that such

contract no longer is just and reasonable

and therefore ought to be modified. We

clarify that, in making this second

finding, our reference to a ‘‘party’’ to a

requirements contract containing a

Mobile-Sierra clause was directed at

modification of contract provisions by

customers.661 Additionally, this second

finding applies to any contract revisions

sought, whether or not they relate to

stranded costs.662

We also concluded that ‘‘if a customer

is permitted to argue for modification of

existing contracts that are less favorable

to it than other generation alternatives,

then the utility should be able to seek

modification of contracts that may be

beneficial to the customer.’’ 663 We

clarify in response to APPA and TDU

Systems that this statement was not

intended to imply that the Commission

had made Mobile-Sierra findings that

would permit utilities with MobileSierra contracts to seek non-stranded

cost amendments to contracts that may

be favorable to a customer, based on a

showing that the contracts are no longer

just and reasonable. Our Mobile-Sierra

findings as to public utility sellers apply

only when utilities seek to add stranded

cost provisions or make other

modifications related to stranded costs.

Thus, if a utility with a Mobile-Sierra

contract initiates a section 206

proceeding in which it seeks to modify

contract provisions that do not relate to

stranded costs, it will have to show that

it is contrary to the public interest not

to modify the contract.

As we stated in Order No. 888, the

most productive way to analyze contract

modification issues is to consider

simultaneously both the selling public

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

reasonable expectation of continuing to

serve the customer beyond the term of

the contract and the customer’s claim, if

any, that the contract no longer is just

and reasonable and therefore ought to be

modified. We said that if a customer

brings a claim in a section 206

proceeding to shorten or terminate a

contract, the selling public utility must

bring any stranded cost claim with

respect to that customer in that section

206 proceeding. Our goal is to ensure

that all of the issues expected to be

raised by the parties when a customer

departs a utility’s generation system can

be efficiently litigated in one

proceeding. Therefore, we have

similarly required that if the customer

intends to claim that the notice or

termination provision of its existing

requirements contract is unjust and

unreasonable, it must present that claim

in any proceeding brought by the selling

public utility to seek recovery of

stranded costs. We disagree with

American Forest & Paper’s argument

that it is a ‘‘no-win’’ situation if a

customer seeking to modify a contract

must present that claim in any stranded

cost proceeding brought by the selling

public utility. To the contrary,

providing the customer to a MobileSierra contract with the opportunity to

demonstrate that its contract is no

longer just and reasonable and that its

term should be shortened or eliminated

could be beneficial to the customer,

notwithstanding the customer’s

potential stranded cost obligation. As

we explained in the Rule:

[G]iven the industry circumstances now

facing us, both selling utilities and their

customers ought to have an opportunity to

make the case that their existing

requirements contracts ought to be modified.

By providing both buyers and sellers this

opportunity, the Commission attempts to

strike a reasonable balance of the interests of

all market participants.[664]]

In response to APPA’s analysis of

Northeast Utilities, it is true, as APPA

asserts, that Northeast Utilities involved

the Commission’s initial review of a

contract, not modification of a

previously accepted and approved

contract, and that the contract involved

an affiliate transaction, while this

rulemaking is targeted at arm’s-length

agreements. However, we do not believe

that these differences bear on the

precedential value of this case to the

circumstances presented in the Rule. To

the contrary, we believe that Northeast

Utilities provides valuable guidance

concerning application of the public

interest standard where, as here, a

failure to allow limited contract

modification may harm the public

interest by harming third parties.

We disagree with APPA’s contention

that the Commission should have

applied the ‘‘practically
12404 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

665APPA at 49. It should be noted that, as the

Northeast Utilities court indicated, the Papago

court’s description of the public interest standard

as ‘‘practically insurmountable’’ was dictum. 55

F.3d at 691. Further, Papago did not involve a

contractual arrangement for rate revision where the

parties ‘‘by broad waiver * * * eliminate both the

utility’s right to make immediately effective rate

changes under § 205 and the Commission’s power

to impose changes under § 206, except the

indefeasible right of the Commission under § 206 to

replace rates that are contrary to the public

interest.’’ Papago, 723 F.2d at 953. Instead, Papago

involved a contractual regime that ‘‘contractually

eliminate[d] the utility’s right to make immediately

effective rate changes under § 205 but [left]

unaffected the power of the Commission under

§ 206 to replace not only rates that are contrary to

the public interest but also rates that are unjust,

unreasonable, or unduly discriminatory or

preferential to the detriment of the contracting

purchaser.’’ Id. See also id. at 953–54.

666Southern Company Services, Inc., 67 FERC

¶ 61,080 at 61,228 (1994); see also Florida Power &

Light Company, 67 FERC ¶ 61,141 at 61,398–99

(1994).

667 66 FERC ¶ 61,332 at 62,081, reh’g denied, 68

FERC ¶ 61,041 (1994).

668 66 FERC at 62,081–83; see also Southern, 67

FERC at 61,228–29.

669E.g., Central Montana EC, Central Illinois

Light.

670 It is not possible for the Commission to come

up with a reliable yardstick of the remaining terms

of existing requirements contracts. The

Commission’s files do not categorize rate schedules

as requirements, coordination and transmissiononly contracts. Moreover, there is no uniform

format for requirements contracts. Many have

evergreen provisions, the terminology of which

varies from contract-to-contract (e.g., some may be

year-to-year, others may roll over).

671The value of its assets could vary over time as

new technologies emerge, fuel costs fluctuate, or

environmental requirements change.

672FERC Stats. & Regs. at 31,818–19; mimeo at

534–37.

673We indicated that we will require the same

evidentiary demonstration for recovery of stranded

costs from a retail-turned-wholesale customer (and

will apply the same procedures for determining

stranded cost obligation) as that required in the case

of a wholesale requirements customer.

insurmountable’’ standard from ‘‘the

classic ‘low-rate’ case, namely,

Papago.’’665 As we have stated on

several occasions, ‘‘we do not interpret

the public interest standard of review

* * * as imposing on us a practically

insurmountable burden in situations in

which we are protecting non-parties to

a contract.’’ 666 Additionally, we do not

interpret the public interest standard as

practically insurmountable in

extraordinary situations such as this one

where historic statutory and regulatory

changes have converged to

fundamentally change the obligations of

utilities and the markets in which they

and their customers will operate. In this

circumstance, we believe the public

interest test is met where the

Commission determines that it is

necessary to allow parties to seek

contract amendments in order to protect

the stability and financial integrity of

the electric industry in general during

the transition to competition as well as

the interest of third parties affected by

the transition. This type of situation

simply was not addressed in Papago.

Congress has entrusted the

Commission with the statutory

responsibility to protect the public

interest. As we explained in Northeast

Utilities Service Company: 667

Protection of the ‘public interest’ provides

the justification for the Commission’s power

to regulate public utilities under Part II [of

the FPA]. Specifically, section 201(a) of the

FPA declares ‘that the business of

transmitting and selling electric energy for

ultimate distribution to the public is affected

with a public interest’ and that federal

regulation of matters related to generation (to

the extent provided in Parts II and III of the

FPA) and of the transmission and sale at

wholesale of electric energy in interstate

commerce ‘is necessary in the public

interest.’

Consistent with our statutory

obligations under the FPA, the

Commission has an overriding

responsibility to protect non-parties

affected by Mobile-Sierra contracts,

including consumers, to ensure that

matters entrusted to our jurisdiction

function smoothly during the

restructuring transition, and to fairly

balance the interests of utilities and

customers during the transition. 668 The

ability to meet our overarching public

interest responsibilities would be

virtually precluded if we must apply a

practically insurmountable standard of

review before we can take action to

address industry-wide transition issues.

Rehearing Requests Supporting Limited

Transition Period

Several entities request rehearing of

the Commission’s decision not to

establish a three-to five-year period

within which stranded cost recovery

could be raised. They assert that if the

Commission truly views stranded

investment as a transition process, the

transition should not be an extended

one.669

Commission Conclusion

The Commission will deny the

requests for rehearing on this point. As

we explained in Order No. 888,

although we considered limiting the

period within which stranded cost

recovery could be raised, there is no

uniform time remaining on

requirements contracts executed on or

before July 11, 1994. 670 As a result, any

limitation on the period in which

parties could propose amendments

covering stranded costs, such as three

years, would affect market participants

unequally. Those with long terms

remaining on their contracts could

object that immediately addressing the

issue would not be cost effective. A

utility with a long remaining term might

not even seek stranded cost recovery

depending on the competitive value of

its assets near the end of the contract

term.671 However, such a utility would

invariably seek to preserve its option to

seek stranded cost recovery if its failure

to do so within a short period resulted

in a waiver of its right to do so. Having

determined that it is generally

appropriate to leave in place existing

requirements contracts, it is not then

reasonable to create a time limitation on

stranded cost recovery that would

encourage a supplier to seek early

termination in order to preserve its

stranded cost recovery rights.

On this basis, we believe that we have

adequately explained the rationale for

our decision to allow stranded cost

claims to be raised at any time prior to

the termination of the contract, instead

of within three to five years of the

effective date of the Rule.

6. Recovery of Stranded Costs Caused by

Retail-Turned-Wholesale Customers

In Order No. 888, we concluded that

this Commission should be the primary

forum for addressing the recovery of

stranded costs caused by a retail-turnedwholesale customer.672 We stated that if

such a customer is able to reach a new

generation supplier because of the new

open access (through the use of a FERCfiled open access transmission tariff or

through transmission services ordered

pursuant to section 211 of the FPA), any

costs stranded as a result of this

wholesale transmission access should

be viewed as ‘‘wholesale stranded

costs.’’ We explained that there is a

clear nexus between the FERCjurisdictional transmission access

requirement and the exposure to nonrecovery of prudently incurred costs

and that, in these circumstances, this

Commission should be the primary

forum for addressing recovery of such

costs. 673

We said we will not be the primary

forum for stranded cost recovery in

situations in which an existing

municipal utility annexes territory

served by another utility or otherwise

expands its service territory. We

indicated that in these situations there

is no direct nexus between the FERCjurisdictional transmission access

requirement and the exposure to nonrecovery of prudently incurred costs.

The risk of an existing municipal utility

expanding its territory was a risk prior
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12405

674E.g., NARUC, TAPS, Nucor, Suffolk County, IL

Com, Multiple Intervenors, APPA, CAMU, WI Com,

NASUCA.

675E.g., ELCON, IL Com, IN Com, American

Forest & Paper, AR Com, MO/KS Coms, NJ BPU,

Suffolk County, WY Com, VA Com, FL Com,

NARUC, TAPS.

676 VT DPS and Valero cite in this regard Florida

Power & Light Company, 8 FERC ¶ 61,121 (1979);

Power Authority of the State of New York v. FERC,

743 F.2d 93 (2d Cir. 1984); Metropolitan

Transportation Authority v. FERC, 796 F.2d 584 (2d

Cir. 1986).

677American Forest & Paper cites in support of its

position Great Lakes Gas Transmission Limited

Partnership, 68 FERC ¶ 61,376 (1994).

678United Illuminating Company, 63 FERC

¶ 61,212, reh’g denied, 64 FERC ¶ 61,087 (1993)

(United Illuminating).

679See also Suffolk County Rehearing

(Commission’s analysis in United Illuminating was

correct; nothing has changed to warrant the

Commission’s rejection of that analysis).

to the Energy Policy Act and prior to

any open access requirement.

Nevertheless, we did express concern

that there may be circumstances in

which customers and/or utilities could

attempt, through indirect use of open

access transmission, to circumvent the

ability of any regulatory commission—

either this Commission or state

commissions—to address recovery of

stranded costs. We reserved the right to

address such situations on a case-bycase basis.

Rehearing Requests Opposing RetailTurned-Wholesale Jurisdiction

A number of entities challenge the

Commission’s assertion that costs

associated with retail-turned-wholesale

customers would not be stranded but for

the FERC-jurisdictional transmission

access requirement. They assert that the

condition precedent to municipalization

is the operation of a state process, and

thus that it cannot be the case that the

recovery of costs caused by a retailturned-wholesale customer is ‘‘not

subject to regulation by the States.’’

They submit that such costs would not

be stranded but for the action of state

legislators or state regulators in granting

authority for the customer’s status

change. They argue that any nexus that

the Commission’s authority under the

FPA has to wholesale transmission

services subsequently provided to the

new wholesale customer is entirely

derivative of the state’s action.674

A number of entities argue that

jurisdiction over costs that are stranded

when a retail customer becomes a

wholesale customer should be left to the

states because the facilities used to

provide retail service to these retail

customers were subject to state

jurisdiction and were included in retail

rate base when the service was

rendered.675 They argue that because the

Commission had no jurisdiction over

the public utility facilities and costs

incurred to serve retail-turnedwholesale customers, it has no

jurisdiction to address those public

utility costs if they become stranded.

Thus, according to these entities, the

conversion of the customer from retail

to wholesale does not simultaneously

effectuate a conversion of the costs from

retail to wholesale.

AR Com and MO/KS Coms submit

that jurisdiction over the costs incurred

for historical retail customers does not

shift unless the parties themselves make

those costs a part of their new wholesale

contract. NY Com submits that the

Commission should recognize the states’

jurisdiction to set the level of stranded

costs associated with retail-turnedwholesale customers to be recovered in

wholesale transmission rates set by

FERC. FL Com asserts that state

authorities are in a better position to

assess the extent of stranded facilities

and their costs, and that the

Commission’s involvement should be

limited to that requested by a state by

petition.

OH Com states that the Commission’s

position on stranded costs associated

with retail-turned-wholesale customers

invites second-guessing of state

commission determinations and

encourages forum shopping by

introducing more than one stranded cost

treatment within a single state

jurisdiction. It expresses concern that

utilities may seek to creatively

disaggregate into generation,

transmission, and distribution

companies in ways to deliberately recast

traditional retail relationships as

wholesale in an effort to obtain

favorable regulatory treatment of

stranded costs.

IN Com submits that Order No. 888’s

treatment of stranded costs associated

with retail-turned-wholesale customers

will discourage state legislatures from

making municipalization more

available. VT DPS and Valero argue that

the threat of a stranded cost surcharge

will erect a new barrier to the formation

of municipal utilities. They note that the

Rule refers to one commenter’s

observation that, if Otter Tail could have

made a stranded cost claim against the

municipal utility that Elbow Lake

planned to create, Otter Tail would not

have needed to refuse to wheel and

there would never have been an Otter

Tail case. They submit that the

Commission never addressed whether,

or why, it believed the point to be

wrong.

VT DPS and Valero also assert that the

Rule represents a major inconsistency

with prior Commission treatment of

municipalization. They submit that the

Commission historically promoted

franchise competition between

municipalities and utilities by holding

tariff provisions that restrict such

competition to be anticompetitive and

unreasonable.676

American Forest & Paper submits that

recovery of 100 percent of stranded

costs caused by municipalization is

inconsistent with the Commission’s

actions in the natural gas industry,

where the Commission has encouraged

competition at the retail level through

competitive bypass and has not created

barriers to competitive entry by

imposing transition charges or exit fees

on converting customers.677

Nucor objects that the Rule does not

address the substantive findings, the

common sense rationale, or the

jurisdictional distinction drawn in

United Illuminating.678 It contends that

the Commission’s observation in Order

No. 888 that there may not be a state

regulatory forum for the recovery of

stranded costs associated with retailturned-wholesale customers and hence

that the Commission should be the

primary forum for addressing such

stranded costs is flawed because there

always is a state forum to address such

cost recovery (the adequacy of the relief

provided is a very distinct issue) and

open access transmission does not and

cannot cause retail competition to

occur.679

Commission Conclusion

We will reject the requests for

rehearing of our decision to be the

primary forum for addressing the

recovery of stranded costs caused by

retail-turned-wholesale customers. We

find the requests for rehearing on this

issue unpersuasive. While it may be the

case, as some entities suggest, that state

action is a condition precedent to

municipalization, the rehearing

petitions ignore the fact that the Rule

covers situations in which open access

is also a condition precedent to the

municipalized customers leaving their

existing supplier’s system. Order No.

888 does not propose that the

Commission be the primary forum for

stranded cost recovery for all cases of

municipalization. Instead, our holding

is limited to those cases in which the

new wholesale entity uses Commissionmandated transmission access to obtain

new power supply on behalf of retail

customers that were formerly supplied
12406 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

680 In the case of municipalization, the bundled

retail customers of a local utility become the

bundled retail customers of the new municipal

utility. As explained above, we call this a ‘‘retailturned-wholesale customer’’ situation because the

new municipal entity in effect ‘‘stands in the shoes’’

of the retail customers for purposes of obtaining

wholesale transmission access and new power

supply.

681 In response to VT DPS and Valero, we note

that whether or not Otter Tail may have agreed to

wheel power for the municipal utility that Elbow

Lake planned to create if Otter Tail could have

made a stranded cost claim against that municipal

utility is of no moment to the Commission’s

decision in Order No. 888 to allow utilities the

opportunity to seek recovery of stranded costs

associated with retail-turned-wholesale customers.

The Court in Otter Tail did not address the stranded

cost issue because it was not presented in that case.

Nor was the Court presented with the extraordinary

circumstances—the historic statutory and

regulatory changes, including the requirement of

open access, that have converged to fundamentally

change the obligations of utilities and the markets

in which they operate—that have justified this

Commission’s Order No. 888 stranded cost policy.

power by the utility providing the

transmission service.680

As we explained in Order No. 888, in

such cases there is a direct nexus

between the FERC-jurisdictional

transmission access requirement and the

exposure to non-recovery of costs

stranded as a result of this wholesale

transmission access. Thus, the stranded

costs associated with retail-turnedwholesale customers for which Order

No. 888 provides an opportunity for

recovery would not have been incurred

but for the action of this Commission in

requiring a utility to make unbundled

transmission services available. In these

cases, the former bundled retail

customers of the historical supplying

utility (now the bundled retail

customers of the new municipal system)

would not have obtained access to new

power supply but for the Commission’s

order mandating transmission. Without

the regulatory mandate to provide

access, the utility would have indirectly

continued sales to the same retail

customers because the new municipal

utility purchasing power on the retail

customers’ behalf would have had no

way to reach other power suppliers. In

this situation, there would be no

stranded generation costs. In other

words, the creation of a municipal

utility intermediary to purchase power

at wholesale would not, by itself, trigger

stranded costs. Rather, it is the access

from the historical supplier of the

bundled retail customers that is the

condition precedent to reaching other

power suppliers and thereby triggering

stranded costs. Therefore, there is a

clear causal nexus between the stranded

costs and the availability and use of the

tariff required by the Commission.

Costs that are exposed to nonrecovery

when a retail customer or a newlycreated wholesale power sales customer

ceases to purchase power from the

utility and does not use the utility’s

transmission system to reach a new

generation supplier (e.g., through selfgeneration or use of another utility’s

transmission system) do not meet the

definition of ‘‘wholesale stranded costs’’

for which the Rule provides an

opportunity for recovery. Such costs are

outside the scope of the Rule because

such costs would not be stranded as a

direct result of the new open access.

In response to the argument that

conversion of a customer from retail to

wholesale would not simultaneously

effectuate a conversion of the costs from

retail to wholesale, we believe this

argument confuses the issue. We note

that we have defined stranded costs as

wholesale or retail on the basis of

whether wholesale or retail open access

is the cause of the costs being stranded,

not on the basis of the original retail or

wholesale characteristic of the costs.

Thus, even though costs may have been

originally incurred as retail-related

costs, the precipitating event that results

in such costs being stranded in the

retail-turned-wholesale customer

scenario is the use by the new wholesale

customer of the Commission-mandated

tariff. When a customer is able to use

the Commission-required tariff to reach

another generation supplier, it causes

the utility to incur an economic cost in

providing transmission service that is

equal to the foregone revenues that the

utility reasonably expected to receive

under a state regulatory regime. Thus,

because of the causal nexus between the

use of a former supplying utility’s

Commission-mandated transmission

tariff and the potential for foregone

revenues by that utility as a result of the

Commission-required access, the costs

stranded by a retail-turned-wholesale

customer are properly viewed as

economic costs that are jurisdictional to

this Commission.

In response to those entities that

express concern that the Commission’s

position on stranded costs associated

with retail-turned-wholesale customers

invites second-guessing of state

commission determinations, we

emphasize that we have assumed

primary authority to address such costs

only in a limited category of cases

where there is a direct nexus between

the availability of Commission-required

open access and the stranding of costs

when the former customer uses the

former supplying utility’s transmission

system (through its open access tariff or

a section 211 order) to reach a new

supplier. We indicated in Order No. 888

that if the state has permitted any

recovery from departing retail-turnedwholesale customers, such amount will

not be stranded for purposes of this

Rule. We will deduct that amount from

the costs for which the utility will be

allowed to seek recovery under this

Rule from the Commission. In so doing,

however, we are not second-guessing

the states as to what a utility may

recover under state law. Additionally,

we will give great weight in our

proceedings to a state’s view of what

might be recoverable.

We also reject the argument that the

Commission’s position on stranded

costs associated with retail-turnedwholesale customers encourages forum

shopping. To the contrary, as we said in

Order No. 888, to avoid forum shopping

and duplicative litigation of the issue,

we expect parties to raise claims before

this Commission in the first instance.

We believe that this Commission should

be the primary forum because, without

the open access provided by the Rule,

the new municipal utility would not be

able to reach a new supplier and, as a

result, would not cause the utility to

incur stranded costs (as defined in this

Rule).

We reject as misplaced arguments that

the Rule represents a major

inconsistency with the Commission’s

historical promotion of franchise

competition between municipalities and

utilities and that it will discourage

municipalization.681 It continues to be

the Commission’s policy to encourage

competition. Indeed, the goal of Order

No. 888 is to remove impediments to

competition in the wholesale bulk

power marketplace and to bring more

efficient, lower cost power to the

Nation’s electricity consumers.

However, the purpose of the stranded

cost policy is neither to encourage nor

to discourage municipalization, but

rather to facilitate a fair transition to

competition and to ensure stability in

the industry during that transition. As

we discuss elsewhere in this order, we

believe that this Commission must

address the recovery of the costs of

moving from a monopoly-regulated

regime to one in which all sellers can

compete on a fair basis and in which

electricity is more competitively priced.

On this basis, we believe that if a new

wholesale entity such as a municipal

utility uses Commission-required open

access to reach a new supplier on behalf

of its retail customers (previously retail

customers of the former supplier), the

former supplying utility should be given

an opportunity to recover legitimate,

prudent and verifiable costs that it
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12407

682Texas Gas Transmission Corporation, 65 FERC

¶ 61,275 (1993).

683Texas Gas Transmission Corporation, 69 FERC

¶ 61,245, reh’g, 70 FERC ¶ 61,207 (1995) (requiring

pipeline to offer LDC a reduction in its contract

demand).

684See Southern Natural Gas Company, 75 FERC

¶ 61,046 at 61,158 (1996); Arcadian Corporation v.

Southern Natural Gas Company, 67 FERC ¶ 61,176

at 61,538 (1994). See also United Distribution

Companies, 88 F.3d at 1181. As the United

Distribution Companies court noted, the

Commission has given an LDC relief (and required

the bypassing customer to bear its share of

transition costs) if the LDC can show a direct nexus

between the bypass and the pipeline, although the

Commission has declined to adopt a generic rule

addressing this issue. 88 F.3d at 1180–81. 685 63 FERC at 62,583–84.

686E.g., EEI, SoCal Edison, Centerior, Atlantic

City, PSE&G, Puget, Public Service Co of CO,

Coalition for Economic Competition.

687E.g., EEI, SoCal Edison, PSE&G, Puget, Public

Service Co of CO, Coalition for Economic

Competition. Coalition for Economic Competition

suggests, for example, that villages and large

industrial customers may opt to join existing

municipal systems that, in most cases, will use

Commission-jurisdictional transmission tariffs to

obtain resources to supply power to the annexed

loads.

688E.g., EEI, Coalition for Economic Competition,

Atlantic City, Puget, Public Service Co of CO.

689 74 FERC ¶ 61,086, final order directing

transmission service, 76 FERC ¶ 61,265 (1996).

incurred under the prior regulatory

regime to serve that customer.

In response to American Forest &

Paper’s argument that recovery of 100

percent of stranded costs caused by

municipalization is inconsistent with

the Commission’s policy in the natural

gas industry of allowing competitive

bypass without imposing transition

charges or exit fees on converting

customers, we note that industrial gas

customers who bypass a local

distribution company’s (LDC) facilities

do not escape transition costs quite so

easily as suggested by American Forest

& Paper. It is true that, when the end

user bypasses the LDC to reach an

interstate pipeline different from the

pipeline serving the LDC, the

Commission views the bypass as a risk

of competition from which the LDC

should not be shielded.682 However,

when the end user bypasses the LDC to

reach the same interstate pipeline that

serves the LDC, the Commission may

take certain actions to minimize adverse

effects on the LDC and its remaining

customers.683 Moreover, an end user

that bypasses an LDC to reach the same

pipeline that serves the LDC would, in

any event, be allocated a share of the

pipeline’s gas supply realignment costs

(if any), since those costs are allocated

based on current contract demand (or

usage).684 Accordingly, we see no

inconsistency between our bypass

policy for the natural gas industry and

Order No. 888’s treatment of stranded

costs associated with retail-turnedwholesale customers. Similar to our

refusal to shield LDCs from the adverse

effects of an end user’s bypass to reach

a different pipeline than serves the LDC,

Order No. 888 does not provide an

opportunity for stranded cost recovery

where a retail-turned-wholesale

customer uses another utility’s

transmission system to reach a new

supplier. As we note above, the

opportunity for recovery of stranded

costs associated with retail-turnedwholesale customers is limited to those

cases in which the former retail

customer obtains (either directly or

through another wholesale transmission

purchaser) unbundled transmission

services from its former supplying

utility. In the case of an end use

customer bypassing the LDC to reach

the same pipeline that serves the LDC,

the end use customer would similarly

be allocated a share of the pipeline’s gas

supply realignment costs. As a result,

American Forest & Paper’s attempt to

rely on the Commission’s gas bypass

policy is misplaced.

We also disagree with those entities

that argue that the Commission has

failed to adequately distinguish Order

No. 888’s treatment of stranded costs

associated with retail-turned-wholesale

customers with the Commission’s

decision in United Illuminating. As we

stated in Order No. 888, we recognize

that we took a different approach to

stranded cost recovery associated with

retail-turned-wholesale customers in

United Illuminating, where we

suggested that state and local regulatory

authorities or the courts should be able

to provide an adequate forum to address

retail franchise matters, including

recovery of stranded costs caused by

municipalization, but said we would

consider revisiting the question if

United Illuminating could demonstrate

the lack of a forum.685 However, we

explained that since the issuance of that

decision we have had an opportunity to

re-analyze the nature of the stranded

cost problem when a retail customer

becomes a wholesale customer,

including the potential that there might

not be a state regulatory forum for

recovery of such costs. In these

circumstances, we have determined that

where such costs are stranded as a

direct result of Commission-mandated

wholesale transmission access, these

costs should be viewed as costs of the

transition to competitive wholesale bulk

power markets and this Commission

should be the primary forum for

addressing their recovery.

In response to Nucor’s objection that

there always is a state forum to address

stranded cost recovery associated with

retail-turned-wholesale customers, with

the adequacy of the relief being a

distinct issue, we clarify that our

primary concern in retail-turnedwholesale situations is not whether

there is an adequate state regulatory

forum for the recovery of stranded costs

associated with retail-turned-wholesale

customers. Rather, our primary concern

is that wholesale customers (whether or

not formerly retail) should be

responsible for the costs incurred to

meet their power needs that are

stranded when they use the wholesale

transmission ordered by this

Commission to reach new suppliers.

Our decision to be the primary forum in

the case of stranded costs associated

with retail-turned-wholesale customers

is based on the causal nexus between

regulatory-mandated wholesale

transmission access and the stranding of

costs when a new municipal utility uses

such access to obtain new power supply

on behalf of retail customers previously

served by the former supplying utility.

Rehearing Requests Seeking Expansion

of Retail-Turned-Wholesale Jurisdiction

Other entities seek rehearing of the

Commission’s decision not to be the

primary forum for stranded cost

recovery in situations in which an

existing municipal utility annexes

territory served by another utility or

otherwise expands its service

territory.686 A number of them argue

that the loss of existing retail customers

through municipal annexations or

expansions is no different from the loss

of retail customers through new

municipalization because existing

municipal systems are likely to use

Commission-jurisdictional open access

transmission to obtain resources to

supply power to the annexed loads.687

They submit that, just as with newlymunicipalized customers, such costs

would not be stranded but for the action

of this Commission.

Some of these entities express

concern that the Rule will encourage

retail-turned-wholesale transactions to

be undertaken as annexations rather

than through the formation of new

entities to avoid stranded costs. 688

Public Service Co of CO contends that

Order No. 888, in conjunction with the

Commission’s section 211 order in

American Municipal Power Ohio,

Inc.,689 may facilitate municipal

annexations by enabling municipal

systems to serve new territory through

the establishment of second delivery

points.

Coalition for Economic Competition

and Puget also argue that the

Commission must consider stranded
12408 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

690SoCal Edison requests clarification that a

transaction in which a retail customer disconnects

from a utility’s system and accesses another

generation supplier by interconnecting with a

public power entity, who in turn would

interconnect with a neighboring jurisdictional

utility, constitutes a municipalization, not an

expansion of a service territory. Because we have

decided to treat municipal annexations (or

expansions) and new municipalizations similarly

for purposes of stranded cost recovery under the

Rule, SoCal Edison’s request is moot to the extent

that it envisions a scenario in which the former

supplier’s transmission system is used to access a

new generation supplier. However, as discussed

below, the Rule would not provide an opportunity

to seek recovery of stranded costs if the municipal

entity in the scenario described by SoCal Edison

does not use the former supplier’s transmission

system.

costs that arise from municipal

expansion in order to satisfy its

statutory obligation under the FPA to

‘‘set just and reasonable’’ rates. They

contend that there is no justification for

charging one rate to former retail

customers taking transmission services

through a new municipal utility and

another rate to those taking service

through municipal annexation or

through use of another utility’s

transmission system.

PSE&G suggests that the distinction

between new municipalization on the

one hand and municipal annexation or

expansion on the other hand may lead

to unnecessary controversy and

litigation as entities wrangle over

whether a given expansion/annexation

is really an expansion or a

municipalization. It says that a situation

could arise where a municipality serves

one town in order to serve thousands of

additional customers in a second town.

According to PSE&G, it is not clear from

the Rule whether the Commission

would consider this an expansion of a

municipality’s service territory or a new

municipalization.

Puget submits that the stranded cost

recovery mechanism must not be subject

to being frustrated by simple artifices

such as having the new supplier

(instead of the departing customer)

request and contract for transmission

service. SoCal Edison seeks clarification

of the Commission’s authority to

mandate stranded cost recovery if a

retail customer disconnects from a

utility’s system and accesses another

generation supplier by interconnecting

with a public power entity (who in turn

would interconnect with a neighboring

jurisdictional utility). It asks the

Commission to clarify that such a

transaction effectively constitutes a

municipalization, not an expansion of a

service territory, and that the

Commission, under FPA section 211,

can compel the recovery of stranded

costs by having the ‘‘new’’ jurisdictional

utility assess a stranded cost charge and

pass the revenues on to the utility from

whose system the customer departed.

SoCal Edison seeks several additional

clarifications. It states that it

understands that the Commission’s

primary forum status in no way

prevents or interferes with a state’s

authority to order stranded cost

recovery from departing retail

customers. If this is not the case, SoCal

Edison seeks rehearing on this issue.

SoCal Edison also asks the Commission

to clarify that the Commission retains

the discretion to defer to a state

stranded cost calculation methodology

if appropriate to do so on the facts of a

particular case.

Commission Conclusion

We have carefully reviewed the

arguments made by petitioners seeking

rehearing of our decision not to be the

primary forum for stranded cost

recovery in the case of municipal

annexations. Based on that review we

have decided to reconsider our decision.

This conclusion is based in large part

upon the very significant similarities

between the creation of a new municipal

utility system (also referred to as

municipalization) and the expansion of

an existing municipal utility system

(e.g., through annexation of additional

retail service territory). We recognize

that the same nexus to Commissionrequired transmission access that forms

the basis for our decision to allow a

utility to seek stranded cost recovery in

cases of new municipalization—use of

the former supplying utility’s

transmission system—is likely to be

present in some cases of municipal

annexation. In the case of both new

municipalizations and annexations, the

bundled retail customers of a local

utility become the bundled retail

customers of a municipal utility (in one

case a new municipal utility, in the

other an existing municipal utility) that

will use the transmission system of the

retail customers’ former supplier in

order to access other suppliers.

As we explain above, in a ‘‘retailturned-wholesale customer’’ situation,

such as the creation of a municipal

utility system, a newly-created entity

becomes a wholesale power purchaser

on behalf of the retail customers. It is

the conduit by which retail customers,

if they cannot obtain direct retail access,

can reach power suppliers other than

their historical local utility power

supplier. Although the retail customers

remain bundled retail customers, in that

they become the bundled customers of

the new entity, we call this a ‘‘retailturned-wholesale customer’’ situation

because the new entity in effect ‘‘stands

in the shoes’’ of the retail customers for

purposes of obtaining wholesale

transmission access and new power

supply. The same analogy applies to

newly-annexed customers; they become

‘‘new’’ wholesale customers in the sense

that the wholesale entity obtains

transmission and new power supply on

their behalf.

Accordingly, we clarify that this

Commission will be the primary forum

for addressing the recovery of stranded

costs if an existing municipal utility

uses the transmission system of its

annexed retail customers’ former

supplier to access new suppliers to

serve the annexed load. As long as

Commission-required transmission

access (the former supplier’s open

access tariff or transmission services

ordered under FPA section 211) is the

vehicle that enables an existing

municipal utility to obtain power

supplies to serve annexed loads, we

believe that any costs stranded as a

result of this wholesale transmission

access are properly viewed as economic

costs that are jurisdictional to this

Commission. In such a case, the

bundled retail customers that are

annexed by an existing municipal utility

would, through the municipal utility,

use the transmission system of their

former supplier to obtain access to new

supplies and thereby expose their

former supplier to non-recovery of

prudently incurred costs. As in the case

of new municipal systems that use the

transmission system of their retail

customers’ former supplier, such costs

would not be stranded but for the action

of this Commission in requiring a utility

to make unbundled transmission

services available.690

Just as we will not be the primary

forum for stranded cost recovery for all

new municipalizations, so also we will

not be the primary forum for stranded

cost recovery for all cases of municipal

annexation. Instead, our holding is

limited to those cases in which the

existing municipal system uses

Commission-mandated transmission

access from the annexed customers’

former supplying utility to obtain power

from a new supplier. Costs that are

exposed to nonrecovery when an

existing municipal utility does not use

the transmission system of the retail

customers’ former supplier to reach a

new generation supplier (e.g., through

self-generation or use of another utility’s

transmission system) do not meet the

definition of ‘‘wholesale stranded costs’’

for which the Rule provides an

opportunity for recovery. Such costs are

outside the scope of the Rule because

such costs would not be stranded as a

direct result of Commission-required

transmission access.
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12409

691FERC Stats. & Regs. at 31,819; mimeo at 536–

37.

692FERC Stats. & Regs. at 31,819; mimeo at 537.

693FERC Stats. & Regs. at 31,824–26; mimeo at

553–58.

694 ‘‘State regulatory authority’’ has the same

meaning as provided in section 3(21) of the FPA:

‘State regulatory authority’ has the same meaning

as the term ‘State commission’, except that in the

case of an electric utility with respect to which the

Tennessee Valley Authority has ratemaking

authority (as defined in section 3 of the Public

Utility Regulatory Policies Act of 1978), such term

means the Tennessee Valley Authority.

We reject as misplaced the argument

that the Commission, by failing to

address costs that arise if a municipal

utility (whether a new municipal utility

or an existing municipal utility that

annexes additional retail customer

territory) does not use the historical

supplying utility’s transmission system,

has not met its statutory obligation to

‘‘set just and reasonable’’ rates. The

Commission in this rulemaking has not

determined any utility’s just and

reasonable rates. Further, Order No. 888

does not by its terms bar the recovery

of costs that do not result from the use

of Commission-required transmission

access. Utilities may, as before, seek

recovery of such non-open accessrelated costs on a case-by-case basis in

individual rate proceedings. The

Commission will not prejudge those

issues here.

As we indicated in Order No. 888, we

also are concerned that there may be

circumstances in which customers and/

or utilities could attempt, through

indirect use of open access

transmission, to circumvent the ability

of any regulatory commission—either

this Commission or state commissions—

to address recovery of stranded costs.691

We reiterate that we reserve the right to

address such situations on a case-bycase basis.

We share the concern expressed by

Puget that a retail-turned-wholesale

customer should not be allowed to

avoid any stranded cost obligation that

it may have under Order No. 888 simply

by having its new supplier be the entity

that requests and contracts for

transmission service from the former

supplying utility. We clarify that the

opportunity for recovery of stranded

costs associated with retail-turnedwholesale customers under Order No.

888 applies if the transmission system

of the former supplier is used to

transmit the newly obtained power

supplies to the departing retail

customer, regardless of whether the

customer or its new supplier is the

actual entity that requests and contracts

for the unbundled transmission service.

We have revised the definition of

‘‘wholesale stranded cost’’ in section

35.26(b)(1)(ii) accordingly to include the

situation in which the retail customer

subsequently becomes, either directly or

through another wholesale transmission

purchaser, an unbundled wholesale

transmission services customer of the

former supplying utility.

We clarify in response to SoCal

Edison’s request that our decision to be

the primary forum for recovery of

stranded costs from retail-turnedwholesale customers is not intended to

prevent or to interfere with the authority

of a state to permit any recovery from

departing retail customers, such as by

imposing an exit fee prior to creating the

wholesale entity. As we indicated in

Order No. 888, if the state has permitted

any such recovery from a departing

retail-turned-wholesale customer, that

amount will not in fact be stranded.

Accordingly, we will deduct that

amount from the costs for which the

utility will be allowed to seek recovery

from this Commission.692

We clarify in response to SoCal

Edison’s request that the Commission

has the discretion to defer to a state

stranded cost calculation methodology.

However, because we recognize that

state retail access plans may present

questions that need to be addressed on

a case-by-case basis, we will consider

whether to exercise that discretion on a

case-by-case basis.

7. Recovery of Stranded Costs Caused by

Retail Wheeling

In Order No. 888, we concluded that

both this Commission and the states

have the legal authority to address

stranded costs that result when retail

customers obtain retail wheeling in

order to reach a different generation

supplier, and that utilities are entitled,

from both a legal and a policy

perspective, to an opportunity to

recover all of their prudently incurred

costs.693 We explained that this

Commission’s authority to address retail

stranded costs (i.e., stranded costs

associated with retail wheeling

customers) is based on our jurisdiction

over the rates, terms, and conditions of

unbundled retail transmission in

interstate commerce by public utilities,

and that the authority of state

commissions to address retail stranded

costs is based on their jurisdiction over

local distribution facilities and the

service of delivering electric energy to

end users. Because it is a state decision

to permit or to require the retail

wheeling that causes stranded costs to

occur, we decided we generally will

leave it to state regulatory authorities to

deal with any stranded costs occasioned

by retail wheeling. The only

circumstance in which we will entertain

requests to recover stranded costs

caused by retail wheeling is when the

state regulatory authority 694 does not

have authority under state law to

address stranded costs when the retail

wheeling is required. In such a case, we

will permit a utility to seek a customerspecific surcharge to be added to an

unbundled transmission rate.

We noted that most states have a

number of mechanisms for addressing

stranded costs caused by retail

wheeling. We indicated that rates for

services using facilities used in local

distribution to make a retail sale are

state-jurisdictional, and that states will

be free to impose stranded costs caused

by retail wheeling on facilities or

services used in local distribution. We

also said that states may use their

jurisdiction over local distribution

facilities or services to recover so-called

stranded benefits.

We stated that we believe our

approach to stranded costs associated

with retail wheeling customers

represents an appropriate balance

between federal and state interests that

ensures that the rates for transmission in

interstate commerce by public utilities

(except in a narrow circumstance) will

not be burdened by retail costs.

We expressed concern about the costshifting potential in a holding company

or other multi-state situation, where

denial of retail stranded cost recovery

by a state regulatory authority could,

through operation of the reserve

equalization formula in a Commissionjurisdictional intra-system agreement,

inappropriately shift the disallowed

costs to affiliated operating companies

in other states. We said that we will deal

with such situations if they arise

pursuant to public utility filings under

section 205 or complaints under section

206. Thus, the need to amend a

jurisdictional agreement to prevent

stranded costs associated with retail

wheeling customers from being shifted

to customers in other states will be

addressed on a case-by-case basis. We

encouraged the affected state

commissions in such situations to seek

a mutually agreeable approach to this

potential problem. If such a consensus

solution resulted in a filing to modify a

jurisdictional agreement, we indicated

that we would accord such a proposal

deference, particularly if other

interested parties support the filing. In

the event that the state commissions and

other interested parties cannot reach

consensus that would prevent cost

shifting, we said that the Commission

would ultimately have to resolve the
12410 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

695 376 U.S. 205, 215–16 (1964).

696E.g., Central Illinois Light, IN Consumer

Counselor, IN Consumers, Nucor, FL Com, WI Com,

VA Com, AR Com, MO/KS Com, OH Com, APPA.

For example, FL Com asserts that costs for facilities

that are currently under the jurisdiction of state

authorities do not become the Commission’s

jurisdiction because retail wheeling is instituted; in

most cases, the states approved both the

construction and the cost recovery for these

facilities under bundled rate structures. FL Com

submits that the states are in a better position to

judge the extent and value of assets that may

become stranded as a result of retail wheeling.

697E.g., APPA, AR Com, MO/KS Coms, OH Com.

698E.g., NARUC, TAPS.

699E.g., NASUCA, NY Com, WY Com, NARUC.

The Consumer’s Utility Counsel Division of the

Georgia Governor’s Office of Consumer Affairs filed

comments on June 24, 1996, in support of NARUC’s

request for rehearing on the jurisdictional issues

pertaining to the recovery of retail stranded costs.

While answers to requests for rehearing generally

are not permitted, 18 CFR 385.213(a)(2) (1996), we

will depart from our general rule because of the

significant nature of this proceeding and will accept

these comments.

700According to NASUCA, whether or not that

authority includes a requirement that a utility

receive 100 percent return on stranded costs (or

something less) is a matter to be determined by the

state courts and legislatures.

701See also AR Com (one retail transaction is

replaced by another retail transaction; there is no

wholesale transaction and no wholesale costs over

which the Commission has jurisdiction).

702E.g., NARUC, Central Illinois Light, IN Com,

American Forest & Paper, IN Consumer Counselor,

IN Consumers, IL Com.

703E.g., Central Illinois Light, IN Com, American

Forest & Paper, IN Consumer Counselor, IN

Consumers, IL Com. TX Com considers that it has

the power to address stranded cost issues related to

retail transmission service.

704 IL Com at 38 (emphasis in original).

appropriate treatment of such stranded

costs.

Rehearing Requests Opposing Any

Commission Involvement in Stranded

Costs Associated With Retail Wheeling

Customers

A number of entities dispute the

Commission’s statement that both it and

the states have the legal authority to

address stranded costs that result from

retail wheeling. Central Illinois Light

contends that the Commission’s claim of

dual jurisdiction is inconsistent with

FPC v. Southern California Edison

Company.695 It says that the court in

that case recognized that Congress

meant to draw a bright line easily

ascertained between state and federal

jurisdiction, making unnecessary caseby-case analysis. Central Illinois Light

asserts that the Commission has stepped

over the bright line into the states’

exclusive jurisdiction over retail rates.

IA Com seeks rehearing of the

Commission’s assertion of concurrent

jurisdiction with state authorities over

stranded costs associated with retail

wheeling customers on the ground that

it is based on the Commission’s

erroneous assertion of jurisdiction over

unbundled retail transmission.

IL Com says that regardless of

whether the Commission’s claim of

jurisdiction over retail transmission is

upheld, the Commission’s ruling that

there is joint jurisdiction over retail

stranded costs is in error. According to

IL Com, the Commission has no

authority over such stranded costs. IL

Com also disputes the Commission’s

characterization of the derivation of

state authority to address such stranded

costs. It says that state commission

authority does not derive only from

states’ jurisdiction over local

distribution facilities and the service of

delivering electric energy to end users.

IL Com submits that state commission

authority to address retail stranded costs

derives from the existence of state

commission jurisdiction over the

facilities and costs at the time of their

incurrence.

A number of entities contend that

Commission jurisdiction over

transmission facilities used in interstate

commerce does not give it jurisdiction

over stranded investment in retail

generating assets.696 Several argue that

the fact that a retail wheeling customer

might need transmission access from its

former supplier does not change the

character of the costs that are stranded.

They maintain that retail stranded costs

are not costs of providing unbundled

transmission service, but are costs

associated with providing what was

formerly bundled retail service, over

which the Commission has no

jurisdiction.697

Several entities argue that it is solely

the action of the state that allows a

given utility’s retail customers to seek

alternative sources of supply; therefore,

there is no nexus between the

Commission’s wholesale transmission

rule and any costs that might be

stranded by a state-established customer

choice regime.698

A number of entities submit that the

provision of FPA section 201 that

federal regulation is ‘‘to extend only to

those matters which are not subject to

regulation by the States’’ bars any

attempt by the Commission to displace

or supplant an admittedly legitimate

exercise of state authority over retail

stranded costs.699 NASUCA submits that

all state commissions have the authority

to establish just and reasonable rates for

the retail electric utilities in their

respective jurisdictions.700 It maintains

that only state regulators are in a

position to rule on the treatment of costs

that were allowed in retail rates

pursuant to state laws; the Commission

has no knowledge or expertise regarding

the specific state legal frameworks in

which these costs were included in

rates. NY Com argues that the

Commission does not have jurisdiction

to determine the rate treatment of costs

devoted to retail service and, thus, lacks

authority to allow recovery if a state

decides not to do so.

VA Com argues that section 201(b)(1)

of the FPA restricts the Commission’s

jurisdiction to wholesale sales. It says

that a departing retail customer remains

a retail customer, regardless of the

supplier. VA Com concludes that no

portion of the transaction is a wholesale

sale, and that there are no wholesale

costs associated with a retail wheeling

transaction.701

A number of entities seek rehearing of

the Commission’s decision that it will

entertain stranded cost claims when the

state regulatory authority does not have

authority under state law to address

stranded costs when the retail wheeling

is required.702 NARUC submits that

Congress did not intend the

Commission to become involved in

adjudicating legal questions regarding

the breadth of state law authority

granted state commissions by their

legislatures. NARUC expresses concern

that the Commission would secondguess a state cost recovery

determination and promote forum

shopping. Once a balance has been

struck at the state level concerning the

terms of restructuring, NARUC submits

that it is inconceivable that the

Commission would have either the

desire or authority to second-guess a

state’s legislative and regulatory

processes.

Several entities object that the

Commission effectively would authorize

recovery of stranded costs associated

with a retail wheeling customer if a state

legislature withholds from the state

regulatory agency the authority to

approve stranded cost recovery.703 They

submit that just because a state has not

given its regulatory commission the

authority to impose stranded costs in

the case of retail wheeling does not

confer jurisdiction on the Commission

to impose such charges. They contend

that the state legislature should be the

final arbiter of state policy. IL Com

submits that if a state legislature

chooses not to give its state commission

the authority to act on stranded costs,

‘‘that can be taken as a clear indication

that the state’s legislature most certainly

does not want FERC to address

them.’’ 704 Central Illinois Light objects

that the Commission has offered no

reason why it will accept the decision
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12411

705E.g., ELCON, NASUCA, IL Com, NY Com.

706See FERC Stats. & Regs. at 31,780–85; mimeo

at 427–42 and Appendix G.

707 If a utility is regulated by both this

Commission and a state commission, each

commission, in setting cost-of-service rates within

its jurisdiction, will separately and independently

determine the utility’s total cost of providing

service (also known as the utility’s total revenue

requirement). This will be based on the expenses

incurred in providing service and a reasonable

profit on the utility’s assets that are used to provide

the service. The commissions may differ as to what

assets are appropriately included in total rate base,

what other costs are appropriately included in the

total cost of service, and what rate of return should

be permitted. Once each regulatory authority has

determined the appropriate total revenue

requirement, it then will determine what portion of

that total revenue requirement should be borne by

the utility’s wholesale customers and what share

should be borne by retail customers (also called cost

allocation). Each commission may also reach

different conclusions on this split as well. Thus,

under historical cost-based ratemaking, regulatory

authorities do not carve out so-called ‘‘wholesale

costs’’ that only this Commission can take into

account in determining rates subject to its

jurisdiction or so-called ‘‘retail costs’’ that only a

state commission can take into account in

determining rates subject to state jurisdiction.

Additionally, this Commission and state

commissions have the discretion to determine

whether costs are appropriately recovered through

a transmission, generation, or distribution

component of a rate (also called functionalization

of costs) within their respective jurisdictions.

708We reject arguments that stranded retail

generation costs are not a cost of providing

unbundled retail transmission. While such costs are

not a cost of operating the physical transmission

system, nevertheless, they are an economic cost

incurred as a result of being required to provide

retail transmission.

of the regulatory agency, but not that of

the legislature.

AMP-Ohio and Cleveland ask the

Commission to clarify that its deference

to the determinations of the states is to

the authority of the states as exercised

through state legislative bodies (and

other political subdivisions with

legislative authority) as well as to state

regulatory bodies. They submit that if

the state legislature, or a local

government acting in accordance with

its authority, enacts retail wheeling

legislation that expressly limits the

ability of its regulatory body to permit

recovery of stranded costs, even barring

all such recovery, the Commission

should not become involved.

Several entities ask the Commission

to clarify that Order No. 888 does not

permit utilities to apply to the

Commission for recovery of stranded

costs associated with a retail wheeling

customer when a state regulatory

authority has ‘‘addressed’’ a request for

the same stranded costs but has not

allowed 100 percent recovery.705

ELCON gives two hypothetical

examples to which it asks the

Commission to respond: one where a

state regulatory authority possesses full

stranded cost recovery authority but

allows only 50 percent recovery; the

other where the state legislature

provides the state regulatory authority

by statute with the power to permit

recovery of up to 50 percent of

identified stranded costs.

Commission Conclusion

We reaffirm our conclusion that both

this Commission and the states have the

legal authority to address stranded costs

that result when retail customers obtain

retail wheeling in interstate commerce

from public utilities in order to reach a

different generation supplier, but that,

because it is a state decision to permit

or require the retail wheeling that

causes retail stranded costs to occur, we

will leave it to state regulatory

authorities to deal with any stranded

costs occasioned by retail wheeling. The

only circumstance in which we will

entertain requests to recover stranded

costs caused by retail wheeling is when

the state regulatory authority does not

have authority under state law to

address stranded costs when the retail

wheeling is required.

We will reject the requests for

rehearing that oppose any Commission

involvement in stranded costs

associated with retail wheeling

customers. We disagree with those

entities that challenge our conclusion

that both this Commission and the states

have the legal authority to address

stranded costs that result from retail

wheeling (variously described by those

entities as dual, concurrent, or joint

jurisdiction). The Commission

explained in detail in Order No. 888 the

legal basis for concluding that this

Commission and the state commissions

each have jurisdiction over separate

aspects of a retail wheeling

transaction.706 This Commission has

jurisdiction over the rates, terms, and

conditions of unbundled retail

transmission in interstate commerce by

public utilities. State commissions have

jurisdiction over local distribution

facilities and the service of delivering

electric energy to end users. Based on

our respective jurisdictions over

separate aspects of the retail wheeling

transaction, we believe either has the

authority to provide the former

supplying utility with an opportunity to

recover costs stranded when the

departing customer uses retail

transmission in interstate commerce to

reach a new supplier, but that here,

unlike the retail-turned-wholesale

scenario, the state commission should

be the primary forum because these

costs are stranded by the action of the

state. We would act only if the primary

forum is not available. We have made a

policy decision that this Commission

will step in to fill a regulatory ‘‘gap’’

that could result in no effective forum

under which utilities would have an

opportunity to seek recovery of

prudently incurred costs.

Several entities argue that the

Commission does not have jurisdiction

over stranded investment in retail

generating assets, that use of

Commission-jurisdictional transmission

does not change the character of the

costs that are stranded, that stranded

costs associated with retail wheeling

customers are not costs of providing

unbundled transmission service, but are

costs associated with providing what

was formerly bundled retail service, and

that only state regulators are in a

position to rule on the treatment of costs

that were allowed in retail rates

pursuant to state laws. While we agree

that stranded costs associated with retail

wheeling are costs that are retail in

character in the sense that they are in

retail bundled rates and become

stranded as a result of retail wheeling

required by the state commission, we do

not believe this precludes the

Commission from exercising

jurisdiction in the limited

circumstances of the Rule.

As an initial matter, we note that

there are rarely separate retail and

wholesale generating facilities. Retail

customers and wholesale requirements

customers get energy from the same

facilities, each buying a ‘‘slice of the

system.’’ Typically all generating assets

go into both the retail and the wholesale

rate bases for determining retail and

wholesale rates. Rates are determined by

allocating the total generating costs

among customer classes. The parties

confuse the issue before us to the extent

they suggest that state commissions, not

this Commission, have ‘‘jurisdiction’’

over certain ‘‘costs.’’ Neither the state

commissions nor this Commission has

exclusive jurisdiction over ‘‘costs.’’ Each

regulatory authority has jurisdiction to

determine ‘‘rates’’ for services subject to

its jurisdiction and, in determining

rates, may take into account all of the

costs incurred by the utility. Under

historical cost-of-service ratemaking,

each regulatory authority, in exercising

its respective ratemaking jurisdiction,

reviews the total costs incurred by a

utility to provide service and makes its

separate and independent determination

of what costs may be recovered through

rates within its jurisdiction.707

Generating costs continually shift

between retail and wholesale rates over

time.708
12412 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

709This is not a regulatory ‘‘gap’’ in the sense that

the Commission would be asserting authority over

matters not within its jurisdiction. However, the

Commission would be filling a regulatory ‘‘gap’’ to

the extent that the utility normally would have the

opportunity to seek approval from its state

regulatory commission to recover costs in retail

rates from a departing retail customer or to

reallocate those costs to other retail customers. In

circumstances where the utility does not have this

opportunity because the state regulatory authority

has no authority to address the issue, we may

appropriately fill this regulatory ‘‘gap’’ to permit

recovery from the departing customer through the

retail transmission rate.

710E.g., Utilities For Improved Transition,

Coalition for Economic Competition.

711FERC Stats. & Regs. at 31,784; mimeo at 439.

712Utilities For Improved Transition argues that,

based on Consolidated Edison Company of New

York, Inc., 15 FERC ¶61,174 at 61,405 (1981) and

other cases, the Commission has jurisdiction over

the entire delivery service (rendered on both the

transmission and local distribution facilities) as a

transmission transaction. Utilities For Improved

Transition submits that states do not have authority

over rates on local distribution facilities used to

complete a transmission transaction.

More importantly, both the state

commission and this Commission have

a responsibility to oversee the financial

health of the utilities we regulate. Each

has jurisdiction to make judgments

about recovery of the costs of the assets

in the utility’s total rate base. Utilities

are entitled to a regulatory forum that

can adjudicate claims that they are or

are not entitled to recovery of costs

incurred regardless of the initial retail or

wholesale ‘‘character’’ of those costs,

and we believe we have the authority

and obligation to fill a regulatory ‘‘gap’’

that could occur.709

In response to the argument that it is

solely the action of the state that allows

a retail customer to seek alternative

sources of supply and, as a result, there

is no nexus between the Commission’s

wholesale transmission rule and any

costs that might be stranded by a stateestablished customer choice regime, we

agree. Indeed, as we indicate in Order

No. 888, we decided to leave it to state

regulatory authorities to deal with any

stranded costs occasioned by retail

wheeling (with a limited exception)

because it is a state decision to permit

or require the retail wheeling in the first

instance that causes retail stranded costs

to occur. Our determination, as

explained above, is to fill any regulatory

gap that arises as a result of interstate

wheeling. We believe that it is necessary

for the Commission to act as a backstop

in this limited instance to ensure that

costs stranded as a result of retail

wheeling do not go unrecovered because

the state regulatory authority lacks the

authority under state law to address

such costs. At the same time, as we

stated in Order No. 888, we believe that

most states have a number of

mechanisms for addressing stranded

costs caused by retail wheeling. We

emphasize that this Rule is not intended

to preempt the exercise of any existing

state authority with respect to the

assessment of a stranded cost or

stranded benefits charge on a retail

customer that obtains retail wheeling.

In response to arguments that the

Commission’s decision will result in

second-guessing or interfering with a

state’s legislative processes and

decisions, we believe these arguments

are premature. As a general matter, we

do not expect that our decision to be a

backstop will interfere with legislative

decisions that specifically address

stranded cost matters and the scope of

the state regulatory authority’s authority

in determining stranded costs. If states

or parties to a retail stranded cost

recovery case brought before this

Commission believe that a Commission

decision on the issue would interfere

with state legislative decisions, they

should raise their arguments, and

support therefore, at that time.

We clarify that Order No. 888 does

not permit utilities to seek recovery

from the Commission of stranded costs

associated with retail wheeling

customers if a state regulatory authority

with authority to address retail

wheeling stranded costs has in fact

addressed such costs, regardless of

whether the state regulatory authority

has allowed full recovery, partial

recovery, or no recovery.

Rehearing Requests Supporting

Broader Jurisdiction Over Stranded

Costs Associated With Retail Wheeling

Customers

A number of entities seek rehearing of

the Commission’s decision not to serve

as a backstop for all stranded costs

associated with retail wheeling

customers. Some assert that the

Commission has the legal authority to

address independently stranded costs

that arise from retail wheeling and that

the Commission cannot lawfully

abdicate or delegate such authority to

the states.710 Coalition for Economic

Competition submits that the

Commission correctly concluded that it

has jurisdiction over retail transmission

rates, terms and conditions and the

authority to address retail wheeling

stranded costs. Thus, it argues that the

Commission is without the power to

make a ‘‘policy determination’’ that

results in the Commission not

exercising its legal authority over

stranded costs associated with retail

wheeling customers. It asserts that, just

as the Commission recognizes that it

‘‘cannot simply turn over its

jurisdiction’’ to the states to determine

facilities subject to Commission

jurisdiction,711 the Commission cannot

turn over its jurisdiction to establish

stranded cost charges that it correctly

determined it has the authority to

establish. Coalition for Economic

Competition argues that the

Commission should adopt a stranded

cost recovery policy similar to the

policy the Commission has adopted

with respect to the determination of

state/federal jurisdiction, whereby the

Commission would defer to state

stranded cost determinations so long as

they are consistent with the

Commission’s policy.

Utilities For Improved Transition

argues that the Commission’s authority

over public utility rates for the

transmission of electric power, both

wholesale and retail, is plenary and

exclusive. As a result, it submits that the

Commission may not avoid

responsibility for costs stranded by

transmission of retail power.712 Illinois

Power contends that Congress did not

authorize the Commission to reject

jurisdictional rate filings whenever the

Commission regards the state

commissions as a more convenient or

appropriate forum.

EEI and the Coalition for Economic

Competition contend that virtually all

retail stranded costs can only occur

through the vehicle of Commissionjurisdictional transmission in interstate

commerce. They submit that the

Commission, having recognized the

clear nexus between FERC-jurisdictional

transmission and stranded costs in the

retail-turned-wholesale context, cannot

fail to recognize the same clear nexus in

the retail wheeling context.

Utilities For Improved Transition says

that it is legally immaterial whether

stranded costs are caused by the

Commission’s ordering the transmission

or the states’ doing so; the determining

factor is who has the jurisdiction to

make the rates for the service, not who

has the jurisdiction to order the service.

Coalition for Economic Competition

and Utilities For Improved Transition

contend that the Commission must

consider stranded costs that arise from

retail wheeling in order to satisfy its

statutory obligation under the FPA to

‘‘set just and reasonable’’ rates.

Coalition for Economic Competition

maintains that FPA sections 201, 205

and 206 do not give the Commission the

flexibility to allow stranded costs in

certain jurisdictional wheeling rates

(e.g., wholesale wheeling and new

municipalizations) but to exclude them

from other jurisdictional wheeling rates

(e.g., retail wheeling, municipal
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12413

713EEI states that the Commission did not rebut

EEI’s argument that the Commission’s failure to

address all retail stranded costs was unduly

discriminatory.

714 In support of its argument, Coalition for

Economic Competition cites Federal Power

Commission v. Hope Natural Gas Company, 320

U.S. 591, 602 (1944); Duquesne Light Company v.

Barasch, 488 U.S 299, 307–08 (1989).

715Coalition for Economic Competition at 14.

716E.g., Centerior, Southern, SoCal Edison.

717We also explained that the case law they cite

(which they refer to again in their rehearing

requests) to support the proposition that an agency

is not authorized to abdicate its statutory

responsibility or to delegate to parties and

intervenors regulatory responsibilities is factually

distinguishable and inapposite. See FERC Stats. &

Regs. at 31,825 and note 765; mimeo at 554–55 and

note 765.

718The entities who argue that the Commission

has abdicated or delegated its jurisdiction to the

states misconstrue the Commission’s jurisdiction to

determine rates for unbundled transmission in

interstate commerce as somehow including

exclusive ‘‘jurisdiction’’ over ‘‘costs.’’ However, as

discussed above, neither this Commission nor the

state commissions has exclusive ‘‘jurisdiction’’ over

‘‘costs.’’ Rather, each has jurisdiction to determine

‘‘rates’’ for services subject to its jurisdiction. It is

in the course of determining ‘‘rates’’ for unbundled

transmission in interstate commerce that this

Commission can take into account various costs

incurred by a utility to provide jurisdictional

service. A state commission can take those same

costs into account in making its separate and

independent determinations of what costs may be

recovered through rates within its jurisdiction. See

note 707, supra, and accompanying text.

719Based on these same considerations, we reject

Coalition for Economic Competition’s request that

the Commission assume a backstop role for all

stranded costs associated with retail wheeling

customers but defer to state stranded cost

determinations so long as they are consistent with

the Commission’s policy.

annexation, and bypass).713 Utilities For

Improved Transition says that the just

and reasonable standard requires the

Commission to backstop the states to

ensure that there is full stranded cost

recovery. It objects that Order No. 888’s

disposition of jurisdiction creates a

problem of cross-class discrimination

(wholesale versus retail) and inter-class

discrimination (some retail versus the

remainder of the retail).

Coalition for Economic Competition

further argues that the Commission’s

failure to address all stranded costs

associated with retail wheeling

customers will result in an improper

taking under the Constitution.714 It also

argues that the Commission is not

permitted to disregard its findings in

Order No. 888 which, according to

Coalition for Economic Competition,

‘‘inexorably’’ lead to the conclusion that

Commission action on ‘‘all’’ stranded

costs (including retail wheeling,

municipal annexation, and bypass

stranded costs) is required.715

Illinois Power argues that the FPA

does not authorize the Commission to

discriminate among utilities based on

the state of their residence, and that the

Commission must allow all utilities to

seek interstate rate recovery of just and

reasonable retail stranded costs. Illinois

Power asserts that the Rule will lead to

the absurd, unduly discriminatory result

that utilities located in states whose

legislatures have failed to provide for

stranded cost recovery will be better off

than those located in states that provide

for only limited stranded cost recovery.

It supports use of the Commission’s

statutory authority to establish a

uniform, national method for retail

stranded cost recovery.

Coalition for Economic Competition

also contends that the Commission’s

decision to let the states deal with retail

stranded costs is arbitrary and

capricious because the Commission

failed to consider the arguments that

stranded cost opponents will make

before state commissions, such as that a

state lacks jurisdiction to impose

stranded cost charges or that the state

imposition of such charges may be

preempted or found to be an undue

burden on interstate commerce. It

further argues that the Commission’s

reliance on state jurisdiction over the

service of delivering electric energy to

the end user does not reflect reasoned

decisionmaking. It submits that the

Commission has failed to consider that

the sale of electric energy may take

place outside of the state into which the

energy is transmitted, in which case the

state commission may have no

jurisdiction over either the sale or the

transmission of the energy and,

accordingly, no authority to consider

stranded costs.

A number of entities ask the

Commission to act on requests for retail

stranded cost recovery when the state

commission lacks authority or has

authority to order recovery, but has

declined to do so or has only allowed

partial recovery.716

Lastly, TX Com notes that section

35.26(d) (dealing with recovery of retail

stranded costs) refers only to public

utilities. It suggests that the omission of

a reference to transmitting utilities

appears to be inadvertent and should be

corrected.

Commission Conclusion

The Commission will reject the

requests for rehearing of our decision

not to assume a backstop role for all

stranded costs associated with retail

wheeling customers. We explained in

Order No. 888 that commenters that

describe our action as an unlawful

abdication or delegation of authority

misconstrue the nature of our decision

to leave stranded costs associated with

retail wheeling customers (with a

limited exception) to state regulatory

authorities.717 We have not ‘‘abdicated’’

or ‘‘delegated’’ to state regulatory

authorities our jurisdiction over the

rates, terms, and conditions of retail

transmission in interstate commerce; if

retail transmission in interstate

commerce by a public utility occurs,

public utilities offering such

transmission must comply with the FPA

by filing proposed rate schedules under

section 205.718 Instead, we have made a

policy determination that the recovery

of stranded costs associated with retail

wheeling customers—an issue over

which either this Commission or state

commissions could exercise authority

by virtue of their jurisdiction over retail

transmission in interstate commerce and

over local distribution facilities and

services, respectively—is primarily a

matter of local or state concern for

which the primary forum should be the

state commissions. However, if the state

regulatory authority does not have

authority under state law to be the

forum to address stranded costs when

the retail wheeling is required, then we

will entertain requests to recover such

costs. As we explain above in response

to the rehearing petitioners that oppose

any Commission involvement in

stranded costs associated with retail

wheeling customers, we have made a

policy decision that this Commission

will step in to fill a regulatory ‘‘gap’’

that could result in no effective forum

under which utilities would have an

opportunity to seek recovery of

prudently incurred costs.719

We disagree with Coalition for

Economic Competition’s argument that

our findings in Order No. 888

‘‘inexorably’’ lead to the conclusion that

Commission action on ‘‘all’’ stranded

costs (including retail wheeling and

bypass stranded costs) is required, much

less that the Commission has ignored

the findings in Order No. 888. To the

contrary, as we explain in Section IV.J.1,

it is not the purpose of this Rule to

allow utilities an opportunity to seek to

recover ‘‘all’’ uneconomic costs that

might be stranded when a customer

leaves its utility supplier. We have fully

explained our reasons for adopting an

approach that, for purposes of stranded

cost recovery from wholesale

transmission customers, relies on the

nexus between stranded costs and the

use of transmission tariffs required by

this Commission and, for purposes of

stranded cost recovery from retail

customers, recognizes state commission

jurisdiction but fills potential regulatory

gaps that could arise in the transition to

new market structures.
12414 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

720 If the state regulatory authority is the forum

before which to seek recovery, the utility may make

whatever arguments it wishes regarding the justness

and reasonableness of its rates, as well as any

unconstitutional taking arguments it may have,

before the state forum. Further, it can pursue

appeals of unfavorable decisions through the state

court system.

721We note that the definition of ‘‘retail stranded

cost’’ in section 35.26(b)(5) mistakenly refers to ‘‘a

public utility or transmitting utility’’ (emphasis

added). We will revise the definition to remove the

reference to ‘‘transmitting utility.’’

722See also MO/KS Coms (the cost-shifting

problem does not arise because of a particular state

treatment of stranded costs; it arises because

Entergy insists on recovering 100 percent of its

costs even when some portion of the costs are not

economical).

We disagree with those entities that

contend that the Commission must

consider retail stranded costs in order to

satisfy our statutory obligation under

the FPA to set just and reasonable rates.

In determining just and reasonable rates

for jurisdictional transmission service,

which currently are determined on a

cost basis, the Commission satisfies its

statutory obligation under the FPA by

allowing utilities an opportunity to

recover their prudently incurred costs

plus a reasonable rate of return. As we

have explained above, this may include

the costs of use of the physical

transmission system, as well as

economic costs incurred by the utility

when it provides transmission service

(e.g., stranded costs). However, in

situations in which a state regulatory

authority has the authority to address

recovery of retail stranded costs, there is

no regulatory ‘‘gap,’’ and there is no

obligation for this Commission to

provide a second opportunity for

recovery.720

We reject arguments that FPA sections

201, 205 and 206 do not give the

Commission the flexibility to allow

stranded costs in certain jurisdictional

wheeling rates (wholesale wheeling and

new municipalizations) but to exclude

them from other jurisdictional wheeling

rates (retail wheeling in interstate

commerce and use of another utility’s

transmission tariff), and that this policy

somehow makes rates discriminatory.

Recovery of this type of cost through a

transmission rate is obviously not the

norm, but is necessitated by the need to

deal with the transition costs associated

with this Rule. As discussed in detail in

the Rule, the Commission has carefully

balanced the interests of utilities as well

as customers in concluding that the

opportunity for stranded cost recovery

through transmission rates should be

permitted in only two general

circumstances: (1) in the case of

wholesale stranded costs, where there is

a direct nexus to Commission-required

transmission access; and (2) in the case

of retail stranded costs, where there

otherwise would be a regulatory gap

because a state regulatory authority

lacks authority under state law to

address stranded costs at the time that

retail wheeling is required. We see

nothing in the FPA that precludes us

from exercising this flexibility and,

indeed, the parties have not pointed to

anything that, in our opinion, precludes

us from exercising this discretion.

We reject the argument that virtually

all stranded costs associated with retail

wheeling customers can occur only

through the vehicle of Commissionjurisdictional transmission in interstate

commerce, and therefore, that the same

nexus between FERC-jurisdictional

transmission and stranded costs that

exists in the retail-turned-wholesale

context is present in the retail wheeling

context. We also disagree that it is

legally immaterial whether stranded

costs are caused by the Commission’s

ordering the transmission or the states

doing so, and that the determining

factor is who has the jurisdiction to

make the rates for the service, not who

has the jurisdiction to order the service.

The opportunity for stranded cost

recovery set forth in this Rule is based

on the causal link between stranded

costs and the availability and use of the

Commission-required transmission

tariff. It is true that in both the retailturned-wholesale context and the retail

wheeling context there is a limited

nexus between stranded costs and

Commission-jurisdictional access since,

in both situations, the Commission has

jurisdiction over the rates, terms and

conditions of the transmission service

and, therefore, the authority to permit

stranded cost recovery through the

transmission rates. However, the causal

nexus to FERC-jurisdictional

transmission and stranded costs in the

two contexts (retail vs. retail-turnedwholesale) is different. In the retail

wheeling context, there is no causal

nexus between stranded costs and

transmission that has been ordered by

this Commission. In the retail-turnedwholesale context, in contrast, the

opportunity for a utility to seek recovery

of stranded costs is grounded on the

existence of a direct causal nexus

between stranded costs and

transmission that has been ordered by

this Commission.

We will reject the rehearing petitions

that ask the Commission to act on

requests for stranded cost recovery

associated with retail wheeling

customers not only when the state

commission lacks authority, but also

when the state commission has

authority but either has declined to use

it or has only allowed partial recovery.

As explained above, our decision to

entertain requests to recover stranded

costs caused by retail wheeling in a

limited circumstance (when the state

regulatory authority does not have

authority under state law to address

stranded costs when the retail wheeling

is required) is based on our

determination to fill any regulatory gap

that arises in association with interstate

transmission.

We will reject TX Com’s request that

the Commission clarify that section

35.26(d) (dealing with recovery of retail

stranded costs), which refers only to

public utilities, should also refer to

transmitting utilities. The Commission’s

decision to act as a limited backstop in

the case of stranded costs associated

with retail wheeling customers is based

on our jurisdiction under sections 205

and 206 of the FPA over the rates, terms,

and conditions of retail transmission in

interstate commerce. As a result, our

ability to allow the recovery of such

costs through a surcharge on a section

205 unbundled transmission rate is

necessarily limited to public utilities.721

Rehearing Requests Opposing

Commission Treatment of Stranded

Costs Associated With Retail Wheeling

Customers in Holding Company IntraSystem Agreement Cases

A number of entities oppose the

Commission’s proposal to address on a

case-by-case basis whether

jurisdictional intra-system agreements

may need to be amended in order to

prevent inappropriate cost-shifting that

could occur if one state disallows

stranded cost recovery associated with

retail wheeling customers. IN Com

objects that the problem is not the

actions of one state or another, but

rather the terms of the intra-system

agreement.

AR Com objects that Order No. 888 is

factually in error because a state’s

treatment of retail stranded costs under

the Entergy System Agreement cannot

shift costs to other jurisdictions.722 It

submits that whenever retail load

changes, whether due to retail wheeling

or any other factor, responsibility ratios

under Entergy’s reserve equalization

schedule, MSS–1, will change and costs

will shift irrespective of the regulator’s

treatment of retail stranded costs. AR

Com says that MSS–1 reveals no

changes in calculations due to retail

treatment of stranded costs or any other

retail ratemaking; only ‘‘excess’’

capacity costs of intermediate gas- and

oil-fired plant are ‘‘shifted’’ under the

Entergy System Agreement. Although

the Commission has the authority to

amend intra-system agreements when
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12415

723AR Com also objects to the Commission’s

description of the issue as involving not only

holding companies, but also other multi-state

situations. AR Com says that ‘‘[t]he mere fact that

a company’s territory crosses state lines does not

automatically mean that all assets serve all

customers, or that all customers are required to bear

the economic risk associated with all assets, or that

assets that at one time were solely statejurisdictional can somehow, by virtue of a

company’s decision to expand across state lines,

become FERC-jurisdictional.’’ AR Com at 11.

724FERC Stats. & Regs. at 31,831; mimeo at

570–72.

725FERC Stats. & Regs. at 31,831; mimeo at 572.

We indicated that the same procedures would apply

to retail customers that obtain retail wheeling.

726FERC Stats. & Regs. at 31,831; mimeo at

572–73.

wholesale cost allocations have become

unjust and unreasonable, AR Com

submits that the Commission does not

have jurisdiction to reach to the state

level and dictate what retail ratepayers

should pay to shareholders. AR Com

maintains that a FERC-jurisdictional

intra-system agreement extends only to

sales for resale (transactions among

subsidiaries), and that if a holding

company believes that an intra-system

agreement is unduly discriminatory as a

result of a state’s disallowance of costs,

the holding company can propose to

amend it.723

AR Com argues that retail stranded

costs fall to state jurisdiction regardless

of whether the utility is a member of an

interstate holding company. AR Com

says that because the costs at issue are

in retail rate base, any Commission

influence over their recovery could

occur only through preemption, but

preemption of a state disallowance from

retail rate base is possible only if there

is a ‘‘trapped cost.’’ AR Com submits

that a disallowance of retail rate base

cost cannot result in a trapped cost

because there is no inconsistency

between two agencies acting within

their jurisdiction; the Commission has

no jurisdiction to act. AR Com

maintains that, unlike the Grand Gulf

situation, the Commission has not

mandated any Entergy generation costs

into retail rate base. It further says that

different state decisions regarding

recovery of retail costs are not

inconsistent decisions; they represent

each state applying its law to its facts.

According to AR Com, decisions by

states leading to less than full recovery

could be deemed inconsistent decisions

only if there were a federal guarantee of

full cost recovery of retail costs, which

there is not.

AR Com and MO/KS Coms assert that

the Commission’s proposal for holding

company situations cannot apply to

future holding companies, where there

is no history of joint planning justifying

cost equalization, nor can it apply to

future investments. They contend that

this would require an assumption that

the utility subsidiaries of a registered

holding company have planned, and

should plan, together rather than

separately (i.e., that interaffiliate

transactions are always more efficient

than nonaffiliate transactions), and that

such assumption would be sound only

if having the transaction occur between

affiliates is inherently more efficient

than having the transaction occur

between an affiliate and a nonaffiliate.

Commission Conclusion

The comments raised for the most

part are either premature or reflect a

misunderstanding of the Commission’s

decision. Contrary to AR Com’s

argument, the Commission in Order No.

888 in no way asserted jurisdiction over

state determinations of stranded costs

associated with retail wheeling

customers. We agree with AR Com that

our jurisdiction extends only to sales for

resale (and transmission in interstate

commerce) and that a holding company

can seek to amend an intra-system

agreement if it believes the agreement is

unduly discriminatory as a result of a

state’s disallowance of costs. However,

a holding company also may seek to

amend an agreement before any

potential disallowances can occur, to

keep cost-shifting from occurring. The

fact is that intra-system agreements

which involve wholesale sales among

affiliate companies in different states

could, through operation of their reserve

equalization formulas, result in

customers in one or more states having

to indirectly bear stranded costs that are

disallowed in another state, and the

Commission has a responsibility to

prevent inappropriate cost-shifting.

Such determinations can be made only

on a case-by-case basis. Again, as we

stated in Order No. 888, we encourage

affected state commissions to propose

mutually agreeable solutions to this

potential problem.

8. Evidentiary Demonstration

Necessary—Reasonable Expectation

Standard

In Order No. 888, the Commission

concluded that a utility seeking to

recover stranded costs must

demonstrate that it had a reasonable

expectation of continuing to serve a

customer. We stated that whether a

utility had a reasonable expectation of

continuing to serve a customer, and for

how long, will be determined on a caseby-case basis, and will depend on all of

the facts and circumstances. We also

determined that the existence of a notice

provision in a contract would create a

rebuttable presumption that the utility

had no reasonable expectation of

serving the customer beyond the

specified period. We said that whether

or not a contract contains an

‘‘evergreen’’ or other automatic renewal

provision will be a factor to be

considered in determining whether the

presumption of no reasonable

expectation is rebutted in a particular

case.724

We also said that we would apply the

reasonable expectation standard to

retail-turned-wholesale customers. We

explained that, before the Commission

will permit a utility to recover stranded

costs, the utility must demonstrate that

it incurred such costs based on a

reasonable expectation that the retailturned-wholesale customer would

continue to receive bundled retail

service. Whether the state law awards

exclusive service territories and imposes

a mandatory obligation to serve would

be among the factors to be considered in

determining whether the reasonable

expectation test is met in a particular

case.725

We noted that Order No. 888 does not

address who will bear the stranded costs

caused by a departing generation

customer if the Commission finds that

the utility had no reasonable

expectation of continuing to serve that

customer. We indicated that we

anticipate that, in such a case, a public

utility will seek in subsequent

requirements rate cases to have the costs

reallocated among the remaining

customers on its system. However, we

stated that we were not prejudging that

issue in the Rule.726

Rehearing Requests Opposing or

Seeking Modification of the Reasonable

Expectation Standard

APPA challenges the reasonable

expectation standard as being too vague.

It submits that the Commission has

provided no guidance concerning

application of the reasonable

expectation standard, other than to state

that it would decide the issue on a caseby-case basis. APPA objects that public

utilities can exploit the uncertainty

created by this standard, which will

lead to costly and time-consuming

litigation. IL Com supports replacing the

reasonable expectation standard with a

statutory, regulatory, contractual

standard.

Several entities contend that there is

no basis to conclude that the reasonable

expectation test could ever be met. VT

DPS and Valero submit that, since 1973,

utilities have known that a refusal to

wheel power could subject them to

antitrust liability. They say that Order

No. 888 ignores the breadth of NRC
12416 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

727AMP-Ohio submits that where transmission

access and competition have existed to varying

extents for decades, there should be an irrebuttable

presumption of no reasonable expectation of

continued service.

728E.g., APPA, American Forest & Paper, Central

Montana EC, NRECA, TDU Systems, Oglethorpe,

IMPA, VT DPS, Valero, PA Munis.

729E.g., APPA, NRECA, TDU Systems. See also

VT DPS and Valero (by signing a contract with a

termination date, the utility assumed the risk that

the customer will elect to leave when the contract

expires).

730 In support of its argument, PA Munis cites

Boston Edison Company, 56 FPC 3414 (1976). See

also American Forest & Paper.

731Citing Kentucky Utilities Company, 23 FERC

¶ 61,317 (1983); Philadelphia Electric Company and

Susquehanna Electric Company, 65 FERC ¶ 61,303

(1993).

732E.g., NRECA, IMPA, PA Munis.

733FERC Stats. & Regs. at 31,665, 31,813–14;

mimeo at 87, 522.

licensing conditions. LEPA similarly

argues that the reasonable expectation

standard could not be met where NRC

license conditions required an explicit

wheeling commitment and prohibited

the utility from including in the

wheeling cost any amount attributable

to the loss of customers due to the

wheeling. It objects that delaying a

decision on stranded cost recovery in

such cases holds the threat of possible

stranded cost charges over the heads of

bulk power purchasers and thereby

chills their ability to seek competitive

sellers.

TAPS asserts that there should be an

irrefutable presumption that no

stranded costs are due from customers

with pre-existing transmission rights,

including customers who were the

beneficiaries of NRC license

conditions.727 TAPS submits that there

can be no legitimate ‘‘reasonable

expectation’’ that such customers would

continue to purchase power if the price

was higher than the market price.

Occidental Chemical asks the

Commission to clarify that a utility

could have had no reasonable

expectation of recovering stranded costs

from customers who, prior to the

issuance of the NOPR, had the

opportunity to switch to an alternative

electric supplier or had the option of

self-generating, obtaining on-site thirdparty generation, or municipalizing.

Occidental Chemical further argues that

it defies commercial expectations to

allow a utility to argue that if a contract

is silent on the issue of renewal, the

obligation to purchase does not expire

with the termination of the contract. It

submits that the Commission has not

shown that it has the authority to force

customers to extend purchase

agreements against their will in

violation of accepted commercial

practice.

A number of entities submit that the

Commission erred in failing to treat a

notice of termination provision as

conclusive evidence that the utility had

no reasonable expectation of continued

service.728 Several object that the

Commission has failed to explain why

the presence of a notice provision does

not conclusively demonstrate the lack of

a reasonable expectation and ipso facto

terminate the obligation of the customer

to purchase the product.729 APPA

objects that the Commission provided

no evidence that it considered

comments supporting making the

presumption conclusive and that it

found legally sufficient reasons to reject

them.

PA Munis objects that the rebuttable

presumption represents an unjustified

departure from the Commission’s

traditional policy of enforcing the

express terms of notice provisions

without any inquiry into the reasonable

expectations of the party, provided that

the agreements were negotiated in good

faith and approved by the

Commission.730 PA Munis contends that

wholesale requirements customers

negotiated notice provisions with the

knowledge that the Commission would

enforce the notice provisions according

to their terms, including the specific

length of the term. 731 PA Munis argues

that it is arbitrary and capricious to

provide utilities an opportunity to seek

to amend these contracts.

Several entities submit that the

rebuttable presumption invites litigation

and promotes uncertainty for

customers.732 APPA objects that the

Commission has failed to establish the

showing that it would require to

overcome the presumption.

Referring to the Commission’s

discussion of evergreen provisions,

Central Montana EC argues that it is

wrong to infer from the existence of an

automatic renewal provision that the

parties intended that the contract might

run longer than its initial term. Central

Montana EC asserts that the presence of

an evergreen provision infers simply

that the parties agreed upon a

mechanism to avoid the renegotiation of

a power supply contract if, at the

conclusion of its initial term, the parties

were satisfied with the contract. It

maintains that the parties’ obligations

are defined by the term and termination

provisions of wholesale power

contracts, and that the presence of a

mechanism to avoid contract

renegotiation does not alter those

termination rights.

Commission Conclusion

We will reject the requests for

rehearing of our decision to adopt a

reasonable expectation standard to be

applied on a case-by-case basis and to

treat a notice provision in a contract as

a rebuttable, not a conclusive,

presumption of no reasonable

expectation. Contrary to the claims of

some entities, the Commission has

explained the basis for its finding that

utilities may have had an implicit

obligation to serve their wholesale

requirements customers and, therefore,

that a utility should be given an

opportunity to demonstrate that it

incurred costs to provide service to a

customer and that it had a reasonable

expectation that it would continue to

serve the customer beyond the contract

termination date. The same factors that

some petitioners contend establish the

absence of a reasonable expectation of

continued service may be offered as

evidence to be considered in

determining whether the reasonable

expectation test is met in a particular

case.

We believe that our decision to treat

a notice of termination provision in a

contract as creating a rebuttable

presumption that the utility had no

reasonable expectation of serving the

customer beyond the period provided

for in the notice provision is a

reasonable one. It places evidentiary

significance on the fact that a contract

contains a notice of termination

provision. Moreover, while it gives the

utility an opportunity, based on the

facts and circumstances of a particular

case, to rebut the presumption of no

reasonable expectation, it firmly places

the burden of establishing reasonable

expectation on the utility. Although

some entities support treating notice

provisions as a conclusive presumption

of no reasonable expectation, as

discussed below, we decline to adopt

such an inflexible approach.

Nevertheless, as we indicated in Order

No. 888, when a utility is seeking a

contract amendment to permit stranded

cost recovery based on expectations

beyond the stated term of the contract,

we believe that the utility has a heavy

burden in demonstrating that the

contract ought to be modified.733

Contrary to the position of PA Munis,

the rebuttable presumption is fully

consistent with the Commission’s past

treatment of notice provisions. For

example, the Kentucky Utilities

Company case cited by PA Munis

supports the proposition that, until a

customer exercises a notice of
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12417

734See Kentucky Utilities Company, 23 FERC at

61,679–80 (‘‘Once it receives an effective notice of

cancellation, Kentucky can stop planning for the

future needs of that customer. . . . To be effective

a notice of cancellation must contain a specification

of the source of supply, the date on which the

source of supply will be available, and an affidavit

from the supplier that it will supply the customer

on the date the contract ends.’’).

735See Potomac Electric Power Company, 43

FERC ¶ 61,189 (1988) (suspending a notice of

termination for five months due to questions about

the impact of the proposed cancellation on service

reliability).

736E.g., EEI, Oklahoma G&E, Southern, Florida

Power Corp, Utilities For Improved Transition.

termination provision, the utility is

under an implicit obligation to continue

to serve and plan for the future needs of

the customer.734 Thus, the presence of a

notice of termination provision in a

contract (particularly one not yet

exercised by the customer), in and of

itself, may not necessarily support the

conclusion that the utility could never

prove that it reasonably expected to

continue serving the customer beyond

the notice period.735

In response to APPA’s objection that

the Commission has failed to establish

the showing that it would require to

overcome the presumption, we note that

the Commission cannot establish such a

showing upfront because whether there

is sufficient evidence to rebut the

presumption of no reasonable

expectation will depend on the facts of

each case.

We appreciate the concerns expressed

by some entities that the rebuttable

presumption may increase the

customer’s uncertainty by inviting

litigation. We have carefully weighed

the pros and cons of treating a notice

provision as a rebuttable presumption of

no reasonable expectation versus the

pros and cons of treating it as a

conclusive presumption of no

reasonable expectation. It is true, as

some entities assert, that the rebuttable

presumption approach presents the

potential for litigation between the

parties as to whether, in a particular

case, the utility can rebut the

presumption. The alternative would be

to treat all contracts with notice of

termination provisions as conclusive

evidence that the utility could have had

no reasonable expectation that it would

continue to serve the customer beyond

the specified notice period. While the

latter approach presumably would

reduce the number of cases in which the

issue of a utility’s reasonable

expectation would have to be litigated,

it would do so only by prohibiting a

utility from ever demonstrating that,

notwithstanding the existence of a

notice provision, based on the facts of

a particular case, the utility reasonably

expected to continue serving the

customer. While we do not prejudge the

likelihood of a utility being able to rebut

the presumption in a particular case, we

believe that it would not be in the

public interest for the Commission to

absolutely preclude a utility from being

able to make such a showing. On this

basis, we conclude that treating a notice

provision as a rebuttable, rather than a

conclusive, presumption that the utility

did not have a reasonable expectation of

continuing service to the customer is, on

balance, the fairer and more equitable

approach.

Central Montana EC asserts that it is

wrong to infer from the existence of an

automatic renewal provision that the

parties intended that the contract might

run longer than its initial term.

However, our statement in Order No.

888 that the existence of an automatic

renewal provision will be a factor to be

considered in determining whether the

presumption of no reasonable

expectation is rebutted in a particular

case makes no such inference. Whether

the utility can rebut the presumption

will depend on the facts of each case.

Rehearing Requests Supporting

Modification of Evidentiary Standard

for Retail Customers

Several entities ask the Commission

to consider adopting a rebuttable

presumption that utilities had a

reasonable expectation of continuing to

serve any retail load for which they had

a public utility obligation to serve. They

submit that the burden should be on the

former bundled retail customer to show

that the utility’s service obligation was

not binding and that the utility’s

expectation of continuing service was

unfounded.736 Florida Power Corp and

Utilities For Improved Transition

suggest that the only exception to such

a rebuttable presumption should be for

retail customers that gave notice of

termination before the effective date of

the Rule. EEI expresses concern that the

issue may be wrongly decided on the

existence (or lack) of an exclusive

franchise. It states that while many

states do award franchises delineating

exclusive service territories, some do

not, even though long-established

service arrangements are in place. Puget

submits that because there is a duty to

serve all retail customers, Order No. 888

should provide for stranded cost

recovery from all departing retail

customers without application of a

reasonable expectation test.

NY Com, on the other hand, opposes

application of the reasonable

expectation standard to stranded costs

associated with retail-turned-wholesale

customers. It argues that the reasonable

expectation test would ignore prudence,

customer impact, financial viability and

a series of criteria traditionally analyzed

by state regulatory agencies in

determining rate treatment of costs

incurred with the intention of providing

service.

Commission Conclusion

We will deny the requests for

rehearing of the Commission’s decision

to apply the reasonable expectation

standard to retail-turned-wholesale and

retail wheeling customers on a case-bycase basis without adopting a rebuttable

presumption that utilities had a

reasonable expectation of continuing to

serve any retail load for which they had

a public utility obligation to serve.

When a utility seeks to recover stranded

costs from former bundled retail

customers, we think it is appropriate

that the utility bear the burden of

proving reasonable expectation (instead

of requiring the customer to bear the

burden of disproving the utility’s

reasonable expectation). Placing the

burden on the utility is consistent with

the requirement of sections 205 and 206

of the FPA that a public utility

demonstrate the justness and

reasonableness of its proposed rates.

The same factors that are offered as

support for the establishment of a

rebuttable presumption of a reasonable

expectation (such as the utility’s

obligation to serve all retail customers)

may be offered by the utility as evidence

to be considered in determining

whether the reasonable expectation test

is met in a particular case.

We also will deny NY Com’s request

that the Commission not apply the

reasonable expectation standard to

retail-turned-wholesale customers. We

believe it is appropriate to require the

same evidentiary demonstration for

recovery of stranded costs from a retailturned-wholesale customer as that

required in the case of a wholesale

requirements customer. Moreover, as

discussed in Section IV.J.7 above, the

reasonable expectation standard

contemplates evidence as to what a

utility might reasonably expect to

recover under state law, and we will

give great weight to a state’s view of

what might be recoverable.

9. Calculation of Recoverable Stranded

Costs

In Order No. 888, the Commission

considered various proposals regarding

how stranded costs should be calculated

and who should pay. With respect to the

calculation of stranded costs, the

Commission rejected as overly

complicated and costly an asset-by-asset
12418 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

737Briefly, SCO refers to the departing customer’s

stranded cost obligation, which is determined by

taking the average annual revenues that the

customer would have paid had it remained a

customer of the utility (RSE), and subtracting from

it the competitive market value of the power (on an

average annual basis) no longer taken by the

departing customer (CMVE). The difference

represents the average annual stranded cost, which

must be multiplied by ‘‘L’’ (L represents the period

over which the utility reasonably could have

expected to serve the departing customer beyond

the contract termination, but for the open access

required under Order No. 888) to produce the

departing customer’s total SCO.

738FERC Stats. & Regs. at 31,839–40; mimeo at

595–99.

739E.g., TDU Systems, APPA, Central Vermont,

ELCON.

740E.g., TDU Systems, NRECA, Central Montana

EC, SoCal Edison.

741See also Coalition for Economic Competition

at 47.

742E.g., Central Vermont, Texaco, Carolina P&L.

743 80 F.3d 526 (D.C. Cir. 1996) (Town of

Norwood).

744E.g., EEI, Utilities For Improved Transition,

VEPCO, Coalition for Economic Competition.

approach to determine the amount of

stranded costs assigned to a departing

customer. Instead, the Commission

determined that the revenues lost

approach was the fairest and most

efficient way to make this determination

during the transition to a competitive

wholesale bulk power market. The

Commission adopted the following

revenues lost formula for calculating the

stranded cost for each departing

customer: SCO¥(RSE—CMVE)×L. The

Commission provided a precise

definition for each component of the

formula,737 and made the application of

the formula, and collection of the

resulting stranded costs, subject to a

number of conditions.738

RSE Issues

Numerous petitioners oppose the use

of present revenues in the stranded cost

formula.739 TDU Systems argues that the

revenues lost approach is arbitrary and

capricious because its effect exceeds its

purpose. Specifically, TDU Systems

contends that the revenues lost

approach can permit overrecovery

because it provides recovery of any

difference between pre-Order No. 888

cost-plus rates and post-Order No. 888

competitive rates, regardless of the

cause of the difference. TDU Systems

cites enhanced utilization and

technological improvements as two

examples of pre-and post-Order No. 888

rate differences that are not competition

related, but for which recovery would

be provided. TDU Systems states that

instead of using present revenues, RSE

should be calculated based on the most

current, reliable estimate of future

revenues.

Multiple Intervenors argues that the

revenues lost method assumes that a

utility’s costs of operating its plants are

per se reasonable, yet the New York

utilities’ current rates include levels of

O&M, especially wages and benefits,

expenses that may reflect inefficiencies

and thus are not stranded costs for

which a utility’s shareholders should be

compensated. Similarly, other

petitioners oppose as backward-looking

the use of present revenues for what

should be a forward-looking remedy,

consistent with the other elements in

the formula.740 TDU Systems argues that

the use of past revenues is inappropriate

in a falling cost environment, and notes

that new capacity costs are less than the

existing capacity costs embedded in a

utility’s rate base.

NYSEG states that the Commission

should permit a utility to reconcile

initial stranded cost charges to actual

stranded costs on a periodic basis to

account for changes in sales, energy

purchases from NUGs, and changes in

market price. NYSEG supports

development of stranded cost charges

based on three-year estimates. Under

this approach, a customer would pay

locked-in charges for a series of threeyear periods. At the end of each period,

the stranded cost estimate would be

revised for the next three-year period.

This process would continue until all

stranded costs are recovered.741 Other

petitioners support the use of a

projected revenue stream or a true-up

mechanism.742 These petitioners argue

that a true-up mechanism is necessary

to protect all parties against the

inevitable risk of inaccurate forecasts.

ELCON argues that calculating RSE

based upon customer usage over the

past three years results in an artificially

high stranded cost because it fails to

take into account that the utility would

have had to reduce its prices in the

future in response to competition.

ELCON states that wholesale customers

have a reasonable expectation that

utility costs will be lower in the future,

and thus that the annual revenues

contributed by a customer who remains

with the utility would be lower than

RSE. ELCON further contends that the

revenues lost formula should not

guarantee the profits the utility was

allowed to receive prior to the issuance

of Order No. 888 because such revenues

included a risk factor (e.g., plant

operating risk, or risk of customer

insolvency) that is absent under the

direct assignment method of allocating

stranded costs. ELCON cites Town of

Norwood v. FERC743 as support for its

position that the RSE should be reduced

to reflect the decreased risk associated

with the direct assignment approach.

TDU Systems and NRECA also argue

that the Commission should eliminate

from RSE the risk component of the

return on equity contained in present

rates. They argue for this adjustment

because the Commission is eliminating

the risk associated with non-recovery of

plant costs by providing full recovery of

stranded costs. NRECA further contends

that if the Commission keeps the equity

return in the calculation of stranded

costs, it should permit a consumerowned system to include an imputed

equity component in its RSE if it needs

to recover stranded costs.

APPA argues that the use of present

revenues fails to reflect future cost

reductions expected from accumulated

depreciation, load growth, and

declining capital costs. APPA further

opposes the use of present revenues

because present revenues are the direct

product of the monopoly power that the

utility exercised over transmission.

APPA states that RSE should be

calculated based upon the price of

wholesale power in a competitive

market.

CCEM argues that only fixed costs

should be eligible for recovery, and that

this amount should exclude any return

on investment. CCEM would exclude

variable costs from the calculation of

stranded costs because allowing

recovery of variable charges would

encourage the continued operation of

facilities that are conceded to be

uneconomic. CCEM further contends

that the Commission should provide

less than full recovery of stranded costs

so that the utility has some incentive to

mitigate them.

Central Vermont states that where the

contract does not commit the customer

to a set amount of service, the utility’s

reasonable expectation of the amount of

continuing service will not necessarily

be reflected in the revenues of the three

previous years. Central Vermont urges

the Commission to allow utilities the

option of showing that their actual

reasonable expectation of continued

service differs from historical

experience. Central Vermont maintains

that any other approach would be less

than reasonable, and, in fact, would be

arbitrary and capricious.

Numerous petitioners 744 would retain

the use of present revenues as the RSE;

however, they support a limited

exception that would permit a utility to

seek recovery of certain future cost

increases (primarily nuclear

decommissioning costs, back-loaded

PURPA contract costs, and other

deferred costs) if those costs are not in

rates now or are in rates but are being

under-recovered at present. These
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12419

745The use of present revenues is reasonably

workable from an administrative standpoint.

746Our rationale here is equally applicable to

APPA’s argument that RSE should be based upon

the price of wholesale power in a competitive

market.

petitioners argue that the majority of

these costs were incurred as a result of

various regulatory mandates, with the

reasonable expectation of future

recovery in rates. As a part of their

proposal, Utilities For Improved

Transition and EEI (and others) support

offsetting such cost increases with any

decreases in other costs reflected in

present revenues. Utilities For Improved

Transition maintains that nuclear

decommissioning costs, in particular,

should be revisited as they become

better defined. Similarly, Nuclear

Energy Institute and others request that

the Commission allow a utility, on a

case-by-case basis, to propose its own

recovery mechanism, as nuclear

decommissioning costs are significantly

different from other future cost

increases.

Lastly, TDU Systems and NRECA

object to the manner by which the

formula deducts average transmissionrelated revenues (which would be

unbundled in the utility’s new open

access tariff) in the development of RSE.

TDU Systems and NRECA contend that

the transmission credit, because it is

based on the revenues that would be

generated under a utility’s new

wholesale tariff, would not reflect that

the cost of transmission has been

declining.

Commission Conclusion

In Order No. 888, the Commission

stated that the use of ‘‘present’’ annual

revenues as the basis for the stranded

cost calculation has numerous

advantages over other approaches

advocated. The Commission noted that

the use of present revenues (1)

eliminates disputes over estimates of

future revenues, providing certainty to

the calculation; and (2) eliminates the

need for a detailed listing and litigation

of includable costs, relying instead on

the presumption that present rates

include all just and reasonable costs of

providing service. The Commission

further noted that the rates that produce

present revenues have been approved by

regulators, which strongly suggests that

the costs included in them are prudent,

legitimate and verifiable.

The Commission continues to believe

that the use of present revenues as the

basis for the stranded cost calculation is

superior to other proposed methods.

Arguments that the use of present

revenues either over-or under-recovers

‘‘true’’ costs are not persuasive. Either

the customer or the utility may file for

a change in rates before the existing

contract ends if it believes the existing

rate is inappropriate.

In response to petitioners requesting

an RSE based on estimates of future

revenues for the reasonable expectation

period (L), we continue to believe that

an approach based on estimates of

future revenue streams would engender

countless disputes over the RSE

component in the formula with little, if

any, added accuracy. These would in

effect be rate cases that attempt to

litigate not what costs were during a test

year based on audited accounting data,

but what costs will be, based on

speculation about future fuel costs,

employment levels, capital costs, and so

on. In contrast, we believe that the use

of present revenues will produce fair

results and minimize litigation of RSE.

This is appropriate for a transition

period cost recovery charge that needs

to be settled quickly for market

participants to make business decisions

about future wholesale sales and

purchases. Our approach minimizes

transaction costs and provides greater

certainty with respect to the RSE term

in the formula.

Some have argued that a method that

periodically adjusts the departing

customer’s stranded cost obligation in

the future to reflect actual future

increases or decreases in a utility’s

future cost-based rates would produce

more accurate results. However, this

‘‘true-up’’ approach has several

difficulties. First, it assumes that the

utility will have wholesale cost-based

rates in the future. Many utilities

already sell in the wholesale market at

market-based rates, and this trend is

accelerating. Having a series of ongoing

rate cases solely for the purpose of

trueing-up a stranded cost calculation

would be cumbersome and costly. It

would eliminate much of the regulatory

cost savings that result from marketbased rates. Further, even if ‘‘costbased’’ rates were on file in the future,

many such future wholesale rates, as in

the past, are likely to result from

settlements among the parties. Such

settlements are agreements on prices

that do not necessarily spell out the cost

components of the final agreed-upon

rate.

These difficulties aside, the true-up

approach would introduce a great deal

of ongoing uncertainty about the

departing customer’s stranded cost

obligation. This uncertainty would add

unnecessary risk for both the customer

and the utility as they consider

alternative purchase or sales

transactions. Customers would have no

way of knowing what their ultimate

stranded cost charge would be, and

therefore would be unable to evaluate

definitively whether changing suppliers

would be beneficial. Under a true-up

approach, the eventual sum of the

customer’s SCO and replacement power

cost could be more or less than the

amount it would have paid had it

simply stayed with its host supplier.

This possibility could discourage many

customers from taking advantage of the

open access provided by Order No. 888.

We believe that any potential accuracy

benefit of a true-up approach is greatly

outweighed by the cost, uncertainty,

delay, and litigation such an approach

would cause.

In summary, we believe that the use

of present revenues as the basis for

calculating stranded cost appropriately

balances precision and efficiency 745 for

what is fundamentally a transition

period policy.

In response to the other arguments

raised, the Commission makes the

following findings. We disagree with

ELCON that the use of present revenues

will result in an artificially high

stranded cost because it fails to account

for the fact that a utility would have to

lower its prices to respond to new

competition. ELCON’s argument is

circular in that much of the new

competition to which it refers results

from our issuance of Order No. 888.

ELCON’s approach would undo the goal

of providing recovery of stranded costs

by eliminating the very difference that

the formula is intended to determine.

746 ELCON’s argument is rejected

accordingly.

In addition, ELCON’s reliance on

Town of Norwood (for the proposition

that RSE should be reduced to reflect

the reduced operating risk and reduced

risk of customer insolvency associated

with direct assignment of stranded

costs) is misplaced. In Town of

Norwood, the Commission was faced

with a request for recovery of plant

costs. The utility made a cost-effective

proposal to shut down its single asset,

a small nuclear reactor. In that case, the

Commission disallowed full return on

investment in part because the unit was

no longer operating and the utility had

no operating risk.

Elimination of the rate of return is

inappropriate because, unlike Town of

Norwood, the departing customer’s

service is not tied to any particular unit;

rather, service is considered to be

provided by the entire system. Contrary

to ELCON’s assertion, operating risk is

not reduced because the utility must

continue to operate its generating

facilities (by reselling the capacity) if it

is to recover all its costs. Accordingly,
12420 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

747 In addition, Order No. 888 provides recovery

of only the difference between the average annual

revenues that the customer would have paid had it

remained a customer (RSE) and the estimated

competitive market value (CMVE) of the released

power (i.e., the stranded cost). However, while the

formula contemplates that the utility can sell the

released power at the estimated competitive market

value, the actual market value may be lower,

increasing the risk that the utility will not be able

to recover its stranded costs.

748 In Order No. 888, the Commission rejected

arguments that return-related revenues be excluded

from the revenue stream. The Commission found

that such exclusion would effectively require

shareholders to absorb stranded costs, which is

contrary to the Commission’s finding that a utility

is entitled to an opportunity to fully recover

legitimate, prudent and verifiable stranded costs. In

this order, we reaffirm our earlier finding.

749FERC Stats. & Regs. at 31,840; mimeo at 597.

750Present revenues depend, of course, on both

price and quantity. Most petitioners who dispute

the use of present revenues argue, in some fashion

or another, that present revenues are inappropriate

because the costs included in present revenues may

not equate to the costs incurred by the utility during

L. These petitioners are arguing about price.

there is not a reduced operating risk as

argued by ELCON.

With respect to ELCON’s customer

insolvency argument, this risk is also

present under the direct assignment

approach. Because Order No. 888

permits a customer to pay its stranded

cost obligation over a number of years,

during this period the customer could

become insolvent, thereby leaving the

utility with uncollected stranded

costs.747

Also, unlike Town of Norwood, the

utility is presently collecting rates that

compensate for traditional utility risks,

but do not include the risk of open

access. Further, eliminating the rate of

return would engender considerable

complication, speculation and expense

as the Commission would have to

determine an appropriate rate of return

that included some risks (e.g., customer

bankruptcy) but not others (e.g., 211

request or use of the open access tariff).

Thus, eliminating the rate of return (or

a portion thereof) is inappropriate.

Accordingly, ELCON’s arguments that

the revenue stream should be reduced to

reflect lower risk associated with direct

assignment is rejected. Instead, we

continue to believe that the

transmission provider is entitled to

recover all the costs, including return on

equity, that it incurred based on a

reasonable expectation of having to

serve the departing customer. All these

costs would have been recoverable

absent the action taken in Order No.

888.748

The Commission also rejects NRECA’s

proposal to include an imputed equity

component in the RSE when calculating

stranded costs for a consumer-owned

system. Simply put, if a cost is not

stranded, or if a cost is not really a cost,

recovery should not be granted.

The Commission rejects APPA’s

contention that it is inappropriate to use

present revenues as the RSE because

those revenues are the direct product of

the monopoly power that the utility

exercised over transmission. The

Commission believes that the use of

present revenues is one of the strengths

of the formula in that the rates that

produce present revenues have been

approved by regulators as just and

reasonable, which strongly suggests that

the costs included in them have been

shown to be prudent, legitimate and

verifiable.

In response to CCEM’s argument that

only fixed costs should be eligible for

recovery (because the inclusion of

variable costs in the RSE will encourage

the continued operation of facilities that

are conceded to be uneconomic), we

agree. The Commission notes that

condition 1, ‘‘Cap on SCO’’ 749 limits

the recovery of stranded costs to fixed

costs. Accordingly, the formula, as

designed, addresses CCEM’s concern.

We note that Central Vermont

supports its opposition to the use of

present revenues differently from other

petitioners, who argue (in effect) that

the price component of RSE is

flawed.750 Central Vermont, on the other

hand, is concerned that the quantity

component of present revenues may not

reflect the quantity that would have

been taken during L. It states that the

Commission should permit the utility to

show that it had a reasonable

expectation of continued customer

service that is not based on the

customer’s previous three years of

power consumption. The Commission

does not believe that this is appropriate.

Central Vermont’s approach would

introduce forecasting controversy,

litigation cost, and uncertainty which

are similar to the disputes about cost

discussed above. For example, a utility

might argue that the customer was

expected to consume more than it has

in the last three years, based presumably

on such factors as expected economic

development, changing demographics,

appliance saturation rates, and even

changes in climate. Conversely, the

departing customer might argue that it

would have increased electricity

conservation efforts, used more natural

gas, relied more on self-generation, and

so on, if open access had not been made

available by Order No. 888. The

Commission has stated above why it

favors the use of present revenues, for

both price and quantity combined, and

these reasons apply regardless of

whether the argument is directed

toward the price or quantity component

of present revenues.

Finally, TDU Systems’ and NRECA’s

argument regarding the transmission

revenue credit component of RSE is

made on the same basis as their

argument that the revenue stream

should be calculated on a forwardlooking basis. For the reasons discussed

above, we reject this argument also.

Therefore, after consideration of the

arguments on rehearing, and

reconsideration of our policy rationale

supporting the use of present revenues,

we continue to support the use of

present revenues, without true-ups or

adders, as the basis for the stranded cost

formula. We find that the use of present

revenues fairly and efficiently balances

the competing interests of the affected

parties.

CMVE Issues

Petitioners raised a number of CMVE

related issues. We take them up in the

following two categories.

Present Value Issues

EEI agrees with the Commission that

stranded costs should be calculated on

a present value basis. EEI states that

with respect to RSE, the formula

appears to be stated on a present value

basis, although it believes that the

language could be strengthened to read:

‘‘the present value of average annual

revenues from the departing customer

over the three years prior * * * ’’ (new

text emphasized).

However, EEI maintains that the rule

fails to define CMVE clearly on a

present value basis. Therefore, EEI

suggests that the Commission clarify the

definition as follows: ‘‘Option 1—the

utility’s estimate of the net present

value of the average annual revenues

* * * or Option 2—the net present

value of the average annual cost to the

customer of replacement capacity and

associated energy * * * ’’ (new text

underlined). EEI states that this

clarification could also be applied to the

‘‘Cap on SCO,’’ to put it on a par with

the other definitions in terms of the time

value component.

TDU Systems and NRECA also

express concerns regarding the

calculation of SCO on a present value

basis. Specifically, they state that the

formula contains no component, factor,

or other mechanism to indicate how

such present value is to be determined.

They also state that no discount rate is

specified, and that the calculation

should be synchronized with the

customer’s chosen payment option.

Central Vermont maintains that the

Commission should make it clear that a

utility is entitled to recovery of both
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12421

751Condition 2 requires use of the most recent

twelve months of revenue if there has been a rate

change. See FERC Stats. & Regs. at 31,840; mimeo

at 597.

752 If RSE and CMVE are calculated on a present

value basis, and the difference between the two is

multiplied by L, the result constitutes the

customer’s SCO. This present value is the amount

to be paid under the lump-sum payment option. If

the customer chooses another payment option,

additional time-value calculations would be

required to match the customer’s stranded cost

obligation with a series of payments made over

time.

753The utility is entitled to recover no more than

the present value of the revenue stream (less the

competitive market value) it would have received

had the customer remained on its system. 754FERC Stats. & Regs. at 31,842; mimeo at 604.

stranded costs and the time value of

those costs from the date on which they

were experienced through the date of

their recovery.

Commission Conclusion

We believe that EEI misinterprets our

intent with the three-year average

annual revenues for RSE. EEI is

proposing to increase the revenues of

three years ago to current dollars, the

revenues of two years ago to current

dollars (and so on) before finding the

three-year average. The Commission

clarifies that our use of the term

‘‘present value’’ does not require such

an adjustment. If the utility thought its

rates on file did not adequately reflect

rising costs, it should have filed for a

rate increase. If it did file for and receive

a rate increase, the formula does not use

a three-year average, but rather revenue

based on the new rate.751 It would be

inappropriate to adjust the three years of

revenue used to calculate RSE to a

current dollar value if these rates have

been in effect for three years without

change. It is assumed that all costs,

including inflationary and deflationary

changes in the underlying costs, have

been recovered. We do not have any

time lag between the provision of

service and the recovery of the costs of

providing that service. Accordingly,

EEI’s proposed present value adjustment

is neither necessary nor appropriate.

With respect to EEI’s concern that

CMVE is not determined on a present

value basis, we clarify that it should be

calculated on a present value basis. Both

the revenues that would have been

collected if the customer had remained

on the system and the revenues the

utility expects to collect by selling the

power must be stated on a present value

basis so that the difference, RSE–CMVE,

is at present value.752 The ‘‘Cap on

SCO’’ must also be stated on a present

value basis.

In response to TDU Systems, NRECA

and Central Vermont, we clarify that a

utility is entitled to recovery of stranded

costs and the time-value of the revenues

that would have been recovered.753

However, we decline to specify the

discount rate or the number of periods

to be used in the calculation. Although

establishing a uniform discount rate

would serve to minimize disputes over

the calculation, we prefer to give the

parties some flexibility on the use of a

discount rate. Similarly, we do not

prescribe the number of periods to be

used in the present value calculation as

this also should be determined on a

case-by-case basis due to differences in

‘‘L’’ and billing payment cycles for each

departing customer.

CMVE Option 2 Issues

In Order No. 888, the Commission

allows the departing customer to set

CMVE equal to the average annual

revenues it would pay to its alternative

supplier. This option is referred to as

CMVE Option 2.

SoCal Edison and Central Vermont

argue that CMVE Option 2 should be

eliminated because it will be

administratively difficult to monitor and

enforce. In their view, Option 2 will

allow customers the opportunity to

‘‘game’’ the system, which will increase

the utility’s and the Commission’s

administrative costs and place the

utility at risk for less than full recovery

of stranded costs. In addition, SoCal

Edison maintains that it will be difficult

to reflect in the calculation of stranded

costs any non-price benefits a customer

may receive under the contract. SoCal

Edison further maintains that there is a

possibility that additional bargains may

have been struck outside of the

agreement between the new supplier

and the departing customer. These

bargains may have the effect of

increasing the price of the alternative

power, but the terms of the bargains

would not be known to the utility to use

in adjusting CMVE. As a result, the

customer’s contract price may not

accurately reflect the utility’s CMVE,

resulting in an inaccurate estimate of

stranded cost responsibility.

EEI has requested that the

Commission clarify that the conditions

placed on CMVE Option 2 were

intended to prevent the customer from

unfairly avoiding its full stranded cost

obligation (i.e., prevent gaming of the

stranded cost calculation). EEI also

states that the Commission should give

the utility an opportunity to challenge

the validity of the replacement

contract’s price, terms and conditions

on a case-by-case basis or give the utility

the right of first refusal to provide

power to the customer under the

replacement contract’s price, terms and

conditions. Carolina P&L requests that

the Commission require the departing

customer to make a compliance filing

containing information regarding the

replacement contract. Centerior

maintains that in order to guard against

the customer overpaying for

replacement capacity (thereby lowering

its SCO), the Commission should use

the revenues received by the host utility

in the resale of the power to determine

the CMVE.

NRECA and TDU Systems maintain

that the formula fails to address how the

CMVE component will be adjusted

when the customer’s contractual

commitment for replacement capacity is

for a period shorter than L.

Commission Conclusion

The comments filed in response to

our Open Access NOPR maintained

overwhelmingly that determining

accurately the competitive market value

of the released capacity and energy is a

difficult and subjective task. Therefore,

we did not prescribe a CMVE by

formula as we did for RSE. Instead, we

provide options for determining it. Our

requirement for the utility to estimate it

is CMVE Option 1. However, the

customer may contend that the utility

will underestimate CMVE under this

option so as to increase the customer’s

stranded cost obligation. In response to

these concerns, the Commission

adopted CMVE Option 2 because ‘‘[t]he

customer will test the market and

choose the best deal available. Hence,

the price the customer pays its

alternative supplier is arguably a more

accurate measure of the competitive

market value of the capacity and

associated energy not taken from the

host utility.’’ 754 The Commission also

believes that, because of the potential

for disputes over the CMVE component

of the formula, many utilities and

departing customers would appreciate

CMVE Option 2 because it would

provide them with a simple and reliable

method for determining the CMVE.

However, the Commission recognized

the potential for gaming on the part of

the customer. To address this potential,

the Commission placed certain

conditions on the use of Option 2. One

of these conditions is that the departing

customer must demonstrate that the

replacement service is equivalent to that

from the current supplier. This provides

the utility with the ability to investigate

whether the new service is essentially

the same, in terms of contract duration,

terms and conditions, as that which it

currently provides the customer. Any

unresolvable disputes over the value of
12422 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

755We note that in a section 206 proceeding

initiated by a customer, Order No. 888 requires that

estimates of stranded cost liability shall include the

information necessary to allow the utility to

understand the basis of the estimate. (Mimeo at 610

referencing Implementation Procedure (2)). The

implementation requirements in Implementation

Procedure (2) apply not only to a utility making a

stranded cost estimate, but also to a customer filing

under section 206. Therefore, in case Order No. 888

is unclear, we clarify that a customer filing under

section 206 and choosing CMVE Option 2 must

include a copy of its replacement contract and any

other information necessary to determine the

equivalence of its replacement contract.

756 If the customer decides not to exercise either

CMVE Option 2 or the marketing/brokering option,

the customer still would be permitted to challenge

the reasonableness of the utility’s CMVE estimate

(under CMVE Option 1) as well as the

reasonableness of the other aspects of the utility’s

stranded cost estimate.

non-price benefits contained in the

customer’s replacement contract, which

is SoCal Edison’s concern, can be

developed during a stranded cost

hearing, and the Commission will

decide the disputed issues based on the

record provided. SoCal Edison’s

concern with additional bargains

outside the contract, which increase the

contract price and lower the customer’s

SCO, is properly addressed through the

discovery process. The utility could ask

for a copy of agreements between the

new supplier and the departing

customer, and the customer would be

obligated to provide the requested

information.

Although we recognize that there may

be difficulties in assuring the

‘‘equivalence’’ of the customer’s

replacement contract, we believe that

CMVE Option 2 creates an incentive for

the utility to estimate CMVE as

accurately as possible (in Option 1), and

provides a quick and simple alternative

to protracted litigation of the utility’s

estimate of CMVE. Accordingly, SoCal

Edison’s and Central Vermont’s request

for elimination of CMVE Option 2 is

rejected. Also, because a utility is

permitted to undertake discovery

regarding the terms and conditions of

the replacement contract, and any

contracts or considerations associated

with the replacement contract, we do

not believe that it is necessary to give

the utility the right of first refusal to

supply the departing customer under

the replacement contract’s price, terms

and conditions. EEI’s ‘‘gaming’’

concerns are best addressed through the

discovery process in a stranded cost

hearing.

Furthermore, we will not require the

departing customer to make a

compliance filing containing

information about its replacement

contract, as the utility can obtain this

information through discovery if it is

needed and relevant, without

automatically burdening the

Commission with additional filings or

requiring the customer to disclose

confidential and irrelevant information.

A customer must file replacement

contract information only if it chooses

to assert that the replacement contract

price is relevant to the determination of

CMVE.755

In response to NRECA and TDU

Systems, the Commission reiterates that

a customer cannot avail itself of CMVE

Option 2 if its replacement contract is

for a period shorter than L. This

restriction is necessary to ensure

equivalence of service.

Marketing/Brokering Option Issues

In Order No. 888, the Commission

allows the departing customer to market

or broker the capacity that it would

strand as a result of its decision to

purchase power from an alternative

supplier. This option is intended to

protect a departing customer from a low

utility estimate of CMVE, which would

result in a higher stranded cost charge

to the customer.

ELCON maintains that the option to

broker the released power in response to

a ‘‘low balling’’ of the CMVE by a utility

places an unfair burden on the customer

by requiring it to engage in brokering.

SoCal Edison and NIMO argue that a

customer choosing the marketing option

should pay the utility’s estimate of the

market value of energy, rather than the

average system energy costs for the

energy it purchases. SoCal Edison and

NIMO argue that the use of average

system energy costs is inconsistent with

the use of estimated market value used

to calculate the customer’s stranded cost

responsibility and will result in an

under-recovery of stranded costs.

Florida Power Corp is also concerned

that the payment provisions of the

marketing option could result in underrecovery of stranded costs. Specifically,

Florida Power Corp states that

permitting customers to purchase the

associated energy at average system

variable costs is appropriate if the

stranded capacity marketed by the

customer is slice-of-system and if the

energy used is at the same load factor as

the average load factor of the utility’s

remaining requirements customers. If

these conditions are not met, Florida

Power Corp states that under-recovery

or over-recovery of stranded costs could

occur. To prevent this, Florida Power

Corp would require the customer to

reimburse the utility for the marketed

energy at the utility’s actual hourly

average energy costs for the hours in

which the energy is resold.

Occidental Chemical requests

guidance as to when a stranded cost is

‘‘legitimate’’ and how the utility will

develop an estimate of the capacity to be

released. Occidental Chemical also

requests clarification regarding the

obligations of a departing customer to

the replacement buyer and whether the

departing customer can resell the

capacity under terms and conditions

different from those under which it

bought it. Similarly, CCEM requests that

the Commission clarify that there can be

no conditions attached to the former

customer’s use of the capacity, except

for conditions pertaining to safety and

reliability. CCEM also contends that the

60-day limit for finding a buyer under

the brokering option is too short and

should be eliminated. CCEM states that

if the customer pays for the capacity in

the stranded cost charge, it should have

flexibility in disposing of it.

Commission Conclusion

The Commission disagrees with

ELCON that the brokering option places

an unfair burden on the departing

customer. The Commission believes that

the marketing/brokering option is

another effective incentive for a utility

to make a good faith estimate of CMVE.

Furthermore, we note that the

marketing/brokering option is just that:

an option. A customer is not required to

exercise the marketing/brokering option,

just as it is not required to exercise

CMVE Option 2. Rather, the marketing/

brokering option is available to a

customer who believes it can reduce its

stranded cost obligation through

marketing or brokering the released

power.756

In response to SoCal Edison, NIMO

and Florida Power Corp, the

Commission believes that permitting a

customer to purchase the associated

energy under the marketing option at

average system variable costs is

appropriate in most instances for at least

two reasons. First, the capacity being

marketed in all or almost all cases

would not be associated with a single

asset or subset of assets. Instead, a

customer who chooses to exercise this

option is purchasing a ‘‘slice of the

system,’’ i.e., a fraction of the

production of all assets. Accordingly,

our requirement that the customer

purchase the associated energy at

average system variable costs is

consistent with the notion that it is

purchasing a slice-of-the-system.

Furthermore, we believe that the

customer should have the opportunity

to purchase the associated energy at the

price it currently pays, and for most

customers that price is based on average
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12423

757For estimation purposes the utility should still

provide its CMVE on a market value basis for both

capacity (fixed) and energy (variable) so that

customers can better understand the basis for the

utility’s estimate.

758This is so because, throughout the period that

the customer is trying to find a buyer, the utility

can sell the released capacity and energy only in the

short-term market, most likely at a lower price than

it could receive in a longer-term market. The utility

is limited to the short-term market because the

capacity must be available when the customer finds

a buyer.

system costs. It is not appropriate to

require market value pricing of

associated energy when the customer’s

present payments are based on average

system variable costs. For SoCal Edison

and NIMO, we further clarify that, when

the departing customer markets the

released power at a market-based rate

and pays average system variable cost

for the energy component of the price,

the difference between the market price

of the power and the average system

variable cost determines the market

value of the released capacity. When we

refer to ‘‘purchasing energy at average

system variable cost,’’ we refer to

compensation for the variable cost

component of the sale (mostly fuel cost);

we are not referring to the total price of

the power sale, which would include a

fixed cost recovery component.

We agree with the argument of Florida

Power Corp. The Commission

recognizes that there may be instances

where the departing customer does not

purchase energy at average system

variable costs. We also recognize that

the entity to which the departing

customer sells the released capacity may

have a usage pattern that differs

significantly from that of the departing

customer. In this circumstance, the

utility should be paid actual hourly

average energy costs for the hours in

which the energy is resold by the

departing customer. Parties should

address this issue in their marketing

agreement.

In addition, we clarify that the

departing customer’s capacity charge is

the utility’s CMVE minus average

system variable costs as contained in its

estimate of RSE.757 Hence, the capacity

charge is the fixed cost that the utility

could recover if it sold the power at

market value. This approach assumes

that the customer choosing the

marketing option is buying a slice of the

system and buys the energy associated

with the released capacity on the same

basis as under its contract with the

utility.

In response to Occidental Chemical, a

stranded cost is legitimate if it meets the

criteria established in the Rule. With

respect to the obligations of a departing

customer to a replacement customer,

such obligations will be governed in

part by the individual contracts between

the parties. However, with respect to

Occidental Chemical’s question as to

whether the departing customer can

resell the capacity under terms and

conditions different from those under

which it bought the capacity, the

Commission finds that, at a minimum,

the customer is entitled to resell the

capacity and energy under the terms

and conditions governing its purchase

from the utility. However, customers

would not be precluded from

negotiating different terms and

conditions with the utility.

In response to CCEM’s concerns, the

Commission will not prohibit a utility

from attaching conditions to the former

customer’s use of the system. There may

be circumstances (which we have not

contemplated) where certain conditions

may be necessary, and we do not wish

to foreclose such instances at this time.

However, we caution utilities against

using this to restrict the customer’s use

of this option. We reiterate our finding

in Order No. 888 that the utility should

allow the customer to market/broker the

released capacity under terms and

conditions comparable to a utility resale

of the capacity to a third party.

The Commission disagrees with

CCEM that the 60-day period for finding

a buyer under the brokering option is

too short and should be eliminated. The

60-day period protects both customers

and utilities in the event that an

acceptable buyer for the power cannot

be found. It protects the utility from

being stuck with the released capacity

for an extended period, during which

time it can receive only minimal

compensation for it.758 Similarly, the 60-

day limit protects the customer by

reverting back to the formula if its

brokering attempt is unsuccessful.

CCEM’s argument that the customer

who pays for the capacity in the

stranded cost charge should have

flexibility in disposing of it ignores the

fact that under the brokering option (as

opposed to the marketing option), the

customer does not take title to the

released capacity. For these reasons, the

Commission continues to believe that a

time limit is necessary, and that 60 days

is adequate to meet the dual goals

described above.

Length of Reasonable Expectation

Issues

American Forest & Paper faults the

Commission for failing to limit the

period of reasonable expectation to a

discrete period, such as three to five

years. TDU Systems contends that the

threat of stranded costs extends well

beyond a mere transition period, and

therefore, is inconsistent with the

Commission’s statement that stranded

costs are a transition issue. TDU

Systems maintains that the period of

reasonable expectation should be

defined as the shorter of either the term

of the terminating contract or the

utility’s planning horizon as of July 11,

1994. IL Com states that absent a

statutory, regulatory or contractual

obligation to incur costs or provide

service, the length of a utility’s

expectation to serve a customer beyond

its contract expiration should be zero.

However, IL Com states that if a

statutory or regulatory obligation to

serve can be demonstrated by a public

utility on a case-by-case basis, extracontractual recovery may be appropriate

but should not exceed three years. IL

Com proposes a formula for L that

incorporates a three-year cap.

Commission Conclusion

We reiterate that our stranded cost

procedure applies to wholesale

contracts only if they are entered into on

or before July 11, 1994 (and do not

contain exit fees or other stranded cost

provisions), so that as these contracts

end this stranded cost recovery

procedure will cease to apply. This fact

alone shows that the policy is a

transition issue and not a permanent

policy for wholesale requirements

contracts. Further, it should be

remembered that a utility must

demonstrate that it had a reasonable

expectation of continued service for a

time certain (L) before any stranded cost

is recognized to exist or recovery

permitted. This is not an insignificant

demonstration. Moreover, although we

decline to establish an outside limit for

L, it is likely that the longer the period

claimed by the utility, the harder it will

be for the utility to demonstrate a

reasonable expectation. In any event, to

provide recovery of the full stranded

cost, it is necessary that the reasonable

expectation period not be limited to an

arbitrary number, such as three to five

years, as suggested by American Forest

& Paper.

Regarding the time it takes to

complete the transition to a market

unaffected by stranded cost

considerations, the Commission

distinguishes the reasonable expectation

period for determining the amount of

stranded costs attributable to a

departing customer from the period over

which the customer pays for stranded

costs. For example, a utility may have

incurred a cost under the expectation

that the customer would remain for

another seven years (L). However, the

customer could pay that amount
12424 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

immediately, over three years, over

seven years, or over a longer period. The

period of reasonable expectation, L, is

unrelated to the repayment period. If all

customers were to choose the lump-sum

payment option, the transition period to

a market completely unaffected by

stranded cost recovery would be short.

In response to TDU Systems, we note

that its proposal to define the period of

reasonable expectation as the shorter of

either the term of the terminating

contract or the utility’s planning

horizon as of July 11, 1994 is not

foreclosed by our Rule. When faced

with a claim for stranded costs, TDU

Systems may argue that either of these

limit the reasonable expectation period

in that instance. However, it would be

inappropriate to limit generically the

period of reasonable expectation as

suggested because the limitation may

not fit all circumstances. We reiterate

that whether a utility had a reasonable

expectation of continued service, and

for how long, will be determined on a

case-by-case basis, and will depend on

the facts and circumstances of each

individual case.

With respect to IL Com’s argument

that absent a statutory, regulatory or

contractual obligation to incur costs, the

length of a utility’s expectation to serve

a customer beyond its contract

expiration should be zero, the

Commission agrees that such obligations

are likely to be the principal reasons for

a reasonable expectation in most cases,

but we would not preclude a utility

from introducing other relevant

evidence. If a utility can demonstrate

that costs were incurred to serve a

customer, based on a reasonable

expectation of continued service, and if

that customer uses the open access

provided by Order No. 888 to reach an

alternative supplier, leaving the utility

with unrecovered costs, the utility

should be allowed to make its case for

recovery of those costs based on

whatever evidence it chooses to offer.

Implementation Issues

SoCal Edison is concerned that, under

the framework established in Order No.

888, a customer could request numerous

estimates of stranded costs based on

different alternative supply scenarios

and departure dates, to which the utility

would have to respond in a 30-day

period. SoCal Edison states that the

Commission should reasonably limit the

number and types of requests. SoCal

Edison maintains that if the number and

type of a customer’s requests are unduly

burdensome or unreasonable in the

utility’s view, the utility should be

permitted to refuse the requests. Under

SoCal Edison’s approach, the customer

would have the right to petition the

Commission to demand that such

studies be undertaken.

SoCal Edison also argues that the

Commission should allow a utility to

assess a reasonable charge to cover

administrative costs associated with

developing the studies required to

produce estimates of stranded cost

responsibility.

TDU Systems states that the 30-day

period allowed for a customer to

respond to a utility’s notice of alleged

stranded costs is too little time to

perform an adequate analysis. In

addition, TDU Systems and NRECA

maintain that a customer should not be

bound by its estimate of stranded cost

obligation as filed in a petition for

declaratory order or a section 205 or 206

proceeding. They contend that certain

elements of the formula depend heavily

on data in the public utility’s

possession, and that the Rule, as

written, will encourage the customer to

present a low-end estimate of stranded

cost liability. TDU Systems and NRECA

maintain that the Commission should

instead require the customer to state its

binding estimate at the close of the

discovery period when it presumably

would be in possession of the data

necessary to make a realistic estimate of

the stranded cost floor.

PSE&G argues that a utility should be

able to begin recovering stranded costs

right away, subject to refund pending

the outcome of the proceeding, to

eliminate any incentive a customer

would have to delay proceedings so as

to delay payment of stranded costs.

Commission Conclusion

Regarding SoCal Edison’s concern

about numerous requests for estimates

of stranded costs, we do not believe that

the number of requests will rise to the

level of ‘‘unduly burdensome’’ or

‘‘unreasonable’’ in most instances.

However, if this problem occurs, a

utility can petition the Commission for

relief, and we will consider each

petition on a case-by-case basis.

The Commission does not agree with

SoCal Edison that a utility should be

permitted a special charge to cover the

cost associated with providing a

stranded cost estimate. Such costs are

likely to be de minimis. Given that

Order No. 888 provides an opportunity

for full recovery of stranded costs, we

do not believe it is appropriate for a

utility to charge a customer an

additional fee for asking whether it can

expect a stranded cost claim.

The Commission also disagrees with

TDU Systems that the 30-day customer

response period is too short. No utility

has argued on rehearing that the 30-day

utility response to a request for an

estimate is too short, and only TDU

Systems argues that the 30-day customer

response to the utility’s estimate is too

short. The 30-day period is intended to

speed the negotiation process, with the

goal of settling stranded costs disputes

without Commission involvement.

Order No. 888 requires a utility to

provide an estimate of stranded cost

responsibility within 30 days of the

customer’s request for an estimate. We

do not believe it is unreasonable to

require the customer to respond in like

time. Accordingly, we will not modify

the 30-day response requirement.

Furthermore, the Commission is

unpersuaded by TDU Systems’ and

NRECA’s argument that a customer

should be bound by its estimate of

stranded cost obligation only after the

close of the discovery period. Order No.

888 requires the utility to provide

detailed support for its stranded cost

estimates, and this information should

be adequate to allow the customer to

develop its own estimate of any

stranded cost obligation.

In response to PSE&G, we clarify that

recovery of stranded cost claims filed

under section 205, 206, or 211/212 will

be governed by these sections and the

Commission’s promulgating regulations

thereto.

Net Benefit Issues

EGA and IMPA argue that the

revenues lost approach does not capture

the net utility benefits that result from

open access. EGA states that no

stranded costs should be imposed on

any one ‘‘lost’’ customer if the utility is

a ‘‘net winner,’’ that is, where the

benefits from the new competitive

regime outweigh the utility’s stranded

costs. EGA states that the formula is

unclear as to how the revenues lost

approach will take into account the

following three potentially beneficial

effects of competition: (1) an expanded

customer base as a result of enhanced

transmission access; (2) reductions in

the cost of purchased power, which is

resold by a utility; and (3) a utility’s

ability to obtain higher than cost of

service rates for electricity. Freedom

Energy argues that the potential future

benefit should be factored into the

revenues lost calculation.

IMPA maintains that a mechanism

should be provided for recovery of the

benefits of open access, particularly if a

utility does not seek stranded cost

recovery. IMPA states that it is

economically inefficient for consumers

of generation and transmission services

to pay stranded costs to those suppliers

that have higher than average cost

generation, while the benefits from
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12425

759Freedom Energy and ELCON reference a study

conducted under the aegis of the Massachusetts

Attorney General to support their position that the

future benefits of deregulating sales of energy and

capacity will produce a net gain for utilities that is

often sufficient to offset the full amount of any

potential stranded costs. 760 16 U.S.C. § 824(a).

increases in asset value are not shared

with the consumers or used to pay for

other utilities’ stranded costs. IMPA

further contends that if the customer’s

departure as a power customer frees up

the generating capacity for remarketing

through the use of the transmission

system, section 212 of the FPA, as

modified by the Energy Policy Act,

supports recognition of such benefits in

the price paid by the customer for its

continued usage. Finally, IMPA

maintains that if a transmission

provider seeks stranded cost recovery

for an asset that appears ‘‘high cost’’ due

to its relative youth, the asset’s future

lower cost as an older unit must also be

included in the calculation; otherwise

the departing customer will be denied

the long-term average benefit of the

generating asset.

Multiple Intervenors contend that

there should be consistent treatment of

all assets that deviate from fair market

value. For example, if a utility is

allowed to recover the difference

between the book value of an asset and

its lower market value, then that amount

should be offset by the appreciated

value of any assets that have a market

value higher than book value. Similarly,

ELCON and Freedom Energy are

concerned that the revenues lost

approach may overcompensate a utility

for stranded costs because it fails to

account for the fact that uneconomic

assets may be offset by the increased

economic value of other assets in a

deregulated environment.759 Freedom

Energy states that losses may occur in

the short run, but in the long run the

utility may be better off.

Commission Conclusion

The Commission believes that the

suggestion by EGA and others that a

long-run comprehensive analysis be

undertaken every time a customer

departs, in order to determine whether

the utility would eventually be a net

winner, is unworkable. Identifying the

competitive market value for power

during the reasonable expectation

period (L) is hard enough; EGA would

have us also find the market value of the

power for an indefinite time after the

expectation period ends. Further,

attempts to define which benefits are

the result of Order No. 888 would, at the

very least, be unwieldy and highly

subjective. The Commission’s approach,

on the other hand, is far less subjective

and more likely to produce a reasonable

result.

With respect to the specific

‘‘potentially’’ beneficial effects of

competition during the period L, which

EGA states should be used to offset

stranded costs, the Commission finds

these benefits to be questionable at best.

However, if these potential benefits

occur, the Rule’s stranded cost approach

accommodates them. For example, our

clarification (infra) that the formula

addresses load growth responds to

EGA’s first concern that the formula

should take into account the expanded

customer base that results from open

access. EGA’s second concern, i.e., that

the formula should reflect reductions in

the cost of purchased power, is

misplaced. If, in a future market-based

pricing world, a utility can purchase

power at a lower cost, it must either

pass this lower cost through to

customers in its cost-based rates or sell

power at similarly low market-based

rates to other customers. In either case,

except for possible timing

considerations, it is unable to profit by

buying low and selling high. If a utility

has such a hypothetical benefit before

the customer departs, the customer may

file a section 206 complaint prior to the

termination of the existing contract, so

that the resulting rates, reflecting the

reduction in the cost of purchased

power, could be used to calculate RSE.

Lastly, if a utility can sell at marketbased rates that are higher than costbased rates (other than in the

speculative long run), it would not

qualify to recover stranded costs.

In addition, ELCON’s and Freedom

Energy’s concern that utilities may be

overcompensated under the revenues

lost approach is based on a study that

assumes a fully deregulated

environment. There is no basis for this

assumption over the next several years.

Furthermore, it is highly speculative

whether a particular utility will

necessarily be better off in future

markets as the study predicts. This is

especially so because Freedom Energy’s

argument that future benefits should be

used to offset stranded costs appears to

assume a short reasonable expectation

period, L. We do not find merit in

Freedom Energy’s suggestion that events

beyond the reasonable expectation

period should be factored into the

stranded cost calculation.

The Commission also believes that

IMPA’s benefit reallocation proposal is

inappropriate and unworkable. It would

require a utility not requesting stranded

cost recovery to share with its wholesale

customers any future benefits that

would accrue to it as a result of Order

No. 888. Customers have purchased

power from utilities at cost-based rates

that have been found to be just and

reasonable by this Commission. Such

purchases in no way convey an

ownership interest in the facilities used

to provide service. The rationale for

stranded cost recovery, i.e., payment for

investments made to serve a customer

under the utility’s reasonable

expectation of continuing to serve,

cannot be converted into what would be

in effect an ownership interest with the

right to receive a share of profits from

future sales. Moreover, IMPA’s

argument assumes that utilities whose

assets have a book value less than

market value will be able to charge

market-based rates for their capacity.

This assumption is unrealistic for many

utilities, and therefore cannot be relied

upon as basis for a generic policy.

However, even if all utilities could

charge market-based rates, economic

efficiency would argue strongly against

such utility payments to departing

customers. Specifically, there would be

little or no incentive for an efficient, low

cost utility to seek the best deal in the

power market if the profits must be

credited back to its former customers, or

other utilities’ customers, as IMPA

suggests. Therefore, while IMPA’s

symmetry argument (i.e., customers

must pay stranded costs so equity

requires utilities to pay customers any

benefits that result from open access)

may have surface appeal, it would serve

to undo the goal of Order No. 888—that

is, to promote competition and

economic efficiency in bulk power

markets. The Commission considered

carefully the issue of symmetry in Order

No. 888 and provided the appropriate

utility-customer symmetry: a utility is

entitled to make the case that it

expected the customer to remain a

customer longer than the term of the

contract and the customer is entitled to

make the case that the term of an

existing contract should be shortened.

We also reject IMPA’s argument that

section 212 of the FPA requires

recognition in transmission rates of any

generation benefits that accrue to a

utility as a result of Order No. 888.

Section 212 requires the Commission to

consider all costs incurred by the

transmission provider in providing the

service, ‘‘including taking into account

any benefits to the transmission system

of providing the transmission service.’’

760 We do not interpret this to refer to

the resale of a utility’s generation freedup as a result of Order No. 888.

IMPA’s argument that if a

transmission provider seeks stranded

cost recovery for an asset that appears
12426 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

761See also Wisconsin Municipals.

‘‘high cost’’ due to its relative youth, the

asset’s projected future lower

(depreciated) cost as an older unit must

also be included in the calculation,

improperly focusses on an individual

asset. As we explained above, the

revenues lost approach is not an assetby-asset approach, but an approach that

looks at a utility’s current rates which

are based on all the utility’s assets,

including typically a mix of facilities of

various ages.

Lastly, the revenues lost approach

automatically includes an offset of the

type described by Multiple Intervenors,

ELCON and Freedom Energy. The

revenue stream is based on present

rates, which are based on the net book

value of all of the underlying assets

used to provide the service. If present

rates include some assets that have a

market value that exceeds net book

value (for example, plants that are

almost fully depreciated), the formula

automatically captures the described

offset because the revenue stream is

based on the lower book value of the

utility’s assets rather than their higher

market value.

Miscellaneous Formula Issues

Rehearing Requests

American Forest & Paper argues that

the definition of wholesale stranded

costs in section 35.26(b)(1) is overly

inclusive; rather than using a gross

measure of stranded costs, it believes

the regulations should adopt a net

measure that accounts for a utility

redeploying its assets in a competitive

market at market price. American Forest

& Paper also maintains that the formula

fails to reward efficient utilities or those

that already have borne the pain of

restructuring. On the contrary, it argues

that the Commission’s definition

artificially and unjustifiably improves

the competitive position of the

inefficient utilities. American Forest &

Paper further contends that the formula

fails to allocate the risk of nonmitigation to utilities, the entities that

are in the best position to mitigate such

costs, but rather places the risk on

customers by requiring customers to

challenge the utility’s CMVE.

Commission Conclusion

In response to American Forest &

Paper, we note that the definition of

wholesale stranded cost in section

35.26(b)(1) should not be looked at in

isolation. Although that definition does

not specifically mention the subtraction

of the competitive market value of the

released power from RSE, the revenues

lost formula, which is set forth in

section 35.26(c)(2)(iii), does. The

formula explicitly provides that a

customer’s stranded cost obligation is to

be calculated by subtracting the

estimated competitive market value (of

the released power) from the revenue

stream estimate.

In response to the argument that the

formula fails to reward the efficient

utility that has already borne the pain of

restructuring, we note that our intention

in providing stranded cost recovery was

not to review or reward utility business

decisions that preceded this Rule. Our

decision was, at bottom, based on equity

for a utility that chooses to make a case

to regulators for recovery of costs

stranded by transmission access.

Furthermore, we disagree that the

definition of stranded costs artificially

and unjustifiably improves the

competitive position of an inefficient

utility. Instead, the Commission

believes that to deny stranded cost

recovery would violate the pre-existing

regulatory compact and would

unjustifiably place certain utilities with

stranded costs at a financial

disadvantage.

With respect to American Forest &

Paper’s concern about mitigation risk,

the Commission requires the utility to

mitigate, or reduce, its stranded cost by

reselling the released capacity at a price

as high as the market allows. In

addition, Order No. 888 contains several

other incentives (e.g., the marketing/

brokering option) to protect the

departing customer from paying an

excessive stranded cost charge. These

incentives serve to mitigate stranded

costs. Regarding the customer’s

‘‘requirement’’ to challenge the utility’s

CMVE, we view this as the customer’s

right to challenge the utility’s stranded

cost estimate, which is like its right to

challenge a cost item in any rate case.

Rehearing Requests

NRECA and TDU Systems maintain

that the formula fails to account for any

savings or reductions in fuel costs

attributable to a customer’s departure.

NRECA and TDU Systems contend that

the utility’s fuel costs will decrease

equivalent to the incremental fuel costs

associated with the energy not taken.

They maintain that if the customer’s

associated revenues are based on

average fuel cost energy charges,

stranded costs should be offset by the

reduction in average system fuel costs

directly related to the incremental fuel

costs savings. They argue that any

stranded cost recovery mechanism

should properly reflect such offsetting

savings.

Commission Conclusion

The Commission disagrees with

NRECA and TDU Systems that the

formula fails to account for any savings

or reductions in fuel costs attributable to

a departing customer. The formula

automatically accounts for fuel costs by

assuming that the utility will be

reselling the same capacity and energy

to another buyer, presumably at a lower

price. The lower price can be viewed as

contributing less to capital cost and

purchased power cost recovery, but

containing the same fuel cost

component. Under this approach, any

decrease in fuel cost caused by no

longer serving the departing customer is

offset by the increased fuel cost of

serving the new customer. Hence, there

is no fuel costs savings to reflect.

Rehearing Requests—Divestiture

CCEM continues to support

divestiture of generating assets as a

precondition to a utility’s authority to

recover stranded costs. CCEM maintains

that divestiture is the only way to obtain

an accurate determination of CMVE on

a net asset basis.

Commission Conclusion

The Commission disagrees that

divestiture is the only way to obtain an

accurate measure of CMVE and we

continue to believe that mandatory asset

divestiture does not need to be a

requirement for stranded cost recovery.

However, the Rule (Section IV.J.10)

states that we are willing to consider

case-specific proposals for dealing with

stranded costs in the context of any

voluntary restructuring proceeding

instituted by an individual utility.

Rehearing Requests—Load Growth and

Excess Capacity

TDU Systems and NRECA argue that

the formula fails to take into account the

effect of load growth on the recovering

utility’s revenues. They maintain that if

the recovering utility is able to sell the

released capacity to new or existing

customers, the rationale for stranded

cost recovery would be eliminated.

Similarly, Arkansas Cities argues that

the formula is an imperfect indicator of

a utility’s stranded costs because it does

not explicitly take into account the role

played by the utility’s having (or not

having) excess capacity. PA Munis

maintains that as a prerequisite to

stranded cost recovery, a utility should

be required to prove that the customer’s

use of open access transmission actually

resulted (or could result) in excess

capacity on its system. 761
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12427

762FERC Stats. & Regs. at 31,840; mimeo at 598.

Commission Conclusion

We clarify that our stranded cost

policy does take into account the effects

of load growth and excess capacity. The

formula is used to calculate the value of

stranded costs only if the Commission

determines that the utility has proved it

has legitimate, prudent, and verifiable

stranded costs. For example, it must

pass our reasonable expectation test

before the formula applies. However,

costs may be stranded only if they are

not fully recovered from another

customer; that is, the released capacity

may be either left unsold or resold at a

price below full embedded cost.

The resale may be either to a new

third-party customer or to remaining

native load. If the released capacity is

resold to a third-party customer at full

embedded cost-based rates, then no

costs would be stranded and the

formula would not have to be used.

Released capacity would also be

considered ‘‘resold’’ if its cost is

subsequently (and without delay)

included in the rate base of the utility’s

retail and wholesale native load. It may

be included if it is needed, in the

judgment of the appropriate state or

federal regulatory body, for native load

growth plus reliability reserve. In this

case the cost is not stranded if it is fully

recovered in the cost-based rates paid by

native load. If the full embedded cost

rate is paid by the new purchaser for the

capacity released by the departing

customer, the parties may argue either

that there is no stranded cost or that the

formula produces a stranded cost

obligation of zero because CMVE equals

the embedded-cost rate that the utility

charges its wholesale and retail native

load customers; hence RSE equals

CMVE.

In response to Arkansas Cities, if the

released capacity was included in the

Commission-approved cost-based rates

paid by the departing customer, we

presume that such capacity is not

‘‘excess’’ capacity. The departing

customer’s rate (which produces annual

revenues, RSE) for the released capacity

includes capacity that regulators have

approved as needed to meet the needs

of requirements customers, including

capacity needed for reliability reserve.

The only excess capacity issue is

whether the released capacity becomes

‘‘excess’’ because of the customer’s

departure, that is, whether the departure

strands costs because the utility cannot

find a buyer for the capacity. If the

released capacity is ‘‘excess’’ capacity

that is excluded from subsequent native

load rates because it is not needed for

native load, its cost may be eligible for

stranded cost recovery under the

formula. Thus, contrary to the

arguments made by TDU Systems,

NRECA, Arkansas Cities, Pa Munis and

others, the revenues lost formula does

take load growth and excess capacity

into account appropriately in

determining the departing customer’s

stranded cost obligation. For this reason,

we reject the arguments made by

commenters that the formula is flawed.

Rehearing Requests—Tax Treatment of

Nuclear Decommissioning Costs

EEI and Nuclear Energy Institute

request clarification that the

Commission did not intend Order No.

888 to change the IRS’s tax treatment of

nuclear decommissioning costs. To be

tax deductible, nuclear

decommissioning costs must be part of

a utility’s regulated cost of service. EEI

and Nuclear Energy Institute seek

clarification that costs included in a

utility’s stranded cost calculation

continue to be considered by the

Commission as included in the utility’s

cost of service.

Commission Conclusion

The requested clarification is granted.

We clarify that costs included in a

utility’s stranded cost calculation

continue to be considered by the

Commission as included in the utility’s

cost of service.

Rehearing Requests—Application of

Formula to Stranded Costs Associated

With Retail-Turned-Wholesale

Customers and Retail Wheeling

Customers

OH Com, MO Com and KS Com

maintain that the Commission’s formula

is inappropriate for calculating stranded

costs associated with retail wheeling

customers and/or retail-turned

wholesale customers. They contend that

the formula would be impractical to

administer and would produce

inaccurate results given the enormity of

the calculations and assumptions

involved. Suffolk County argues that the

formula is flawed for retail-related

stranded costs because the Commission

cannot guarantee any retail rates into

the future because it has no basis for

even speculating about how retail rates

may be changed by subsequent state

action.

Commission Conclusion

With respect to stranded costs caused

by retail wheeling, the Commission

determined in Order No. 888 that the

formula was inappropriate, and that if

the Commission had to determine

stranded costs associated with retail

wheeling it would do so on a case-bycase basis. 762 However, the formula

does work for stranded costs associated

with retail-turned-wholesale customers

because the newly formed municipal

utility would have the resources to

engage in marketing or brokering and

would have a marketable product. This

stands in contrast to individual retail

customers, most of whom are unlikely

to have the resources to engage in

marketing or brokering and would have

very small amounts of energy for sale.

Although the calculations necessary to

estimate stranded costs associated with

retail-turned-wholesale customers are

somewhat more involved than stranded

costs associated with wholesale

contracts, they are not impossible or

overly burdensome. Accordingly, we

affirm our finding in Order No. 888 that

the formula is appropriate in the retailturned-wholesale context.

Rehearing Requests

Allegheny Power states that stranded

cost recovery should not be permitted if

a utility recovers large amounts through

exit fees, then uses the freed capacity to

make sales in the market at anything

over variable costs. Allegheny Power

argues that a utility with nuclear

generation, which has a low variable

cost, can dump power on the market

because its fixed costs are subsidized by

stranded cost recovery. Allegheny

Power requests that the Commission

recognize that this distortion of the

competitive market should not be

facilitated by stranded cost recovery.

Commission Conclusion

Allegheny Power’s concern that a

utility recovering stranded costs will

use those revenues to subsidize sales in

the market at anything above variable

costs is misplaced. In the power market,

power pricing decisions are based on

whether the utility can recover its

variable cost, plus earn some

contribution to capital costs. Stranded

cost revenues are not relevant. This fact

is demonstrated by considering the

situation where no stranded cost

revenues are provided to a utility with

nuclear generation as described by

Allegheny Power. The utility, in pricing

power for off-system sales, would still

face the same choice, i.e., make the sale

and earn some minimal contribution to

capital, or forego the sale and earn

nothing. The Commission’s decision to

provide recovery of stranded costs does

not change the economics involved in

utility power pricing decisions, and

does not lead to the type of market

distortion that concerns Allegheny

Power.
12428 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

763As discussed in Section VI., we will treat

SBA’s request as a motion for reconsideration.

764 18 CFR 385.214 (1996).

765See FERC Stats. & Regs. at 31,845–46; mimeo

at 614–15.

766See FERC Stats. & Regs. at 31,846–47; mimeo

at 615–18.

767 Mimeo at 768.

768FERC Stats. & Regs. at 31,849–50; mimeo at

624–26. The definition of ‘‘retail stranded cost’’

contains a similar requirement that the retail

customer must become, in whole or in part, an

unbundled retail transmission services customer of

the public utility from which the customer

previously received bundled retail services. We said

that we would retain it for the same reasons

discussed above.

769As we clarify in this Order, there is not a

sufficient nexus to Commission-required

transmission access in such circumstances. The

Commission’s decision not to allow utilities to seek

recovery of stranded costs under the provisions of

Order No. 888 if the customer leaves its historical

power supplier by exercising power supply options

that do not rely on access to the former supplier’s

transmission is based on the absence of a direct

causal nexus between stranded costs and the

availability and use of Commission-required

transmission access. Self-generation and access to

another utility’s transmission system would have

been options prior to the Rule.

770FERC Stats. & Regs. at 31,850; mimeo at

626–27.

Rehearing Requests

SBA asserts that determining the

proper amount of stranded cost recovery

is an integral step in the deregulation

process.763 It expresses concern that the

revenues lost formula can be abused

through the manipulation of the

necessary financial statements of the

parties and that such abuse could be

harmful to small businesses. SBA

requests that the Commission solicit its

input, as well as the input of the small

business community and small business

organizations, when determining

whether the proposed stranded cost

recovery amount in a particular case is

fundamentally fair in terms of

maintaining a viable environment for

small businesses.

Commission Conclusion

In response to SBA’s request, we note

that SBA, or any interested small

business organization, has the

opportunity to provide input to the

Commission in a particular stranded

cost proceeding by filing a motion to

intervene in that proceeding.764

10. Stranded Costs in the Context of

Voluntary Restructuring

No rehearing requests were filed on

this issue. The Commission reaffirms

that we are willing to consider casespecific proposals for dealing with

stranded costs in the context of any

restructuring proceedings that may be

instituted by individual utilities.765

11. Accounting Treatment for Stranded

Costs

No rehearing requests were filed on

this issue. The Commission reaffirms

Order No. 888’s treatment of this

issue.766

12. Definitions, Application, and

Summary

In Order No. 888, we defined

‘‘wholesale stranded cost’’ in section

35.26(b)(1) as follows:

(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. [767]

We rejected requests by commenters in

this proceeding to expand the definition

to include the situation where a

wholesale requirements customer or a

retail-turned-wholesale customer ceases

to purchase power from the utility

without using the transmission services

of that utility.768 We explained that any

costs that the utility might incur as a

result of the loss of the requirements

customer in this scenario would be

outside the scope of this Rule. We noted

that the premise of this Rule is that,

where a customer uses Commissionmandated transmission access of its

former power supplier to obtain power

from a new generation supplier, the

customer must pay the costs that were

incurred to provide service to the

customer under the prior regulatory

regime. We indicated that if a customer

leaves its utility supplier by exercising

power supply options (such as access to

another utility’s transmission system or

self-generation) that do not rely on

access to the former seller’s

transmission, there is no nexus to the

new open access rules.769

We also decided to retain the

requirement that stranded costs be

‘‘legitimate, prudent and verifiable,’’

rejecting requests by some commenters

to eliminate the term ‘‘prudent’’ from

the definition of stranded costs.770 We

explained that a determination that a

utility had a reasonable expectation of

continuing to serve a customer would

not, in all circumstances, mean that

costs incurred by the utility were

prudent. We said that prudence of costs,

depending upon the facts in a specific

case, may include different things: e.g.,

prudence in operation and maintenance

of a plant; prudence in continuing to

own a plant when cheaper alternatives

become available; prudence in entering

into purchased power contracts, or

continuing such contracts when buyouts or buy-downs of the contracts

would result in savings. We concluded

that the Commission cannot make a

blanket assumption that all claimed

stranded costs will have been prudently

incurred, but we clarified that we do not

intend to relitigate the prudence of costs

previously recovered.

Rehearing Requests—Definitions of

‘‘Wholesale Stranded Cost’’ and

‘‘Wholesale Requirements Contract’’

As discussed in Sections IV.J.1 and

IV.J.6, supra, a number of entities ask

the Commission to expand the scope of

stranded cost recovery allowed under

the Rule to include ‘‘bypass’’ situations

(i.e., situations in which a departing

customer does not use its former

supplier’s transmission system to reach

another supplier). Coalition for

Economic Competition asks the

Commission to revise the definition of

‘‘wholesale stranded cost’’ to

accomplish that result. It notes, for

example, that the reference in the

definition to ‘‘newly created wholesale

power sales customer’’ creates an

ambiguity and may provide a loophole

to evade stranded costs through

municipal annexation.

El Paso expresses concern that a

retail-turned-wholesale customer could

attempt to avoid its stranded cost

responsibility simply by having its

outside power supplier be the

‘‘wholesale transmission customer’’ (i.e.,

the entity that formally requests

transmission service from the

transmitting utility). El Paso asks the

Commission to clarify that a retailturned-wholesale customer is

responsible to the transmitting utility

for stranded costs regardless of whether

it or its outside power supplier is the

‘‘transmission customer’’ of the

transmitting utility. El Paso asks the

Commission to revise section

35.26(c)(1)(vii) (which presently

provides for recovery from retail-turnedwholesale customers through section

205–206 or 211–212 wholesale

transmission rates) to provide for the

recovery of stranded costs directly from

retail-turned-wholesale customers

(through an exit fee or lump sum

payment).

Utilities For Improved Transition asks

the Commission to expand the

definition to include costs incurred to

provide service to ‘‘a wholesale

requirements customer that loses retail

load because of retail wheeling,
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12429

771Utilities For Improved Transition at 17.

772Both note that this is the prudence standard

that the Commission applied in Order No. 636.

municipalization of retail load, the

creation of a new customer, or because

retail customers have bypassed its

system through transmission or

distribution taps to other suppliers or by

other means.’’ 771 Utilities For Improved

Transition argues that, in the case of

retail wheeling and municipalization,

these costs are incurred because of open

access tariffs. It further submits that the

Commission also should include costs

incurred because of taps

(interconnections) to other systems to

avoid encouraging uneconomic bypass

as a way to avoid stranded cost charges.

APPA expresses concern that the

definition in section 35.26(b)(4) of

‘‘wholesale requirements contract’’ as ‘‘a

contract under which a public utility or

transmitting utility provides any portion

of a customer’s bundled wholesale

power requirements’’ could be read as

including a bundled sale of capacity

regardless of whether the seller

undertook to meet the customer’s load

growth. As a result, APPA submits that

the definition could include

coordination arrangements. It is APPA’s

position that the Commission could not,

or should not, have intended to allow

stranded cost recovery for such

contracts. APPA asks the Commission to

specify on rehearing that a ‘‘wholesale

requirements contract’’ is a bundled

power and transmission arrangement

that includes the obligation to meet

some or all of the customer’s load

growth, and that all other services are

coordination arrangements to which the

stranded cost recovery rules do not

apply.

Commission Conclusion

We will reject the requests for

rehearing that ask the Commission to

expand the scope of stranded cost

recovery allowed under the Rule to

include situations in which a wholesale

requirements customer (or a retailturned-wholesale customer) ceases to

purchase power from the utility without

using the transmission services of that

utility. As we explain in Sections IV.J.1

and IV.J.6, supra, any costs that the

utility might incur as a result of the loss

of the customer in these scenarios

would be outside the scope of Order No.

888. However, as discussed in Section

IV.J.6, we grant rehearing on the

municipal annexation issue.

We share El Paso’s concern that a

retail-turned-wholesale customer should

not be able to avoid its stranded cost

responsibility simply by having its

outside power supplier be the entity

that formally requests unbundled

transmission service from the utility. As

we explain in Section IV.J.6, supra, in

response to a similar concern expressed

by Puget, we have revised the definition

of ‘‘wholesale stranded cost’’ in section

35.26(b)(1)(ii) to cover this situation. As

revised, that section provides that

‘‘[w]holesale stranded cost means any

legitimate, prudent and verifiable cost

incurred by a public utility or a

transmitting utility to provide service to:

* * *. (ii) a retail customer that

subsequently becomes, either directly or

through another wholesale transmission

purchaser, an unbundled wholesale

transmission services customer of such

public utility or transmitting utility.

We will deny Utilities For Improved

Transition’s request that the

Commission expand the definition to

include costs incurred to provide

service to ‘‘a wholesale requirements

customer that loses retail load because

of retail wheeling, municipalization of

retail load, the creation of a new

customer, or because retail customers

have bypassed its system through

transmission or distribution taps to

other suppliers or by other means.’’

Utilities For Improved Transition, in

effect, is asking that the Commission

allow the recovery of costs that may be

stranded due to the loss of an indirect

customer and to expand the scope of the

‘‘wholesale stranded costs’’ for which

Order No. 888 provides an opportunity

for recovery. As we discuss in Section

IV.J.1, supra, the Commission does not

believe it is appropriate to expand the

scope of the stranded cost recovery

opportunity provided under this Rule to

include costs that may be stranded due

to the loss of an indirect customer (i.e.,

a customer of a wholesale requirements

customer of the utility). The reasonable

expectation analysis would apply only

to the direct wholesale requirements

customer of the utility, not to the

indirect customer. A utility may seek to

recover stranded costs from a direct

wholesale customer (subject to the

requirements of the Rule), but it is up

to the direct wholesale customer,

through its contracts with its customers

or through the appropriate regulatory

authority, to seek to recover stranded

costs from its customers.

In response to APPA’s argument that

the definition of ‘‘wholesale

requirements contract’’ in new section

35.26(b)(4) of the Commission’s

regulations could be read as including

coordination arrangements, we clarify

that it does not. The opportunity to

recover stranded costs applies only to

bundled power contracts where the

utility can demonstrate that it incurred

costs to provide service to a customer

based on a reasonable expectation of

continuing service to the customer

beyond the contract term. Coordination

arrangements could not meet the cost

incurrence and reasonable expectation

prerequisites of Order No. 888, and

therefore a customer served under such

an arrangement would not be subject to

stranded cost charges.

Rehearing Requests—Relitigation of

Prudence

A number of entities express concern

that, notwithstanding the Commission’s

stated preference not to relitigate

prudence, Order No. 888 leaves the door

open for subsequent litigation of

prudence issues. Centerior asks the

Commission either to remove ‘‘prudent’’

from the definition or to clarify that

‘‘prudent’’ means all costs found

prudently incurred by the state

commissions. Centerior asks the

Commission not to relitigate prudence

in the operation and maintenance of a

plant or the prudence of continuing to

own a plant when cheaper alternatives

become available. Other entities

(including EEI, PSE&G, and Nuclear

Energy Institute) similarly ask the

Commission to clarify that it does not

intend to relitigate costs that are already

in rates when calculating the revenue

stream estimate. Nuclear Energy

Institute states that, in the case of

nuclear plants, significant prudence

proceedings have already been

conducted and, by definition, the

embedded capital costs included in

current rates to customers are prudent.

PSE&G recommends that if costs that

form the basis for a utility’s claimed

stranded costs are already included in

filed rates and are no longer subject to

refund, those costs should be treated as

per se prudent. Southern states that if

the Commission does not strike the

word ‘‘prudent’’ from the definition of

stranded costs, at a minimum it should

modify the Rule to establish a rebuttable

presumption of prudence that must be

overcome by the departing customer.

PSE&G and Carolina P&L submit that

if prudence challenges under the Rule

are retained on rehearing, they should

be subject to the same standards as any

other prudence challenge, namely the

‘‘reasonable person test’’ under which

prudent costs are those ‘‘which a

reasonable utility management * * *

would have made, in good faith, under

the same circumstances, and at the

relevant point in time.’’ 772 PSE&G and

Carolina P&L ask the Commission to

limit the prudence review to the

reasonableness of the costs that were

incurred to provide wholesale

requirements service based on the
12430 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

773For the same reason, we will reject Southern’s

request that we establish a rebuttable presumption

of prudence that must be overcome by the departing

customer.

774See Minnesota Power & Light Company,

Opinion No. 86, 11 FERC ¶ 61,312 at 61,644–45

(1980).

775 Id. at 61,644; Anaheim Riverside, et al. v.

FERC, 669 F.2d 799, 809 (D.C. Cir. 1981).

776A utility has an ongoing prudence obligation.

As pointed out in Order No. 888, although an

investment or a contract may have been prudently

incurred, it may become imprudent at a later point

in time not to dispose of assets or not to buy-out

contracts that have become uneconomic, assuming

this results in net benefits to customers.

777See Canal Electric Company, 47 FERC ¶ 61,044

at 61,127, reh’g denied, 49 FERC ¶ 61,069 (1989) (if

a party raises prudence issues in a later proceeding,

any future finding concerning prudence will have

no effect on past rates).

778Although we will not go so far as to

characterize these costs as ‘‘per se prudent’’ (as

requested by PSE&G), in effect, the result is the

same because we will not allow the prudence of

such costs to be relitigated.

779See New England Power Company, 31 FERC

¶ 61,047 at 61,081–84 (1985), aff’d sub nom., Violet

v. FERC, 800 F.2d 280, 282–83 (1st Cir. 1986). We

note that this is the same standard that the

Commission has used for reviewing the prudence

of a pipeline’s Order No. 636 gas supply

realignment costs. See Texas Eastern Transmission

Corporation, 65 FERC ¶ 61,363 (1993).

780New England Power Company, 31 FERC at

61,084.

781 Id.

782FERC Stats. & Regs. at 31,851–52; mimeo at

631–32.

783See, e.g., Consolidated Edison Company of

New York, Inc. and Central Hudson Gas & Electric

Corp., 72 FERC ¶ 61,184 at 61,891 (1995) (ConEd).

784 72 FERC at 61,891.

utility’s reasonable expectation of

continued service. They ask the

Commission to clarify that it will not

permit prudence proceedings to devolve

into collateral attacks on stranded cost

recovery and unfocused debates on the

sufficiency of the utility’s efforts to

adapt to changes in the industry, such

as its decisions on staffing reductions

and asset write-offs.

Commission Conclusion

In Order No. 888, we specifically

stated that we do not intend to relitigate

the prudence of costs previously

recovered but that we would not

preclude parties from raising prudence

in stranded cost proceedings. Because

we believe that this approach

adequately ensures that the prudence of

costs previously recovered at this

Commission or a state commission will

not be relitigated for stranded cost

purposes, we will reject the rehearing

requests that seek elimination of the

term ‘‘prudent’’ from the definition of

stranded costs.773 However, we make

certain clarifications below in response

to the rehearing petitions.

As an initial matter, we clarify that

the Commission’s determination in

Order No. 888, which is reaffirmed here,

is the same approach the Commission

traditionally has followed regarding

prudence matters.774 Costs are assumed

prudent unless a party or the

Commission raises a serious doubt as to

prudence; then the burden is on the

utility to prove that costs were

prudently incurred.775 If costs have

previously been recovered in rates

(either following an explicit prudence

determination or based on an implicit

assumption of prudence because no one

raised prudence), they cannot be

relitigated. However, if prudence has

not previously been litigated or if

certain costs or activities have become

imprudent,776 a party may raise the

issue as it pertains to future cost

recovery.777 The Commission intends to

apply the same prudence standards with

regard to future cost recovery, including

stranded costs.

We further clarify that we do not

intend to relitigate, for purposes of

stranded cost determinations involving

retail-turned-wholesale customers or

unbundled retail customers, the

prudence of costs for which rate

recovery has been allowed by state

commissions. Similarly, in calculating

the revenue stream estimate, we do not

intend to relitigate the prudence of any

costs for which rate recovery has been

allowed by this Commission or a state

commission.778

In response to PSE&G and Carolina

P&L, we also clarify that, in cases in

which we do entertain stranded cost

claims, the standard to be used for

reviewing the prudence of a utility’s

costs is the ‘‘reasonable person’’ test that

we apply in other contexts.779 This test

gives utility managers ‘‘broad discretion

in conducting their business affairs and

in incurring costs necessary to provide

services to their customers.’’ 780 It asks

whether the costs are those ‘‘which a

reasonable utility management * * *

would have made, in good faith, under

the same circumstances, and at the

relevant point in time.’’ 781 We clarify

that we do not intend to permit

prudence proceedings to become an

opportunity for collateral attacks on

stranded cost recovery.

K. Other

1. Information Reporting Requirements

for Public Utilities

In the Final Rule, the Commission

indicated that it will not now eliminate

the public disclosure of allegedly

competitively sensitive, proprietary, or

otherwise confidential data submitted to

the Commission on Form No. 1, as well

as on other Commission forms. 782 It

explained that the information it

collects from public utilities is

necessary to carry out its jurisdictional

responsibilities and is used, among

other things, to evaluate the

reasonableness of cost-based rates

subject to the Commission’s jurisdiction

and the operation of power markets.783

Moreover, the Commission noted its

explanation in ConEd:

[r]eports required to be submitted by

Commission rule and necessary for the

Commission’s jurisdictional activities are

considered public information. 18 C.F.R.

§ 388.106. In addition, the Commission has

long required jurisdictional utilities to

submit Form 1 data on a form that states on

its cover that the Commission does not

consider the material to be confidential. [784]

The Commission expressed sensitivity

to the lack of symmetry in the

generation information we require from

traditional public utilities, particularly

those that have market-based rate

authority, and the generation

information required from other public

utilities (e.g., public utility marketers)

authorized to sell at market-based rates,

but explained that the record in the

proceeding is insufficiently developed

to make and support a well-informed

decision requiring a different reporting

scheme, particularly given the

industry’s current rapid pace of change.

Also, the Commission indicated that it

was not persuaded that the burdens

borne by traditional public utilities

(primarily annual reports submitted

months after-the-fact) are impairing the

competitiveness of these utilities so

much that we must act hastily now,

instead of deferring a decision to a more

appropriate proceeding.

However, the Commission stated that

it will monitor its reporting

requirements to make sure that they are

needed, fair to all segments of the

industry, and consistent with the

workings of a competitive environment.

Rehearing Requests

Allegheny asserts that this proceeding

is the proper forum to evaluate the

public disclosure of information

required from public utilities because it

is necessary to avoid disparate treatment

of market participants that violates the

comparability standard and leads to

market distortions. It argues that the

Commission should eliminate the

requirement to file data on Form No. 1

and other informational filings, or

alternatively the Commission should

protect the information as proprietary

and confidential.

Centerior argues that the Commission

should eliminate the public disclosure

of the cost-based generation rates and

provide for symmetry between the

information provided by public utilities
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12431

785FERC Stats. & Regs. at 31,853–54; mimeo at

636–38. The Commission also noted that nonpublic utility entities could request that the

Commission find that they can satisfy the

reciprocity condition without meeting all or some

of the requirements that public utilities must meet.

786FERC Stats. & Regs. at 31,854; mimeo at 637–

38.

787Black Creek Hydro, Inc. (Black Creek), 77

FERC ¶ 61,232 (1996); Midwest Energy, Inc., 77

FERC ¶ 61,208 (1996).

788FERC Stats. & Regs. at 31,854–55; mimeo at

640.

789FERC Stats. & Regs. at 31,855; mimeo at 642.

790FERC Stats. & Regs. at 31,856; mimeo at

644–45.

and power marketers by eliminating the

reporting requirements.

EEI indicates that it intends to

petition the Commission for further

action on information reporting

requirements in the near future. It adds

that it seeks to work with the

Commission in streamlining the

reporting process and in creating a level

playing field.

Commission Conclusion

We are not persuaded that the

information reporting requirements for

public utilities need to be changed at

this time. Very simply, it is premature

to take such a step at a time when much

of the industry is still under cost-based

rate regulation for sales of electric

energy and when corporate

restructuring, including utility mergers,

is occurring at a rapid pace. On

rehearing, entities have merely

reiterated the arguments that we

previously addressed in the Final Rule

and have presented no evidence that the

competitiveness of traditional public

utilities is being impaired by their

having to submit primarily annual

reports that are filed months after the

fact. Accordingly, we will continue to

require public utilities to submit the

information required by our rules and

regulations and we will monitor our

reporting requirements as the industry

environment continues to change.

2. Small Utilities

The Commission noted that it was

sympathetic to the array of concerns

raised by small public utilities and

small transmission customers and

explained that the regulations it was

adopting include waiver provisions

under which public utilities and

transmission customers, and non-public

utility entities seeking exemption from

the reciprocity condition, may file

requests for waivers from all or part of

the Commission’s regulations or for

special treatment.785 However, the

Commission explained, it is difficult to

imagine any circumstance that would

justify waiving the requirements of this

Rule for any public utility that is also a

control area operator.

The Commission recognized that it

might be a financial burden on small

public utilities to unbundle generation

from transmission, follow standards of

conduct that separate transmission

personnel from wholesale marketing

personnel, and maintain an OASIS. In

addition, the Commission explained

that for small public utilities that own

no generation and buy at wholesale on

a radial transmission line from another

utility’s grid or if their service territory

is part of another utility’s control area,

the small public utility should be

permitted to make a showing that it

should be exempt from all or some of

the Rule.

The Commission further explained

that because the possible scenarios

under which small entities may seek

waivers from the Final Rule are diverse,

they are not susceptible to resolution on

a generic basis and the Commission will

require applications and fact-specific

determinations in each instance.

In addition, the Commission

indicated that it will apply the same

standards to any entity seeking a waiver.

The Commission explained that this

includes public utilities seeking waiver

of some or all of the requirements of the

Rule, as well as non-public utilities

seeking waiver of the reciprocity

provisions contained in the pro forma

open access tariff. The Commission

concluded that it would not apply the

open access reciprocity provision to

small non-public utilities that are not

control area operators and either do not

own or control transmission or have

transmission that no one is likely to ask

to use. However, the Commission

explained that they will have to apply

for this waiver and demonstrate that

they qualify for the waiver.

Rehearing Requests

APPA asserts that absent a finding

that a non-public utility has market

power or has exhibited undue

discrimination, the non-public utility

should be granted a waiver.

Michigan Systems asks that the

Commission modify the Rule to provide

a blanket waiver for systems that by

their nature cannot have market power

over transmission and do not have the

personnel to separate functions. It also

asserts that the Final Rule waiver

procedure is cumbersome and time

consuming.

Tallahassee asks the Commission to

clarify that it will liberally apply its

waiver policy to small public utilities

even if they run a control area. It asserts

that the proper focus of concerns over

competition are a utility’s size, its

ability to manipulate the market, and

how it operates its control room.

CAMU asks the Commission to clarify

that the small utilities waiver will be

generally available to those entities

lacking market power because only

utilities with market power are capable

of subverting the transmission market.

Commission Conclusion

The issues raised with respect to

waivers for small utilities are more

appropriately addressed in individual

fact-specific proceedings. As we

explained in the Final Rule,

[b]ecause the possible scenarios under which

small entities may seek waivers from the

Final Rule are diverse, they are not

susceptible to resolution on a generic basis

and we will require applications and factspecific determinations in each instance. We

note here that any waivers that we may grant

depend upon the facts presented in each

case.[786]

Indeed, we have granted a variety of

waiver requests by small utilities since

issuance of the Final Rule.787

3. Regional Transmission Groups

a. Incentives for RTGs To Form and

Resolve Regional Transmission Issues

In the Final Rule, the Commission

expressed its continued support for the

development of RTGs and encouraged

regional tariffs.788 To further encourage

the development of RTGs, the

Commission stated that it will accept

regional open access transmission tariffs

developed by RTGs that are consistent

with the objectives of this Rule.

b. Deference To RTGs to Develop

Regional Tariffs and Prices

In the Final Rule, the Commission

indicated its intent to give deference to

the planning, dispute resolution, and

decisionmaking processes of an RTG. 789

With respect to pricing proposals

submitted by RTGs, the Commission

stated that RTGs may be able to develop

solutions to such problems as loop

flows through innovative flow-based

pricing methodologies.

Rehearing Requests

No requests for rehearing addressed

this matter.

4. Pacific Northwest

In the Final Rule, the Commission

encouraged the filing of regional open

access transmission tariffs.790 It also

explained that the Final Rule pro forma

tariff contains provisions allowing

utilities to modify tariff terms to reflect

prevailing regional practices. The

Commission concluded that this should

permit entities in the Pacific Northwest
12432 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

791FERC Stats. & Regs. at 31,857–58; mimeo at

648–49.

792The Commission noted, however, that PMAs

are transmitting utilities subject to requests for

mandatory transmission services under section 211

of the FPA.

793FERC Stats. & Regs. at 31,858; mimeo at 650–

51.

794The Commission noted, however, that TVA is

a transmitting utility subject to requests for

mandatory transmission services under section 211

of the FPA.

795FERC Stats. & Regs. at 31,858–59; mimeo at

651–52.

796FERC Stats. & Regs. at 31,859; mimeo at

654–55.

797FERC Stats. & Regs. at 31,860; mimeo at 656.

to address unique circumstances that

exist in the Pacific Northwest and to

incorporate prevailing regional practices

(e.g., treatment of hydropower

generation in the priority of dispatch)

into their open access transmission

tariffs.

Rehearing Requests

No requests for rehearing addressed

this matter.

5. Power Marketing Agencies

a. Bonneville Power Administration

(BPA)

In the Final Rule, the Commission

stated that BPA is not a public utility

under section 201(e) of the FPA and,

thus, is not subject to the requirements

of this Rule to put the Final Rule pro

forma tariff into effect.791 However, the

Commission indicated three

circumstances under which the

Commission may review BPA’s

transmission access and pricing

policies.

With respect to stranded costs, the

Commission clarified that the Rule

addresses only stranded costs recovered

by public utilities under the FPA and

transmitting utilities (including BPA)

that are subject to mandatory

transmission requests under FPA

section 211. It explained that the Rule

does not address stranded cost recovery

by BPA under the Northwest Power Act.

Rehearing Requests

BPA asks the Commission to clarify

that it did not intend to address

stranded cost recovery by BPA under

either the Northwest Power Act or

section 212(i) of the FPA. If Order No.

888 is intended to govern stranded cost

recovery by BPA in the case of

Commission-ordered transmission

under section 211, BPA asks the

Commission for an opportunity to brief

the issue on rehearing.

Commission Conclusion

We clarify that our review of stranded

cost recovery by BPA would take into

account the statutory requirements of

the Northwest Power Act and the other

authorities under which we regulate

BPA (e.g., DOE delegation for interim

rate approval) and/or section 212(i), as

appropriate.

b. Other Power Marketing Agencies

In the Final Rule, the Commission

explained that Federal power marketing

agencies (PMAs) are not public utilities

as defined under section 201(e) of the

FPA and, thus, are not required by this

Rule to file non-discriminatory open

access transmission tariffs.792 However,

the Commission did state that to the

extent a PMA receives open access

transmission service from a public

utility, it is subject to the reciprocity

provisions in the utility’s pro forma

tariff.793

With respect to SEPA’s concern that

the proposed point-to-point tariff has a

one MW minimum scheduling

requirement, but many of its customers

have loads of less than one MW, the

Commission clarified that the Final Rule

pro forma tariff will allow SEPA to

continue to schedule service for these

customers. The Commission also

clarified that SEPA, as a seller of power

to multiple purchasers inside several

control areas, is eligible to receive

network service.

Rehearing Requests

Entergy asks the Commission to

clarify that SEPA can obtain network

service only in the same manner as any

other customer and that there was no

intent in the Rule to create a special

type of network service for SEPA.

Commission Conclusion

We will clarify that for purposes of

obtaining network service SEPA is to be

treated as any other customer.

6. Tennessee Valley Authority

In the Final Rule, the Commission

stated that TVA is not a public utility

under section 201(e) of the FPA and,

thus, is not required to file a nondiscriminatory open access transmission

tariff under this Rule.794 However, the

Commission explained, if TVA receives

open access transmission service from a

public utility, it is subject to the

reciprocity provision in the utility’s pro

forma tariff.795

Rehearing Requests

No requests for rehearing addressed

this matter.

7. Hydroelectric Power

Non-Firm Transactions

In the Final Rule, the Commission

explained that it will permit entities to

incorporate prevailing regional practices

(e.g., treatment of hydropower

generation in the priority of dispatch)

into regional open access transmission

tariffs.796 This, the Commission

indicated, should permit entities in a

region to resolve concerns over the

scheduling of non-firm hydropower.

Commission’s Licensing Practices

The Commission explained that the

issues raised by National Hydropower

with respect to the Commission’s

hydroelectric licensing practices are

beyond the scope of this rulemaking.

The Commission also noted that these

issues were raised in a petition to the

Commission to revise hydroelectric

licensing procedures, filed on July 10,

1995. That is the proper proceeding, the

Commission explained, in which to

address the Commission’s hydroelectric

licensing practices.

Rehearing Requests

No requests for rehearing addressed

this matter.

8. Residential Customers

In the Final Rule, the Commission

stated that it was convinced that the

proposed changes for wholesale markets

will benefit residential consumers. 797

Moreover, the Commission explained

that the Rule does not require retail

transmission access for retail customers

of any size and does not require any

changes in programs such as assistance

to low-income and elderly consumers

and weatherization and energy

conservation, which are, and will

remain, under the jurisdiction of the

individual states. The Commission

further noted that the Rule contains

several safeguards to maintain the

ability of states to impose conditions on

retail access, such as conditions that

help to protect residential customers

from becoming the residual payer of

stranded costs.

Rehearing Requests

No requests for rehearing addressed

this matter.

9. Miscellaneous Issues

Unconstitutional Taking of Property

Union Electric declares that the

imposition of an onerous regime of

mandates governing what utilities must

and must not do with their own

property constitutes an unconstitutional

taking of their property in violation of

the takings clause.
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12433

798FERC Stats. & Regs. at 31,682–84; mimeo at

136–142.

799Union Electric argues that

[t]he dramatic changes in the regulatory scheme

set forth in the final rules impose extensive

constraints on Union Electric’s use of its own

property, forcing Union Electric to throw open its

transmission system to use by third parties,

dictating the terms and conditions of that usage

and, in the process, providing for the physical

occupation of Union Electric’s transmission system

by third parties’ facilities and power. (Union

Electric at 59).

However, as Union Electric’s own words

demonstrate, these so-called dramatic changes are

no more than a summary of the Commission’s

current authority and the Commission’s current

regulation of public utilities. Under the FPA, Union

Electric can only provide non-undulydiscriminatory jurisdictional services to third

parties and must obtain Commission approval of

the rates, terms and conditions pursuant to which

it provides such service. Moreover, under Order No.

888, third parties may ‘‘physically occupy’’ Union

Electric’s transmission system only pursuant to the

terms of Union Electric’s tariff and contracts

entered into with Union Electric, just as third

parties previously had the right to ‘‘physically

occupy’’ its transmission system.

Finally, we are confused about Union Electric’s

argument in that in the pending merger proceeding

involving its proposed merger with Central Illinois,

it argues that the open access tariff of the merged

company will be used to mitigate market power.

See El Paso Electric Company and Central and

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

61,914 (1994), dismissed, 72 FERC ¶ 61,292 (1995).

Union Electric cannot argue that the tariff mitigates

market power at the same time it argues that the

requirement to have the tariff is prohibited as an

unconstitutional taking of property.

800See, e.g., FPC v. Hope Natural Gas Company,

320 U.S. 591 (1944). Moreover, to the extent Union

Electric’s facilities are used for public service,

Union Electric is entitled to recover all prudently

invested capital in the public utility enterprise. We

have not changed that principle.

801FPC v. Texaco, 417 U.S. 380, 391–92 (1974);

see also FPC v. Natural Gas Pipeline Co., 315 U.S.

575, 585 (1942).

802All public utilities subject to Commission

jurisdiction were required to file open access

compliance tariffs, including the rate to be charged

for various types of transmission service, by July 9,

1996.

803With specific regard to Cleveland and CEI, we

note that the Commission has expended

considerable resources over the years dealing with

and resolving a significant number of section 205

and 206 proceedings in which these companies

contested a plethora of issues. As the D.C. Circuit

noted, these two entities have a particularly hostile

relationship. City of Cleveland v. FERC, 773 F.2d

1368, 1371 (1985). This has led to a situation where

these contentious entities are more likely to contest

issues before the Commission than to resolve them.

Since 1993 alone, the Commission has addressed

and resolved at least 9 proceedings involving

disputes between Cleveland and CEI. Indeed, at this

time, the Commission has only several ongoing

proceedings involving disputes between these

entities. In addition, the parties are in disagreement

over transmission issues in the pending merger

application involving CEI and Ohio Edison.

Commission Conclusion

Union Electric has provided no valid

legal or factual basis to support its

arguments that our final orders result in

an unconstitutional taking of property

in violation of the takings clause. We

have a statutory obligation under the

FPA to remedy undue discrimination in

the transmission or sale of electric

energy subject to our jurisdiction. In

Order No. 888, we concluded that

unduly discriminatory and

anticompetitive practices exist today in

the electric industry and that such

practices will increase as competitive

pressures continue to grow in the

industry.798 Accordingly, we exercised

our remedial authority by issuing Order

Nos. 888 and 889 to ensure that unduly

discriminatory practices can no longer

occur.799

In exercising our remedial authority,

we did not alter the traditional principle

that a utility is entitled to a reasonable

opportunity to recover its prudently

incurred costs.800 Union Electric has

provided no evidence that it will not be

adequately compensated for whatever

services it may provide on its system

following the effectiveness of Order

Nos. 888 and 889. To the extent a third

party uses Union Electric’s transmission

system, it must still compensate Union

Electric for that usage, as has happened

in the past. There simply cannot be an

unconstitutional taking of property

when public utilities continue to have

the right to file for and receive rates that

provide them a reasonable opportunity

to recover their prudently incurred

costs. Indeed, as the Supreme Court has

explained, ‘‘[a]ll that is protected

against, in a constitutional sense, is that

the rates fixed by the Commission be

higher than a confiscatory level.’’ 801

Union Electric has made no showing

that Order Nos. 888 and 889 will result

in its rates being set at a confiscatory

level. Furthermore, the rate that Union

Electric may charge for transmission

service is currently before the

Commission in Docket No. OA96–50–

000 and Union Electric should make

arguments regarding the reasonableness

of its transmission rate in that

proceeding. 802 Moreover, Union

Electric is free to propose changes to the

rate it charges for transmission from

time to time to ensure that it is being

fairly compensated for its investment in

its transmission system, as well as any

expenses it incurs in providing such

service.

Section 206 Complaints

Cleveland states that, unfortunately, it

has suffered significantly because of

denied transmission access and the

inefficacy of long-delayed enforcement

relief under section 206 of the FPA.

Thus, Cleveland states that the

Commission must announce its

intention to enforce transmission and

related obligations and, having made

that pronouncement, take whatever

steps are necessary to do so.

TAPS states that throughout the Final

Rule the Commission points to

complaint procedures to redress

complaints against transmission

providers’ open access tariffs and argues

that the Commission must clarify that

these complaints will receive expedited

treatment.

Commission Conclusion

The Commission has a statutory

obligation to act if it finds, upon its own

motion or upon complaint, that any rate,

charges, or classification demanded,

observed, charged, or collected by any

public utility, or that any rule,

regulation, practice, or contract affecting

such rate, charge, or classification is

unjust, unreasonable, unduly

discriminatory or preferential, and to

determine the just and reasonable rate,

charge, classification, rule, regulation,

practice, or contract to be thereafter

observed. Moreover, section 206(b) of

the FPA requires that whenever the

Commission institutes a proceeding

under this section it must establish a

refund effective date. In carrying out its

obligations under section 206 of the

FPA, the Commission acts as

expeditiously as is possible, given the

complexities of the issues at hand, its

other workload and its level of staffing.

The Commission will continue to work

as expeditiously as possible in resolving

section 206 proceedings, as well as in

resolving all of the other matters that

come before it. Given the critical

importance of timely, comparable

transmission access in fostering

competitive wholesale power markets,

the Commission intends to vigorously

enforce utilities’ open access

obligations. 803

We would emphasize that filing

complaints with the Commission is not

the only avenue that transmission

customers (or potential customers) can

pursue to raise their concerns. Under

the Open Access Transmission Tariff,

parties can and should avail themselves

of the Dispute Resolution Procedures set

forth in section 12 of the pro forma

tariff. This section provides that an

arbitrator must render a decision and

notify the parties within ninety days of

appointment.

NRC Remedial Orders

Cleveland asks that the Commission

clarify that directives requiring nondiscriminatory treatment of

transmission customers are not intended

to override, but are expected to

accommodate, valid remedial orders of

the NRC imposed in the form of nuclear

license conditions.
12434 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

804Ohio Valley states that the facility is now

leased by the United States to the United States

Enrichment Corporation.

805 Dayton filed a motion to reject Ohio Valley’s

request for rehearing, arguing that it was really an

application for waiver. (Dayton Motion to Reject).

806Order Clarifying Order Nos. 888 and 889

Compliance Matters, 76 FERC ¶ 61,009 (1996).

807E.g., VT DPS, Valero, APPA.

Commission Conclusion

We will deny Cleveland’s requested

clarification because it is overly broad.

However, we do clarify that we view our

jurisdiction under the FPA and the

NRC’s jurisdiction as complementary. In

that regard, a utility subject to the

Commission’s jurisdiction and to the

NRC’s jurisdiction would have to

comply with the orders of both

commissions. Moreover, just as the NRC

cannot and does not enforce this

Commission’s orders, it is not within

our jurisdiction to enforce orders of the

NRC. In the event that an entity believes

that it must, but cannot, comply with

separate orders issued by this

Commission and the NRC, it should

present evidence to this Commission

and/or the NRC of such a conflict. To

the extent necessary and appropriate,

we would attempt to resolve any such

conflicts subject to our jurisdiction

under the FPA.

Retail Customers’ Future Access to

Transmission Capacity

IL Industrials states that the

Commission should fashion safeguards

to prevent monopolization of

transmission capacity by wholesale

customers before retail customers are

entitled to engage in direct access.

Alternatively, IL Industrials states that

the Commission should specify that this

issue will be addressed in the CRT

NOPR proceeding and that contracts or

other arrangements affecting available

transmission capacity will be subject to

safeguards to protect retail customer

transmission access.

Commission Conclusion

This matter is beyond the scope of

this proceeding. We have no way of

ascertaining the transmission capacity

that a retail customer may require in the

future should it become entitled to

engage in direct access through a stateapproved program or voluntary action

by its current transmission provider. We

cannot require a transmission provider

to keep transmission capacity available

for all possible transactions that a retail

customer may possibly enter into in the

future. Just as transmission customers

must take the system as it exists at the

time of a request, so must future

potential transmission customers take

the system as it exists at the time of their

request.

Transaction Accommodation

Arrangements

NCMPA argues that the Commission

failed to address the problem of market

power arising from a transmission

provider’s control over transaction

accommodation arrangements, which it

states are arrangements needed by

transmission dependent utilities to

accommodate third-party transactions

within an existing power supply

relationship between the TDU and the

transmission provider. NCMPA explains

that this problem is most apparent

where there is a comprehensive power

supply relationship that purports to

establish most or all of the TDU’s bulk

power needs. For example, NCMPA

points out that because of Duke Power

Company’s control over transaction

accommodation arrangements, NCMPA

has been frustrated in its attempts to

pursue beneficial bulk power

transactions with parties other than

Duke. NCMPA asks that the

Commission require transmission

providers to provide these arrangements

on a comparable basis, state that it will

take prompt action to remedy a denial

of comparable arrangements, and

require that any utility seeking specific

permission for any action premised on

the mitigation of market power to

demonstrate that it has offered

comparable transaction accommodation

arrangements to any TDU that requires

such arrangements.

Commission Conclusion

NCMPA’s concerns appear to be

related to its existing power supply

arrangements, not with new service

under the pro forma tariff. These

concerns are more appropriately

addressed in a case-specific section 206

complaint proceeding before the

Commission.

Ohio Valley—Power to Uranium

Enrichment Facility

Ohio Valley asks the Commission to

clarify that the orders do not apply to

Ohio Valley so that Ohio Valley can

continue to provide the lowest possible

cost, and most reliable, service to the

Piketon, Ohio uranium enrichment

facility owned by the United States.804

Otherwise, Ohio Valley argues,

compliance could result in increased

costs to the United States and to the

customers of the utilities participating

in providing power to the enrichment

facility. Ohio Valley seeks to avoid

unnecessary interference with its ability

to carry out its obligations under the

existing agreements, but is amenable to

reasonable and prudent use of its

transmission system in accordance with

sections 211 and 212.805

Commission Conclusion

Ohio Valley’s rehearing request is

essentially an application for waiver

that is not properly addressed in this

proceeding. By order issued July 2,

1996, we explained that because of the

fact-specific nature of waiver requests

the Commission will not address such

requests in a generic rulemaking

proceeding, but will require entities

seeking waiver to submit separate, factspecific requests that will be docketed

in separate OA proceedings.806

Subsequently, Ohio Valley filed a

separate petition for waiver in Docket

No. OA96–126–000 that effectively

reiterated the arguments made in its

rehearing request. The Commission will

address Ohio Valley’s fact-specific

arguments in Docket No. OA96–126–

000.

Exchanges

Several entities argue that exchanges

should be permitted without a

requirement that customers book

capacity for each direction the power

will flow and parties should not each

have to pay the full reservation

charge.807 Because point-to-point

customers can change receipt points

without payment of additional charges,

they argue that the same logic applies to

exchanges.

Commission Conclusion

An exchange between two utilities

has traditionally been viewed as two

separate transactions (two one-way

services) from the transmitting utility’s

planning and reservation perspective

and has been priced as two separate

services. Consistent with this approach,

the pro forma tariff only allows changes

to points of receipt and delivery for

point-to-point service on a non-firm

basis at no extra charge. Any changes to

points of receipt and delivery on a firm

basis must be submitted to the

Commission as new applications.

However, we note that comparability is

achieved if the transmission provider

charges itself and its transmission

customers for point-to-point service on

a consistent basis, whether that be

separately for both directions or on a

bidirectional basis.

Various Rate Matters

VT DPS and Valero argue that rates

‘‘should be based on a definition and

quantification of a core of transmission

function lines and substations for use in

wholesale wheeling rather than on the

basis of a rolled-in rate for the entire
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12435

808American Forest & Paper at 24.

809FERC Stats. & Regs. at 31,860; mimeo at 657–

58 (footnote omitted).

810The EIS also conducts sensitivity analyses of

how projected air emissions might change if key

assumptions in the analysis are changed. These

analyses include two frozen efficiency reference

cases which represent a world in which: (1) the

Commission reverses current pro-competitive

transmission policy (inconsistent with

congressional mandates under EPAct); (2) states

cease to adopt programs to improve industry

efficiency; and (3) electric companies cease to

improve operations or to enter into mutually

beneficial transactions.

811Letter of May 22, 1996 from Mary Nichols,

Assistant Administrator for Air and Radiation, EPA,

to Kathleen McGinty, Chair, CEQ.

transmission network.’’ VT DPS states

that ‘‘[i]n order to insure against cross

subsidization, the tariffs should provide

for the imposition of a Local

Transmission System Access Charge to

recover the costs of the facilities used to

provide service to customers in this

category.’’ (VT DPS at 23–24; Valero at

8–10).

American Forest & Paper argues that

the Commission’s proposal includes as part

of the transmission revenue requirement

amounts attributable to the utility’s use of its

own transmission system to effectuate offsystem sales and revenues received from

transmission customers taking service under

existing contracts and tariffs but not under

the new transmission tariffs. By failing to

subtract such revenues from the revenue

requirement used to determine rates for

services rendered under the new tariffs, the

utility effectively recovers these amounts

twice: once from its off-system sales and

transmission customers not taking service

under the new tariffs and a second time from

its customers taking service under the

proposed new tariffs.’’[808]

American Forest & Paper asserts that

to eliminate this double-recovery, the

Commission should adopt PacifiCorp’s

proposal in Docket No. ER95–1240.

American Forest & Paper further

declares that the Commission must

demonstrate that the charges imposed

on customers of network wheeling

service are commensurate with the

benefits that they receive.

Commission Conclusion

We are not prepared to mandate in a

generic proceeding such as this that all

transmission rates must be established

by function or that a specific pricing

methodology should be used. Our rate

policy, as set forth in the Transmission

Pricing Policy Statement, is to

encourage flexible and innovative rate

approaches by the electric industry.

Mandating a single methodology for the

entire industry would certainly defeat

that goal. While the Commission

welcomes new and innovative

proposals, we will not impose a generic

change in this proceeding. As always,

utilities are free to propose the use of a

functional pricing method in their

compliance filings or in any section 205

filing it may submit to the Commission.

Federal Government Contract Clauses

ConEd asserts that the Commission

must modify the pro forma tariff to

include certain Federal government

required anti-discrimination clauses.

According to ConEd, these clauses

require that all of Con Edison’s

transmission providers agree to be

bound by certain provisions of the

federal subcontractor regulations.

ConEd suggests that the ‘‘Commission

state that Con Edison and similarlysituated utilities be permitted to comply

with the federal subcontracting

requirements by inserting such clauses

in their service agreements for

transmission services.’’ (ConEd at 17–

18).

Commission Conclusion

The Commission disagrees with

ConEd’s assertion that the Commission

must modify the pro forma tariff to

include certain Federal government

anti-discrimination clauses. The

Commission does not dispute that

certain parties must comply with

provisions of the federal subcontractor

regulations for particular transactions

that may involve the provision of

transmission service. However, we do

not agree that these provisions must be

incorporated into the pro forma tariff.

The contracting obligation raised by

ConEd is independent of the pro forma

tariff and more appropriately addressed

in a separate contract between the

parties to the purchase or the service

agreements for transmission services.

The Commission notes that this is

apparently how the issue has been

handled in the past by ConEd because

its tariffs previously filed with the

Commission (pre-NOPR) did not

include such anti-discrimination

clauses.

V. Environmental Statement

Summary

The Commission prepared an

environmental impact statement (EIS) to

evaluate the environmental

consequences that could result from

adopting the Rule. We did so largely in

response to the claims of several

commenters who charge that the Rule

will have significant adverse

environmental effects. As described in

Order No. 888:

Although a number of issues were raised,

by far the most prominent concern arises

from the theory that competitive market

conditions created by the rule will provide

an advantage to power suppliers who

produce power from coal-fired facilities that

are not subject to stringent controls on

nitrogen oxides (NOX) emissions. Under this

theory, these facilities, located primarily in

the Midwest and South, will, as a result of

the rule, generate more power and emit more

NOX, which will contribute to ozone

formation. The ozone could add to pollution

both in those regions and more significantly

in the Northeast, to which area such

pollutants could be transported. Those who

propound this theory argue that it is the

responsibility of the Commission, using its

authority under the Federal Power Act, to

effect environmental controls that will

mitigate what they predict will be significant

increases in NOX emissions associated with

this rule.[809]

The EIS recognizes that the electric

industry will contribute to air emissions

regardless of whether the Rule is

adopted. The purpose of the EIS is to

analyze to what extent the Rule is likely

to affect those emissions.

Many variables can influence the

impacts of the Rule and the EIS uses a

modeling framework that incorporates a

range of assumptions about these

variables. The most significant variable

is likely to be the future prices of the

two primary fuels used to generate

electricity—coal and natural gas.

Government and industry price

forecasts were used to construct two

alternative fuel price assumptions: (1)

that the price of natural gas will

increase relative to the price of coal; and

(2) that the relative price of coal and

natural gas will remain constant. These

assumptions form the basis for two base

cases that project the environmental

impacts of developments in the electric

industry without the Rule. The EIS then

makes assumptions about the effects of

the Rule to create three scenarios that

project a range of possible results. It

compares the environmental impacts

projected in the scenarios with those

projected in the base cases to determine

the effect of the Rule.810 The analysis set

forth in the EIS demonstrates that the

Rule will not in any significant respect

affect overall trends in NOX emissions.

Subsequent to the issuance of Order

No. 888, the Environmental Protection

Agency (EPA) conducted a review of the

Commission’s FEIS in which EPA

employed alternative assumptions for a

number of model inputs. In doing so,

EPA stressed that ‘‘[n]aturally there can

be differences among reasonable

analysts concerning the assumptions

used in such an analysis’’ and that ‘‘EPA

believes the assumptions used by the

FERC and those used by EPA both lie

within the reasonable range.’’ 811 EPA

has concluded that the Rule is unlikely

to have any significant adverse

environmental impact in the immediate
12436 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

812Letter of May 13, 1996, from Carol Browner,

Administrator, EPA to Kathleen McGinty, Chair,

CEQ.

813Order Responding to Referral to Council on

Environmental Quality, 75 FERC ¶ 61,208 at

61,691–92 (1996).

814Letter of June 14, 1996 from Kathleen

McGinty, Chair, CEQ, to Carol Browner,

Administrator, EPA and Elizabeth Moler, Chair,

FERC.

815FEIS at 2–1 and 2–2.

816To date, the Commission has issued six

proposed orders and four final section 211 orders.

Id. at 2–1.

future, and that implementation of the

Rule should go forward without delay.

In reaching these conclusions, EPA

concurred that the Commission

conducted an adequate NEPA analysis

of the environmental impacts of the

Rule under a range of possible

scenarios. EPA also agreed that the

Commission made a reasonable choice

of models with which to conduct the

analysis and, as noted above, made

assumptions for various factors input

into the model that lie within the range

of reasonable assumptions.

EPA also concurred with the

Commission that NOX emissions

increases associated with the Rule, if

any, should be addressed as part of a

comprehensive NOX emissions control

program developed by EPA and the

states pursuant to the Clean Air Act.

EPA committed to use its Clean Air Act

authority to support successful

completion of this program, and stated

that it will establish a NOX cap-andtrade program through Federal

Implementation Plans if some states are

unwilling or unable to act in a timely

manner.

In a letter dated May 13, 1996, the

EPA Administrator referred Order No.

888 to CEQ.812 In doing so, EPA suggests

that if the Ozone Transport Assessment

Group (OTAG) and Clean Air Act

processes fail to produce the necessary

pollution limitations in a timely

manner, EPA will call upon all other

interested federal agencies to assist in

solving the problem. EPA would ask the

Commission to contribute by examining,

through a Notice of Inquiry, possible

strategies for mitigating NOX emissions

increases associated with the Rule.

The Commission subsequently

responded by issuing an order stating

that if EPA concludes that the OTAG

process has not succeeded in meeting its

objectives in a timely manner, the

Commission would initiate a Notice of

Inquiry to further examine what

mitigation might be permissible and

appropriate under the Federal Power

Act. Such an inquiry would solicit

public comment on how to assess

appropriately the air pollution impacts

attributable to the Rule, suitable ways in

which to address such impacts, if any,

and the scope of the Commission’s

authority to address such impacts. The

Commission also stated that, under the

extraordinary circumstances in which

EPA would undertake a Federal

Implementation Plan, the Commission

would agree to initiate

contemporaneously a rulemaking to

propose possible mitigation that could

be undertaken by the Commission under

the FPA. Such a rulemaking would be

undertaken on the basis of the Notice of

Inquiry discussed above and would be

appropriate only if environmental harm

attributable to the Rule that warranted

mitigation is demonstrated.813 On June

14, 1996, CEQ concluded that the

Commission’s order was fully

responsive to EPA’s concerns and

requests and that the referral process

and corresponding responses to the

referral from the Commission and other

agencies have successfully resolved the

disagreements between EPA and the

Commission.814

As discussed below, EPA is currently

taking steps to implement a

comprehensive NOX emissions control

program to ensure that emissions

reductions are achieved to prevent

significant transport of ozone pollution

across state boundaries in the Eastern

United States. OTAG is continuing to

work in conjunction with EPA on this

issue and intends to complete its

process in the near future.

Rehearing is sought on eight

categories of issues relating to the

Commission’s analysis of environmental

issues: selection of the appropriate noaction alternative; challenges to

modeling assumptions; need for

mitigation; emissions standards

disparity; the short-term consequences

of the Rule; cost benefit analysis;

socioeconomic impacts; and compliance

with the Coastal Zone Management Act.

For the reasons discussed below,

rehearing is denied.

A. The Appropriate No-Action

Alternative

The FEIS discusses several

alternatives, including the alternative of

instituting open access pursuant to

section 211 of the FPA. The FEIS states

in this regard that:

Actions taken pursuant to section 211 and

pursuant to sections 203 and 205 in merger

and market-rate cases, respectively, represent

a case-by-case approach to establishing open

access. Absent action on the proposed rule,

the Commission would continue using these

authorities to require utilities to file open

access tariffs and provide case-specific

service, as necessary or appropriate. In

addition, sections 205 and 206 charge the

Commission with ensuring that purely

voluntary transmission tariffs are not unduly

discriminatory. Thus, if the proposed rule

were not adopted, the Commission would

continue to require that voluntary tariffs be

upgraded to offer the Commission’s current

standards for non-discriminatory open access

transmission services. The result of

continuing the Commission’s policies

without the proposed rule is that the

Commission would effectuate a more open

transmission grid, but in a patchwork manner

and at a slower pace.

The case-by-case approach to achieving

open access currently in use is slower and

more costly, and thereby less desirable, than

the generic approach set forth in the

proposed rule. Thus, the no-action

alternative is not a reasonable alternative to

the proposed rule.815

Rehearing Requests

The PA Com contends that the FEIS

does not adequately consider the

alternative of instituting open access

pursuant to section 211 of the FPA. It

states that 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 that the FEIS

ignores the steady, if slow, progression

to open access taking place under

section 211.

Commission Conclusion

The FEIS notes that there are

significant reasons for implementing

open access through a rulemaking rather

than the case-by-case approach of

section 211. In the absence of a

Commission rulemaking, the

development of open access pursuant to

section 211 would occur as potential

transmission users file requests for such

services and the Commission approves

them as appropriate. Such proceedings

are likely to be contested by competitors

and the Commission would decide each

application individually. Given the

number of potential transmission users

who are likely to file requests for such

services, it is conceivable that this

approach may require the Commission

to decide a large number of such

applications. 816 Thus, the case-by-case

approach is likely to be much slower

and more costly to implement than

action by rule.

Case-by-case implementation of open

access is also more likely to result in

patchwork development as the policy

evolves over time. It is important to

develop uniform national standards to

facilitate the move to open access. This

approach adds certainty and facilitates

development and implementation of

open access in a way that would be

difficult to achieve on a case-by-case

basis. The development of national
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12437

817See also Northwest Coalition for Alternatives

to Pesticides v. Lyng, 844 F.2d 588, 591 (9th Cir.

1988).

818 Vermont Yankee Nuclear Power Corp. v.

Natural Resources Defense Council, Inc., 435 U.S.

519, 551 (1978); Laguna Greenbelt, Inc. v. U.S.

Department of Transportation, 42 F.3d 517, 524 (9th

Cir. 1994).

819National Wildlife Federation v. Whistler, 27

F.3d 1341, 1345 (8th Cir. 1994).

820Laguna Greenbelt, supra, 42 F.2d at 524. In

that case, involving construction of a tollroad,

Laguna contended that the EIS ignored a smaller,

four-lane alternative. The EIS addressed this

proposal, explaining that it was rejected because a

four lane highway would not meet the project’s goal

of reducing traffic congestion. The court found that

the proposal was thus properly rejected as not

reasonably related to the purposes of the project. Id.

at 524–25.

standards is best done through a

mechanism whereby all interested

parties can participate in shaping the

policy through notice and comment

rulemaking. The piecemeal

implementation of open access on a

case-by-case basis over time, no matter

how carefully conducted, is likely to

result in inconsistencies and difficulty

in application. Given the national

nature of the electric grid and the

developing open access market, case-bycase implementation is not practical nor

desirable and will limit the anticipated

benefits of open access.

The PA Com does not specify how the

Commission fails to adequately consider

the alternative of instituting open access

pursuant to section 211. It is insufficient

for a party to complain that an analysis

is inadequate without providing specific

support for its claim. As the court noted

in Northside Sanitary Landfill, Inc. v.

Thomas, 849 F.2d 1516, 1519–20 (D.C.

Cir. 1988), cert. denied, 489 U.S. 1078

(1989):

In Vermont Yankee Nuclear Power Corp. v.

Natural Resources Defense Council, Inc., 435

U.S. 519, 98 S.Ct. 1197, 55 L.Ed.2d 460

(1978), then-Justice Rehnquist expressed the

unanimous opinion of seven members of the

Supreme Court that a party * * * has the

burden of clarifying its position for the

[agency]. Even though the [agency] has the

statutory obligation to consider fully

significant comments, ‘‘it is still incumbent

upon intervenors who wish to participate

* * * to structure their participation so that

it is meaningful, so that it alerts the agency

to the intervenors’ position and contentions.’’

435 U.S. at 553, 98 S.Ct. at 1216. Justice

Rehnquist, then quoted with approval Judge

Leventhal’s remarks in Portland Cement, id.,

and concluded that administrative

proceedings should not be a game or a forum

to engage in unjustified obstructionism by

making cryptic and obscure references to

matters that ‘‘ought to be’’ considered and

then, after failing to do more to bring the

matter to the agency’s attention, seeking to

have that agency determination vacated on

the ground that the agency failed to consider

matters forcefully presented.’’

Id., at 533–54, 98 S.Ct. at 1217.

We also note that the PA Com’s

quarrel does not appear to be with the

Commission’s analysis of the section

211 alternative in any event, but rather

with the underlying policy decision to

implement open access through a

rulemaking rather than more slowly on

a case-by-case basis.

The Administrative Procedure Act

authorizes agencies to establish policies

by rulemaking or on a case-by-case

basis. Here, the Commission has

properly exercised its discretion to

establish open access by rulemaking

rather than in individual proceedings.

The PA Com does not contest this

authority or the Commission’s exercise

of it. Rather, its complaint goes to the

underlying policy choices guiding that

decision. Disagreement with an agency’s

policy choice is not a proper basis for

a NEPA-based challenge to agency

action. As the Circuit Court of Appeals

for the District of Columbia (D.C.

Circuit) stated in Foundation on

Economic Trends v. Lyng, 817 F.2d 882,

886 (D.C. Cir. 1987) (footnote omitted)

(brackets in original):

NEPA was not intended to resolve

fundamental policy disputes. As the

Supreme Court recently admonished, ‘‘[t]he

political process, and not NEPA, provides the

appropriate forum in which to air policy

disagreements.’’ Metropolitan Edison Co. v.

People Against Nuclear Energy, 460 U.S. 766,

777, 103 S.Ct. 1556, 1563, 75 L.Ed.2d 534

(1983) (citation omitted). A policy

disagreement, at bottom, is the gravamen of

appellants’ complaint. In our view, ‘‘[t]ime

and resources are simply too limited for us

to believe that Congress intended to extend

NEPA as far as [appellant would take] it.’’ Id.

at 776, 103 S.Ct. at 1562. [817]]

Contrary to the PA Com’s assertion,

and regardless of the basis for that

assertion, the discussion of the section

211 alternative in the FEIS satisfies the

requirements of NEPA. The Supreme

Court has stated that ‘‘[t]o make an

impact statement something more than

an exercise in frivolous boilerplate the

concept of alternatives must be bounded

by some notion of feasibility.’’ 818

‘‘Central to evaluating practicable

alternatives is the determination of a

project’s purpose.’’ 819 ‘‘The range of

alternatives that must be considered in

the EIS need not extend beyond those

reasonably related to the purposes of the

project.’’ 820 The purpose of the Rule is

to implement open access in order to

remedy undue discrimination and to do

so on a timely basis and in a uniform

manner; the Commission has

determined that case-by-case

implementation of open access will not

satisfy that purpose.

The PA Com has proffered no reasons

why the examination in the FEIS of the

section 211 alternative is insufficient.

We conclude that the FEIS adequately

considers the alternative of instituting

open access pursuant to section 211.

Rehearing on this issue is denied.

B. Challenges to Modeling Assumptions

Several rehearing requests challenge

the modeling assumptions used in the

FEIS. These challenges are raised in

support of the claim that the

Commission’s analysis understates the

environmental impacts of the Rule. The

most fundamental challenge is the PA

Com’s claim that computer modeling is

insufficient to examine the impacts of

the Rule. The PA Com and Joint

Commenters suggest that the model fails

to use the appropriate base case.

Questions are also raised regarding

specific assumptions used in the model.

In discussing these issues below, we

note that although EPA raised many

similar points with respect to the

Commission’s modeling approach in

comments on the DEIS, EPA ultimately

concluded that ‘‘the FERC has

conducted an adequate analysis under

the National Environmental Policy Act

of the environmental impacts of the

open access rule under a range of

possible scenarios’’ and that ‘‘[t]he

FERC made a reasonable choice of

models (CEUM) and made assumptions

for various factors input into the model

that lie within the range of reasonable

assumptions.’’ EPA also notes that the

Commission performed the specific

additional analyses that were requested

in comments on the draft EIS.

As EPA points out, ‘‘[n]aturally, there

can be differences among reasonable

analysts concerning the assumptions

used in such an analysis.’’ EPA then

reiterates that it believes that

assumptions used by the Commission

‘‘lie within the reasonable range.’’ It

concludes that ‘‘the FEIS provides a

credible basis for understanding the

possible environmental impacts of the

open access rule.’’

1. Appropriate Base Case

Selection of the appropriate base case

was contested in the DEIS on grounds

similar to those presented here. Certain

commenters argued that the

Commission should compare the

impacts of the Rule to a no-action

alternative that assumes that the

Commission abandons all open access

policies, not just the Rule. Some

commenters went even further,

suggesting that the Commission

compare emission levels projected to

result from the Rule against a frozen

efficiency case in which other major
12438 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

821FERC Stats. & Regs. at 31,863; mimeo at 665–

66 (footnote omitted).

822Although cast as use of an inappropriate ‘‘no

action alternative’’, the Joint Commenters’ point

goes to the appropriateness of the base case used

in the analysis.

823This analysis is described as a sensitivity

analysis because it examines how projected air

emissions might change if key assumptions in the

analysis are altered.

factors—factors that would increase

industry efficiency independent of the

Rule—do not occur. Such factors

include adoption of pro-competitive

state polices and actions by utilities to

undertake mutually beneficial voluntary

transactions that do not require the use

of open access tariffs mandated under

the Rule. Commenters who advocated

either a different no-action alternative or

the frozen efficiency case posited that

studies using those assumptions would

show that the Rule will cause

significantly greater NOX emissions than

those shown in the DEIS. We concluded

in Order No. 888 that:

[S]taff has selected the appropriate ‘‘noaction’’ alternative. An alternative that

requires the Commission to reverse all its

other open access policies is simply not a

‘‘no-action’’ alternative. To the contrary, it

would require decisive action running

counter to the direction from the Congress in

the Energy Policy Act and the needs of the

marketplace and electricity consumers.

However, to ensure that the effects of the

rule were analyzed fully, the FEIS did study

a reference case based on the ‘‘frozen

efficiency’’ case * * * Although, as

described below, we believe this case to be

highly unlikely, the results show that, even

under this scenario, the impacts of the rule

are not great and do not vary significantly

from those projected by staff under the other

assumptions. [821]]

Rehearing Requests

Pennsylvania PUC. The PA Com

asserts that the Commission did not

compare emissions levels associated

with the Rule against the appropriate

base case. It claims that the Commission

should have used continued case-bycase evolution of open access and

increased wholesale competition under

FPA sections 211 and 212 as the base

case instead of generic, simultaneous,

nationwide open access as mandated by

Order No. 888. Put differently, the PA

Com claims that the appropriate base

case is the evolution of competition and

open access without the intervention of

Order No. 888. The PA Com concludes

that by using the improper base case the

FEIS ignores evidence of significant

NOX increases resulting from the Rule,

which affects the ability of Pennsylvania

to meet the mandates of the Clean Air

Act.

Joint Commenters. The Joint

Commenters maintain that the FEIS uses

an inappropriate no-action alternative as

a basis for analysis. 822 The gist of its

argument is that the Commission must

acknowledge the policy initiative of

which it contends Order No. 888 is only

one part. It claims that the Commission

ignores the fact that, whether

competition is pursued through Order

No. 888 or on a case-by-case basis,

implementation of open access is a

major programmatic policy choice the

environmental impacts of which must

be addressed. It contends that by using

case-by-case implementation as the noaction alternative, the Commission

effectively defines away most of the

impacts of the Rule.

In short, the Joint Commenters claim

that by defining the no-action

alternative as implementation of the

open access program over a longer

period of time through case-by-case

action, the Commission did not fully

examine the potential impacts of Order

No. 888. It states that if the effects of

Order No. 888 are defined to include

only those that result from the timing

difference between implementation of

open access through case-by-case

decisions and open access pursuant to

a generic rule, it is virtually a foregone

conclusion that most of the potentially

adverse environmental effects of the

Commission’s open access policies will

not be identified.

The Joint Commenters concur that the

frozen efficiency case analyzed in the

FEIS is a proper starting place for an

acceptable NEPA review. It faults the

discussion of the frozen efficiency case,

however, as failing to provide important

information needed to allow parties to

evaluate the analysis. The Joint

Commenters complain that the analysis

does not include the model outputs

which demonstrate the most severe

environmental effects; this, they claim,

makes it impossible to verify the results

or analyze the factors contributing to the

effects shown.

The Joint Commenters state that in

addition to omitting the modeling

outputs for the most environmentally

relevant cases, the FEIS does not

contain air quality modeling of the

scenarios that show the greatest

emissions increases. It claims that the

Urban Airshed Model (UAM–V)

examines only the incremental impacts

of the Competition-Favors-Coal Scenario

as compared with the High-PriceDifferential Base Case, the same analysis

presented in the DEIS. The Joint

Commenters stress that EPA in its

comments on the DEIS noted that the

results shown for this case (an

emissions decrease) is illogical and

should be explained. It states that

without modeling the emissions

changes associated with the

Competition-Favors-Coal Scenario over

the frozen efficiency base case, the FEIS

provides no indication of the

seriousness of the environmental harm

from potential emissions increases

caused by FERC’s initiatives. The Joint

Commenters also claim that the

expanded transmission analysis used in

the FEIS is unduly conservative.

Commission Conclusion

The Commission continues to believe

that the base cases and scenarios used

in the DEIS are most appropriate for

studying the effects of the Rule.

Nonetheless, to ensure that the effects of

the Rule were analyzed fully, the FEIS

also examined a frozen efficiency case

that uses a combination of assumptions

most likely to show significant increases

in emissions.

We did this despite our belief that it

is inaccurate to attribute all efficiency

improvements in the industry to Order

No. 888 or even to federal actions of all

kinds. In fact, as noted in the FEIS, the

frozen efficiency case is far more

extreme in its assumptions than would

be reasonable for a no-furtherCommission-action case because it

presumes that industry and state

regulators also cease all changes toward

a more competitive industry. However,

the frozen efficiency case is useful as a

sensitivity analysis because it reflects an

extreme bound on any separate nofurther-Commission-action case. 823 A

fortiori the impact actually to be

expected from the Rule must be less

than that determined using the frozen

efficiency case.

We believe that the frozen efficiency

analysis is highly implausible because

its represents a world in which: (1) the

Commission reverses current procompetitive transmission policies

(inconsistent with congressional

mandates under EPAct); (2) states cease

to adopt programs to improve industry

efficiency; and (3) electric companies

cease to improve operation or to enter

into mutually beneficial transactions.

The Joint Commenters agree that the

frozen efficiency analysis constitutes a

valid NEPA review. That issue,

therefore, is not in dispute. It objects

that the FEIS does not include the

model outputs for the sensitivity cases

which demonstrate the most severe

environmental effects, and that it is

therefore impossible to verify the results

or analyze the factors contributing to the

effects shown.

The Joint Commenters’ assertion is

incorrect. Appendix K of the FEIS sets

forth tables demonstrating the results of
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12439

824 DEIS at 3–2 through 3–5; FEIS at 3–2 through

3–5.

825The PUC appears to base its rehearing

comments on the DEIS; the points it asserts on

rehearing ignore extensive responses to these

comments in the FEIS. For example, the FEIS

responds to the following specific points that are

now raised by the PUC on rehearing: Impact of the

rule on Pennsylvania coal production (FEIS at J–

22); impact on reliability (FEIS at J–26); impact on

stranded benefits (FEIS at J–30); impact of assumed

increased volume of transmission transactions

(FEIS at J–39); claim that the analysis must consider

impact of Group II boiler rule and Phase III of the

MOU (FEIS at J–49); claim that FEIS makes

conclusory statements (FEIS at J–60); claim that

heat rate assumptions are optimistic (FEIS at J–63);

claim that transmission usage prices are circular

(FEIS at J–65); claim that availabilities are

speculative (FEIS at J–67); claim that reserve

margins are unlikely to fall as far as the FEIS

assumes (FEIS at J–68); concerns about choice of

linear modeling (FEIS at J–73); concerns about

differing emission standards in Pennsylvania and

West Virginia (FEIS at J–92); claim that the Rule is

inconsistent with Title I of the Clean Air Act (FEIS

at J–97).

the model runs for the sensitivity

analysis. These tables provide adequate

documentation to analyze and verify the

conclusions reached in the FEIS. We

note also that the Joint Commenters

have not requested specific model

outputs that it claims are lacking. The

Commission will make available

information used in the study that Joint

Commenters or anyone else identifies as

not being provided.

As to the claim raised by the PA Com,

it appears to be mistaken regarding the

base case actually used in the FEIS.

Contrary to what the PA Com states, the

base cases do include continuing caseby-case actions under section 211 and

the Commission’s open access policy.

2. Challenge to the Use of Computer

Modeling

The Commission’s intent to use

computer modeling in the identification

and evaluation of the impacts of the

Rule has been clear since the

Commission decided to prepare an EIS.

The DEIS and FEIS explain the

computer modeling techniques used in

the analysis in great detail.

For example, the DEIS and FEIS

explain that the Coal and Electric

Utilities Model (CEUM) was selected for

the analysis because it is the best tested,

most widely used national-level model

available. 824 CEUM is a forecasting

model that incorporates virtually all

coal and electric utility market

activities—ranging from mining,

transportation, and blending of coal to

power plant and system dispatching,

transmission, and new capacity

construction. It also examines the

impact of changes in factors such as

plant availabilities, heat rates, planning

reserve margins, and transmission costs.

CEUM has been used extensively by,

among others, EPA and DOE.

CEUM models the contiguous United

States as 45 separate demand regions. It

possesses a supply component which

models key coal supply regions and coal

transportation networks in great detail.

It also incorporates constraints on longterm coal supplies, power plant

emission limitations, national emission

caps (e.g., acid rain requirements of

Title IV of the Clean Air Act

Amendments of 1990), coal

transportation capacity, electric

transmission capacity, and power plant

construction plans.

The DEIS and FEIS explain that to

analyze the Rule, assumptions as to

factors such as electricity demand

growth rates, oil and gas prices, and

planning reserve margins were

developed and incorporated into the

model. Factors such as existing patterns

of transmission capacity and costs were

also analyzed and incorporated into the

model.

Once the necessary information and

assumptions were incorporated into

CEUM, model runs were conducted to

ensure that the projections closely

match actual experience for a selected

year, in this case 1993. These runs used

the information prepared for the base

cases together with other inputs (e.g.,

electricity demand) for the historical

year. The purpose of this calibration

process was to ensure that the model

replicates historical experience. After

the model was calibrated, it was run for

each of the base cases, and then for each

of the Rule scenarios for selected time

periods.

To examine the impact of the Rule on

regional attainment of ozone standards,

additional air quality modeling was

conducted using the UAM–V. UAM-V is

a three-dimensional photochemical grid

model that simulates the physical and

chemical processes in the atmosphere

that affect pollutant concentrations. It

tracks emissions both geographically

according to preset weather patterns and

chemically over time. The UAM–V was

used to create detailed air quality

analyses for cases that might potentially

create additional impacts from NOX

transport and ozone in the Northeast.

Rehearing Requests

The PA Com challenges the ability of

computer modeling to simulate the

effects of the Rule. It states that

computer modeling is an attempt to

reflect an approximation of reality that

uses systems of linear equations, and

that the airborne transport of pollutants

in the atmosphere and the North

American electric transmission grid are

extremely large, complex nonlinear

systems.825

The PA Com’s challenge to the use of

computer modeling also turns on the

observation that models produce results

that are dependent on the inputs and

assumptions used in the models. The

specific challenges to the inputs and

assumptions used in the model are

discussed separately below.

Commission Conclusion

We note first that computer models

are the only available means of analysis

that incorporate the range of factors that

influence engineering and economic

choices in the electric power industry,

and the atmospheric chemistry and

weather patterns that influence

downstream air quality. We are mindful

of the limitations of models, but the

alternative of using no model at all—

and hence making no analytic attempt

to capture the complex economic and

environmental factors—did not appear

reasonable.

The PA Com does not explain how

the Commission should otherwise

simulate the effects of the Rule.

Computer modeling may not be a

perfect tool, but it is the best existing

mode of analysis for this type of effort.

The PA Com cannot merely assert that

such modeling is inadequate. As the

court noted in a similar context in City

of Los Angeles v. National Highway

Traffic Safety Administration, 912 F.2d

478, 488 (D.C. Cir. 1990), overruled in

part on other grounds, Florida Audubon

Society v. Bentsen, 94 F.3d 658 (D.C.

Cir. 1996):

Petitioners call for more ‘‘analysis,’’ but do

not specify what they see as lacking or how

‘‘analysis’’ could supply the want. At some

point—here after a seemingly full

treatment—the agency must make a

judgment. We discern no more from

petitioners’ argument than that they disagree

with that judgment. Even were we to share

their view of the matter, that would not be

a sufficient basis for overturning the agency’s

decision.

Quoting Portland Cement Ass’n v.

Ruckelshaus, 486 F.2d 375, 394 (D.C.

Cir. 1973), cert. denied sub nom.

Portland Cement Ass’n v.

Administrator, EPA, 417 U.S. 921, 94

S.Ct. 2628, 41 L.Ed.2d 226 (1974), the

court in Northside Sanitary Landfill,

Inc. v. Thomas, 849 F.2d 1516, 1519

(D.C. Cir. 1988), cert. denied, 489 U.S.

1078 (1989), stated in like manner that:

[C]omments must be significant enough to

step over a threshold requirement of

materiality before any lack of agency

response or consideration becomes of

concern. The comment cannot merely state

that a particular mistake was made * * *; it

must show why the mistake was of possible
12440 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

826FEIS at 3–8 through 3–11.

827As explained in the FEIS at 3–13 through 3–

15 and as discussed below, the movement of power

from low cost sources is limited not only by the

physical constraints of the transmission system, but

also by institutional impediments such as lack of

access to needed transmission. As a result, in a

model like that used in the EIS, where flows are

based on minimizing costs subject to physical

constraints, the model will typically overestimate

the amount of power flowing from low-cost sources

of generation. The Commission chose to address

this by developing a ‘‘usage price’’ to raise the

variable cost to simulate the effect of observed

barriers to power flows between regions. The usage

price is a proxy for transmission barriers, not an

attempt to estimate or model an actual transmission

price. The usage price was calibrated to produce

actual historical flows of electricity, not costs of

transmission. As such it has almost no relationship

with actual transmission prices.

828 Id.

significance in the results [the agency

reaches]. (Emphasis in original).

The FEIS explains the Commission’s

conclusion that the environmental

analysis of Order No. 888 is best

conducted using the CEUM and UAM–

V computer models. The PA Com

cannot merely state that the use of such

models is inappropriate. It must explain

why this is so and what alternative

method of analysis should be used. This

it has not done. The request for

rehearing is denied.

3. Transmission Assumptions

The FEIS recognizes the

interdependence of interregional

electric transmission transactions;

accordingly, non-simultaneous

interregional transfer capabilities

estimated by the North American

Electricity Reliability Council (NERC)

were reduced for use in the model (see

FEIS section 3.4.2). The analysis also

considers the impact of the Rule on

interregional transfers (see FEIS Tables

5–13 and 5–14), and the impact of

changes in transmission capacity

through sensitivity analysis.826

Rehearing Requests

The PA Com asserts that transmission

usage in the FEIS is based on

assumptions which are indeterminate to

some degree. It states that historical

interregional power transfers are used to

estimate future transmission capabilities

and capacity, and that while historical

interregional electric transmission

transactions have been large and

complex, under the Rule the level of

transactions will increase enormously.

The PA Com claims that almost every

time a new major interregional electric

transmission transaction has occurred,

there have been unpredictable flows of

electricity in other regions that might be

a thousand miles away. It concludes

that relatively small changes in

transmission flows can and have

produced large harmonic transients and

instabilities on the power grid.

The PA Com also contends that the

relationship between the transmission

usage price and the price of

transmission service is unclear. It states

that the development of the usage price

seems circular, at least in part. It notes

that model inputs were changed until

the usage price coincided with an

estimate of historical costs. The PA Com

requests clarification of the

development of the usage price

assumption.

Commission Conclusion

The PA Com does not appear to

understand the way the transmission

usage price functioned in the

analysis.827 As explained in the FEIS,

the CEUM model is annual and regional:

it models a single year at a time using

regions approximately the size of a state

or large regions within a state.828

Transmission in the model is

represented as movement of power from

one region to another. The model

attempts to satisfy the demand for

electricity at lowest cost—if there were

no limitations on the movement of

power from one region to another, the

model would always generate power at

the cheapest source and move that

power to meet the demand. This result

would clearly be unrealistic, since

sources of power are limited in their

ability to reach demand by limitations

in the intervening transmission

network. The transmission network in

CEUM is represented primarily by the

limitations that the transmission grid

places on the ability of power to move

freely to meet demand.

To use CEUM to provide a reasonable

representation of transmission requires

balancing the different ways in which

the transmission system imposes limits

on the movement of power. Flows on

links between regions are limited by

three general parameters in the model:

losses, variable costs, and constraints on

the quantity of capacity or energy that

can be transferred. Losses are generally

small, and are typically kept fixed from

one model run to the next. Simulating

transmission limits is largely a matter of

balancing variable costs and quantity

limits. True variable costs are usually

assumed to be small, reflecting the low

variable cost of operating the

transmission system. Basic quantity

limits are usually developed from NERC

sources or other studies of the limits

imposed by the physical operation of

the transmission system.

However, such limits do not always

provide an adequate picture of current

patterns of generation and transmission

in the electric utility system. Movement

of power from low cost sources is

limited not only by the physical

constraints of the transmission system,

but also by institutional impediments

such as lack of access to needed

transmission. As a result, in a model

like CEUM, where flows are based on

minimizing costs subject to physical

constraints, the amount of power

flowing from lost-cost sources of

generation is typically overestimated.

The FEIS explains that there are two

primary ways to address this difficulty

when calibrating the model to represent

historical power flows. One is to impose

further limits on the quantity of power

transferred within the model. The other

is to raise the variable cost to simulate

the effect of observed barriers to power

flows between regions. The second

approach was used by developing a

‘‘usage price’’ to raise the variable cost

barriers in CEUM and supplement basic

quantity limits derived from NERC

estimates. This approach was taken

because of its nexus to the primary

effect of the Rule on transmission

activities. The primary effect of the Rule

on transmission will be to increase the

ability of transmission users to gain

access to transmission service and to

permit users to develop flexible ways

for buyers and sellers to use the

transmission system efficiently. The

primary effect is thus to remove

institutional barriers to the use of the

transmission system—in effect to reduce

the transaction costs, or usage price,

faced by those seeking access to

transmission. Thus, the model was

calibrated by selecting an initial set of

usage prices and adjusting those prices

until the model provided an accurate

representation of historical generation

and transmission patterns.

Usage prices (in mills per kWh) were

developed by running CEUM for a

historical period (1993). Starting from

initial estimates of usage prices between

CEUM regions, the model was run using

historical inputs for 1993; the outputs

from these runs were compared with the

historical pattern of generation and

transmission for that year. Usage prices

were then adjusted until the pattern

projected by the model was consistent

with the observed historical pattern.

The final adjusted prices were then used

as the current usage prices.

Two rules were used to set the initial

usage price estimates:

(1) For closely coordinated (i.e., tight)

pools, no separate usage price was assumed.

This is consistent with the principle

embodied in many pools that transmission
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12441

829 Id. at 3–18. 830 Id. at J–63 and J–67.

assets are to be treated as one system and

used to minimize variable costs. Any

allocation of the cost of service associated

with transmission assets is typically treated

as a fixed cost.

(2) Separate transmission costs are

commonly applied in loosely configured

pools. In many cases, these separate costs are

derived on a MW-mile basis. Because the

number of systems that have to be traversed

within a loosely configured pool is generally

small, the transmission usage price for areas

with loosely configured pools were set to a

small initial value (1 to 2 mills/kWh).

Transmission across NERC regions may

require traversing many utility systems, and

for modeling purposes a charge of about 3

mills/kWh was assumed.

Applying this method required

several runs of CEUM. Usage price

changes were typically downward in

areas where the initial prices were set at

3 mills per kWh, and prices after

adjustment remained within the range

of the initial usage prices. As a result,

estimates of the current usage price

varied from region to region after

calibration, but generally fell within the

range of 1 to 3 mills per kWh.

Thus, the concerns expressed by the

PA Com were either considered in the

FEIS, or are based on a

misunderstanding of the method used.

4. Plant Availabilities and Heat Rates

The FEIS explains that power plant

availability is the percentage of time

that a generating unit is available to

provide electricity to the grid, and that

availability estimates for coal plants

have an important effect on projected

base case emissions because those

estimates determine the amount of

future generation expected from existing

power plants.829

The base cases assume that average

fossil-fuel plant availability rises to 85

percent by 2005 and then remains

constant through 2010. This assumption

reflects continuing efforts by utilities to

improve plant availability. Between

1984 and 1993, coal plant availability

increased five percent to nearly 81

percent. This trend is projected to

continue through 2005 as electric

generators respond to competitive

pressures and opportunities extant

without the Rule.

The FEIS explains that in the

Competition-Favors-Coal Scenario,

plant availabilities are assumed to reach

90 percent (as opposed to 85 percent in

the base cases and other Rule scenarios)

because competition is projected to lead

to greater operational efficiency in

generation markets. It notes that some

older coal plants are not likely to reach

this level without substantial capital

investment. However, since 90 percent

availability is achievable for many

plants, this figure was selected as an

upper bound to illustrate how much

existing plants may be able to run if

generation owners focus on meeting

competition through greater use of coal

plants.

The FEIS also explains that the base

cases assume some deterioration in heat

rates between life extension programs.

In the Competition-Favors-Coal

Scenario, existing generating plants are

assumed to be better maintained so that

there is no deterioration of heat rates

between life extension programs. Except

in the Competition-Favors-Gas Scenario,

it is assumed that new combined cycle

natural gas plants sustain existing heat

rates (rather than improving as the next

generation of gas technology comes on

line). These assumptions reflect the fact

that industry has put more effort into

making better use of existing

(disproportionately coal) plants rather

than into improving the performance of

new (almost entirely gas) plants.

Rehearing Requests

The PA Com challenges the plant

availability assumptions used in the

FEIS. It notes that the analysis assumes

that generation plant availability will

rise to 85 percent and that the

Competition-Favors-Coal Scenario

assumes that generation plant

availability will rise to 90 percent by the

year 2005. The PA Com states that

although historical trends indicate that

plant availability might increase, in

reality as availability goes up it becomes

increasingly difficult to obtain further

improvements.

The PA Com contends that increasing

availability to 85 percent would be

surprising; an increase to 90 percent

would be astonishing. It states that such

increases would require a number of

simultaneous technical advances, the

likelihood of which are speculative. The

PA Com argues that utilities in

competition with each other may be less

willing to fund and participate in

cooperative research that leads to

technical advances. The PA Com notes

that maintenance staffs are being

reduced as a result of cost reduction

programs and that plant availability

might decline as maintenance is

deferred.

The PA Com also contends that the

assumption in the Competition-FavorsCoal Scenario that heat rates do not

degrade (go up) over time may be

optimistic. It concedes that

technological advances have produced

dramatic improvements in heat rates,

but states that it is unclear if this

improvement is sufficient to overcome

losses caused by backfitting emission

control equipment. The PA Com notes

that coal-fired generating stations in

Pennsylvania have been required to

install emission control equipment and

that efficiency has been reduced in

some cases, degrading the heat rate. It

states that some coal stations have

installed sulfur dioxide (SO2) scrubbers

which can reduce efficiency by five

percent, and that other stations may be

required to install selective catalytic

reduction systems for NOx or SO2

scrubbers.

The PA Com contends that an

additional limit on heat rate

improvements is the age of generating

stations and the fact that heat rates

decline as stations age. It posits that this

decline may be greater than the

improvements that can be gained

through technological advances.

Commission Conclusion

The PA Com’s argument fails to

consider the discussion of this issue in

the FEIS.830 Briefly, higher availabilities

for coal plants were assumed in order to

provide a scenario that was extremely

favorable to the use of coal in existing

facilities and hence a scenario that was

most likely to have a larger

environmental impact. The fact that

some coal plants are able to maintain 90

percent availability is sufficient grounds

for considering such a case, especially

where the purpose of the assumption is

to establish a reasonable range of

potential environmental outcomes from

the Rule.

With regard to the heat rate

assumptions, the PA Com does not

appear to understand how the

assumptions functioned in the analysis.

First, the factors it mentions (e.g.,

efficiency reductions resulting from the

addition of scrubber technology) are

already considered in the CEUM model.

Second, the CEUM does assume that

heat rates degrade over time in the base

cases. The assumption that they do not

degrade in the Competition-Favors-Coal

Scenario was made to simulate the

relative improvement that might be

achieved through potential effects of the

Rule when competition is favorable to

coal. As with certain other modeling

assumptions challenged by the PA Com

on rehearing, the heat rate assumptions

used by the Commission are more

conservative than those urged by the PA

Com and thus demonstrate greater

impacts from the Rule than would be

the case using the assumptions urged by

the PA Com.
12442 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

831 Id. at 3–16 and 3–17. Table 3–4 is found on

page 3–17. 832 Id. at 3–25. 833 Id. at 3–5 through 3–8.

5. Reserve Margins

The FEIS discusses the assumptions

regarding planning reserve margins and

their use in the model.831 It states that

planning reserve margins influence the

amount of new capacity built and the

mix of gas versus coal fired generation

projected in CEUM. In particular, lower

reserve margins tend to result in the

construction of less capacity (typically,

fewer gas-fired turbines and combined

cycle units) and a somewhat greater

utilization of existing coal units.

Generally, individual utilities set their

reserve margins to comply with a

technical standard established by the

NERC sub-region. Typically, the NERC

sub-region might determine that a one

day in 10 years loss of load probability

(LOLP) is the appropriate standard.

Individual utilities within the subregion would determine their reserve

planning margin to be consistent with

this standard after accounting for tie

capabilities. NERC sub-regional studies

are performed periodically to determine

whether the reliability standard is being

satisfied for the planning horizon given

planned capacity additions. The tie

capability between the sub-region and

other regions is accounted for in

reliability studies at the NERC subregional level.

The FEIS notes that in recent years,

reserve margins typically have been

revised downwards, although the

planning standard itself (most

commonly the one day in 10 years

LOLP) has not been changed. Three

reasons support the downward revision

in reserve margins: (1) An expected

improvement in unit availability; (2)

anticipated shifts in utility load shape

towards a lower load factor; and (3) an

increase in the number of generating

units.

FEIS Table 3–4 summarizes the

reserve criteria and associated planning

reserve margins that have been derived

from the most recent annual planning

documents prepared by the reliability

councils. It states that a review of

current planning documents shows that

utilities expect planning reserve

margins to decline over time. One factor

identified as contributing to this decline

is the expectation that availability will

improve appreciably as utilities are

subject to performance-based regulation

and experience greater competition.

Additionally, some utilities have

revised their planning reserve margins

to account for ties in other regions. In

some cases, utilities have updated their

planning reserve margin calculation to

reflect current estimates of customer

willingness to pay for increase

reliability.

Based upon a review of utility

expectations, the FEIS concludes that an

appropriate base case assumption is for

planning reserve margins to decline by

2005 to the lower end of the applicable

ranges set forth in FEIS Table 3–4.

Rehearing Requests

The PA Com challenges the reserve

margin assumptions used in the model.

It asserts that the assumption that

reserve margins will fall to fifteen

percent by 2000 and (in one scenario) to

thirteen percent by 2005 is based in part

upon the assumption of increased

generation plant availability across the

board. The PA Com notes that this

increase in availability might not occur.

It states that as wholesale transactions

increase under open access, some, but

not most, utilities will be able to reduce

reserve margins and still maintain

reliability. The PA Com asserts that

many utilities cannot reduce reserve

margins because available transmission

capacity between regions is already

being utilized to the maximum extent

possible. It concludes that reserve

margins for certain individual utilities

could decline, but this alone would not

reduce required reserve margins for all

utilities to the levels that are assumed

in the model.

Commission Conclusion

The reserve margins used in the base

cases were set using current utility

plans and trends in the industry.

Reserve margins for the competition

scenarios were set slightly lower,

reflecting the potential for decline in a

more open competitive environment.

The PA Com acknowledges the potential

decline, but claims that not all utilities

will be able to reduce reserve margins

to the levels assumed. However, the

FEIS addresses such differences by

using different regional assumptions

about reserve margins and different

reserve margins in each region. The PA

Com’s concern is therefore without

basis.

6. Northeast MOU

The FEIS assumes that power plants

in the Northeast Ozone Transport

Region (OTR) will comply with Phase II

of the Northeast Memorandum of

Understanding (MOU). The MOU

establishes NOX tonnage limits during

the five-month ozone season (MaySeptember) for electric generating and

large industrial services and allows for

emissions trading.832 The FEIS states

that compliance with Phase III of the

MOU was not assumed since its

implementation is optional, depending

on final attainment status with regard to

Clean Air Act requirements.

Rehearing Requests

The PA Com states that the base cases

and scenarios assume that no NOX

controls will be required for Title IV

group II boilers, that phase II of the

MOU will be implemented, and that no

additional requirements will be

imposed. The PA Com contends that

phase III of the MOU might be

implemented, and that if this occurs and

upwind generation is not required to

control ozone precursors, cleaner

generation in the Northeast may be

displaced by increased generation from

outside the OTR.

Commission Conclusion

In essence, the PA Com appears to be

raising an emissions disparity argument

rather than posing a challenge to the

modeling assumptions used in the FEIS.

The emissions disparity argument is

addressed below.

7. Natural Gas Prices

Average wellhead natural gas prices

for the High-Price-Differential Base Case

were based on a recent forecast of

natural gas acquisition prices by

Wharton Econometric Forecasting

Associates (WEFA).833 This forecast

projected at that time that natural gas

prices would increase in real terms

(1994 dollars) to $1.83 per MMBtu by

2000, and rise to $2.42 per MMBtu by

2010. The forecast was selected as

representative of a number of natural

gas price forecasts that were made

during that time.

CEUM requires delivered, not

wellhead or acquisition, prices as an

input. Delivered natural gas prices for

each Census region were derived from

the weighted average transportation

mark-ups reported by the Energy

Information Administration (EIA) in

Natural Gas Monthly for each Census

region. The Natural Gas Monthly

provides a consistent historical series of

wellhead and delivered prices for

calculating historical transportation

margins. These margins were assumed

to remain constant throughout the

forecast period.

In the Constant-Price-Differential Base

Case, delivered gas prices were assumed

to equal current delivered spot prices in

each region. To maintain a constant gas

price relative to coal, these prices were

assumed to decline from current levels
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12443

834 Id. at 3–7 through 3–8.

835The Joint Commenters claims as to the

Constant-Price-Differential Base Case are probably

meant as a reference to the Competition-Favors-Gas

Scenario.

836FEIS Chapter 6.

837 Id. at Table 6–19 (page 6–23) and Table 5–18

(page 5–16), respectively.

838FERC Stats. & Regs. at 31,872 n.974; mimeo at

691–92 n.974.

at the same rate as coal prices decline

in CEUM.834

Rehearing Requests

The Joint Commenters assert that the

fuel-price assumptions used in the

model unduly favor the use of natural

gas as a fuel and appear to understate

adverse effects.

In particular, the Joint Commenters

claim that the two alternative fuel-price

cases use the same coal price

assumptions. It states that the

Competition-Favors-Coal Scenario is

supposed to demonstrate the effects of

economic assumptions that favor coal,

but that this case actually uses price

assumptions that reflect the lowest

natural gas price of the projections cited

in the FEIS. It states that the FEIS

should have used projections less

favorable to natural gas: for example,

$2.51 per MMBtu in 2000 (Gas Research

Institute) and $3.37 per MMBtu in 2010

(Energy Information Administration).

Put differently, a more appropriate

Competition-Favors-Coal Scenario

would have used the projected highest

reasonable natural gas prices relied on

in the FEIS.

The Joint Commenters then claim that

the Constant-Price-Differential Base

Case is based on gas price assumptions

that are far below the projected prices

cited in the FEIS.835 According to the

Joint Commenters, this case assumes

natural gas prices of $1.67 per MMBtu

in 2000 and $1.57 per MMBtu in 2010.

It asserts that these estimates are

approximately 10 and 54 percent lower

in years 2005 and 2010, respectively,

than the lowest forecasts cited. A more

appropriate Competition-Favors-Gas

Scenario would have used the WEFA

forecasts that contain the lowest

reasonable projected gas prices.

Commission Conclusion

The claim that the assumptions

unduly favor natural gas prices is

incorrect. First, the assumption that

lower gas prices will reflect favorably

the environmental effects of the Rule is

not valid. The impact of the Rule when

gas prices are constant relative to coal

is very close to the impact when gas

prices are high relative to coal.836 For

example, the impact on total NOX

emissions in 2005 is higher when gas

prices are constant relative to coal than

when gas prices are high relative to coal

(88,000 tons for the Constant-PriceDifferential Base Case versus 55,000

tons for the High-Price-Differential Base

Case).837

Second, the two price series were

selected to give a range of variation in

emissions that reflect differences in the

price of gas relative to coal, rather than

to project a ‘‘correct’’ natural gas price.

As discussed in the FEIS, the ConstantPrice-Differential Base Case reflects a

continuation of the historical

relationship between gas and coal prices

over the past 10 years. Appendix G

shows how forecasts over this period

have consistently overestimated the

price of gas relative to coal. It is

therefore reasonable to consider the

Constant-Price-Differential Base Case as

one side of a reasonable range.

The prices selected for the other side

of the reasonable range of gas prices

relative to coal (the High-PriceDifferential Base Case) were based on

current forecasts at the time of the

analysis. There were two primary

reasons for selecting a lower gas price

from the range of existing forecasts.

First, the CEUM coal price forecast is

determined within the model and could

not be changed as an input. This coal

price forecast was lower than the coal

prices assumed in other forecasts. By

picking a gas price forecast at the lower

end of the range of current forecasts,

and combining this forecast with the

lower coal prices forecasts in CEUM, the

analysis assumed a typical price of

natural gas relative to coal.

Second, at the time the analysis was

conducted, all major forecasting

organizations stated that they expected

their gas price forecasts to be lower.

However, these organizations did not

complete their forecasts for several

months. Since the available forecasts

were up to a year old, there was reason

to believe the forecasts overstated the

current thinking among forecasters

regarding future natural gas prices. This

reason was confirmed by the forecasts

that appeared around the time the

analysis was completed. For example,

the forecast for the wellhead price of

natural gas in the year 2010 from the

EIA published in January 1996 was

$2.10 per million Btu, 15 percent below

the forecast of $2.42 assumed for the

High-Price-Differential Base Case in the

FEIS.

8. Expanded Transmission Analysis

Several commenters on the DEIS

expressed concern that increases in

transmission capacity resulting from

open access might increase generation

levels and thus air pollution. In

response, the FEIS examined scenarios

that increased transmission capacity

substantially beyond current levels—

including increases that the

Commission believed would far exceed

any transmission capacity increases that

might occur as a result of the Rule. This

analysis found that postulated increases

in transmission do not affect emissions

attributable to the Rule. The

Commission also found that issues

regarding enhancement of existing lines

are more complex, and that this is due

in part to the fact that state-level siting

issues, the principal barrier to major

increases in the transmission grid, are

unaffected by the Rule. While

competition will lead to improved

efficiencies in generation, transmission

will remain a regulated monopoly

function. The Rule will reduce barriers

to access, but will not open the

transmission system to direct

competition. Thus, the Commission

concluded that the competitive effects

of the Rule on transmission will be

relatively small.838

Rehearing Requests

The Joint Commenters claim that the

expanded transmission analysis is

unduly conservative. It states that the

Commission increased peak

transmission usage from 75 percent of

first contingency total transfer capability

(FCTTC) to 105 percent of FCTTC, and

that this expanded transmission

analysis represent minimal actual

expansions, the most extreme of which

barely increases FCTTC above current

levels by the year 2010. The Joint

Commenters claim that the Commission

should have examined additional

expansion potential in those analyses

that more accurately demonstrate the

effects of transmission expansion.

Commission Conclusion

The Joint Commenters’ claim that the

expanded transmission analysis is

inadequate is based on the premise that

the FEIS used the wrong assumptions in

developing transmission capacity. Joint

Commenters contend that 100 percent of

the FCTTC should have been used in

CEUM. We believe that the use of 75

percent of this capacity to reflect annual

capability is the appropriate level for

modeling purposes. This reduction

factor is necessary because the

capability must be simultaneous

systemwide capability and it must be

sustainable. The FCTTC is a nonsimultaneous ‘‘snapshot’’ transmission

capability. The total simultaneous

transfer capability is not accurately

represented by adding together the
12444 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

839Edison Electric Institute, Assessment of

Greenhouse Gas Emissions Policies on the Electric

Utility Industry: Costs, Impacts and Opportunities,

prepared by ICF Resources, January 1992.

840See also FEIS Sections 3.4.2.1 and J.7.1.

841The EIS and Order No. 888 examine the

specific mitigation proposals advanced by the

Center for Clean Air Policy, the EPA, the Joint

Commenters, the Project for Sustainable FERC

Energy Policy, and the Department of Energy. FEIS

at 7–28 through 7–43; FERC Stats. & Regs. at

31,877–82; mimeo at 705–17. The Commission

concluded that the mitigation measures urged by

the commenters are unwarranted, and that

mitigation of the Rule is not required. Of the

commenters advancing specific mitigation

proposals in comments on the draft EIS, only the

Joint Commenters seek rehearing of Order No. 888

on environmental issues. The Joint Commenters do

not take issue on rehearing with the Commission’s

rejection of its mitigation proposal, but rather

mounts a broad attack in which it asserts that the

Commission has failed to properly consider and

disclose the potential environmental effects of the

Rule, and that the Commission’s decision that it

lacks authority to implement mitigation is contrary

to law. 842FEIS at 7–47 and 7–48.

maximum transfer capability of each

line in the system. The transmission

system is a system. Loading on one line

affects loading capability on all other

lines in the system. This is especially

true if the calculation is for capability

over an extended period of time, as is

the case with the FEIS, which uses

transfer capability over one year.

‘‘Derating’’ as it has been called, is a

reasonable way to represent the fact that

a transmission system is capable of

carrying less than the sum of the

capabilities of the individual lines.

Further, when modeling, if the model is

calibrated so that the system is carrying

actual historical flows—no matter what

factor is used—the system will be

carrying at or near its maximum

capacity at constrained points which are

the only points on the system where

increased capacity would produce

increased flows. As a result, increasing

the transfer capability factor by up to 40

percent, as is done in the sensitivity

analyses in Chapter 6 of the FEIS,

represents a large change in the

capability and use of the transmission

system. Moreover, we note that this

methodology has been used in previous

CEUM analysis, where it was subject to

review by electric utility experts.839 For

these reasons, the Joint Commenters’

criticisms are invalid.840

The Joint Commenters challenge the

assumptions used in the Commission’s

expanded transmission analysis as

‘‘unduly conservative’’ and

‘‘represent[ing] minimal actual

expansions.’’ Joint Commenters fail to

explain in what respect they deem the

expanded transmission analysis to be

inadequate. They fail even to respond to

the matters discussed by the

Commission with regard to this issue in

Order No. 888.

As we noted above in the discussion

of the PA Com’s argument that the

Commission failed adequately to

consider the alternative of instituting

open access pursuant to section 211 of

the FPA, it is insufficient for a party to

complain that an analysis is inadequate

without providing specifics.

C. Mitigation

The FEIS and Order No. 888

extensively assess the need for

mitigation and discuss potential

mitigation measures, including

proposals advanced by commenters.841

This discussion is perhaps best

summarized by the conclusion to

Chapter 7 of the FEIS, which states that:

This FEIS shows that the proposed rule is

expected to slightly increase or slightly

decrease total future NOX emissions,

depending on whether competitive

conditions in the electric industry favor

natural gas or coal. The insistence of

commenters that the Commission adopt and

implement mitigation measures is based on

significantly overstated assumptions

regarding the contribution of the proposed

rule to the existing environmental problems.

The analysis presented in Chapter 6

establishes that overstated assumptions about

the impact of the proposed rule are simply

wrong.

Nonetheless, in light of the importance of

this issue, we have examined potential

mitigation measures in detail, including

those proposed by commenters, to ensure

that environmental consequences of the rule

have been fully and fairly evaluated. We do

not believe mitigation should be undertaken

in this rule because:

Any mitigation measures the Commission

might undertake are not justified by the small

impacts of the rule, which impacts are as

likely to be beneficial as they are to be

harmful;

The impacts of the proposed rule are

dwarfed by the far larger ozone and NOX

emission issues that either have nothing to

do with the electric industry or will be

unchanged by the rule or the larger open

access program. We believe that it would be

ineffective to address the NOX and ozone

issues in a piecemeal way;

The NOX issue is part of a long-standing,

difficult set of inter-regional environmental

issues. Representatives of many interests in

both the Northeast and the Midwest have

invested substantial efforts towards finding

acceptable solutions through the OTAG

process. Any mitigation the Commission

might undertake could usurp EPA’s mandate

under the Clean Air Act and undermine

progress towards comprehensive solutions

sought by OTAG. This is not justified by

impacts that are small and just as likely to

be positive.

We do not agree that the frozen efficiency

reference case should be substituted for the

EIS base cases or that competitive forces will

favor coal over the next 15 years. But even

accepting those assumptions, emissions

attributable to the rule are relatively small

until well after the turn of the century. So,

even accepting such assumptions, the staff

believes it would be unreasonable for the

Commission to adopt mitigation

requirements as part of the final rule; to do

so would be tantamount to assuming that

EPA and OTAG will not implement

reasonable control measures in the next ten

to 15 years;

The Federal Power Act and NEPA, either

singly or conjointly, do not authorize the

Commission to adopt and implement the

proposed mitigation measures. The

Commission does not possess (and has no

mandate to possess) expertise on the

extremely difficult issues involved in

atmospheric chemistry and transport. It is

fundamentally a economic regulatory agency.

As a result, any mitigation measures the

Commission undertook would be based on

less-than-ideal information and analysis. It is

unreasonable for the Commission to attempt

such mitigation given the impacts found in

this FEIS. This is especially true in light of

the substantial additional research that EPA

and OTAG are undertaking on the basic

nature of the problem;

Some suggested mitigation measures that

might work at the transaction level would

undermine the purpose of the rule. There is

no justification for endangering the

substantial benefits projected from the rule to

mitigate a problem that might not exist and

that is, in any case, likely to be small.[842]

The FEIS goes on to note that the

long-term existence of a significant

ozone nonattainment problem in parts

of the country has led to the

development of mechanisms to address

this issue. It states that any incremental

increases in NOX emissions that may

result from the Rule can be addressed

within this existing framework. In

particular:

The Clean Air Act authorizes EPA to

establish transport regions that are charged

with assessing the degree of interstate

transport of pollutants, assessing mitigation

strategies, and recommending revisions to

State Implementation Plans to correct the

problem. The Clean Air Act specifically

establishes an ozone transport region for the

Northeast. The jurisdictions that comprise

the OTR have developed a coordinated

approach to this problem that includes

adopting a regional cap on NOX emissions.

Although the OTR process is achieving its

purpose, the problem is larger than the OTR

can address. As a consequence, the Ozone

Transport Assessment Group has been

formed which encompasses the OTR and

upwind states that contribute to

nonattainment. OTAG is performing

extensive photochemical grid modeling of

the eastern U.S. to determine ozone transport

patterns and to evaluate the efficiency of

various control strategies. OTAG is

considering imposing a cap and trade system

for NOX emissions in a 37-state area

comprised of the Northeast OTR and upwind

states. If the cap and trading system becomes
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12445

843 Id. at 7–49.

844The New York Attorney General wrote to the

Commission on May 13, 1996 expressing concern

about the potential environmental effects of the

Rule. Its filing does not appear to constitute a

request for rehearing, but it is treated here as such.

effective it should fully mitigate NOX

emission increases, if any, attributable to

open access transmission within the 37-state

area. A cap and trade program is also likely

to mitigate CO2 and mercury emissions.

We believe that the cap and trading system

under consideration in the OTAG process is

the preferred approach to the overall NOX

emissions problem. The OTAG process

brings to the table the parties that must

participate in making the difficult decisions

to fully resolve this problem. The OTAG

process possesses the technical resources and

expertise to address the difficult scientific

and technical issues that must be resolved to

remedy this problem. More limited

approaches cannot render a satisfactory

solution. We respect the expertise and the

goals of the OTAG process and do not believe

we can or should substitute for them in

addressing this long-term national

problem.[843]

Rehearing Requests

Pennsylvania PUC. The PA Com

claims that the Commission has

inappropriately declined to assume any

responsibility for mitigating

environmental impacts associated with

the Rule. It states that the Commission

has authority to take mitigation

measures related to its regulatory

actions and that the Commission can

reasonably add environmental impacts

to the list of factors to be weighed under

the FPA’s public interest standard. In

this regard, it contends that the FPA

grants FERC authority to place

conditions on the regulation of rates and

conditions of wholesale power sales and

the interstate transmission of electric

power as well as to order wholesale

wheeling under certain circumstances.

The PA Com states that the

Commission should act to minimize the

likelihood of significant additional NOX

emissions by developing a mitigation

plan to be implemented in conjunction

with the Rule, and that FERC should use

the results of the OTAG process to

provide information to develop this

strategy. The PA Com concludes that

FERC should not require open access

generically.

Vermont Department of Public

Service. The Vermont Department of

Public Service (VT DPS) contends that

the Commission erred in failing to

establish a monitoring program and a

periodic reopener provision to address

environmental considerations. VT DPS

submits that the Commission has given

inadequate consideration to the

possibility that the Rule may

unnecessarily exacerbate environmental

impacts. It notes EPA’s claim in its

referral letter to the Council on

Environmental Quality (CEQ) that any

future NOX increases resulting from

open access would exacerbate the

difficulty of accomplishing reductions

in NOX emissions.

VT DPS claims that the environmental

review process has not facilitated the

ability of affected parties to review all

modeling assumptions. It also claims

that other environmental reviews

suggests more serious NOX emission

consequences of the Rule than

acknowledged by the Commission.

VT DPS states that given the

possibility that the FEIS conclusions

may prove wrong, the Commission

should take steps to permit timely

reevaluation of its program. VT DPS

recommends that the Commission

establish an ongoing monitoring

program to determine if the Rule poses

an unacceptable risk to air quality. It

states that a monitoring program would

allow the Commission to take timely

action to mitigate any unintended

consequences of the Rule. The

Commission should also provide for

periodic reevaluation of the Rule’s open

access provisions and should commit to

a comprehensive reevaluation of the

Rule’s environmental impacts every five

years over the next 20 years.

New York Attorney General. The New

York Attorney General (Attorney

General) states that the federal

government should ensure that New

York and other Northeast states do not

bear the burden of any increased air

pollution resulting from deregulation.844

The Attorney General asserts that

utilities in upwind states have a

competitive advantage relative to

Northeast utilities because they are

subject to less extensive environmental

controls. The Attorney General contends

that deregulation may result in these

plants increasing generation, thus

increasing emissions that will

contribute to the inability of New York

and the Northeast to meet the federal

ozone standard. The Attorney General

claims that, regardless of the effects of

the Rule, studies show that a 50 percent

reduction in NOX emissions from all

sources east of the Mississippi will be

necessary for New York and other

Northeast states to achieve the ozone

standard.

The Attorney General states that

Congress has placed limits on EPA’s

authority to protect New York from

upwind emissions, and that it is

therefore essential that FERC exercise

any authority it may have to mitigate the

environmental effects of the Rule.

The Attorney General claims that

EPA’s proposal in its February 20, 1996

comments to place a cap on NOX

emissions would mitigate the effects of

the Rule; it suggests basing this system

on the MOU pursuant to authority

residing in EPA and/or FERC. Under

this proposal, a utility would be

permitted to take advantage of

deregulation if it simultaneously takes

steps to prevent emission increases.

Joint Commenters—Overview. The

Joint Commenters state that FERC has

failed to consider and disclose the

potential environmental effects of the

Rule, and that FERC’s decision that it

lacks authority to implement mitigation

is contrary to law.

The Joint Commenters’ premise is

that, despite deficiencies in the

Commission’s analysis which

understate the effects of the Rule, the

FEIS nonetheless presents data

confirming that open access will have

significant adverse environmental

impacts. Joint Commenters posit that

increased emissions from open access

could seriously threaten achievement of

Clean Air Act requirements and other

environmental commitments. It reasons

that the Commission therefore must

develop and implement environmental

mitigation.

The Joint Commenters begin with the

assertion that the data presented in the

FEIS do not support the conclusion that

the effect of the Rule on air pollution

will be insignificant. It claims that the

Commission relied on cases that show

small impacts. Joint Commenters note in

this regard that EPA has determined that

any increase in NOX emissions from

restructuring is unacceptable and

should be remedied.

Joint Commenters then assert that

FPA sections 205 and 206 require the

Commission to adopt mitigation. It

claims that case law supports the

proposition that both NEPA and the

FPA authorize FERC to mitigate the

adverse environmental impacts arising

from its action. Even assuming

arguendo that it was reasonable for the

Commission to reject specific proposed

mitigation measures, it is unreasonable

the deny the existence of authority to

mitigate. The Commission should

remedy this by adopting mitigation

concurrent with implementation of

Order No. 888.

According to Joint Commenters, the

FEIS establishes that competitive

electric markets will likely result in

higher utilization of heavily polluting

coal-fired generation. Thus, in view of

EPA’s statement in its referral to CEQ

that any increase in NOX emissions

could seriously undermine attainment

of health based standards, the FEIS
12446 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

845This aspect of the Joint Commenters’ argument

is addressed below.

finding that emission increases that may

be as large as 315,000 tons per year are

insignificant is not supported by the

record.

Joint Commenters then argue that not

only does the decision not to implement

mitigation measures risk nonattainment

of public health goals, it will fail to

achieve the regulatory objective of fair

and efficient bulk power competition. It

contends that without concurrent

environmental mitigation, the

Commission will put in place a market

structure that is inherently

discriminatory and that arbitrarily shifts

costs. It states that Order No. 888, in

effect, provides a class of competitors

with an undue preference subsidy. This

undue preference results from the fact

that the owners of coal-fired generation

that are not subject to emissions

regulation will be able to shift financial

responsibility for their pollution to

competitors in downwind regions. This

discriminatory situation will distort the

bulk power market and produce

inefficiencies that the Commission has

not addressed.845

Open Access Will Have Significant

Adverse Impacts. The Joint Commenters

state that some FEIS scenarios show that

restructuring is likely to have significant

adverse environmental effects. It claims

that the sensitivity analyses confirm that

low-cost, high-emission coal plants may

increase their capacity utilization from

an average of 62 percent in 1993 to 81.5

percent by 2010 and that this increase

is associated with an additional 515

billion kWh of coal generation per year

by 2010 above 1993 levels, assuming

expanding transmission. FEIS data

further indicate that 110 billion kWh of

this annual increase by the year 2010

will be attributable to competition

under the open access policy compared

to the frozen efficiency case.

The Joint Commenters assert that the

FEIS also confirms that this increase in

coal-based generation will increase NOX

emissions across the 37-state OTAG

region by 250,000 tons per year by 2010

(315,000 tons for the entire U.S.) and

result in a cumulative NOX emissions

increase across the U.S. of 530,000 tons

by 2000 and 2.7 million tons by 2010.

The Joint Commenters assert that the

impacts of a 250,000 ton NOX increase

across the OTAG region are extremely

significant, particularly in downwind

nonattainment areas, and fly in the face

of EPA’s determination that any

increase is unacceptable.

The Joint Commenters contend that

the Commission understates the

significance of these numbers by

emphasizing percentages and using

national figures. According to Joint

Commenters, the FEIS demonstrates that

regional increases in NOX include a

seven percent increase in the East North

Central region, 10 percent in the

Mountain region and 26 percent in the

Pacific regions. These references are to

emissions in 2005. The percentages in

the year 2010 are approximately five

percent nationally, rather than the three

percent discussed in Order No. 888.

The Joint Commenters state that the

FEIS also shows that increased

utilization of coal plants could

significantly add to utility carbon

dioxide (CO2) emissions, which would

conflict with the Clinton

Administration’s commitment to

stabilize greenhouse gas emissions at

1990 levels by the year 2000. It states

that the Competition-Favors-Coal

Scenario projects that annual utility CO2

emissions will increase by 285 million

tons by 2000 and by 737 million tons by

2010; and that the FEIS attributes about

10 percent of the increase to the Rule.

It argues that this increase will threaten

international commitments of the U.S.

Government. The Joint Commenters

assert that utility CO2 emissions are not

currently on track to fulfill national and

international climate protection

objectives and open access competition,

to the extent it favors existing coal

plants, will exacerbate these trends.

The Joint Commenters then claim that

in addition to the emissions impacts

that are identified in the FEIS, EPA’s

technical analysis indicates that the

Rule has the potential to cause much

larger impacts than the FEIS estimates

for the Competition-Favors-Coal

Scenario. EPA’s evaluation, which Joint

Commenters claim does not incorporate

worst case scenario assumptions,

indicates that the potential increases in

NOX emissions from open access could

be more than twice the increases

projected in the FEIS CompetitionFavors-Coal Scenario in years 2000,

2005 and 2010. The potential that

FERC’s highest polluting case

understates emissions increases to this

extent illustrates the uncertainty

surrounding the impacts of open access,

particularly the uncertainties

surrounding the accuracy of the

Commission’s estimates, and the critical

importance of developing mitigation

programs.

Authority to Mitigate. The Joint

Commenters assert that the

Commission’s rejection of authority to

mitigate environmental impacts is

contrary to law and arbitrary and

capricious. It states that the

Commission’s rejection is inconsistent

with Commission claims about its

sections 205 and 206 authority, and that

both NEPA and the FPA permit FERC to

mitigate adverse environmental impacts.

Thus, while it may be reasonable for the

Commission to reject specific mitigation

measures, the Commission’s decision

that it lacks authority to implement

mitigation constitutes an arbitrary and

capricious exercise of agency authority.

The Joint Commenters argue that

NEPA authorizes agencies to consider

and address environmental impacts so

long as any actions undertaken do not

conflict with the agency’s authorizing

statute. It states that a number of cases

support the proposition that FERC’s

FPA authority is broadened by NEPA—

that NEPA policies and goals inform

and expand the FPA’s definition of

public interest. In effect, NEPA

establishes a legal nexus between the

Commission’s primary regulatory duties

and environmental protection. Thus,

courts have upheld agency mitigation

actions under NEPA even when the

agencies have no explicit environmental

protection mandate. The Joint

Commenters assert that the Commission

did not address these cases in

concluding that it lacks authority to

mitigate adverse environmental impacts

under sections 205 and 206 and the

FPA’s general public interest standard.

The Joint Commenters assert that if

NEPA is to be given practical effect,

agencies must have authority to do more

than study the potential environmental

impacts of proposed actions. To

interpret and administer federal laws in

accordance with NEPA policies,

agencies must have the authority to use

their statutory powers in ways that

implement NEPA policies. The arena of

permissible environmental action is

constrained only by the limits of the

agency’s jurisdictional authority under

its enabling statutes. Thus, the only

limits on FERC’s ability to implement

environmental mitigation are those

defined by the FPA. Therefore, the

question is whether mitigation falls

within the regulatory powers of FERC.

The Joint Commenters argue that the

FPA authorizes the Commission to

mitigate the environmental effects of its

actions, stating that the public interest

standard of FPA section 201

encompasses the environmental and

other competitive concerns discussed in

its request for rehearing. The Joint

Commenters state that NAACP v. FPC,

425 U.S. 662 (1976) and similar cases

establish that FERC has jurisdiction to

address environmental concerns since

such concerns are directly related to

FERC’s regulation of economic interests

in the electric industry.

The Joint Commenters assert that

FERC’s duty to ensure just and
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12447

846FERC Stats. & Regs. at 31,862–63; mimeo at

663–65 (footnotes omitted).

847 Id. at 31,863; mimeo at 665.

reasonable rates that are not unduly

discriminatory or preferential also

encompasses non-economic factors in

appropriate circumstances. It argues that

the Commission’s reliance on Office of

Consumers’ Counsel v. FERC, 655 F.2d

1132 (D.C. Cir. 1980), to support its

narrow reading of the FPA’s public

interest standard is misplaced.

The Joint Commenters then take issue

with the position that the Commission

lacks authority to implement mitigation

because it has insufficient expertise in

air pollution control and because

Congress gave EPA authority to address

such issues. It states that the record does

not support a conclusion that FERC

lacks the expertise necessary to provide

for mitigation of the Rule’s impacts.

Moreover, nothing would prevent the

Commission from acting in concert with

EPA to take advantage of EPA’s

expertise.

The Joint Commenters state that,

unlike the situation in Office of

Consumers’ Counsel, Congress has given

FERC, along with EPA and other federal

agencies, the responsibility to address

the environmental effects of its actions.

In this case, Joint Commenters are

asking the Commission to mitigate the

environmental impacts of its Rule, not

to assert jurisdiction proactively over air

pollution matters or to usurp EPA’s role.

Under Order No. 888’s logic, no federal

agency would have authority to mitigate

the environmental impacts of its

proposed actions because EPA is the

primary agency with environmental

expertise and responsibility.

The Joint Commenters then argue that

the Commission’s jurisdiction to

consider environmental issues also

derives from a traditional analysis of

FERC’s jurisdiction over wholesale

power rates. It states that if the

Commission does not allocate

environmental responsibility to highemission utilities, environmental

compliance costs will be transferred to

downwind utilities and their customers.

These utilities will be required to incur

costs to reduce emissions and must

increase rates to recapture these costs.

Thus, Order No. 888 will directly affect

the costs that are included in electric

rates, which the Commission has

authority to review under sections 205

and 206.

The Joint Commenters conclude their

discussion by noting that, while it may

have been reasonable for the

Commission to reject specific mitigation

proposals, the Commission should

reexamine the position that it has no

authority in this area and instead

acknowledge that the exercise of that

authority is not warranted here given

the conclusions in the FEIS. The Joint

Commenters go on to note that EPA

proposed in its referral to CEQ a

mitigation approach that seeks the

Commission’s commitment to future

actions and outlines immediate actions

EPA will take to address the potential

NOX emission increases identified in

the FEIS. The Joint Commenters state

that although it believes EPA’s proposal

is reasonable and strongly support the

tracking system recommended, the

Commission should develop a backup

NOX mitigation mechanism by the end

of 1996 to assure that Order No. 888 will

be implemented without adverse

environmental impacts.

Commission Conclusion

Need for Mitigation. The FEIS

examines fully claims that the Rule will

have significant environmental impacts

requiring mitigation. As stated in Order

No. 888:

First, the findings show that, without the

rule, NOX emissions are expected to decline

until at least the year 2000. Thereafter, again

without the rule, NOX emissions are expected

to increase steadily through the year 2010

(the end of the FEIS study period). The extent

of the decrease and the increase will be

largely determined by the relative prices of

natural gas and coal, the two main fuels used

to generate electric power in most regions.

In reaching this conclusion, the FEIS used

two ‘‘base’’ cases. In one (the ‘‘High-PriceDifferential Base Case’’), natural gas was

assumed to become substantially more

expensive compared with coal than it is

today. In the other (the ‘‘Constant-PriceDifferential Base Case’’), natural gas was

assumed to maintain essentially the same

price relative to coal that has existed for the

last ten years. The two cases describe the

range of emissions due to fuel price

uncertainty without the rule and demonstrate

the overall trends of decreases until 2000 and

increases thereafter.

Second, the FEIS finds that the rule will

not in any significant respect affect these

overall trends.

The potential impact of the rule was

studied initially under two scenarios. In one

(the ‘‘Competition-Favors-Gas Scenario’’), the

rule is assumed to result in efficiency gains

in the electric industry that would tend to

favor natural gas as a fuel. In this scenario

the effect of the rule is slightly beneficial.

Total NOX emissions are reduced overall by

about two percent nationwide from the base

cases. In the other (the ‘‘Competition-FavorsCoal Scenario’’), the rule is assumed to result

in efficiency gains in the electric industry

that would tend to favor coal as a fuel. In this

scenario the effect is again slight, showing

approximately a one percent increase in NOX

emissions nationwide from the base cases. In

both scenarios, however, the rule does not

have an overall effect on NOX emission

trends.

Stated differently, under any case studied,

with or without the rule, there will be an

overall net decrease in NOX emissions

through the year 2000. Thereafter, NOx

emissions begin to increase. The rule does

not materially affect either the decline prior

to 2000 or the increase thereafter.

Based on these findings the Commission

concludes that a comprehensive,

Commission-imposed mitigation scheme to

address the environmental consequences of

the rule is not appropriate. If competition

favors gas, the effects are beneficial and

mitigation is unnecessary. If competitive

conditions favor coal through the year 2010,

and NOX emissions increase slightly as a

result of the rule, these minor effects would

be effectively mitigated as a part of a

comprehensive NOX cap and trading

allowance scheme developed by EPA in

cooperation with the Ozone Transport

Assessment Group (OTAG) and administered

by EPA and state environmental regulators

under the clearly established authority of the

Clean Air Act. [846]

The Commission went on to note that

it believes the appropriate no-action

alternative was used to conduct this

analysis. ‘‘An alternative that requires

the Commission to reverse all its other

open access policies is simply not a ’noaction’ alternative. To the contrary, it

would require decisive action running

counter to the direction from the

Congress in the Energy Policy Act and

the needs of the marketplace and

electricity consumers.’’ 847 The

Commission then explained:

However, to ensure that the effects of the

rule were analyzed fully, the FEIS did study

a reference case based on the ‘‘frozen

efficiency’’ case proffered by EPA and the

Department of Energy (DOE). Although, as

described below, we believe this case to be

highly unlikely, the results show that, even

under this scenario, the impacts of the rule

are not great and do not vary significantly

from those projected by staff under the other

assumptions.

In one case requested by EPA, staff studied

a combination of assumptions most likely to

show significant increases in emissions

associated with the rule; the case included

EPA’s frozen efficiency scenario, coupled

with the ‘‘Competition-Favors-Coal’’

assumptions. Other cases requested by EPA

posit dramatic increases in transmission

capacity (that we find highly unlikely). Even

this combination of assumptions—geared to

demonstrate the greatest impact the rule

might have on increased NOX emissions—

produced little in the way of environmental

consequences associated with the rule. Under

these extreme (and unlikely) conditions,

there would still be a net decrease in NOX

emissions until at least the year 2000, albeit

a smaller decrease than in the base cases.

Comparing projections of emissions for the

same years, emissions would be higher than

the base cases only by two percent in 2000

and three percent in 2005. It is only in the

year 2010, assuming these improbable

scenarios, that NOX emissions associated

with the rule would be higher than the base

case by even five percent.
12448 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

848 Id. at 31,863–64; mimeo at 665–67 (footnotes

omitted).

849The FEIS at page 7–8 discusses EPA’s

authority under the Clean Air Act to remedy the

interstate transport of air pollution. Section 176A

provides that whenever EPA has reason to believe

that the interstate transport of air pollutants from

one or more states contributes significantly to a

violation of national ambient air quality standards

in one or more other states, it may establish a

transport region for such pollutant. The transport

commission is charged statutorily with assessing

the degree of interstate transport of the pollutant or

precursors to the pollutant throughout the transport

region, assessing strategies for mitigating the

interstate pollution, and recommending to the EPA

Administrator measures to ensure that the relevant

State Implementation Plans (which every state is

required to have in place to address air pollution)

meet the requirements of the Clean Air Act.

A transport commission may request the

Administrator to issue a finding under section

110(k)(5) that the SIP for one or more of the states

in the transport region is substantially inadequate

to meet the requirements of section 110. The

Administrator must approve or disapprove such a

request within 18 months of its receipt.

Upon approval of recommendations submitted by

the transport commission, the Administrator must

issue to each state in the OTR to which a

requirement of the approved plan applies, a finding

under section 110(k)(5) that the implementation

plan for such state is inadequate to meet the

requirements of section 110. Such finding shall

require each such state to revise its SIP to include

the approved additional control measures within

one year after the finding is issued.

Based on these studies, including the EPA

reference case, the Commission endorses the

staff findings that the rule will affect air

quality slightly, if at all, and that the

environmental impacts are as likely to be

beneficial as negative. This is true even

under scenarios contrived to maximize

emissions associated with the rule under

circumstances that this Commission believes

to be highly unlikely.

Importantly, this is also true in the nearto mid-term. Until the year 2010, even the

worst case (the frozen efficiency case)

produces results very similar to those

produced using assumptions the Commission

believes to be reasonable. In short, the rule

will not produce an ‘‘ozone cloud’’ coming

across the Appalachians to threaten the

Northeast on the day the rule goes into effect.

Assuming that any environmental impacts

occur, they are years in the future and may

well be beneficial. As a result, calls for

Commission mitigation, and in particular for

interim mitigation to ‘‘fill the gap’’ until

programs under the Clean Air Act can be

adopted, are unnecessary and

disproportionate to the possible effects of the

rule. [ 848]

Thus, there is no basis for claims that

the Rule will result in large increases in

pollution from generating plants

operating under less stringent

environmental controls. This negates

arguments calling for the imposition of

mitigation measures to ensure that all

entities compete under an identical

regulatory regime.

We note in this regard that the Joint

Commenters’ claim that the Rule may

result in emissions increases as large as

315,000 tons per year by the year 2010,

and cumulative NOX increases across

the United States of 530,000 tons by

2000 and 2.7 million tons by 2010, is

incorrect. The Joint Commenters derive

this result by selectively choosing

numbers from the FEIS, comparing

sensitivity cases designed to be

unrealistically low and high extremes.

The low emissions case selected is the

frozen efficiency case that represents a

complete reversal of current industry

and regulatory trends that are occurring

without the Rule. The high emissions

case represents an increase in

transmission capacity that cannot

reasonably be ascribed to the Rule. The

FEIS indicates that these cases were

used to examine the sensitivity of

findings to certain extreme assumptions

maintained by commenters and are not

the appropriate cases to use for

considering potential environmental

impacts from the Rule.

Moreover, the Joint Commenters

reference increases from the Rule

without noting equally likely decreases.

Even with the lower emissions resulting

from the unrealistic frozen efficiency

case, the FEIS finds decreases in

emissions from the Rule when

competitive forces lead to greater

efficiency for natural gas generation

compared to coal.

Actions to Mitigate NOX Emissions.

Moreover, EPA and the Commission

have committed to undertake the

actions sought by those seeking

rehearing on this issue. EPA in its

referral to the CEQ concurred with the

Commission ‘‘that the open access rule

is unlikely to have any significant

adverse environmental impact in the

immediate future, and that in light of its

anticipated economic benefits,

implementation of the Rule should go

forward without delay.’’ EPA also

‘‘concludes that the FERC has

conducted an adequate analysis under

the National Environmental Policy Act

of the environmental impacts of the

open access rule under a range of

possible scenarios.’’ In particular, EPA

concurs that the ‘‘FERC made a

reasonable choice of models (CEUM)

and made assumptions for various

factors input into the model that lie

within the range of reasonable

assumptions.’’

EPA also concurred with the

Commission that NOX emissions

increases associated with the Rule, if

any, should be addressed as part of a

comprehensive NOX emissions control

program developed by EPA and the

states under mechanisms available

under the Clean Air Act. This includes

support for the efforts of OTAG to

develop standards for measuring the

scope of the ozone transport problem

and developing emissions reduction

strategies.

More significantly, EPA committed to

use its authority under the Clean Air

Act to support successful completion of

the OTAG process. EPA will establish a

NOX cap-and-trade program for the

OTAG region through Federal

Implementation Plans ‘‘if some States

are unable or unwilling to act in a

timely manner.’’ 849

EPA also states that if ‘‘the OTAG and

Clean Air Act processes fail to produce

the necessary pollution limitations in a

timely manner, EPA will call upon all

other interested Federal agencies to

assist in solving the problem.’’ In this

context EPA would ask the Commission

to contribute by further examining,

through a Notice of Inquiry, possible

strategies for mitigating NOX emissions

increases associated with the Rule. EPA

also suggested that if it determines that

the problem must be addressed through

EPA initiation of Federal

Implementation Plans, FERC could then

initiate a rulemaking to propose

‘‘suitable means under the Federal

Power Act’’ for mitigating impacts

attributable to the Rule.

The Commission, on May 29, 1996,

issued an order responding to EPA’s

referral. The Commission stated that:

Given EPA’s commitment to address air

pollution issues, it is appropriate for EPA to

seek assurances that if its best efforts are not

successful, other agencies will examine their

abilities to address the problem within the

scope of their respective statutory authorities.

Given the broad powers vested in EPA by the

Clean Air Act, we fully expect EPA to

succeed. We also note that if EPA is unable

ultimately to address the issue, either

through the voluntary OTAG process or by

means of its authority under the Clean Air

Act, we doubt that other agencies will be able

to resolve the NOX emissions problem under

more limited authority. In such

circumstances, action by the Congress may be

necessary.

Nevertheless, we believe that the

Commission should be willing, if called upon

under the circumstances EPA describes, to

consider whether, under the Federal Power

Act, it can and should attempt to address

NOX emissions issues attributable to the

Rule. Therefore, if EPA concludes that the

OTAG process has not succeeded in meeting

its objectives in a timely manner, we will

initiate a Notice of Inquiry to further examine

what mitigation might be permissible and

appropriate under the Federal Power Act.

Such an inquiry would solicit public

comment on how to assess appropriately the

air pollution impacts attributable to the Final

Rule, suitable ways in which to address such

impacts, if any, and the scope of the

Commission’s authority to address such

impacts.
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12449

850Order Responding to Referral to Council on

Environmental Quality, 75 FERC ¶ 61,208 at

61,691–92 (1996).

851FEIS at 7–10 through 7–11.

852We note in this regard that in a recently

completed rulemaking promulgating standards for

the second phase of the Nitrogen Oxides Reduction

Program under Title IV of the Clean Air Act, EPA

authorized states to adopt a NOX cap and trading

program under certain circumstances. ‘‘Acid Rain

Program; Nitrogen Oxides Emission Reduction

Program’’, 61 FR 67112, 67163 (1996).

853 62 FR 1420 (1997).

854 Id. at 1423.

855 Id.

Additionally, under the extraordinary

circumstances in which EPA would

undertake a Federal Implementation Plan,

the Commission would agree to initiate

contemporaneously a rulemaking to propose

possible mitigation that could be undertaken

by the Commission under the Federal Power

Act. Such a rulemaking would be undertaken

on the basis of the NOI mentioned above and

would be appropriate only if environmental

harm attributable to the rule that warranted

mitigation is demonstrated. The Commission

would rely upon information gleaned in the

NOI in proposing possible mitigation

strategies that are workable, tailored to

address consequences attributable to the

Rule, and consistent with our statutory

authority. In no event would the Commission

propose a mitigation strategy that would

undermine the purposes of the rule to

provide open transmission access on a nondiscriminatory basis. We emphasize that

neither the NOI nor the rulemaking, if they

occur, will affect the implementation of the

rule as required under Orders of the

Commission. [850]

Thus, EPA has concluded that the

Commission conducted an adequate

analysis of the impacts of the Rule and

agrees that the Rule is unlikely to have

any significant adverse environmental

impact in the near future. EPA also

concurs that NOX emissions increases

associated with the Rule, if any, should

be addressed as part of a comprehensive

NOX emissions control program

developed by EPA and the states under

mechanisms available under the Clean

Air Act. This includes support for the

efforts of OTAG to develop emissions

reductions strategies. EPA will use its

Clean Air Act authority to support

completion of the OTAG process. EPA

is prepared to establish a NOX cap-andtrade program for the OTAG region

through Federal Implementation Plans if

states are unable or unwilling to act in

a timely manner.

This commitment by EPA puts to rest

the concerns expressed by those seeking

rehearing on the issues of mitigation

and disparate emissions standards. As

stated in the FEIS:

The Ozone Transport Assessment Group

(OTAG) represents [a] broad[] effort to deal

with the interstate transport of pollutants that

form ozone. OTAG is a voluntary

organization that consists of 37 eastern states,

the District of Columbia, and the EPA;

industry and environmental groups also

participate in the OTAG process. It was

organized by the Environmental Council of

States to study the transport of ozone and its

precursors in the eastern U.S. and to develop

mitigation strategies. OTAG is performing

extensive photochemical grid modeling to

determine ozone transport patterns and to

evaluate the efficiency of various control

strategies. OTAG intends to submit its

findings regarding transport patterns and its

recommendations for mitigation of ozone

transport to EPA by January 1997.

OTAG is considering a number of strategies

to mitigate the problem of ozone

nonattainment. One strategy is the

imposition of a cap and trading system for

NOX emissions in a 37-state area

compromising the Northeast OTR and

upwind states. If the cap and trading system

becomes effective, it will fully mitigate any

NOX emissions increases attributable to open

access transmission within the 37-state area,

because increases within this area would

have to be offset by a corresponding emission

reduction.

The OTAG cap and trade program may not

deal directly with emissions of pollutants

other than NOX. However, a cap on NOX is

likely to mitigate CO2 and mercury increases,

because internalizing costs of NOX controls

on coal-fired units is likely to dampen

increases in capacity utilization of such

units.[851]

The OTAG process includes the

players of concern here—both the states

from which alleged pollution increases

would originate and the states that

would be affected by the increased

pollution. OTAG has a process

underway to determine transport

patterns and to evaluate control

strategies. One strategy that is being

considered is the imposition of a cap

and trade system for NOX emissions like

that sought on rehearing here.852 OTAG

originally intended to submit its

findings regarding transport patterns

and recommendations for mitigation to

EPA by January 1997. As a result of its

decision to conduct additional modeling

to determine the appropriate geographic

applicability of emission reduction

strategies, OTAG has extended its

January timeframe by a few months, and

now intends to complete its process by

April or May 1997.

While OTAG is continuing its efforts,

EPA is moving rapidly forward to

remedy in a comprehensive fashion the

interstate transport of air pollution. On

January 10, 1997, EPA issued a notice of

intent to use the authority granted it by

sections 110(k)(5) and 110(a)(2)(D) of

the Clean Air Act to require states to

submit state implementation plan (SIP)

measures to ensure that emission

reductions are achieved as needed to

prevent significant transport of ozone

pollution across state boundaries in the

Eastern United States. This notice

‘‘announces EPA’s intention to conduct

the formal process for implementing the

regional reductions in ozone precursors

that are necessary for areas in the

Eastern United States to reach

attainment.’’ 853 EPA states that it

intends to publish a Notice of Proposed

Rulemaking in March 1997 that ‘‘will

propose overall amounts or ranges of

NOX and/or VOC emission reductions

that each State would need to achieve

to reduce the boundary condition

concentrations of ozone and its

precursors within a specified timeframe

and require the submission of SIP

controls to achieve these reductions.’’ 854

The notice of inquiry also states that the

SIP revision must contain a schedule for

adoption and implementation of these

measures. It notes that while EPA could

allow up to 18 months for SIP

submittals under section 110(k)(5),

‘‘EPA is considering a more accelerated

schedule for submittals under this SIP

call to attain air quality benefits sooner

and to facilitate area specific SIP

planning.’’ 855 EPA notes that as it goes

through the process of developing an

implementation program for the new

standard, it will be able to take

advantage of the information gathered

by OTAG and account for emission

reductions that result from the

recommended strategy. EPA intends to

publish the final SIP call notice in

summer 1997.

Thus, actions to address the concerns

with regard to mitigation and emissions

standards disparity are taking place at

this time and should be in place in the

near future. This lays to rest as well

concerns that any near-term impacts of

the Rule have not been taken into

account.

The Commission’s Authority to

Mitigate. The PA Com makes an

unsupported assertion that the FPA’s

public interest standard authorizes the

Commission to take mitigation measures

related to its regulatory actions, and that

the Commission should use the results

of the OTAG process to develop a

mitigation strategy.

The Joint Commenters argue that the

Commission has broad authority under

NEPA to mitigate the environmental

consequences of its proposed actions. It

contends that NEPA broadens the

Commission’s FPA authority—that

NEPA policies and goals inform and

expand the FPA’s definition of the

public interest. It also argues that the

Commission’s duty to ensure just and

reasonable rates that are not unduly

discriminatory or preferential also
12450 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

856See, e.g., Marsh v. Oregon Natural Resources

Council, 490 U.S. 360 (1989); Sierra Club v. Marita,

46 F.3d 606, 623–24 (7th Cir. 1995); Inland Empire

Public Lands Council v. Schultz, 992 F.2d 977, 981

(9th Cir. 1993).

857 Kleppe v. Sierra Club, 427 U.S. 390 (1976).

encompasses non-economic factors in

appropriate circumstances.

The Joint Commenters conclude that,

while it may be reasonable for the

Commission to reject specific proposed

mitigation measures, the Commission

should, at a minimum, acknowledge

that the FEIS demonstrates that the

exercise of that authority is not

warranted in this case. The Joint

Commenters add that the Commission

should initiate a rulemaking proceeding

that considers mitigation options and

evaluates the effectiveness of alternative

strategies and proposals. The Joint

Commenters concur that EPA’s

commitment to address air pollution

issues is reasonable, but would have the

Commission develop a backup NOX

mitigation mechanism by the end of

1996.

Thus, the PA Com and the Joint

Commenters would have the

Commission revisit in this order, by

means of a generalized reexamination of

the Commission’s authority to impose

mitigation, the conclusion in Order No.

888 that the mitigation measures

recommended by commenters are

beyond our authority to implement.

Order No. 888 and the FEIS fully

examine the need for mitigation and the

Commission’s legal authority to impose

mitigation measures. That examination

led to the conclusion that: (1) the

insistence of certain commenters that

the Commission adopt and implement

mitigation measures is based on

significantly overstated assumptions

regarding the contribution of the Rule to

existing environmental problems, and

that these assumptions about the impact

of the Rule are wrong; (2) the existence

for many years of a significant ozone

nonattainment problem in part of the

U.S. has led to the development of

mechanisms to address this issue; (3)

the mitigation recommendations

suggested by commenters suffer from

serious legal and practical

shortcomings; and (4) the mitigation

measures recommended by commenters

are beyond the Commission’s authority

to implement and strong policy

considerations militate against their

adoption.

The PA Com and Joint Commenters

have not raised any arguments that

warrant revisiting the Commission’s

exhaustive examination of this issue in

Order No. 888 and the FEIS, and we

hereby reaffirm those decisions. We

note in this regard that the PA Com did

not advance a specific mitigation

proposal in comments on the EIS and

does not challenge the Commission’s

rejection in Order No. 888 of specific

mitigation proposals advanced by other

commenters. The Joint Commenters did

propose a specific mitigation strategy

which the Commission rejected because,

among other things, it would have the

Commission impose a revenue

collection measure. The Joint

Commenters do not challenge the

Commission’s analysis of its proposal or

seek rehearing of its rejection. Instead,

the Joint Commenters seek an

acknowledgement from the Commission

that, given the conclusions in the FEIS,

the exercise of authority to mitigate is

not warranted in this case. As we stated

in Order No. 888 and the FEIS,

mitigation is not warranted given the

conclusions reached in the FEIS. The

Commission also notes that we have

thoroughly examined our legal authority

in Order No. 888 and we find nothing

in the arguments on rehearing that

persuade us now to a different result.

We have agreed to further examine our

authority to engage in environmental

mitigation through a Notice of Inquiry if

EPA determines that the OTAG efforts

are not successful. Therefore, it is

unnecessary in this context to opine

further in the abstract as to the scope of

the Commission’s mitigation authority.

Because the PA Com and the Joint

Commenters have raised no new

arguments that were not thoroughly

addressed in Order No. 888 and the

FEIS, it is unnecessary to repeat here the

thorough analysis of this issue set forth

in those documents. The Commission

declines to grant rehearing on this issue.

Other Mitigation-Related Issues. VT

DPS states that the Commission has

given inadequate consideration to the

possibility that the Rule may

unnecessarily exacerbate environmental

impacts and that the Commission,

therefore, should adopt mitigation.

This statement, which VT DPS fails to

substantiate, is incorrect. The FEIS and

the process which led to the

conclusions contained therein fully

consider the environmental impact of

the Rule. VT DPS fails to identify any

particulars in which the FEIS is

deficient. VT DPS’s disagreement

appears to be a generalized

dissatisfaction with the substantive

conclusion reached by the FEIS that the

Rule will not have significant

environmental impacts.

VT DPS next claims that the

Commission’s environmental review

process has not facilitated the ability of

affected parties to review all of the

modeling assumptions. It also claims

that other environmental reviews

suggest that the Rule will have more

serious NOX emissions consequences

than acknowledged by the Commission.

VT DPS again attacks the FEIS with a

broad brush, but fails to identify ways

in which the ability of parties to review

modeling assumptions has been

impeded. Likewise, it does not identify

areas in which modeling assumptions

have not been identified or any way in

which its understanding of the FEIS has

been hampered by the alleged

unavailability of certain modeling

assumptions. VT DPS is very late in

raising such claims. The time to raise

such issues is during the scoping

process or in comments on the DEIS.

It is unclear what other environmental

reviews VT DPS is referring to or the

ways in which those reviews allegedly

suggest that the Rule will have more

serious NOX emissions consequences

than acknowledged by the Commission.

Even if the unidentified studies reach

different results than the FEIS this does

not invalidate the conclusions

contained in the FEIS. The mere fact of

disagreement, even disagreement among

experts in a given area, does not

invalidate a study. 856

VT DPS next recommends that the

Commission establish an ongoing

monitoring program in consultation

with environmental agencies. It states

that a monitoring program would allow

the Commission to take timely action to

mitigate any unintended consequences

of the Rule.

An EIS is required to be prepared,

when appropriate, prior to agency

action. As the Supreme Court has stated,

the moment at which an agency must

have a final statement ready is the time

at which it makes a recommendation or

report on a proposal for federal action.

857 There is no requirement that an

agency continue to evaluate the

environmental impacts of a project after

it is implemented, particularly where, as

here, the agency has determined that the

proposal is not likely to have adverse

environmental impacts.

Moreover, as discussed extensively

above, EPA’s commitment to take action

with regard to the underlying problems

of the interstate transport of air

pollutants provides a fuller measure of

relief than that sought by VT DPS.

The New York Attorney General

claims that it is essential that FERC

exercise any authority it may have to

mitigate the environmental effects of the

Rule because Congress has limited

EPA’s authority in this regard. The

Attorney General also claims that EPA’s

proposal in its comments of February

20, 1996 on the DEIS to place a cap on

NOX emissions would mitigate the

effects of the Rule; it suggests basing
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12451

858FERC Stats. & Reg. at 31,890–91; mimeo at

740–43 (footnotes omitted). The FEIS noted in this

regard at page J–93 that:

Many factors cause generation sources to have

differing costs. Some states impose taxes on

generators that others do not. Some fuels are taxed

differently than others (e.g., renewable generators

such as wind power receive tax incentives that

fossil generators do not while fossil fuels receive

other tax advantages that renewables do not.) Such

differences cannot be said to be unduly

discriminatory, especially when they are

sanctioned, or even required, by the actions of the

Congress or state authorities. If the Commission

attempted to ‘‘level’’ all of the ‘‘playing fields’’ it

would be unable to judge any rate to be just and

reasonable. Further, traditional rates are not

determined through competitive processes but on a

cost of service basis. Not all rates have to be

determined to be competitive in order to be judged

just and reasonable. * * *

this system on the MOU. The Attorney

General urges implementation of this

system on the federal level pursuant to

authority residing in EPA and/or FERC.

We note first that Congress has made

a full grant of authority to EPA to

address the issue of the interstate

transport of air pollution. As discussed

extensively above, EPA has committed

to address this issue, and to use its

authority pursuant to the Clean Air Act

if states are unwilling to address this

issue cooperatively through the MOU

process. Thus, EPA has committed to

undertake the relief sought by the

Attorney General. If EPA is

unsuccessful, the Commission has

pledged to assist in this effort as

discussed above.

D. Emissions Standards Disparity

Order No. 888 addresses claims that

the Commission should ‘‘level the

playing field’’ as to environmental

standards. The argument was that

unless the Commission imposes

mitigation, competitors with ‘‘dirty’’

generation will be favored over ‘‘clean’’

competitors. Those urging the adoption

of measures to level the playing field

argue that mitigation of environmental

impacts has a direct relationship to

ensuring that open access is

implemented under terms of economic

fairness for all utilities, and not merely

those with current low-cost regulatory

advantages.

We responded to those arguments in

Order No. 888 by noting that:

[A]ll power generation technologies have

different costs. For example, hydroelectric

facilities which, like coal-fired facilities, may

have environmental mitigation conditions

imposed on them, may be quite expensive to

build compared to gas or oil-fired generation,

but their operating costs may be significantly

lower. These cost differences may reflect the

different costs of complying with mandated

environmental requirements; the prudent

costs of complying with such mandates may

be reflected in rates.

Indeed, sellers come to the power markets

with a variety of advantages and

disadvantages, many of which are the result

of federal laws—for example, tax preferences,

labor standards, and similar matters. In

empowering the Commission to remedy

undue discrimination and promote

competition, Congress has not authorized the

Commission to equalize the environmental

costs of electricity production in order to

ensure ‘‘economic fairness.’’ Such

homogenization of competitors, or their

costs, has never been a goal of the FPA.

* * * * *

In short, the ‘‘economic nexus’’ urged by

commenters advocating that the Commission

undertake to regulate air emissions is

inconsistent with the ‘‘charge to promote the

orderly production of plentiful supplies of

electric energy’’ envisioned by the FPA.

We have exercised conditioning authority

in the past only where necessary to ensure

that jurisdictional transactions and rates do

not result in anti-competitive effects, or are

not unjust, unreasonable or unduly

discriminatory or preferential. Thus, the

conditions we have imposed have involved

economic regulatory matters within our

purview under the FPA. Any exercise of

conditioning authority must, as the Supreme

Court noted in NAACP, be directly related to

our economic regulation responsibilities;

EPA and the other commenters have not

demonstrated such a nexus.

This distinction is more evident when one

considers the way in which we are

authorized to treat the costs of environmental

compliance. There are legitimate costs of

environmental compliance that should be

reflected in jurisdictional rates to the extent

prudently incurred, just as the prudent costs

of complying with, for example, occupational

health and safety requirements designed to

protect utility employees should be reflected

in jurisdictional rates. This we are authorized

to do and we routinely review and allow

such costs. However, the fact that the costs

of providing utility workers with a safe

workplace are properly reflected in utilities’

jurisdictional rates does not mean that we

have authority to condition sellers’ rates or

customers’ use of jurisdictional services on

meeting safety regulations that are in the

public interest. The same rationale applies to

environmental matters related to the rule.

[858]

Rehearing Requests

Pennsylvania PUC. The PA Com

asserts that the FEIS does not

adequately address challenges posed by

the Clean Air Act Amendments of 1990.

The PA Com contends that the Rule may

shift power production from

Pennsylvania plants with strong

environmental controls to upwind

plants with less stringent controls, and

that prevailing climatic patterns may

transport the increased pollution

downwind. It states that mitigation is

needed to prevent degradation of

downwind air quality and the

imposition of further costs and limits on

downwind generation.

The PA Com states that the Clean Air

Act Amendments imposed stringent

emission standards on Pennsylvania

generation, but did not impose similar

standards on neighboring states such as

Ohio and West Virginia. It claims that

the FEIS does not sufficiently consider

these requirements. The PA Com

concludes that implementing open

access without mitigation will place

Pennsylvania utilities at a competitive

disadvantage, and that this result is

inconsistent with the public policy

goals of the Clean Air Act and the

Federal Power Act. The PA Com also

asserts that the Rule may discriminate

against Pennsylvania utilities and the

Pennsylvania coal industry, and that the

combination of the Clean Air Act and

Order No. 888 places Pennsylvania at a

disadvantage in the competition for new

industry and jobs.

The PA Com claims that Order No.

888 may push states in the Northeast

Ozone Transport Commission into

repudiating the existing MOU. It claims

that it is inconsistent for one federal

purpose which is statutorily clear (i.e.,

clean air mandates established by the

Clean Air Act Amendments) to be

prejudiced by another federal purpose

with only inferential statutory authority

(i.e., open access under sections 205 and

206 of the FPA).

The PA Com asserts in this regard that

Phase II of the MOU will require by

1999 a 55 percent reduction in NOX

emissions in most of Pennsylvania and

65 percent (0.2 lbs/mmBTU) in the

Philadelphia area. Title I of the Clean

Air Act requires that the Northeast make

reasonable progress towards attainment.

If the inner zone of states comprising

the Ozone Transport Commission do not

achieve attainment, Phase III of the

MOU will be implemented in 2003.

Phase III requires a 75 percent reduction

in emissions (0.15 lbs/mmBTU) for the

entire state. According to the PA Com,

to meet Phase III requirements most

Pennsylvania coal-fired stations will

have to install Selective Catalytic

Reduction technology at a capital cost of

$2.3 to $3.5 billion. It states that other

Northeast states will be required to

make expenditures that are much lower,

and that states such as West Virginia

and Ohio will not be subject to these

requirements at all.

New Jersey BPU. The NJ BPU poses a

similar concern. It states that upwind

power plants are designed to meet NOX

emission standards which are

substantially less restrictive than those

required in New Jersey. The NJ BPU

claims that this will have a two-fold

impact—New Jersey air quality will be

degraded through air transport and New

Jersey utilities will be placed at a
12452 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

significant cost disadvantage. The NJ

BPU states that it is inconsistent to

assert substantial incremental benefits

associated with competition brought

about by the Rule, while asserting that

the Rule will not result in any change

in the utilization of existing power

plants.

NJ BPU asserts that there are

disparities in the electric industry

among suppliers with regard to

environmental impacts and costs, and

that the Commission did not take this

into account in determining the total

economic benefit of a competitive

wholesale generation market. It notes

that the Commission may consider that

it produced an economic benefit if the

Rule enables a buyer in the Southeast to

displace self-generated 4-cent power

with 3-cent power from the Midwest.

The NJ BPU contends, however, that if

emissions from the plants producing the

electricity result in 1.5 cents worth of

mitigation costs on a downwind state,

an appropriate economic analysis would

conclude that the transaction actually

increases total costs. NJ BPU asserts that

it was inappropriate for the Commission

to focus on economic gains while

leaving cost issues to be dealt with by

other entities.

NJ BPU recommends that the

Commission adopt an integrated

environmental, economic and energy

policy approach which embraces the

underlying principles in EPA’s acid rain

program. It states that the Commission

should call for specific, significant and

enforceable reductions in NOX

emissions coupled with a market based

trading program of emissions. It asserts

that this approach would ensure a fair

and competitive playing field at a

fraction of the expected cost savings

from the Rule.

Joint Commenters. The Joint

Commenters assert that the Commission

has a duty under the FPA to mitigate

undue preferences that affect

competition in the wholesale power

market. It concludes that this mandate

must be applied here where

implementation of open access policies

without concurrent environmental

mitigation will cause generation-owning

utilities to face a discriminatory

competitive situation.

The Joint Commenters note that the

Northeast is an ozone nonattainment

area because of high levels of ambient

ozone pollution, and is therefore subject

to strict NOX reduction requirements. It

states that regional utilities have

invested significant sums in pollution

reduction facilities and cleaner

generation to meet legal requirements to

reduce emissions. It contends that these

utilities will be subject to additional

NOX reduction requirements, thus

increasing generation costs, if ambient

ozone levels increase as a result of

competition.

The Joint Commenters contend that if

open access increases emissions,

utilities in the Northeast that have

increased their generation costs to

reduce air pollution will be required to

bear additional costs to offset the

impacts of increased upwind emissions.

It states that the cost to Northeast

utilities to offset additional NOX

emissions will likely be substantially

higher than the costs would be to

upwind competitors to mitigate

emissions at the source. It claims that

offsetting the impacts of a 250,000 ton

NOX increase in downwind

nonattainment areas, where marginal

NOX and volatile organic compound

(VOC) control costs average about

$3,800 per ton, could total $1 billion.

On the other hand, mitigating the

pollution increases at generation

sources which currently operate with

minimal environmental controls would

cost about $500 per ton, or $130 million.

The Joint Commenters assert that this

cost differential will be hidden from the

competitive market because Northeast

generators will bear the cost.

The Joint Commenters assert that this

demonstrates that the wholesale bulk

power market in the eastern United

States is suffused with an existing

undue preference that inordinately

favors one category of competitors by

allowing them to produce and sell

power at a lower marginal cost. This

preference exists today as a result of

costs incurred in the past to meet Clean

Air Act obligations; the FEIS

demonstrates that Order No. 888 could

worsen this situation as a result of

increased sales from older, higheremitting upwind coal generators.

The Joint Commenters add that, aside

from the competitive unfairness of this

situation, the undue preferences will

produce inefficiencies which distort

investment decisions and increase the

overall cost to produce electricity—the

antithesis of what Order No. 888 is

meant to achieve. It asserts that these

inefficiencies will occur in four ways:

Sources in downwind nonattainment areas

could have to spend hundreds of millions of

dollars to address increased air pollution

resulting from open access if polluting plants

do not mitigate at the source. Thus, less

efficient investments will be made to reduce

air pollution and the overall cost of

generating electricity will be higher than in

a competitive market that is not distorted by

discrimination.

Order No. 888 could adversely impact the

economic dispatch of generating sources

under competitive conditions. In the absence

of mitigation, generation from higher

polluting upwind plants could displace

generation from plants in the Northeast that

operate more efficiently at the margin. As

utilities in the Northeast are required to add

more costly emission controls in response to

interregional migration of air pollution, their

operating costs will be driven up and may

exceed the costs of less efficient plants which

have avoided such controls. Thus, in the

absence of mitigation, Order No. 888 may

foster less efficient utilization of generating

resources.

Implementation of Order No. 888 without

mitigation may distort the market for future

generation capacity. If older, more highlypolluting plants can shift the environmental

cost of production to other wholesale

generators, they are likely to expand their

output to address market needs, thus

reducing the demand for more efficient,

clean-burning generating facilities.

Transmission from the Midwest to the East

is often heavily constrained. Consequently, a

distorted price signal to increase generation

in the Midwest would exacerbate existing

constraints and improperly stimulate the

construction of new transmission capacity to

support additional interregional transactions.

The Joint Commenters conclude that the

Commission has an obligation to

exercise its authority in non-arbitrary

manner, particularly when acting to

prevent undue discrimination.

Finally, the Joint Commenters

disagree with the Commission’s

response to this issue in Order No. 888.

It asserts that the Commission and the

courts have found in the ‘‘price

squeeze’’ context that the Commission

has authority to remedy anticompetitive discrimination, even when

it is caused by regulatory practices of

others over which it and its regulated

public utilities have no control. Second,

the Commission has the authority and

responsibility to address environmental

issues that directly affect and have a

nexus to its section 205 and 206

responsibilities. Third, if the

competitive market that the Commission

wishes to create will not operate fairly

or efficiently, the Commission has a

duty to consider whether it should go

forward at all if it believes it does not

have the power to remedy important

adverse competitive consequences.

Commission Conclusion

Congress has empowered the

Commission to remedy undue

discrimination and promote

competition; it has not authorized the

Commission to equalize the

environmental costs of electricity

production in order to ensure

‘‘economic fairness.’’ Homogenization of

competitors, or their costs, has never

been a goal of the FPA.

Action in Order No. 888 to remedy

undue discrimination in access to the

monopoly owned transmission wires
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12453

that control whether and to whom

electricity can be transported in

interstate commerce does not require

action by the Commission to cure all

competitive differences between

participants in the utility marketplace.

This is particularly true where the

disparities arise because Congress has

established policies with regard to

competing issues of national

significance and charged other agencies

of the federal government with

implementing those policies. The

assertion that the Commission must

eliminate any competitive disadvantage

arising from congressionally mandated

policies, including the vital national

policies set forth in the Clean Air Act,

before it can act to remedy undue

discrimination and encourage

competition in the electric utility

industry is in error.

Furthermore, as noted above, the

analysis reflected in the FEIS refutes the

claim that the Rule will result in

significant environmental impacts.

Thus, there is no basis in any event to

support requests that the Commission

‘‘level’’ the playing field.

Recounted briefly, those findings

show that, without the Rule, NOX

emissions are expected to decline until

at least the year 2000. Thereafter, again

without the Rule, NOX emissions are

expected to increase steadily through

the year 2010. The extent of the

decrease and increase will be largely

determined by the relative prices of

natural gas and coal.

The analysis also demonstrates that

the Rule will not in any significant

respect affect these overall trends. The

analysis shows that if the Rule results in

efficiency gains in the electric industry

that favors the use of natural gas as a

fuel, the effect will be slightly

beneficial; total NOX emissions will be

reduced overall by about two percent

nationwide below what would

otherwise be expected to occur. If the

Rule results in efficiency gains that

favor the use of coal as a fuel, the Rule

is expected to increase NOX emissions

approximately one percent above what

would otherwise be expected to occur.

Even analyzing the highly unlikely

frozen efficiency case, the analysis

demonstrates that the impacts of the

Rule will not be great and will not vary

significantly from those projected by

staff under the assumptions discussed

above. This study, utilizing a

combination of assumptions geared to

demonstrate the greatest impact the

Rule might have on increased NOX

emissions, produced little in the way of

environmental consequences associated

with the Rule. Under these extreme (and

unlikely) conditions, there would still

be a net decrease in NOX emissions

until at least the year 2000, albeit a

smaller decrease than in the base cases.

Comparing projections of emissions for

the same years, emissions would be

higher than the base cases only by two

percent in 2000 and three percent in

2005. It is only in the year 2010,

assuming these improbable scenarios,

that NOX emissions associated with the

Rule would be higher than the base case

by even five percent.

All told, this analysis demonstrates

that the Rule will affect air quality

slightly, if at all, and that the

environmental impacts are as likely to

be beneficial as negative. This is true

under scenarios contrived to maximize

emissions under circumstances that the

Commission believes to be highly

unlikely. This is also true in the near to

mid-term. Assuming that any

environmental impacts occur, they are

years in the future and may well be

beneficial.

Thus, contrary to the position taken

by those seeking to have the

Commission impose mitigation, the

Rule will not result in impacts requiring

mitigation to level the playing field.

Moreover, as also noted above, EPA

has committed to address the existing

NOX transport issue, including the

contribution of the Rule, if any, to those

impacts. It must be emphasized in this

regard that the Northeast has

experienced significant air pollution

problems for many, many years. Much

of this pollution is generated by

activities within the affected states and

within the affected region; the problem

is exacerbated somewhat by the airborne

transport of pollutants from upwind

areas, including pollutants resulting

from the generation of electricity that

will occur regardless of any future

increase in generation that might result

from implementation of the Rule.

Put differently, the pollution

problems in the individual states and in

the Northeast in general result primarily

from economic activities within those

states. The airborne transport of

pollutants, including pollution resulting

from existing electric generation, adds

to the existing problem to some degree.

The analysis in the FEIS demonstrates

that open access may increase the

amount of upwind generation by some

small increment, and thus increase the

downwind NOX levels by an even

smaller incremental amount. On the

other hand, depending on the future

competitive position of natural gas

versus coal, a situation over which the

Commission has no control, the Rule

may decrease the amount of pollution

that would otherwise exist and thus

decrease downwind pollution. In any

event, the Rule will affect existing

trends slightly, if at all.

In recognition of the situation

described above, which again is likely to

be affected only very slightly, if at all,

by the Rule, EPA has committed to

address the overall issue of NOX

emissions as part of a comprehensive

program developed by EPA and the

states. EPA has committed to use its

authority under the Clean Air Act to

successfully complete the OTAG

process. EPA states that it will, if

necessary, establish a NOX cap-andtrade program for the OTAG region

through Federal Implementation Plans if

some states are unable or unwilling to

act in a timely manner.

As discussed in the FEIS, and as

noted above, OTAG has efforts

underway to develop responses to this

problem. For example, OTAG intends to

submit its findings regarding ozone

transport patterns and its

recommendations for mitigation of

ozone transport to EPA by April or May

1997. If this process is less than fully

successful, the Clean Air Act authorizes

EPA to act in a relatively short timeframe to address this problem. EPA has

committed to exercise this authority to

address the problem.

It must be emphasized that EPA has

stated its intent to address the problem

regardless of the effects of the Rule.

Even if the Rule results in

environmental impacts, those

incremental impacts will be addressed

as part of the comprehensive NOX

regulatory developed by EPA in

conjunction with the states.

Thus, EPA has committed to

undertake the mitigation sought by the

PA Com, NJ BPU and Joint Commenters.

The Commission has stated its intent to

participate in this process as discussed

above. This result negates claims that

implementing open access without

mitigation will place downwind utilities

and the Pennsylvania coal industry at a

competitive disadvantage. Accordingly,

the requests that the Commission

impose mitigation measures to ‘‘level’’

the environmental playing field are

denied.

E. Short-Term Consequences of the Rule

The FEIS projects future electric

powerplant emissions under a range of

assumptions without the Rule (base

cases). These results are then compared

to what electric powerplant emissions

are likely to be under corresponding

assumptions with the Rule in place

(Rule scenarios). The study utilizes

three reporting years: 2000, 2005, and

2010. These reporting years were chosen

because they cover a reasonable time

frame for the study. Beyond 2010, the
12454 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

859FEIS at ES–9, 3–1.

860 Id. at 3–1.

861 Id. at 5–15.

862FERC Stats. & Regs. at 31,634; mimeo at 1.

863FEIS at ES–13 through ES–16.

projections are dependent on too many

unforeseeable factors to be

meaningful.859

Although the effects of the Rule will

begin to occur when the final Rule is

issued, the effects should develop

gradually over time. Measurable effects

are expected to be clearly observable by

the year 2000, though not necessarily

fully complete.860

The FEIS analysis of the Rule

scenarios shows that NOX emissions are

expected to decrease significantly

between 1993 and 2000. The

Competition-Favors-Gas Scenario

demonstrates that the Rule will

reinforce decreases already present in

the base case. Thus, the Rule will

enhance underlying environmental

improvements. While the CompetitionFavors-Coal Scenario demonstrates

small emissions increases, NOX

emissions nonetheless continue to

decrease from 1993 to 2000. A similar

trend is also seen on a regional basis.

The Rule does not alter the basic pattern

of environmental improvement.861

Rehearing Requests

New Jersey BPU. The NJ BPU claims

that the FEIS fails to recognize possible

short-term effects the Rule may have on

existing ozone problems in the

Northeast, and that the failure to

address short-term consequences is of

particular importance to nonattainment

states who must meet Clean Air Act

attainment dates in 1996 and 1999.

Joint Commenters. The Joint

Commenters claim that by examining

the period between 2000 and 2010, the

FEIS fails to analyze near-term impacts

and the need for a short-term mitigation

strategy. Joint Commenters note that the

Rule will be implemented almost

immediately, and that changes in

generation plant utilization that give

rise to the greatest environmental

concerns may occur very quickly.

The Joint Commenters are concerned

that the FEIS does not consider how

projected environmental effects prior to

2000 would impact air quality and

Clean Air Act attainment deadlines. The

Joint Commenters contest the

conclusion that utility NOX emissions

will decline between 1993 and 2000. It

states that emissions will increase each

year between 1993 and 2000 except in

1996 and 2000, when large NOX

reductions will be implemented

pursuant to the Clean Air Act. The Joint

Commenters also contend that it is

irrelevant whether clean air programs

will cause overall emissions to be lower

in 2000 than they were in 1993; the

relevant question is whether emissions

will be higher with Order No. 888 than

without it.

The Joint Commenters contend that

the data presented in the FEIS for the

year 2000 suggest that, if the Rule is

considered in isolation, there will be

potentially significant short-term

emissions increases in the period 1996–

2000. It states that the FEIS indicates

that implementation of the Rule under

the Competition-Favors-Coal Scenario

with expanded transmission will lead to

an additional 132,000 tons of NOX

emissions in 2000 compared with the

frozen efficiency reference case. It

contends, assuming a linear increase,

that this means there could be an

additional 75,000, 94,000 and 113,000

tons of NOX emissions as a result of the

Rule in 1997, 1998, and 1999,

respectively.

Commission Conclusion

The Joint Commenters’ claims that

implementation of the Rule will lead to

an additional 132,000 tons of NOX

emissions in the year 2000 in incorrect.

As is the case with regard to its

assertion above that the Rule will result

an additional 315,000 tons of NOX

emissions in 2010, this impact was

derived by selectively choosing

numbers from the FEIS, comparing two

sensitivity cases designed to be

unrealistically low and high extremes.

The low emissions case is the frozen

efficiency case that represents a

complete reversal of current industry

and regulatory trends that are occurring

without the Rule. The high emissions

case represents an increase in

transmission capacity that cannot

reasonably be ascribed to the Rule. As

stated in the FEIS, these cases were

selected to examine the sensitivity of

FEIS findings to certain extreme

assumptions maintained by commenters

and are not the appropriate cases for

determining potential environmental

impacts from the Rule.

Moreover, we note that the Joint

Commenters reference increases from

the Rule without noting equally likely

decreases. Even with the lower

emissions resulting from the unrealistic

frozen efficiency case, the FEIS finds

decreases in emissions from the Rule

when competitive forces lead to greater

efficiency for natural gas generation

compared to coal.

The Commission has analyzed the

Rule and found that its impacts will be

insignificant. We also note that even if

the Rule were to result in short-term

emission increases, EPA has signaled its

willingness to address the transport of

pollutants in a timely fashion. As

discussed above, EPA has concluded

that any emissions increases associated

with the Rule should be addressed as

part of a comprehensive NOX emissions

control program developed by EPA and

the states under mechanisms available

under the Clean Air Act. This approach

includes support for OTAG efforts to

develop emissions reduction strategies.

OTAG plans to submit its findings and

mitigation recommendations to EPA by

April or May 1997. As discussed above,

EPA has issued a notice of intent to

adopt by summer 1997 a rule that would

require state implementation plan

measures to ensure that emission

reductions are achieved as needed to

prevent significant transport of ozone

pollution across state boundaries in the

Eastern United States. EPA is

contemplating establishing deadlines for

state implementation plan submittals

ranging from six months to 18 months

following the date of publication of its

notice of final rulemaking.

The instant Rule will affect the

existing NOX transport issue very little,

if at all. As stated in Order No. 888, the

Rule is not the appropriate vehicle for

resolving this debate. The appropriate

regulatory mechanism for addressing

the overall NOX problem, including

emissions from electric utility

generating plants, is a NOX emissions

cap and allowance trading scheme along

the lines of that developed by the

Congress under the Clean Air Act for

SO2 emissions. As noted, EPA has

committed to implement this approach.

Even if there are slight environmental

impacts associated with the Rule, they

are better and more effectively

addressed as part of a comprehensive

NOX regulatory program.

G. Cost Benefit Analysis

‘‘The legal and policy cornerstone’’ of

Order No. 888 ‘‘is to remedy undue

discrimination in access to the

monopoly owned transmission wires

that control whether and to whom

electricity can be transported in

interstate commerce.’’ 862 As reiterated

in the FEIS, the purpose of the Rule is

to increase access to non-discriminatory

transmission services and thereby

increase competition in wholesale

electric markets.863

The FEIS states that the Rule will give

wholesale power customers a greater

opportunity to obtain competitively

priced electricity. Competition will

create benefits through better use of

existing assets and institutions, new

market mechanisms, technical

innovation, and less rate distortion.
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12455

864The discussion of the economic benefits of the

Rule in found in the FEIS at ES–13 through ES–16

and 5–64 through 5–75. 865FEIS at 5–64.

Only the first—better use of existing

assets and institutions—was estimated

quantitatively: approximately $3.8 to

$5.4 billion per year. The FEIS also

discusses other benefits that cannot be

quantified but may be large. Based on

the experience of, for example, the

natural gas and telecommunications

industries, the Commission opined that

the other three are likely to increase

industry efficiency—and benefits—

substantially.864

As described elsewhere in this order,

the FEIS also discusses extensively

possible environmental effects (i.e.,

costs) of the Rule. It concludes that the

Rule could raise or lower national

emissions slightly, but will not have a

significant effect on the environment.

Rehearing Requests

The Joint Commenters contend that

the analysis of projected benefits from

the Rule appears to be inadequately

substantiated and uses assumptions that

are inconsistent with those used to

reach a finding of no significant impact

on environmental issues. Although Joint

Commenters do not challenge the

conclusion that Order No. 888 will

result in economic benefits, it states that

the benefits identified in the FEIS are

inadequately substantiated and do not

reflect a balanced analysis. It claims that

courts have held that when economic

development is the selling point or

raison d’etre of an action NEPA requires

the agency to provide a specific

comparison of economic benefits versus

environmental costs. It concludes that

the analysis of the economic benefits of

Order No. 888 is tipped in favor of

benefits, especially when contrasted

with the analysis of projected

environmental impacts.

Joint Commenters state that the

conclusion that benefits will range from

$3.76 to $5.37 billion per year is not

properly documented and cannot be

relied upon as justification for

implementing the Rule without

mitigation. It contends that the

Commission is counting benefits from

changes that are unrelated to the Rule,

such as benefits resulting from higher

plant availability factors. Joint

Commenters claim that this assertion

appears to be inconsistent with industry

reactions to competition to date. The

same is true of planning reserve

margins. It states that key assumptions

used to define the operating savings,

particularly fuel price assumptions, are

unreasonable. It adds that these savings

are the ones that give rise to adverse

environmental effects due to increased

utilization of existing low-cost coal

generation. Therefore, it is inappropriate

to count these economic benefits

without examining the offsetting

environmental costs, which increase as

the level of the asserted benefits

increase.

Finally, Joint Commenters assert that

the FEIS does not address potential

costs associated with implementing the

Rule. These include costs to the

Northeast and other regions of

additional environmental compliance

and the impact on public health of

additional pollution; socioeconomic

costs associated with utility downsizing;

potential adverse effects on nuclear

power plant operations from

competition; or potential regulatory

costs associated with compliance with

Order No. 888. Thus, Joint Commenters

conclude that the FEIS does not provide

a basis for calculating the net benefits of

Order No. 888. It also states that the

FEIS does not provide a basis for

concluding that the potential savings

will exceed the additional costs

associated with increased use of coal

generation without mitigation.

Commission Conclusion

The fulcrum of Joint Commenters’

challenge is its claim that when

economic development is the selling

point of a proposed action, NEPA

requires the agency to provide a specific

comparison of economic benefits versus

environmental costs. The Joint

Commenters do not challenge the

conclusion that the Rule will result in

economic benefits. Rather, it claims that

the benefits identified in the FEIS are

not adequately substantiated and do not

reflect a balanced analysis of benefits

versus costs. This argument is made to

further the claim, asserted by Joint

Commenters in various forms, that the

Commission must impose mitigation to

‘‘level’’ the playing field.

The Joint Commenters’ argument

misapprehends the purpose of Order

No. 888, the role a cost-benefit analysis

plays in an EIS, and the reasons for the

Commission’s discussion of the

economic benefits of the Rule.

The purpose of the Rule is not to

foster economic development, although

the Commission anticipates that this

will be a salutary effect of open access.

The purpose of the Rule is to promote

competition in the wholesale bulk

power markets by remedying undue

discrimination in access. The fact that

the Rule will create benefits through

better use of existing assets and

institutions, new market mechanisms,

technical innovation, and less rate

distortion is a consequence rather than

the purpose of the Rule.

The Joint Commenters also mistake

the role a cost-benefit analysis plays in

an EIS. The CEQ regulations

implementing NEPA set forth the

requirements pertaining to a cost-benefit

analysis at 40 CFR 1502.23 (1996):

If a cost-benefit analysis relevant to the

choice among environmentally different

alternatives is being considered for the

proposed action, it shall be incorporated by

reference or appended to the statement as an

aid in evaluating the environmental

consequences. To assess the adequacy of

compliance with section 102(2)(B) of the Act

the statement shall, when a cost-benefit

analysis is prepared, discuss the relationship

between that analysis and any analyses of

unquantified environmental impacts, values,

and amenities. For purposes of complying

with the Act, the weighing of the merits and

drawback of the various alternatives need not

be displayed in a monetary cost-benefit

analysis and should not be when there are

important qualitative considerations. In any

event, an environmental impact statement

should at least indicate those considerations,

including factors not related to

environmental quality, which are likely to be

relevant and important to a decision.

Thus, the function of a cost-benefit

analysis is to assist in the choice among

environmentally different alternatives.

As discussed above, the Commission’s

recitation in the FEIS of the anticipated

economic benefits of the Rule is not

undertaken to assist in the choice

among environmental different

alternatives. The FEIS discusses the

expected economic benefits of the Rule

in a broader context, noting that ‘‘[t]he

most important socioeconomic effect of

the proposed rule is expected to be

potentially large benefits to ratepayers

and to the economy as a whole.’’ 865

The authorities cited by the Joint

Commenters do not alter this

conclusion. The Commission is not

using the benefits of the Rule as a

selling point to go forward with the

action while ignoring disadvantages that

might flow from it. The FEIS fully

examines the impacts of the Rule and

concludes that implementation of the

Rule will not result in adverse

environmental consequences. The Joint

Commenters disagreement is with this

substantive conclusion, not with the

alleged failure to conduct a cost-benefit

analysis. Their disagreement does not

mean, however, that the Commission

has ignored the disadvantages that Joint

Commenters assert would flow from the

Rule. In brief, as discussed throughout

the FEIS, Order No. 888, and this order

on rehearing, the Commission has

examined the impacts of the Rule and
12456 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

866 In point of fact, the overall thrust of the FEIS

is to analyze and discuss the projected costs of the

Rule. The discussion of the projected benefits of the

Rule comprise a tiny fraction of that discussion.

The Joint Commenters dissatisfaction with the

results of the analysis does not mean that the

projected impacts of the Rule were not discussed

in full.

867Public Utilities Commission, 900 F.2d at 282

(brackets, ellipses, and emphasis in original).

868FEIS at 5–64 and 5–75 through 5–76.

869 Id. at 5–75 through 5–76.

concluded that it will not result in

environmental harms.

Thus, even under the broadest

possible interpretation of the costbenefit analysis requirement, the

Commission has evaluated the benefits

of the Rule against its impacts and

concluded that the benefits are likely to

be significant and that the impacts are

likely to be insignificant.866

The D.C. Circuit rejected the

underlying argument advanced here by

the Joint Commenters in Public Utilities

Commission of the State of California v.

FERC, 900 F.2d 269 (D.C. Cir. 1990).

There, California contended that the

Commission did not comply with NEPA

in granting an Optional Expedited

Certificate (OEC) permitting

construction of a natural gas pipeline.

California argued that the Commission

could not have balanced the adverse

environmental effects against the need

for the project because under the OEC

procedures it made no particularized

inquiry into the economic benefits of

the pipeline. The court responded that:

Two of our cases speak of a NEPA

requirement that ‘‘responsible

decisionmakers * * * fully advert[] to the

environmental consequences’’ of a proposed

action and ‘‘decide[] that the public benefits

* * * outweigh[] the[] environmental

costs.’’ Illinois Commerce Comm’n v. ICC,

848 F.2d 1246, 1259 (D.C.Cir.1988); Jones v.

District of Columbia Redevelopment Land

Agency, 499 F.2d 502, 512 (D.C.Cir.1974).

Though the Commission engaged in an

‘‘individualized consideration and balancing

of environmental factors,’’ as required by

Calvert Cliffs’ Coord. Comm. v. United States

Atomic Energy Comm’n, 449 F.2d 1109, 1115

(D.C.Cir.1971), its evaluation of the

nonenvironmental aspects of the pipeline

was not individualized. As to them the

Commission stated that ‘‘the interests of the

public articulated in our adoption of the

optional certificate process [i.e., Order No.

436] outweigh, on balance, the relatively

insubstantial environmental harm which will

result from a properly mitigated WyCal

Pipeline.’’ Mojave Pipeline Co., 46 FERC at

61,168 (emphasis added).

California’s insistence on a particularized

assessment of non-environmental features

finds no support in the statutory language.

See NEPA § 102, 42 U.S.C. § 4332 (requiring

the agency to consider a variety of

environmental, not economic, factors). Its

theory would disable any number of efforts

at streamlining the resolution of regulatory

issues that have nothing to do with the

environment. An agency’s primary duty

under the NEPA is to ‘‘take[] a ’hard look’ at

environmental consequences.’’ Kleppe v.

Sierra Club, 427 U.S. 390, 410 n. 21, 96 S.Ct.

2718, 2730 n. 21, 49 L.Ed.2d 576 (1976). We

will not extend that statute well beyond its

realm so as to create unnecessary conflicts

with others. [867]

Thus, an agency need not conduct a

particularized assessment of the

nonenvironmental features of a

proposal, in particular its economic

benefits or costs. The Commission

nonetheless examined the potential

costs of the Rule and determined that

those costs will be very small and may

be positive instead of negative in any

event. The Commission has also

examined the benefits of the project and

concluded that it will have substantial

benefits. Accordingly, the request for

rehearing is denied.

H. Socioeconomic Impacts

The FEIS examines the socioeconomic

impacts of the Rule, including whether

the Rule will result in regional shifts in

economic activity (especially electric

generation and coal mining).868 The

analysis demonstrates that an effect of a

more competitive industry may be

increased use of existing electric

generating facilities. Consequently, it

seems likely that those who supply fuel

to existing plants could see a higher

demand for their output as a result of

the Rule. The FEIS notes that this might

not be true in all places, however, if

factors such as changes in

environmental standards work in the

opposite direction. The FEIS does not

attempt to measure local or site-specific

impacts given the speculative nature of

such impacts.

The FEIS also notes that open access

could lead to changes in employment

patterns, but concludes that it is highly

uncertain, however, which changes are

likely to result from restructuring.869

The FEIS notes that some changes

should lead to cost reductions that will

tend to increase jobs in other industries,

as well as lower rates for other

consumers. Lower power bills can make

other industries more competitive and

lead them to increase employment.

The FEIS also notes that the Rule is

only part of the restructuring currently

affecting the industry. Employment in

traditional utilities has fallen in recent

years. Developments at the state and

federal levels will increase competition

in the industry even without the Rule.

Given the highly uncertain nature of

future developments in the electric

industry and the complex, dynamic

economic issues involved, the FEIS

concludes that any quantitative estimate

of changes in employment (or even the

direction of change) would be highly

speculative.

Rehearing Requests

The PA Com claims that

socioeconomic impacts that may result

from regional economic shifts occurring

as a result of the Rule are not adequately

discussed in the FEIS. It states that

Order No. 888 contemplates a reduction

in the amount of coal-fired generation,

and that if Pennsylvania generation is

shut-down or dispatched less often in

favor of generation that is not subject to

the same environmental costs and

requirements, less Pennsylvania coal

will be mined.

The PA Com states that Pennsylvania

produces 60 million tons of coal a year,

most of which is purchased by

Pennsylvania electric utilities. It alleges

that the Pennsylvania coal industry

provides 9,200 direct mining jobs and

9,500 support service jobs. Coal sales

contribute $1.5 billion to the

Pennsylvania economy each year and

provide an annual payroll of $600

million. The PA Com adds that if coal

production declines, the state may

curtail efforts to reclaim abandoned

mines and coal refuse piles.

The PA Com also contends that social

obligations now borne by transmission

owning utilities—demand side

management programs, integrated

resource planning, low-income

assistance programs, and federal

environmental mandates—have an

impact upon price and the market for

power, and that utilities might view

these obligations as an impediment to

competition. It claims that third parties

who wish to use the transmission

system may balk if they are required to

contribute to those social goals.

Finally, the PA Com claims that

functional unbundling, open access on

a comparability basis, and increased

competition may impact reliability of

service. It states that it is concerned that

reliability is subordinate to economic

concerns, and that if reliability is not an

articulated foundation of FERC actions,

system reliability may suffer. It

concludes that the FEIS assumes that

reliability will be enhanced by open

access, but that this assumption is not

adequately explained.

Commission Conclusion

The PA Com’s concerns as to the

alleged socioeconomic impacts of the

Rule are based on a series of tenuous

economic ‘‘what-ifs.’’ It assumes that the

Rule will result in a reduction in

Pennsylvania generation. It assumes

from this that less coal will be mined in
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12457

870The CEQ regulations, 40 CFR 1508.14 (1996),

state that ‘‘economic or social effects are not

intended by themselves to require preparation of an

environmental impact statement.’’ See also

Panhandle Producers & Royalty Owners Association

v. Economic Regulatory Administration, 847 F.2d

1168, 1179 (5th Cir. 1988); Olmstead Citizens for a

Better Community v. United States, 793 F.2d 201,

205 (8th Cir. 1986).

871The CEQ regulations, 40 CFR 1508.14 (1996),

provide that ‘‘[w]hen an environmental impact

statement is prepared and economic or social and

natural or physical environmental effects are

interrelated, then the environmental impact

statement will discuss all of these effects on the

human environment.’’ This limitation has been read

very strictly. In Stauber v. Shalala, 895 F.Supp.

1178, 1194 (W.D.Wis.1995), for example, the court

responded to a claim that a proposed action would

cause both environmental and socioeconomic

harms and that for this reason an EIS was necessary.

The court found that:

This assertion is insufficient to satisfy the

‘‘interrelatedness’’ requirement of § 1508.14. I read

40 C.F.R. § 1508.14 to mean that it is only after an

agency determines that the socioeconomic impact

of the proposed agency action is likely to cause

environmental harms itself that the agency needs to

discuss the socioeconomic effects in the

environmental impact statement. See Breckinridge

v. Rumsfield, 537 F.2d 864, 866 (6th Cir.1976)

(accord), cert. denied, 429 U.S. 1061, 97 S.Ct. 785,

50 L.Ed.2d 777 (1977). This reading fully comports

with the plain language of the regulation. * * *

872 It is interesting to note in this regard that

Pennsylvania recently adopted electric

restructuring legislation of its own establishing

retail wheeling. It thus became the fourth state in

the Northeast to do so; the others are Massachusetts,

Rhode Island, and New Hampshire. The legislation

was described by the Governor of Pennsylvania as

creating a ‘‘critical competitive advantage’’ for

Pennsylvania. The Energy Daily, December 4, 1996.

873Metropolitan Edison Co., 460 U.S. at 769.

PANE also asserted that NEPA required

consideration of ‘‘[t]he perception, created by the

accident, that the communities near Three Mile

Island are undesirable locations for business or

industry, or for the establishment of law or medical

practice, or homes compounds the damage to the

viability of the communities.’’ Id. at 770 n.2.

874 Id. at 772–73 (emphasis in original) (footnote

omitted). The continuing validity of the argument

that socioeconomic effects are to be considered in

an EIS if the federal action has a primary impact

on the natural environment is doubtful. The court

in Olmsted Citizens for a Better Community v.

United States, 793 F.2d 201, 206 (8th Cir. 1986)

stated that:

[I]t is unlikely that such a distinction survives the

recent Supreme Court holding in Metropolitan

Edison. That decision, as discussed above, was

based on congressional intent, and there is no

suggestion that Congress contemplated that the

process it designed to make agencies aware of the

consequences of their actions with regard to the

physical environment would be converted into a

process for airing general policy objections anytime

the physical environment was implicated. Such a

rule would divert agency resources away from the

primary statutory goal of protecting the physical

environment and natural resources. * * *

875FERC Stats. & Regs. at 31,895; mimeo at 754.

876 Id. at 31,895–96; mimeo at 755–56 (footnote

omitted).

Pennsylvania and that Pennsylvania

will suffer adverse economic

consequences. It then assumes that this

might lead Pennsylvania to curtail

efforts to reclaim abandoned surface and

strip mines. No basis has been shown to

support the elements in this chain of

assumptions. The effects Pennsylvania

fears are simply too speculative to

assess at this time.

Moreover, the PA Com’s concerns

stem from the postulated economic

impacts of the Rule rather than from the

alleged impact of the Rule on the

physical environment. Thus, its

concerns are not proper for

consideration in an EIS. The CEQ states

that socioeconomic impacts alone do

not warrant study in an EIS.870 The CEQ

also states that an agency must make

reasonable efforts in preparing an EIS to

acquire relevant information concerning

socioeconomic impacts when economic

or social and natural or physical

environmental effects are interrelated.871

If such effects are not interrelated, they

need not be considered. In this case, the

PA Com’s concerns stem from what it

anticipates will be the economic impact

of the Rule on Pennsylvania, and not

from the natural or physical

environmental impacts of the Rule.

Thus, these concerns are not proper for

consideration in an EIS.872

The approach to such issues is

perhaps best symbolized by the

Supreme Court’s decision in

Metropolitan Edison Co. v. People

Against Nuclear Energy, 460 U.S. 766

(1983). In that case, People Against

Nuclear Energy (PANE) contended that

NEPA required the Nuclear Regulatory

Commission to consider whether

restarting the Three Mile Island-1

nuclear reactor after the accident at the

Three Mile Island-2 reactor would

‘‘cause both severe psychological health

damage to persons living in the vicinity,

and serious damage to the stability,

cohesiveness, and well-being of the

neighboring communities.’’ 873 The court

rejected this argument:

The theme of § 102 is sounded by the

adjective ‘‘environmental’’: NEPA does not

require the agency to assess every impact or

effect of its proposed action, but only the

impact or effect on the environment. If we

were to seize the word ‘‘environmental’’ out

of its context and give it the broadest possible

definition, the words ‘‘adverse environmental

effects’’ might embrace virtually any

consequence of a governmental action that

someone thought ‘‘adverse.’’ But we think the

context of the statute shows that Congress

was talking about the physical

environment—the world around us, so to

speak. NEPA was designed to promote

human welfare by alerting governmental

actors to the effect of their proposed actions

on the physical environment.

* * * Thus, although NEPA states its goals

in sweeping terms of human health and

welfare, those goals are ends that Congress

has chosen to pursue by means of protecting

the physical environment. [874]

Even though it was not incumbent

upon it to do so, the Commission

analyzed the concerns raised by the PA

Com to the extent it was practicable to

do so. The impacts of the Rule on future

levels of coal-fired generation in

Pennsylvania or on employment in a

specific geographic area or in a specific

economic sector are influenced by a

virtually unlimited roster of other

factors, and thus are too speculative to

be useful.

I. Coastal Zone Management Act

Order No. 888 found that the Rule

does not constitute a federal activity

subject to compliance with the Coastal

Zone Management Act, 16 U.S.C. § 1451

et seq. (CZMA). 875 Order No. 888

concluded that:

Connecticut has in any event waived its

right to request a consistency determination

for the Commission’s rulemaking.

Connecticut’s coastal management program’s

list of federal agency activities likely to

require a consistency determination does not

(for good reason) describe rulemakings of this

kind, and the rule will not ‘‘result in a

significant change in air or water quality

within the management area’’ (the program’s

catch-all category). In addition, Connecticut

did not notify the Commission of its

conclusion that the Rule requires a

consistency determination until well after 45

days from receipt of several notices of the

rulemaking proceeding. Consequently,

pursuant to 15 CFR 930.35(b), Connecticut

has in any event waived its right to request

a consistency determination for this

rulemaking. [ 876]

Rehearing Requests

The Connecticut Department of

Environmental Protection (Connecticut

DEP) requests that the Commission

determine whether Order No. 888 is a

federal activity requiring a coastal

consistency determination, determine

whether the Rule is consistent with

Connecticut’s coastal management plan

(CMP), and consider the impacts that

promoting competition and altering

transmission and generation patterns

may have on water quality in the Long

Island Sound. The Connecticut DEP also

requests that the Commission mitigate

potential increases in nitrogen and

sulphur oxide emissions occurring as a

result of the Rule.

Commission Conclusion

On August 20, 1996, the Commission

responded to the Connecticut DEP,

issuing a consistency determination and

a negative determination. The response

notes that the FEIS focuses on the

concerns raised by the Connecticut DEP

and concludes that the most important

factor determining changes in future

emissions is the relative competitive
12458 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

877 In issuing a negative determination, the

Commission noted that it questioned whether the

CZMA applies to economic regulatory activities

involving interstate electric rates and service. The

Commission also noted that Connecticut had

waived its right to request a consistency

determination or negative determination by failing

to notify the Commission of its request within 45

days from receipt of the notice of the federal

activity. The Commission concluded that it did not

waive those arguments by providing Connecticut

with a consistency determination and negative

determination.

878 5 U.S.C. § 601–612.

879Open Access Rule, 61 FR 21540 at 21691 (May

10, 1996), FERC Stats. & Regs. ¶ 31,036 at 31,898

(1996).

880The SBA filed its Request for Rehearing on

June 10, 1996, after the statutory deadline for the

filing of such a pleading. Accordingly, we will not

accept its pleading as a request for rehearing but

will, instead, treat it as a motion for

reconsideration.

On November 1, 1996, NRECA filed a supplement

to its Requests for Rehearing and Clarifications. We

will reject the supplement to the request for

rehearing as barred by the 30 day time limit for

filing petitions for reconsideration. Neither the

Commission nor the courts can waive a failure to

comply with the statute. See Platte River Whooping

Crane Critical Habitat Maintenance Trust v. FERC,

876 F.2d 109, 113 (D.C. Cir. 1989); Tennessee Gas

Pipeline Company v. FERC, 871 F. 2d 1099, 1107

(D.C. Cir. 1989); Boston Gas Company v. FERC, 575

F.2d 975 (1st Cir. 1978). Accord Commonwealth

Electric Company v. Boston Edison Company, 46

FERC ¶ 61,253 at 61,757, reh’g denied, 47 FERC

¶ 61,118 (1989). We will accept NRECA’s

supplemental request for clarifications.

881NRECA at 42–43.

882NRECA at 44.

883Capacity Reservation Open Access

Transmission Tariffs, Notice of Proposed

Rulemaking, IV FERC Stats. & Regs Proposed

Regulations ¶ 32,519 (1996), 61 FR 21847 (May 10,

1996) (Capacity Reservation).

884We will discuss NRECA’s arguments

concerning the OASIS Final Rule in our order on

rehearing in that proceeding. We reject NRECA’s

reference to the Capacity Tariff Reservation NOPR

as inapposite to this proceeding. We have invited

comments on the proposed Capacity Reservation

Open Access Transmission Tariffs (Capacity

Reservation, IV FERC Stats. & Regs. Proposed

Regulations at 33,235, 61 FR 21847 at 21853) and

will discuss those comments in the appropriate

proceeding.

885SBA Request for Reconsideration at 5. The

SBA defines a small public electric utility as one

that disposes of 4 Million MWh per year. 13 CFR

121.201.

886 773 F.2d 327 (D.C. Cir. 1985) (Mid-Tex).

position (e.g., price) of coal and natural

gas. Depending on the relative prices of

these fuels, emissions from electric

generating facilities may increase

slightly or decrease slightly. Regional

effects, including those for the region

encompassing Connecticut, are

projected to be similar. The response

also notes that these estimates fall

within the ‘‘noise’’ level of the model.

That is, they are smaller than the

uncertainties in the science underlying

the model.

Thus, the response concludes that the

Rule will not have an effect on the land

and water uses or natural resources of

Connecticut. Accordingly, the

Commission issued a negative

determination pursuant to the

regulations implementing the CZMA, 15

CFR 930.35(d). 877

The response also notes that even if

the Rule were to have a minimal effect

on Connecticut’s coastal zone, the Rule

is consistent to the maximum extent

practicable with the enforceable policies

of the Connecticut Coastal Management

Plan (Connecticut Plan). The

Connecticut Coastal Management Act

and supporting policies which provide

the basis for the Connecticut Plan

require that activities be consistent with

the Clean Air Act. The Connecticut Plan

provides that activities are not assumed

to directly affect Connecticut, and thus

do not require a consistency

determination, unless they ‘‘would

result in a significant change in air or

water quality.’’

The August 20, 1996 response

concludes that the Rule is consistent

with the requirements of the Clean Air

Act and will not result in a significant

change in air or water quality in

Connecticut. In fact, depending on the

future prices of fuel, the Rule is equally

likely to improve air quality over

Connecticut and decrease emissions

deposition in the waters of the Long

Island Sound. Thus, the Rule is

consistent with the Connecticut Plan

regardless of any slight effects it may

have.

Finally, the response notes that the

action sought by Connecticut DEP to

ensure consistency with the Connecticut

Plan has already been taken in any

event. Following issuance of the Rule,

EPA, the federal agency charged with

implementing the Clean Air Act, stated

that it would use its authority to

comprehensively address NOX

emissions, including any potential

incremental increases in emissions that

might result from implementation of the

Rule, in the 37-state region that makes

up the Ozone Transport Assessment

Group. This region includes

Connecticut. In an Order issued May 29,

1996, the Commission agreed to

examine the issue of mitigation of the

impacts, if any, of the Rule in the event

that EPA and the OTAG states are

unsuccessful in addressing the NOX

problem.

Thus, the FEIS demonstrates that the

Rule will not have an effect on any land

or water use or natural resource of

Connecticut’s coastal zone. Moreover,

the Rule is consistent with

Connecticut’s CMP. Finally, EPA and

the Commission have taken the action

sought by Connecticut DEP to ensure

consistency with Connecticut’s CMP.

These actions fully address Connecticut

DEP’s coastal zone concerns.

VI. Regulatory Flexibility Act

Certification

The Regulatory Flexibility Act

(RFA) 878 requires rulemakings to either

contain a description and analysis of the

effect that the proposed or final rule will

have on small entities or to contain a

certification that the rule will not have

a significant economic impact on a

substantial number of small entities. In

the Open Access and Stranded Cost

Final Rules, the Commission certified

that the final rules would not impose a

significant economic impact on a

substantial number of small entities.879

NRECA and SBA question this

certification.880 According to NRECA

there are about 1,000 rural electric

cooperatives and 2,000 municipal

electric systems, most of which meet the

RFA definition of small electric entity.

NRECA states that the Commission has

imposed open access, OASIS and code

of conduct requirements on non-public

utilities. NRECA maintains that if nonpublic utilities do not meet these

requirements, ‘‘they will not retain

access over the long-term to the nation’s

bulk power transmission grid—access

they must have if they wish to stay in

business.’’ 881

NRECA also contends that the

stranded cost issue will affect small

non-public utilities ‘‘any time a nonpublic utility is required to render

reciprocal transmission service, and

loses a customer as a result of rendering

that service, or a TDU [transmission

dependent utility] loses a customer to

an open access public utility

transmission provider.’’ 882 NRECA

asserts that both the OASIS Final Rule

and the Capacity Reservation Tariff

NOPR883 will substantially burden

small non-public utilities.884 NRECA

further maintains that the Commission’s

waiver provisions will not alleviate the

burden on small utilities. It states that

filing a waiver request with the

Commission is burdensome for small

utilities.

SBA states that 30 percent (50 of 166)

of public utilities are small under the

SBA’s definition of a small public

electric utility.885 SBA contends that if,

as the Commission has found, 11

percent of public utilities are small, the

Final Rules will still affect a significant

number of small public utilities.

SBA challenges the Commission’s

reliance on Mid-Tex Electric

Cooperative, Inc. v. FERC.886 It contends

that the Commission should have

analyzed the probable effect of the Final

Rules on small businesses by projecting,

perhaps on the model of the deregulated
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12459

887FERC Stats. & Regs. at 31,897 (1996)(footnotes

omitted); mimeo at 758–59.

888 Id. at n.1078.

889 Id. at n.1081.

890 Mid-Tex, 773 F. 2d at 340–43.

891 Id.

892The Commission’s waiver policy follows the

SBA definition of small electric utility. See 5 U.S.C.

§ 601(3) and 601(6) and 15 U.S.C. § 632(a). The RFA

defines a small entity as one that is independently

owned and not dominant in its field of operation.

See 15 U.S.C. § 632(a). The SBA defines a small

electric utility as one that disposes of 4 million

MWh or less of electric energy in a given year. See

13 CFR 121.601 (Major Group 49–Electric, Gas and

Sanitary Services) (1995).

893Northern States Power Company, 76 FERC

¶ 61,250 (1996); Central Electric Cooperative, et al.,

77 FERC ¶ 61,076 (1996); Black Creek Hydro, et al.,

77 FERC 61,232 (1996); Dakota Electric Association,

et al., 78 FERC ¶ 61,117 (1997); Soyland Power

Cooperative, Inc., et al., 78 FERC ¶ 61,095 (1997);

Niobrara Valley Electric Membership Cooperation,

Docket Nos. OA96–146–001 and ER97–1412–000,

Letter Order issued February 26, 1997.

894These total more that the 19 small public

utilities we referenced in Order No. 888 because,

since the issuance of that order, several entities

have repaid their RUS-financed debt and become

public utilities subject to our jurisdiction and

several new public utilities have been created as the

result of the construction of new facilities.

895See United Distribution Companies v. FERC,

88 F.3d 1105, 1170 (July 16, 1996) (‘‘FERC had no

obligation to conduct a small entity impact analysis

of effects on entities which it does not regulate.’’).

telecommunications industry, how

many small electric utilities, as the SBA

defines that term, would enter the

deregulated electric utility market.

Commission Conclusion

A. Docket No. RM95–8–000 (Open

Access Final Rule)

1. Public Utilities

In the Open Access Final Rule we

determined that the Rule applies:

to public utilities that own, control or operate

interstate transmission facilities, not to

electric utilities per se. The total number of

public utilities that, absent waiver, would

have to have open access tariffs on file is 166.

Of these, only 50 public utilities dispose of

4 million MWh or less per year. Eliminating

those utilities that are affiliates of other

utilities whose sales exceed 4 million MWh

or less per year, or are not independently

owned, the total number of public utilities

affected by the Open Access Final Rule that

qualify under the SBA’s definition of small

electric utility is 19 or 11 percent of the total

number of public utilities that would have to

have on file open access tariffs.887

We do not agree with the SBA that 11

percent of all of the public utilities that

would have to file open access tariffs

with us is a significant number. Also,

the SBA has overlooked several of the

other findings we made as to the

possible effect of the Open Access Final

Rule on small public utilities. As we

noted, of the 19 public utilities that

would come within the SBA’s definition

of small electric utility, five have

already filed open access tariffs with the

Commission, so that the effect of the

Open Access Rule on these utilities

should not be significant.888

Further, the Commission is specifying

the non-rate terms and conditions of the

tariffs that public utilities must file, so

all public utilities need to do is file a

rate, and the small public utilities with

open access tariffs already on file with

us need not even do that. They may

elect to continue service under the Open

Access Final Rule’s non-rate terms and

conditions at their existing rates. In our

Final Rule we estimated that the cost for

filing a rate would not, on average,

exceed one half of one percent of total

annual sales for small electric

utilities,889 which is not a significant

economic impact.

We disagree with SBA that our

reliance on Mid-Tex is misplaced. In

Mid-Tex, the court accepted the

Commission’s conclusion that virtually

all of the public utilities that the

Commission regulates do not fall within

the RFA’s meaning of the term ‘‘small

entities.’’ Mid-Tex involved a rule that

applies to all public utilities. The Open

Access Final Rule applies to only those

public utilities that own, control or

operate interstate transmission facilities,

which are a subset of the group of

public utilities for which Mid-Tex did

not require the preparation of a

regulatory flexibility analysis.890

SBA attempts to distinguish Mid-Tex

by postulating that the Commission

should have attempted to predict how

many new entrants into a deregulated

market would be small electric utilities,

within the SBA’s meaning of that term.

Mid-Tex held just the opposite, deciding

squarely that an agency need only

consider the businesses that a regulation

directly affects.891 There is no precedent

for SBA’s suggestion that the

Commission must engage in a

hypothetical projection of how many

entrants likely to enter a deregulated

market may be small electric utilities,

and we know of no satisfactory way of

making such a projection. Entry into the

telecommunications industry, which the

SBA offers as a model, involves very

different costs, distribution and

marketing patterns and entirely different

technology. There is no way, from

looking at what has happened in the

telecommunications industry, that the

Commission could project, with any

degree of accuracy, how many small

electric utilities, if any, will enter the

market following the effective date of

the Final Open Access Rule.

Finally, SBA overlooks, and NRECA

unreasonably discounts, the effect that

the Commission’s waiver rules have on

relieving the burden of the Open Access

Final Rule on small entities.892 The

Commission has recently issued a

number of orders waiving the

requirements of the Open Access Final

Rule for a number of small electric

utilities.893 As these cases show, the

Commission is carefully evaluating the

effect of the Open Access Final Rule on

small electric utilities and is granting

waivers where appropriate, thus

mitigating the economic effect of that

rule on small entities. Indeed, as we

noted in Order No. 888, 5 small public

utilities previously had filed open

access tariffs, and we have since, in the

cases cited above, granted waivers to

approximately 17 small public

utilities.894

2. Non-Public Utilities

We disagree with NRECA’s argument

that Order No. 888 imposes burdens

upon non-public utilities. As we noted

in the Final Rule, we do not have

jurisdiction to regulate non-public

utilities’ rates, terms and conditions of

transmission service under sections 205

and 206 of the FPA, and there is no

requirement in Order No. 888 that nonpublic utilities file open access tariffs.895

In addition, under the waiver

provisions of the Open Access Final

Rule, small non-public utilities may

seek waiver from the reciprocity

provision. As reflected in the cases cited

above, the Commission has granted

waivers of the reciprocity provision to

10 small non-public electric utilities

and issued disclaimers of jurisdiction

with respect to 19 small electric

utilities, thus mitigating the effect of the

Open Access Final Rule on small nonpublic electric utilities.

B. Docket No. RM94–7–000 (Stranded

Cost Final Rule)

1. Public Utilities

No rehearing requests addressed this

matter.

2. Non-Public Utilities

In Order No. 888, the Commission

indicated that the Stranded Cost Final

Rule will not impose a significant

economic impact on a substantial

number of non-public utility small

entities because the stranded cost issue

would only arise in a proceeding under

sections 211 and 212 of the FPA when,

in directing transmission, the

Commission addresses the stranded cost

issue in determining a just and

reasonable rate. NRECA counters that

the stranded cost issue will ‘‘arise: any

time a non-public utility is required to
12460 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

896NRECA at 44.

897Stranded costs could also conceivably arise as

a result of an ordered interconnection under section

210. However, the rates for such an interconnection

would be established pursuant to section 212 and

could therefore also include stranded costs.

898Although the Commission would not

determine the rate, including the stranded cost

component of the rate, of a non-public utility, we

would review a public utility’s claim that it is

entitled to deny service to a non-public utility

because the stranded cost component of the nonpublic utility’s transmission rate is being applied in

a way that violates the principle of comparability.

899One need not respond to a collection of

information unless it displays a valid OMB control

number. The OMB control number for this

collection of information is 1902–0096.

render reciprocal transmission service,

and loses a customer as a result of

rendering that service, or a TDU loses a

customer to an open access public

utility transmission provider.’’ 896

NRECA submits that the adverse

economic impact on small non-public

utilities will ‘‘arise’’ from the stranding

of costs, not from the utilities’

participation in proceedings at the

Commission, and that the Commission

‘‘cannot in good conscience fail at least

to probe the potential adverse economic

impact on small non-public utilities of

the stranded costs they incur as a direct

result of Order No. 888.’’

Notwithstanding NRECA’s argument

that small non-public utilities may

experience stranded costs outside of a

section 211/212 proceeding, as we

explain in Section IV.J.1, supra, our

jurisdiction over the recovery of

stranded costs by non-public utilities,

and thus our ability to permit an

opportunity for recovery of such costs,

is limited by statute. With the exception

of our section 210 interconnection and

sections 211–212 transmission rate

jurisdiction, we do not have jurisdiction

over the rates of non-public utilities.

Because the stranded cost issue would

primarily arise as to non-public utilities

over which the Commission has

jurisdiction in a proceeding under

sections 211 and 212 of the FPA when,

in directing transmission, the

Commission addresses the stranded cost

issue in determining a just and

reasonable rate,897 we concluded that

the Stranded Cost Final Rule will not

impose a significant economic impact

on a substantial number of non-public

utility small entities.

Because the Commission does not

have rate jurisdiction over non-public

utilities other than through sections 210,

211 and 212, the Commission does not

have the authority to allow them to

recover stranded costs other than

through rates set under section 212.

However, we clarify that nothing in the

Final Rule was intended to preclude

non-public utilities from including

stranded cost provisions in voluntary

reciprocity tariffs or from otherwise

recovering stranded costs under

applicable law. Thus, a non-public

utility that chooses voluntarily to offer

an open access tariff for purposes of

demonstrating that it meets the

reciprocity provision can include a

stranded cost provision in its tariff.

However, adjudication of any stranded

cost claims under that tariff is not

subject to the Commission’s

jurisdiction.898 If a non-public utility

wishes to recover stranded costs

pursuant to a tariff or otherwise, it can

seek to do so subject to the review of the

appropriate regulatory or judicial

authority.

VII. Information Collection Statement

Order No. 888 contained an

information collection statement for

which the Commission obtained

approval from the Office of Management

and Budget (OMB).899 Given that this

order on rehearing makes only minor

revisions to Order No. 888, none of

which is substantive, OMB approval for

this order will not be necessary.

However, the Commission will send a

copy of this order to OMB, for

informational purposes only.

The information reporting

requirements under this order are

virtually unchanged from those

contained in Order No. 888. Interested

persons may obtain information on the

reporting requirements by contacting

the Federal Energy Regulatory

Commission, 888 First Street, N.E.,

Washington, D.C. 20426 [Attention

Michael Miller, Information Services

Division, (202) 208–1415], and the

Office of Management and Budget

[Attention: Desk Officer for the Federal

Energy Regulatory Commission (202)

395–3087].

VIII. Effective Date

Changes to Order No. 888 made in

this order on rehearing will become

effective on May 13, 1997.

List of Subjects 18 CFR Part 35

Electric power rates, Electric utilities,

Reporting and recordkeeping

requirements.

By the Commission. Commissioners

Hoecker and Massey dissented in part with

separate statements attached.

Lois D. Cashell,

Secretary.

In consideration of the foregoing, the

Commission amends 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

§ 35.26 to read as follows:

§ 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 that

subsequently becomes, either directly or

through another wholesale transmission

purchaser, 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

means the transmission of electric

energy sold, or to be sold, at wholesale

in interstate commerce or ordered

pursuant to section 211 of the Federal

Power Act (FPA).

(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 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.

(6) Retail transmission services means

the transmission of electric energy sold,

or to be sold, in interstate commerce

directly to a retail customer.

(7) New wholesale requirements

contract means any wholesale

requirements contract executed after

July 11, 1994, or extended or

renegotiated to be effective after July 11,

1994.

(8) Existing wholesale requirements

contract means any wholesale
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12461

requirements contract executed on or

before July 11, 1994.

(c) Recovery of wholesale stranded

costs.—(1) General requirement. A

public utility or transmitting utility will

be allowed to seek recovery of

wholesale stranded costs only as

follows:

(i) No public utility or transmitting

utility may seek recovery of wholesale

stranded costs if such recovery is

explicitly prohibited by a contract or

settlement agreement, or by any power

sales or transmission rate schedule or

tariff.

(ii) No public utility or transmitting

utility may seek recovery of stranded

costs associated with a new wholesale

requirements contract if such contract

does not contain an exit fee or other

explicit stranded cost provision.

(iii) If wholesale stranded costs are

associated with a new wholesale

requirements contract containing an exit

fee or other explicit stranded cost

provision, and the seller under the

contract is a public utility, the public

utility may seek recovery of such costs,

in accordance with the contract, through

rates for electric energy under sections

205–206 of the FPA. The public utility

may not seek recovery of such costs

through any transmission rate for FPA

section 205 or 211 transmission

services.

(iv) If wholesale stranded costs are

associated with a new wholesale

requirements contract, and the seller

under the contract is a transmitting

utility but not also a public utility, the

transmitting utility may not seek an

order from the Commission allowing

recovery of such costs.

(v) If wholesale stranded costs are

associated with an existing wholesale

requirements contract, if the seller

under such contract is a public utility,

and if the contract does not contain an

exit fee or other explicit stranded cost

provision, the public utility may seek

recovery of stranded costs only as

follows:

(A) If either party to the contract seeks

a stranded cost amendment pursuant to

a section 205 or section 206 filing under

the FPA made prior to the expiration of

the contract, and the Commission

accepts or approves an amendment

permitting recovery of stranded costs,

the public utility may seek recovery of

such costs through FPA section 205–206

rates for electric energy.

(B) If the contract is not amended to

permit recovery of stranded costs as

described in paragraph (c)(1)(v)(A) of

this section, the public utility may file

a proposal, prior to the expiration of the

contract, to recover stranded costs

through FPA section 205–206 or section

211–212 rates for wholesale

transmission services to the customer.

(vi) If wholesale stranded costs are

associated with an existing wholesale

requirements contract, if the seller

under such contract is a transmitting

utility but not also a public utility, and

if the contract does not contain an exit

fee or other explicit stranded cost

provision, the transmitting utility may

seek recovery of stranded costs through

FPA section 211–212 transmission rates.

(vii) If a retail customer becomes a

legitimate wholesale transmission

customer of a public utility or

transmitting utility, e.g., through

municipalization, and costs are stranded

as a result of the retail-turned-wholesale

customer’s access to wholesale

transmission, the utility may seek

recovery of such costs through FPA

section 205–206 or section 211–212

rates for wholesale transmission

services to that customer.

(2) Evidentiary demonstration for

wholesale stranded cost recovery. A

public utility or transmitting utility

seeking to recover wholesale stranded

costs in accordance with paragraphs

(c)(1) (v) through (vii) of this section

must demonstrate that:

(i) It incurred costs to provide service

to a 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 the utility; and

(iii) The stranded costs are derived

using the following formula: Stranded

Cost Obligation = (Revenue Stream

Estimate—Competitive Market Value

Estimate) × Length of Obligation

(reasonable expectation period).

(3) Rebuttable presumption. If a

public utility or transmitting utility

seeks recovery of wholesale stranded

costs associated with an existing

wholesale requirements contract, as

permitted in paragraph (c)(1) of this

section, and the existing wholesale

requirements contract contains a notice

provision, there will be a rebuttable

presumption that the utility had no

reasonable expectation of continuing to

serve the customer beyond the term of

the notice provision.

(4) Procedure for customer to obtain

stranded cost estimate. A customer

under an existing wholesale

requirements contract with a public

utility seller may obtain from the seller

an estimate of the customer’s stranded

cost obligation if it were to leave the

public utility’s generation supply

system by filing with the public utility

a request for an estimate at any time

prior to the termination date specified

in its contract.

(i) The public utility must provide a

response within 30 days of receiving the

request. The response must include:

(A) An estimate of the customer’s

stranded cost obligation based on the

formula in paragraph (c)(2)(iii) of this

section;

(B) Supporting detail indicating how

each element in the formula was

derived;

(C) A detailed rationale justifying the

basis for the utility’s reasonable

expectation of continuing to serve the

customer beyond the termination date

in the contract;

(D) An estimate of the amount of

released capacity and associated energy

that would result from the customer’s

departure; and

(E) The utility’s proposal for any

contract amendment needed to

implement the customer’s payment of

stranded costs.

(ii) If the customer disagrees with the

utility’s response, it must respond to the

utility within 30 days explaining why it

disagrees. If the parties cannot work out

a mutually agreeable resolution, they

may exercise their rights to Commission

resolution under the FPA.

(5) A customer must be given the

option to market or broker a portion or

all of the capacity and energy associated

with any stranded costs claimed by the

public utility.

(i) To exercise the option, the

customer must so notify the utility in

writing no later than 30 days after the

public utility files its estimate of

stranded costs for the customer with the

Commission.

(A) Before marketing or brokering can

begin, the utility and customer must

execute an agreement identifying, at a

minimum, the amount and the price of

capacity and associated energy the

customer is entitled to schedule, and the

duration of the customer’s marketing or

brokering of such capacity and energy.

(ii) If agreement over marketing or

brokering cannot be reached, and the

parties seek Commission resolution of

disputed issues, upon issuance of a

Commission order resolving the

disputed issues, the customer may

reevaluate its decision in paragraph

(c)(5)(i) of this section to exercise the

marketing or brokering option. The

customer must notify the utility in

writing within 30 days of issuance of

the Commission’s order resolving the

disputed issues whether the customer

will market or broker a portion or all of
12462 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

the capacity and energy associated with

stranded costs allowed by the

Commission.

(iii) If a customer undertakes the

brokering option, and the customer’s

brokering efforts fail to produce a buyer

within 60 days of the date of the

brokering agreement entered into

between the customer and the utility,

the customer shall relinquish all rights

to broker the released capacity and

associated energy and will pay stranded

costs as determined by the formula in

paragraph (c)(2)(iii) of this section.

(d) Recovery of retail stranded costs—

(1) General requirement. A public utility

may seek to recover retail stranded costs

through rates for retail transmission

services only if the state regulatory

authority does not have authority under

state law to address stranded costs at the

time the retail wheeling is required.

(2) Evidentiary demonstration

necessary for retail stranded cost

recovery. A public utility seeking to

recover retail stranded costs in

accordance with paragraph (d)(1) of this

section must demonstrate that:

(i) It incurred costs to provide service

to a retail customer that obtains retail

wheeling based on a reasonable

expectation that the utility would

continue to serve the customer; and

(ii) The stranded costs are not more

than the customer would have

contributed to the utility had the

customer remained a retail customer of

the utility.

Note: Appendices A and B and statements

of Commissioners Hoecker and Massey will

not be published in the Code of Federal

Regulations.

Appendix A—List of Petitioners

Docket Nos. RM95–8–001 and RM94–7–002

Abbreviation Petitioner

1. AEC & SMEPA ........................... Alabama Electric Cooperative, Inc. and South Mississippi Electric Power Association.

2. AEP ............................................. Operating Companies of the American Electric Power System.

3. AL Com ....................................... Alabama Public Service Commission.

4. Allegheny .................................... Allegheny Power Service Corporation.

5. AL Municipal ............................... Alabama Municipal Electric Authority.

6. American Forest & Paper ........... American Forest & Paper Association.

7. AMP-Ohio .................................... American Municipal Power-Ohio, Inc. and Indiana Municipal Power Agency.

8. Anaheim ...................................... Cities of Anaheim, Azusa, Banning, Colton and Riverside, California.

9. APPA ........................................... American Public Power Association.

10. AR Com .................................... Arkansas Public Service Commission.

11. Arkansas Cities ......................... Arkansas Cities and Farmers Electric Cooperative.

12. Associated EC .......................... Associated Electric Cooperative, Inc.

13. Atlantic City ............................... Atlantic City Electric Company.

14. Basin EC ................................... Basin Electric Power Cooperative.

15. Blue Ridge ................................ Blue Ridge Power Agency, Northeast Texas Electric Cooperative, Inc., Sam Rayburn G&T Electric Cooperative, Inc., and Tex-La Electric Cooperative of Texas, Inc.

16. BPA ........................................... Bonneville Power Administration.

17. Cajun ......................................... Ralph R. Mabey, Chapter II Trustee for Cajun Electric Power Cooperative, Inc.

18. California DWR ......................... California Department of Water Resources.

19. Carolina P&L ............................. Carolina Power & Light Company.

20. CCEM ........................................ Coalition for a Competitive Electric Market (consisting of Coastal Electric Services Company, Destec

Power Services, Inc., Electric Clearinghouse, Inc., Enron Power Marketing, Inc., Equitable Power Services Company, KCS Power Marketing, Inc., MidCon Power Services Corp. and Vitol Gas & Electric

Services, Inc).

21. Centerior ................................... Centerior Energy Corporation.

22. Central Illinois Light .................. Central Illinois Light Company.

23. Central Minnesota Municipal .... Central Minnesota Municipal Power Agency.

24. Central Montana EC ................. Central Montana Electric Power Cooperative, Inc.

25. Cleveland .................................. Cleveland Public Power.

26. CO Consumers Counsel ........... Colorado Office of Consumer Counsel.

27. Coalition for Economic Competition.Coalition for Economic Competition Consisting of Consolidated Edison Company of New York, Inc., General Public Utilities Corporation, Illinois Power Company, Long Island Lighting Company, New York State

Electric & Gas Corporation, Niagara Mohawk Power Corporation, Northeast Utilities, and Rochester Gas

and Electric Corporation.

28. ConEd ....................................... Consolidated Edison Company of New York, Inc.

29. Connecticut DEP ....................... State of Connecticut Department of Environmental Protection.

30. Consumers Power .................... Consumers Power Company.

31. Cooperative Power ................... Cooperative Power.

32. CSW Operating Companies ..... Central Power and Light, West Texas Utilities Company, Public Service Company of Oklahoma and Southwestern Electric Power Company.

33. CVPSC ...................................... Central Vermont Public Service Corporation.

34. Dairyland ................................... Dairyland Power Cooperative.

35. Dalton ........................................ City of Dalton, Georgia.

36. Detroit Edison ........................... Detroit Edison Company.

37. Dispute Resolution .................... Communications and Energy Dispute Resolution Associates.

38. Duquesne .................................. Duquesne Light Company.

39. EEI ............................................ Edison Electric Institute.

40. EGA ........................................... Electric Generation Association.

41. El Paso ...................................... El Paso Electric Company.

42. ELCON ...................................... Electricity Consumers Resource Council, American Iron and Steel Institute, Chemical Manufacturers Association and Council of Industrial Boiler Owners.

43. Entergy ...................................... Entergy Services, Inc.

44. EPRI .......................................... Electric Power Research Institute.

45. FL Com ..................................... Florida Public Service Commission.

46. Florida Power Corp ................... Florida Power Corporation.

47. FMPA ........................................ Florida Municipal Power Agency.
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12463

Abbreviation Petitioner

48. FPL ............................................ Florida Power & Light Company.

49. Freedom Energy Co ................. Freedom Energy Corporation, LLC.

50. Hoosier EC ................................ Hoosier Energy Rural Electric Cooperative.

51. IA Com ...................................... Iowa Utilities Board.

52. IL Com ...................................... Illinois Commerce Commission.

53. IL Industrials .............................. Illinois Industrial Energy Consumers.

54. Illinois Power ............................. Illinois Power Company.

55. IMPA ......................................... Indiana Municipal Power Agency.

56. IN Com ...................................... Indiana Utility Regulatory Commission.

57. IN Consumer ............................. Indiana Office of Utility Consumer Counselor.

58. Indianapolis POL ....................... Indianapolis Power & Light Company.

59. IN Industrials ............................. Citizens Action Coalition of Indiana, Inc., Indiana Industrial Energy Consumers, Inc. and Indianapolis

Power & Light Company.

60. Joint Commenters ..................... Joint Commenters Supporting Clear Air and Fair Corporation.

61. KCPL ......................................... Kansas City Power & Light Company.

62. LEPA ......................................... Louisiana Energy and Power Authority.

63. Local Furnishing Utilities ........... Local Furnishing Utilities (Long Island Lighting Company, Nevada Power Company, San Diego Gas &

Electric Company and Tuscon Electric Power Company).

64. MA Municipals ........................... Twenty Four Massachusetts Municipals.

65. Maine Public Service ................ Maine Public Service Company.

66. MI Com ..................................... Michigan Public Service Commission and New Hampshire Public Utilities Commission.

67. Michigan Systems ..................... Michigan Public Power Agency, Michigan South Central Power Agency, and Wolverine Power Supply Cooperative, Inc.

68. Minnesota P&L .......................... Minnesota Power & Light Company.

69. MN DPS .................................... Minnesota Department of Public Service and Minnesota Public Utilities Commission.

70. MO/KS Coms ............................ Missouri Public Service Commission and Kansas Corporation Commission.

71. Montana Power ......................... Montana Power Company.

72. Montana-Dakota Utilities ........... Montana-Dakota Utilities Company.

73. Multiple Intervenors ................... Multiple Intervenors.

74. NARUC ..................................... National Association of Regulatory Utility Commissioners.

75. NASUCA ................................... National Association of State Utility Consumer Advocates.

76. NCMPA ..................................... North Carolina Municipal Power Agency Number 1.

77. NE Public Power District ........... Nebraska Public Power District.

78. NIMO ......................................... Niagara Mohawk Power Corporation.

79. NJ BPU ..................................... New Jersey Board of Public Utilities.

80. North Jersey .............................. North Jersey Energy Associates.

81. NRECA ...................................... National Rural Electric Cooperative Association.

82. NU ............................................. Northeast Utilities Service Company.

83. Nuclear Energy Institute ........... Nuclear Energy Institute.

84. Nucor ......................................... Nucor Corporation.

85. NWRTA ..................................... Northwest Regional Transmission Association.

86. NY AG ....................................... New York State Attorney General.

87. NY Com .................................... Public Service Commission of the State of New York.

88. NY Municipals ........................... Municipal Electric Utilities Association of New York States.

89. NY Utilities ................................ Consolidated Edison Company of New York, Inc., Long Island Lighting Company, New York State Electric

& Gas Corporation, and Rochester Gas and Electric Corporation.

90. NYPP ........................................ New York Power Pool.

91. NYSEG ...................................... New York State Electric & Gas Corporation.

92. Occidental Chemical ................. Occidental Chemical Corporation.

93. Oglethorpe ................................ Oglethorpe Power Corporation.

94. OH Com .................................... Public Utilities Commission of Ohio.

95. OH Consumers’ Counsel .......... Ohio Office of Consumers’ Counsel.

96. Ohio Valley ................................ Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation.

97. Oklahoma G&E ......................... Oklahoma Gas and Electric Company Inc.

98. Ontario Hydro ............................ Ontario Hydro.

99. PA Com ..................................... Pennsylvania Public Utility Commission.

100. PA Coops ................................ Pennsylvania Rural Electric Association and Allegheny Electric Cooperative, Inc.

101. PA Munis ................................. Pennsylvania Municipal Electric Association.

102. PacifiCorp ................................ PacifiCorp.

103. PSE&G .................................... Public Service Electric and Gas Company.

104. PSNM ...................................... Public Service Company of New Mexico.

105. Public Service Co of CO ......... Public Service Company of Colorado.

106. Puget ....................................... Puget Sound Power & Light Company.

107. Redding ................................... City of Redding, California.

108. San Francisco ......................... City and County of San Francisco.

109. Santa Clara ............................. City of Santa Clara, California.

110. SBA ......................................... United States Small Business Administration, Office of Advocacy.

111. SC Public Service Authority .... South Carolina Public Service Authority.

112. SoCal Edison .......................... Southern California Edison Company.

113. Southern .................................. Southern Company Services, Inc.

114. Southwestern .......................... Southwestern Public Service Company.

115. Speciality Steel ....................... Speciality Steel Industry of North America.

116. Suffolk County ......................... Suffolk County (New York) Electric Agency.

117. SWRTA ................................... Southwest Regional Transmission Association.
12464 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

Abbreviation Petitioner

118. Tallahassee ............................. City of Tallahassee, Florida.

119. TANC ...................................... Transmission Agency of Northern California.

120. TAPS ....................................... Transmission Access Policy Study Group.

121. TDU Systems .......................... Transmission Dependent Utility Systems.

122. Texaco .................................... Texaco Inc.

123. Tucson Power ......................... Tucson Electric Power Company.

124. Turlock .................................... Turlock Irrigation District.

125. TX Com ................................... Public Utility Commission of Texas.

126. Umatilla EC ............................. Umatilla Electric Cooperative.

127. Union Electric .......................... Union Electric Company.

128. Utilities For Improved transition.Utilities For an Improved Transition (consisting of Associated Electric Cooperative, Inc., Boston Edison

Company, Central Vermont Public Service Corporation, Montaup Electric Company, Wisconsin Electric

Power Company, and Wisconsin Public Service Corporation).

129. VA Com ................................... Staff of the Virginia State Corporation Commission.

130. Valero ...................................... Valero Power Services Company.

131. VEPCO .................................... Virginia Electric and Power Company.

132. VT DPS ................................... Vermont Department of Public Service.

133. Wabash ................................... Wabash Valley Power Association, Inc.

134. Washington Water Power ....... Washington Water Power Company.

135. WI Com ................................... Public Service Commission of Wisconsin.

136. Wisconsin Municipals .............. Municipal Electric Utilities of Wisconsin.

137. WY Com .................................. Public Service Commission of Wyoming.

Appendix B—Pro Forma Open Access

Transmission Tariff

Table of Contents

I Common Service Provisions

1 Definitions

1.1 Ancillary Services

1.2 Annual Transmission Costs

1.3 Application

1.4 Commission

1.5 Completed Application

1.6 Control Area

1.7 Curtailment

1.8 Delivering Party

1.9 Designated Agent

1.10 Direct Assignment Facilities

1.11 Eligible Customer

1.12 Facilities Study

1.13 Firm Point-To-Point Transmission

Service

1.14 Good Utility Practice

1.15 Interruption

1.16 Load Ratio Share

1.17 Load Shedding

1.18 Long-Term Firm Point-To-Point

Transmission Service

1.19 Native Load Customers

1.20 Network Customer

1.21 Network Integration Transmission

Service

1.22 Network Load

1.23 Network Operating Agreement

1.24 Network Operating Committee

1.25 Network Resource

1.26 Network Upgrades

1.27 Non-Firm Point-To-Point Transmission

Service

1.28 Open Access Same-Time Information

System (OASIS)

1.29 Part I

1.30 Part II

1.31 Part III

1.32 Parties

1.33 Point(s) of Delivery

1.34 Point(s) of Receipt

1.35 Point-To-Point Transmission Service

1.36 Power Purchaser

1.37 Receiving Party

1.38 Regional Transmission Group (RTG)

1.39 Reserved Capacity

1.40 Service Agreement

1.41 Service Commencement Date

1.42 Short-Term Firm Point-To-Point

Transmission Service

1.43 System Impact Study

1.44 Third-Party Sale

1.45 Transmission Customer

1.46 Transmission Provider

1.47 Transmission Provider’s Monthly

Transmission System Peak

1.48 Transmission Service

1.49 Transmission System

2 Initial Allocation and Renewal

Procedures

2.1 Initial Allocation of Available

Transmission Capability

2.2 Reservation Priority For Existing Firm

Service Customers

3 Ancillary Services

3.1 Scheduling, System Control and

Dispatch Service

3.2 Reactive Supply and Voltage Control

from Generation Sources Service

3.3 Regulation and Frequency Response

Service

3.4 Energy Imbalance Service

3.5 Operating Reserve—Spinning Reserve

Service

3.6 Operating Reserve—Supplemental

Reserve Service

4 Open Access Same-Time Information

System (OASIS)

5 Local Furnishing Bonds

5.1 Transmission Providers That Own

Facilities Financed by Local Furnishing

Bonds

5.2 Alternative Procedures for Requesting

Transmission Service

6 Reciprocity

7 Billing and Payment

7.1 Billing Procedure

7.2 Interest on Unpaid Balances

7.3 Customer Default

8 Accounting for the Transmission

Provider’s Use of the Tariff

8.1 Transmission Revenues

8.2 Study Costs and Revenues

9 Regulatory Filings

10 Force Majeure and Indemnification

10.1 Force Majeure

10.2 Indemnification

11 Creditworthiness

12 Dispute Resolution Procedures

12.1 Internal Dispute Resolution Procedures

12.2 External Arbitration Procedures

12.3 Arbitration Decisions

12.4 Costs

12.5 Rights Under The Federal Power Act

II. Point-to-Point Transmission Service

Preamble

13 Nature of Firm Point-To-Point

Transmission Service

13.1 Term

13.2 Reservation Priority

13.3 Use of Firm Transmission Service by

the Transmission Provider

13.4 Service Agreements

13.5 Transmission Customer Obligations for

Facility Additions or Redispatch Costs

13.6 Curtailment of Firm Transmission

Service

13.7 Classification of Firm Transmission

Service

13.8 Scheduling of Firm Point-To-Point

Transmission Service

14 Nature of Non-Firm Point-To-Point

Transmission Service

14.1 Term

14.2 Reservation Priority

14.3 Use of Non-Firm Point-To-Point

Transmission Service by the

Transmission Provider

14.4 Service Agreements

14.5 Classification of Non-Firm Point-ToPoint Transmission Service
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12465

14.6 Scheduling of Non-Firm Point-ToPoint Transmission Service

14.7 Curtailment or Interruption of Service

15 Service Availability

15.1 General Conditions

15.2 Determination of Available

Transmission Capability

15.3 Initiating Service in the Absence of an

Executed Service Agreement

15.4 Obligation to Provide Transmission

Service that Requires Expansion or

Modification of the Transmission System

15.5 Deferral of Service

15.6 Other Transmission Service Schedules

15.7 Real Power Losses

16 Transmission Customer Responsibilities

16.1 Conditions Required of Transmission

Customers

16.2 Transmission Customer Responsibility

for Third-Party Arrangements

17 Procedures for Arranging Firm Point-ToPoint Transmission Service

17.1 Application

17.2 Completed Application

17.3 Deposit

17.4 Notice of Deficient Application

17.5 Response to a Completed Application

17.6 Execution of Service Agreement

17.7 Extensions for Commencement of

Service

18 Procedures for Arranging Non-Firm

Point-To-Point Transmission Service

18.1 Application

18.2 Completed Application

18.3 Reservation of Non-Firm Point-ToPoint Transmission Service

18.4 Determination of Available

Transmission Capability

19 Additional Study Procedures For Firm

Point-To-Point Transmission Service

Requests

19.1 Notice of Need for System Impact

Study

19.2 System Impact Study Agreement and

Cost Reimbursement

19.3 System Impact Study Procedures

19.4 Facilities Study Procedures

19.5 Facilities Study Modifications

19.6 Due Diligence in Completing New

Facilities

19.7 Partial Interim Service

19.8 Expedited Procedures for New

Facilities

20 Procedures if the Transmission Provider

is Unable to Complete New Transmission

Facilities for Firm Point-To-Point

Transmission Service

20.1 Delays in Construction of New

Facilities

20.2 Alternatives to the Original Facility

Additions

20.3 Refund Obligation for Unfinished

Facility Additions

21 Provisions Relating to Transmission

Construction and Services on the Systems of

Other Utilities

21.1 Responsibility for Third-Party System

Additions

21.2 Coordination of Third-Party System

Additions

22 Changes in Service Specifications

22.1 Modifications On a Non-Firm Basis

22.2 Modification On a Firm Basis

23 Sale or Assignment of Transmission

Service

23.1 Procedures for Assignment or Transfer

of Service

23.2 Limitations on Assignment or Transfer

of Service

23.3 Information on Assignment or Transfer

of Service

24 Metering and Power Factor Correction at

Receipt and Delivery Points(s)

24.1 Transmission Customer Obligations

24.2 Transmission Provider Access to

Metering Data

24.3 Power Factor

25 Compensation for Transmission Service

26 Stranded Cost Recovery

27 Compensation for New Facilities and

Redispatch Costs

III. Network Integration Transmission Service

Preamble

28 Nature of Network Integration

Transmission Service

28.1 Scope of Service

28.2 Transmission Provider Responsibilities

28.3 Network Integration Transmission

Service

28.4 Secondary Service

28.5 Real Power Losses

28.6 Restrictions on Use of Service

29 Initiating Service

29.1 Condition Precedent for Receiving

Service

29.2 Application Procedures

29.3 Technical Arrangements to be

Completed Prior to Commencement of

Service

29.4 Network Customer Facilities

29.5 Filing of Service Agreement

30 Network Resources

30.1 Designation of Network Resources

30.2 Designation of New Network

Resources

30.3 Termination of Network Resources

30.4 Operation of Network Resources

30.5 Network Customer Redispatch

Obligation

30.6 Transmission Arrangements for

Network Resources Not Physically

Interconnected With The Transmission

Provider

30.7 Limitation on Designation of Network

Resources

30.8 Use of Interface Capacity by the

Network Customer

30.9 Network Customer Owned

Transmission Facilities

31 Designation of Network Load

31.1 Network Load

31.2 New Network Loads Connected With

the Transmission Provider

31.3 Network Load Not Physically

Interconnected with the Transmission

Provider

31.4 New Interconnection Points

31.5 Changes in Service Requests

31.6 Annual Load and Resource

Information Updates

32 Additional Study Procedures for

Network Integration Transmission Service

Requests

32.1 Notice of Need for System Impact

Study

32.2 System Impact Study Agreement and

Cost Reimbursement

32.3 System Impact Study Procedures

32.4 Facilities Study Procedures

33 Load Shedding and Curtailments

33.1 Procedures

33.2 Transmission Constraints

33.3 Cost Responsibility for Relieving

Transmission Constraints

33.4 Curtailments of Scheduled Deliveries

33.5 Allocation of Curtailments

33.6 Load Shedding

33.7 System Reliability

34 Rates and Charges

34.1 Monthly Demand Charge

34.2 Determination of Network Customer’s

Monthly Network Load

34.3 Determination of Transmission

Provider’s Monthly Transmission System

Load

34.4 Redispatch Charge

34.5 Stranded Cost Recovery

35 Operating Arrangements

35.1 Operation under The Network

Operating Agreement

35.2 Network Operating Agreement

35.3 Network Operating Committee

Schedule 1

Scheduling, System Control and Dispatch

Service

Schedule 2

Reactive Supply and Voltage Control from

Generation Sources Service

Schedule 3

Regulation and Frequency Response

Service

Schedule 4

Energy Imbalance Service

Schedule 5

Operating Reserve—Spinning Reserve

Service

Schedule 6

Operating Reserve—Supplemental Reserve

Service

Schedule 7

Long-Term Firm and Short-Term Firm

Point-To-Point Transmission Service

Schedule 8

Non-Firm Point-To-Point Transmission

Service

Attachment A

Form Of Service Agreement For Firm

Point-To-Point Transmission Service

Attachment B

Form Of Service Agreement For Non-Firm

Point-To-Point Transmission Service

Attachment C

Methodology To Assess Available

Transmission Capability

Attachment D

Methodology for Completing a System

Impact Study

Attachment E

Index Of Point-To-Point Transmission

Service Customers

Attachment F

Service Agreement For Network Integration

Transmission Service

Attachment G
12466 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

Network Operating Agreement

Attachment H

Annual Transmission Revenue

Requirement For Network Integration

Transmission Service

Attachment I

Index Of Network Integration Transmission

Service Customers

I. Common Service Provisions

1 Definitions

1.1 Ancillary Services: Those services

that are necessary to support the

transmission of capacity and energy from

resources to loads while maintaining reliable

operation of the Transmission Provider’s

Transmission System in accordance with

Good Utility Practice.

1.2 Annual Transmission Costs: The total

annual cost of the Transmission System for

purposes of Network Integration

Transmission Service shall be the amount

specified in Attachment until amended by

the Transmission Provider or modified by the

Commission.

1.3 Application: A request by an Eligible

Customer for transmission service pursuant

to the provisions of the Tariff.

1.4 Commission: The Federal Energy

Regulatory Commission.

1.5 Completed Application: An

Application that satisfies all of the

information and other requirements of the

Tariff, including any required deposit.

1.6 Control Area: An electric power

system or combination of electric power

systems to which a common automatic

generation control scheme is applied in order

to:

(1) Match, at all times, the power output

of the generators within the electric power

system(s) and capacity and energy purchased

from entities outside the electric power

system(s), with the load within the electric

power system(s);

(2) Maintain scheduled interchange with

other Control Areas, within the limits of

Good Utility Practice;

(3) Maintain the frequency of the electric

power system(s) within reasonable limits in

accordance with Good Utility Practice; and

(4) Provide sufficient generating capacity to

maintain operating reserves in accordance

with Good Utility Practice.

1.7 Curtailment: A reduction in firm or

non-firm transmission service in response to

a transmission capacity shortage as a result

of system reliability conditions.

1.8 Delivering Party: The entity supplying

capacity and energy to be transmitted at

Point(s) of Receipt.

1.9 Designated Agent: Any entity that

performs actions or functions on behalf of the

Transmission Provider, an Eligible Customer,

or the Transmission Customer required under

the Tariff.

1.10 Direct Assignment Facilities:

Facilities or portions of facilities that are

constructed by the Transmission Provider for

the sole use/benefit of a particular

Transmission Customer requesting service

under the Tariff. Direct Assignment Facilities

shall be specified in the Service Agreement

that governs service to the Transmission

Customer and shall be subject to Commission

approval.

1.11 Eligible Customer: (i) Any electric

utility (including the Transmission Provider

and any power marketer), Federal power

marketing agency, or any person generating

electric energy for sale for resale is an

Eligible Customer under the Tariff. Electric

energy sold or produced by such entity may

be electric energy produced in the United

States, Canada or Mexico. However, with

respect to transmission service that the

Commission is prohibited from ordering by

Section 212(h) of the Federal Power Act,

such entity is eligible only if the service is

provided pursuant to a state requirement that

the Transmission Provider offer the

unbundled transmission service, or pursuant

to a voluntary offer of such service by the

Transmission Provider. (ii) Any retail

customer taking unbundled transmission

service pursuant to a state requirement that

the Transmission Provider offer the

transmission service, or pursuant to a

voluntary offer of such service by the

Transmission Provider, is an Eligible

Customer under the Tariff.

1.12 Facilities Study: An engineering

study conducted by the Transmission

Provider to determine the required

modifications to the Transmission Provider’s

Transmission System, including the cost and

scheduled completion date for such

modifications, that will be required to

provide the requested transmission service.

1.13 Firm Point-To-Point Transmission

Service: Transmission Service under this

Tariff that is reserved and/or scheduled

between specified Points of Receipt and

Delivery pursuant to Part II of this Tariff.

1.14 Good Utility Practice: Any of the

practices, methods and acts engaged in or

approved by a significant portion of the

electric utility industry during the relevant

time period, or any of the practices, methods

and acts which, in the exercise of reasonable

judgment in light of the facts known at the

time the decision was made, could have been

expected to accomplish the desired result at

a reasonable cost consistent with good

business practices, reliability, safety and

expedition. Good Utility Practice is not

intended to be limited to the optimum

practice, method, or act to the exclusion of

all others, but rather to be acceptable

practices, methods, or acts generally accepted

in the region.

1.15 Interruption: A reduction in nonfirm transmission service due to economic

reasons pursuant to Section 14.7.

1.16 Load Ratio Share: Ratio of a

Transmission Customer’s Network Load to

the Transmission Provider’s total load

computed in accordance with Sections 34.2

and 34.3 of the Network Integration

Transmission Service under Part III the Tariff

and calculated on a rolling twelve month

basis.

1.17 Load Shedding: The systematic

reduction of system demand by temporarily

decreasing load in response to transmission

system or area capacity shortages, system

instability, or voltage control considerations

under Part III of the Tariff.

1.18 Long-Term Firm Point-To-Point

Transmission Service: Firm Point-To-Point

Transmission Service under Part II of the

Tariff with a term of one year or more.

1.19 Native Load Customers: The

wholesale and retail power customers of the

Transmission Provider on whose behalf the

Transmission Provider, by statute, franchise,

regulatory requirement, or contract, has

undertaken an obligation to construct and

operate the Transmission Provider’s system

to meet the reliable electric needs of such

customers.

1.20 Network Customer: An entity

receiving transmission service pursuant to

the terms of the Transmission Provider’s

Network Integration Transmission Service

under Part III of the Tariff.

1.21 Network Integration Transmission

Service: The transmission service provided

under Part III of the Tariff.

1.22 Network Load: The load that a

Network Customer designates for Network

Integration Transmission Service under Part

III of the Tariff. The Network Customer’s

Network Load shall include all load served

by the output of any Network Resources

designated by the Network Customer. A

Network Customer may elect to designate

less than its total load as Network Load but

may not designate only part of the load at a

discrete Point of Delivery. Where a Eligible

Customer has elected not to designate a

particular load at discrete points of delivery

as Network Load, the Eligible Customer is

responsible for making separate arrangements

under Part II of the Tariff for any Point-ToPoint Transmission Service that may be

necessary for such non-designated load.

1.23 Network Operating Agreement: An

executed agreement that contains the terms

and conditions under which the Network

Customer shall operate its facilities and the

technical and operational matters associated

with the implementation of Network

Integration Transmission Service under Part

III of the Tariff.

1.24 Network Operating Committee: A

group made up of representatives from the

Network Customer(s) and the Transmission

Provider established to coordinate operating

criteria and other technical considerations

required for implementation of Network

Integration Transmission Service under Part

III of this Tariff.

1.25 Network Resource: Any designated

generating resource owned, purchased or

leased by a Network Customer under the

Network Integration Transmission Service

Tariff. Network Resources do not include any

resource, or any portion thereof, that is

committed for sale to third parties or

otherwise cannot be called upon to meet the

Network Customer’s Network Load on a noninterruptible basis.

1.26 Network Upgrades: Modifications or

additions to transmission-related facilities

that are integrated with and support the

Transmission Provider’s overall

Transmission System for the general benefit

of all users of such Transmission System.

1.27 Non-Firm Point-To-Point

Transmission Service: Point-To-Point

Transmission Service under the Tariff that is

reserved and scheduled on an as-available

basis and is subject to Curtailment or

Interruption as set forth in Section 14.7

under Part II of this Tariff. Non-Firm PointTo-Point Transmission Service is available

on a stand-alone basis for periods ranging

from one hour to one month.
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1.28 Open Access Same-Time

Information System (OASIS): The

information system and standards of conduct

contained in Part 37 of the Commission’s

regulations and all additional requirements

implemented by subsequent Commission

orders dealing with OASIS.

1.29 Part I: Tariff Definitions and

Common Service Provisions contained in

Sections 2 through 12.

1.30 Part II: Tariff Sections 13 through 27

pertaining to Point-To-Point Transmission

Service in conjunction with the applicable

Common Service Provisions of Part I and

appropriate Schedules and Attachments.

1.31 Part III: Tariff Sections 28 through 35

pertaining to Network Integration

Transmission Service in conjunction with the

applicable Common Service Provisions of

Part I and appropriate Schedules and

Attachments.

1.32 Parties: The Transmission Provider

and the Transmission Customer receiving

service under the Tariff.

1.33 Point(s) of Delivery: Point(s) on the

Transmission Provider’s Transmission

System where capacity and energy

transmitted by the Transmission Provider

will be made available to the Receiving Party

under Part II of the Tariff. The Point(s) of

Delivery shall be specified in the Service

Agreement for Long-Term Firm Point-ToPoint Transmission Service.

1.34 Point(s) of Receipt: Point(s) of

interconnection on the Transmission

Provider’s Transmission System where

capacity and energy will be made available

to the Transmission Provider by the

Delivering Party under Part II of the Tariff.

The Point(s) of Receipt shall be specified in

the Service Agreement for Long-Term Firm

Point-To-Point Transmission Service.

1.35 Point-To-Point Transmission

Service: The reservation and transmission of

capacity and energy on either a firm or nonfirm basis from the Point(s) of Receipt to the

Point(s) of Delivery under Part II of the Tariff.

1.36 Power Purchaser: The entity that is

purchasing the capacity and energy to be

transmitted under the Tariff.

1.37 Receiving Party: The entity receiving

the capacity and energy transmitted by the

Transmission Provider to Point(s) of

Delivery.

1.38 Regional Transmission Group (RTG):

A voluntary organization of transmission

owners, transmission users and other entities

approved by the Commission to efficiently

coordinate transmission planning (and

expansion), operation and use on a regional

(and interregional) basis.

1.39 Reserved Capacity: The maximum

amount of capacity and energy that the

Transmission Provider agrees to transmit for

the Transmission Customer over the

Transmission Provider’s Transmission

System between the Point(s) of Receipt and

the Point(s) of Delivery under Part II of the

Tariff. Reserved Capacity shall be expressed

in terms of whole megawatts on a sixty (60)

minute interval (commencing on the clock

hour) basis.

1.40 Service Agreement: The initial

agreement and any amendments or

supplements thereto entered into by the

Transmission Customer and the

Transmission Provider for service under the

Tariff.

1.41 Service Commencement Date: The

date the Transmission Provider begins to

provide service pursuant to the terms of an

executed Service Agreement, or the date the

Transmission Provider begins to provide

service in accordance with Section 15.3 or

Section 29.1 under the Tariff.

1.42 Short-Term Firm Point-To-Point

Transmission Service: Firm Point-To-Point

Transmission Service under Part II of the

Tariff with a term of less than one year.

1.43 System Impact Study: An

assessment by the Transmission Provider of

(i) the adequacy of the Transmission System

to accommodate a request for either Firm

Point-To-Point Transmission Service or

Network Integration Transmission Service

and (ii) whether any additional costs may be

incurred in order to provide transmission

service.

1.44 Third-Party Sale: Any sale for resale

in interstate commerce to a Power Purchaser

that is not designated as part of Network

Load under the Network Integration

Transmission Service.

1.45 Transmission Customer: Any

Eligible Customer (or its Designated Agent)

that (i) executes a Service Agreement, or (ii)

requests in writing that the Transmission

Provider file with the Commission, a

proposed unexecuted Service Agreement to

receive transmission service under Part II of

the Tariff. This term is used in the Part I

Common Service Provisions to include

customers receiving transmission service

under Part II and Part III of this Tariff.

1.46 Transmission Provider: The public

utility (or its Designated Agent) that owns,

controls, or operates facilities used for the

transmission of electric energy in interstate

commerce and provides transmission service

under the Tariff.

1.47 Transmission Provider’s Monthly

Transmission System Peak: The maximum

firm usage of the Transmission Provider’s

Transmission System in a calendar month.

1.48 Transmission Service: Point-ToPoint Transmission Service provided under

Part II of the Tariff on a firm and non-firm

basis.

1.49 Transmission System: The facilities

owned, controlled or operated by the

Transmission Provider that are used to

provide transmission service under Part II

and Part III of the Tariff.

2. Initial Allocation and Renewal

Procedures

2.1 Initial Allocation of Available

Transmission Capability: For purposes of

determining whether existing capability on

the Transmission Provider’s Transmission

System is adequate to accommodate a request

for firm service under this Tariff, all

Completed Applications for new firm

transmission service received during the

initial sixty (60) day period commencing

with the effective date of the Tariff will be

deemed to have been filed simultaneously. A

lottery system conducted by an independent

party shall be used to assign priorities for

Completed Applications filed

simultaneously. All Completed Applications

for firm transmission service received after

the initial sixty (60) day period shall be

assigned a priority pursuant to Section 13.2.

2.2 Reservation Priority For Existing Firm

Service Customers: Existing firm service

customers (wholesale requirements and

transmission-only, with a contract term of

one-year or more), have the right to continue

to take transmission service from the

Transmission Provider when the contract

expires, rolls over or is renewed. This

transmission reservation priority is

independent of whether the existing

customer continues to purchase capacity and

energy from the Transmission Provider or

elects to purchase capacity and energy from

another supplier. If at the end of the contract

term, the Transmission Provider’s

Transmission System cannot accommodate

all of the requests for transmission service

the existing firm service customer must agree

to accept a contract term at least equal to a

competing request by any new Eligible

Customer and to pay the current just and

reasonable rate, as approved by the

Commission, for such service. This

transmission reservation priority for existing

firm service customers is an ongoing right

that may be exercised at the end of all firm

contract terms of one-year or longer.

3. Ancillary Services

Ancillary Services are needed with

transmission service to maintain reliability

within and among the Control Areas affected

by the transmission service. The

Transmission Provider is required to provide

(or offer to arrange with the local Control

Area operator as discussed below), and the

Transmission Customer is required to

purchase, the following Ancillary Services (i)

Scheduling, System Control and Dispatch,

and (ii) Reactive Supply and Voltage Control

from Generation Sources.

The Transmission Provider is required to

offer to provide (or offer to arrange with the

local Control Area operator as discussed

below) the following Ancillary Services only

to the Transmission Customer serving load

within the Transmission Provider’s Control

Area (i) Regulation and Frequency Response,

(ii) Energy Imbalance, (iii) Operating

Reserve—Spinning, and (iv) Operating

Reserve—Supplemental. The Transmission

Customer serving load within the

Transmission Provider’s Control Area is

required to acquire these Ancillary Services,

whether from the Transmission Provider,

from a third party, or by self-supply. The

Transmission Customer may not decline the

Transmission Provider’s offer of Ancillary

Services unless it demonstrates that it has

acquired the Ancillary Services from another

source. The Transmission Customer must list

in its Application which Ancillary Services

it will purchase from the Transmission

Provider.

If the Transmission Provider is a public

utility providing transmission service but is

not a Control Area operator, it may be unable

to provide some or all of the Ancillary

Services. In this case, the Transmission

Provider can fulfill its obligation to provide

Ancillary Services by acting as the

Transmission Customer’s agent to secure

these Ancillary Services from the Control

Area operator. The Transmission Customer
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may elect to (i) have the Transmission

Provider act as its agent, (ii) secure the

Ancillary Services directly from the Control

Area operator, or (iii) secure the Ancillary

Services (discussed in Schedules 3, 4, 5 and

6) from a third party or by self-supply when

technically feasible.

The Transmission Provider shall specify

the rate treatment and all related terms and

conditions in the event of an unauthorized

use of Ancillary Services by the

Transmission Customer.

The specific Ancillary Services, prices

and/or compensation methods are described

on the Schedules that are attached to and

made a part of the Tariff. Three principal

requirements apply to discounts for Ancillary

Services provided by the Transmission

Provider in conjunction with its provision of

transmission service as follows: (1) any offer

of a discount made by the Transmission

Provider must be announced to all Eligible

Customers solely by posting on the OASIS,

(2) any customer-initiated requests for

discounts (including requests for use by one’s

wholesale merchant or an affiliate’s use)

must occur solely by posting on the OASIS,

and (3) once a discount is negotiated, details

must be immediately posted on the OASIS.

A discount agreed upon for an Ancillary

Service must be offered for the same period

to all Eligible Customers on the Transmission

Provider’s system. Sections 3.1 through 3.6

below list the six Ancillary Services.

3.1 Scheduling, System Control and

Dispatch Service: The rates and/or

methodology are described in Schedule 1.

3.2 Reactive Supply and Voltage Control

from Generation Sources Service: The rates

and/or methodology are described in

Schedule 2.

3.3 Regulation and Frequency Response

Service: Where applicable the rates and/or

methodology are described in Schedule 3.

3.4 Energy Imbalance Service: Where

applicable the rates and/or methodology are

described in Schedule 4.

3.5 Operating Reserve—Spinning Reserve

Service: Where applicable the rates and/or

methodology are described in Schedule 5.

3.6 Operating Reserve—Supplemental

Reserve Service: Where applicable the rates

and/or methodology are described in

Schedule 6.

4 Open Access Same-Time Information

System (OASIS)

Terms and conditions regarding Open

Access Same-Time Information System and

standards of conduct are set forth in 18 CFR

§ 37 of the Commission’s regulations (Open

Access Same-Time Information System and

Standards of Conduct for Public Utilities). In

the event available transmission capability as

posted on the OASIS is insufficient to

accommodate a request for firm transmission

service, additional studies may be required as

provided by this Tariff pursuant to Sections

19 and 32.

5 Local Furnishing Bonds

5.1 Transmission Providers That Own

Facilities Financed by Local Furnishing

Bonds: This provision is applicable only to

Transmission Providers that have financed

facilities for the local furnishing of electric

energy with tax-exempt bonds, as described

in Section 142(f) of the Internal Revenue

Code (‘‘local furnishing bonds’’).

Notwithstanding any other provision of this

Tariff, the Transmission Provider shall not be

required to provide transmission service to

any Eligible Customer pursuant to this Tariff

if the provision of such transmission service

would jeopardize the tax-exempt status of

any local furnishing bond(s) used to finance

the Transmission Provider’s facilities that

would be used in providing such

transmission service.

5.2 Alternative Procedures for Requesting

Transmission Service:

(i) If the Transmission Provider determines

that the provision of transmission service

requested by an Eligible Customer would

jeopardize the tax-exempt status of any local

furnishing bond(s) used to finance its

facilities that would be used in providing

such transmission service, it shall advise the

Eligible Customer within thirty (30) days of

receipt of the Completed Application.

(ii) If the Eligible Customer thereafter

renews its request for the same transmission

service referred to in (i) by tendering an

application under Section 211 of the Federal

Power Act, the Transmission Provider,

within ten (10) days of receiving a copy of

the Section 211 application, will waive its

rights to a request for service under Section

213(a) of the Federal Power Act and to the

issuance of a proposed order under Section

212(c) of the Federal Power Act. The

Commission, upon receipt of the

Transmission Provider’s waiver of its rights

to a request for service under Section 213(a)

of the Federal Power Act and to the issuance

of a proposed order under Section 212(c) of

the Federal Power Act, shall issue an order

under Section 211 of the Federal Power Act.

Upon issuance of the order under Section

211 of the Federal Power Act, the

Transmission Provider shall be required to

provide the requested transmission service in

accordance with the terms and conditions of

this Tariff.

6 Reciprocity

A Transmission Customer receiving

transmission service under this Tariff agrees

to provide comparable transmission service

that it is capable of providing to the

Transmission Provider on similar terms and

conditions over facilities used for the

transmission of electric energy owned,

controlled or operated by the Transmission

Customer and over facilities used for the

transmission of electric energy owned,

controlled or operated by the Transmission

Customer’s corporate affiliates. A

Transmission Customer that is a member of

a power pool or Regional Transmission

Group also agrees to provide comparable

transmission service to the members of such

power pool and Regional Transmission

Group on similar terms and conditions over

facilities used for the transmission of electric

energy owned, controlled or operated by the

Transmission Customer and over facilities

used for the transmission of electric energy

owned, controlled or operated by the

Transmission Customer’s corporate affiliates.

This reciprocity requirement applies not

only to the Transmission Customer that

obtains transmission service under the Tariff,

but also to all parties to a transaction that

involves the use of transmission service

under the Tariff, including the power seller,

buyer and any intermediary, such as a power

marketer. This reciprocity requirement also

applies to any Eligible Customer that owns,

controls or operates transmission facilities

that uses an intermediary, such as a power

marketer, to request transmission service

under the Tariff. If the Transmission

Customer does not own, control or operate

transmission facilities, it must include in its

Application a sworn statement of one of its

duly authorized officers or other

representatives that the purpose of its

Application is not to assist an Eligible

Customer to avoid the requirements of this

provision.

7 Billing and Payment

7.1 Billing Procedure: Within a

reasonable time after the first day of each

month, the Transmission Provider shall

submit an invoice to the Transmission

Customer for the charges for all services

furnished under the Tariff during the

preceding month. The invoice shall be paid

by the Transmission Customer within twenty

(20) days of receipt. All payments shall be

made in immediately available funds payable

to the Transmission Provider, or by wire

transfer to a bank named by the Transmission

Provider.

7.2 Interest on Unpaid Balances: Interest

on any unpaid amounts (including amounts

placed in escrow) shall be calculated in

accordance with the methodology specified

for interest on refunds in the Commission’s

regulations at 18 C.F.R. § 35.19a(a)(2)(iii).

Interest on delinquent amounts shall be

calculated from the due date of the bill to the

date of payment. When payments are made

by mail, bills shall be considered as having

been paid on the date of receipt by the

Transmission Provider.

7.3 Customer Default: In the event the

Transmission Customer fails, for any reason

other than a billing dispute as described

below, to make payment to the Transmission

Provider on or before the due date as

described above, and such failure of payment

is not corrected within thirty (30) calendar

days after the Transmission Provider notifies

the Transmission Customer to cure such

failure, a default by the Transmission

Customer shall be deemed to exist. Upon the

occurrence of a default, the Transmission

Provider may initiate a proceeding with the

Commission to terminate service but shall

not terminate service until the Commission

so approves any such request. In the event of

a billing dispute between the Transmission

Provider and the Transmission Customer, the

Transmission Provider will continue to

provide service under the Service Agreement

as long as the Transmission Customer (i)

continues to make all payments not in

dispute, and (ii) pays into an independent

escrow account the portion of the invoice in

dispute, pending resolution of such dispute.

If the Transmission Customer fails to meet

these two requirements for continuation of

service, then the Transmission Provider may

provide notice to the Transmission Customer

of its intention to suspend service in sixty
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12469

(60) days, in accordance with Commission

policy.

8 Accounting for the Transmission

Provider’s Use of the Tariff

The Transmission Provider shall record the

following amounts, as outlined below.

8.1 Transmission Revenues: Include in a

separate operating revenue account or

subaccount the revenues it receives from

Transmission Service when making ThirdParty Sales under Part II of the Tariff.

8.2 Study Costs and Revenues: Include in

a separate transmission operating expense

account or subaccount, costs properly

chargeable to expense that are incurred to

perform any System Impact Studies or

Facilities Studies which the Transmission

Provider conducts to determine if it must

construct new transmission facilities or

upgrades necessary for its own uses,

including making Third-Party Sales under

the Tariff; and include in a separate operating

revenue account or subaccount the revenues

received for System Impact Studies or

Facilities Studies performed when such

amounts are separately stated and identified

in the Transmission Customer’s billing under

the Tariff.

9 Regulatory Filings

Nothing contained in the Tariff or any

Service Agreement shall be construed as

affecting in any way the right of the

Transmission Provider to unilaterally make

application to the Commission for a change

in rates, terms and conditions, charges,

classification of service, Service Agreement,

rule or regulation under Section 205 of the

Federal Power Act and pursuant to the

Commission’s rules and regulations

promulgated thereunder.

Nothing contained in the Tariff or any

Service Agreement shall be construed as

affecting in any way the ability of any Party

receiving service under the Tariff to exercise

its rights under the Federal Power Act and

pursuant to the Commission’s rules and

regulations promulgated thereunder.

10 Force Majeure and Indemnification

10.1 Force Majeure: An event of Force

Majeure means any act of God, labor

disturbance, act of the public enemy, war,

insurrection, riot, fire, storm or flood,

explosion, breakage or accident to machinery

or equipment, any Curtailment, order,

regulation or restriction imposed by

governmental military or lawfully established

civilian authorities, or any other cause

beyond a Party’s control. A Force Majeure

event does not include an act of negligence

or intentional wrongdoing. Neither the

Transmission Provider nor the Transmission

Customer will be considered in default as to

any obligation under this Tariff if prevented

from fulfilling the obligation due to an event

of Force Majeure. However, a Party whose

performance under this Tariff is hindered by

an event of Force Majeure shall make all

reasonable efforts to perform its obligations

under this Tariff.

10.2 Indemnification: The Transmission

Customer shall at all times indemnify,

defend, and save the Transmission Provider

harmless from, any and all damages, losses,

claims, including claims and actions relating

to injury to or death of any person or damage

to property, demands, suits, recoveries, costs

and expenses, court costs, attorney fees, and

all other obligations by or to third parties,

arising out of or resulting from the

Transmission Provider’s performance of its

obligations under this Tariff on behalf of the

Transmission Customer, except in cases of

negligence or intentional wrongdoing by the

Transmission Provider.

11 Creditworthiness

For the purpose of determining the ability

of the Transmission Customer to meet its

obligations related to service hereunder, the

Transmission Provider may require

reasonable credit review procedures. This

review shall be made in accordance with

standard commercial practices. In addition,

the Transmission Provider may require the

Transmission Customer to provide and

maintain in effect during the term of the

Service Agreement, an unconditional and

irrevocable letter of credit as security to meet

its responsibilities and obligations under the

Tariff, or an alternative form of security

proposed by the Transmission Customer and

acceptable to the Transmission Provider and

consistent with commercial practices

established by the Uniform Commercial Code

that protects the Transmission Provider

against the risk of non-payment.

12 Dispute Resolution Procedures

12.1 Internal Dispute Resolution

Procedures: Any dispute between a

Transmission Customer and the

Transmission Provider involving

transmission service under the Tariff

(excluding applications for rate changes or

other changes to the Tariff, or to any Service

Agreement entered into under the Tariff,

which shall be presented directly to the

Commission for resolution) shall be referred

to a designated senior representative of the

Transmission Provider and a senior

representative of the Transmission Customer

for resolution on an informal basis as

promptly as practicable. In the event the

designated representatives are unable to

resolve the dispute within thirty (30) days [or

such other period as the Parties may agree

upon] by mutual agreement, such dispute

may be submitted to arbitration and resolved

in accordance with the arbitration procedures

set forth below.

12.2 External Arbitration Procedures:

Any arbitration initiated under the Tariff

shall be conducted before a single neutral

arbitrator appointed by the Parties. If the

Parties fail to agree upon a single arbitrator

within ten (10) days of the referral of the

dispute to arbitration, each Party shall choose

one arbitrator who shall sit on a threemember arbitration panel. The two arbitrators

so chosen shall within twenty (20) days

select a third arbitrator to chair the

arbitration panel. In either case, the

arbitrators shall be knowledgeable in electric

utility matters, including electric

transmission and bulk power issues, and

shall not have any current or past substantial

business or financial relationships with any

party to the arbitration (except prior

arbitration). The arbitrator(s) shall provide

each of the Parties an opportunity to be heard

and, except as otherwise provided herein,

shall generally conduct the arbitration in

accordance with the Commercial Arbitration

Rules of the American Arbitration

Association and any applicable Commission

regulations or Regional Transmission Group

rules.

12.3 Arbitration Decisions: Unless

otherwise agreed, the arbitrator(s) shall

render a decision within ninety (90) days of

appointment and shall notify the Parties in

writing of such decision and the reasons

therefor. The arbitrator(s) shall be authorized

only to interpret and apply the provisions of

the Tariff and any Service Agreement entered

into under the Tariff and shall have no power

to modify or change any of the above in any

manner. The decision of the arbitrator(s)

shall be final and binding upon the Parties,

and judgment on the award may be entered

in any court having jurisdiction. The

decision of the arbitrator(s) may be appealed

solely on the grounds that the conduct of the

arbitrator(s), or the decision itself, violated

the standards set forth in the Federal

Arbitration Act and/or the Administrative

Dispute Resolution Act. The final decision of

the arbitrator must also be filed with the

Commission if it affects jurisdictional rates,

terms and conditions of service or facilities.

12.4 Costs: Each Party shall be

responsible for its own costs incurred during

the arbitration process and for the following

costs, if applicable:

(A) The cost of the arbitrator chosen by the

Party to sit on the three member panel and

one half of the cost of the third arbitrator

chosen; or

(B) One half the cost of the single arbitrator

jointly chosen by the Parties.

12.5 Rights Under The Federal Power

Act: Nothing in this section shall restrict the

rights of any party to file a Complaint with

the Commission under relevant provisions of

the Federal Power Act.

II. Point-to-Point Transmission Service

Preamble

The Transmission Provider will provide

Firm and Non-Firm Point-To-Point

Transmission Service pursuant to the

applicable terms and conditions of this

Tariff. Point-To-Point Transmission Service

is for the receipt of capacity and energy at

designated Point(s) of Receipt and the

transmission of such capacity and energy to

designated Point(s) of Delivery.

13 Nature of Firm Point-To-Point

Transmission Service

13.1 Term: The minimum term of Firm

Point-To-Point Transmission Service shall be

one day and the maximum term shall be

specified in the Service Agreement.

13.2 Reservation Priority: Long-Term

Firm Point-To-Point Transmission Service

shall be available on a first-come, first-served

basis i.e., in the chronological sequence in

which each Transmission Customer has

reserved service. Reservations for Short-Term

Firm Point-To-Point Transmission Service

will be conditional based upon the length of

the requested transaction. If the Transmission

System becomes oversubscribed, requests for

longer term service may preempt requests for

shorter term service up to the following
12470 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

deadlines: one day before the commencement

of daily service, one week before the

commencement of weekly service, and one

month before the commencement of monthly

service. Before the conditional reservation

deadline, if available transmission capability

is insufficient to satisfy all Applications, an

Eligible Customer with a reservation for

shorter term service has the right of first

refusal to match any longer term reservation

before losing its reservation priority. A longer

term competing request for Short-Term Firm

Point-To-Point Transmission Service will be

granted if the Eligible Customer with the

right of first refusal does not agree to match

the competing request within 24 hours (or

earlier if necessary to comply with the

scheduling deadlines provided in section

13.8) from being notified by the Transmission

Provider of a longer-term competing request

for Short-Term Firm Point-To-Point

Transmission Service. After the conditional

reservation deadline, service will commence

pursuant to the terms of Part II of the Tariff.

Firm Point-To-Point Transmission Service

will always have a reservation priority over

Non-Firm Point-To-Point Transmission

Service under the Tariff. All Long-Term Firm

Point-To-Point Transmission Service will

have equal reservation priority with Native

Load Customers and Network Customers.

Reservation priorities for existing firm

service customers are provided in Section

2.2.

13.3 Use of Firm Transmission Service by

the Transmission Provider: The Transmission

Provider will be subject to the rates, terms

and conditions of Part II of the Tariff when

making Third-Party Sales under (i)

agreements executed on or after [insert date

sixty (60) days after publication in Federal

Register] or (ii) agreements executed prior to

the aforementioned date that the Commission

requires to be unbundled, by the date

specified by the Commission. The

Transmission Provider will maintain separate

accounting, pursuant to Section 8 , for any

use of the Point-To-Point Transmission

Service to make Third-Party Sales.

13.4 Service Agreements: The

Transmission Provider shall offer a standard

form Firm Point-To-Point Transmission

Service Agreement (Attachment A) to an

Eligible Customer when it submits a

Completed Application for Long-Term Firm

Point-To-Point Transmission Service. The

Transmission Provider shall offer a standard

form Firm Point-To-Point Transmission

Service Agreement (Attachment A) to an

Eligible Customer when it first submits a

Completed Application for Short-Term Firm

Point-To-Point Transmission Service

pursuant to the Tariff. Executed Service

Agreements that contain the information

required under the Tariff shall be filed with

the Commission in compliance with

applicable Commission regulations.

13.5 Transmission Customer Obligations

for Facility Additions or Redispatch Costs: In

cases where the Transmission Provider

determines that the Transmission System is

not capable of providing Firm Point-To-Point

Transmission Service without (1) degrading

or impairing the reliability of service to

Native Load Customers, Network Customers

and other Transmission Customers taking

Firm Point-To-Point Transmission Service, or

(2) interfering with the Transmission

Provider’s ability to meet prior firm

contractual commitments to others, the

Transmission Provider will be obligated to

expand or upgrade its Transmission System

pursuant to the terms of Section 15.4. The

Transmission Customer must agree to

compensate the Transmission Provider for

any necessary transmission facility additions

pursuant to the terms of Section 27. To the

extent the Transmission Provider can relieve

any system constraint more economically by

redispatching the Transmission Provider’s

resources than through constructing Network

Upgrades, it shall do so, provided that the

Eligible Customer agrees to compensate the

Transmission Provider pursuant to the terms

of Section 27 . Any redispatch, Network

Upgrade or Direct Assignment Facilities costs

to be charged to the Transmission Customer

on an incremental basis under the Tariff will

be specified in the Service Agreement prior

to initiating service.

13.6 Curtailment of Firm Transmission

Service: In the event that a Curtailment on

the Transmission Provider’s Transmission

System, or a portion thereof, is required to

maintain reliable operation of such system,

Curtailments will be made on a nondiscriminatory basis to the transaction(s) that

effectively relieve the constraint. If multiple

transactions require Curtailment, to the

extent practicable and consistent with Good

Utility Practice, the Transmission Provider

will curtail service to Network Customers

and Transmission Customers taking Firm

Point-To-Point Transmission Service on a

basis comparable to the curtailment of

service to the Transmission Provider’s Native

Load Customers. All Curtailments will be

made on a non-discriminatory basis,

however, Non-Firm Point-To-Point

Transmission Service shall be subordinate to

Firm Transmission Service. When the

Transmission Provider determines that an

electrical emergency exists on its

Transmission System and implements

emergency procedures to Curtail Firm

Transmission Service, the Transmission

Customer shall make the required reductions

upon request of the Transmission Provider.

However, the Transmission Provider reserves

the right to Curtail, in whole or in part, any

Firm Transmission Service provided under

the Tariff when, in the Transmission

Provider’s sole discretion, an emergency or

other unforeseen condition impairs or

degrades the reliability of its Transmission

System. The Transmission Provider will

notify all affected Transmission Customers in

a timely manner of any scheduled

Curtailments.

13.7 Classification of Firm Transmission

Service:

(a) The Transmission Customer taking Firm

Point-To-Point Transmission Service may (1)

change its Receipt and Delivery Points to

obtain service on a non-firm basis consistent

with the terms of Section 22.1 or (2) request

a modification of the Points of Receipt or

Delivery on a firm basis pursuant to the terms

of Section 22.2.

(b) The Transmission Customer may

purchase transmission service to make sales

of capacity and energy from multiple

generating units that are on the Transmission

Provider’s Transmission System. For such a

purchase of transmission service, the

resources will be designated as multiple

Points of Receipt, unless the multiple

generating units are at the same generating

plant in which case the units would be

treated as a single Point of Receipt.

(c) The Transmission Provider shall

provide firm deliveries of capacity and

energy from the Point(s) of Receipt to the

Point(s) of Delivery. Each Point of Receipt at

which firm transmission capacity is reserved

by the Transmission Customer shall be set

forth in the Firm Point-To-Point Service

Agreement for Long-Term Firm Transmission

Service along with a corresponding capacity

reservation associated with each Point of

Receipt. Points of Receipt and corresponding

capacity reservations shall be as mutually

agreed upon by the Parties for Short-Term

Firm Transmission. Each Point of Delivery at

which firm transmission capacity is reserved

by the Transmission Customer shall be set

forth in the Firm Point-To-Point Service

Agreement for Long-Term Firm Transmission

Service along with a corresponding capacity

reservation associated with each Point of

Delivery. Points of Delivery and

corresponding capacity reservations shall be

as mutually agreed upon by the Parties for

Short-Term Firm Transmission. The greater

of either (1) the sum of the capacity

reservations at the Point(s) of Receipt, or (2)

the sum of the capacity reservations at the

Point(s) of Delivery shall be the Transmission

Customer’s Reserved Capacity. The

Transmission Customer will be billed for its

Reserved Capacity under the terms of

Schedule 7. The Transmission Customer may

not exceed its firm capacity reserved at each

Point of Receipt and each Point of Delivery

except as otherwise specified in Section 22.

The Transmission Provider shall specify the

rate treatment and all related terms and

conditions applicable in the event that a

Transmission Customer (including ThirdParty Sales by the Transmission Provider)

exceeds its firm reserved capacity at any

Point of Receipt or Point of Delivery.

13.8 Scheduling of Firm Point-To-Point

Transmission Service: Schedules for the

Transmission Customer’s Firm Point-ToPoint Transmission Service must be

submitted to the Transmission Provider no

later than 10:00 a.m. [or a reasonable time

that is generally accepted in the region and

is consistently adhered to by the

Transmission Provider] of the day prior to

commencement of such service. Schedules

submitted after 10:00 a.m. will be

accommodated, if practicable. Hour-to-hour

schedules of any capacity and energy that is

to be delivered must be stated in increments

of 1,000 kW per hour [or a reasonable

increment that is generally accepted in the

region and is consistently adhered to by the

Transmission Provider]. Transmission

Customers within the Transmission

Provider’s service area with multiple requests

for Transmission Service at a Point of

Receipt, each of which is under 1,000 kW per

hour, may consolidate their service requests

at a common point of receipt into units of

1,000 kW per hour for scheduling and billing

purposes. Scheduling changes will be
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12471

permitted up to twenty (20) minutes [or a

reasonable time that is generally accepted in

the region and is consistently adhered to by

the Transmission Provider] before the start of

the next clock hour provided that the

Delivering Party and Receiving Party also

agree to the schedule modification. The

Transmission Provider will furnish to the

Delivering Party’s system operator, hour-tohour schedules equal to those furnished by

the Receiving Party (unless reduced for

losses) and shall deliver the capacity and

energy provided by such schedules. Should

the Transmission Customer, Delivering Party

or Receiving Party revise or terminate any

schedule, such party shall immediately

notify the Transmission Provider, and the

Transmission Provider shall have the right to

adjust accordingly the schedule for capacity

and energy to be received and to be

delivered.

14 Nature of Non-Firm Point-To-Point

Transmission Service

14.1 Term: Non-Firm Point-To-Point

Transmission Service will be available for

periods ranging from one (1) hour to one (1)

month. However, a Purchaser of Non-Firm

Point-To-Point Transmission Service will be

entitled to reserve a sequential term of

service (such as a sequential monthly term

without having to wait for the initial term to

expire before requesting another monthly

term) so that the total time period for which

the reservation applies is greater than one

month, subject to the requirements of Section

18.3.

14.2 Reservation Priority: Non-Firm

Point-To-Point Transmission Service shall be

available from transmission capability in

excess of that needed for reliable service to

Native Load Customers, Network Customers

and other Transmission Customers taking

Long-Term and Short-Term Firm Point-ToPoint Transmission Service. A higher priority

will be assigned to reservations with a longer

duration of service. In the event the

Transmission System is constrained,

competing requests of equal duration will be

prioritized based on the highest price offered

by the Eligible Customer for the

Transmission Service. Eligible Customers

that have already reserved shorter term

service have the right of first refusal to match

any longer term reservation before being

preempted. A longer term competing request

for Non-Firm Point-To-Point Transmission

Service will be granted if the Eligible

Customer with the right of first refusal does

not agree to match the competing request: (a)

immediately for hourly Non-Firm Point-ToPoint Transmission Service after notification

by the Transmission Provider; and, (b) within

24 hours (or earlier if necessary to comply

with the scheduling deadlines provided in

section 14.6) for Non-Firm Point-To-Point

Transmission Service other than hourly

transactions after notification by the

Transmission Provider. Transmission service

for Network Customers from resources other

than designated Network Resources will have

a higher priority than any Non-Firm PointTo-Point Transmission Service. Non-Firm

Point-To-Point Transmission Service over

secondary Point(s) of Receipt and Point(s) of

Delivery will have the lowest reservation

priority under the Tariff.

14.3 Use of Non-Firm Point-To-Point

Transmission Service by the Transmission

Provider: The Transmission Provider will be

subject to the rates, terms and conditions of

Part II of the Tariff when making Third-Party

Sales under (i) agreements executed on or

after [insert date sixty (60) days after

publication in Federal Register] or (ii)

agreements executed prior to the

aforementioned date that the Commission

requires to be unbundled, by the date

specified by the Commission. The

Transmission Provider will maintain separate

accounting, pursuant to Section 8 , for any

use of Non-Firm Point-To-Point

Transmission Service to make Third-Party

Sales.

14.4 Service Agreements: The

Transmission Provider shall offer a standard

form Non-Firm Point-To-Point Transmission

Service Agreement (Attachment B) to an

Eligible Customer when it first submits a

Completed Application for Non-Firm PointTo-Point Transmission Service pursuant to

the Tariff. Executed Service Agreements that

contain the information required under the

Tariff shall be filed with the Commission in

compliance with applicable Commission

regulations.

14.5 Classification of Non-Firm Point-ToPoint Transmission Service: Non-Firm PointTo-Point Transmission Service shall be

offered under terms and conditions

contained in Part II of the Tariff. The

Transmission Provider undertakes no

obligation under the Tariff to plan its

Transmission System in order to have

sufficient capacity for Non-Firm Point-ToPoint Transmission Service. Parties

requesting Non-Firm Point-To-Point

Transmission Service for the transmission of

firm power do so with the full realization

that such service is subject to availability and

to Curtailment or Interruption under the

terms of the Tariff. The Transmission

Provider shall specify the rate treatment and

all related terms and conditions applicable in

the event that a Transmission Customer

(including Third-Party Sales by the

Transmission Provider) exceeds its non-firm

capacity reservation. Non-Firm Point-ToPoint Transmission Service shall include

transmission of energy on an hourly basis

and transmission of scheduled short-term

capacity and energy on a daily, weekly or

monthly basis, but not to exceed one month’s

reservation for any one Application, under

Schedule 8.

14.6 Scheduling of Non-Firm Point-ToPoint Transmission Service: Schedules for

Non-Firm Point-To-Point Transmission

Service must be submitted to the

Transmission Provider no later than 2:00

p.m. [or a reasonable time that is generally

accepted in the region and is consistently

adhered to by the Transmission Provider] of

the day prior to commencement of such

service. Schedules submitted after 2:00 p.m.

will be accommodated, if practicable. Hourto-hour schedules of energy that is to be

delivered must be stated in increments of

1,000 kW per hour [or a reasonable increment

that is generally accepted in the region and

is consistently adhered to by the

Transmission Provider]. Transmission

Customers within the Transmission

Provider’s service area with multiple requests

for Transmission Service at a Point of

Receipt, each of which is under 1,000 kW per

hour, may consolidate their schedules at a

common Point of Receipt into units of 1,000

kW per hour. Scheduling changes will be

permitted up to twenty (20) minutes [or a

reasonable time that is generally accepted in

the region and is consistently adhered to by

the Transmission Provider] before the start of

the next clock hour provided that the

Delivering Party and Receiving Party also

agree to the schedule modification. The

Transmission Provider will furnish to the

Delivering Party’s system operator, hour-tohour schedules equal to those furnished by

the Receiving Party (unless reduced for

losses) and shall deliver the capacity and

energy provided by such schedules. Should

the Transmission Customer, Delivering Party

or Receiving Party revise or terminate any

schedule, such party shall immediately

notify the Transmission Provider, and the

Transmission Provider shall have the right to

adjust accordingly the schedule for capacity

and energy to be received and to be

delivered.

14.7 Curtailment or Interruption of

Service: The Transmission Provider reserves

the right to Curtail, in whole or in part, NonFirm Point-To-Point Transmission Service

provided under the Tariff for reliability

reasons when, an emergency or other

unforeseen condition threatens to impair or

degrade the reliability of its Transmission

System. The Transmission Provider reserves

the right to Interrupt, in whole or in part,

Non-Firm Point-To-Point Transmission

Service provided under the Tariff for

economic reasons in order to accommodate

(1) a request for Firm Transmission Service,

(2) a request for Non-Firm Point-To-Point

Transmission Service of greater duration, (3)

a request for Non-Firm Point-To-Point

Transmission Service of equal duration with

a higher price, or (4) transmission service for

Network Customers from non-designated

resources. The Transmission Provider also

will discontinue or reduce service to the

Transmission Customer to the extent that

deliveries for transmission are discontinued

or reduced at the Point(s) of Receipt. Where

required, Curtailments or Interruptions will

be made on a non-discriminatory basis to the

transaction(s) that effectively relieve the

constraint, however, Non-Firm Point-ToPoint Transmission Service shall be

subordinate to Firm Transmission Service. If

multiple transactions require Curtailment or

Interruption, to the extent practicable and

consistent with Good Utility Practice,

Curtailments or Interruptions will be made to

transactions of the shortest term (e.g., hourly

non-firm transactions will be Curtailed or

Interrupted before daily non-firm

transactions and daily non-firm transactions

will be Curtailed or Interrupted before

weekly non-firm transactions). Transmission

service for Network Customers from

resources other than designated Network

Resources will have a higher priority than

any Non-Firm Point-To-Point Transmission

Service under the Tariff. Non-Firm Point-ToPoint Transmission Service over secondary

Point(s) of Receipt and Point(s) of Delivery

will have a lower priority than any Non-Firm
12472 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

Point-To-Point Transmission Service under

the Tariff. The Transmission Provider will

provide advance notice of Curtailment or

Interruption where such notice can be

provided consistent with Good Utility

Practice.

15 Service Availability

15.1 General Conditions: The

Transmission Provider will provide Firm and

Non-Firm Point-To-Point Transmission

Service over, on or across its Transmission

System to any Transmission Customer that

has met the requirements of Section 16.

15.2 Determination of Available

Transmission Capability: A description of the

Transmission Provider’s specific

methodology for assessing available

transmission capability posted on the

Transmission Provider’s OASIS (Section ) is

contained in Attachment of the Tariff. In the

event sufficient transmission capability may

not exist to accommodate a service request,

the Transmission Provider will respond by

performing a System Impact Study.

15.3 Initiating Service in the Absence of

an Executed Service Agreement: If the

Transmission Provider and the Transmission

Customer requesting Firm or Non-Firm PointTo-Point Transmission Service cannot agree

on all the terms and conditions of the PointTo-Point Service Agreement, the

Transmission Provider shall file with the

Commission, within thirty (30) days after the

date the Transmission Customer provides

written notification directing the

Transmission Provider to file, an unexecuted

Point-To-Point Service Agreement containing

terms and conditions deemed appropriate by

the Transmission Provider for such requested

Transmission Service. The Transmission

Provider shall commence providing

Transmission Service subject to the

Transmission Customer agreeing to (i)

compensate the Transmission Provider at

whatever rate the Commission ultimately

determines to be just and reasonable, and (ii)

comply with the terms and conditions of the

Tariff including posting appropriate security

deposits in accordance with the terms of

Section 17.3.

15.4 Obligation to Provide Transmission

Service that Requires Expansion or

Modification of the Transmission System: If

the Transmission Provider determines that it

cannot accommodate a Completed

Application for Firm Point-To-Point

Transmission Service because of insufficient

capability on its Transmission System, the

Transmission Provider will use due diligence

to expand or modify its Transmission System

to provide the requested Firm Transmission

Service, provided the Transmission Customer

agrees to compensate the Transmission

Provider for such costs pursuant to the terms

of Section 27. The Transmission Provider

will conform to Good Utility Practice in

determining the need for new facilities and

in the design and construction of such

facilities. The obligation applies only to those

facilities that the Transmission Provider has

the right to expand or modify.

15.5 Deferral of Service: The

Transmission Provider may defer providing

service until it completes construction of

new transmission facilities or upgrades

needed to provide Firm Point-To-Point

Transmission Service whenever the

Transmission Provider determines that

providing the requested service would,

without such new facilities or upgrades,

impair or degrade reliability to any existing

firm services.

15.6 Other Transmission Service

Schedules: Eligible Customers receiving

transmission service under other agreements

on file with the Commission may continue to

receive transmission service under those

agreements until such time as those

agreements may be modified by the

Commission.

15.7 Real Power Losses: Real Power

Losses are associated with all transmission

service. The Transmission Provider is not

obligated to provide Real Power Losses. The

Transmission Customer is responsible for

replacing losses associated with all

transmission service as calculated by the

Transmission Provider. The applicable Real

Power Loss factors are as follows: [To be

completed by the Transmission Provider].

16 Transmission Customer Responsibilities

16.1 Conditions Required of

Transmission Customers: Point-To-Point

Transmission Service shall be provided by

the Transmission Provider only if the

following conditions are satisfied by the

Transmission Customer:

a. The Transmission Customer has pending

a Completed Application for service;

b. The Transmission Customer meets the

creditworthiness criteria set forth in Section

11;

c. The Transmission Customer will have

arrangements in place for any other

transmission service necessary to effect the

delivery from the generating source to the

Transmission Provider prior to the time

service under Part II of the Tariff commences;

d. The Transmission Customer agrees to

pay for any facilities constructed and

chargeable to such Transmission Customer

under Part II of the Tariff, whether or not the

Transmission Customer takes service for the

full term of its reservation; and

e. The Transmission Customer has

executed a Point-To-Point Service Agreement

or has agreed to receive service pursuant to

Section 15.3.

16.2 Transmission Customer

Responsibility for Third-Party Arrangements:

Any scheduling arrangements that may be

required by other electric systems shall be

the responsibility of the Transmission

Customer requesting service. The

Transmission Customer shall provide, unless

waived by the Transmission Provider,

notification to the Transmission Provider

identifying such systems and authorizing

them to schedule the capacity and energy to

be transmitted by the Transmission Provider

pursuant to Part II of the Tariff on behalf of

the Receiving Party at the Point of Delivery

or the Delivering Party at the Point of

Receipt. However, the Transmission Provider

will undertake reasonable efforts to assist the

Transmission Customer in making such

arrangements, including without limitation,

providing any information or data required

by such other electric system pursuant to

Good Utility Practice.

17 Procedures for Arranging Firm Point-ToPoint Transmission Service

17.1 Application: A request for Firm

Point-To-Point Transmission Service for

periods of one year or longer must contain a

written Application to: [Transmission

Provider Name and Address], at least sixty

(60) days in advance of the calendar month

in which service is to commence. The

Transmission Provider will consider requests

for such firm service on shorter notice when

feasible. Requests for firm service for periods

of less than one year shall be subject to

expedited procedures that shall be negotiated

between the Parties within the time

constraints provided in Section 17.5. All

Firm Point-To-Point Transmission Service

requests should be submitted by entering the

information listed below on the Transmission

Provider’s OASIS. Prior to implementation of

the Transmission Provider’s OASIS, a

Completed Application may be submitted by

(i) transmitting the required information to

the Transmission Provider by telefax, or (ii)

providing the information by telephone over

the Transmission Provider’s time recorded

telephone line. Each of these methods will

provide a time-stamped record for

establishing the priority of the Application.

17.2 Completed Application: A

Completed Application shall provide all of

the information included in 18 CFR § 2.20

including but not limited to the following:

(i) The identity, address, telephone number

and facsimile number of the entity requesting

service;

(ii) A statement that the entity requesting

service is, or will be upon commencement of

service, an Eligible Customer under the

Tariff;

(iii) The location of the Point(s) of Receipt

and Point(s) of Delivery and the identities of

the Delivering Parties and the Receiving

Parties;

(iv) The location of the generating

facility(ies) supplying the capacity and

energy and the location of the load ultimately

served by the capacity and energy

transmitted. The Transmission Provider will

treat this information as confidential except

to the extent that disclosure of this

information is required by this Tariff, by

regulatory or judicial order, for reliability

purposes pursuant to Good Utility Practice or

pursuant to RTG transmission information

sharing agreements. The Transmission

Provider shall treat this information

consistent with the standards of conduct

contained in Part 37 of the Commission’s

regulations;

(v) A description of the supply

characteristics of the capacity and energy to

be delivered;

(vi) An estimate of the capacity and energy

expected to be delivered to the Receiving

Party;

(vii) The Service Commencement Date and

the term of the requested Transmission

Service; and

(viii) The transmission capacity requested

for each Point of Receipt and each Point of

Delivery on the Transmission Provider’s

Transmission System; customers may

combine their requests for service in order to

satisfy the minimum transmission capacity

requirement.
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12473

The Transmission Provider shall treat this

information consistent with the standards of

conduct contained in Part 37 of the

Commission’s regulations.

17.3 Deposit: A Completed Application

for Firm Point-To-Point Transmission Service

also shall include a deposit of either one

month’s charge for Reserved Capacity or the

full charge for Reserved Capacity for service

requests of less than one month. If the

Application is rejected by the Transmission

Provider because it does not meet the

conditions for service as set forth herein, or

in the case of requests for service arising in

connection with losing bidders in a Request

For Proposals (RFP), said deposit shall be

returned with interest less any reasonable

costs incurred by the Transmission Provider

in connection with the review of the losing

bidder’s Application. The deposit also will

be returned with interest less any reasonable

costs incurred by the Transmission Provider

if the Transmission Provider is unable to

complete new facilities needed to provide the

service. If an Application is withdrawn or the

Eligible Customer decides not to enter into a

Service Agreement for Firm Point-To-Point

Transmission Service, the deposit shall be

refunded in full, with interest, less

reasonable costs incurred by the

Transmission Provider to the extent such

costs have not already been recovered by the

Transmission Provider from the Eligible

Customer. The Transmission Provider will

provide to the Eligible Customer a complete

accounting of all costs deducted from the

refunded deposit, which the Eligible

Customer may contest if there is a dispute

concerning the deducted costs. Deposits

associated with construction of new facilities

are subject to the provisions of Section 19. If

a Service Agreement for Firm Point-To-Point

Transmission Service is executed, the

deposit, with interest, will be returned to the

Transmission Customer upon expiration or

termination of the Service Agreement for

Firm Point-To-Point Transmission Service.

Applicable interest shall be computed in

accordance with the Commission’s

regulations at 18 CFR § 35.19a(a)(2)(iii), and

shall be calculated from the day the deposit

check is credited to the Transmission

Provider’s account.

17.4 Notice of Deficient Application: If an

Application fails to meet the requirements of

the Tariff, the Transmission Provider shall

notify the entity requesting service within

fifteen (15) days of receipt of the reasons for

such failure. The Transmission Provider will

attempt to remedy minor deficiencies in the

Application through informal

communications with the Eligible Customer.

If such efforts are unsuccessful, the

Transmission Provider shall return the

Application, along with any deposit, with

interest. Upon receipt of a new or revised

Application that fully complies with the

requirements of Part II of the Tariff, the

Eligible Customer shall be assigned a new

priority consistent with the date of the new

or revised Application.

17.5 Response to a Completed

Application: Following receipt of a

Completed Application for Firm Point-ToPoint Transmission Service, the

Transmission Provider shall make a

determination of available transmission

capability as required in Section 15.2. The

Transmission Provider shall notify the

Eligible Customer as soon as practicable, but

not later than thirty (30) days after the date

of receipt of a Completed Application either

(i) if it will be able to provide service without

performing a System Impact Study or (ii) if

such a study is needed to evaluate the impact

of the Application pursuant to Section 19.1.

Responses by the Transmission Provider

must be made as soon as practicable to all

completed applications (including

applications by its own merchant function)

and the timing of such responses must be

made on a non-discriminatory basis.

17.6 Execution of Service Agreement:

Whenever the Transmission Provider

determines that a System Impact Study is not

required and that the service can be

provided, it shall notify the Eligible

Customer as soon as practicable but no later

than thirty (30) days after receipt of the

Completed Application. Where a System

Impact Study is required, the provisions of

Section 19 will govern the execution of a

Service Agreement. Failure of an Eligible

Customer to execute and return the Service

Agreement or request the filing of an

unexecuted service agreement pursuant to

Section , within fifteen (15) days after it is

tendered by the Transmission Provider will

be deemed a withdrawal and termination of

the Application and any deposit submitted

shall be refunded with interest. Nothing

herein limits the right of an Eligible

Customer to file another Application after

such withdrawal and termination.

17.7 Extensions for Commencement of

Service: The Transmission Customer can

obtain up to five (5) one-year extensions for

the commencement of service. The

Transmission Customer may postpone

service by paying a non-refundable annual

reservation fee equal to one-month’s charge

for Firm Transmission Service for each year

or fraction thereof. If during any extension

for the commencement of service an Eligible

Customer submits a Completed Application

for Firm Transmission Service, and such

request can be satisfied only by releasing all

or part of the Transmission Customer’s

Reserved Capacity, the original Reserved

Capacity will be released unless the

following condition is satisfied. Within thirty

(30) days, the original Transmission

Customer agrees to pay the Firm Point-ToPoint transmission rate for its Reserved

Capacity concurrent with the new Service

Commencement Date. In the event the

Transmission Customer elects to release the

Reserved Capacity, the reservation fees or

portions thereof previously paid will be

forfeited.

18 Procedures for Arranging Non-Firm

Point-To-Point Transmission Service

18.1 Application: Eligible Customers

seeking Non-Firm Point-To-Point

Transmission Service must submit a

Completed Application to the Transmission

Provider. Applications should be submitted

by entering the information listed below on

the Transmission Provider’s OASIS. Prior to

implementation of the Transmission

Provider’s OASIS, a Completed Application

may be submitted by (i) transmitting the

required information to the Transmission

Provider by telefax, or (ii) providing the

information by telephone over the

Transmission Provider’s time recorded

telephone line. Each of these methods will

provide a time-stamped record for

establishing the service priority of the

Application.

18.2 Completed Application: A

Completed Application shall provide all of

the information included in 18 CFR § 2.20

including but not limited to the following:

(i) The identity, address, telephone number

and facsimile number of the entity requesting

service;

(ii) A statement that the entity requesting

service is, or will be upon commencement of

service, an Eligible Customer under the

Tariff;

(iii) The Point(s) of Receipt and the Point(s)

of Delivery;

(iv) The maximum amount of capacity

requested at each Point of Receipt and Point

of Delivery; and

(v) The proposed dates and hours for

initiating and terminating transmission

service hereunder.

In addition to the information specified

above, when required to properly evaluate

system conditions, the Transmission

Provider also may ask the Transmission

Customer to provide the following:

(vi) The electrical location of the initial

source of the power to be transmitted

pursuant to the Transmission Customer’s

request for service; and

(vii) The electrical location of the ultimate

load.

The Transmission Provider will treat this

information in (vi) and (vii) as confidential

at the request of the Transmission Customer

except to the extent that disclosure of this

information is required by this Tariff, by

regulatory or judicial order, for reliability

purposes pursuant to Good Utility Practice,

or pursuant to RTG transmission information

sharing agreements. The Transmission

Provider shall treat this information

consistent with the standards of conduct

contained in Part 37 of the Commission’s

regulations.

18.3 Reservation of Non-Firm Point-ToPoint Transmission Service: Requests for

monthly service shall be submitted no earlier

than sixty (60) days before service is to

commence; requests for weekly service shall

be submitted no earlier than fourteen (14)

days before service is to commence, requests

for daily service shall be submitted no earlier

than two (2) days before service is to

commence, and requests for hourly service

shall be submitted no earlier than noon the

day before service is to commence. Requests

for service received later than 2:00 p.m. prior

to the day service is scheduled to commence

will be accommodated if practicable [or such

reasonable times that are generally accepted

in the region and are consistently adhered to

by the Transmission Provider].

18.4 Determination of Available

Transmission Capability: Following receipt

of a tendered schedule the Transmission

Provider will make a determination on a nondiscriminatory basis of available

transmission capability pursuant to Section
12474 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

15.2. Such determination shall be made as

soon as reasonably practicable after receipt,

but not later than the following time periods

for the following terms of service (i) thirty

(30) minutes for hourly service, (ii) thirty (30)

minutes for daily service, (iii) four (4) hours

for weekly service, and (iv) two (2) days for

monthly service. [Or such reasonable times

that are generally accepted in the region and

are consistently adhered to by the

Transmission Provider].

19 Additional Study Procedures For Firm

Point-To-Point Transmission Service

Requests

Notice of Need for System Impact Study:

After receiving a request for service, the

Transmission Provider shall determine on a

non-discriminatory basis whether a System

Impact Study is needed. A description of the

Transmission Provider’s methodology for

completing a System Impact Study is

provided in Attachment D. If the

Transmission Provider determines that a

System Impact Study is necessary to

accommodate the requested service, it shall

so inform the Eligible Customer, as soon as

practicable. In such cases, the Transmission

Provider shall within thirty (30) days of

receipt of a Completed Application, tender a

System Impact Study Agreement pursuant to

which the Eligible Customer shall agree to

reimburse the Transmission Provider for

performing the required System Impact

Study. For a service request to remain a

Completed Application, the Eligible

Customer shall execute the System Impact

Study Agreement and return it to the

Transmission Provider within fifteen (15)

days. If the Eligible Customer elects not to

execute the System Impact Study Agreement,

its application shall be deemed withdrawn

and its deposit, pursuant to Section 17.3 ,

shall be returned with interest.

19.2 System Impact Study Agreement and

Cost Reimbursement:

(i) The System Impact Study Agreement

will clearly specify the Transmission

Provider’s estimate of the actual cost, and

time for completion of the System Impact

Study. The charge shall not exceed the actual

cost of the study. In performing the System

Impact Study, the Transmission Provider

shall rely, to the extent reasonably

practicable, on existing transmission

planning studies. The Eligible Customer will

not be assessed a charge for such existing

studies; however, the Eligible Customer will

be responsible for charges associated with

any modifications to existing planning

studies that are reasonably necessary to

evaluate the impact of the Eligible

Customer’s request for service on the

Transmission System.

(ii) If in response to multiple Eligible

Customers requesting service in relation to

the same competitive solicitation, a single

System Impact Study is sufficient for the

Transmission Provider to accommodate the

requests for service, the costs of that study

shall be pro-rated among the Eligible

Customers.

(iii) For System Impact Studies that the

Transmission Provider conducts on its own

behalf, the Transmission Provider shall

record the cost of the System Impact Studies

pursuant to Section 20.

19.3 System Impact Study Procedures:

Upon receipt of an executed System Impact

Study Agreement, the Transmission Provider

will use due diligence to complete the

required System Impact Study within a sixty

(60) day period. The System Impact Study

shall identify any system constraints and

redispatch options, additional Direct

Assignment Facilities or Network Upgrades

required to provide the requested service. In

the event that the Transmission Provider is

unable to complete the required System

Impact Study within such time period, it

shall so notify the Eligible Customer and

provide an estimated completion date along

with an explanation of the reasons why

additional time is required to complete the

required studies. A copy of the completed

System Impact Study and related work

papers shall be made available to the Eligible

Customer. The Transmission Provider will

use the same due diligence in completing the

System Impact Study for an Eligible

Customer as it uses when completing studies

for itself. The Transmission Provider shall

notify the Eligible Customer immediately

upon completion of the System Impact Study

if the Transmission System will be adequate

to accommodate all or part of a request for

service or that no costs are likely to be

incurred for new transmission facilities or

upgrades. In order for a request to remain a

Completed Application, within fifteen (15)

days of completion of the System Impact

Study the Eligible Customer must execute a

Service Agreement or request the filing of an

unexecuted Service Agreement pursuant to

Section 15.3, or the Application shall be

deemed terminated and withdrawn.

19.4 Facilities Study Procedures: If a

System Impact Study indicates that additions

or upgrades to the Transmission System are

needed to supply the Eligible Customer’s

service request, the Transmission Provider,

within thirty (30) days of the completion of

the System Impact Study, shall tender to the

Eligible Customer a Facilities Study

Agreement pursuant to which the Eligible

Customer shall agree to reimburse the

Transmission Provider for performing the

required Facilities Study. For a service

request to remain a Completed Application,

the Eligible Customer shall execute the

Facilities Study Agreement and return it to

the Transmission Provider within fifteen (15)

days. If the Eligible Customer elects not to

execute the Facilities Study Agreement, its

application shall be deemed withdrawn and

its deposit, pursuant to Section 17.3, shall be

returned with interest. Upon receipt of an

executed Facilities Study Agreement, the

Transmission Provider will use due diligence

to complete the required Facilities Study

within a sixty (60) day period. If the

Transmission Provider is unable to complete

the Facilities Study in the allotted time

period, the Transmission Provider shall

notify the Transmission Customer and

provide an estimate of the time needed to

reach a final determination along with an

explanation of the reasons that additional

time is required to complete the study. When

completed, the Facilities Study will include

a good faith estimate of (i) the cost of Direct

Assignment Facilities to be charged to the

Transmission Customer, (ii) the Transmission

Customer’s appropriate share of the cost of

any required Network Upgrades as

determined pursuant to the provisions of Part

II of the Tariff, and (iii) the time required to

complete such construction and initiate the

requested service. The Transmission

Customer shall provide the Transmission

Provider with a letter of credit or other

reasonable form of security acceptable to the

Transmission Provider equivalent to the costs

of new facilities or upgrades consistent with

commercial practices as established by the

Uniform Commercial Code. The

Transmission Customer shall have thirty (30)

days to execute a Service Agreement or

request the filing of an unexecuted Service

Agreement and provide the required letter of

credit or other form of security or the request

will no longer be a Completed Application

and shall be deemed terminated and

withdrawn.

19.5 Facilities Study Modifications: Any

change in design arising from inability to site

or construct facilities as proposed will

require development of a revised good faith

estimate. New good faith estimates also will

be required in the event of new statutory or

regulatory requirements that are effective

before the completion of construction or

other circumstances beyond the control of

the Transmission Provider that significantly

affect the final cost of new facilities or

upgrades to be charged to the Transmission

Customer pursuant to the provisions of Part

II of the Tariff.

19.6 Due Diligence in Completing New

Facilities: The Transmission Provider shall

use due diligence to add necessary facilities

or upgrade its Transmission System within a

reasonable time. The Transmission Provider

will not upgrade its existing or planned

Transmission System in order to provide the

requested Firm Point-To-Point Transmission

Service if doing so would impair system

reliability or otherwise impair or degrade

existing firm service.

19.7 Partial Interim Service: If the

Transmission Provider determines that it will

not have adequate transmission capability to

satisfy the full amount of a Completed

Application for Firm Point-To-Point

Transmission Service, the Transmission

Provider nonetheless shall be obligated to

offer and provide the portion of the requested

Firm Point-To-Point Transmission Service

that can be accommodated without addition

of any facilities and through redispatch.

However, the Transmission Provider shall

not be obligated to provide the incremental

amount of requested Firm Point-To-Point

Transmission Service that requires the

addition of facilities or upgrades to the

Transmission System until such facilities or

upgrades have been placed in service.

19.8 Expedited Procedures for New

Facilities: In lieu of the procedures set forth

above, the Eligible Customer shall have the

option to expedite the process by requesting

the Transmission Provider to tender at one

time, together with the results of required

studies, an ‘‘Expedited Service Agreement’’

pursuant to which the Eligible Customer

would agree to compensate the Transmission

Provider for all costs incurred pursuant to the

terms of the Tariff. In order to exercise this

option, the Eligible Customer shall request in
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writing an expedited Service Agreement

covering all of the above-specified items

within thirty (30) days of receiving the

results of the System Impact Study

identifying needed facility additions or

upgrades or costs incurred in providing the

requested service. While the Transmission

Provider agrees to provide the Eligible

Customer with its best estimate of the new

facility costs and other charges that may be

incurred, such estimate shall not be binding

and the Eligible Customer must agree in

writing to compensate the Transmission

Provider for all costs incurred pursuant to the

provisions of the Tariff. The Eligible

Customer shall execute and return such an

Expedited Service Agreement within fifteen

(15) days of its receipt or the Eligible

Customer’s request for service will cease to

be a Completed Application and will be

deemed terminated and withdrawn.

20 Procedures if The Transmission Provider

is Unable to Complete New Transmission

Facilities for Firm Point-To-Point

Transmission Service

20.1 Delays in Construction of New

Facilities: If any event occurs that will

materially affect the time for completion of

new facilities, or the ability to complete

them, the Transmission Provider shall

promptly notify the Transmission Customer.

In such circumstances, the Transmission

Provider shall within thirty (30) days of

notifying the Transmission Customer of such

delays, convene a technical meeting with the

Transmission Customer to evaluate the

alternatives available to the Transmission

Customer. The Transmission Provider also

shall make available to the Transmission

Customer studies and work papers related to

the delay, including all information that is in

the possession of the Transmission Provider

that is reasonably needed by the

Transmission Customer to evaluate any

alternatives.

20.2 Alternatives to the Original Facility

Additions: When the review process of

Section determines that one or more

alternatives exist to the originally planned

construction project, the Transmission

Provider shall present such alternatives for

consideration by the Transmission Customer.

If, upon review of any alternatives, the

Transmission Customer desires to maintain

its Completed Application subject to

construction of the alternative facilities, it

may request the Transmission Provider to

submit a revised Service Agreement for Firm

Point-To-Point Transmission Service. If the

alternative approach solely involves NonFirm Point-To-Point Transmission Service,

the Transmission Provider shall promptly

tender a Service Agreement for Non-Firm

Point-To-Point Transmission Service

providing for the service. In the event the

Transmission Provider concludes that no

reasonable alternative exists and the

Transmission Customer disagrees, the

Transmission Customer may seek relief

under the dispute resolution procedures

pursuant to Section or it may refer the

dispute to the Commission for resolution.

20.3 Refund Obligation for Unfinished

Facility Additions: If the Transmission

Provider and the Transmission Customer

mutually agree that no other reasonable

alternatives exist and the requested service

cannot be provided out of existing capability

under the conditions of Part II of the Tariff,

the obligation to provide the requested Firm

Point-To-Point Transmission Service shall

terminate and any deposit made by the

Transmission Customer shall be returned

with interest pursuant to Commission

regulations 35.19a(a)(2)(iii). However, the

Transmission Customer shall be responsible

for all prudently incurred costs by the

Transmission Provider through the time

construction was suspended.

21 Provisions Relating to Transmission

Construction and Services on the Systems of

Other Utilities

21.1 Responsibility for Third-Party

System Additions: The Transmission

Provider shall not be responsible for making

arrangements for any necessary engineering,

permitting, and construction of transmission

or distribution facilities on the system(s) of

any other entity or for obtaining any

regulatory approval for such facilities. The

Transmission Provider will undertake

reasonable efforts to assist the Transmission

Customer in obtaining such arrangements,

including without limitation, providing any

information or data required by such other

electric system pursuant to Good Utility

Practice.

21.2 Coordination of Third-Party System

Additions: In circumstances where the need

for transmission facilities or upgrades is

identified pursuant to the provisions of Part

II of the Tariff, and if such upgrades further

require the addition of transmission facilities

on other systems, the Transmission Provider

shall have the right to coordinate

construction on its own system with the

construction required by others. The

Transmission Provider, after consultation

with the Transmission Customer and

representatives of such other systems, may

defer construction of its new transmission

facilities, if the new transmission facilities on

another system cannot be completed in a

timely manner. The Transmission Provider

shall notify the Transmission Customer in

writing of the basis for any decision to defer

construction and the specific problems

which must be resolved before it will initiate

or resume construction of new facilities.

Within sixty (60) days of receiving written

notification by the Transmission Provider of

its intent to defer construction pursuant to

this section, the Transmission Customer may

challenge the decision in accordance with

the dispute resolution procedures pursuant

to Section 12 or it may refer the dispute to

the Commission for resolution.

22 Changes in Service Specifications

22.1 Modifications On a Non-Firm Basis:

The Transmission Customer taking Firm

Point-To-Point Transmission Service may

request the Transmission Provider to provide

transmission service on a non-firm basis over

Receipt and Delivery Points other than those

specified in the Service Agreement

(‘‘Secondary Receipt and Delivery Points’’),

in amounts not to exceed its firm capacity

reservation, without incurring an additional

Non-Firm Point-To-Point Transmission

Service charge or executing a new Service

Agreement, subject to the following

conditions.

(a) Service provided over Secondary

Receipt and Delivery Points will be non-firm

only, on an as-available basis and will not

displace any firm or non-firm service

reserved or scheduled by third parties under

the Tariff or by the Transmission Provider on

behalf of its Native Load Customers.

(b) The sum of all Firm and non-firm PointTo-Point Transmission Service provided to

the Transmission Customer at any time

pursuant to this section shall not exceed the

Reserved Capacity in the relevant Service

Agreement under which such services are

provided.

(c) The Transmission Customer shall retain

its right to schedule Firm Point-To-Point

Transmission Service at the Receipt and

Delivery Points specified in the relevant

Service Agreement in the amount of its

original capacity reservation.

(d) Service over Secondary Receipt and

Delivery Points on a non-firm basis shall not

require the filing of an Application for NonFirm Point-To-Point Transmission Service

under the Tariff. However, all other

requirements of Part II of the Tariff (except

as to transmission rates) shall apply to

transmission service on a non-firm basis over

Secondary Receipt and Delivery Points.

22.2 Modification On a Firm Basis: Any

request by a Transmission Customer to

modify Receipt and Delivery Points on a firm

basis shall be treated as a new request for

service in accordance with Section 17 hereof,

except that such Transmission Customer

shall not be obligated to pay any additional

deposit if the capacity reservation does not

exceed the amount reserved in the existing

Service Agreement. While such new request

is pending, the Transmission Customer shall

retain its priority for service at the existing

firm Receipt and Delivery Points specified in

its Service Agreement.

23 Sale or Assignment of Transmission

Service

23.1 Procedures for Assignment or

Transfer of Service: Subject to Commission

approval of any necessary filings, a

Transmission Customer may sell, assign, or

transfer all or a portion of its rights under its

Service Agreement, but only to another

Eligible Customer (the Assignee). The

Transmission Customer that sells, assigns or

transfers its rights under its Service

Agreement is hereafter referred to as the

Reseller. Compensation to the Reseller shall

not exceed the higher of (i) the original rate

paid by the Reseller, (ii) the Transmission

Provider’s maximum rate on file at the time

of the assignment, or (iii) the Reseller’s

opportunity cost capped at the Transmission

Provider’s cost of expansion. If the Assignee

does not request any change in the Point(s)

of Receipt or the Point(s) of Delivery, or a

change in any other term or condition set

forth in the original Service Agreement, the

Assignee will receive the same services as

did the Reseller and the priority of service for

the Assignee will be the same as that of the

Reseller. A Reseller should notify the

Transmission Provider as soon as possible

after any assignment or transfer of service
12476 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

occurs but in any event, notification must be

provided prior to any provision of service to

the Assignee. The Assignee will be subject to

all terms and conditions of this Tariff. If the

Assignee requests a change in service, the

reservation priority of service will be

determined by the Transmission Provider

pursuant to Section 13.2.

23.2 Limitations on Assignment or

Transfer of Service: If the Assignee requests

a change in the Point(s) of Receipt or Point(s)

of Delivery, or a change in any other

specifications set forth in the original Service

Agreement, the Transmission Provider will

consent to such change subject to the

provisions of the Tariff, provided that the

change will not impair the operation and

reliability of the Transmission Provider’s

generation, transmission, or distribution

systems. The Assignee shall compensate the

Transmission Provider for performing any

System Impact Study needed to evaluate the

capability of the Transmission System to

accommodate the proposed change and any

additional costs resulting from such change.

The Reseller shall remain liable for the

performance of all obligations under the

Service Agreement, except as specifically

agreed to by the Parties through an

amendment to the Service Agreement.

23.3 Information on Assignment or

Transfer of Service: In accordance with

Section 4, Resellers may use the

Transmission Provider’s OASIS to post

transmission capacity available for resale.

24 Metering and Power Factor Correction at

Receipt and Delivery Point(s)

24.1 Transmission Customer Obligations:

Unless otherwise agreed, the Transmission

Customer shall be responsible for installing

and maintaining compatible metering and

communications equipment to accurately

account for the capacity and energy being

transmitted under Part II of the Tariff and to

communicate the information to the

Transmission Provider. Such equipment

shall remain the property of the

Transmission Customer.

24.2 Transmission Provider Access to

Metering Data: The Transmission Provider

shall have access to metering data, which

may reasonably be required to facilitate

measurements and billing under the Service

Agreement.

24.3 Power Factor: Unless otherwise

agreed, the Transmission Customer is

required to maintain a power factor within

the same range as the Transmission Provider

pursuant to Good Utility Practices. The

power factor requirements are specified in

the Service Agreement where applicable.

25 Compensation for Transmission Service

Rates for Firm and Non-Firm Point-ToPoint Transmission Service are provided in

the Schedules appended to the Tariff: Firm

Point-To-Point Transmission Service

(Schedule 7); and Non-Firm Point-To-Point

Transmission Service (Schedule 8). The

Transmission Provider shall use Part II of the

Tariff to make its Third-Party Sales. The

Transmission Provider shall account for such

use at the applicable Tariff rates, pursuant to

Section 8.

26 Stranded Cost Recovery

The Transmission Provider may seek to

recover stranded costs from the Transmission

Customer pursuant to this Tariff in

accordance with the terms, conditions and

procedures set forth in FERC Order No. 888.

However, the Transmission Provider must

separately file any specific proposed

stranded cost charge under Section 205 of the

Federal Power Act.

27 Compensation for New Facilities and

Redispatch Costs

Whenever a System Impact Study

performed by the Transmission Provider in

connection with the provision of Firm PointTo-Point Transmission Service identifies the

need for new facilities, the Transmission

Customer shall be responsible for such costs

to the extent consistent with Commission

policy. Whenever a System Impact Study

performed by the Transmission Provider

identifies capacity constraints that may be

relieved more economically by redispatching

the Transmission Provider’s resources than

by building new facilities or upgrading

existing facilities to eliminate such

constraints, the Transmission Customer shall

be responsible for the redispatch costs to the

extent consistent with Commission policy.

III. Network Integration Transmission

Service

Preamble

The Transmission Provider will provide

Network Integration Transmission Service

pursuant to the applicable terms and

conditions contained in the Tariff and

Service Agreement. Network Integration

Transmission Service allows the Network

Customer to integrate, economically dispatch

and regulate its current and planned Network

Resources to serve its Network Load in a

manner comparable to that in which the

Transmission Provider utilizes its

Transmission System to serve its Native Load

Customers. Network Integration

Transmission Service also may be used by

the Network Customer to deliver economy

energy purchases to its Network Load from

non-designated resources on an as-available

basis without additional charge.

Transmission service for sales to nondesignated loads will be provided pursuant

to the applicable terms and conditions of Part

II of the Tariff.

28 Nature of Network Integration

Transmission Service

28.1 Scope of Service: Network

Integration Transmission Service is a

transmission service that allows Network

Customers to efficiently and economically

utilize their Network Resources (as well as

other non-designated generation resources) to

serve their Network Load located in the

Transmission Provider’s Control Area and

any additional load that may be designated

pursuant to Section 31.3 of the Tariff. The

Network Customer taking Network

Integration Transmission Service must obtain

or provide Ancillary Services pursuant to

Section 3.

28.2 Transmission Provider

Responsibilities: The Transmission Provider

will plan, construct, operate and maintain its

Transmission System in accordance with

Good Utility Practice in order to provide the

Network Customer with Network Integration

Transmission Service over the Transmission

Provider’s Transmission System. The

Transmission Provider, on behalf of its

Native Load Customers, shall be required to

designate resources and loads in the same

manner as any Network Customer under Part

III of this Tariff. This information must be

consistent with the information used by the

Transmission Provider to calculate available

transmission capability. The Transmission

Provider shall include the Network

Customer’s Network Load in its Transmission

System planning and shall, consistent with

Good Utility Practice, endeavor to construct

and place into service sufficient transmission

capacity to deliver the Network Customer’s

Network Resources to serve its Network Load

on a basis comparable to the Transmission

Provider’s delivery of its own generating and

purchased resources to its Native Load

Customers.

28.3 Network Integration Transmission

Service: The Transmission Provider will

provide firm transmission service over its

Transmission System to the Network

Customer for the delivery of capacity and

energy from its designated Network

Resources to service its Network Loads on a

basis that is comparable to the Transmission

Provider’s use of the Transmission System to

reliably serve its Native Load Customers.

28.4 Secondary Service: The Network

Customer may use the Transmission

Provider’s Transmission System to deliver

energy to its Network Loads from resources

that have not been designated as Network

Resources. Such energy shall be transmitted,

on an as-available basis, at no additional

charge. Deliveries from resources other than

Network Resources will have a higher

priority than any Non-Firm Point-To-Point

Transmission Service under Part II of the

Tariff.

28.5 Real Power Losses: Real Power

Losses are associated with all transmission

service. The Transmission Provider is not

obligated to provide Real Power Losses. The

Network Customer is responsible for

replacing losses associated with all

transmission service as calculated by the

Transmission Provider. The applicable Real

Power Loss factors are as follows: [To be

completed by the Transmission Provider].

28.6 Restrictions on Use of Service: The

Network Customer shall not use Network

Integration Transmission Service for (i) sales

of capacity and energy to non-designated

loads, or (ii) direct or indirect provision of

transmission service by the Network

Customer to third parties. All Network

Customers taking Network Integration

Transmission Service shall use Point-ToPoint Transmission Service under Part II of

the Tariff for any Third-Party Sale which

requires use of the Transmission Provider’s

Transmission System.

29 Initiating Service

29.1 Condition Precedent for Receiving

Service: Subject to the terms and conditions

of Part III of the Tariff, the Transmission

Provider will provide Network Integration

Transmission Service to any Eligible
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12477

Customer, provided that (i) the Eligible

Customer completes an Application for

service as provided under Part III of the

Tariff, (ii) the Eligible Customer and the

Transmission Provider complete the

technical arrangements set forth in Sections

29.3 and 29.4, (iii) the Eligible Customer

executes a Service Agreement pursuant to

Attachment F for service under Part III of the

Tariff or requests in writing that the

Transmission Provider file a proposed

unexecuted Service Agreement with the

Commission, and (iv) the Eligible Customer

executes a Network Operating Agreement

with the Transmission Provider pursuant to

Attachment G.

29.2 Application Procedures: An Eligible

Customer requesting service under Part III of

the Tariff must submit an Application, with

a deposit approximating the charge for one

month of service, to the Transmission

Provider as far as possible in advance of the

month in which service is to commence.

Unless subject to the procedures in Section

2, Completed Applications for Network

Integration Transmission Service will be

assigned a priority according to the date and

time the Application is received, with the

earliest Application receiving the highest

priority. Applications should be submitted

by entering the information listed below on

the Transmission Provider’s OASIS. Prior to

implementation of the Transmission

Provider’s OASIS, a Completed Application

may be submitted by (i) transmitting the

required information to the Transmission

Provider by telefax, or (ii) providing the

information by telephone over the

Transmission Provider’s time recorded

telephone line. Each of these methods will

provide a time-stamped record for

establishing the service priority of the

Application. A Completed Application shall

provide all of the information included in 18

CFR § 2.20 including but not limited to the

following:

(i) The identity, address, telephone number

and facsimile number of the party requesting

service;

(ii) A statement that the party requesting

service is, or will be upon commencement of

service, an Eligible Customer under the

Tariff;

(iii) A description of the Network Load at

each delivery point. This description should

separately identify and provide the Eligible

Customer’s best estimate of the total loads to

be served at each transmission voltage level,

and the loads to be served from each

Transmission Provider substation at the same

transmission voltage level. The description

should include a ten (10) year forecast of

summer and winter load and resource

requirements beginning with the first year

after the service is scheduled to commence;

(iv) The amount and location of any

interruptible loads included in the Network

Load. This shall include the summer and

winter capacity requirements for each

interruptible load (had such load not been

interruptible), that portion of the load subject

to interruption, the conditions under which

an interruption can be implemented and any

limitations on the amount and frequency of

interruptions. An Eligible Customer should

identify the amount of interruptible customer

load (if any) included in the 10 year load

forecast provided in response to (iii) above;

(v) A description of Network Resources

(current and 10-year projection), which shall

include, for each Network Resource:

—Unit size and amount of capacity from that

unit to be designated as Network Resource

—VAR capability (both leading and lagging)

of all generators

—Operating restrictions

—Any periods of restricted operations

throughout the year

—Maintenance schedules

—Minimum loading level of unit

—Normal operating level of unit

—Any must-run unit designations required

for system reliability or contract reasons

—Approximate variable generating cost ($/

MWH) for redispatch computations

—Arrangements governing sale and delivery

of power to third parties from generating

facilities located in the Transmission

Provider Control Area, where only a

portion of unit output is designated as a

Network Resource

—Description of purchased power designated

as a Network Resource including source of

supply, Control Area location,

transmission arrangements and delivery

point(s) to the Transmission Provider’s

Transmission System;

(vi) Description of Eligible Customer’s

transmission system:

—Load flow and stability data, such as real

and reactive parts of the load, lines,

transformers, reactive devices and load

type, including normal and emergency

ratings of all transmission equipment in a

load flow format compatible with that used

by the Transmission Provider

—Operating restrictions needed for reliability

—Operating guides employed by system

operators

—Contractual restrictions or committed uses

of the Eligible Customer’s transmission

system, other than the Eligible Customer’s

Network Loads and Resources

—Location of Network Resources described

in subsection (v) above

—10 year projection of system expansions or

upgrades

—Transmission System maps that include

any proposed expansions or upgrades

—Thermal ratings of Eligible Customer’s

Control Area ties with other Control Areas;

and

(vii) Service Commencement Date and the

term of the requested Network Integration

Transmission Service. The minimum term for

Network Integration Transmission Service is

one year.

Unless the Parties agree to a different time

frame, the Transmission Provider must

acknowledge the request within ten (10) days

of receipt. The acknowledgement must

include a date by which a response,

including a Service Agreement, will be sent

to the Eligible Customer. If an Application

fails to meet the requirements of this section,

the Transmission Provider shall notify the

Eligible Customer requesting service within

fifteen (15) days of receipt and specify the

reasons for such failure. Wherever possible,

the Transmission Provider will attempt to

remedy deficiencies in the Application

through informal communications with the

Eligible Customer. If such efforts are

unsuccessful, the Transmission Provider

shall return the Application without

prejudice to the Eligible Customer filing a

new or revised Application that fully

complies with the requirements of this

section. The Eligible Customer will be

assigned a new priority consistent with the

date of the new or revised Application. The

Transmission Provider shall treat this

information consistent with the standards of

conduct contained in Part 37 of the

Commission’s regulations.

29.3 Technical Arrangements to be

Completed Prior to Commencement of

Service: Network Integration Transmission

Service shall not commence until the

Transmission Provider and the Network

Customer, or a third party, have completed

installation of all equipment specified under

the Network Operating Agreement consistent

with Good Utility Practice and any additional

requirements reasonably and consistently

imposed to ensure the reliable operation of

the Transmission System. The Transmission

Provider shall exercise reasonable efforts, in

coordination with the Network Customer, to

complete such arrangements as soon as

practicable taking into consideration the

Service Commencement Date.

29.4 Network Customer Facilities: The

provision of Network Integration

Transmission Service shall be conditioned

upon the Network Customer’s constructing,

maintaining and operating the facilities on its

side of each delivery point or interconnection

necessary to reliably deliver capacity and

energy from the Transmission Provider’s

Transmission System to the Network

Customer. The Network Customer shall be

solely responsible for constructing or

installing all facilities on the Network

Customer’s side of each such delivery point

or interconnection.

29.5 Filing of Service Agreement: The

Transmission Provider will file Service

Agreements with the Commission in

compliance with applicable Commission

regulations.

30 Network Resources

30.1 Designation of Network Resources:

Network Resources shall include all

generation owned, purchased or leased by

the Network Customer designated to serve

Network Load under the Tariff. Network

Resources may not include resources, or any

portion thereof, that are committed for sale

to non-designated third party load or

otherwise cannot be called upon to meet the

Network Customer’s Network Load on a noninterruptible basis. Any owned or purchased

resources that were serving the Network

Customer’s loads under firm agreements

entered into on or before the Service

Commencement Date shall initially be

designated as Network Resources until the

Network Customer terminates the

designation of such resources.

30.2 Designation of New Network

Resources: The Network Customer may

designate a new Network Resource by

providing the Transmission Provider with as

much advance notice as practicable. A

designation of a new Network Resource must
12478 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

be made by a request for modification of

service pursuant to an Application under

Section 29.

30.3 Termination of Network Resources:

The Network Customer may terminate the

designation of all or part of a generating

resource as a Network Resource at any time

but should provide notification to the

Transmission Provider as soon as reasonably

practicable.

30.4 Operation of Network Resources:

The Network Customer shall not operate its

designated Network Resources located in the

Network Customer’s or Transmission

Provider’s Control Area such that the output

of those facilities exceeds its designated

Network Load, plus non-firm sales delivered

pursuant to Part II of the Tariff, plus losses.

This limitation shall not apply to changes in

the operation of a Transmission Customer’s

Network Resources at the request of the

Transmission Provider to respond to an

emergency or other unforeseen condition

which may impair or degrade the reliability

of the Transmission System.

30.5 Network Customer Redispatch

Obligation: As a condition to receiving

Network Integration Transmission Service,

the Network Customer agrees to redispatch

its Network Resources as requested by the

Transmission Provider pursuant to Section

33.2. To the extent practical, the redispatch

of resources pursuant to this section shall be

on a least cost, non-discriminatory basis

between all Network Customers, and the

Transmission Provider.

30.6 Transmission Arrangements for

Network Resources Not Physically

Interconnected With The Transmission

Provider: The Network Customer shall be

responsible for any arrangements necessary

to deliver capacity and energy from a

Network Resource not physically

interconnected with the Transmission

Provider’s Transmission System. The

Transmission Provider will undertake

reasonable efforts to assist the Network

Customer in obtaining such arrangements,

including without limitation, providing any

information or data required by such other

entity pursuant to Good Utility Practice.

30.7 Limitation on Designation of

Network Resources: The Network Customer

must demonstrate that it owns or has

committed to purchase generation pursuant

to an executed contract in order to designate

a generating resource as a Network Resource.

Alternatively, the Network Customer may

establish that execution of a contract is

contingent upon the availability of

transmission service under Part III of the

Tariff.

30.8 Use of Interface Capacity by the

Network Customer: There is no limitation

upon a Network Customer’s use of the

Transmission Provider’s Transmission

System at any particular interface to integrate

the Network Customer’s Network Resources

(or substitute economy purchases) with its

Network Loads. However, a Network

Customer’s use of the Transmission

Provider’s total interface capacity with other

transmission systems may not exceed the

Network Customer’s Load.

30.9 Network Customer Owned

Transmission Facilities: The Network

Customer that owns existing transmission

facilities that are integrated with the

Transmission Provider’s Transmission

System may be eligible to receive

consideration either through a billing credit

or some other mechanism. In order to receive

such consideration the Network Customer

must demonstrate that its transmission

facilities are integrated into the plans or

operations of the Transmission Provider to

serve its power and transmission customers.

For facilities constructed by the Network

Customer subsequent to the Service

Commencement Date under Part III of the

Tariff, the Network Customer shall receive

credit where such facilities are jointly

planned and installed in coordination with

the Transmission Provider. Calculation of the

credit shall be addressed in either the

Network Customer’s Service Agreement or

any other agreement between the Parties.

31 Designation of Network Load

31.1 Network Load: The Network

Customer must designate the individual

Network Loads on whose behalf the

Transmission Provider will provide Network

Integration Transmission Service. The

Network Loads shall be specified in the

Service Agreement.

31.2 New Network Loads Connected With

the Transmission Provider: The Network

Customer shall provide the Transmission

Provider with as much advance notice as

reasonably practicable of the designation of

new Network Load that will be added to its

Transmission System. A designation of new

Network Load must be made through a

modification of service pursuant to a new

Application. The Transmission Provider will

use due diligence to install any transmission

facilities required to interconnect a new

Network Load designated by the Network

Customer. The costs of new facilities

required to interconnect a new Network Load

shall be determined in accordance with the

procedures provided in Section and shall be

charged to the Network Customer in

accordance with Commission policies.

31.3 Network Load Not Physically

Interconnected with the Transmission

Provider: This section applies to both initial

designation pursuant to Section and the

subsequent addition of new Network Load

not physically interconnected with the

Transmission Provider. To the extent that the

Network Customer desires to obtain

transmission service for a load outside the

Transmission Provider’s Transmission

System, the Network Customer shall have the

option of (1) electing to include the entire

load as Network Load for all purposes under

Part III of the Tariff and designating Network

Resources in connection with such

additional Network Load, or (2) excluding

that entire load from its Network Load and

purchasing Point-To-Point Transmission

Service under Part II of the Tariff. To the

extent that the Network Customer gives

notice of its intent to add a new Network

Load as part of its Network Load pursuant to

this section the request must be made

through a modification of service pursuant to

a new Application.

31.4 New Interconnection Points: To the

extent the Network Customer desires to add

a new Delivery Point or interconnection

point between the Transmission Provider’s

Transmission System and a Network Load,

the Network Customer shall provide the

Transmission Provider with as much advance

notice as reasonably practicable.

31.5 Changes in Service Requests: Under

no circumstances shall the Network

Customer’s decision to cancel or delay a

requested change in Network Integration

Transmission Service (e.g. the addition of a

new Network Resource or designation of a

new Network Load) in any way relieve the

Network Customer of its obligation to pay the

costs of transmission facilities constructed by

the Transmission Provider and charged to the

Network Customer as reflected in the Service

Agreement. However, the Transmission

Provider must treat any requested change in

Network Integration Transmission Service in

a non-discriminatory manner.

31.6 Annual Load and Resource

Information Updates: The Network Customer

shall provide the Transmission Provider with

annual updates of Network Load and

Network Resource forecasts consistent with

those included in its Application for Network

Integration Transmission Service under Part

III of the Tariff. The Network Customer also

shall provide the Transmission Provider with

timely written notice of material changes in

any other information provided in its

Application relating to the Network

Customer’s Network Load, Network

Resources, its transmission system or other

aspects of its facilities or operations affecting

the Transmission Provider’s ability to

provide reliable service.

32 Additional Study Procedures For

Network Integration Transmission Service

Requests

32.1 Notice of Need for System Impact

Study: After receiving a request for service,

the Transmission Provider shall determine

on a non-discriminatory basis whether a

System Impact Study is needed. A

description of the Transmission Provider’s

methodology for completing a System Impact

Study is provided in Attachment . If the

Transmission Provider determines that a

System Impact Study is necessary to

accommodate the requested service, it shall

so inform the Eligible Customer, as soon as

practicable. In such cases, the Transmission

Provider shall within thirty (30) days of

receipt of a Completed Application, tender a

System Impact Study Agreement pursuant to

which the Eligible Customer shall agree to

reimburse the Transmission Provider for

performing the required System Impact

Study. For a service request to remain a

Completed Application, the Eligible

Customer shall execute the System Impact

Study Agreement and return it to the

Transmission Provider within fifteen (15)

days. If the Eligible Customer elects not to

execute the System Impact Study Agreement,

its Application shall be deemed withdrawn

and its deposit shall be returned with

interest.

32.2 System Impact Study Agreement and

Cost Reimbursement:

(i) The System Impact Study Agreement

will clearly specify the Transmission

Provider’s estimate of the actual cost, and
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12479

time for completion of the System Impact

Study. The charge shall not exceed the actual

cost of the study. In performing the System

Impact Study, the Transmission Provider

shall rely, to the extent reasonably

practicable, on existing transmission

planning studies. The Eligible Customer will

not be assessed a charge for such existing

studies; however, the Eligible Customer will

be responsible for charges associated with

any modifications to existing planning

studies that are reasonably necessary to

evaluate the impact of the Eligible

Customer’s request for service on the

Transmission System.

(ii) If in response to multiple Eligible

Customers requesting service in relation to

the same competitive solicitation, a single

System Impact Study is sufficient for the

Transmission Provider to accommodate the

service requests, the costs of that study shall

be pro-rated among the Eligible Customers.

(iii) For System Impact Studies that the

Transmission Provider conducts on its own

behalf, the Transmission Provider shall

record the cost of the System Impact Studies

pursuant to Section 8.

32.3 System Impact Study Procedures:

Upon receipt of an executed System Impact

Study Agreement, the Transmission Provider

will use due diligence to complete the

required System Impact Study within a sixty

(60) day period. The System Impact Study

shall identify any system constraints and

redispatch options, additional Direct

Assignment Facilities or Network Upgrades

required to provide the requested service. In

the event that the Transmission Provider is

unable to complete the required System

Impact Study within such time period, it

shall so notify the Eligible Customer and

provide an estimated completion date along

with an explanation of the reasons why

additional time is required to complete the

required studies. A copy of the completed

System Impact Study and related work

papers shall be made available to the Eligible

Customer. The Transmission Provider will

use the same due diligence in completing the

System Impact Study for an Eligible

Customer as it uses when completing studies

for itself. The Transmission Provider shall

notify the Eligible Customer immediately

upon completion of the System Impact Study

if the Transmission System will be adequate

to accommodate all or part of a request for

service or that no costs are likely to be

incurred for new transmission facilities or

upgrades. In order for a request to remain a

Completed Application, within fifteen (15)

days of completion of the System Impact

Study the Eligible Customer must execute a

Service Agreement or request the filing of an

unexecuted Service Agreement, or the

Application shall be deemed terminated and

withdrawn.

32.4 Facilities Study Procedures: If a

System Impact Study indicates that additions

or upgrades to the Transmission System are

needed to supply the Eligible Customer’s

service request, the Transmission Provider,

within thirty (30) days of the completion of

the System Impact Study, shall tender to the

Eligible Customer a Facilities Study

Agreement pursuant to which the Eligible

Customer shall agree to reimburse the

Transmission Provider for performing the

required Facilities Study. For a service

request to remain a Completed Application,

the Eligible Customer shall execute the

Facilities Study Agreement and return it to

the Transmission Provider within fifteen (15)

days. If the Eligible Customer elects not to

execute the Facilities Study Agreement, its

Application shall be deemed withdrawn and

its deposit shall be returned with interest.

Upon receipt of an executed Facilities Study

Agreement, the Transmission Provider will

use due diligence to complete the required

Facilities Study within a sixty (60) day

period. If the Transmission Provider is

unable to complete the Facilities Study in the

allotted time period, the Transmission

Provider shall notify the Eligible Customer

and provide an estimate of the time needed

to reach a final determination along with an

explanation of the reasons that additional

time is required to complete the study. When

completed, the Facilities Study will include

a good faith estimate of (i) the cost of Direct

Assignment Facilities to be charged to the

Eligible Customer, (ii) the Eligible Customer’s

appropriate share of the cost of any required

Network Upgrades, and (iii) the time required

to complete such construction and initiate

the requested service. The Eligible Customer

shall provide the Transmission Provider with

a letter of credit or other reasonable form of

security acceptable to the Transmission

Provider equivalent to the costs of new

facilities or upgrades consistent with

commercial practices as established by the

Uniform Commercial Code. The Eligible

Customer shall have thirty (30) days to

execute a Service Agreement or request the

filing of an unexecuted Service Agreement

and provide the required letter of credit or

other form of security or the request no

longer will be a Completed Application and

shall be deemed terminated and withdrawn.

33 Load Shedding and Curtailments

33.1 Procedures: Prior to the Service

Commencement Date, the Transmission

Provider and the Network Customer shall

establish Load Shedding and Curtailment

procedures pursuant to the Network

Operating Agreement with the objective of

responding to contingencies on the

Transmission System. The Parties will

implement such programs during any period

when the Transmission Provider determines

that a system contingency exists and such

procedures are necessary to alleviate such

contingency. The Transmission Provider will

notify all affected Network Customers in a

timely manner of any scheduled Curtailment.

33.2 Transmission Constraints: During

any period when the Transmission Provider

determines that a transmission constraint

exists on the Transmission System, and such

constraint may impair the reliability of the

Transmission Provider’s system, the

Transmission Provider will take whatever

actions, consistent with Good Utility

Practice, that are reasonably necessary to

maintain the reliability of the Transmission

Provider’s system. To the extent the

Transmission Provider determines that the

reliability of the Transmission System can be

maintained by redispatching resources, the

Transmission Provider will initiate

procedures pursuant to the Network

Operating Agreement to redispatch all

Network Resources and the Transmission

Provider’s own resources on a least-cost basis

without regard to the ownership of such

resources. Any redispatch under this section

may not unduly discriminate between the

Transmission Provider’s use of the

Transmission System on behalf of its Native

Load Customers and any Network Customer’s

use of the Transmission System to serve its

designated Network Load.

33.3 Cost Responsibility for Relieving

Transmission Constraints: Whenever the

Transmission Provider implements least-cost

redispatch procedures in response to a

transmission constraint, the Transmission

Provider and Network Customers will each

bear a proportionate share of the total

redispatch cost based on their respective

Load Ratio Shares.

33.4 Curtailments of Scheduled

Deliveries: If a transmission constraint on the

Transmission Provider’s Transmission

System cannot be relieved through the

implementation of least-cost redispatch

procedures and the Transmission Provider

determines that it is necessary to Curtail

scheduled deliveries, the Parties shall Curtail

such schedules in accordance with the

Network Operating Agreement.

33.5 Allocation of Curtailments: The

Transmission Provider shall, on a nondiscriminatory basis, Curtail the

transaction(s) that effectively relieve the

constraint. However, to the extent practicable

and consistent with Good Utility Practice,

any Curtailment will be shared by the

Transmission Provider and Network

Customer in proportion to their respective

Load Ratio Shares. The Transmission

Provider shall not direct the Network

Customer to Curtail schedules to an extent

greater than the Transmission Provider

would Curtail the Transmission Provider’s

schedules under similar circumstances.

33.6 Load Shedding: To the extent that a

system contingency exists on the

Transmission Provider’s Transmission

System and the Transmission Provider

determines that it is necessary for the

Transmission Provider and the Network

Customer to shed load, the Parties shall shed

load in accordance with previously

established procedures under the Network

Operating Agreement.

33.7 System Reliability: Notwithstanding

any other provisions of this Tariff, the

Transmission Provider reserves the right,

consistent with Good Utility Practice and on

a not unduly discriminatory basis, to Curtail

Network Integration Transmission Service

without liability on the Transmission

Provider’s part for the purpose of making

necessary adjustments to, changes in, or

repairs on its lines, substations and facilities,

and in cases where the continuance of

Network Integration Transmission Service

would endanger persons or property. In the

event of any adverse condition(s) or

disturbance(s) on the Transmission

Provider’s Transmission System or on any

other system(s) directly or indirectly

interconnected with the Transmission

Provider’s Transmission System, the

Transmission Provider, consistent with Good
12480 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

Utility Practice, also may Curtail Network

Integration Transmission Service in order to

(i) limit the extent or damage of the adverse

condition(s) or disturbance(s), (ii) prevent

damage to generating or transmission

facilities, or (iii) expedite restoration of

service. The Transmission Provider will give

the Network Customer as much advance

notice as is practicable in the event of such

Curtailment. Any Curtailment of Network

Integration Transmission Service will be not

unduly discriminatory relative to the

Transmission Provider’s use of the

Transmission System on behalf of its Native

Load Customers. The Transmission Provider

shall specify the rate treatment and all

related terms and conditions applicable in

the event that the Network Customer fails to

respond to established Load Shedding and

Curtailment procedures.

34 Rates and Charges

The Network Customer shall pay the

Transmission Provider for any Direct

Assignment Facilities, Ancillary Services,

and applicable study costs, consistent with

Commission policy, along with the following:

34.1 Monthly Demand Charge: The

Network Customer shall pay a monthly

Demand Charge, which shall be determined

by multiplying its Load Ratio Share times

one twelfth (1⁄12) of the Transmission

Provider’s Annual Transmission Revenue

Requirement specified in Schedule H.

34.2 Determination of Network

Customer’s Monthly Network Load: The

Network Customer’s monthly Network Load

is its hourly load (including its designated

Network Load not physically interconnected

with the Transmission Provider under

Section 31.3) coincident with the

Transmission Provider’s Monthly

Transmission System Peak.

34.3 Determination of Transmission

Provider’s Monthly Transmission System

Load: The Transmission Provider’s monthly

Transmission System load is the

Transmission Provider’s Monthly

Transmission System Peak minus the

coincident peak usage of all Firm Point-ToPoint Transmission Service customers

pursuant to Part II of this Tariff plus the

Reserved Capacity of all Firm Point-To-Point

Transmission Service customers.

34.4 Redispatch Charge: The Network

Customer shall pay a Load Ratio Share of any

redispatch costs allocated between the

Network Customer and the Transmission

Provider pursuant to Section 33. To the

extent that the Transmission Provider incurs

an obligation to the Network Customer for

redispatch costs in accordance with Section

33, such amounts shall be credited against

the Network Customer’s bill for the

applicable month.

34.5 Stranded Cost Recovery: The

Transmission Provider may seek to recover

stranded costs from the Network Customer

pursuant to this Tariff in accordance with the

terms, conditions and procedures set forth in

FERC Order No. 888. However, the

Transmission Provider must separately file

any proposal to recover stranded costs under

Section 205 of the Federal Power Act.

35 Operating Arrangements

35.1 Operation under The Network

Operating Agreement: The Network

Customer shall plan, construct, operate and

maintain its facilities in accordance with

Good Utility Practice and in conformance

with the Network Operating Agreement.

35.2 Network Operating Agreement: The

terms and conditions under which the

Network Customer shall operate its facilities

and the technical and operational matters

associated with the implementation of Part III

of the Tariff shall be specified in the Network

Operating Agreement. The Network

Operating Agreement shall provide for the

Parties to (i) operate and maintain equipment

necessary for integrating the Network

Customer within the Transmission Provider’s

Transmission System (including, but not

limited to, remote terminal units, metering,

communications equipment and relaying

equipment), (ii) transfer data between the

Transmission Provider and the Network

Customer (including, but not limited to, heat

rates and operational characteristics of

Network Resources, generation schedules for

units outside the Transmission Provider’s

Transmission System, interchange schedules,

unit outputs for redispatch required under

Section 33, voltage schedules, loss factors

and other real time data), (iii) use software

programs required for data links and

constraint dispatching, (iv) exchange data on

forecasted loads and resources necessary for

long-term planning, and (v) address any other

technical and operational considerations

required for implementation of Part III of the

Tariff, including scheduling protocols. The

Network Operating Agreement will recognize

that the Network Customer shall either (i)

operate as a Control Area under applicable

guidelines of the North American Electric

Reliability Council (NERC) and the

[applicable regional reliability council], (ii)

satisfy its Control Area requirements,

including all necessary Ancillary Services, by

contracting with the Transmission Provider,

or (iii) satisfy its Control Area requirements,

including all necessary Ancillary Services, by

contracting with another entity, consistent

with Good Utility Practice, which satisfies

NERC and the [applicable regional reliability

council] requirements. The Transmission

Provider shall not unreasonably refuse to

accept contractual arrangements with another

entity for Ancillary Services. The Network

Operating Agreement is included in

Attachment G.

35.3 Network Operating Committee: A

Network Operating Committee (Committee)

shall be established to coordinate operating

criteria for the Parties’ respective

responsibilities under the Network Operating

Agreement. Each Network Customer shall be

entitled to have at least one representative on

the Committee. The Committee shall meet

from time to time as need requires, but no

less than once each calendar year.

Schedule 1—Scheduling, System Control

and Dispatch Service

This service is required to schedule the

movement of power through, out of, within,

or into a Control Area. This service can be

provided only by the operator of the Control

Area in which the transmission facilities

used for transmission service are located.

Scheduling, System Control and Dispatch

Service is to be provided directly by the

Transmission Provider (if the Transmission

Provider is the Control Area operator) or

indirectly by the Transmission Provider

making arrangements with the Control Area

operator that performs this service for the

Transmission Provider’s Transmission

System. The Transmission Customer must

purchase this service from the Transmission

Provider or the Control Area operator. The

charges for Scheduling, System Control and

Dispatch Service are to be based on the rates

set forth below. To the extent the Control

Area operator performs this service for the

Transmission Provider, charges to the

Transmission Customer are to reflect only a

pass-through of the costs charged to the

Transmission Provider by that Control Area

operator.

Schedule 2—Reactive Supply and Voltage

Control from Generation Sources Service

In order to maintain transmission voltages

on the Transmission Provider’s transmission

facilities within acceptable limits, generation

facilities under the control of the control area

operator are operated to produce (or absorb)

reactive power. Thus, Reactive Supply and

Voltage Control from Generation Sources

Service must be provided for each

transaction on the Transmission Provider’s

transmission facilities. The amount of

Reactive Supply and Voltage Control from

Generation Sources Service that must be

supplied with respect to the Transmission

Customer’s transaction will be determined

based on the reactive power support

necessary to maintain transmission voltages

within limits that are generally accepted in

the region and consistently adhered to by the

Transmission Provider.

Reactive Supply and Voltage Control from

Generation Sources Service is to be provided

directly by the Transmission Provider (if the

Transmission Provider is the Control Area

operator) or indirectly by the Transmission

Provider making arrangements with the

Control Area operator that performs this

service for the Transmission Provider’s

Transmission System. The Transmission

Customer must purchase this service from

the Transmission Provider or the Control

Area operator. The charges for such service

will be based on the rates set forth below. To

the extent the Control Area operator performs

this service for the Transmission Provider,

charges to the Transmission Customer are to

reflect only a pass-through of the costs

charged to the Transmission Provider by the

Control Area operator.

Schedule 3—Regulation and Frequency

Response Service

Regulation and Frequency Response

Service is necessary to provide for the

continuous balancing of resources

(generation and interchange) with load and

for maintaining scheduled Interconnection

frequency at sixty cycles per second (60 Hz).

Regulation and Frequency Response Service

is accomplished by committing on-line

generation whose output is raised or lowered

(predominantly through the use of automatic

generating control equipment) as necessary to
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12481

follow the moment-by-moment changes in

load. The obligation to maintain this balance

between resources and load lies with the

Transmission Provider (or the Control Area

operator that performs this function for the

Transmission Provider). The Transmission

Provider must offer this service when the

transmission service is used to serve load

within its Control Area. The Transmission

Customer must either purchase this service

from the Transmission Provider or make

alternative comparable arrangements to

satisfy its Regulation and Frequency

Response Service obligation. The amount of

and charges for Regulation and Frequency

Response Service are set forth below. To the

extent the Control Area operator performs

this service for the Transmission Provider,

charges to the Transmission Customer are to

reflect only a pass-through of the costs

charged to the Transmission Provider by that

Control Area operator.

Schedule 4—Energy Imbalance Service

Energy Imbalance Service is provided

when a difference occurs between the

scheduled and the actual delivery of energy

to a load located within a Control Area over

a single hour. The Transmission Provider

must offer this service when the transmission

service is used to serve load within its

Control Area. The Transmission Customer

must either purchase this service from the

Transmission Provider or make alternative

comparable arrangements to satisfy its Energy

Imbalance Service obligation. To the extent

the Control Area operator performs this

service for the Transmission Provider,

charges to the Transmission Customer are to

reflect only a pass-through of the costs

charged to the Transmission Provider by that

Control Area operator.

The Transmission Provider shall establish

a deviation band of +/¥1.5 percent (with a

minimum of 2 MW) of the scheduled

transaction to be applied hourly to any

energy imbalance that occurs as a result of

the Transmission Customer’s scheduled

transaction(s). Parties should attempt to

eliminate energy imbalances within the

limits of the deviation band within thirty (30)

days or within such other reasonable period

of time as is generally accepted in the region

and consistently adhered to by the

Transmission Provider. If an energy

imbalance is not corrected within thirty (30)

days or a reasonable period of time that is

generally accepted in the region and

consistently adhered to by the Transmission

Provider, the Transmission Customer will

compensate the Transmission Provider for

such service. Energy imbalances outside the

deviation band will be subject to charges to

be specified by the Transmission Provider.

The charges for Energy Imbalance Service are

set forth below.

Schedule 5—Operating Reserve—Spinning

Reserve Service

Spinning Reserve Service is needed to

serve load immediately in the event of a

system contingency. Spinning Reserve

Service may be provided by generating units

that are on-line and loaded at less than

maximum output. The Transmission

Provider must offer this service when the

transmission service is used to serve load

within its Control Area. The Transmission

Customer must either purchase this service

from the Transmission Provider or make

alternative comparable arrangements to

satisfy its Spinning Reserve Service

obligation. The amount of and charges for

Spinning Reserve Service are set forth below.

To the extent the Control Area operator

performs this service for the Transmission

Provider, charges to the Transmission

Customer are to reflect only a pass-through

of the costs charged to the Transmission

Provider by that Control Area operator.

Schedule 6—Operating Reserve—

Supplemental Reserve Service

Supplemental Reserve Service is needed to

serve load in the event of a system

contingency; however, it is not available

immediately to serve load but rather within

a short period of time. Supplemental Reserve

Service may be provided by generating units

that are on-line but unloaded, by quick-start

generation or by interruptible load. The

Transmission Provider must offer this service

when the transmission service is used to

serve load within its Control Area. The

Transmission Customer must either purchase

this service from the Transmission Provider

or make alternative comparable arrangements

to satisfy its Supplemental Reserve Service

obligation. The amount of and charges for

Supplemental Reserve Service are set forth

below. To the extent the Control Area

operator performs this service for the

Transmission Provider, charges to the

Transmission Customer are to reflect only a

pass-through of the costs charged to the

Transmission Provider by that Control Area

operator.

Schedule 7—Long-Term Firm and ShortTerm Firm Point-To-Point Transmission

Service

The Transmission Customer shall

compensate the Transmission Provider each

month for Reserved Capacity at the sum of

the applicable charges set forth below:

(1) Yearly delivery: one-twelfth of the

demand charge of $llllllll/KW of

Reserved Capacity per year.

(2) Monthly delivery: $llllllll/

KW of Reserved Capacity per month.

(3) Weekly delivery: $llllllll/

KW of Reserved Capacity per week.

(4) Daily delivery: $llllllll/

KW of Reserved Capacity per day.

The total demand charge in any week,

pursuant to a reservation for Daily delivery,

shall not exceed the rate specified in section

(3) above times the highest amount in

kilowatts of Reserved Capacity in any day

during such week.

(5) Discounts: Three principal

requirements apply to discounts for

transmission service as follows (1) any offer

of a discount made by the Transmission

Provider must be announced to all Eligible

Customers solely by posting on the OASIS,

(2) any customer-initiated requests for

discounts (including requests for use by one’s

wholesale merchant or an affiliate’s use)

must occur solely by posting on the OASIS,

and (3) once a discount is negotiated, details

must be immediately posted on the OASIS.

For any discount agreed upon for service on

a path, from point(s) of receipt to point(s) of

delivery, the Transmission Provider must

offer the same discounted transmission

service rate for the same time period to all

Eligible Customers on all unconstrained

transmission paths that go to the same

point(s) of delivery on the Transmission

System.

Schedule 8—Non-Firm Point-To-Point

Transmission Service

The Transmission Customer shall

compensate the Transmission Provider for

Non-Firm Point-To-Point Transmission

Service up to the sum of the applicable

charges set forth below:

(1) Monthly delivery: $llllllll/

KW of Reserved Capacity per month.

(2) Weekly delivery: $llllllll/

KW of Reserved Capacity per week.

(3) Daily delivery: $llllllll/KW

of Reserved Capacity per day.

The total demand charge in any week,

pursuant to a reservation for Daily delivery,

shall not exceed the rate specified in section

(2) above times the highest amount in

kilowatts of Reserved Capacity in any day

during such week.

(4) Hourly delivery: The basic charge shall

be that agreed upon by the Parties at the time

this service is reserved and in no event shall

exceed $llllllll/MWH. The total

demand charge in any day, pursuant to a

reservation for Hourly delivery, shall not

exceed the rate specified in section (3) above

times the highest amount in kilowatts of

Reserved Capacity in any hour during such

day. In addition, the total demand charge in

any week, pursuant to a reservation for

Hourly or Daily delivery, shall not exceed the

rate specified in section (2) above times the

highest amount in kilowatts of Reserved

Capacity in any hour during such week.

(5) Discounts: Three principal

requirements apply to discounts for

transmission service as follows (1) any offer

of a discount made by the Transmission

Provider must be announced to all Eligible

Customers solely by posting on the OASIS,

(2) any customer-initiated requests for

discounts (including requests for use by one’s

wholesale merchant or an affiliate’s use)

must occur solely by posting on the OASIS,

and (3) once a discount is negotiated, details

must be immediately posted on the OASIS.

For any discount agreed upon for service on

a path, from point(s) of receipt to point(s) of

delivery, the Transmission Provider must

offer the same discounted transmission

service rate for the same time period to all

Eligible Customers on all unconstrained

transmission paths that go to the same

point(s) of delivery on the Transmission

System.

Attachment A—Form of Service Agreement

for Firm Point-To-Point Transmission

Service

1.0 This Service Agreement, dated as

ofllllllllll, is entered into, by

and between llllllllll (the

Transmission Provider), and

llllllllll (‘‘Transmission

Customer’’).

2.0 The Transmission Customer has been

determined by the Transmission Provider to
12482 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

have a Completed Application for Firm

Point-To-Point Transmission Service under

the Tariff.

3.0 The Transmission Customer has

provided to the Transmission Provider an

Application deposit in accordance with the

provisions of Section 17.3 of the Tariff.

4.0 Service under this agreement shall

commence on the later of (1) the requested

service commencement date, or (2) the date

on which construction of any Direct

Assignment Facilities and/or Network

Upgrades are completed, or (3) such other

date as it is permitted to become effective by

the Commission. Service under this

agreement shall terminate on such date as

mutually agreed upon by the parties.

5.0 The Transmission Provider agrees to

provide and the Transmission Customer

agrees to take and pay for Firm Point-ToPoint Transmission Service in accordance

with the provisions of Part II of the Tariff and

this Service Agreement.

6.0 Any notice or request made to or by

either Party regarding this Service Agreement

shall be made to the representative of the

other Party as indicated below.

Transmission Provider

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

Transmission Customer

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

7.0 The Tariff is incorporated herein and

made a part hereof.

IN WITNESS WHEREOF, the Parties have

caused this Service Agreement to be executed

by their respective authorized officials.

Transmission Provider

By: lllllllllllllllllll

Name

lllllllllllllllllllll

Title

lllllllllllllllllllll

Date

Transmission Customer

By: lllllllllllllllllll

Name

lllllllllllllllllllll

Title

lllllllllllllllllllll

Date

Specifications for Long-Term Firm Point-ToPoint Transmission Service

1.0 Term of Transaction:

lllllllllllllll

Start Date: llllllllllllll

Termination Date: lllllllllll

2.0 Description of capacity and energy to

be transmitted by Transmission Provider

including the electric Control Area in which

the transaction originates.

lllllllllllllllllllll

3.0 Point(s) of Receipt:

lllllllllllllll

Delivering Party:

lllllllllllllll lllll

4.0 Point(s) of Delivery:

lllllllllllllll

Receiving Party:

lllllllllllllll lllll

5.0 Maximum amount of capacity and

energy to be transmitted (Reserved Capacity):

lllllllllllllllllllll

6.0 Designation of party(ies) subject to

reciprocal service obligation:

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

7.0 Name(s) of any Intervening Systems

providing transmission service:

lllllllllllllllllllll

lllllllllllllllllllll

8.0 Service under this Agreement may be

subject to some combination of the charges

detailed below. (The appropriate charges for

individual transactions will be determined in

accordance with the terms and conditions of

the Tariff.)

8.1 Transmission Charge:

lllllllllllllllllllll

8.2 System Impact and/or Facilities Study

Charge(s):

lllllllllllllllllllll

8.3 Direct Assignment Facilities Charge:

lllllllllllllllllllll

lllllllllllllllllllll

8.4 Ancillary Services Charges:

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

Attachment B—Form of Service Agreement

For Non-Firm Point-To-Point Transmission

Service

1.0 This Service Agreement, dated as of

llllllllll, is entered into, by and

between llllllllll(the

Transmission Provider), and

llllllllll (Transmission

Customer).

2.0 The Transmission Customer has been

determined by the Transmission Provider to

be a Transmission Customer under Part II of

the Tariff and has filed a Completed

Application for Non-Firm Point-To-Point

Transmission Service in accordance with

Section 18.2 of the Tariff.

3.0 Service under this Agreement shall be

provided by the Transmission Provider upon

request by an authorized representative of the

Transmission Customer.

4.0 The Transmission Customer agrees to

supply information the Transmission

Provider deems reasonably necessary in

accordance with Good Utility Practice in

order for it to provide the requested service.

5.0 The Transmission Provider agrees to

provide and the Transmission Customer

agrees to take and pay for Non-Firm PointTo-Point Transmission Service in accordance

with the provisions of Part II of the Tariff and

this Service Agreement.

6.0 Any notice or request made to or by

either Party regarding this Service Agreement

shall be made to the representative of the

other Party as indicated below.

Transmission Provider

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

Transmission Customer

lllllllllllllllllllll

lllllllllllllllllllll

lllllllllllllllllllll

7.0 The Tariff is incorporated herein and

made a part hereof.

IN WITNESS WHEREOF, the Parties have

caused this Service Agreement to be executed

by their respective authorized officials.

Transmission Provider

By: lllllllllllllllllll

Name

lllllllllllllllllllll

Title

lllllllllllllllllllll

Date

Transmission Customer

By: lllllllllllllllllll

Name

lllllllllllllllllllll

Title

lllllllllllllllllllll

Date

Attachment C—Methodology To Assess

Available Transmission Capability

To be filed by the Transmission Provider.

Attachment D—Methodology for Completing

a System Impact Study

To be filed by the Transmission Provider.

Attachment E—Index of Point-To-Point

Transmission Service Customers

lllllllllllllllllllll

Customer

Date of Service Agreement

lllllllllllllllllllll

Attachment F—Service Agreement for

Network Integration Transmission Service

To be filed by the Transmission Provider.

Attachment G—Network Operating

Agreement

To be filed by the Transmission Provider.

Attachment H—Annual Transmission

Revenue Requirement for Network

Integration Transmission Service

1. The Annual Transmission Revenue

Requirement for purposes of the Network

Integration Transmission Service shall be

llllllllll.

2. The amount in (1) shall be effective

until amended by the Transmission

Provider or modified by the

Commission.
Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations 12483

Attachment I—Index of Network Integration

Transmission Service Customers

lllllllllllllllllllll

Customer

Date of Service Agreement

lllllllllllllllllllll

Promoting Wholesale Competition

Through Open Access Non-discriminatory

Transmission Services by Public Utilities.

Docket No. RM95–8–001.

Recovery of Stranded Costs by Public

Utilities and Transmitting Utilities. Docket

No. RM94–7–002.

(Issued March 4, 1997)

HOECKER, Commissioner, dissenting in part:

I. General Observations

Today’s rehearing order makes Order No.

888 ripe for judicial review and largely

concludes the most ambitious generic

rulemaking effort in this agency’s history.

The scores of specific policy calls embodied

in Order No. 888–A represent reasoned

decisionmaking that, in its sheer level of

detail, takes us to the outer limits of our

ability to predict or control the proper future

operation of the market. Still, the timeliness

of this order ought to be welcomed. Having

satisfactorily demonstrated that the

fundamental rules governing a network as

complex and important as the Nation’s

transmission grid can be changed and made

to work, the Commission will henceforth be

engaged in implementing open access tariffs

and dealing with the direct and indirect

consequences of bulk power competition.

The mantle of major policymaking now shifts

to the states and to the U.S. Congress.

During this proceeding, the industry has

continued to evolve. In ten short months,

merger and acquisition activity has increased

dramatically and may foretell a more

significant reconfiguration in the future. The

concept of an independent system operator

has attained significant credibility as a

possible way to throttle market power, ensure

system reliability, and rationalize the bulk

power market. Retail access and customer

choice suddenly dominate the restructuring

debate, although the future competitive retail

power market still defies prediction. The

demarcation between state and federal

jurisdiction is actively being tested. And, as

the implications of full stranded cost

recovery are being thought through within

the industry, companies are also trying to

diagnose and address their other competitive

vulnerabilities. These remarkable and largely

unforeseeable changes counsel against the

temptation among public policymakers to

over-plan and over-prescribe the future of

power markets.

II. Partial Dissent

In Order No. 888, the Commission

announced that it would be the ‘‘primary

forum’’ for stranded cost claims in those

instances where a retail power customer

turns wholesale wheeling customer, usually

through a municipalization. I dissented from

that portion of the Final Rule because I

concluded that the Commission’s decision to

take responsibility for stranded costs arising

from municipalization was insupportable as

a matter of either policy or law. As the

‘‘primary forum’’ for recovery of these costs,

the Commission will be required to secondguess certain state retail stranded cost

determinations, even when state regulators

and state statutes address the issue

sufficiently. This would, in my estimation,

encourage forum shopping and

fundamentally contradict our approach in the

retail wheeling situation, where retail

stranded costs are subject to Commission

action only if the state regulatory body lacks

authority to deal with this important

transitional issue. I continue to hold these

views.

The majority has bolstered its position

today with additional arguments connecting

the Commission’s actions in Order No. 888

to the wholesale status of new municipal

power customers. While inventive, the

majority rests its theory of jurisdiction on a

tenuous theory of cause and effect. Briefly,

the rehearing order distinguishes wholesale

stranded costs from retail stranded costs not

by the nature of the costs, but by the status

of the customer (i.e., a wholesale

transmission services customer versus a retail

transmission services customer) with whom

the costs are associated. It further contends

that jurisdiction over stranded costs depends

on ‘‘whether the transmission tariffs used by

the customer to escape its former power

supplier * * * were required by this

Commission or by a state commission’’. The

majority states that this Commission will

serve as the ‘‘primary forum’’ for stranded

cost recovery only where there exists a direct

nexus between the availability and use of

FERC’s open access transmission tariffs and

the stranding of costs.

I am not persuaded by the rationale

supplied by my colleagues. I continue to

believe that municipalization, like retail

wheeling, would be unavailable to retail

customers as a competitive supply alternative

but for state action. In both instances, it is

state law that provides the legal means for

retail customers to gain access to FERCjurisdictional transmission tariffs. In the final

analysis, I am not persuaded that the public

interest is served by the majority’s intrusion

into an area potentially policed under state

law, notwithstanding the Commission’s

strong commitment to full cost recovery.

In today’s order, the Commission also

broadens its ‘‘primary forum’’ approach to

include situations involving the expansion of

existing municipal utility systems, for

example through annexation of retail

customer load or additional service territory.

I contend, however, that the ‘‘primary forum’’

approach is no more appropriate for

municipal annexations than it is for new

municipalizations.

The discussion of this issue in Order No.

888–A heightens my previous concerns in a

number of ways. First, the majority’s position

is based on the alleged similarities between

the creation of a new municipal utility

system and the expansion of an existing

municipal utility system. In both cases, they

argue, a nexus exists between the

municipalization and Commission-required

transmission access; the salient connection is

the use that the new wholesale customer

makes of the former supplying utility’s

transmission system. If one were to assume

the correctness of the majority’s

municipalization approach, it would make

sense to limit its stranded cost recovery

provisions to such circumstances only. But,

there are two more compelling factors that

determine the legitimacy of any stranded cost

approach. First, like retail wheeling, all

municipalizations, whether new or

annexations, occur pursuant to state law. As

already discussed, state action allows retail

customers to aggregate load and, through

municipalization, gain access to FERCjurisdictional transmission tariffs. Second,

the risk of annexation (and with it the loss

of retail load) existed long before enactment

of the Energy Policy Act or implementation

of Order No. 888. I believe these factors argue

for treatment of all costs incurred to serve

retail load and stranded pursuant to state

action—whether by retail wheeling, new

municipalization, or annexation—by the

same state regulatory body. I do not dispute,

however, that the Commission should step in

when states fail to ensure some level of

stranded cost recovery, thereby creating a

regulatory gap.

The rehearing order has an additional

problem. It states that the Commission will

not necessarily be the ‘‘primary forum’’ for

stranded cost recovery in all cases of

municipal annexation. The majority’s new

willingness to decide stranded costs arising

from the annexation of new load will

therefore require a finding that the existing

municipality will use the transmission

system of the annexed retail customers’

former supplier to provide service to the

annexed load. This approach is necessitated

by the ‘‘nexus’’ theory of jurisdiction over the

underlying stranded costs, and it represents

a novel theory of law. Moreover, the

administrative difficulties associated with

this particular fact-finding will be extensive.

An existing municipality already has

transmission and generation service

arrangements in place. With access to

additional generation resources now

available in the newly competitive wholesale

power market, a municipality ultimately may

be served by a number of suppliers, possibly

in addition to its own resources. In such

circumstances, the difficulty in determining

which generation resources, and hence

which transmission services, are being used

to supply service to the annexed customers

in particular may be virtually

insurmountable. Under the nexus test, the

Commission must settle that matter

preliminarily just to decide whether it is the

proper forum for addressing the costs

stranded by an annexation.

To compound this practical problem, the

majority’s commitment to give ‘‘great weight

to a state’s view’’ of what stranded costs are

recoverable under state law in these

circumstances, and to deduct the amount of

state stranded cost awards from the amount

that a utility may seek to recover from this

Commission, is likely to prove a hollow

promise. Such deference would require a

prior stranded cost determination on the

merits by state regulators, despite the

majority’s instruction to the parties to raise

all stranded cost claims under the

municipalization scenario before this

Commission ‘‘in the first instance.’’
12484 Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules and Regulations

1Pipeline Service Obligations and Revisions to

Regulations Governing Self-Implementing

Transportation Under Part 284 of the Commission’s

Regulations and Regulation of Natural Gas Pipelines

After Partial Wellhead Decontrol, Order No. 636–C,

78 FERC ¶ 61,186 (1997).

2Mechanisms for Passthrough of Pipeline Takeor-Pay Buyout and Buydown Costs, Order No. 528–

A, 54 FERC ¶ 61,095 (1991).

Deference in this context is a slippery

proposition for other reasons, too. Naturally,

states may perceive equity considerations,

cost causation principles, 1 and market risk

factors2 differently than the Commission, and

consequently they may not share the

Commission’s view that utilities are entitled

to full recovery of stranded costs here.

Because of this potential difference of

opinion, I suspect that the amount of

deference that the Commission provides to

the states may be directly proportional to the

level of stranded cost recovery that states

grant the utilities.

In sum, the majority’s ingenious attempt to

federalize stranded cost claims arising from

municipalization, while admirable in terms

of the need to resolve transition cost issues

expeditiously, is more likely to cause greater

uncertainty and more argument about the

appropriate standard to apply than it is to

promote settlement of the matter.

I therefore respectfully dissent in small

part to Order No. 888–A.

James J. Hoecker,

Commissioner.

Promoting Wholesale Competition

Through Open Access Non-Discriminatory

Transmission Services by Public Utilities.

Docket No. RM95–8–001.

Recovery of Stranded Costs by Public

Utilities and Transmitting Utilities. Docket

No. RM94–7–002.

Order No. 888–A

(Issued March 4, 1997)

MASSEY, Commissioner, dissenting in part:

I dissent in part, from this otherwise

excellent rule, on a single issue. I continue

to believe, as I stated in my dissent to Order

No. 888, that the Commission should treat

stranded costs arising from retail competition

and municipalizations similarly.

Municipalization occurs under state rather

than federal law. The majority’s decision in

Order No. 888 that FERC should be the

primary forum for addressing the recovery of

stranded costs caused by municipalization

boldly and unnecessarily preempts legitimate

state authority. Today’s order perpetuates

and compounds this error by extending

federal preemption to stranded costs arising

from municipal annexations as well.

Many state commissions have express

legislative authority to address these issues

and should not be prohibited from doing so

by federal regulators. It is only when a state

commission does not have the authority, or

has the authority and fails to use it, that the

Commission should be available as a

stranded cost recovery forum of last resort.

On this one issue, I respectfully dissent.

William L. Massey,

Commissioner.

[FR Doc. 97–5767 Filed 3–13–97; 8:45 am]

BILLING CODE 6717–01–P

DEPARTMENT OF ENERGY

Federal Energy Regulatory

Commission

18 CFR Part 37

[Docket No. RM95–9–001; Order No. 889–

A]

Open Access Same-Time Information

System and Standards of Conduct

Issued March 4, 1997.

AGENCY: Federal Energy Regulatory

Commission, DOE.

ACTION: Final Rule; order on rehearing.

SUMMARY: The Federal Energy

Regulatory Commission is revising its

policy on posting discounts to be

consistent with changes in the discount

policy that we simultaneously are

implementing in Order No. 888–A.

Additionally, we are making other

minor revisions to 18 CFR Part 37—

which contains rules establishing and

governing transmission information

networks and standards of conduct—to

be responsive to arguments made on

rehearing and to make the regulations

operate more smoothly.

In addition, the Commission requests

that the How Working Group propose

the necessary changes in the Standards

and Protocols document and the Data

Dictionary by June 2, 1997 to address

four issues.

EFFECTIVE DATE: This rule is effective on

May 13, 1997.

FOR FURTHER INFORMATION CONTACT:

Marvin Rosenberg (Technical

Information), Office of Economic

Policy, Federal Energy Regulatory

Commission, 888 First Street, N.E.,

Washington, DC 20426, (202) 208–

1283.

William C. Booth (Technical

Information), Office of Electric Power

Regulation, Federal Energy Regulatory

Commission, 888 First Street, N.E.,

Washington, DC 20426, (202) 208–

0849.

Gary D. Cohen (Legal Information),

Office of the General Counsel, Federal

Energy Regulatory Commission, 888

First Street, N.E., Washington, DC

20426, (202) 208–0321.

SUPPLEMENTARY INFORMATION: In

addition to publishing the full text of

this document in the Federal Register,

the Commission also provides all

interested persons an opportunity to

inspect or copy the contents of this

document during normal business hours

in the Public Reference Room at 888

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

20426.

The Commission Issuance Posting

System (CIPS), an electronic bulletin

board service, provides access to the

texts of formal documents issued by the

Commission. CIPS is available at no

charge to the user and may be accessed

using a personal computer with a

modem by dialing 202–208–1397 if

dialing locally or 1–800–856–3920 if

dialing long distance. To access CIPS,

set your communications software to

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

2400, or 1200 bps, full duplex, no

parity, 8 data bits and 1 stop bit. The

full text of this order will be available

on CIPS in ASCII and Wordperfect 5.1

format. CIPS user assistance is available

at 202–208–2474.

CIPS is also available through the Fed

World system. Telnet software is

required. To access CIPS via the

Internet, point your browser to the URL

address: http://www.fedworld.gov and

select the ‘‘Go to the FedWorld Telnet

Site’’ button. When your Telnet software

connects you, log onto the FedWorld

system, scroll down and select

FedWorld by typing: 1 and at the

command line then typing: /go FERC.

FedWorld may also be accessed by

Telnet at the address fedworld.gov.

Finally, the complete text on diskette

in WordPerfect format may be

purchased from the Commission’s copy

contractor, La Dorn Systems

Corporation. La Dorn Systems

Corporation is also located in the Public

Reference Room at 888 First Street, N.E.,

Washington, D.C. 20426.

Table of Contents

I. Introduction

II. Background

III. Public Reporting Burden

IV. Discussion

A. Overview of Revisions Made in This

Order

B. Section 37.1—Applicability

1. Extent of the Commission’s Authority to

Impose Standards of Conduct

2. The Commission’s Authority to Impose

Reciprocity Provision

3. Waiver Policy

C. Section 37.2—Purpose

D. Section 37.3—Definitions

E. Section 37.4—Standards of Conduct

1. Contacts Between Employees Providing

Ancillary Services and System Operators

2. Contacts Between Generation Control

Employees and Transmission Operations

and Wholesale Merchant Employees

3. Monitoring the Standards of Conduct

4. Adequacy of Emergency Exception

5. Short-term Economy Energy Purchases

6. Tight Pools

7. Clarification of § 37.4(b)(5)(iv)

8. Discounts

F. Section 37.5—Obligations of

Transmission Providers and Responsible

Parties

G. Section 37.6—Information to be Posted

on an OASIS