64688 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

Investment Company Act [15 U.S.C.

80a–24, –37(a)].

Text of Form Amendments

For the reasons set out in the

preamble, Form 24F–2, referenced in

§ 274.24, Title 17, Chapter II of the Code

of Federal Regulations, is amended as

follows:

PART 274—FORMS PRESCRIBED

UNDER THE INVESTMENT COMPANY

ACT OF 1940

1. The authority citation for Part 274

continues to read as follows:

Authority: 15 U.S.C. 77f, 77g, 77h, 77j, 77s,

78c(b), 78l, 78m, 78n, 78o(d), 80a–8, 80a–24,

and 80a–29, unless otherwise noted.

2. Form 24F–2 (referenced in

§ 274.24) is amended by revising the

second and third sentences of

Instruction C.9 to Item 5(vii) to read as

follows:

Note: Form 24F–2 does not, and the

amendments will not, appear in the Code of

Federal Regulations.

Form 24F–2

Annual Notice of Securities Sold

Pursuant to Rule 24f–2

* * * * *

Instructions

* * * * *

C. Computation of Registration Fee

* * * * *

9. Item 5(vii)—* * * As of November

28, 1997, the fee rate was $295 per

$1,000,000 offered or sold (prorated for

amounts less than $1,000,000). The

registration fee is calculated by

multiplying the aggregate offering or

sales amount by .000295. * * *

* * * * *

For the Commission, by the Office of the

Secretary, pursuant to delegated authority.

Dated: December 2, 1997.

Margaret H. McFarland,

Deputy Secretary.

[FR Doc. 97–31961 Filed 12–8–97; 8:45 am]

BILLING CODE 8010–01–M

DEPARTMENT OF ENERGY

Federal Energy Regulatory

Commission

18 CFR Part 35

[Docket Nos. RM95–8–003 and RM94–7–

004; Order No. 888–B]

Promoting Wholesale Competition

Through Open Access NonDiscriminatory Transmission Services

by Public Utilities; Recovery of

Stranded Costs by Public Utilities and

Transmitting Utilities

Issued November 25, 1997.

AGENCY: Federal Energy Regulatory

Commission, Energy.

ACTION: Final rule; order on rehearing.

SUMMARY: The Federal Energy

Regulatory Commission affirms, with

certain clarifications, the fundamental

calls made in its order on rehearing of

the final rule in this proceeding. The

final rule directed public utilities to

open their transmission lines to

competitors and to offer them the same

charges and conditions they apply to

themselves. The rule also gave utilities

an opportunity to seek recovery of

certain stranded costs, i.e., costs that

were prudently incurred to serve

customers that use open access

transmission under the final rule to shift

to another power supplier. The

Commission in this order clarifies its

position on recovery of stranded costs in

the case of municipalizations and

municipal annexations, where

customers previously served by a public

utility become customers of a municipal

utility instead.

EFFECTIVE DATE: February 9, 1998.

FOR FURTHER INFORMATION CONTACT:

David D. Withnell (Legal Information—

Docket No. RM95–8–003), 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. RM94–7–004), Office of

the General Counsel, Federal Energy

Regulatory Commission, 888 First

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

(202) 208–2039.

Daniel T. Hedberg (Technical

Information—Docket No. RM95–8–

003), 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–

004), Office of Electric Power

Regulation, Federal Energy Regulatory

Commission, 888 First Street, N.E.,

Washington, D.C. 20426, (202) 208–

0243.

SUPPLEMENTARY INFORMATION: In

addition to publishing the full text of

this document in the Federal Register,

the Commission also provides all

interested persons an opportunity to

inspect or copy the contents of this

document during normal business hours

in Room 2A, 888 First Street, N.E.,

Washington, D.C. 20426. 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 located 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, also provides access to

the texts of formal documents issued by

the Commission. CIPS is available at no

charge to the user. CIPS can be accessed

over the Internet by pointing your

browser to the URL address: http://

www.ferc.fed.us. Select the link to CIPS.

The full text of this document can be

viewed, and saved, in ASCII format and

an entire day’s documents can be

downloaded in WordPerfect 6.1 format

by searching the miscellaneous file for

the last seven days. CIPS also 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 6.1

format. CIPS user assistance is available

at 202–208–2474.

Table of Contents

I. Introduction

II. Public Reporting Burden

III. Background

IV. Discussion

A. Open Access Issues

1. Discounting

2. Reciprocity

3. Indemnification/Liability

4. Qualifying Facilities (QF)/Real Power

Loss Service

5. Right of First Refusal/Reservation of

Transmission Capacity

6. Energy Imbalance Service

a. Appropriate bandwidth for small

utilities

b. Settlements establishing a deviation

bandwidth or minimum imbalance

7. Transmission Provider ‘‘Taking Service’’

Under Its Tariff for Power Purchased on

Behalf of Bundled Retail Customers

a. Jurisdiction

b. Purchases for retail native load
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64689

1As described further below, the Commission is

making one revision to the pro forma open access

transmission tariff. See infra Section IV.A.10.f and

Appendix B. Because of this single revision and its

minor nature, the Commission concludes that it

would be administratively burdensome to require

all public utilities with pro forma open access

transmission tariffs on file with the Commission to

submit compliance tariffs to reflect the revision.

Accordingly, the Commission will amend all pro

forma open access transmission tariffs currently on

file with the Commission to incorporate the tariff

revision and no tariff compliance filings will be

necessary.

2Promoting Wholesale Competition Through

Open Access Non-Discriminatory Transmission

Services by Public Utilities; Recovery of Stranded

Costs by Public Utilities and Transmitting Utilities,

Order No. 888, 61 FR 21540 (May 10, 1996), FERC

Stats. & Regs. ¶ 31,036 (1996), order on reh’g, Order

No. 888-A, 62 FR 12274 (March 14, 1997), FERC

Stats. & Regs. ¶ 31,048 (1997).

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

¶ 31,036 at 31,638 (1996). In Order No. 888-A, the

Commission concluded that its estimate of the

public reporting burden in that order on rehearing

remained unchanged from its estimate in Order No.

888. 62 FR 12274, 12280; FERC Stats. & Regs.

¶ 31,048 at 30,183 (1997).

8. Indirect Unbundled Retail Transmission

in Interstate Commerce

9. Mobile-Sierra

10. Tariff Issues

a. Load served ‘‘behind-the-meter’’

b. Definition of ‘‘Native Load Customers’’

c. Schedule changes

d. Restriction on making firm sales from

designated network resources

e. Reactive Power

f. Network Operating Agreements

g. Network customers with loads and

resources in multiple control areas

h. Network customer designation of load

11. Waivers of Order Nos. 888 and 889

12. Financial Independence of ISO

Employees

13. Distribution Charges

14. Tight Power Pools

a. Non-pancaked rates

b. Coordination transactions

15. Legal Authority

16. Ancillary Services

17. Fair Market Value

18. Pre-Existing Transmission-Only

Contracts

19. Apportionment of Transmission

Revenues For Public Utility Holding

Companies And Power Pools

20. Accounting for Transmission Provider’s

Own Use of Its System

B. Stranded Cost Issues

1. Municipal Annexation

2. Pre-existing Transmission Rights

3. Load Growth and Excess Capacity

4. G&T and Distribution Cooperatives

5. Treatment of Contracts Extended or

Renegotiated Without a Stranded Cost

Provision

6. Customer Expectations of Continued

Service at Below-Market Rates

7. Miscellaneous

V. Environmental Statement

VI. Regulatory Flexibility Act Certification

VII. Information Collection Statement

VIII. Effective Date

Appendix A (List of Petitioners)

Appendix B (Tariff Revision)

Before Commissioners: James J. Hoecker,

Chairman; Vicky A. Bailey, and William L.

Massey.

I. Introduction

In this order, the Commission affirms,

with certain clarifications, the

fundamental calls made in Order No.

888–A. 1

II. Public Reporting Burden

This order on rehearing issues a

minor revision to Order Nos. 888 and

888–A.2 We find, after reviewing this

revision, that it does not increase or

decrease the public reporting burden.

Order No. 888 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 burden estimate

contained in Order No. 888 as a starting

point, we evaluated the public burden

estimate in light of the revision

contained in this order and assessed

whether the estimate needed revision.

We have concluded, given the minor

nature of the revision, 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 Order

Nos. 888 and 888–A. 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 Order Nos. 888 and 888–A,

as revised and clarified 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 Order Nos. 888 and 888–

A, for the collection, efficient

management, and use of the required

information.

Persons wishing to comment on the

collections of information required by

Order Nos. 888 and 888–A, 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. 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 Order No. 888, the Commission

required 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. Order No. 888 required

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. To implement the

requirements of comparable open access

transmission, the Commission required

all public utilities that own, operate or

control interstate transmission facilities

to file open access non-discriminatory

transmission tariffs that contain

minimum terms and conditions of nondiscriminatory transmission service. In

Order No. 888, the Commission

established rules for discounting

practices, provisions governing priority

of service and curtailment, and a right

of first refusal for all firm transmission

customers. In addition, Order No. 888

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.

With regard to stranded costs, Order

No. 888 gives utilities the opportunity to

seek to recover legitimate, prudent, and

verifiable wholesale stranded 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. 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

Commission adopted a revenues lost

approach for calculating a utility’s

stranded costs, and determined that

stranded costs should be recovered from

the customer that caused the costs to be

incurred. The Commission decided in

Order No. 888 to be the primary forum

for addressing the recovery of stranded

costs caused by retail-turned-wholesale

customers, but not to be the primary

forum in cases involving existing

municipal utilities that annex retail

customer service territories. Order No.

888 also clarified whether and when the
64690 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

4Arizona, NRECA, TAPS, and TDU Systems.

APPA also raises this issue, but APPA filed its

request for rehearing out-of-time on April 4, 1997.

APPA failed to file its rehearing request within the

30 day period required by the Federal Power Act.

See 16 U.S.C. 825l(a). Accordingly, we will not

accept the rehearing request for filing, but will

accept the pleading as a motion for reconsideration.

5NRECA, TDU Systems, TAPS and APPA.

6See also TAPS.

7TDU Systems at 8–10.

8TAPS at 17.

9 Id. at 18 (footnote omitted).

10 Id.

11APPA at 17.

12 Id. at 19.

Commission may address stranded costs

caused by retail wheeling and the extent

of the Commission’s jurisdiction over

unbundled retail transmission. The

Commission determined that the only

circumstance in which it will entertain

requests for the recovery of stranded

costs caused by unbundled 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.

Order No. 888 further addressed 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. The

Commission determined that preexisting contracts would continue to be

honored until such time as they were

revised or terminated. The Commission

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,

and that public utilities would be

allowed to file to amend their MobileSierra 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.

In Order No. 888–A, the Commission

reaffirmed its basic determinations in

Order No. 888, with certain

clarifications. For example, it revised

the discounting requirements to better

permit the ready identification of

discriminatory discounting practices

while also providing greater discount

flexibility, and it clarified several

aspects of the reciprocity condition. It

also clarified that if utilities under

Mobile-Sierra 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. In addition, the

Commission reconsidered its decision

in Order No. 888 not to be the primary

forum for determining stranded cost

recovery in cases involving municipal

annexation and concluded that such

cases should fall within the

Commission’s province.

In this order, the Commission affirms,

with certain clarifications, the

fundamental calls made in Order No.

888–A.

IV. Discussion

A. Open Access Issues

1. Discounting

A number of entities seek rehearing

and/or clarification of the Commission’s

modified discounting policy that

requires transmission providers to offer

the same discount over all

unconstrained paths to the same point

of delivery.4 Several of these entities

assert that the Commission’s modified

policy encourages discriminatory

behavior.5 NRECA and TDU Systems

argue that the Commission’s policy

opens the door to customer-by-customer

discrimination (including

discrimination by the transmission

provider in favor of its native load

customers) because it is likely that only

one or a few customers would want

transmission service to a particular

delivery point. They also assert that the

transmission provider unreasonably

could discount service on a path where

it has load, but decline discounts to

another delivery point halfway along

the same path.6 They further contend

that the Commission’s new policy

‘‘swings the pendulum too far in the

direction of allowing price

discrimination’’ by the transmission

monopolist. According to TDU Systems,

the Commission’s policy ‘‘does not

confine the transmission provider’s

incentive to give discounts for its own

transmission uses to those instances,

and only those instances, in which such

discounts are economically justified.’’

TDU Systems adds that ‘‘the OASIS

reporting will be inadequate to remedy

discrimination in discounting shortterm non-firm transmission, since the

transactions will be over before

complaints can even be filed.’’ 7

TAPS likewise asserts that ‘‘[b]y

allowing transmission providers to

select the delivery points meriting a

discount, the Commission is

encouraging discriminatory behavior

that it will be unable to remedy’’

through an after-the-fact complaint

proceeding.8 It maintains that the

Commission’s approach ‘‘makes it less

likely that transmission providers will

provide competitors non-firm

transmission service at rates reflecting

the lower quality of the service (if the

Commission permits non-firm

transmission rates to be capped at the

firm rate).’’ 9 It notes that TAPS

members—

have experienced withdrawal of discounts

they have enjoyed under the Order No. 888

discounting policy and have seen evidence

that the revised policy will be applied by

transmission providers to offer discounts to

each other, in the hope, expectation, or tacit

agreement that they will be offered reciprocal

discounts on the other transmission

provider’s system when requested, while a

transmission dependent utility must always

pay full freight. [10]

APPA asserts that the Commission

properly required all discount

negotiations to occur on the OASIS, but

erroneously removed the requirement

that affiliate discounts be offered for all

service on unconstrained paths. It

argues that the Commission ‘‘has failed

to balance its policy of ending

discrimination in wholesale

transmission services with the objective

to send proper price signals to

transmission providers and

customers.’’ 11 Under the Commission’s

modified approach, APPA believes that

transmission providers can offer

discounts on a very selective basis—

‘‘public utility transmission providers

will have the ability to provide

discounts to affiliates in ways that

exclude smaller utilities, including

municipal utilities, from receiving those

same discounts.’’ 12

These entities propose several

approaches to resolve the competitive

problems they believe are associated

with the Commission’s modified

approach to discounting. NRECA states

that the Commission should revert to its

Order No. 888 policy or require that

discounts be offered on all

unconstrained paths serving all

similarly situated customers. NRECA

and TDU Systems (which supports the

second alternative) state that the

alternative approach could be

accomplished by requiring discounts on

all unconstrained ‘‘posted paths,’’ or, if

a discount is provided within a

particular unconstrained area, the

transmission provider should be

required to offer the same discount on

all unconstrained paths within the same

area. Similarly, TAPS states that the

Commission should revert to its Order

No. 888 policy or, at a minimum, ‘‘the

discounts should be extended to all

delivery points in the same

unconstrained portion of the

transmission provider’s transmission
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64691

13TAPS at 19.

14APPA at 20.

15TAPS at 20.

16Arizona at 4.

17 Id. at 5 (footnote omitted).

18 Id. at 6 n.12.

19 Id. at 6 (footnote omitted).

20AEP at 3. On April 17, 1997, AEP filed an

answer to the request for clarification and rehearing

of TAPS. In the circumstances presented, we will

accept the answer notwithstanding our general

prohibition on allowing answer notwithstanding

our general prohibition on allowing answers to

rehearing requests. See 18 CFR 385.713(d).

21 Id. at 4 (emphasis in original).

22FERC Stats. & Regs. ¶ 31,048 at 30,274–76.

23With respect to Arizona’s request that a

transmission provider be allowed to offer varying

degrees of discount depending on the

circumstances, we note that this Rule does not

reach that level of specificity. A transmission

provider is free to implement any discounting

proposal which it believes can increase throughput

without doing so in an unduly discriminatory

manner, provided that the proposal offers the same

discount for the same period to all eligible

customers on all unconstrained paths that go to the

same point(s) of delivery. However, if challenged on

complaint, it should be prepared to defend its

method. The only alternative is to require no

discounting, an approach we reject as contrary to

firm customers’ interests and efficient grid use.

system plus other similarly situated

customers (from an operational/cost,

rather than competitive, viewpoint).’’ 13

Moreover, APPA states that the

Commission should revert to Order No.

888 or, in the alternative, ‘‘should

require uniform discounts across

interfaces and within control areas, or,

at a minimum, within unconstrained

zones.’’ 14

TAPS adds that the best way to

promote efficient transmission usage

and competitive bulk power markets is

‘‘to set non-firm rates at the lowest

reasonable rate, in accordance with the

Commission’s statutory mandate * * *.

It is unreasonable to rely on

discounting, especially delivery pointspecific discounts, to ensure that

customers are not charged firm rates for

interruptible, low priority, non-firm

service.’’ 15 It requests that the

Commission clarify that it will actively

exercise its responsibility to ensure that

customers are not overcharged for nonfirm service.

Arizona, on the other hand, seeks to

narrow the Commission’s revised

discounting policy. It requests that the

Commission allow a transmission

provider to offer varying degrees of

discount depending upon whether—

(1) transactions over a particular path

alleviate constraints on another transmission

path, (2) certain transmission paths are

loaded to a different degree than other paths,

and (3) initial discounts encourage a

sufficient number of transactions. [16]

For example, it asserts that ‘‘there could

be multiple paths to the same delivery

point, with each path potentially

warranting different discounting

treatment. A steep discount may be

appropriate on one unutilized

transmission path to encourage counterwheeling transactions that will alleviate

constraints on another path into the

delivery point, whereas a smaller

discount (or no discount at all) may be

appropriate on another unconstrained,

but highly valued, path into the delivery

point.’’ 17

With respect to its second point,

Arizona asserts that a transmission path

with relatively little available

transmission capability (ATC) deserves

a lower discount than a transmission

path with relatively high ATC. It urges

the Commission to clarify ‘‘whether a

transmission path that has an ATC equal

to 80% of [total transmission capability

(TTC)] should be discounted to the same

degree as a transmission path that has

an ATC equal to only 30% of TTC.’’ 18

As to its third point, it seeks

clarification that it ‘‘may initially offer

a steep discount on a transmission path

into a particular delivery point to

encourage transactions, but reduce the

discount as more and more transactions

take place over that path.’’ 19

American Electric Power System

(AEP) responds to TAPS’ assertion that

transmission providers will only offer

discounts to each other as evidenced by

a printout from AEP’s OASIS under

which TAPS contends ‘‘discounts are

now available only to delivery points of

other transmission providers, not those

of TDUs.’’ 20 AEP indicates that,

contrary to TAPS’ assertion, it offers

discounts to any transmission customer

that has alternatives to using AEP’s

transmission system. It notes that this is

consistent with the Order No. 888–A

statement that a transmission provider

should discount only if necessary to

increase throughput on its system. It

also adds that no customer is being

charged rates that exceed a just and

reasonable, cost-based rate. According

to AEP, ‘‘[t]o charge customers without

alternatives less than the cost-based rate

would be unduly discriminatory to

AEP’s native load customers who would

otherwise have to make up the revenues

not recovered from such customers.’’ 21

Moreover, because discounting must be

conducted through the OASIS, AEP

declares that there is no chance that a

transmission provider will use

discounting for any purpose other than

to increase throughput. AEP also

opposes TAPS’ request to establish a

price cap for non-firm service below

that for firm service. It claims that such

a change would allow customers on

largely unconstrained transmission

systems such as AEP’s to game the

system by requesting non-firm service

priced at a low level with the

knowledge that the service is essentially

the equivalent of firm service.

Commission Conclusion. We deny the

requests for rehearing of our discounting

policy. In Order No. 888–A, we

addressed certain concerns raised by

various parties on rehearing regarding

our prior discounting policy and

adopted a more balanced approach that

would provide incentives to

transmission providers to operate the

transmission grid efficiently while

ensuring that they do so in a not unduly

discriminatory manner.22 Our balanced

approach requires that (1) a

transmission provider should discount

only if necessary to increase throughput

on its system, (2) any offer of a discount

and the details of any agreed upon

discount transaction must be posted on

the OASIS (including any negotiation,

i.e., any offers and counteroffers, of the

discount), and (3) a 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.

We believe that this approach is a

reasonable and workable means to

permit transmission providers to

provide discounts in a not unduly

discriminatory manner. Transmission

providers will not have unnecessary

restrictions on their ability to increase

throughput on their transmission

systems, which accrues to the benefit of

all of their firm customers, while OASIS

will allow the Commission and other

users of the system to monitor for

instances of unduly discriminatory

behavior by such transmission

providers.23

In this regard, we also disagree that

posting of discounts on OASIS is

inadequate for short-term discounts

because the transactions will be over

before a complaint could be filed. All

complaint proceedings occur after the

fact, but we believe that such

proceedings nevertheless act as a

deterrent to improper behavior. The

Commission will not be reluctant to

impose appropriate sanctions in

instances where transmission providers

engage in unduly discriminatory

discounting practices. Moreover, any

alternative would likely require a

preapproval process that could, as

parties to this proceeding have argued,

shut down a substantial portion of the

hourly transactions in short-term

markets that depend upon discounted

transmission to go forward.

We see no need at this time to adopt

a more restrictive discounting policy
64692 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

24As the market evolves, the Commission may

need to take up a broad array of transmission

pricing issues. It may well develop that a long-term

solution to any problems raised by discounting

requires fundamental changes to the transmission

pricing methods currently in place in the electric

industry.

25NRECA at 13–14; TDU Systems at 13–14.

26NEPOOL at 7.

27 Id. at 7–8.

28TAPS at 22.

29 Id. at 23 (footnote omitted).

30RUS at 10–11.

31 Id. at 12.

that could hinder a transmission

provider’s ability to increase throughput

on its system based solely on allegations

that the transmission provider may act

in an unduly discriminatory manner.

The opportunity to monitor the

discounting behavior of transmission

providers through OASIS will provide

data that will allow the Commission to

evaluate the adequacy and effectiveness

of its discounting policy.24 Until we see

evidence that our discounting policy

will not work or see patterns of unduly

discriminatory discounting practices,

we will continue the Order No. 888–A

discounting policy, with the OASIS

safeguards in place.

2. Reciprocity

Several entities raise a variety of

issues with respect to the Commission’s

reciprocity condition. NRECA and TDU

Systems request clarification that the

amendment to section 6 of the pro forma

tariff that deleted the words ‘‘in

interstate commerce’’ was intended to

affect only the reciprocity obligation of

foreign transmission customers and not

the reciprocity obligation of

transmission customers located in the

United States.25 They seek clarification

that transmission customers within the

United States need provide reciprocal

service only on facilities used for the

transmission of electric energy in

interstate commerce and not over

facilities used in local distribution or

only for the transmission of electric

energy in intrastate commerce. Also with respect to section 6 of the

pro forma tariff, NEPOOL takes issue

with the additional language that

provides that reciprocity applies 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.’’ 26 It asserts that the breadth

of this language could cause New

Brunswick Power Corporation (New

Brunswick), a Canadian utility that has

engaged in economy and emergency

transactions with NEPOOL and made

unit sales to New England buyers, to

cease or reduce sales in New England.

According to NEPOOL, New Brunswick

has indicated a concern that it does not

have the legal authority to implement a

generic open access tariff in New

Brunswick. Thus, NEPOOL requests that

the Commission provide that where a

seller is simply continuing to make sales

in the same manner as it did before

Order Nos. 888 and 888–A, and is

legally unable to provide reciprocity,

the reciprocity requirement will not be

applicable to it.27

TAPS takes issue with the

Commission’s modified ‘‘safe harbor’’

procedure set forth in Order No. 888–A

that permits a non-public utility to

provide reciprocal service only to the

transmission provider from whom it

receives open access transmission

service. TAPS believes that the

Commission’s modification is ‘‘an

unnecessary step backwards from its

expressed aim of remedying past undue

discrimination and providing nondiscriminatory open access.’’ 28 It

believes that the transmission provider’s

access to third party systems will be

superior to that of its customers that

support the transmission grid.

According to TAPS, a customer would

be at a disadvantage because it would be

forced to resort to a filing under section

211. Thus, it asserts that the safe harbor

should be available only to those that

offer open access to all eligible

wholesale transmission customers. ‘‘At

the very least, [it argues,] the special

protections offered by the safe harbor

should be available only if the nonjurisdictional utility makes its tariff

available to the long term customers of

the transmission provider.’’ 29

RUS seeks rehearing and/or

clarification with respect to a number of

reciprocity related issues. RUS first

complains that there is confusion

regarding the alternatives available to

non-public utilities. It asserts that in

certain places in Order No. 888–A the

Commission indicates that it will no

longer allow bilateral agreements (e.g.,

‘‘Alternatively, bilateral agreements for

transmission service provided by a

public utility will not be permitted.’’),

but that in other places the Commission

encourages the use of bilateral

agreements (e.g., ‘‘A non-public utility

may also satisfy reciprocity through

bilateral agreements with a public

utility.’’). It also notes that Order No.

888–A appears to substitute public

utility waivers for the alternative of

bilateral agreements. In any event,

however, it argues that

[p]ublic utilities have no incentive to enter

into bilateral agreements or to waive the

reciprocity requirement for a non-public

utility that owns transmission. Indeed, these

so-called options effectively invite public

utilities to deny access to non-public utilities

that have not filed open access tariffs. If a

non-public utility cannot qualify for a waiver

from the Commission, the public utility can,

by denying a waiver or refusing to enter into

a bilateral agreement, force the non-public

utility to file a reciprocal tariff with the

Commission. Moreover, requiring a nonpublic utility to seek a waiver—whether from

the public utility or the Commission—is

inconsistent with the Commission’s

assertions that the provision of open access

by non-public utilities is not required, but

merely voluntary.30

RUS takes issue with the following

statement in Order No. 888–A, claiming

that it mischaracterizes the RUS

program and RUS as anti-competitive:

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 argument. Such cooperatives have

the option to seek bilateral service

agreements. [Order No. 888–A, mimeo at

318].

RUS maintains that it does not place

any prohibitions, restrictions, or

conditions on financing to electric

systems based on rendering reciprocal

service. It states that while the Rural

Electrification Act places restrictions on

RUS financing, it does not prohibit

cooperatives from obtaining financing

for facilities through non-RUS sources.

RUS seeks clarification that the

statement in Order No. 888–A that ‘‘the

seller as well as the buyer in the chain

of a transaction involving a non-public

utility will have to comply with the

reciprocity condition’’ does not mean

that if a G&T uses an open access tariff,

both the G&T and its distribution system

are subject to the reciprocity provision.

RUS also states that although the

Commission acknowledges that it lacks

jurisdiction to enforce rates charged by

non-public utilities in reciprocal open

access tariffs and to adjudicate stranded

cost claims of non-public utilities, the

Commission has indicated that if a nonpublic utility includes a stranded cost

component in a reciprocity tariff, ‘‘the

Commission will review that stranded

cost provision if a public utility claims

that the stranded cost component, as

applied, violates the principle of

comparability.’’ 31 According to RUS,

‘‘any comparability determination with

respect to stranded cost or other

provisions contained in a non-public

utility’s open access tariff will involve

the exercise of Commission jurisdiction

over a non-public utility’s open access
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64693

32 Id.

33See FERC Stats. & Regs. at 30,513.

34Order Clarifying Order No. 888 Reciprocity

Condition and Requesting Additional Information,

79 FERC ¶ 61,182 at (1997) (footnotes omitted); see

also Order Denying Motion for Stay, 79 FERC

¶ 61,367 (1997).

35FERC Stats. & Regs. at 31,760.

36 Id. at 31,761.

37South Carolina Public Service Authority, 75

FERC ¶ 61,209 at 61,701 (1996).

38FERC Stats. & Regs. ¶ 31,048 at 30,289.

39FERC Stats. & Regs. ¶ 31,036 at 31,762.

40FERC Stats. & Regs. ¶ 31,048 at 30,285.

41 Id. at 30,289.

42Of course, the flip side is equally true. If a

public utility seeks service from a non-public

Continued

transmission tariff as well as a

determination of the legitimacy of the

non-public utility’s stranded cost

claims.’’ 32 RUS says that the

Commission has not indicated that it

will apply the comparability standard to

the transmission rates that rural

cooperatives charge members and nonmembers in a manner that will take into

account the unique characteristics of a

cooperative system, the inherent

differences between members and nonmembers, and the intended beneficiaries

of the RE Act.

Commission Conclusion. With respect

to NRECA and TDU Systems’ requested

clarification of the deleted words ‘‘in

interstate commerce’’ from section 6 of

the pro forma tariff, we reiterate that

transmission customers in the United

States must provide reciprocal

transmission service ‘‘over facilities

used for the transmission of electric

energy owned, controlled or operated by

the Transmission Customer.’’ 33 Thus, a

transmission customer must provide

transmission service over all

transmission facilities that it owns,

controls or operates. This includes

transmission facilities in both interstate

and intrastate commerce. Such a

customer, however, need not provide

reciprocal service over facilities used

solely in local distribution.

We recently addressed concerns

similar to those raised by NEPOOL as to

the applicability of the reciprocity

condition to a Canadian utility selling

power to a U.S. utility. In an order

addressing Ontario Hydro’s motion for a

stay of the reciprocity provision of

Order Nos. 888 and 888–A as those

orders apply to transmission-owning

foreign entities, we explained that the

reciprocity condition does not apply

in circumstances where a Canadian utility

sells power to a U.S. utility located at the

United States/Canada border, title to the

electric power transfers to the U.S. border

utility, and the power is then resold by the

U.S. border utility to a U.S. customer that has

no affiliation with, and no contractual or

other tie to, the Canadian utility. The

reciprocity provision thus does not in any

way affect historical Canadian-United States

buy-sell arrangements, i.e., those involving

sales to U.S. border utilities who then resell

power to purchasers that have no contractual

or other transactional link to the Canadian

seller. For these types of historical sales, a

Canadian seller is no worse off under Order

Nos. 888 and 888–A than it was prior to the

orders’ issuance. Additionally, Order Nos.

888 and 888–A do not disrupt any pre-Order

No. 888 power sales contracts under which

Ontario Hydro sells to U.S. utilities, or any

pre-Order No. 888 transmission contracts

under which it purchases transmission from

U.S. utilities.34

Thus, Order Nos. 888 and 888–A do not

disrupt any existing agreements, as

defined in those orders, between New

Brunswick and any of its U.S.

customers. Moreover, to the extent any

of New Brunswick’s transactions are

buy-sell arrangements of the type

described above, such transactions also

are not affected by Order Nos. 888 and

888–A. However, if New Brunswick

seeks to sell power under new

agreements or through new coordination

transactions, such transactions are

subject to Order Nos. 888 and 888–A

and New Brunswick would have to

agree to provide reciprocal open access

transmission, unless waived by the U.S.

public utility or this Commission.

TAPS’ rehearing request with respect

to the safe harbor procedure was not

timely filed. In Order No. 888, the

Commission explicitly stated that ‘‘we

intend that reciprocal service be limited

to the transmission provider.’’ 35 The

Commission also stated, in establishing

the safe harbor procedure, that ‘‘[w]e are

aware that many non-public utilities are

very willing to offer reciprocal access,

and that some are willing to provide

access to all eligible customers through

an open access tariff.’’ 36 Thus, it was

clear that a non-public utility could

meet reciprocity under the safe harbor

procedure by agreeing to provide service

only to the transmission provider or to

any eligible customer. Nothing in Order

No. 888–A changed this approach. The

Commission’s discussion of the safe

harbor procedure in Order No. 888–A

was limited to Santee Cooper 37—a

company-specific case decided

subsequent to Order No. 888. The

Commission noted that while the

company in that case chose to offer an

open access tariff to all eligible

customers, ‘‘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.’’ 38

We also disagree with TAPS’ assertion

that the Commission has taken ‘‘an

unnecessary step backwards from its

expressed aim of remedying past undue

discrimination and providing nondiscriminatory open access.’’ We

explicitly stated in Order No. 888 our

rationale for requiring that reciprocal

access be offered only to the

transmission provider from whom the

non-public utility obtains open access

service:

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.39

With respect to RUS’ concerns

regarding the availability of bilateral

agreements, we clarify the distinction

between the two different

circumstances: (1) That of a non-public

utility seeking transmission service from

a public utility, and the requirement

imposed on the public utility in

providing the service; and (2) that of a

public utility seeking transmission from

a non-public utility, and what is

sufficient for the non-public utility to

provide reciprocal transmission service.

As we stated in Order No. 888–A, if a

non-public utility seeks service from a

public utility, that public utility should,

except in unusual circumstances,

provide the service ‘‘pursuant to the

open access tariff and not pursuant to

separate bilateral agreements.’’ 40 On the

other hand, if a public utility seeks

service from a non-public utility

through the reciprocity condition, Order

No. 888–A provides that the non-public

utility may provide that service

pursuant to a bilateral agreement to

satisfy its reciprocity obligation.41

We do not agree with RUS that public

utilities will have no incentive to take

service under bilateral agreements or to

waive the reciprocity condition for nonpublic utilities. If a public utility needs

transmission service from a non-public

utility to maximize its profits or to make

sales or purchases on behalf of its native

load, then it should not care whether it

takes service from the non-public utility

under a bilateral agreement or an open

access tariff. However, we recognize that

even if the public utility does not need

transmission service from a non-public

utility, it may use the reciprocity

condition as a reason to deny

transmission service. But this is no

different from the situation non-public

utilities were in prior to the issuance of

Order No. 888 when utilities could

outright deny any transmission service.

In that situation, the only recourse for

the non-public utility was to file a

request for service under section 211.

The same is true post-Order No. 888.42
64694 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

utility, the only way it may be able to seek such

service is by filing a section 211 application.

43We note that since issuance of Order No. 888,

ten non-public utilities have filed reciprocity tariffs,

including cooperatives.

44FERC Stats. & Regs. ¶ 31,048 at 30,285

(emphasis in original).

45Order No. 888–A, FERC Stats. & Regs. ¶ 31,048

at 30,286. We note that this does not prevent an

eligible entity from filing a section 211 request with

a ‘‘distribution’’ cooperative.

46RUS at 12.

47Order No. 888–A, FERC Stats. & Regs. ¶ 31,048

at 30,364 n.527.

48 Id. at 30,285.

49See KCPL and Coalition for Economic

Competition. EEI also raises this issue, but EEI filed

its request for rehearing out-of-time on April 4,

1997 with a request that the Commission accept the

rehearing request because it has occurred at the

very start of the proceeding, no response is required

by any other party and there will be no prejudice

to any other party. EEI failed to file its rehearing

request within the 30 day period required by the

Federal Power Act. See 16 U.S.C. 825l(a).

Accordingly, we will not accept the rehearing

request for filing, but will accept the pleading as a

motion for reconsideration.

50See Coalition for Economic Competition, EEI.

In any event, should a public utility

refuse to provide transmission service

based on a claim that the non-public

utility requesting transmission service is

not willing to provide reciprocal

service, the non-public utility may

always file a transmission tariff under

the safe harbor procedure. We do not

see this as any burden as the

Commission has made available for

interested entities a complete open

access tariff that would require little

modification to file.43 Moreover, as we

have explained, this reciprocal tariff,

filed under the safe harbor procedure,

need only be made available to the

public utility (or utilities) from whom

the non-public utility obtains open

access transmission service. Further, if,

as RUS seems to imply, the cooperatives

do not want to provide any service, that

is fundamentally at odds with the basic

reciprocity provision and the fairness/

competition concepts that underlie it.

We also reject RUS’ argument that

requiring a non-public utility to seek a

waiver is inconsistent with the

Commission’s assertion that the

reciprocity condition is voluntary. First,

we did not require that non-public

utilities seek a waiver, but merely

provided a waiver as an option for them

to pursue. Moreover, the waiver option

(from the public utility or the

Commission) is available only if a nonpublic utility voluntarily chooses to

request open access transmission

service from a public utility. As we

explained in Order No. 888–A:

we are not requiring non-public utilities to

provide transmission access. Instead, we are

conditioning the use of public utility open

access tariffs, by all customers including nonpublic utilities, on an agreement to offer

comparable (not unduly discriminatory)

services in return.44

We will clarify for RUS that the

Commission’s statement that ‘‘the seller

as well as the buyer in the chain of a

transaction involving a non-public

utility will have to comply with the

reciprocity condition’’ does not apply to

member distribution cooperatives when

their G&T cooperative obtains open

access transmission service. We did not

intend this statement to change our

position with respect to cooperatives

and reaffirm our prior pronouncement

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.45

Finally, we disagree with RUS’ claim

that ‘‘any comparability determination

with respect to stranded cost or other

provisions contained in a non-public

utility’s open access tariff will involve

the exercise of Commission jurisdiction

over a non-public utility’s open access

transmission tariff as well as a

determination of the legitimacy of the

non-public utility’s stranded cost

claims.’’ 46 In Order No. 888–A, the

Commission explained that a nonpublic utility that chooses voluntarily to

offer an open access tariff for purposes

of demonstrating that it meets the

reciprocity condition can include a

stranded cost provision in its tariff, but

adjudication of any stranded cost claims

under that tariff would not be subject to

our jurisdiction. We said that although

we would not determine the rate of a

non-public utility (including the

stranded cost component of the rate),

‘‘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.’’ 47 In

reviewing a public utility’s claims that

a non-public utility is applying its

stranded cost provision in a noncomparable (or discriminatory) manner,

we would not be exercising jurisdiction

over the non-public utility or its rates.

We simply would be enforcing the

reciprocity condition. As we said in

Order No. 888–A, ‘‘[i]t 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.’’ 48

3. Indemnification/Liability

Several petitioners argue that the

Commission erroneously established a

new standard of liability for

transmission providers—simple

negligence—that is contrary to the

weight of authority in states across the

country.49 They claim that the

Commission’s standard would expose

transmission providers and their native

load customers to potentially enormous

liability, including large consequential

damage awards.50 EEI also argues that

the Commission has made no finding

that a change in the standard is needed

to remedy alleged undue discrimination

nor, it argues, has the Commission

demonstrated any reason to change the

liability standard. According to EEI, the

proper standard is ‘‘gross negligence.’’

Similarly, Puget argues that the

Commission erroneously refuses to

allow the express exclusion of

consequential and indirect damages. It

argues that the exception language in

section 10.2 of the pro forma tariff

(‘‘except in cases of negligence or

intentional wrongdoing by the

Transmission Provider’’) should be

changed to ‘‘except in cases of and to

the extent of comparative or

contributory negligence or intentional

wrongdoing by the Transmission

Provider.’’ It further argues that Order

No. 888 should be revised to exclude

liability for special, incidental,

consequential or indirect damages.

Coalition for Economic Competition

states that the Commission erroneously

relied upon a gas decision as a basis for

adopting an ordinary negligence

standard. It asserts that the

characteristics of gas and electric service

and the risks associated with each are

very different: (1) the wires for electric

transmission are located above ground

and more susceptible to outages than

buried pipelines and (2) the electric grid

is more complex, with the potential for

a single problem to affect a significant

number of customers over a large

geographic area. Thus, it argues, electric

transmission providers face a much

greater exposure to liability than gas

transporters.

EEI and KCPL request that the

Commission clarify whether states have

authority to establish the scope of a

utility’s liability in providing federally

mandated transmission service, as

provided for in Order No. 888–A.

Because of some uncertainty on this

issue and the fact that 25 states do not

have reported decisions on the issue,

EEI indicates that there is likely to be

significant litigation, which may lead to

uncertainty between the parties to the
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64695

51EEI at 7; KCPL at 7–8.

52Coalition for Economic Competition at 7.

53 Id. at 8.

54 Id. at 9.

55FERC Stats. & Regs. ¶ 31,048 at 30,301.

56 16 U.S.C. 824b; see, e.g., Nantahala Power &

Light Company v. Thornburg, 476 U.S. 953, 963–

66 (1986); FPC v. Southern California Edison

Company, 376 U.S. 205 (1964); Public Utilities

Commission v. Attleboro Steam & Electric

Company, 273 U.S. 83 (1927).

57See, e.g., Mississippi Power & Light Company

v. Mississippi ex rel Moore, 487 U.S. 354, 374–75

(1988); Gulf States Utilities Company v. Alabama

Power Company, 824 F.2d 1465, 1471–72,

amended, 831 F.2d 557 (5th Cir. 1987).

interstate service transaction. If the

Commission determines that states do

not have authority, EEI and KCPL assert

that the Commission should establish a

rule of liability based on a standard of

gross negligence. If the Commission

determines that states do have the

authority to establish the scope of a

transmission provider’s liability, EEI, as

well as KCPL, assert that the

Commission ‘‘should clarify that states

are preempted from attaching liability to

actions taken by a transmission provider

in compliance with the provisions of its

filed pro forma tariff’’ and ‘‘should make

an affirmative statement that it is

expressing no opinion on whether a

transmission provider should be liable,

for public policy reasons, for acts of

ordinary negligence.’’ 51

Coalition for Economic Competition

further maintains that

while the Commission directs transmission

providers to rely on state law for protection

against liability, it ignores the policies

established at the state level which already

address the issue. As a result, FERC is

reallocating the risks associated with the

transmission of electricity. To the extent that

reallocation forces utilities to experience an

additional financial burden, captive

customers will be forced to pay more—more

than the parties agreed would be their fair

share. [52]

Furthermore, Coalition for Economic

Competition states that case law may

not protect the utility and its captive

customers from the costs associated

with the reallocation of risk:

Frequently, the outcome of a case is closely

related to any applicable tariff language that

embodies that state’s public policy as set by

its regulatory commission. If the pro forma

liability provision differs from the standards

used in a particular state, the applicability

and usefulness of that state’s prior court

decisions is unclear. [53]

Coalition for Economic Competition

also asserts that the Commission

appears to be sending contradictory

signals, citing a recent decision (New

York State Electric & Gas Corporation,

78 FERC ¶ 61,114 (1997)) in which the

Commission rejected a provision in an

open access tariff that acted as a choice

of law provision. It argues that issues

involving which jurisdiction provides

the most appropriate forum, and which

law should apply, are likely to be

contested issues. In sum, Coalition for

Economic Competition states that ‘‘the

Commission’s reliance on state law

leaves a wide open gap in which the

outcome of potential claims is

completely unknown, and the risk to

which transmission providers are

exposed is increased even more.’’ 54

Commission Conclusion. The tariff

provisions on Force Majeure and

Indemnification, as clarified in Order

No. 888–A, provide certain limited

protections to the transmission provider

as well as its customers, when they

faithfully attempt to carry out their

duties under the tariff. The petitioners

want the Commission to extend these

limited protections to other situations or

otherwise set forth definitive rules on

liability in various situations that might

arise under the tariff. We believe that

the tariff provisions strike the right

balance, and we will not here attempt to

define the consequences of every

conceivable breach that might occur

under the tariff. Nor will we use the

tariff, as some appear to want us to do,

as an instrument for defining exclusive

and preemptive federal laws for liability

for all damages that might arise from the

operation of the transmission system.

The Force Majeure provision of the

tariff, in its essence, provides that

neither the transmission provider nor

the customer will be liable to the other

when they behave in all respects

properly, but unpredictable and

uncontrollable force majeure events

prevent compliance with the tariff. The

Indemnification provision of the tariff,

in its essence, provides that when the

transmission provider behaves in all

respects properly, the customer will

indemnify the transmission provider

from claims of damage to third parties

arising from the service provided under

the tariff. Under the terms of the tariff,

the transmission provider may not rely

on the protections provided by the

Force Majeure clause or the

Indemnification Clause for acts or

omissions that are the product of

negligence or intentional wrongdoing.

Likewise, the customer may not rely on

the protections provided by the Force

Majeure clause for acts or omissions that

are the product of negligence or

intentional wrongdoing.

Contrary to the contention of EEI, the

Force Majeure and Indemnification

provisions do not establish a new

simple negligence standard of liability

for transmission providers. As we

explained in Order No. 888–A, the issue

of whether liability will attach to certain

acts or omissions by a transmission

provider is a different question from

whether a customer should be obligated

to indemnify the transmission provider

in such circumstances.55 In Order Nos.

888 and 888–A, the Commission has

made no finding and expressed no

opinion concerning whether a

transmission provider should be held

liable for damages to third parties

arising from the transmission provider’s

acts or omissions of simple negligence,

and the tariff language should not be

construed as preempting the appropriate

tribunal’s consideration of whether

liability should attach for acts or

omissions of the transmission provider

that injure third parties.

While the Commission has not

established an exclusive and preemptive

liability standard for electric utilities,

EEI and the Coalition for Economic

Competition would have us do so. They

seek exculpatory language in the tariff

that would protect the transmission

provider from liability in all cases,

except where gross negligence has been

shown. Both acknowledge in their

rehearing requests that such an

exculpatory standard would in some

regions alter the current liability

standards, citing a study which

concludes that 25 states have addressed

the issue, with 21 of the 25 finding a

gross negligence standard appropriate.

Both argue that the Commission could

eliminate potential uncertainties and

conflicts among tribunals by

determining a comprehensive and

exclusive federal standard that accords

with the determinations of the majority

of states that have addressed this issue.

EEI and KCP&L also question whether

reference to state law is appropriate at

all, suggesting that the Commission

must develop a comprehensive federal

standard of liability for service under

the tariffs. We do not believe that such

a determination is necessary or

appropriate at this time.

First, we note that there is no question

that the Commission has exclusive

jurisdiction to determine the

reasonableness of rates, terms, and

conditions for the transmission of

electric energy in interstate commerce.56

Moreover, it is clear that state tribunals

may not second-guess or collaterally

attack Commission determinations of

the reasonableness of filed rates, terms,

and conditions.57 On the other hand, it

is likewise clear that the Commission’s

jurisdiction to consider disputes arising

under jurisdictional tariffs does not as a

matter of law preclude state courts from

also entertaining such disputes in the
64696 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

58See, e.g., Pan American Petroleum Corporation

v. Superior Court of Delaware, 366 U.S. 656, 662,

666 (1961).

59 7 FERC ¶ 61,175, reh’g denied, 8 FERC ¶ 61,031

(1979).

60 824 F.2d 417 (5th Cir. 1987).

61 824 F.2d 427.

62Some of the rehearing requests concerning

indemnification/liability raise issues that

previously were raised on rehearing of Order No.

888 and were addressed by the Commission in

Order No. 888–A. See Coalition for Economic

Competition argument that the circumstances of

electric transmission require a different result than

the gas pipeline cases and Puget arguments that the

negligence language of the indemnification

provision should be changed to reference

comparative or contributory negligence and that the

tariff should exclude transmission provider liability

for special, incidental, consequential, or indirect

damages. The Commission will not further address

such issues in this proceeding.

63As discussed above, EEI filed its request for

rehearing out-of-time. Accordingly, we are treating

EEI’s pleading as a motion for reconsideration.

64FERC Stats. & Regs. ¶ 31,048 at 30,237 (1997).

See also Puget.

65On April 21, 1997, Granite State Hydropower

Association filed an answer to NIMO’s rehearing

request arguing that gross sales are permissible for

QFs. In the circumstances presented, we will accept

the answer notwithstanding our general prohibition

on allowing answers to rehearing requests. See 18

CFR 385.713(d).

66EEI supports NIMO’s arguments.

67 17 FERC ¶61,231 (1981).

68H.R. Rep. No. 95–1750, Public Utility

Regulatory Policies Act, 95th Cong. 2d Sess. 89

(1978) (emphasis added). See also Turners Falls

Limited Partnership, 55 FERC ¶61,487 at 62,670

n.33 (1991) (Turners Falls).

69We note that other aspects of the ‘‘net/gross’’

issue are pending before the Commission in

separate proceedings and will be addressed by the

Commission in subsequent orders. See Connecticut

Valley Electric Company, Inc. v. Wheelabrator

Claremont Company, L.P., et al. (Docket Nos. EL94–

10–000 and QF86–177–001); Carolina Power &

Light Company v. Stone Container Corporation

(Docket Nos. EL94–62–000 and QF85–102–005);

and Niagara Mohawk Power Company v. Penntech

Papers, Inc. (Docket Nos. EL96–1–000 and QF86–

722–003).

70 32 FERC ¶61,101 (1985).

71 41 FERC ¶61,350 (1987).

72 48 FERC ¶61,120 (1989).

73Supplementary power is defined as ‘‘electric

energy or capacity supplied by an electric utility,

regularly used by a qualifying facility in addition

to that which the facility generates itself.’’

appropriate circumstances.58 In

determining whether the Commission

will exercise jurisdiction in such cases,

the Commission is guided by the

principles set forth in Arkansas

Louisiana Gas Company v. Hall.59

Application of these principles suggests

the possibility that tribunals other than

the Commission may be called upon to

adjudicate disputes arising from service

under the tariff.

With that background, the concerns

expressed by EEI and KCP&L

concerning the need for a uniform

federal liability standard closely

resemble the concerns addressed by the

court in United Gas Pipe Line Company

v. FERC.60 In that case, the Commission

had approved a tariff that limited a

pipeline’s liability to claims of

‘‘negligence, bad faith, fault or wilful

misconduct’’ and the pipeline appealed,

arguing that a uniform standard of

liability should be established that was

more protective of the pipeline. The

court rejected the claim that there was

a need for a uniform federal standard

more favorable to the pipeline. As the

court explained, ‘‘uniformity of result is

needed only to protect the federal

interest, that is, only to exculpate [the

pipeline] from contract liability in all

cases not based on [the pipeline’s] fault.

Uniformity of exculpation beyond those

cases is not a matter of federal concern’’

because in such instances ‘‘liability

flows only from [the pipeline’s]

mismanagement.’’61 This same

reasoning applies here. It is appropriate

for the Commission to protect the

transmission provider through the tariff

provisions on Force Majeure and

Indemnification from damages or

liability that may occur when the

transmission provider provides service

without negligence, but to leave the

determination of liability in other

instances to other proceedings.62

4. Qualifying Facilities (QF)/Real Power

Loss Service

NIMO and EEI 63 seek rehearing of the

Commission’s clarification in Order No.

888–A that a

QF arrangement for the 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.64

NIMO argues that the Commission’s

clarification is inconsistent with the

criteria for QF status under sections

3(17) and 3(18) of the FPA and the

Commission’s precedent. NIMO argues

that the Commission has decided that a

QF can only sell the net output of its

facility without losing QF status.

According to NIMO, allowing QFs to

purchase Real Power Loss Service will

result in QFs selling in excess of their

net output at avoided cost.65

Finally, NIMO argues that if the

Commission wishes to allow QFs to

purchase power to compensate for line

losses from third parties, and to include

such power in their sales, it must do so

only after a rulemaking in which it has

noticed its intention to amend its QF

regulations.66

Commission Conclusion. As a

preliminary matter, we reject NIMO’s

argument that the Commission could

only grant the clarification provided in

Order No. 888–A after a rulemaking in

which it noticed its intent to amend its

QF regulations. All of the QF cases cited

by NIMO in its rehearing request

involve the Commission clarifying its

rules in case-specific situations. For

example, in Occidental Geothermal, Inc.

(Occidental), the Commission was

required to define the term ‘‘power

production capacity’’ of a facility as that

term was used in 18 CFR 292.204(a).67

The Commission did so without issuing

a notice of proposed rulemaking and

seeking comments.

Moreover, the issue raised by NIMO

and EEI is whether the Commission’s

clarification would result in a facility

losing QF status, as defined in sections

3(17) and 3(18) of the FPA. The

Conference Report on PURPA provides:

The new paragraphs 17(C) and 18(B) of the

definitions provide that the Commission

shall determine, by rule, on a case-by-case

basis, or otherwise, that a small power

production facility or a cogeneration facility

is a qualifying small power production

facility or cogeneration facility, as the case

may be.[68]

Accordingly, NIMO’s argument that the

Commission has improperly amended

its PURPA regulations is wrong.

The substantive issue raised on

rehearing is an issue of first

impression.69 In Occidental, Turners

Falls, as well as in Power Developers,

Inc.,70 Malacha Power Project, Inc.

(Malacha),71 and Pentech Papers, Inc.,72

the Commission found that QFs were

permitted to sell only the net output of

their power production facilities as

measured at the point of

interconnection with the electric utility

to which they were interconnected. The

Commission did not decide the question

of whether ‘‘the 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’’ would be a

sale-for-resale of power by a QF that

would violate the Commission’s QF

rules.

At first glance, it would appear that

Real Power Loss Service and ancillary

services fall within the definition of

‘‘supplementary power’’ as defined in

18 CFR 292.101(b)(8).73 If this were in

fact the case, the precedent cited above

would be relevant because

supplementary power would be

subtracted from gross output to

determine the net output available for

sale and, pursuant to Turner Falls, any

sale in excess of the net output would

result in a loss of QF status. However,

if Real Power Loss Service and ancillary

services are part of the costs of

transmission, they are not covered
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64697

74FERC Stats. & Regs., Proposed Regulations

1977–1981, ¶32,039 at 32,437 (1979). See also id.

at 32,447 (costs of transmission constitute

interconnection costs and must be borne by QF

unless transmitting utility agrees to share them).

75FERC Stats. & Regs., Regulations Preambles

1977–1981, ¶30,128 (1980).

76 Id. at 30,866. See also 18 CFR 292.101(b)(7).

77FERC Stats. & Regs., ¶31,036 at 31,705

(footnote omitted).

78 Id.

79 Id. at 31,709.

80 Id.

81 In Order No. 69, the Commission noted:

Subparagraph (4) addresses the costs or savings

resulting from line losses. An appropriate rate for

purchases from a qualifying facility should reflect

the cost savings actually accruing to the electric

utility. If energy produced from a qualifying facility

undergoes line losses such that the delivered power

is not equivalent to the power that would have been

delivered from the source of power it replaces, then

the qualifying facility should not be reimbursed for

the difference in losses. If the load served by the

qualifying facility is closer to the qualifying facility

than it is to the utility, it is possible that there may

be net savings resulting from reduced line losses.

In such cases, the rates should be adjusted upwards.

Order No. 69 at 30,885–86.

82TDU Systems at 6; NRECA at 5.

83TDU Systems at 7.

84NRECA at 7.

85TAPS at 33.

under the definition of ‘‘supplementary

power.’’

As the Commission explained in its

Notice of Proposed Rulemaking, Small

Power Production and CogenerationRates and Exemptions:

The costs of transmission are not a part of

the rate which an electric utility to which

energy is transmitted is obligated to pay the

qualifying facility. These costs are part of the

costs of interconnection, and are the

responsibility of the qualifying

facility * * *. The electric utility to which

the electric energy is transmitted has the

obligation to purchase the energy at a rate

which reflects the costs that it can avoid as

a result of making such a purchase.74

This view was adopted by the

Commission in Order No. 69, Small

Power Production and Cogeneration

Facilities, Regulations Implementing

Section 210 of the Public Utility

Regulatory Policies Act of 1978.75 There

the Commission defined

‘‘‘interconnection costs’ as the

reasonable costs of * * *

transmission * * *.’’76 It is also

consistent with the Commission’s

findings in 18 CFR 292.303(d) that if a

QF transmits its output to an electric

utility with which it is not

interconnected, the rate for the purchase

of such energy ‘‘shall not include any

charges for transmission.’’ Thus, all that

remains is to determine whether Real

Power Loss Service and ancillary

services are part of the costs of

transmission.

Ancillary services as defined in Order

Nos. 888 and 888-A are part of the costs

of transmission services. In Order No.

888, we defined ancillary services as

those services ‘‘that must be offered

with basic transmission service under

an open access transmission tariff.’’77

We noted that these services are those

‘‘needed to accomplish transmission

service while maintaining reliability

within and among control areas affected

by the transmission service.’’78 Thus,

there is no question that ancillary

services are part of the cost of

transmission and therefore are included

among the interconnection costs a QF is

responsible for.

Real Power Loss Service is an

interconnected operations service.79 It is

thus not a service which a transmission

provider is required to provide under its

open access transmission tariff.

Nevertheless, the Commission

recognized that a transmission customer

must make provisions for Real Power

Loss. As the Commission noted, a

customer ‘‘cannot take basic

transmission service without such a

provision.’’80 As a result, we find that

Real Power Loss Service is also a part

of the cost of transmission and included

among the interconnection costs a QF is

responsible for.

Consistent with 18 CFR 292.303(d),

however, a QF purchasing Real Power

Loss Service shall have its purchase rate

adjusted up or down consistent with 18

CFR 292.304(e)(4).81 In other words,

while a QF can never sell more power

than its net output at its point of

interconnection with the grid, its

location in relation to its purchaser (and

thus its losses) may be relevant in the

calculation of the avoided cost which it

is entitled for the power it does deliver

to its electric utility purchaser.

However, as explained above, the

receipt of Real Power Loss Service or

ancillary services is not a sale-for-resale

of power. Rather, they are part of the

costs of transmission which the QF

must bear, in the absence of an

agreement to share such costs with the

transmitting utility.

5. Right Of First Refusal/Reservation Of

Transmission Capacity

NRECA, TDU Systems and TAPS seek

clarification that the rights of network

customers to reserve capacity to serve

their own retail load are comparable to

a transmission provider’s right to

reserve transmission capacity for its

retail native load. They point to

language in Order No. 888–A that

supports their interpretation, but note

that other language concerning the Right

of First Refusal (ROFR) mechanism

seems to provide an advantage to

transmission providers in serving their

retail native load.

NRECA and TDU Systems argue that

the Commission improperly allows a

transmission provider to reserve

capacity as needed to serve its existing

native load customers, but the

cooperative wholesale power or firm

transmission customer has only a right

of first refusal that requires it to match

competing bids, which exposes it to

matching an incremental rate or

opportunity cost rate capped at the cost

of system expansion. They assert that

‘‘[t]o the extent the transmission

provider is able to continue to provide

service to its retail native load at average

embedded transmission costs, so too

should the network customer have the

right to continued service at average

embedded-cost rates, rather than at

incremental-cost rates or opportunitycost rates capped only at the cost of

system expansion.’’ 82 TDU Systems

requests that the Commission clarify

that

the ROFR provisions allow an existing

network customer to continue to reserve

transmission capacity at rates that remain

comparable to the transmission provider’s

service to its retail native load.83

Similarly, NRECA requests the

Commission to clarify that

firm transmission customers for which the

transmission provider has a planning

requirement are on an equal footing with the

transmission provider’s retail load in

reserving transmission capacity. The

Commission accordingly should clarify that

the ROFR provisions allow existing firm

transmission customers for which the

transmission provider has a planning

requirement to continue to reserve their

existing transmission capacity at rates that

remain comparable to the transmission

provider’s existing service to its retail native

load.84

TAPS asks the Commission to clarify

that

its discussion of the rights of a

transmission provider to reserve and reclaim

capacity needed for native load growth apply

with equal force to capacity needed for

network customers for which the

transmission provider is equally responsible

for planning its system. The Commission

should also clarify that the transmission

provider’s reclamation/reservation right

cannot be used to withdraw capacity

currently or reasonably forecasted to be used

by a network customer.85

TDU Systems further requests that the

Commission clarify the rate an existing

transmission customer would have to

match to retain its reservation priority.

It requests that the Commission clarify

that the customer need match only the

undiscounted tariff rate of general

applicability and not the highest rate the

transmission provider is then collecting
64698 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

86FERC Stats. & Regs. ¶ 31,036 at 31,694

(emphasis added).

87FERC Stats. & Regs. ¶ 31,048 at 30,220.

88TDU Systems at 8.

89FERC Stats. & Regs. ¶ 31,048 at 30,197.

90 Depending on the rate design on file for the

existing capacity, a customer exercising its right of

first refusal could face an average embedded costbased rate, an incremental cost-based rate, a flowbased rate, a zonal rate, or any other rate design that

the Commission may have approved under section

205 of the FPA.

91APPA at 21–23 (citing Blue Creek Hydro, Inc.,

77 FERC ¶ 61,232 at 61,941 (1996), in which the

Commission used the 4 million Mwh level for

determining small utilities eligible for waiver of the

requirements of Order No. 889).

from any customer, i.e., an incremental

rate based on an upgrade for a particular

customer.

Commission Conclusion. In Order No.

888–A, we addressed concerns raised by

transmission providers that the right of

first refusal may prohibit them from

recalling capacity needed for native load

growth, by clarifying that the

transmission provider may reserve

existing capacity for retail native load

growth. While the Commission’s

conclusion in Order No. 888–A, in the

context of the treatment of retail native

load, is correct, a transmission provider

may also reserve existing capacity for

both its own wholesale native load

growth and network customers’ load

growth. As the Commission originally

explained in Order No. 888:

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.86

Accordingly, in order to allay the

concerns of NRECA, TDU Systems and

TAPS, we clarify that network

transmission customers are afforded the

same treatment as the transmission

provider on behalf of native load (retail

and wholesale requirements customers)

in terms of the reservation of existing

transmission capacity by the

transmission provider.

Regarding NRECA’s and TDU

Systems’ allegation that a transmission

provider’s right to reserve existing

transmission capacity for its retail

native load is superior to a firm

transmission customer’s right of first

refusal, we note that it is not clear if

NRECA and TDU Systems’ argument

pertains to network transmission

customers or to point-to-point

transmission customers. The right of a

transmission provider to reserve

existing transmission capacity on behalf

of network transmission customers is

discussed above. The reservation

priority of transmission capacity for

point-to-point transmission customers is

different because point-to-point

transmission customers do not

undertake the same payment obligation

as either network transmission

customers or the transmission provider

on behalf of native load customers. As

the Commission explained in Order No.

888–A in the context of reservation of

existing capacity:

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-to-point

customers. In this regard, native load and

third-party network customers face a

payment risk that point-to-point customers

generally do not face.87

Additionally, we note that a firm

transmission customer may always elect

to take network transmission service in

lieu of point-to-point transmission

service, thereby obtaining rights to

reserve existing transmission capacity

that are comparable to the rights of other

network customers and the transmission

provider on behalf of native load.

Furthermore, unless prohibited by the

terms of the existing transmission

customer’s contract, there is nothing to

prevent an existing point-to-point

transmission customer from seeking to

extend the term of its contract. An

existing transmission customer may also

enter into an additional agreement for

point-to-point transmission service and

reassign such capacity until needed or

choose a service commencement date

concurrent with the termination of its

existing contract.

TDU Systems asserts that Order No.

888–A ‘‘leaves unresolved whether the

customer must pay the undiscounted

rate of general applicability for tariff

service at the time of conversion or the

highest rate the transmission provider is

then collecting from any customer,’’

such as an incremental cost-based

rate.88 We clarify that the right of first

refusal does not require an existing

transmission customer to match the

highest rate the transmission provider is

then collecting from any customer. The

highest rate collected from any customer

may involve a different service than that

service received by the existing

customer, which may result in an

inappropriate comparison. In this

regard, the Commission stated in Order

No. 888–A that the purpose of the right

of first refusal is to be a tie-breaker and,

therefore, the competing requests

should be substantially the same in all

respects.89 Accordingly, we clarify that

the existing transmission customer

exercising its right of first refusal will be

required to match the term of service

requested by another potential customer

and may be required to pay the

transmission provider’s maximum filed

transmission rate. However, the rate

must be for substantially similar service

of equal or greater duration.

TDU Systems also asks whether the

maximum rate that a customer must

match in exercising its right of first

refusal would include an incremental

cost-based rate for an upgrade to a

competing customer or if the customer

is required to match only the

undiscounted tariff rate of general

applicability. The right of first refusal is

predicated on an existing customer

continuing to use its transmission rights

in the existing transmission system. The

right of first refusal acts as a tiebreaker

to determine whether the competing

eligible customer or the existing

transmission customer gets the existing

transmission capacity. Accordingly, the

maximum rate for such existing

transmission capacity would be the just

and reasonable transmission rate on file

at the time the customer exercises its

right of first refusal.90

In conclusion, we believe that we

have struck an appropriate balance

between our goals of: (1) Protecting the

rights of retail and wholesale native

loads and network customers by

allowing the transmission provider to

reserve existing transmission capacity

for their projected load growth and (2)

providing existing firm transmission

customers with a priority over new

requests for firm transmission service to

continue receiving transmission service

from existing transmission capacity

when there is insufficient existing

capacity available to accommodate all

requests for transmission service.

6. Energy Imbalance Service

a. Appropriate bandwidth for small

utilities. APPA argues that the

Commission’s revision in Order No.

888–A to the deviation bandwidth did

not go far enough and does not address

the requirements of all small utilities,

i.e., utilities that sell no more than 4

million MWh annually.91 It asserts that

the Commission has adequately

remedied the problem for those small

utilities serving load with a peak

demand of less than 20 MW, but not for

those utilities serving loads with greater

peak demands.

To remedy the problem, APPA asks

the Commission to revise the minimum
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64699

92As discussed above, APPA filed its request for

rehearing out-of-time. Accordingly, we are treating

APPA’s pleading as a motion for reconsideration.

93FERC Stats. & Regs. ¶ 31,048 at 30,232.

94 Id. at 30,232.

95 Id.

96TDU Systems at 12–13.

97FERC Stats. & Regs. ¶ 31,048 at 30,233.

98Order No. 888, FERC Stats. & Regs. ¶ 31,036 at

31,734.

99Order No. 888–A, FERC Stats. & Regs. ¶ 31,048

at 30,234 (footnote omitted).

100 IL Com at 8.

101 Id. at 8–9.

102CCEM at 2–6.

103 Id. at 4.

104 Id. at 4–6 (citing Mississippi River

Transmission Corp. v. FERC, 969 F.2d 1215 (D.C.

Cir. 1992)).

bandwidth to provide a minimum

deviation bandwidth of 2 MW for

utilities serving load with a peak

demand of less than 20 MW, 5 MW for

utilities serving load less than 100 MW,

and 7.5 MW for all other small utilities.

Commission Conclusion. We deny

APPA’s motion for reconsideration.92

As the Commission explained in Order

No. 888–A, the deviation bandwidth

was developed ‘‘to promote good

scheduling practices by transmission

customers. It is important that the

implementation of each scheduled

transaction not overly burden others.’’ 93

The Commission reaffirmed its use of

the 1.5 percent energy imbalance

bandwidth as ‘‘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.’’ 94

However, the Commission recognized

the needs of small customers and raised

the minimum energy imbalance from

one megawatthour per hour to two

megawatthours per hour. In doing so,

the Commission sought to balance its

primary goal of promoting good

scheduling practices with its

commitment to provide as much relief

as possible to small customers. Larger

minimum deviation bandwidths, as

proposed by APPA, could only

unnecessarily jeopardize this balance at

the expense of good scheduling

practices.

Moreover, in Order No. 888–A, the

Commission provided all customers,

including small customers, further

options to deal with any difficulties that

may be experienced as the result of the

minimum deviation bandwidth set forth

in Order No. 888–A:

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.95

APPA has simply not shown that the

minimum deviation or the procedures to

reduce or avoid energy imbalance

charges or to negotiate another

bandwidth do not provide adequate

relief for small customers. Nor has

APPA shown that larger bandwidths

could be implemented without unduly

undermining good scheduling practices.

b. Settlements establishing a deviation

bandwidth or minimum imbalance.

TDU Systems states that Order No. 888–

A allows a transmission provider and a

customer to negotiate and file another

bandwidth more flexible to the

customer on a not unduly

discriminatory basis, but if a settlement

was approved subject to the outcome of

Order No. 888, it must be revised in the

subsequent compliance filing to reflect

the language in the pro forma tariff.

Accordingly, TDU Systems seeks

clarification that if such a settlement

contains a bandwidth above 1.5% or a

minimum imbalance above 2 MW, those

amounts need not be revised downward

to conform to the pro forma tariff.96

Commission Conclusion. We will not

grant the clarification sought by TDU

Systems. In Order No. 888–A, we

explicitly stated that

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.97

This is consistent with our desire to

have all public utilities at the same

starting line as open access is

implemented in the electric industry:

By initially requiring a standardized tariff,

we intend to foster broad access across

multiple systems under standardized terms

and conditions.98

However, as we also recognized,

‘‘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.’’ 99 Thus, the

settlement discussed by TDU Systems

must be revised to conform to the pro

forma tariff, but the public utility

transmission provider to the settlement

may then make another filing with the

Commission to seek a change to the

bandwidth contained in the pro forma

tariff.

7. Transmission Provider ‘‘Taking

Service’’ Under Its Tariff for Power

Purchased on Behalf of Bundled Retail

Customers

a. Jurisdiction. IL Com states that the

Commission agreed with IL Com’s

jurisdictional arguments on rehearing of

Order No. 888 and made the following

appropriate clarifications in Order No.

888–A:

In a situation in which a transmission

provider purchases power on behalf of its

retail native load customers, the Commission

[FERC] 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. [quoting

Order No. 888–A at 117–18 (emphasis

added)].

* * * * *

[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.

[quoting Order No. 888–A at 118 (emphasis

added)].100

However, IL Com argues that the

Commission

nevertheless neglected to revise

§ 35.28(c)(2) and § 35.28(c)(2)(i) to

incorporate these clarifications into the Rule.

Therefore, [IL Com] reiterates its request that

the words ‘‘for sale for resale’’ be inserted

into the Rule after the word ‘‘purchases’’ in

§ 35.28(c)(2) and ‘‘purchase’’ in

§ 35.28(c)(2)(i) to codify the Order 888–A

clarification concerning the extent of

required power purchase unbundling.101

CCEM, however, argues that the

Commission’s disclaimer of jurisdiction

over the transmission in interstate

commerce of purchased power headed

for retail customers is contrary to the

FPA’s assertion of jurisdiction over all

transmission of electric energy in

interstate commerce.102 It states that

[t]he Commission has already embraced

the proposition that it has the statutory

authority and mandate to require utilities to

adopt tariffs that will ensure all market

participants comparable access to

transmission services. It must now extend

that authority and mandate to apply to all

transmission service.103

CCEM further argues that the

Commission’s failure to assert

jurisdiction over interstate transmission

of purchased power to retail customers

is contrary to precedent under the

Natural Gas Act (NGA).104 It cites to

Mississippi River Transmission Corp. v.

FERC, 969 F.2d 1215 (D.C. Cir. 1992),

stating that the court affirmed the

Commission’s interpretation of NGA

section 1(b) as authorizing the

Commission to regulate the price of

natural gas transportation service that
64700 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

105 Id. at 6.

106 Id.

107 Id.

108FERC Stats. & Regs. ¶ 31,048 at 30,225–26.

109See MidContinent Area Power Pool, et al., 78

FERC ¶ 61,203 (1997) (Order Accepting for Filing

and Suspending Proposed Pool-Wide and SingleSystem Holding Company Open Access

Transmission Tariffs and Revised Tariffs, and

Deferring Further Action), reh’g pending.

110TAPS at 4 and 6–14.

111 Id. at 5.

112 Id. at 9.

113 Id. at 10–11.

114 Id. at 14.

MRT provided in support of certain firm

direct sales.

If the Commission does not grant

rehearing as requested by CCEM, CCEM

argues that ‘‘the Commission should

nevertheless clarify that its

jurisdictional disclaimer does not

extend to power pool transmission

services.’’ 105 It asserts that because

pools themselves do not have native

load and do not purchase power on

behalf of native load, ‘‘when a public

utility takes poolwide service to

transmit purchased power, it should be

required to take that service on an

unbundled basis pursuant to the power

pool’s open-access tariff.’’ 106 In this

regard, it states that it is ‘‘aware that

certain public utilities claim that the

Commission’s disclaimer of jurisdiction

extends to their uses of poolwide

transmission service to transmit

purchased power to their captive, native

loads.’’ 107

CCEM further argues that the

Commission’s failure to require that all

transmission service be taken under an

open access tariff is arbitrary and

irreconcilable with the Commission’s

concurrent determination in connection

with the rules pertaining to stranded

cost recovery that it has jurisdiction

over the rates, terms and conditions of

unbundled interstate transmission

services by public utilities to retail

customers, and that it has the authority

to address retail stranded costs through

its jurisdiction over such services. It

adds that experience from restructuring

the natural gas industry (Order Nos. 436

and 636) shows the need to unbundle

and separately regulate transmission

provided in connection with retail

service.

Commission Conclusion. CCEM’s

arguments with respect to the

Commission’s disclaimer of jurisdiction

over bundled retail transmission are the

same arguments it raised on rehearing of

Order No. 888 (and were addressed by

the Commission) 108 or should have

raised on rehearing of Order No. 888.

We will not accept CCEM’s invitation to

further address this issue.

In response to CCEM’s request for

clarification regarding power pool

transactions, we note that all power

pool transactions must be taken under

the terms of the pool-wide pro forma

tariffs that were filed on compliance to

Order No. 888.109 The appropriateness

of the terms and conditions contained in

those pool-wide pro forma tariffs will be

addressed on a case-by-case basis when

the Commission addresses the merits of

the various pools’ compliance filings.

Finally, we deny IL Com’s request to

modify sections 35.28(c)(2) and

35.28(c)(2)(i) of the Commission’s

regulations. The additional language

proposed by IL Com simply will not

work. As we describe in more detail in

section 7.b below, it is not possible, as

a practical matter, to divide a single

power purchase made on behalf of both

wholesale and retail native load such

that the transmission provider takes

service under the terms and conditions

of the pro forma open access

transmission tariff for the wholesale part

of the purchase and under the terms and

conditions of a different tariff for the

retail part. Thus, the entire purchase

transaction must be undertaken

pursuant to the terms and conditions of

the pro forma open access transmission

tariff. The language proposed by IL Com

does not recognize the indivisible

nature of single power purchases made

on behalf of both wholesale and retail

native load.

b. Purchases for retail native load.

TAPS argues that the Commission

significantly contracts its functional

unbundling requirement and the

associated Standards of Conduct ‘‘by

exempting from functional unbundling

all use by a transmitting utility of its

own transmission system to serve

bundled retail native load.’’ 110 By

exempting a key aspect of the

transmission provider’s activities in

wholesale markets from the open access

rules, TAPS asserts, comparability is

destroyed and the market is severely

distorted. It emphasizes that

because of the interdependence, elasticity

and fungibility of purchases on behalf of

unbundled retail load with the transmission

provider’s other wholesale marketing

activities, there is little, if anything, left of

functional unbundling.111

TAPS states that Order No. 888–A

leaves unclear issues critical to

comparability, ‘‘such as request

procedures and priority for usage of

limited interface capability applicable to

the transmission provider’s use of

transmission for economy imports for

retail bundled load.’’ 112 It argues that

without clearly established rules that

put the transmission provider in the

same position as network customers, the

transmission provider will have a

competitive advantage.

TAPS further argues that the

Commission’s approach defeats the

Commission’s Standards of Conduct and

allows transmission provider employees

involved in the transmission function to

‘‘share operational and reliability

information with employees engaged in

making economic and other purchases

for retail bundled load on a preferential

basis as compared with other

transmission customers or the

transmission provider’s ‘wholesale’

merchant function.’’ 113 Further, it

asserts that the Commission’s approach

to functional unbundling will encourage

a transmission provider to retain its

preferential access to transmission

service and information and discourage

it from joining an ISO, under which it

would lose its preferential treatment.

TAPS concludes by arguing that

‘‘[c]ontrary to the Commission’s

suggestion, constriction of functional

unbundling is not required by

limitations on the Commission’s

jurisdiction.’’ 114 It asserts that the

Commission has provided no support

for its position and adds that the

Commission’s position cannot be

reconciled with its treatment of

transmission agreements between

jurisdictional and non-jurisdictional

entities whereby the Commission stated

that its authority over a jurisdictional

contract involving a public utility

cannot be impaired by virtue of the fact

that the other party is nonjurisdictional.

Commission Conclusion. While we

have reiterated our view that the

Commission does not have jurisdiction

over the rates, terms and conditions of

bundled retail service, based on the

comments received on rehearing, we

believe certain clarifications need to be

made. As a practical matter, we do not

believe that it is possible to divide a

single power purchase made on behalf

of both wholesale and retail native load

such that the transmission provider

takes service under the open access nonrate terms and conditions for the part of

the purchase that goes to wholesale

native load, but takes service under

different terms and conditions for the

part of the purchase that goes to retail

native load. Because the power

purchase transaction (including the

delivery across the transmission

provider’s system to both wholesale and

retail customers) is indivisible, and

because the transmission of the

purchased power to the wholesale

native load customer must be done
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64701

115See also Puget at 27.

116BPA’s arguments that requiring indirect retail

wheeling may put at risk its ability to meet its

statutory obligation to recover all of the costs of the

Federal Columbia River Power System and the

Commission’s ability to meet its statutory obligation

to ensure that BPA’s rates are sufficient to assure

repayment of the federal investment in the power

system are speculative and more appropriately

addressed in a fact-specific proceeding if and when

this possible risk may arise. Moreover, BPA may

propose appropriate stranded cost provisions.

117Met Ed at 6.

118 Id. at 7.

pursuant to the open access tariff, this

means that the entire transaction de

facto must be pursuant to the non-rate

terms and conditions of the tariff.

Concerning the Standards of Conduct

requirement that public utilities

separate their wholesale power

marketing functions from their

transmission operations, the

Commission did not require separation

of the retail power marketing function

because the state has jurisdiction over

retail power marketing and over

bundled retail transmission. However,

here too we believe further clarification

is necessary. First, the public utility has

no choice pursuant to Order Nos. 888

and 888–A but to separate its wholesale

power marketing function (including

power purchase transactions made by

the marketing function on behalf of

wholesale native load) from the

transmission operations function. This

means that those persons in the

company that are involved in wholesale

power purchases as well as wholesale

sales cannot interact with the

transmission personnel other than

through the OASIS. Thus, to the extent

they are making purchases on behalf of

wholesale as well as bundled retail

native load as part of a single purchase,

they will have to abide by the separation

of function requirement. As discussed

above, such a purchase is not divisible.

Additionally, it is conceivable that there

could be a separate retail marketing

function for native load and a separate

wholesale marketing function for native

load. If a challenge is made to the way

a utility organizes its functions, then the

utility bears the burden of

demonstrating that it is maintaining a

separate staff to perform retail marketing

functions. Furthermore, in such cases, it

would clearly be inappropriate for the

retail staff to share transmission

information with the wholesale

marketing staff.

8. Indirect Unbundled Retail

Transmission in Interstate Commerce

Referencing the Commission’s

conclusion that section 212(h) does not

prohibit the Commission from ordering

public utilities to provide indirect

unbundled retail transmission in

interstate commerce, BPA states that it

appears that the Commission intended

to clarify its jurisdiction to order retail

transmission in certain limited,

interstate situations—namely, to ensure

that state initiatives would not be

frustrated by the failure of neighboring

states to undertake similar initiatives.

Where a state has not mandated retail

access, but a local utility agrees to

provide retail access,115 BPA argues that

it should not be required to distribute

another supplier’s power to its

customers.

BPA also argues that section 212(h)(2)

prohibits orders requiring ‘‘indirect

retail transmission.’’ It declares that the

Commission ignored section 212(h)(2),

which it asserts prohibits orders

requiring indirect retail transmission.

BPA contends that, if it and other

transmitting utilities are required to

provide indirect retail transmission,

BPA’s ability to meet its statutory

obligation to recover all of the costs of

the Federal Columbia River Power

System and the Commission’s ability to

meet its statutory obligation to ensure

that BPA’s rates are sufficient to assure

repayment of the federal investment in

the power system will be placed at risk.

Commission Conclusion. We disagree

with BPA that we ignored section

212(h)(2) in concluding that we have the

authority to order indirect retail

transmission in interstate commerce to

accommodate retail access programs

ordered by a state or voluntary retail

delivery by the local utility. We clarify

that while section 212(h)(2) may limit

the Commission in certain

circumstances, as a general matter, we

believe we can order indirect interstate

transmission services necessary to

accommodate direct retail access

programs that are state ordered or

voluntary. Clearly, whether section

212(h) would prohibit the Commission

from ordering transmission in a

particular circumstance would depend

upon the facts presented, including who

the transmission requestor is, who the

seller of energy is, and who is

transmitting or delivering the energy

and over what facilities. If parties wish

to raise section 212(h)(2) in a particular

case, they may do so; however, we do

not believe Congress intended section

212(h)(2) to be used as a competitive

shield against state-ordered retail access

programs or voluntary retail access by

local utilities.116

9. Mobile-Sierra

Met Ed objects to what it describes as

the Commission’s asymmetric treatment

of customers and suppliers in Order No.

888–A. First, it argues that the existence

of uneven bargaining power prior to

Order No. 888 (that is referred to in

Order No. 888–A) does not provide a

rational basis for imposing different

standards for customer-initiated and

supplier-initiated requests for

modification of existing contracts. It

says that the Commission does not

identify the specific manner in which

existing wholesale contracts would lose

their just and reasonable character due

to changes in the electric industry. ‘‘Just

as competitive wholesale markets may

present opportunities to buyers that are

less costly than existing contracts, they

may also give sellers greater

opportunities to reach new buyers who

would be willing to pay more than

customers under existing below-cost

contracts. If the Commission’s

initiatives to expand wholesale markets

provide a rational basis for making it

easier for buyers to modify existing

contracts, then these initiatives equally

provide a basis to ease the burden on

sellers.’’117

Second, Met Ed argues that because

the existence of uneven bargaining

power was not universal, it cannot

provide the basis for a uniform refusal

to apply a just and reasonable standard

in evaluating all supplier-initiated

requests for modification (other than of

stranded cost provisions). ‘‘The

Commission cannot properly

distinguish customers from suppliers

based on a premise that is only true in

the ‘majority’ of the cases, particularly

when the Commission has the ability to

make the appropriate determination on

a case-by-case basis.’’118

Third, Met Ed says that the

Commission’s distinction between

customers and suppliers is not

rationally related to the purpose of

Order No. 888. It contends that broad

competition is not furthered by a policy

that would hold suppliers, but not

customers, to the terms of existing

unfavorable contracts. Met Ed states that

ending the subsidies reflected in longterm below-cost contracts promotes the

most efficient use of power supply

resources. According to Met Ed, Order

No. 888-A’s treatment of existing

contracts will exacerbate stranded costs

(a utility would not be able to obtain

relief from a wholesale contract that

does not cover its costs, while a

customer under another contract could

obtain a modification or termination of

the contract). ‘‘Even if the Commission

persists in its conclusion that it can

reasonably distinguish requests for

modifications by customers from those

by utilities because existing contracts
64702 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

119 Id. at 10.

120See, e.g., FERC Stats. & Reg ¶ 31,048 at 30,193.

121Central Maine at 2.

122 Id. at 3.

123 Id.

124 Dairyland at 4 (emphasis in original).

125 Dairyland notes that it filed a supplemental

rehearing request on this issue that the Commission

accepted as a motion for reconsideration. It asserts

that the Commission did not address its issue in

Order No. 888–A, but instead described the

arguments as being similar to an argument it

rejected that joint planning is a sufficient criterion

to be considered a ‘‘Native Load Customer’’ and that

construction and operation by the transmission

provider should not be necessary for native load

status to be conferred.

126 Id. at 6.

127 80 FERC ¶ 61,143 at 61,555 (1997).

128We further note that Interstate Power

Company did not file on December 31, 1996, as

provided in Order No. 888, to modify its joint use

agreements with Dairyland. See 18 CFR

35.28(c)(1)(iii). Thus, those agreements must not

prohibit transmission over the facilities to third

parties and, accordingly, remain in effect as existing

bilateral transmission agreements.

129 Dairyland at 6.

130See also TAPS at 35–36; TDU Systems at 24–

25.

131NRECA at 16; see also TAPS at 36–37.

reflect one sided bargaining, it should

clarify that it will not make such a

distinction when customers had other

options at the time the contracts were

executed.’’119

Commission Conclusion. Met Ed has

not raised issues not previously

addressed by the Commission.

Concerning its argument that uneven

bargaining power was not universal,

Order No. 888 clearly recognized that

this was the case.120 However, we

clarify that, in determining whether to

modify an existing contract, we will

look at, among other things, whether a

customer had other supply options

available to it at the time it negotiated

its existing contract. We agree with Met

Ed that the existence of uneven

bargaining power may not have been

‘‘universal’’ and clarify that utilities are

free to present to the Commission, on a

case-by-case basis, arguments that their

contracts are no longer in the public

interest or just and reasonable, and

therefore should be modified.

10. Tariff Issues

a. Load served ‘‘behind-the-meter.’’

Central Maine states that the

Commission required all of a wholesale

network customer’s load ‘‘behind-themeter’’ to be included in its load-ratio

share. It asserts, however, that the

Commission ‘‘failed to state whether the

utility also must include all of a retail

customer’s load ‘behind-the-meter’ in

computing the load-ratio share.’’ 121 It

indicates that it is concerned that it

cannot identify the ‘‘behind-the-meter’’

generation that its retail customers own

and operate. Central Maine maintains

that ‘‘[o]nly if the utility invests

significant effort and incurs substantial

expense to install metering technology

will it have the ability to monitor its

retail customers.’’ 122 In any event,

Central Maine believes that the

Commission did not intend to require

utilities to determine their retail customers

‘‘behind-the-meter’’ load when calculating

network customers’ load-ratio shares.

Moreover, the Commission cannot require a

non-jurisdictional wholesale customer to

determine its retail customers ‘‘behind-themeter’’ load. Thus, if FERC required

jurisdictional companies to make such a

determination, the load-ratio share of

network non-jurisdictional wholesale

customers would always be understated. The

Commission should clarify Order No. 888–A

so that it is clear that utilities are not

required to meter retail customer’s ‘‘behindthe-meter’’ load.123

Commission Conclusion. Central

Maine’s concern regarding the

identification of a retail customer’s

‘‘behind-the-meter’’ generation and load

is unclear. The Commission’s

discussion in Order Nos. 888 and 888–

A regarding the treatment of behind-themeter generation and load specifically

pertained to an individual network

customer’s designated network

generation and load. If Central Maine’s

concern pertains to the calculation of a

transmission provider’s total network

load, including the load of the

transmission provider’s retail native

load customers, such an inquiry is

beyond the scope of Order Nos. 888 and

888–A and should be addressed on a

case-by-case basis.

b. Definition of ‘‘Native Load

Customers.’’ Dairyland argues that the

definition of ‘‘Native Load Customers’’

in section 1.19 of the pro forma tariff is

limited to wholesale and retail power

customers and ‘‘could be read not to

encompass the native loads of parties to

transmission joint use and construction

agreements but who are not power

customers of the Transmission

Provider.’’ 124 It proposes that the

following clause be added to the end of

section 1.19: ‘‘including obligations

arising from transmission joint use

agreements in effect as of July 9,

1996.’’ 125 Dairyland argues that the

Commission should recognize these

agreements and modify the definition so

that ‘‘transmission facilities constructed

and operated to meet the reliable

electric needs of each party’s native load

customers are treated comparably,

without regard to whether either party

is or is not a ‘power’ customer of the

other.’’ 126 It further indicates that its

primary concern in seeking this

modification is in terms of priority

under the pro forma tariff for

curtailment and reservations and

believes that its status and rights are

unclear.

Commission Conclusion. We believe

that Dairyland’s argument is misplaced

and deny its request for rehearing. In

Allegheny Power Systems, Inc., et al.,127

we found that Dairyland’s joint use

agreements ‘‘are in the nature of

bilateral transmission agreements and

are not superseded or otherwise affected

by Interstate Power’s compliance tariff.

Thus, any changes to the definition of

‘native load customers’ are not

necessary.’’ 128 Accordingly, any change

to the definition of native load

customers contained in the pro forma

tariff would have no affect on

Dairyland’s joint use agreements.

We also note that Dairyland has stated

that under its joint use agreement ‘‘the

native loads of Dairyland and the native

loads of the public utility party to the

agreement were to be treated

comparably in terms of transmission

service utilizing the transmission

facilities.’’ 129 Thus, Dairyland already is

obtaining the comparable treatment that

it is apparently seeking through its

proposal to change the definition of

native load contained in the pro forma

tariff.

c. Schedule changes. NRECA states

that Order No. 888–A provided that

schedule changes for firm point-to-point

service were not limited up to twenty

minutes before the start of each clock

hour, but could be set at a reasonable

time limitation that is generally

accepted in the region and consistently

adhered to by the transmission provider.

NRECA requests rehearing to not only

permit, but also to require, scheduling

changes during emergency

conditions.130 It asserts that the

Commission should make this revision

consistent with the language of section

30.4 of the pro forma tariff that permits

network resources to be rescheduled in

response to an emergency or other

unforeseen condition. In any event, if

‘‘schedule changes are not permissible

in such situations, at least any

associated penalties, e.g., punitive

charges for energy imbalances exceeding

the 1.5% ‘deadband,’ should be

waived.’’ 131

Commission Conclusion. We deny

NRECA’s rehearing request to require

transmission providers to make

schedule changes requested by

customers during emergency conditions.

It is the responsibility of transmission

customers to make arrangements for

emergencies, such as operating reserves

for the loss of a power supplier’s

generation source. If an emergency
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64703

132See Order No. 888–A, FERC Stats. & Regs. ¶

31,048 at 30,233 (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).

133See also TDU Systems at 18–21.

134NRECA at 17; see also Dairyland at 8.

135NRECA at 18.

136TDU Systems at 21.

137FERC Stats. & Regs. ¶ 31,036 at 31,753–54.

138NY Com at 15–16.

139On April 11, 1997, NY IPPs filed an answer

to the request for clarification of NY Com. In the

circumstances presented, we will accept the answer

notwithstanding our general prohibition on

allowing answers to rehearing requests. See 18 CFR

385.713(d).

140NY IPPs at 3.

141 Id.

142 Id. at 3–4.

143 Id. at 4.

arises, a transmission provider should

not be required to accept a customerrequested schedule change, though we

would expect the transmission provider

to permit a schedule change to the

extent possible. Granting NRECA’s

request would ignore the fact that

requiring the transmission provider to

accept a requested scheduling change

may not be consistent with maintaining

system reliability.

Moreover, an emergency situation

does not automatically cause a customer

to use Energy Imbalance Service or to

pay a penalty. For example, if a

customer resource becomes unavailable

due to an emergency situation, but is

replaced by an equivalent amount of

reserves, the customer would remain in

balance if its load meets the

schedule.132 However, if the emergency

is the cause of the customer’s energy

imbalance, that is, the transmission

provider is unable to deliver the

scheduled energy, the customer should

not be responsible for paying an Energy

Imbalance Service penalty.

d. Restriction on making firm sales

from designated network resources.

NRECA argues that section 30.4 of the

pro forma tariff unreasonably restricts

network customers’ ability to make firm

sales from their generation and that

similar restrictions do not apply to

transmission providers’ own generation

resources.133 It asserts that this

restriction on network customers ‘‘is

unnecessarily limiting both the number

of competitors and the array of

generation products available, as well as

skewing the market in favor of

generation sales by incumbent public

utility transmission providers.’’ 134 If the

Commission does not change its

position, NRECA states that the

Commission should at least provide

network customers greater flexibility in

designating network resources under

section 30.1 of the pro forma tariff:

the Commission should at least grant

network customers the ability to designate

network resources over shorter time periods

(e.g., one month) or permit the network

customer to designate its network resources

in a manner that varies by season or by

month to track projected variations in

network loads plus reserve requirements.

This would provide network customers more

flexibility in using their network resources to

make firm off-peak sales to loads other than

their network loads when it makes economic

sense to do so, while still ensuring that

adequate resources are committed to meet the

network load and reserve requirements of the

period.135

TDU Systems adds that if the

Commission does not change its

position, ‘‘transmitting utilities should

be required to designate their network

resources, and those resources, too,

should be restricted to serving the

transmitting utilities’ network loads.’’136

Commission Conclusion. We disagree

with NRECA, as well as TDU Systems,

that the restrictions set forth in section

30.4 of the pro forma tariff do not also

apply to a transmission provider’s own

generation resources. In Order No. 888,

we explicitly stated that

a transmission provider taking network

service to serve network load under the tariff

also is required to designate its resources and

is subject to the same limitations required of

any other network customer.137

In addition, we note that, contrary to

NRECA’s assertion, the pro forma tariff

does not prevent network customers

from designating network resources over

shorter time periods or in a manner that

varies by season or by month. It only

prohibits network customers from

making sales from designated network

resources. The purpose of the

prohibition is to ensure that such

resources are available to meet the

network customer’s network load on a

non-interruptible basis. Sections 30.2

and 30.3 of the pro forma tariff already

provide network customers with a

significant level of flexibility.

Specifically, a network customer that

seeks to engage in firm sales from its

current designated network resources

may terminate the generating resource

(or a portion of it) as a network resource

and request, as set forth in section 29 of

the pro forma tariff, that the same

generation resource be designated as a

network resource effective with the end

of its power sale. We note that network

customers, as well as the transmission

provider’s merchant function, must

obtain point-to-point transmission

service for off-system sales.

e. Reactive Power. NY Com states that

under Order No. 888–A ‘‘a transmission

customer may satisfy part of its

obligation [to supply reactive power

service] through self-provision or

purchases from generating facilities

under the control of the control area

operator.’’ 138 It requests clarification

that the phrase ‘‘under the control of the

control area operator’’ refers only to

generators with continuously operating

automatic voltage control (AVC). NY

Com argues that units that do not have

AVC and operate ‘‘flat out’’ do not

support reliability and increase

operating difficulty and inflict higher

costs because system operators need to

monitor local voltage levels and

anticipate changing reactive support

requirements.

The Independent Power Producers of

New York, Inc. (NY IPPs) responds to

NY Com’s request that only generators

with continuously operating AVC be

allowed to self supply reactive

power.139 It asserts that ‘‘[t]here is no

reason to suppose that the Commission

intended that suppliers of reactive

power without AVC should not receive

credit for the service they render.’’140 It

claims that NY Com’s assertion that

generators that do not have AVC and

operate flat out cannot supply reactive

power without inflicting higher costs on

the system ‘‘shows a fundamental

misunderstanding of the operations of

an electric generator.’’ 141 It maintains

that

[t]he ability to provide reactive support at

full power output without imposing higher

system costs has nothing to do with whether

a generator has AVC. Rather, the ability to

provide reactive power support stems from

the design of the generator itself, specifically

the rating of the rotor and stator windings.

The NYPSC’s assertion that providing

reactive support manually ‘‘increases

operating difficulty and inflicts higher costs

because system operators need to actively

monitor local voltage levels, and anticipate

changing local voltage levels’’ is both

unsupported and irrelevant.[142]

Moreover, it asserts that ‘‘[t]o the extent

that generators with AVC that self

provide reactive support render a more

valuable service than those that self

provide reactive support without AVC,

they should be credited accordingly—

but that does not mean that generators

without AVC should not be credited at

all for self providing reactive

support.’’ 143 In addition, NY IPPs

responds to NY Com’s assertion that it

has discouraged the practice of manual

voltage support by requiring non-utility

generators to either use AVC or pay a fee

based on the absorption of reactive

power. It states that NY Com’s

requirement ‘‘that non-utility generators

pay a utility when the generator absorbs

reactive power at the utilities’ request is
64704 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

144 Id. (emphasis in original).

145TAPS at 28.

146 Id. at 29.

147 Id. at 30.

148 Id. 149 Id.

150 Id. at 34.

151FERC Stats. & Regs. ¶ 31,048 at 30,325.

152See Appendix B and note 1 supra.

153TDU Systems at 15.

154 Id.

currently the subject of litigation in the

United States District Court for the

Northern District of New York.’’ 144

TAPS is concerned that without

specific tariff language some

transmission providers will try to deny

reactive power credits to transmission

customers that should otherwise receive

such credits. It suggests that the

following language should be added to

the pro forma tariff:

The service agreement of the transmission

customer that can supply at least a part of the

reactive service it requires, either through

self-supply or purchases from a third party,

shall specify the generating sources made

available by the transmission customer that

provide reactive support.[145]

TAPS also asks the Commission to

clarify that the phrase ‘‘under the

control of the control area operator’’

refers to ‘‘the reactive production or

absorption capability of the generator

and not necessarily to the generator’s

ability to produce real power.’’ 146 It

states that

while a generator’s real power output may

be on automatic generation control (AGC)

and dispatched economically, its reactive

power output usually is not on automatic

control or dispatched on a moment-bymoment basis. Rather, the plant operator

separately regulates the output of the two

kinds of power. As a result, a customer can

give the control area operator the ability to

rely upon the customer’s generation to

produce or absorb reactive power

independent of control over the unit’s real

power output, for example, by the customer’s

setting its generator’s voltage regulator to

respond to the needs of the control area as

established by the control area operator.

Thus, the Commission’s statement that ‘‘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,’’ (Order No. 888–A at 150–51)

should not be read to require that the entire

generating unit be under the control area

operator’s control.[147]

Furthermore, TAPS argues that

comparable standards should be applied

to customer-owned and transmission

provider facilities. ‘‘The control area

operator should not be permitted to

refuse the offer of a customer to turn

over to the control area operator the

control of the reactive capabilities of the

customer’s generating facilities.’’ 148

Moreover, it asserts that ‘‘[i]f the control

area operator is able to rely upon its

own or its customer’s facilities to

produce or absorb reactive power, then

rate base treatment or credits,

respectively, are appropriate.’’ 149

Commission Conclusion. We do not

agree with NY Com’s assertion that the

phrase ‘‘generating facilities under the

control of the control area operator’’

refers only to generators with AVC. We

clarify that what is ‘‘under the control

of the control area operator’’ in

Schedule 2 of the pro forma tariff is the

reactive production and absorption

capability of the generator and not the

generator’s ability to produce real

power. With regard to the dispute

between NY Com and NY IPPs

concerning the appropriate reduction in

charges for Reactive Supply and Voltage

Controls from Generation Sources

Service, we find that this dispute is factspecific and beyond the scope of this

proceeding.

There is no need to add the specific

language to the pro forma tariff as

requested by TAPS. As stated in Order

No. 888–A, the Commission specifically

requires that a transmission customer’s

service agreement specify all reactive

supply arrangements, including the

generating resources made available by

the transmission customer that provide

reactive support.

In response to TAPs’ other concern,

we note that Order No. 888 requires that

a transmission customer obtain or

provide ancillary services for its

transactions. We do not intend that

requirement to provide a means for a

generation owner to compel a

transmission provider to purchase

services it may not need. As we stated

in Order No. 888–A, 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.

f. Network Operating Agreements.

TAPS asks that section 29.1 of the pro

forma tariff be modified to permit a

network customer to request that a

network operating agreement be filed on

an unexecuted basis, just as it may

request a network service agreement to

be filed on an unexecuted basis. It

asserts that this would ‘‘permit service

to commence, pending resolution of

disputed matters, and would reduce the

ability of the transmission provider to

use the network operating agreement as

a competitive tool.’’ 150

Commission Conclusion. In Order No.

888–A, in response to TAPS’ argument

that to avoid improper use of operating

agreements by transmission providers

the 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, we rejected

mandating a particular network

operating agreement but indicated that

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.151

On rehearing, TAPS points out that our

approach would still permit a

transmission provider to delay the

commencement of service. We recognize

this and will permit a network customer

to request that a network operating

agreement be filed on an unexecuted

basis, just as we have allowed a network

customer to request that a network

service agreement be filed on an

unexecuted basis. Accordingly, we will

modify section 29.1 of the pro forma

tariff by adding the following language

to the end of section 29.1: ‘‘, or requests

in writing that the Transmission

Provider file a proposed unexecuted

Network Operating Agreement.’’ 152

g. Network customers with loads and

resources in multiple control areas. TDU

Systems argues that Order No. 888–A

does not respond to its ‘‘core contention

that network service under the pro

forma tariff does not provide them

comparable service.’’ 153 It argues that

[r]equiring the network customer to assign

a designated network resource to a single

control area, and arbitrarily limiting the

ability of a network customer to schedule the

output of network resources between and

among control areas by limiting the output of

those resources to network load in a single

control area, effectively prevents the network

customer from operating an integrated

system.154

Thus, it requests that the Commission

‘‘rule that TDU systems with loads and

resources in multiple control areas may
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64705

155 Id. at 18.

156TAPS at 18 n.36.

157Alternatively, a network customer with

resources and load in multiple control areas may

elect to designate only such load that is located in

a single control area as its designated network load

and separately arrange for transmission service (e.g.,

point-to-point service) to serve load in adjacent

control areas from generation resources located in

the control area in which it designated its network

load. Here too the network customer would be

receiving comparable transmission service because

a transmission provider or any other network

customer seeking to serve load in an adjacent

control area would also have to arrange for pointto-point transmission service to make the service

possible.

158FERC Stats. & Regs. ¶ 31,048 at 30,255.

159TDU Systems at 23.

160FERC Stats. 7 Regs. ¶ 31,048 at 30,261–62.

161 In this regard, we will not mandate that a

transmission provider accept a customer-specified

approach to resolving any double recovery

concerns.

162See also TDU Systems at 10–12 (raising

similar arguments with respect to waivers of Order

No. 889).

designate as Network Resources for each

control area the totality of their

resources that meet the owned,

purchased, or leased requirement of

section 1.25 of the tariff.’’ 155

TDU Systems further asserts that a

network customer can integrate loads

and resources in multiple control areas

only by purchasing network service in

each control area and point-to-point

service for transmission between the

control areas. Thus, it argues,

[A]bsent a regional network tariff, the

Commission should require the provision of

service to network customers with loads and

resources 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.156

Commission Conclusion. We disagree

with TDU Systems that network service

under the pro forma tariff does not

provide network customers with

comparable service. Significantly, a

network customer with resources and

loads in multiple control areas is simply

not similarly situated to a transmission

provider serving native load located

entirely within the transmission

provider’s single control area. Unlike a

transmission provider serving load

entirely within a single control area, a

network customer with resources and

loads in multiple control areas must not

only integrate its resources and loads

within the individual control areas, but

must also arrange transmission services

(network or point-to-point) for

transactions occurring between and

among the multiple control areas in

which it seeks to transact business.

However, we emphasize that if a

transmission provider has resources and

loads in multiple control areas, it must

treat network customers that also have

resources and loads in multiple control

areas on a comparable basis.

In this regard, we also disagree with

TDU Systems’ assertion that we have

required a network customer to assign a

designated network resource to a single

control area and limit the scheduling of

such resources to serve load in a single

control area. Tariff sections 30.6 and

31.3 allow for the designation of both

network resources and network loads

that are not physically interconnected

with the transmission provider. Under

the pro forma tariff, a network customer

that seeks network service for all of its

loads in multiple control areas may

designate all such loads as network

loads.157 By designating all of its loads

as network loads, such network

customer will receive comparable

service in each control area and will

have the ability to schedule the output

of network resources between and

among control areas, just as a

transmission provider or other network

customer would need to do to serve load

in an adjacent control area.

TDU Systems is concerned with the

rates it must pay to the various control

area operators to integrate its resources

and loads. In rejecting TDU Systems’

virtually identical argument in Order

No. 888–A, we explained:

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.158

h. Network customer designation of

load. TDU Systems asks the

Commission to clarify that open access

transmission providers must credit or

eliminate double charges arising from

the inability of network customers to

designate less than all of the load at a

delivery point as network load. TDU

Systems asks the Commission to make

the following points clear:

first, there will be no double recovery of

either transmission costs or ancillary costs

that are being recovered in the existing

bundled generation supply agreement;

second, as the Commission properly noted in

requiring the unbundling of bilateral

economy energy coordination transactions,

the transmission provider will not be

permitted to recover more under the new

arrangement for those (transmission and

ancillary) services than it does under the

existing bundled generation supply

agreement; and third, the transmission

provider is required to achieve these results

by using one of the alternatives stated in

Order No. 888–A at the transmission

customer’s election or by an alternative

arrangement agreed upon by the customer.159

It concludes that ‘‘[i]f the Commission

relegates the customer to a section 206

complaint proceeding, it has reversed

the burden of proof on the transmission

provider to show that its increased rate

is just and reasonable.’’

Commission Conclusion. As noted by

TDU Systems, we stated in Order No.

888–A that

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.160

We intended this language to apply

broadly and, accordingly, clarify that it

applies to transmission costs and

ancillary costs. Moreover, while we

expect transmission providers to design

rates that will avoid double recovery of

such transmission costs or ancillary

costs, we believe that this is a factspecific issue that is appropriately

addressed on a case-by-case basis.161

Finally, while we indicated in Order

No. 888–A that a transmission customer

may file a complaint under section 206

with the Commission to address any

claims of double recovery, the

transmission customer would most

likely raise this issue in the section 205

proceeding in which the transmission

provider files to initiate the particular

service with the transmission customer.

Indeed, it would be in such a section

205 proceeding in which this

transitional problem would first arise

and the transmission customer would

first have the opportunity to challenge

any possible double recovery.

11. Waivers of Order Nos. 888 and 889

NRECA states that the Commission’s

policy on waivers of Order Nos. 888 and

889 provides that such waivers

terminate upon a request for service or

a complaint. It argues that permitting

the termination of a waiver upon a

complaint improperly subjects the

utility to baseless complaints and

significantly diminishes the value of the

waiver. It asserts that a waiver of Order

No. 889 should terminate only upon a

finding by the Commission that there is

a valid basis for the complaint.162

Similarly, it asserts that a waiver of

Order No. 888 should terminate ‘‘only

upon a Commission order finding that,

in light of changed circumstances or

new evidence, the waiver should not be
64706 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

163NRECA at 12.

164FERC Stats. & Regs. ¶ 31,036 at 31,853.

165Open Access Same-Time Information System

and Standards of Conduct, Final Rule, Order No.

889, 61 FR 21737 (May 10, 1996), FERC Stats. &

Regs. ¶ 31,035 (1996), order on reh’g, Order No.

889–A, 62 FR 12484 (March 14, 1997), FERC Stats.

& Regs. ¶ 31,049 (1997), order on reh’g, Order No.

889–B, published elsewhere in this issue of the

Federal Register, FERC Stats. & Regs. ¶llll

(1997).

166NRECA’s request with respect to the

revocation of waivers of Order No. 889 is addressed

in Order No. 889–B, which is being issued

concurrently with this Order. In Order No. 889–B,

the Commission notes that in Central Minnesota

Municipal Power Agency, et al., 79 FERC ¶ 61,260

(1997) (Central Minnesota), it already has revised its

approach concerning the revocation of waivers of

Order No. 889 to provide that such waivers will

remain effective until the Commission takes action

in response to a complaint, rather than until 60

days after a complaint to the Commission.

167Central Minnesota, 79 FERC at 62,127 (1997).

168NEPOOL at 2.

169New England Power Pool, 79 FERC ¶ 61,374

(1997), reh’g pending.

170NY Com at 5–12.

171See Order No. 888, FERC Stats. & Regs.

¶ 31,036 at 31,969 (Appendix G) and Allegheny

Power System, Inc., et al., 80 FERC ¶ 61,143 at

61,551–52 (1997).

172See Order No. 888, FERC Stats. & Regs.

¶ 31,036 at 31,969.

173NY Com at 12.

174 Id. at 13 (emphasis in original).

continued and the utility should be

required to file the pro forma tariff.’’ 163

Commission Conclusion. NRECA’s

request for rehearing with respect to the

termination of a waiver of Order No. 888

should have been raised on rehearing of

Order No. 888, which first established

that a waiver would be granted if,

among other things, the utility

‘‘commits to file an open access tariff

within 60 days of a request to use its

facilities and to comply with the rule in

all other ways.’’ 164 Nothing set forth in

Order No. 888–A changed this

requirement. Accordingly, NRECA’s

request for rehearing was not timely

filed.

However, we note that the

Commission, in a recent order

modifying the circumstances under

which a waiver of Order No. 889 165 will

be revoked,166 addressed this very issue:

we will not, however, alter our

determination that a utility that has been

granted waiver of Order No. 888 is required

to file a pro forma tariff within 60 days after

it receives a request for transmission service

and must comply with any additional

requirements that are effective on the date of

the request. The filing with the Commission

of a pro forma tariff places significantly less

burden on a utility than does full compliance

with Order No. 889, and we continue to

believe that 60 days from receipt of a request

for service provides sufficient time for such

compliance.167

12. Financial Independence of ISO

Employees

NEPOOL expresses concern that the

requirement in Order No. 888–A that

ISO employees sever all financial ties

‘‘can be interpreted to foreclose the

Commission from even considering the

merits of provisions for ownership of

securities by ISO employees contained

in NEPOOL’s ISO proposal that is now

pending before the Commission in

Docket Nos. OA97–237–000 and ER97–

1079–000.’’ 168 It contends that

severance of all financial ties would

impose an economic hardship on

certain NEPOOL employees in pension

and stock ownership plans of market

participants through the years. In

particular, it notes that many of the

existing NEPOOL staff have

accumulated Northeast Utilities stock in

their pension or other employee benefit

plans, but that the market price of that

stock has recently declined

significantly. However, NEPOOL has

required ISO employees to divest

themselves of such securities in excess

of $50,000 within six months of their

employment by the ISO. Thus, NEPOOL

requests that the Commission clarify

that it could waive the requirement that

ISO employees sever all financial ties

with market participants in compelling

circumstances or clarify the acceptable

length of a transition period during

which they may continue to hold such

securities.

Commission Conclusion. In a recent

order conditionally authorizing the

establishment of an ISO by NEPOOL,

the Commission specifically addressed

the concerns raised here by NEPOOL.169

The Commission rejected NEPOOL’s

proposal to allow employees to possess

securities of market participants as long

as the value does not exceed $50,000.

The Commission reaffirmed its strong

commitment, set forth in Order Nos. 888

and 888–A, to ensure that an ISO is

truly independent and that employees

of an ISO are financially independent of

market participants. However, the

Commission recognized, as it had in

Order No. 888–A, that there may be a

need for flexibility with respect to the

length of a transition period and that

this matter is best addressed on a caseby-case basis.

13. Distribution Charges

NY Com seeks clarification of the

Commission’s statement that a utility is

free to include a ‘‘distribution charge’’

in a customer’s service agreement and/

or the network customer’s network

operating agreement.170 In particular, it

requests that the Commission clarify

that it did not intend to preempt state

jurisdiction, but rather that when a

term, condition or rate is required for

local distribution service, the state

determination will apply. It asserts that

such a clarification would avoid forum

shopping that would otherwise occur. In

the alternative, it requests rehearing,

arguing that the Federal Power Act, its

legislative history and case law all

dictate against Commission jurisdiction

over local distribution.

Commission Conclusion. We clarify,

as requested by NY Com, that when a

term, condition or rate is required for

local distribution service the state

determination applies. We reiterate that

we believe there is always a local

distribution service element of a retail

transaction, through which the state

may impose charges on the retail

customer. We also reiterate, however,

that where a public utility is delivering

unbundled energy to a supplier that

then resells the energy to an end-user,

the Commission has exclusive

jurisdiction over the public utility’s

facilities used to effect the transaction

without regard to their being labeled

‘‘transmission,’’ ‘‘distribution,’’ or ‘‘local

distribution.’’ 171 Moreover, where a

public utility is delivering unbundled

energy from a third-party supplier

directly to an end user, the particular

facts of the case will determine which

of the facilities are FERC-jurisdictional

transmission facilities and which are

state-jurisdictional local distribution

facilities.172

14. Tight Power Pools

a. Non-pancaked rates. NY Com seeks

clarification of the following statement

in Order No. 888–A:

Order No. 888 does not require a nonpancaked rate structure unless a nonpancaked 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.173

It argues that this statement conflicts

with other statements that ‘‘require

power pools to file joint pool-wide

tariffs and to offer all transmission

services that they are capable of

providing.’’ 174 NY Com asks that the

Commission clarify that utility members

of tight power pools must provide

transmission service jointly under a

single tariff. It states that this is the best

way to eliminate undue discrimination.

It argues that tight power pools must

provide, pursuant to prior Commission

orders, all transmission services that

they are reasonably capable of providing

and must file joint tariffs to provide
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64707

175However, as explained in Order No. 888–A,

the Commission did require that all transmission

rate proposals filed in compliance with Order Nos.

888 and 888–A be cost based and meet the standard

for conforming proposals set out in the

Commission’s Transmission Pricing Policy

Statement. See 18 CFR 2.22.

176Order No. 888–A, FERC Stats. & Regs. ¶ 31,048

at 31,728.

177Otter Tail at 3 (emphasis added by Otter Tail).

178 Id. at 4 (emphasis in original).

179FERC Stats, & Regs. ¶ 31,048 at 31,241.

180Mid-Continent Area Power Pool Rate

Schedule, FERC No. 5.

181FERC Stats. & Regs. ¶ 31,036 at 31,728.

182See FERC Stats. & Regs. ¶ 31,048 at 30,241.

183We note that Puget filed a rehearing request

of Order No. 888, but did not challenge the

Commission’s authority to require public utilities to

file open accesss tariffs.

184Puget at 18.

185 Id. at 19.

186Footnote 261, which is in the section entitled

Opportunity Cost Pricing, provides in relevant part

that ‘‘[u]nder the Commission’s transmission

pricing policy, utilities are limited to charging the

higher of embedded costs or opportunity/

incremental costs.’’

187Puget at 21.

188 Id. at 21–22.

transmission service on a pool-wide

basis.

Commission Conclusion. NY Com

appears to be confusing services that a

power pool is capable of providing with

pricing methodologies that a power pool

may elect to use. While the Commission

required that by December 31, 1996 all

pool transactions be taken under a joint

pool-wide tariff on file with the

Commission, the Commission did not

mandate a specific transmission rate

structure for such tariff.175 As we stated

in Order No. 888–A, the primary goal

for pooling arrangements is to ensure

comparability regarding transmission

services offered on a pool-wide basis.

Thus, comparability is achieved if the

same service is provided at the same or

comparable rate to both pool and nonpool members.176

b. Coordination transactions. Otter

Tail requests that the Commission

clarify the following statement in Order

No. 888–A:

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.177

It asks the Commission to clarify that

this statement

Is meant only to indicate that in the case of

different services, one service (e.g., wholesale

transactions) can be offered to all potential

customers under the pool tariff, but another

service (e.g., ancillary services) may not be

offered to any customers under the pool

tariff. Otter Tail specifically requests that the

Commission clarify that where the same

service is involved, pools cannot

discriminate against certain transactions

based solely on the transaction’s duration,

that is, pool-wide tariffs cannot exclude

longer term transactions but include shortterm transactions.178

In its case, Otter Tail is concerned that

MAPP limits coordination transactions

under the pool to those with a duration

of two years or less and thereby

prevents any longer term service from

using the pool tariff. It argues that

MAPP’s tariff does not comply with

Order No. 888 because it does not offer

pool-wide service for all coordination

transactions, regardless of duration.

Otter Tail further argues that excluding

the benefits of pool-wide service for

coordination transactions based only on

the length of term is contrary to, and

incompatible with, Congress’ and the

Commission’s goal to promote

competition at the generation level and

permits pools to exercise market power.

Commission Conclusion. We disagree

with Otter Tail. As we stated in Order

No. 888–A, the primary goal of Order

No. 888’s requirements for pooling

arrangements, including ‘‘loose’’ pools,

such as MAPP, is to ensure

comparability regarding transmission

services that are offered on a pool-wide

basis.179 In the case of the MAPP

agreement, pool transactions are limited

to periods not to exceed two years for

all members.180 Comparability is

achieved if all parties, both pool

members and non-pool members, are

treated in a non-discriminatory fashion

as to access to transmission services, the

types of transmission services and the

rates paid for such transmission

services.

In addition, Order No. 888 requires

loose pools to take service under a joint

pool-wide tariff for all pool

transactions.181 If transactions of more

than two years in duration are not pool

transactions, then transmission for those

transactions need not be pursuant to the

pool-wide tariff, and instead would be

provided pursuant to the individual

companies’ pro forma tariffs. This is

consistent with our finding in Order No.

888–A that we will not require pool

members to offer transmission services

to third parties that the pool members

do not provide to themselves on a

poolwide basis.182

15. Legal Authority

Puget states that the Commission does

not have the legal authority to require

public utilities to file open access tariffs

and argues that Order No. 888 does not

contain any specific finding that any

rate, term or condition of Puget’s tariff

is unjust, unreasonable or unduly

discriminatory or preferential.

Commission Conclusion. The

Commission set forth its legal authority

to require public utilities to file open

access tariffs in Order No. 888. Puget’s

request for rehearing with respect to this

issue should have been raised on

rehearing of Order No. 888 and therefore

was not timely filed.183

16. Ancillary Services

Puget argues that ancillary services

such as reactive power and voltage

control cannot be considered merely

ancillary to the provision of

transmission service, but are significant

generation services that should be

subject to market rates. Puget asserts

that ‘‘[i]t is wholly inappropriate for the

Commission to provide for the sale of

power as an ancillary service under the

pro forma tariff; instead, utilities such as

[Puget] should be compensated for the

sale of such power at market based

rates.’’ 184 It argues that the Commission

‘‘must recognize that ancillary services

are generation related and should be

priced at market in order to be

consistent.’’ 185

Commission Conclusion. Puget raises

issues that were previously addressed in

Order No. 888. In that order the

Commission determined that ancillary

services are transmission related and

indicated that market-based pricing for

ancillary services would be addressed

on a case-by-case basis. Puget’s request

for rehearing with respect to these

issues should have been raised on

rehearing of Order No. 888 and therefore

was not timely filed.

17. Fair Market Value

Puget argues that Order No. 888–A

improperly shuts the door on the

pricing of transmission property at fair

market value. Citing footnote 261 of

Order No. 888–A,186 Puget asserts that

the Commission changed its policy from

Order No. 888 and claims that in Order

No. 888–A ‘‘the Commission ruled that

each utility is now expressly limited by

the transmission pricing policy to

charging only embedded costs for

existing transmission facilities to

competitors and others even though

rates for generation assets are priced at

market.’’ 187 Puget argues that Order No.

888–A achieves ‘‘the effect of a

condemnation by forcing [Puget] and

other integrated electric utilities to

allow competitors to use private utility

property, but at less than fair market

value.’’ 188 Puget further argues that the

Constitution ‘‘does not permit the taking

of private property of one citizen to
64708 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

189 Id. at 26.

190 Id.

191 Id. at 27.

192 See Order No. 888, FERC Stats. & Regs. ¶

31,036 at 31,739–40; Order No. 888–A, FERC Stats.

& Regs. ¶ 31,048 at 30,263–66.

193Order No. 888–A, FERC Stats. & Regs. ¶ 31,048

at 30,625.

194 Id. at 30,263.

195Soyland at 8.

196 Id.

197 Id. at 10.

198FERC Stats. & Regs. ¶31,036 at 31,664.

199 In this regard, we note that other entities did

file rehearing requests of Order No. 888 seeking to

expand the scope of the contracts covered by the

Commission’s Mobile-Sierra findings. See Order No.

888–A, FERC Stats. & Regs. ¶31,048 at 30,190–91.

200TDU Systems at 33–34.

201See FERC Stats. & Regs. ¶31,036 at 31,742.

202TDU Systems at 34–35.

203 Id. at 34–35.

204FERC Stats. & Regs. ¶31,048 at 30,310.

benefit competitors or other private

citizens.’’ It contends that

[T]he voluntary provision of transmission

service to noncompetitors in an entirely costbased integrated system is not the same as a

forced provision of service and use of

property by a competitor under a new set of

regulations treating generation at market

rates.189

Puget goes on to argue that

Order 888 erroneously asserts that 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.’’ 62

Fed. Reg. at 12,433. For example, by illegally

requiring unbundling of generation assets at

market without at the same time providing

for utility recovery of the fair market value

of its transmission property, the Commission

is attempting to deprive public utilities of fair

market value compensation.190

In conclusion, Puget declares that ‘‘[t]he

Commission cannot create a situation in

which generation is sold at a new

market-based rate and transmission is

limited to an old historic embedded-cost

rate. Neither the Constitution nor the

FPA will permit such a result.’’ 191

Commission Conclusion. We reject

Puget’s rehearing request. Puget makes a

far-ranging argument that Order No.

888–A improperly shuts the door on the

pricing of transmission property at fair

market value. It bases its argument

entirely on a single footnote in Order

No. 888–A that has been taken

completely out of context. The footnote

in Order No. 888–A cited by Puget

merely recites the Commission’s

longstanding policy as to opportunity

cost pricing.192 Indeed, in the sentence

to which that footnote is attached, the

Commission explicitly stated that it

‘‘does not believe that any changes are

necessary to its policy on opportunity

cost recovery.’’ 193 Moreover, the entire

discussion to which that footnote

applies is in a section entitled

‘‘Opportunity Cost Pricing.’’ 194

18. Pre-Existing Transmission-Only

Contracts

Soyland argues that the Commission’s

Mobile-Sierra findings must apply not

only to wholesale requirements

contracts but also to unbundled

transmission-only contracts. It asserts

that ‘‘[t]here is no legitimate reason to

deny unbundled, transmission-only

customers timely and meaningful access

to the open access regime and

competitive markets on the same terms

as requirements customers.’’ 195 It

contends that it faced the same problem

as requirements customers—‘‘use of

transmission monopoly power to force a

purchase of power as a condition to

getting transmission access to deliver

owned resources from off-system.’’ 196

Moreover, it asserts that the

Commission has not explained how or

why requirements contracts and

transmission-only contracts should be

treated differently as a result of the past

and continuing changes in the industry.

Soyland further states that utilities had

the upper hand over ‘‘customers who

executed unbundled transmission and

power supply contracts simultaneously;

together, such contracts are the

functional equivalent of bundled partial

requirements contracts, and should not

be subject to a different standard for

contract reform.’’ 197

Commission Conclusion. Soyland’s

rehearing request addresses an issue

that should have been raised on

rehearing of Order No. 888. In that

order, the Commission explicitly

indicated that customers under

requirements contracts executed on or

before July 11, 1994 that contained

Mobile-Sierra clauses should have the

opportunity to demonstrate that their

contracts no longer are just and

reasonable.198 Soyland’s opportunity to

request that we expand the scope of the

contracts covered to include unbundled

transmission-only contracts was on

rehearing of Order No. 888.199

Accordingly, Soyland’s request for

rehearing with respect to this issue was

not timely filed.

19. Apportionment of Transmission

Revenues for Public Utility Holding

Companies and Power Pools

TDU Systems asks the Commission to

clarify that the ‘‘apportionment of

credits for customer transmission

facilities among the operating

companies of a utility holding company

or in power pools should be subject to

Commission approval.’’ TDU Systems

states that the method of crediting

transmission customers for operating

companies’ uses of their own and each

other’s transmission facilities in setting

transmission rates must meet the

Commission’s comparability standards

and should not be filed on a unilateral

basis. Similarly, it requests that

customer credits for pool participants’

use of their own and each other’s

transmission facilities should be subject

to Commission review in approving the

pool’s transmission rates and tariff

terms and conditions.200

Commission Conclusion. TDU

Systems’ rehearing request addresses

issues that should have been raised on

rehearing of Order No. 888. In Order No.

888, the Commission stated that credits

for customer-owned facilities should be

addressed on a case-by-case basis.201

Accordingly, TDU Systems’ request for

rehearing with respect to these issues

was not timely filed.

20. Accounting for Transmission

Provider’s Own Use of Its System

TDU Systems argues that the

Commission’s requirement that a

transmission provider’s methodology to

credit customers for the transmission

provider’s off-system sales be addressed

in compliance filings and will depend

on the rate design is insufficient.202 It

argues that this ignores that

Comparability has a time dimension,

requiring the prompt crediting of such

charges if they are not automatically

accounted for in the rate design. Thus, the

order fails to address whether a new kind of

rate mechanism is needed if comparability is

to be ensured on an ongoing basis under

open-access transmission, just as the

Commission years ago approved the use of

fuel-adjustment clauses to deal with more

volatile fuel prices. Requiring parties to

resolve this issue in individual compliance

filings does not address this generic problem.

The Commission should provide more

guidance to public utilities as to what

crediting mechanisms are necessary if

comparability is to be achieved.203

Commission Conclusion. In Order No.

888–A, the Commission explained that

an automatic pass-through mechanism

for revenue credits raises a number of

potential problems including: ‘‘(1) use

of estimates versus actuals; (2) the

appropriate time period to be utilized

and (3) firm versus non-firm

distinctions.’’ 204 The Commission

further noted that the appropriate

treatment of revenue credits for offsystem sales is dependent on the rate

design used by a transmission provider

and concluded that this issue is not

appropriately resolved on a generic

basis. Despite these identified problems,

TDU Systems continues to request that
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64709

205See Treatment of Purchased Power in the Fuel

Cost Adjustment Clause for Electric Utilities, FERC

Stats. & Regs. ¶30,524 at 30,800 (1983).

206 In Pennsylvania-New Jersey-Maryland

Interconnection, et al., 81 FERC ¶llll (1997),

issued concurrently with this order on rehearing,

the Commission made an exception to its general

approach to revenue credits and allowed monthly

crediting of non-firm transmission revenues.

However, this was done in the context of a major

restructuring of a tight power pool.

207See, e.g., Pennsylvania Power Company, 26

FERC ¶61,354 at 61,781 (1984).

208FERC Stats. & Regs. ¶31,048 at 30,310

(emphasis added).

209Some of the rehearing requests raise issues

that previously were raised on rehearing of Order

No. 888 and were addressed by the Commission in

Order No. 888–A. The Commission will not further

address such issues in this proceeding. For

example, Puget repeats some of the same arguments

that it raised in its request for rehearing of Order

No. 888 concerning the federal causes of stranded

costs, the Commission’s alleged abdication of its

legal authority to ensure recovery of stranded costs

associated with bypass and retail wheeling, the

application of the reasonable expectation test to

departing retail customers, and the Commission’s

failure to include deferred costs in the revenues lost

formula. The Commission addressed these concerns

in Order No. 888–A. See FERC Stats. & Regs.

¶31,048 at 30,358–62, 30,424, 30,426–27. TDU

Systems reiterates its objection to the Commission’s

elimination of the section 35.15 prior notice of

termination requirement for power sales contracts

executed after July 9, 1996 that terminate by their

own terms. The Commission addressed TDU

Systems’ concerns in this regard in Order No. 888–

A. See FERC Stats. & Regs. ¶31,048 at 30,392,

30,393–94.

210FERC Stats. & Regs. ¶31,036 at 31,818.

211FERC Stats. & Regs. ¶31,048 at 30,408–09.

212As discussed above, APPA filed its request for

rehearing out-of-time. Accordingly, we are treating

APPA’s pleading as a motion for reconsideration.

213See APPA, CAMU, IL Com, NARUC, TAPS.

TDU Systems, on the other hand, argues that the

Commission should permit non-public utilities

providing reciprocal transmission service to recover

stranded costs arising from municipal annexation.

TDU Systems submits that allowing public utilities

to seek stranded cost recovery arising from

municipal annexation exacerbates the unequal and

unduly discriminatory treatment accorded

transmission dependent utilities and electric

cooperatives.

214See APPA at 11–12; IL Com at 4–5; NARUC

at 2–3.

215E.g., APPA at 12–13; NARUC at 3; TAPS at

24–25. APPA objects that federal regulation of

stranded costs associated with municipal

annexation results in the establishment of

overlapping federal/state authority that precludes

the execution of state laws by state authority in a

matter normally within the power of the state, in

violation of the Tenth Amendment. APPA at 13.

216APPA at 11; see also NARUC at 3.

217CAMU at 2.

218 Id.

219NARUC at 3–4.

the Commission adopt an automatic

revenue credit mechanism without

attempting to address such problems or

proposing an appropriate mechanism to

accomplish its request.

To bolster its proposal, TDU Systems

claims that automatic treatment of

revenue credits is comparable to the

Commission treatment of fuel charges

through the use of an automatic fuel

adjustment charge. We disagree. An

automatic fuel cost adjustment clause

was determined to be appropriate

because of the unpredictability of fuel

prices.205 TDU Systems has not

demonstrated that revenue credits

warrant the same treatment.206

Moreover, TDU Systems has not

demonstrated that the lack of an

automatic credit mechanism is likely to

result in unjust and unreasonable rates.

For example, the Commission’s

traditional means of accounting for

transmission revenues from non-firm

uses of the transmission system is to

reflect a representative level of revenue

credits (based on historical and/or

projected revenue levels) in each rate

case, which has the effect of lowering

the transmission rate for all firm

transmission users.207 TDU Systems has

not shown why a similar rate case

approach to revenue credits (as opposed

to an automatic credit mechanism) is

not appropriate, particularly for all

transmission providers. In any event, we

would anticipate little or no difference

between the results of an automatic

revenue credit mechanism and our

traditional approach and TDU Systems

has not shown otherwise.

Finally, TDU Systems’ proposal is

one-sided in that it would only require

the automatic passthrough of revenues

from the transmission provider’s use of

the transmission system for off-system

sales. As the Commission stated in

Order No. 888–A,

revenue from the transmission component

of all off-system 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.208

B. Stranded Cost Issues 209

1. Municipal Annexation

In Order No. 888, the Commission

decided that it would 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.210 In Order

No. 888–A, the Commission

reconsidered this decision and

concluded that it would be the primary

forum for stranded cost recovery in a

discrete set of municipal annexation

cases, namely, those involving existing

municipal utilities that annex retail

customer service territories and, through

the availability of Commission-required

transmission access, use the

transmission system of the annexed

customers’ former supplier to access

new suppliers to serve the annexed

load.211

A number of petitioners seek

rehearing or reconsideration 212 of the

Commission’s decision in Order No.

888–A to be the primary forum for

stranded cost recovery in the case of

municipal annexations.213 Some oppose

this decision for the same reasons that

they opposed the Commission’s

decision to be the primary forum for

stranded cost recovery in the case of

new municipal utilities. For example,

some entities argue that the Commission

does not have any authority with

respect to costs in retail rate base that

may be stranded as a result of the

annexation of electric service territory

by a municipal utility.214 A number of

petitioners also contend that municipal

annexation occurs pursuant to state or

local law, not federal law, and that

every facet of municipal annexation,

including compensation and valuation,

is governed by state or local

authorities.215

Several submit that annexation is a

form of franchise competition that

predated Order No. 888, that

transmission access was available

(though not as readily as after Order No.

888) for many franchise competitors

utilizing annexation, 216 and that

annexations have occurred and will

continue to occur based upon

motivations removed from the open

access regime.217 CAMU states that

[a]nnexations have occurred and will

continue to occur in a[n] unbroken string

based upon motivations entirely removed

from this Commission’s open access regime.

There is simply no reason to assume that the

open access rule will accelerate the pace of

annexations. [218]

NARUC asks the Commission to grant

rehearing as a matter of policy. It argues

that the Commission’s assertion of

authority to address stranded cost issues

related to annexation will force the

Commission to inject itself into stateestablished processes to second-guess a

state commission’s cost recovery

determinations. According to NARUC,

this will require the Commission to

resolve difficult factual issues to match

specific generation and transmission

facilities with specific annexed

customers.219

CAMU similarly contends that the

Commission’s assertion that it is the

primary forum for the resolution of

annexation-related stranded cost issues

will introduce needless procedural

complications. CAMU submits that

various state-created mechanisms exist

for the identification and payment of

just compensation in the case of

municipal annexations. It questions
64710 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

220CAMU at 3–5. CAMU notes that some state

compensation statutes require the annexing

municipality to pay ‘‘expectation’’ damages for a

defined future period based upon revenues received

from the annexed area. CAMU says that this

element of damage, which is applied in addition to

payment for condemned facilities, is meant to

liquidate claims for lost service territory, idled

generation assets and other business opportunities,

but the awards do not separately value each of these

elements of damage. CAMU questions how the

Commission is going to ascertain what element of

recovery pertains specifically to stranded costs if a

state has adopted this liquidated damages approach.

Id. at 5.

221 IL Com at 5.

222 Id. at 5–6.

223 In so doing, we also reiterate our concern

(expressed in Order Nos. 888 and 888–A) 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. In Order Nos. 888 and

888–A, we reserved the right to address such

situations on a case-by-case basis. Order No. 888,

FERC Stats. & Regs. ¶ 31,036 at 31,819; Order No.

888–A, FERC Stats. & Regs. ¶ 31,048 at 30,409.

224Order No. 888, FERC Stats. & Regs. ¶ 31,036

at 31,819; Order No. 888–A, FERC Stats. & Regs. ¶

31,048 at 30,405.

225Order No. 888–A, FERC Stats. & Regs. ¶ 31,048

at 30,405.

226 Id. at 30,410.

227See City of Las Cruces, New Mexico, 80 FERC

¶ 61,160 (1997).

228Order No. 888–A, FERC Stats. & Regs. ¶ 31,048

at 30,405. See also Order No. 888, FERC Stats. &

Regs. ¶ 31,036 at 31,819.

229Order No. 888–A, FERC Stats. & Regs. ¶ 31,048

at 30,405.

230TAPS at 27.

how the Commission will offset against

stranded cost recovery any

compensation provided under state law

and whether the Commission will await

the completion of state proceedings

before it addresses the issue. 220 CAMU

asks the Commission to defer to existing

state mechanisms and to be the primary

forum for the resolution of stranded cost

recovery issues in annexation situations

only where there is no state procedure

for stranded cost recovery.

IL Com argues that determining

whether the availability of wholesale

open access is the principal cause of the

stranding of public utility costs would

be administratively difficult. 221 IL Com

also submits that the Commission’s

expectation that parties raise retailturned-wholesale stranded cost claims

before this Commission in the first

instance is internally inconsistent with,

and contradictory to, its statements that

it will give great weight in its

proceedings to a state’s view of what

might be recoverable and will deduct

any recovery a state has permitted from

departing retail-turned-wholesale

customers from the costs for which the

utility will be allowed to seek recovery

under the Rule. 222

Commission Conclusion. After careful

consideration of the arguments raised

on rehearing, we have decided not to

grant rehearing, but we do provide

further clarification of our decision in

Order No. 888–A to be the primary

forum for stranded cost recovery in

certain cases involving municipal

annexation. As a policy matter, we will

consider recovery of stranded costs that

potentially could arise as a result of

municipal annexation but only when

there is a sufficient nexus in such cases

to the Commission’s Open Access Rule.

To clarify, this determination to be the

primary forum is not a blanket

determination for all cases involving

annexation. A determination of what

circumstances make Commission review

appropriate will be made on the facts

pertinent to individual cases. The

Commission has limited the opportunity

to seek stranded cost recovery under the

Rule to situations in which the

availability and use of wholesale open

access transmission enable a generation

customer to escape a current power

supplier to obtain cheaper power

supplies. Annexations occur for a

myriad of reasons that may have

nothing to do with seeking less

expensive power supplies (for example,

tax or zoning considerations or

consolidation of local public services).

These reasons existed before adoption of

Order No. 888 and, absent the nexus to

the new availability of these

transmission services, would not require

us to consider the stranded costs from

annexation in the first instance. On the

other hand, an existing municipal utility

that has newly-annexed territory may

use an open access tariff of the annexed

customers’ former power supplier.

Accordingly, the Commission does not

believe it is necessary to reverse its

previous position that annexations may

raise jurisdictional stranded cost issues

but instead provides this clarification.

In the course of reviewing the

rehearing petitions on annexation, the

Commission has also had the

opportunity to reflect on the rationale

for our decision to be the primary forum

for addressing the recovery of stranded

costs associated with retail-turnedwholesale customers (including a

newly-formed municipal utility). We

wish to further elaborate upon and

clarify our prior discussions about

recovery of costs stranded by retailturned-wholesale customers. 223

First, in setting forth our position on

costs stranded in certain retail-turnedwholesale and municipal annexation

situations, the Commission recognized

that states may also have jurisdiction

over retail-turned-wholesale stranded

costs and that state adjudications of

such costs may precede consideration of

them here. 224 Moreover, we indicated

that ‘‘we are not second-guessing the

states as to what a utility may recover

under state law.’’ 225 As we stated in

Order No. 888–A and reiterate here,

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.226

In making this statement, the

Commission clearly recognized that it

may indeed be the states that first

address the difficult stranded cost issues

associated with the formation of new

municipal utilities or other wholesale

entities. The Commission contemplated

then, as now, that it would nevertheless

adjudicate these stranded cost issues

where states lack authority to do so or

where, based on the record before us,

they fail to provide a forum.227

Second, as the Commission stated in

Order No. 888–A,

if the state has permitted any recovery from

departing retail-turned-wholesale customers

[for example, if it imposed an exit fee prior

to, or as a condition of, creating the

wholesale entity], 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.228

Further, we will take into account state

findings on cost determinations

associated with retail-turned-wholesale

situations and ‘‘we will give great

weight in our proceedings to a state’s

view of what might be recoverable.’’ 229

We believe it is important to emphasize

that in those instances where states do

address stranded costs associated with

retail-turned-wholesale customers and

in cases of municipal annexation, we

intend to give substantial deference to

their determinations.

2. Pre-existing Transmission Rights

TAPS requests clarification that the

required nexus between the availability

and use of Commission-required

transmission access and the stranding of

costs would not be met ‘‘if the

municipal utility, including as

expanded through annexation,

possessed rights to transmission prior to

Order No. 888 and EPAct (for example,

NRC license conditions and the

like).’’ 230 TAPS submits that ‘‘[t]he

utility exercising these transmission

rights should not be subject to stranded

costs claims before the Commission

simply because the municipal utility

chooses to use the Commission’s

preferred open access tariff, instead of a
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64711

231 Id.

232As we explained in Order No. 888–A, we

declined to include ‘‘exercise of pre-existing

contract rights for transmission and designation of

wholesale loads’’ as an example of a situation for

which stranded costs may not be sought because we

are not prepared to make individual factual

determinations in the context of the Rule. The

Commission will address specific requests for

stranded cost recovery on the facts presented and

the merits of the particular request. FERC Stats. &

Regs. ¶ 31,048 at 30,358.

233See Duquesne Light Company, 79 FERC

¶ 61,116 at 61,520 (1997).

234FERC Stats. & Regs. ¶31,048 at 30,440.

235Boston Edison at 3.

236See City of Alma, Michigan, 80 FERC ¶61,265

at 61,961 (1997).

237RUS at 16.

238 Id. (citing Order No. 888–A, FERC Stats. &

Regs. ¶31,048 at 30,366).

bilateral or other arrangement available

under pre-existing rights.’’ 231

Commission Conclusion. We will

deny TAPS’ requested clarification. The

existence of rights to transmission prior

to Order No. 888 would not, in and of

itself, indicate that the customer should

be relieved of potential stranded cost

liability under Order Nos. 888 and 888–

A.232 It may be that a customer with

some right to transmission service prior

to Order No. 888 (for example, as a

consequence of NRC license

conditions), was unable to reach an

alternative supplier through the use of

that transmission. Thus,

notwithstanding the existence of preexisting transmission rights, and

depending on the facts of a particular

case, it may be that the utility incurred

costs based on a reasonable expectation

of continuing to serve the customer.

On this basis, the Commission will

not conclusively presume that a

customer with a pre-existing right to

transmission service could never be

subject to a stranded cost obligation

under Order Nos. 888 and 888–A.

Similarly, the Commission will not

conclusively presume that the mere

existence of a pre-existing right to

transmission service precludes any

reasonable expectation of continued

service by the utility. However, the

existence of pre-existing transmission

rights, and any circumstances

surrounding them, may be used as

evidence in the determination of

whether the utility had a reasonable

expectation of continuing to serve a

customer. 233

3. Load Growth and Excess Capacity

Boston Edison seeks rehearing of the

Commission’s finding in Order No. 888-

A that a ‘‘cost is not stranded if it is

fully recovered in the cost-based rates

paid by native load.’’ 234 It submits that

this phrase

Suggests that the cost of capacity released

by a departing wholesale customer can and

should be recovered in the rates of the

remaining retail and wholesale customers if

the remaining customers’ load or load growth

will be sufficient to absorb the released

capacity. . . . Such cost shifting directly

contradicts the cost responsibility principles

set forth in Order No. 888 [i.e., direct

assignment].235

Boston Edison objects that the rationale

for this policy reversal is not articulated

in Order No. 888–A.

Commission Conclusion. At the

outset, we reiterate that we remain

committed to the cost responsibility

principles established in Order No. 888

and continue to believe that a departing

wholesale customer should be

responsible for the costs it strands. Our

statement that a ‘‘cost is not stranded if

it is fully recovered in the cost-based

rates paid by native load’’ was not

meant to imply that the cost of capacity

released by a departing wholesale

customer should always be recovered in

the rates of the remaining retail and

wholesale customers through load

growth. Rather, our discussion of load

growth correctly recognizes that in some

instances a utility can meet native load

growth with existing capacity freed-up

by the departure of wholesale load. If a

utility can recover the costs of existing

capacity freed up by a departing

customer from another customer or

group of customers, the expected

revenues should be reflected in the

CMVE component of the formula.236

Moreover, our requirement that a utility

reflect in the CMVE component of the

formula the revenues it expects to

receive from the sale of the released

capacity does not automatically result in

remaining customers being forced to

subsidize a departing customer’s

stranded cost obligation as Boston

Edison posits. Rather, the rate treatment

of the released capacity needed to meet

the load growth of native load

customers is an open issue that is

properly addressed in future rate

proceedings.

In short, the revenues lost approach

already takes account of the

marketability of the released capacity

and appropriately incorporates load

growth associated with remaining retail

and wholesale customers and does not

contradict the cost responsibility

principle set forth in Order Nos. 888

and 888–A.

4. G&T and Distribution Cooperatives

RUS seeks rehearing and clarification

of the Commission’s determination in

Order No. 888–A that, unless stranded

costs arise as a result of a section 211

order to a G&T cooperative, G&T

cooperatives may not seek (through the

Commission) recovery of stranded costs

from the customers of their distribution

members. RUS argues that the

customers of a G&T cooperative’s

distribution members, as well as the

distribution members themselves, meet

the Commission’s pro forma tariff

definition of ‘‘native load customer’’

with respect to the G&T. It says that, ‘‘as

native load customers, both distribution

members and their customers should be

responsible to a G&T for stranded costs

arising from their use of Commissionrequired transmission access, or from

state mandated retail wheeling.’’ 237

RUS also questions the Commission’s

assertion that ‘‘’to treat a G&T

cooperative and its member distribution

systems 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 the purposes of Order No.

888’s reciprocity provision.’’ 238 RUS

asserts that different treatment for

different purposes is justified because

the relevant issues with respect to the

application of the reciprocity

requirement on a system-wide basis and

the ability to recover stranded costs on

a system-wide basis are different. RUS

submits that the Commission confuses

corporate affiliation with economic

integration, and that lack of corporate

affiliation does not preclude economic

integration. RUS says that although G&T

cooperatives and their distribution

members are operationally separate,

G&T cooperatives and their distribution

members function in many ways like a

single economic unit. According to

RUS, G&Ts undertake an obligation to

construct and operate their systems to

meet the reliable electric needs of their

distribution members and customers of

their distribution members, and G&T

cooperatives and their members are

bound together by long-term

requirements contracts.

RUS states that, as single economic

units, G&T cooperatives or distribution

members both should be able to seek

recovery of stranded costs from the

customers of distribution members. RUS

contends that ‘‘the Commission’s

reliance on distribution members to

seek to recover stranded costs ‘through

contracts with [their] customers or

through the appropriate regulatory

authority’ is misplaced’’ because

‘‘[d]istribution members—many of

which are not subject to state

commission jurisdiction—may have

neither an appropriate regulatory forum

through which to seek stranded cost

recovery, nor the ability to seek to

recover stranded costs incurred by their
64712 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

239 Id. at 17.

240 Id. at 19.

241RUS expresses concern in its rehearing request

that distribution members ‘‘may have neither an

appropriate regulatory forum through which to seek

stranded cost recovery, nor the ability to seek to

recover stranded costs incurred by their G&T

cooperatives to serve native load customers.’’ RUS

at 17. However, presumably when a retail customer

of a distribution cooperative switches suppliers, the

retail customer would still have to use the

distribution lines of the distribution cooperative to

receive its power. RUS has not explained why the

distribution cooperative cannot assess a charge to

recover stranded costs when the retail customer

uses those lines.

242A ‘‘public utility’’ is defined under section

201(e) of the FPA as ‘‘any person who owns or

operates facilities subject to the jurisdiction of the

Commission under this Part (other than facilities

subject to such jurisdiction solely by reason of

sections 210, 211, or 212).’’ 16 U.S.C. 824(e).

243A ‘‘transmitting utility’’ is defined under

section 3(23) of the FPA as ‘‘any electric utility,

qualifying cogeneration facility, qualifying small

power production facility, or Federal power

marketing agency which owns or operates electric

power transmission facilities which are used for the

sale of electric energy at wholesale.’’ 16 U.S.C.

796(23).

244As we explained in Order No. 888–A, our

decision to entertain (in certain limited

circumstances) requests to recover stranded costs

associated with retail wheeling customers applies to

public utilities only because it 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. FERC Stats. &

Regs. ¶ 31,048 at 30,419. Since RUS-financed

cooperatives are not public utilities subject to our

jurisdiction under sections 205 and 206 of the FPA,

we do not have authority to allow them to seek

recovery under Order Nos. 888 and 888–A of

stranded costs associated with retail wheeling

customers.

245Whether a G&T cooperative’s member

distribution cooperatives and the customers of the

distribution cooperatives meet the definition of

‘‘native load customer’’ under the open access tariff

(as RUS submits they do) is not relevant for

purposes of the stranded cost recovery mechanism

set forth in Order Nos. 888 and 888–A.

246FERC Stats. & Regs. ¶31,048 at 30,366.

247 Id.

248 Id. We continue to believe that it would be

inconsistent to treat G&T cooperatives and their

member distribution cooperatives differently for

purposes of the reciprocity condition and stranded

G&T cooperatives to serve native load

customers.’’ 239

Finally, RUS argues that failing to

permit G&T cooperatives to seek

recovery of stranded costs arising from

the loss of native load customers due to

Commission-required transmission

access or the lack of state commission

authority to permit stranded cost

recovery will result in unduly

discriminatory treatment of

cooperatives. Where G&T costs are

stranded by the ability of customers of

distribution members to switch

suppliers through Commission-required

transmission access, RUS submits that

there is a direct nexus between

Commission-required access and the

stranding of costs. In the case of retail

stranded costs, RUS says that many state

regulatory authorities do not have the

authority under state law to regulate

distribution or G&T cooperatives,

thereby creating a regulatory gap. RUS

states that

[f]ailure to allow a G&T the opportunity to

recover stranded costs caused by [the]

departure of any of its native load customers,

including both distribution members and the

customers of the distribution members, will

drastically reduce the G&T’s ability to cover

its costs, including payments on RUSfinanced debt, thereby endangering the

existence of the G&T itself and exposing

Federal taxpayers to the risk of massive loan

defaults.240

Commission Conclusion. We will

deny RUS’ rehearing request. To grant

the request would require the

Commission to reach beyond its

regulatory authority (and allow entities

not subject to our sections 205 and 206

jurisdiction an opportunity to recover

stranded costs) and would broaden the

scope of the Order Nos. 888 and 888–

A stranded cost recovery mechanism.241

Indeed, RUS’ rehearing request appears

to be based on a misunderstanding of

the limited scope of the stranded cost

recovery mechanism contained in Order

Nos. 888 and 888–A.

The stranded cost recovery provisions

in Order Nos. 888 and 888–A apply, in

the case of wholesale stranded costs, to

public utilities 242 and transmitting

utilities.243 In the case of stranded costs

associated with retail wheeling

customers, the provisions of the Rule

apply only to public utilities.244

The Commission has limited the

opportunity for public utilities and

transmitting utilities to seek stranded

cost recovery under Order Nos. 888 and

888-A primarily to two discrete

situations: (1) costs associated with

customers under wholesale

requirements contracts executed on or

before July 11, 1994 (referred to as

‘‘existing wholesale requirements

contracts’’) that do not contain an exit

fee or other explicit stranded cost

provision; and (2) costs associated with

retail-turned-wholesale customers

(including bundled retail customers of a

utility that become bundled retail

customers of a new municipal

utility).245

As the Commission explained in

Order No. 888–A, 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 we have 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 or contractual

channels, this Commission does not

have authority to allow them to seek

recovery of stranded costs unless they

do so in conjunction with transmission

access that they are required to provide

through a section 211 order. In the latter

case, a 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 that

did not contain an exit fee or other

explicit stranded cost provision.246

As we also explained in Order No.

888–A, a G&T cooperative that is a

public utility (a non-RUS financed

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 Order

No. 888’s stranded cost recovery

provisions. We said that, 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. In Order No. 888–A,

we explained why 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 the Rule.

We indicated that ‘‘[t]he 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.’’ 247 We

explained that commenters had

provided no basis for making an

exception in the case of cooperatives.

Further, we said that ‘‘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.’’ 248
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64713

cost recovery, notwithstanding RUS’ argument to

the contrary.

249FERC Stats. & Regs. ¶ 31,048 at 30,396.

250Port of Seattle at 7. Port of Seattle also

contends that the Commission mischaracterized

Port of Seattle’s position when it referred to Puget’s

statement that the parties were working within the

context of the stranded cost NOPR, which provided

that the utility had three years from the date of the

publication of the final rules to negotiate or file for

stranded cost recovery. Port of Seattle says its

assumption and position was that Puget made the

business decision not to include a stranded cost or

exit fee provision in its letter agreement, thus

preventing its recovery of any stranded costs. Id. at

8.

251We note that a certification of an uncontested

offer of settlement in that proceeding is pending

before the Commission.

252TDU Systems uses the term ‘‘stranded

benefits’’ to refer to the benefits to a wholesale

requirements customer that may be lost if ‘‘open

access transmission forces [the customer] to buy

power at market-based rates’’ instead of at costbased rates. TDU Systems at 25.

253 Id. at 27–28.

Although RUS refers in its rehearing

request to a scenario in which costs may

be stranded by the ability of customers

of a distribution cooperative to switch

suppliers through the use of

Commission-required transmission

access, the scenario RUS posits is not

one for which Order Nos. 888 and 888–

A would permit an opportunity for

recovery. Because the Commission

cannot order retail wheeling, the

principal way in which the retail

customers of a distribution cooperative

could use Commission-required

transmission access (and trigger

stranded costs on the part of the

distribution cooperative) would appear

to be through municipalization (i.e.,

through the creation of a new wholesale

entity to obtain power supplies on their

behalf in lieu of obtaining power from

the distribution cooperative). In such a

scenario, however, since the

distribution cooperative (if RUSfinanced) would not be a Commissionjurisdictional public utility or

transmitting utility, it would not be

allowed to seek stranded cost recovery

under Order Nos. 888 and 888–A.

5. Treatment of Contracts Extended or

Renegotiated Without a Stranded Cost

Provision

In Order No. 888–A, the Commission

clarified that it will consider on a caseby-case basis whether to waive the

provisions of 18 CFR 35.26 (which

define a ‘‘new wholesale requirements

contract’’ as ‘‘any wholesale

requirements contract executed after

July 11, 1994, or extended or

renegotiated to be effective after July 11,

1994’’ (emphasis added)) and 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.249

Port of Seattle opposes the

Commission’s decision in this regard. It

argues that the Commission in Order

No. 888–A sided with Puget on an issue

that is being litigated between Port of

Seattle and Puget in a separate

proceeding (Docket No. ER96–714), and

that the Commission improperly

prejudiced Port of Seattle by not

addressing the concerns expressed by

Port of Seattle in the underlying case.250

It submits that Order No. 888–A was not

the forum in which it expected the final

decision in Docket No. ER96–714 to be

made, and that its procedural rights

have been violated. Port of Seattle asks

the Commission on rehearing to

withdraw any determination, reference

or statement in Order No. 888–A that

addresses the issues pending in Docket

No. ER96–714.

Port of Seattle further argues that the

Commission improperly granted Puget

an exclusive waiver of (or private

exception to) the Rule’s definition of

‘‘new’’ contracts.

Commission Conclusion. We will

deny Port of Seattle’s request for

rehearing. Port of Seattle misconstrues

the scope of the Commission’s decision

and its effect on the pending proceeding

in Docket No. ER96–714–001. The

Commission’s decision in Order No.

888–A to consider on a case-by-case

basis whether to waive the provisions of

18 CFR 35.26 and treat a contract

extended or renegotiated to be effective

after July 11, 1994, but before March 29,

1995, as an existing contract for

stranded cost purposes does not

constitute a ruling on the merits in the

pending proceeding in Docket No.

ER96–714–001. In Order No. 888–A, the

Commission has gone no further than to

state that the matter should be

considered on a case-by-case basis, and

to acknowledge that the issue, as

between Puget and Port of Seattle, is

pending in Docket No. ER96–714–

001.251 Contrary to Port of Seattle’s

claim, Order No. 888–A does not grant

Puget a waiver of the Rule’s definition

of ‘‘new wholesale requirements

contract.’’

6. Customer Expectations of Continued

Service at Below-Market Rates

TDU Systems seeks rehearing of the

Commission’s decision not to adopt a

generic mechanism to allow existing

requirements customers with belowmarket 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. TDU Systems

states that the Commission’s decision

rests on the conclusion that, 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. TDU Systems

maintains that this finding rests on a

false distinction between the rate the

wholesale requirements customer

reasonably could have expected to pay

and the rate the wholesale requirements

seller reasonably could have expected to

collect. It says that neither stranded

costs nor ‘‘stranded benefits’’ 252 arise

from a right to, or expectation of, a

grandfathered rate. TDU Systems

contends that ‘‘stranded benefits’’ arise

because, prior to open access

transmission, wholesale requirements

customers had a reasonable expectation

of continuing to receive wholesale

service at just and reasonable cost-based

rates. It argues that when open access

transmission allows the supplier to

charge a higher market-based rate

instead, the customer’s expectation of

continued cost-based service is

destroyed, and the customer may lose

the benefits it had under the prior

regulatory regime.

TDU Systems submits that while

Order No. 888-A suggests that customers

could not reasonably expect to continue

paying their existing rate, the revenues

lost approach to quantifying stranded

costs assumes that sellers reasonably

expected to continue collecting a costbased rate equal to the existing rate.

TDU Systems says that the

Commission’s best estimate of the

seller’s lost revenue from a wholesale

requirements contract is based on the

seller’s existing, cost-based, just and

reasonable rate—the same existing costbased rate that the Commission in Order

No. 888–A finds the captive

requirements customer had no

reasonable expectation of continuing to

pay. TDU Systems says these findings

directly contradict one another.253

TDU further challenges the

Commission’s statement that ‘‘it is not

clear’’ that the customer could show it

reasonably expected continued service

‘‘at the existing contract rate (which

may be below the market price)’’

because the utility might have filed

changed rates during the contract term

or sought new rates at the end of the

contract term. TDU Systems submits

that before open access, established

Commission policy would only have

allowed the monopoly utility to charge

its captive wholesale requirements
64714 Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations

254 Id. at 28–29

255FERC Stats. & Regs. ¶31,048 at 30,391.

256 Id. at 30,393 (emphasis in original),

257 Id. at 30,351 (emphasis added by IL Com).

258 IL Com at 9–10.

259FERC Stats. & Regs. ¶31,048 at 30,351

(emphasis added by IL Com).

260 IL Com. at 10–11.

261See FERC Stats. & Regs. ¶31,036 at 31,789.

262 5 U.S.C. 601–612.

customer a cost-based rate, whether that

rate was above or below market price.254

TDU Systems asks the Commission to

adopt a generic mechanism to allow

customers to demonstrate and recover

their stranded benefits, just as it has

done for the recovery of utility stranded

costs. If the Commission is unwilling to

promulgate such a generic rule, TDU

Systems asks that the Commission

clarify the standard that a customer

must meet in seeking relief under

section 206. It says that although Order

No. 888-A states that a customer may

file a petition under section 206 ‘‘to

show that the contract should be

extended at the existing contract rate,’’

the issue is not whether to extend a

contract at the existing rate, but whether

to continue requirements service at a

cost-based rate. It asks the Commission

to correct its description in Order No.

888–A of the standard the customer

must meet in a case-by-case proceeding

and the relief the Commission would

provide.

Commission Conclusion. As

discussed below, we will deny TDU

Systems’ request for rehearing on this

issue, but will grant, in part, its request

for clarification.

In Order No. 888–A, the Commission

rejected TDU Systems’ request that the

Commission provide a generic

mechanism to allow existing

requirements customers 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. The

Commission noted that TDU Systems

had requested that the customer be

given 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 ‘‘stranded benefits’’ payment

from the utility consisting of the

difference between what the customer

must pay for new supplies and what it

paid under the contract.255 We

concluded that we did not have a

sufficient basis on which to make

generic findings or provide a generic

formula for addressing this issue:

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.256

At the same time, however, we

indicated that a customer under a

contract may exercise its procedural

rights under section 206 of the FPA to

show that the contract should be

extended at the existing contract rate.

We noted that the customer also may

make such a showing in the context of

a utility’s proposed termination of a

contract pursuant to the § 35.15 notice

of termination (approval) requirement,

which the Commission has retained for

power supply contracts executed prior

to July 9, 1996 (the effective date of

Order No. 888).

TDU Systems has not persuaded us

that our decision to address this issue

on a case-by-case, not a generic, basis is

in error. Notwithstanding TDU Systems’

arguments, we continue to believe that

the extent to which a customer could

demonstrate a reasonable expectation of

continued service at the existing

contract rate (or at a cost-based rate, if

that was the customer’s expectation) is

best addressed on a case-by-case basis.

As we explained in Order No. 888–A,

we do not intend to prejudge whether a

requirements customer could ever make

such a showing, nor do we intend to

preclude a customer from attempting to

make such a showing in appropriate

circumstances.

In response to TDU Systems’ request

that the Commission clarify the

standard that a requirements customer

must meet in seeking relief under

section 206, we clarify that a customer

may exercise its procedural rights under

section 206 to show either that the

contract should be extended at the

existing contract rate or, as TDU

Systems suggests, that the contract

should be extended at a cost-based rate.

However, the relief that the Commission

would provide in such a case is a matter

that is more appropriately determined

on a case-by-case basis based on the

particular facts and circumstances.

7. Miscellaneous

IL Com seeks rehearing of the

following sentence in Order No. 888–A:

‘‘It was not unreasonable for the utility

to plan to continue serving the needs of

its wholesale requirements customers

and retail customers, and for those

customers to expect the utility to plan

to meet their needs.’’ 257 IL Com objects

that this sentence prejudges the

reasonable expectation issue.258 It asks

that the Commission withdraw the

quoted sentence in full or, at a

minimum, withdraw the reference to

retail customers in the quoted sentence.

IL Com also seeks clarification of the

Commission’s statement in Order No.

888–A that ‘‘[i]f 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.’’ 259 IL

Com asks the Commission to withdraw

the words ‘‘or a former retail customer’’

from this sentence and to clarify that it

is not prejudging utilities’ entitlement to

retail stranded cost recovery and is not

imposing a ‘‘legitimate, prudent and

verifiable’’ standard for the recovery of

retail stranded costs.260

Commission Conclusion. The

Commission statements that are the

subject of IL Com’s request for rehearing

initially appeared in Order No. 888 261

and were repeated in Order No. 888–A’s

summarization of Order No. 888. IL

Com’s request for rehearing with respect

to these statements should have been

raised on rehearing of Order No. 888

and therefore was not timely filed.

However, we clarify that while we will

not withdraw our statements, the

statements are not intended to prejudge

the reasonable expectation issue as it

might apply to any state proceedings on

retail stranded costs.

V. Environmental Statement

In Order No. 888–A, the Commission

denied requests for rehearing on eight

categories of issues relating to the

Commission’s analysis of environmental

issues. No rehearing requests were filed

concerning Order No. 888–A’s analysis

of environmental issues.

VI. Regulatory Flexibility Act

Certification

The Regulatory Flexibility Act 262

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

Order No. 888, the Commission certified

that the Open Access and Stranded Cost

Final Rules would not impose a

significant economic impact on a

substantial number of small entities. In
Federal Register / Vol. 62, No. 236 / Tuesday, December 9, 1997 / Rules and Regulations 64715

263The OMB control number for this collection of

information is 1902–0096.

1APPA filed its request for rehearing out-of-time

on April 4, 1997. As discussed in Order No. 888–

B, the Commission is accepting this pleading as a

motion for reconsideration.

2CNG Energy Services Corp., Coastal Electric

Services Company, Destec Power Services, Inc.,

Enron Power Marketing, Inc., Koch Energy Trading,

Inc., NorAm Energy Services, Inc., and Vitol Gas &

Electric Services, Inc.

3 General Public Utilities Corp., Illinois Power

Co., Long Island Lighting Co., and New York State

Electric & Gas Corp.

4EEI filed its request for rehearing out-of-time on

April 4, 1997. As discussed in Order No.888–B, the

Commission is accepting this pleading as a motion

for reconsideration.

5 Independent Power Producers of New York, Inc.

(NY IPPs) filed an answer on April 11, 1997.

6 Granite State Hydropower Association filed an

answer on April 21, 1997.

7Formerly Puget Sound Power & Light Company.

8American Municipal Power-Ohio, Inc., Illinois

Municipal Electric Agency, Indiana Municipal

Power Agency, Littleton Electric Light Department,

Massachusetts Municipal Wholesale Electric

Company, Michigan Public Power Agency,

Municipal Energy Agency of Mississippi, Municipal

Energy Agency of Nebraska, New Hampshire

Electric Cooperative, Inc., Northern California

Power Agency, Virginia Municipal Electric

Association No. 1, on behalf of itself and its

members (City of Franklin, City of Manassas,

Harrisonburg Electric Commission, Town of

Blackstone, Town of Culpepper, Town of Elkton,

and Town of Wakefield), and Wisconsin Public

Power, Inc. The operating companies of the

American Electric Power System (AEP) filed an

answer on April 17, 1997.

9Arkansas Electric Cooperative Corporation,

Golden Spread Electric Cooperative, Inc., Holy

Cross Electric Association, Kansas Electric Power

Cooperative, Inc., Magic Valley Electric

Cooperative, Inc., Mid-Tex Generation and

Transmission Electric Cooperative, Inc., North

Carolina Electric Membership Corporation,

Oklahoma Municipal Power Authority, Old

Dominion Electric Membership Corporation, and

Seminole Electric Cooperative, Inc.

Order No. 888–A, the Commission

addressed requests for rehearing that

questioned this certification and that the

final rule would not impose a

significant economic impact on a

substantial number of small entities. No

rehearing requests of Order No. 888–A

were filed on this issue and the

Commission finds no reason to alter its

previous findings on this issue.

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). 263 Given that this

order on rehearing makes only minor

revisions to Order Nos. 888 and 888–A,

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 Nos. 888 and 888–

A. 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

The tariff change to Order Nos. 888

and 888–A made in this order on

rehearing (see footnote 1) will become

effective on February 9, 1998. The

current requirements of Order Nos. 888

and 888–A will remain in effect until

this order becomes effective.

By the Commission.

Lois D. Cashell,

Secretary.

Note: The following Appendices will not

appear in the Code of Federal Regulations.

Appendix A—Order No. 888–B: List of

Petitioners

1. American Public Power Association,

Colorado Association of Municipal

Utilities, Municipal Electric Systems of

Oklahoma, and Utah Associated Municipal

Power Systems (APPA) 1

2. Bonneville Power Administration (BPA)

3. Arizona Public Service Company (Arizona)

4. Boston Edison Company, Central Vermont

Public Service Corporation, Florida Power

Corporation, Montaup Electric Company,

and Wisconsin Public Service Corporation

(Boston Edison)

5. Coalition for a Competitive Electric Market

(CCEM) 2

6. Central Maine Power Company (Central

Maine)

7. Coalition for Economic Competition

(Coalition for Economic Competition) 3

8. Colorado Association of Municipal

Utilities (CAMU)

9. Dairyland Power Cooperative (Dairyland)

10. Edison Electric Institute (EEI) 4

11. Illinois Commerce Commission (IL Com)

12. Kansas City Power & Light Company

(KCPL)

13. Metropolitan Edison Company (Met Ed)

14. National Association of Regulatory Utility

Commissioners (NARUC)

15. National Rural Electric Cooperative

Association (NRECA)

16. New England Power Pool Executive

Committee (NEPOOL)

17. Public Service Commission of the State

of New York (NY Com) 5

18. Niagara Mohawk Power Corporation and

PURPA Reform Group (NIMO) 6

19. Otter Tail Power Company (Otter Tail)

20. Puget Sound Energy, Inc. (Puget) 7

21. Rural Utilities Service, USDA (RUS)

22. Port of Seattle (Port of Seattle)

23. Soyland Power Cooperative, Inc.

(Soyland)

24. Transmission Access Policy Study Group

and certain of its Members (TAPS) 8

25. Transmission Dependent Utility Systems

(TDU Systems) 9

(Name of Transmission Provider) Open

Access Transmission Tariff Original Sheet

No.

Revision to Pro Forma Open Access

Transmission Tariff Pursuant to Order No.

888–B

Appendix B

29.1 Condition Precedent for Receiving

Service: Subject to the terms and conditions

of Part III of the Tariff, the Transmission

Provider will provide Network Integration

Transmission Service to any Eligible

Customer, provided that: (i) The Eligible

Customer completes an Application for

service as provided under Part III of the

Tariff, (ii) the Eligible Customer and the

Transmission Provider complete the

technical arrangements set forth in Sections

29.3 and 29.4, (iii) the Eligible Customer

executes a Service Agreement pursuant to

Attachment F for service under Part III of the

Tariff or requests in writing that the

Transmission Provider file a proposed

unexecuted Service Agreement with the

Commission, and (iv) the Eligible Customer

executes a Network Operating Agreement

with the Transmission Provider pursuant to

Attachment G, or requests in writing that the

Transmission Provider file a proposed

unexecuted Network Operating Agreement.

[FR Doc. 97–31841 Filed 12–8–97; 8:45 am]

BILLING CODE 6717–01–P

DEPARTMENT OF ENERGY

Federal Energy Regulatory

Commission

18 CFR Part 37

[Docket No. RM95–9–002; Order No. 889–

B]

Open Access Same-Time Information

System and Standards of Conduct

Issued November 25, 1997.

AGENCY: Federal Energy Regulatory

Commission.

ACTION: Final order; order denying

rehearing.

SUMMARY: The Federal Energy

Regulatory Commission is denying the

requests for rehearing of its order on

rehearing of the final rule in this

proceeding. The final rule required

public utilities that own, control, or

operate facilities used for the

transmission of electric energy in

interstate commerce to create or

participate in an Open Access SameTime Information System (OASIS) in

conformance with Commission

regulations. The final rule also required