Policy Statement and Interim Rule Regarding Ratemaking Treatment of the Cost of Emissions Allowances in Coordination Rates

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Parts 2 and 35

[Docket No. PL95-1-000]

Policy Statement and Interim Rule Regarding Ratemaking Treatment

of the Cost of Emissions Allowances in Coordination Rates

Issued December 15, 1994

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Policy Statement; Interim Rule.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is

adopting a policy statement setting forth the elements of what

generally constitutes appropriate ratemaking treatment of sulfur

dioxide emissions allowances in coordination transactions under the

Federal Power Act. The Clean Air Act Amendments of 1990, Pub. L. No.

101-549, Title IV, 104 Stat. 2399, 2584 (1990), require issuance of

emissions allowances as a means to reduce sulfur dioxide emissions

levels. The Commission also is issuing an interim rule that implements

the guidelines set forth in the policy statement.

DATES: The policy statement and interim rule are effective January 1,

1995. Comments on the interim rule are due January 23, 1995.

ADDRESSES: Comments can be mailed to: Federal Energy Regulatory

Commission, 825 North Capitol Street NE., Washington, DC 20426.

FOR FURTHER INFORMATION CONTACT:

Wayne W. Miller (Legal Information), Office of the General Counsel,

Federal Energy Regulatory Commission, 825 North Capitol Street, N.E.,

Washington, D.C. 20426, Telephone: (202) 208-0466

Moira Notargiacomo (Technical Information), Office of Electric Power

Regulation, Federal Energy Regulatory Commission, 825 North Capitol

Street, N.E., Washington, D.C. 20426, Telephone: (202) 208-1079

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 3104, 941 North

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

The Commission Issuance Posting System (CIPS), an electronic

bulletin board service, provides access to the texts of formal

documents issued by the Commission. CIPS is available at no charge to

the user and may be accessed using a personal computer with a modem by

dialing (202) 208-1397. To access CIPS, set your communications

software to 19200, 14400, 12000, 9600, 7200, 4800, 2400, 1200 or 300

bps, full duplex, no parity, 8 data bits, and 1 stop bit. The full text

of this document will be available on CIPS for 60 days from the date of

issuance in ASCII and WordPerfect 5.1 format. After 60 days the

document will be archived, but still accessible. The complete text on

diskette in WordPerfect format may also be purchased from the

Commission's copy contractor, LaDorn Systems Corporation, also located

in Room 3104, 941 North Capitol Street, N.E., Washington, D.C. 20426.

Before Commissioners: Elizabeth Anne Moler, Chair; Vicky A.

Bailey, James J. Hoecker, William L. Massey, and Donald F. Santa,

Jr.

Issued December 15, 1994.

I. Introduction

On October 14, 1994, the Edison Electric Institute (EEI)1

filed a petition under section 207 of the Commission's Rules of

Practice and Procedure2 requesting issuance of a Policy Statement

regarding the ratemaking treatment of emissions allowances in

coordination transactions under the Federal Power Act. The acid rain

control title (Title IV) of the Clean Air Act Amendments of 1990, Pub.

L. No. 101-549, Title IV, 104 Stat. 2399, 2584 (1990) (CAAA), provides

for the issuance of emissions allowances as a means to reduce sulfur

dioxide emissions levels. EEI proposes that emission allowances be

included in rates at the allowance's incremental cost3 with

customers having the choice of two options to compensate the seller of

allowances. Either the customer may return, or transfer, emissions

allowances in kind or it may compensate the seller for its incremental

cost of emissions allowances. EEI proposes that the seller be allowed

to use a particular price index selected by the seller or an average of

several price indices to determine the current cost to replace an

allowance. EEI requests issuance of the Policy Statement by January 1,

1995, when Phase I of the CAAA becomes effective.

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\1\EEI states that its member companies generate approximately

79 percent of all electric power produced in the United States,

serve some 76 percent of all ultimate consumers of electricity, and

own a large majority of the generating units which will be affected

by the Clean Air Act Amendments of 1990 when Phase I commences on

January 1, 1995.

\2\18 CFR 385.207 (1994).

\3\According to EEI, the ``incremental cost'' of an emissions

allowance in a coordination sale is the spot market price at the

time of the power sale, as opposed to the inventory value on the

company's books.

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The Commission agrees with EEI that issuance of a Policy Statement

on the ratemaking treatment of emissions allowances in coordination

transactions is necessary at this time. The primary goal of the

allowance trading program is to encourage utilities to implement the

lowest overall cost actions to comply with the cap on sulfur dioxide

emissions contained in the CAAA. The development of a national and open

allowance trading market, the Commission believes, depends in part upon

regulators sending public utilities a clear signal on how allowance

trades and CAAA compliance costs will be treated for ratemaking

purposes. Accordingly, the Commission hereby issues a Policy Statement

adopting EEI's proposal, with various modifications discussed below.

The Commission also hereby issues an Interim Rule implementing the

guidelines set forth in this Policy Statement.4

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\4\The Commission addresses certain jurisdictional issues raised

by EEI in a separate order issued concurrently.

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II. Public Reporting Burden

The Policy Statement and Interim Rule would clarify how existing

filing requirements apply to utilities filing amendments to

coordination rate schedules to provide for the recovery of emissions

allowance costs and to recover them in a timely fashion. Because this

Policy Statement and Interim Rule only clarify how existing

requirements are to be implemented, the public reporting burden for

these information collections (including the time for reviewing

instructions, searching existing data sources, gathering and

maintaining the data needed, and completing and reviewing the

collection of information) is not estimated to increase the number of

hours per response for each utility currently involved in the filing of

rate schedule amendments. Send comments regarding these burden

estimates or any other aspect of these collections of information,

including suggestions for reducing the burden, by contacting the

Federal Energy Regulatory Commission, 941 North Capitol Street, NE,

Washington, DC 20426 [Attention: Michael Miller, Information Services

Division, (202) 208-1415], and to the Office of Information and

Regulatory Affairs, Office of Management and Budget, Washington D.C.

20503 (Attention: Desk Officer for the Federal Energy Regulatory

Commission), FAX: (202) 395-5167.

III. Background

The CAAA and Allowance Trading

The acid rain control title of the CAAA sets forth a comprehensive

regulatory mechanism designed to control acid rain by limiting sulfur

dioxide emissions by electric utilities. The CAAA require reductions in

sulfur dioxide emissions in two phases. Phase I begins on January 1,

1995, and applies to 110 mostly coal-fired utility plants containing

about 260 generating units specifically listed in the statute. These

plants are owned by about 40 jurisdictional utility systems that are

expected to reduce annual sulfur dioxide emissions by as much as 4.5

million tons. Phase II begins on January 1, 2000, and applies to

virtually all existing steam-electric generating utility units with

capacity exceeding 25 megawatts and to new generating utility units

(generally those commencing operation after November 15, 1990) of any

size. Phase II permanently caps sulfur dioxide emissions at 9 million

tons annually. The Environmental Protection Agency (EPA) issues to the

owners of generating units allowances (defined as an authorization to

emit, during or after a specified calendar year, one ton of sulfur

dioxide)5 equal to the number of tons of sulfur dioxide emissions

authorized by the CAAA. EPA does not assess a charge for the allowances

it awards.

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\5\42 U.S.C. Sec. 7651a(3).

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The allowances are not unit-specific and can be sold or traded.

Utilities have incentives to reduce sulfur dioxide emissions so that

they can use allowances to cover load growth, to make additional off-

system sales or to sell or trade allowances on the open market,

offsetting the costs of compliance. Utilities that reduce the amount of

sulfur dioxide emitted below their authorized level (e.g., by switching

to a lower sulfur coal, switching to a new fuel, installing scrubbers,

repowering a unit, or using demand side management (DSM)) may bank

their allowances (i.e., hold and use them in another year) or sell or

trade them to other utilities that expect to exceed their authorized

emission level or other allowance market participants such as

marketers.

Congress created the allowance trading system in Title IV of the

CAAA to enable sulfur dioxide emissions reductions to occur at the

lowest cost, by creating a national market for emissions allowances.

Basically, the emissions allowance trading system works in the

following manner. Title IV of the CAAA established guidelines for the

EPA to implement a system for issuing, recording and tracking

allowances.6 Allowance usage at each affected unit is recorded by

EPA quarterly. There is a national cap on the total number of

allowances issued by EPA each year.7 After the end of each year,

EPA determines whether companies have the right number of emissions

allowances of appropriate vintage on hand for each ton of sulfur

dioxide emitted during the year. The penalty for not having the

requisite number of allowances on hand is $2,000 per ton plus surrender

of an emissions allowance equivalent in the following year, plus other

possible punishments depending on the degree of violation.8 The

CAAA also require EPA to withhold for direct sale and auction 2.8

percent of the annual allowance allocations.9 The allowances are

not property rights,10 and are not unit-specific.11

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\6\42 U.S.C. Secs. 7651b(b) and (d).

\7\The CAAA require EPA to allocate annual allowances to

electric utilities based upon an average 1985-1987 plant-specific

energy use and other factors. 42 U.S.C. Sec. 7651b(a). Various CAAA

provisions require EPA to give additional allowances to utilities

which used certain specified compliance options, some of which may

require some investment or expenditure by the utility. E.g., 42

U.S.C. Sec. 7651c(d) (installation of technological reduction system

to achieve a 90 percent emissions reduction); 42 U.S.C. Sec. 7651h

(repowering with a clean coal technology); 42 U.S.C. Sec. 7651c(f)

(energy conservation and renewable energy).

\8\42 U.S.C. Sec. 7651j.

\9\42 U.S.C. Sec. 7651o(b).

\1\042 U.S.C. Sec. 7651b(f).

\1\1The CAAA do not require a change of any kind in state law

regarding electric utility rates. 42 U.S.C. Sec. 7651b(f). The CAAA

also do not modify the Federal Power Act (FPA) or affect the

Commission's authority under the FPA. Id. Additionally, the CAAA

exempt the acquisition or disposition of allowances from the

provisions of the Public Utility Holding Company Act of 1935

(PUHCA). 42 U.S.C. Sec. 7651b(j).

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Whatever steps a utility takes to comply with the CAAA will affect

the cost of electric service, e.g., if a utility installs new

equipment, its capital costs will change; if a utility purchases low

sulfur fuel, its energy costs will change; and if a utility buys

emission allowances, its operating expenses will change.

In Docket No. RM92-1-000, Revisions to Uniform Systems of Accounts

to Account for Allowances under the Clean Air Act Amendments of 1990

and Regulatory-Created Assets and Liabilities and to Form Nos. 1, 1-F

and 2-A, Order No. 552, III FERC Statutes and Regulations, Regulations

Preambles 30,967, 58 FR 17982 (April 7, 1993), the Commission amended

its Uniform Systems of Accounts for public utilities, licensees and

natural gas companies to establish uniform accounting requirements for

allowances for the emission of sulfur dioxide under the CAAA, and to

establish generic accounts to record assets and liabilities created

through the ratemaking actions of regulatory agencies. While

acknowledging the need for the eventual development of a ratemaking

framework for allowances, the Commission declined to expand the scope

of the accounting rule to address rate issues.12

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\1\2The Commission stated that the accounting rules were

intended to be ``rate neutral,'' i.e., they were not intended to

prescribe ratemaking treatment for allowances and would not bar

regulatory commissions (including this Commission) from adopting any

particular ratemaking treatment. The Commission observed that the

bulk of the cost of allowances and compliance will be within the

ratemaking jurisdiction of the various States and not this

Commission, and found that there was not likely to be a single

ratemaking framework appropriate in each and every ratemaking

jurisdiction for utilities subject to this Commission's accounting

jurisdiction. III FERC Statutes and Regulations, Regulations

Preambles 30,967 at 30,794-96.

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The EEI Petition

EEI requests that the Commission now provide guidance on the

ratemaking treatment of emissions allowances in coordination

transactions so that the CAAA emissions allowance program will work as

Congress intended. EEI states that such guidance is urgently needed in

view of the imminent onset of Phase I. EEI states that the allowance

market is rapidly evolving,13 and EEI expects this market to

become even more active when utilities operating the Phase I generating

units begin to use emissions allowances.

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\1\3EEI Petition, Appendix A.

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EEI requests the Commission to: (1) Provide for costing emissions

allowances at their incremental cost in coordination rates, determined

on the basis of a leading index or combination of indices of the

current price of emissions allowances, such index or combination of

indices to be selected by the seller of the power; (2) compensate

coordination sellers by permitting power purchasers at their option

either: (a) To transfer or return emission allowances in kind14 or

(b) compensate the seller for its incremental cost of emission

allowances, and (c) declare that purchasers who provide emissions

allowances do not need to make filings with the Commission; (3) find

that the cost of emissions allowances may be recovered under provisions

in coordination rate schedules as ``out-of-pocket'' costs; (4) give

utilities up to 45 days after the Commission issues a policy statement

to file amendments to rate schedules to allow recovery of emissions

allowance costs beginning January 1, 1995, provided that each utility

gives its customers notice of the emission allowance recovery

methodology it will be using when energy is scheduled (the Commission

would reserve the ability, as a condition of making the policy

effective January 1, 1995, to order refunds); (5) clarify that the

transfer of emission allowances is not subject to a Section 205 filing

and determine that sales of emissions allowances are not jurisdictional

under Section 203 or 205 of the FPA;15 and (6) declare that the

ratemaking treatment of emissions allowances endorsed in this Policy

Statement does not preclude other approaches proposed by individual

utilities on a case-by-case basis.

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\1\4EEI argues that such option will: (a) Allow a power

purchaser to optimize its economic position if it can purchase

allowances at a price below the seller's declared price; (b) prevent

a seller from dictating the allowance price; (c) reward a power

purchaser who seeks the lowest cost emissions allowances; and (d)

promote an active allowance market that enhances the savings in

compliance costs envisioned by the CAAA and also promotes the FPA's

purpose to provide for reasonable rates. None of the intervenors and

commenters oppose this proposal.

\1\5In particular, EEI asks the Commission to find that

emissions allowances are not ``facilities'' under Section 203, and,

therefore, the sale or transfer of such allowances does not require

the Commission's authorization. We address EEI's request for a

jurisdictional determination in a separate order.

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EEI notes that use of incremental costs as a basis for emission

allowance costing is consistent with the cost basis used for other

variable expenses (e.g., fuel) related to coordination transactions and

dispatch decisions. According to EEI, many utilities operate under

existing rate schedules that include specific provisions allowing the

tracking of incremental costs.16 EEI requests that utilities with

these types of rate schedules not be required to amend their

agreements, but only be required to supplement their rate schedules

with specific details regarding the recovery of the incremental cost of

emissions allowances in their rates.17

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\1\6For example, Indiana Michigan Power Company has an

interconnection agreement with Public Service Company of Indiana,

Inc. (Rate Schedule FERC No. 24), which provides for the sale of

limited term power with an energy charge of 110% of the out-of-

pocket costs of supplying energy, with out-of-pocket cost defined as

all operating, maintenance, tax, transmission losses and other

expenses incurred that would not have been incurred if the energy

had not been supplied.

\1\7EEI does not explain what procedure would be followed by

utilities that have coordination rates on file that do not expressly

provide for the recovery of all incremental costs, e.g., a

coordination rate schedule that provides for recovery of incremental

fuel, but is silent with respect to other types of variable costs;

coordination rate schedules that include stated rates; or

coordination rate schedules that do not adopt incremental cost

pricing.

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Since there may be different ways of determining the incremental

cost of emissions allowances, EEI proposes that utilities be required

to submit the following company-specific details. First, EEI suggests

that utilities should be required to choose a leading national index or

combination of indices to determine the incremental cost of emission

allowances at the time of the allowance's consumption and be required

to use that index until they identify some other acceptable index in a

filing with the Commission. Second, EEI suggests that each utility be

required to explain the method of calculating its emission allowance

dispatch value. EEI indicates that the use of incremental costing for

emissions allowances should be consistent with the use of incremental

costing for economic dispatch decisions. EEI proposes that any

differences between the incremental costing for coordination sales of

emissions allowances and dispatch decisions regarding emissions

allowances be explained and reconciled. Third, EEI suggests that

utilities be required to explain how they will quantify the amount of

emission allowances attributable to each transaction. Fourth, EEI

suggests that, with respect to longer-term transactions, utilities be

required to specify the timing of opportunities for buyers to stipulate

whether they will purchase or provide the emissions allowances.18

Fifth, EEI suggests that utilities be required to identify any other

factors that could impact pricing, such as rates tied to units other

than the incremental unit used for the sale.

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\1\8While EEI's argument on this point is unclear, we believe

EEI's position is that, for longer-term transactions, buyers of

emissions allowances should have the same timing opportunities as

allowance sellers. Because sellers do not have to have the required

emissions allowances until January 30 of the year subsequent to the

calendar year, or the first business day subsequent to January 30 if

January 30 is not a business day (hereinafter EPA reporting date),

40 CFR 72.2 and 73.35(a)(2) (1994), they are able to delay

purchasing allowances in order to possibly obtain a less expensive

allowance price. By providing flexibility as to the time within

which buyers can transfer allowances, buyers might be able to save

money as well.

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Interventions and Comments

Notice of the EEI filing was published in the Federal

Register,19 with comments due on or before November 14, 1994.

Tellus Institute for Resource and Environmental Strategies (Tellus),

Wisconsin Electric Power Company (Wisconsin Electric), the Office of

the Consumers' Counsel, State of Ohio (Consumers' Counsel), Potomac

Electric Power Company (PEPCO), Cincinnati Gas and Electric Company

(CG&E) and PSI Energy, Inc. (PSI), Entergy Services, Inc. (Entergy

Services), EPA, the Independent Petroleum Association of America

(IPAA), the City of Cleveland, Ohio (Cleveland), Florida Power & Light

Company (Florida Power), and the American Public Power Association

(APPA)20 filed timely motions to intervene and/or comments.

Washington Utilities and Transportation Commission (Washington

Commission), the Public Utilities Commission of the State of California

(California Commission) and the Indiana Utility Regulatory Commission

(Indiana Commission) filed notices of intervention and/or timely

comments. On November 21, 23, 25 and 30, 1994, Clean Air Capital

Markets (Clean Air), Emissions Exchange Corporation (Emissions

Exchange), Cantor Fitzgerald Brokerage, L.P. (Cantor Fitzgerald), and

Southern Company Services, Inc. (Southern) filed untimely motions to

intervene and comments. On November 28, 1994, EEI filed reply comments.

EEI does not oppose any of the motions to intervene and welcomes

comments on the issues raised in this proceeding.

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\1\959 FR 53156 (October 21, 1994).

\2\0APPA is a national service organization representing

approximately 1,750 publicly-owned electric utilities throughout the

United States.

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Under Rule 214 of the Commission's Rules of Practice and Procedure,

18 CFR 385.214, the timely, unopposed motions to intervene of Tellus,

Wisconsin Electric, the Consumers' Counsel, PEPCO, CG&E, PSI, Entergy

Services, IPAA, Cleveland, Florida Power, EPA and APPA and the notices

of intervention of the Washington Commission, the California Commission

and the Indiana Commission serve to make them parties to this

proceeding. Furthermore, we find that good cause exists to grant the

untimely interventions of Clean Air, Emissions Exchange, Cantor

Fitzgerald and Southern, given the interests they represent, the early

stage of this proceeding, and the apparent absence of undue prejudice

or delay.

Finally, we will accept EEI's reply comments. While responses to

protests or answers normally are not permitted under the Commission's

Rules of Practice and Procedure, 18 CFR 385.213(a)(2), responses to

intervention requests are permitted.21 Moreover, these reply

comments are necessary in order to clarify issues in this

proceeding,22 provide a more complete record on which the

Commission can base its decision,23 and assist in the

understanding of the parties' positions with respect to certain factual

and legal matters.\24\

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\2\1We will not attempt to separate intervenors' filings into

those portions which pertain solely to the request for intervention

and those portions which contain objections to the original

application. See, e.g., Robbins Resource Recovery Partners, L.P., 69

FERC 61,178 (1994).

\2\2See Buckeye Pipeline Company, L.P., 45 FERC 61,046 at

61,160 (1988).

\2\3See BES Hydro Company, 45 FERC 61,478 at 62,490 & n.2

(1988); and New York Irrigation District, 46 FERC 61,379 at 62,180

& n.2 (1989).

\2\4See Kansas City Power & Light Company, 53 FERC 61,097 at

61,282 (1990).

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IV. Rate Issues

Positions of Intervenors and Commenters

CG&E, PSI, Entergy Services, IPAA and Cleveland take no position on

the merits of EEI's proposal. The Washington Commission, the Indiana

Commission, PEPCO, and Southern generally express support for the

proposal. The remainder of the intervenors and commenters indicate

concerns with various aspects of the proposal, as discussed below.

The California Commission supports EEI's request that alternative

proposals for emissions allowance ratemaking treatment not be precluded

and that such proposals be considered on a case-by-case basis.

EPA supports EEI's request for incremental pricing for allowances

and use of an index to establish the incremental price. However, EPA

requests the Commission to address ratemaking for all wholesale

transactions at this time. EPA also seeks a uniform approach for

costing and rate treatment of allowances. Thus, EPA requests that the

Commission adopt one index option for use by all public utilities. EPA

suggests that its auction presently provides the most reliable price

index. EPA also raises concerns about EEI's proposal to allow alternate

ratemaking proposals on a case-by-case basis. EPA states that utilities

should bear the burden of showing that any different approach is

justified and will not result in an unfair competitive advantage in

electric power markets.

Emissions Exchange, Clean Air and Cantor Fitzgerald state that EPA

auction prices have consistently been artificially low and that the EPA

auction price is not representative of the open market because the

auction is held just once a year and does not track the current price

and availability of allowances. Emissions Exchange asks that the

Commission refrain from dictating use of any particular price index.

Instead, Emissions Exchange proposes that this Commission permit each

utility to choose its market price index from a list which includes,

but is not limited to, the allowance price indicators published by

Cantor Fitzgerald.25

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\2\5Utility Environment Report, Cantor Fitzgerald, Compliance

Strategies Review and Emission Exchange.

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In addition to the problems it sees with the EPA auction, Clean Air

maintains that commercial bulletin board services are also unreliable

sources for allowance price information. It argues that bulletin board

bid/ask prices may not reflect actual allowance transactions and could

subject market participants to inaccurate price signals, gaming and

manipulation. Clean Air opposes allowing the selling utility to cost

emissions allowances at a market index of its own choosing because this

presents the danger of the selling utility picking a price based on the

highest-cost index, with no demonstration that this price reflects the

realities of the market. Clean Air also opposes the selection of a

single index by the Commission, stating that the Commission would risk

sending misleading price signals. Clean Air suggests that, in addition

to requiring sellers of allowances to inform buyers of the price of

allowances and the number of allowances to be provided, the seller

should notify the buyer that there is a third party who will provide

the allowances at a stated price. Clean Air also proposes that the

Commission require sellers to report the volume of allowances

transferred, their price and the name of any third parties supplying

the allowances. Clean Air states that this Commission should publish

these reports to provide buyers with greater market information.

The Consumers' Counsel and Tellus state that this Commission should

expand the scope of this proceeding to include the ratemaking treatment

of allowances for all wholesale transactions. The Consumers' Counsel

also states that it would be more efficient for a policy statement to

recognize other valuation methods in addition to incremental costs,

such as a cost-of-compliance approach, and to specify when that method

would be more appropriate.26 Additionally, the Consumers' Counsel

suggests that the Commission should establish a single monthly market

price for allowances and should develop a standard method of allocation

of EPA-granted allowances between wholesale and retail customers and

between affiliates.

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\2\6The suggested cost of compliance approach would value

emissions allowances at the cost the seller would incur to reduce

emissions rather than using the allowance.

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Wisconsin Electric argues that EEI's pricing policy is contrary to

the CAAA because it will cause generation to shift from Phase I units

to non-Phase I units. This is because a requirement that utilities

charge the full incremental cost of allowances will result in an

increase in the operating cost of Phase I units and result in those

units being underutilized. It is possible, Wisconsin Electric argues,

that if a Phase I unit is not utilized at ``baseline'' (1985-1987)

levels, the utility may be required by the CAAA to forfeit

allowances.27 For these reasons, Wisconsin Electric suggests, the

Commission, in its Policy Statement, should allow utilities with Phase

I units the flexibility to charge ``up to'' the incremental cost of a

Phase I allowance. Wisconsin Electric argues that achieving least cost

dispatch, in light of complexities such as reduced utilization of Phase

I units, may require use of a dispatch emissions value that differs

from incremental cost.

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\2\7According to Wisconsin Electric, it cannot be assumed that

an allowance on a Phase I unit that is underutilized (thereby

subjecting the allowance to possible surrender under the CAAA) has

an opportunity cost equal to incremental costs since an allowance

that is surrendered may not be consumed or traded by the utility.

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Florida Power seeks to ensure that the Policy Statement not

predetermine the issues raised in Southern Company Services, Inc.,

Docket No. ER95-59-000, now pending before this Commission. Florida

Power also seeks clarification that only Phase I utilities need to file

the details of their emission allowance recovery method within 45 days,

because it would be premature for Phase II utilities to make such

filings now.

APPA argues that the proposed policy statement would grant

excessive discretion to utilities and would open the door to

inconsistent ratemaking treatment. APPA complains that EEI's proposal

contains no clear requirement that the selling utility be consistent in

its ratemaking treatment on simultaneous transactions and does not

require a utility to adhere to any particular methodology once adopted.

Further, APPA argues, EEI's petition does not define how the revenues

from emissions allowances included in rates will be credited to various

customer classes. Moreover, APPA argues, EEI's proposal that this

Commission allow utilities with existing incremental cost rate

provisions to file emission allowance pricing information without

revising their rate schedules will authorize utilities to redefine

contract terms unilaterally. APPA contends that EEI's proposal does not

clearly define the scope of transactions to which the Policy Statement

will apply. APPA maintains that the Commission should afford affected

parties the opportunity to challenge application of whatever policy is

adopted in this Policy Statement on a case-by-case basis. APPA also

believes that this Commission should establish a standard market price

for allowances or provide a forum for review to ensure the justness and

reasonableness of indices or methodologies to be used by a selling

utility.

Tellus also states that since several utilities recently have filed

differing proposals for emissions allowance cost recovery in affiliated

transactions, this Commission must act promptly to establish generic

ratemaking policies for each type of wholesale arrangement. Tellus

further urges the Commission, either in this or in a separate

proceeding, to address the ratemaking treatment of costs of compliance

with the CAAA, in addition to allowance costs. Tellus suggests that

this Commission establish its own monthly market index price for

emissions allowances, determine how the profits should be credited to

and among wholesale and retail customers, develop a standard method for

allocating allowances obtained from EPA at no cost between wholesale

and retail customers, and establish generic policies regarding the

adequacy and appropriateness of current wholesale rate designs for

passing CAAA costs through to wholesale customers. Tellus suggests that

average inventory costs might be a valid basis for determining the cost

of emissions allowances.

EEI, in reply, again urges issuance of a policy statement by

January 1, 1995. EEI argues that the policy guidance requested is

appropriately limited to coordination transactions. EEI argues that

coordination transactions are a distinct category of voluntary

transactions and that the treatment it proposes is consistent with

Commission precedent for other out-of-pocket costs incurred in such

transactions. EEI submits that the guidance it requests here, while

appropriate for coordination transactions, cannot accommodate the

varying circumstances and cost allocation issues involved in wholesale

requirements service or transactions among affiliated companies. EEI

also notes, in reply, that the Commission, in Regulation of Electricity

Sales for Resale and Transmission Service, Notice of Inquiry, IV FERC

Stats. and Regs. 35,518 at 35,628 (1985), order terminating docket, 61

FERC 61,371 (1992), defined the term ``coordination transactions,''

and distinguished coordination transactions from requirements

transactions.28

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\2\8The Commission therein defined coordination transactions as

``sales or exchanges of specialized electricity services that allow

buyers to realize cost savings or reliability gains that are not

attainable if they rely solely on their own resources. For sellers,

these transactions provide opportunities to earn additional revenue,

and to lower customer rates, from capacity that is temporarily in

excess to native load capacity requirements. Transactions are

voluntary and the seller's obligation is limited.''

Requirements service was defined as ``a long-term supply of firm

power to meet all or part of the buyer's load requirements,

including load-growth. Sellers undertake a relatively open-ended

commitment to provide service. Utilities must plan and build

generation and transmission capacity to meet this commitment. From

the seller's perspective, requirements service is essentially the

same as retail service with the primary difference being that

delivery is typically made at transmission voltages. Requirements

customers are considered part of the seller's native load. Buyers

are typically municipally or cooperatively owned distributors that

resell the power to end-use customers.''

IV FERC Stats. and Regs. at 35,628 (footnote omitted).

The Commission believes that the definition of coordination

transactions employed in the Notice of Inquiry will generally be

acceptable. Objections that a transaction is not a coordination

transaction can be pursued on a case-by-case basis.

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EEI opposes case-by-case treatment of rate recovery of emissions

allowances in coordination transactions. It argues that a case-by-case

approach would unduly burden the Commission with hundreds of virtually

identical proceedings that can be more efficiently addressed through

the policy statement approach it advocates here. EEI maintains that it

is not seeking to expand the meaning of defined contract terms, but

simply to include in existing contract terms costs that are reasonable

and contractually permissible. EEI recognizes the need for special

treatment of generating units subject to the requirements of reduced

utilization in the CAAA, and that exceptions to the use of the full

incremental costs of emissions allowances associated with those

generating units may take place. However, EEI believes that its

proposal adequately responds to Wisconsin Electric's concerns in this

area because it allows exceptions to full incremental costs as long as

dispatch criteria and the coordination rates are consistent.

EEI further states that the Commission should not designate any

specific index because such action would hinder market competition in

allowance trading. It characterizes as unnecessary and burdensome Clean

Air's proposals that energy sellers certify an unaffiliated third party

to provide allowances to a power purchaser, and that utilities be

required to report the volume and price of allowance trades for

publication by this Commission. Finally, EEI argues that this is not

the appropriate proceeding to specify particular revenue credit

treatment of allowance-related revenues. EEI submits that revenue

credits with respect to coordination transactions are specified either

in agreements between retail and wholesale customer groups and utility

companies or are required under the retail and wholesale practices of

state commissions or this Commission. Thus, EEI argues, revenue credits

are appropriately dealt with in rate cases, rather than in a policy

proceeding.

Discussion

Use of Incremental Costs

We will allow the recovery of incremental costs of emission

allowances in coordination rates whenever the coordination rate also

provides for recovery of other variable costs on an incremental basis.

EEI's proposal that the incremental cost of emissions allowances be

recovered in coordination rates will ensure, under many coordination

rate schedules, consistency with the way in which other costs (e.g.,

fuel) are recovered and with dispatch decisions. In response to APPA's

concern that the scope of the transactions affected by the Policy

Statement is not clearly defined in EEI's proposal, the Commission

wishes to make clear that the policy adopted here will apply only when

a coordination rate expressly provides for the recovery of incremental

costs or if stated rates are designed to recover incremental costs. If

a coordination rate does not reflect incremental cost pricing for other

costs (e.g., coordination transactions that are designed as unit sales

where the rates track the costs of a particular unit or coordination

rates that are designed to recover average costs), the Commission will

require the seller to propose an alternative costing method for

emissions allowances, or demonstrate that any inconsistency between the

proposed costing method and the coordination rate does not produce

unreasonable results. The Commission finds that the cost to replace an

allowance is an appropriate basis to establish incremental cost.29

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\2\9This is generally the method used to determine the

incremental fuel cost for dispatching and pricing for coordination

rates. Pennsylvania Power Company, Opinion No. 34, 6 FERC 61,036

(1979) (Pennsylvania).

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Use of Indices

We will adopt EEI's proposal that sellers be permitted to choose

their own index or a combination of indices. Because the emission

allowance markets are still developing, the Commission cannot, at this

time, conclude that any particular index should be utilized. Our

primary concern in allowing the selling utility to choose the index or

indices is that, if there are variations in the available indices, the

seller will select the one with the highest price at the time of the

transaction, rather than the index that best reflects the incremental

cost. EEI's proposal guards against this practice because it provides

the customer with the option to supply its own allowances rather than

purchase allowances from a selling utility.

Dispatch

EEI's proposal is based on sellers' use of the same index for

pricing coordination sales and making dispatch decisions. If the seller

does not use the same index for both purposes, EEI proposes that the

seller be required to reconcile the differences.

The Commission will adopt this proposal. The purpose of any

dispatch criterion is to meet each increment of load from the increment

of generation with the lowest running costs (fuel, other variable

operating expenses and, now, emissions allowances). If the seller is

not using the same cost index in its dispatch decisions as it is

proposing for pricing its coordination sales, we cannot rely upon the

index to reflect incremental cost.30 Accordingly, sellers must

explain and justify any differences in their use of different

incremental cost references for dispatch and pricing.31

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\3\0See Pennsylvania, supra n. 28.

\3\1In addition, Wisconsin Electric states that it needs to be

able to charge and dispatch at less than the incremental cost of

emissions allowances. Wisconsin Electric could comprehensively

support its method in an individual rate filing.

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Calculation of Amount of Emissions Allowances Associated With a

Transaction

The Commission will also adopt EEI's proposal that sellers explain

how they will compute the amount of emissions allowances that will be

attributed to each coordination transaction. The amount of emissions

allowances related to a coordination sale will vary based on the unit

used for pricing, the amount of energy generated and the type of fuel

used. The Commission expects that the generating unit used to compute

the emission allowance amount would be the same unit that is used to

price the incremental fuel component of the coordination rate. Also,

the seller should explain how fractional amounts will be handled. While

a customer choosing the cash compensation method could pay for part of

an allowance, the customer cannot choose to return part of an

allowance. To resolve this problem, utilities could adopt a

``rounding'' approach, i.e., rounding up to the next whole number if

the fraction is greater than one half, or down if the fraction is less

than one-half. If a rounding approach is used for the return of

allowances in kind, it should also be used for cash settlements so that

there is no bias for or against the return in kind option.

Timing

The Commission also adopts EEI's proposal that utilities provide

details on the timing of opportunities to return allowances or

stipulate whether they will purchase or return allowances. Customers

should be able to take advantage of possible cost savings resulting

from the timing of allowance settlements.32 This can be

accomplished by allowing customers that choose to provide allowances in

kind to do so by the appropriate EPA reporting date33 rather than

at the time of the transaction, i.e., a ``timing option.'' Thus,

allowance customers will have the same opportunities as allowance

sellers and face the same consequences, i.e., possible cost savings or

additional costs.34

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\3\2This issue is significant because utilities in effect settle

their allowance position with EPA at the EPA reporting date and the

cost of obtaining an allowance may be different at that time than it

is at the time that the transaction occurs. Indeed, there may be

significant differences in allowance costs at different times of the

year.

\3\3See supra n. 18. If a transaction begins and ends in

different calendar years, the customer, exercising the in kind

option, would be required to provide sufficient allowances to cover

electric energy purchased in each calendar year by the immediately

following EPA reporting date for such calendar year.

\3\4Customers would continue to have the option of a cash

settlement based on a current index.

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We note, however, that EEI's proposal addresses timing options only

with respect to longer-term transactions. In our opinion, timing

options should be available for all transactions since the seller's

timing flexibility is the same regardless of the length of the

transaction.

Other Factors That Impact Rates

The Commission adopts EEI's proposal that sellers specify any other

factors that may affect pricing. For example, many utilities have

coordination rates that allow a reservation charge based on a unit

other than the unit used to generate energy as long as the total

revenues do not exceed the fixed and variable costs of the unit used

for pricing.35 Utilities which operate under this type of ceiling

will have to clarify that the variable cost component includes the

emissions allowance amount associated with the unit used to establish

the ceiling.

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\3\5An example is Indiana Michigan Power Company's coordination

rate schedule, supra n.16, which consist of an energy charge based

on system incremental fuel and operating costs and a reservation

charge based on the cost of its Rockport generating unit. Because

Indiana Michigan has negotiated favorable coal contracts for the

Rockport unit, that unit is not likely to be available for

coordination sales. As a result, there is an inconsistency between

Indiana Michigan's demand charge (based on its Rockport unit) and

its energy charge (based on system incremental fuel cost which is

higher than Rockport's fuel cost). To conform this rate to the

Commission's requirement that energy and demand charges be designed

on a consistent basis, the rate is subject to a ceiling reflecting

the fixed and variable costs of the Rockport unit. See Indiana &

Michigan Electric Company, 10 FERC 61,295 (1980) (in which the

Commission explained that energy and demand charges must be designed

consistently to reflect the fixed and variable costs of the same

units).

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Other Rate Issues Raised by Intervenors

The Commission will not expand the scope of this Policy Statement

beyond what EEI has proposed. The ratemaking treatment for

coordination, requirements and affiliated pooling arrangements must

recognize the differences in the character of the service arrangements.

Furthermore, the timing of any ratemaking implementation will, of

necessity, be different. For instance, because in requirements service

the cost of emissions allowances will be a very small percentage of a

utility's overall costs, a utility may choose not to address emissions

allowance costs in requirements rates until it files its next general

rate case.

Also, since requirements customers typically pay a pro rata share

of all of a utility's prudently incurred costs and utilities may choose

various methods to comply with the CAAA, it would be difficult, if not

impossible, to establish a generic policy that would be appropriate for

all requirements service. Likewise, since operating agreements between

affiliate utilities are not uniform, it would be difficult to establish

a generic ratemaking policy for affiliated pooling arrangements.

Affiliate agreements also may reflect compromises to satisfy the

concerns of state regulators.36

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\3\6Indeed, several affiliated pooling groups have already made

filings and their proposals reflect these types of significant

distinctions.

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Conversely, the pricing of coordination transactions is fairly

standardized, generally reflecting an energy charge equal to

incremental costs and a reservation charge providing a contribution to

the fixed costs of the units used to price the energy. Thus, the

treatment of emissions allowances in coordination rates can be readily

addressed in a generic fashion.

In accordance with Florida Power's request, we state that Phase II

utilities are not now required to make rate filings detailing their

emission allowance treatment for coordination transactions that will

not be affected until the year 2000. Such filings would be due no more

than 120 or less than 60 days prior to Phase II.

The intervenors have raised concerns regarding the crediting of

allowance related revenues to requirements rates or the allocation of

emissions allowances between retail and wholesale requirements

jurisdictions. It will be our policy to treat the revenues from

allowances sold as part of coordination sales the same way we treat

other revenues from coordination sales. In other words, to the extent,

and in the same way that, the latter revenues are credited to

jurisdictional customers, so should the former revenues. However, we

will address implementation of this policy in the context of individual

requirements rate proceedings, or, if appropriate, complaint

proceedings. In section 205 proceedings, utilities will be expected to

fully support their test year projections for emission allowances

associated with coordination sales.

We reject Clean Air's requests that the Commission require sellers

to report the volume and price of allowances transferred and publish

this information, and that sellers certify unaffiliated third parties

to provide allowances to a customer. Sellers must, of course, be

prepared to document the calculation of all aspects of their rates,

including the emissions allowance component. However, an extensive

reporting requirement and third-party certification would be costly and

time consuming, and there is no basis to conclude that imposition of

this burden on utilities would enhance the development of the emission

allowance trading markets.

Use of Alternate Rate Treatments

Finally, the Commission notes that this Policy Statement contains

general guidelines on ratemaking treatment in coordination rates for

the cost of emissions allowances. It is not intended to preclude

utilities or other interested parties, such as state commissions, from

proposing alternate rate treatments for consideration on a case-by-case

basis.37

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\3\7Florida Power requests that the Policy Statement not

prejudge every contractual relationship. Florida Power is primarily

concerned about its existing arrangements with Southern Companies

which are at issue in Docket No. ER95-59-000. This Policy Statement

will not preclude Florida Power from proposing different treatments

with respect to those arrangements at issue in Docket No. ER95-59-

000.

APPA is concerned about the lack of specifics concerning

possible alternatives to EEI's proposal. However, we will not

address alternate proposals in this Policy Statement, other than to

state that they are permitted to be presented to the Commission and

will be considered on a case-by-case basis. The Commission will

ensure that any alternate proposal adopted is just and reasonable,

and in so doing will consider fully the concerns of affected parties

who intervene in individual rate proceedings, abbreviated or

otherwise, involving emissions allowances.

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V. Implementation Procedures

In the Interim Rule accompanying the Policy Statement, the

Commission also adopts EEI's proposal that if utilities have rate

schedules on file that expressly provide for the recovery of all

incremental or out-of-pocket costs, these utilities should be allowed

to make abbreviated rate filings, limited to detailing how they would

recover emissions allowance costs. These filings should include the

following: the index or combination of indices to be used, the method

by which the emission allowance amounts will be calculated, timing

procedures, how inconsistencies, if any, with dispatch criteria will be

reconciled, and how any other rate impacts will be addressed. These

filings would constitute rate schedule amendments under FPA section 205

since they would describe how the rates are computed. Utilities making

such abbreviated filings should: (1) clearly identify the filing as

being limited to amendments to coordination rates to reflect the costs

of emissions allowances, in the first paragraph of the letter of

transmittal accompanying the filing, (2) submit a document that can be

inserted into each rate schedule and (3) identify each rate schedule to

which the amendment applies. Finally, the abbreviated filing should

apply consistent treatment to all coordination rate schedules or the

filing utility should justify its failure to do so.

Regarding coordination rates that do not provide for the recovery

of all incremental costs,\38\ we conclude that the seller may include

rate schedule amendments together with the abbreviated filing discussed

above if the customer agrees to the rate change. If the customer does

not agree to revise such rates, the utility should tender its emission

allowance proposal in a separate section 205 rate filing, fully

justifying its proposal. This will ensure that the processing of

uncontested rate filings is not delayed by disputes over individual

agreements.

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\38\Some coordination rates provide only for the recovery of

incremental fuel costs, and contain no provisions for recovery of

other incremental costs. Also, some coordination transactions, while

premised upon incremental costs, take place under stated rates.

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Finally, APPA expresses concern that affected parties be afforded

an opportunity to challenge application of the policy announced herein

on a case-by-case basis. APPA's concerns are satisfied because, in all

cases, the filings would be noticed and customers provided an

opportunity to comment.

45-Day Amendment Period

The Commission adopts EEI's proposal that utilities be allowed to

implement the policy announced herein on January 1, 1995, but make the

filings discussed above within 45 days after the Commission issues an

order in this proceeding. In return for granting waiver of notice, the

utilities must agree that revenues will be collected subject to refund

pending Commission action. Utilities making such filings should include

a statement in the first paragraph of their transmittal letter agreeing

to the refund condition with respect to allowance-related charges

assessed between January 1, 1995, and the date the Commission issues an

order accepting the filing without investigation or hearing.

VI. Information Collection Statement

The Office of Management and Budget's (OMB's) regulations at 5 CFR

1320.13 require that OMB approve certain information and recordkeeping

requirements imposed by an agency. The information collection

requirements in this policy statement are contained in FERC-516

``Electric Rate Schedule Filings'' (1902-0096).

The Commission is issuing this Policy Statement and Interim Rule

with the information requirements to carry out its regulatory

responsibilities under the Federal Power Act to determine the

appropriate ratemaking treatment of sulfur dioxide emissions allowances

in coordination transactions.

The Policy Statement and Interim Rule provide guidance to public

utilities on the ratemaking treatment of emissions allowances in

coordination transactions in order that the CAAA emissions allowance

program will be implemented in accordance with the Congressional

mandate. The Commission's Office of Electric Power Regulation uses the

data for determination for the reasonableness and justness of costs for

emissions allowances when a public utility seeks to pass through its

costs in wholesale rates. These collections of information are intended

to be the minimum elements needed for utilities to file amendments to

their rate schedules.

The Commission is submitting to the Office of Management and Budget

a notification of these proposed collections of information. Interested

persons may obtain information on these reporting requirements by

contacting the Federal Energy Regulatory Commission, 941 North Capitol

Street, NE, Washington, DC 20426 [Attention: Michael Miller,

Information Services Division, (202) 208-1415]. Comments on the

requirements of this rule can be sent to the Office of Information and

Regulatory Affairs of OMB, Washington, D.C. 20503, (Attention: Desk

Officer for Federal Energy Regulatory Commission) FAX: (202) 395-5167.

VII. Public Comment Procedures

The Commission invites interested persons to submit additional

written comments on the matters addressed in this Interim Rule. An

original and 14 copies of the comments must be filed with the

Commission no later than January 23, 1995. Comments should be submitted

to the Office of the Secretary, Federal Energy Regulatory Commission,

825 North Capitol Street, N.E., Washington, D.C. 20426, and should

refer to Docket No. PL95-1-000.

All other written comments will be placed in the Commission's

public files and will be available for public inspection in the

Commission's Public Reference Room at 941 North Capitol Street, N.E.

Washington, D.C. 20426, during regular business hours.

VIII. Effective Date

This Policy Statement and Interim Rule are effective January 1,

1995. Because Phase I of the CAAA begins January 1, 1995, public

utilities subject to the Commission's jurisdiction need to have in

place as of that date a method of recovery in rates of the cost of

emissions allowances used in coordination transactions. For that reason

the Commission finds good cause to make the Interim Rule effective

without prior notice and comment, and finds good cause to make the

Interim Rule effective on less than 30 days' notice.

List of Subjects

18 CFR Part 2

Administrative practice and procedure, electric power, natural gas,

pipelines, reporting and recordkeeping requirements.

18 CFR Part 35

Electric power rates, electric utilities, reporting and

recordkeeping requirements.

By the Commission.

Linwood A. Watson, Jr.,

Acting Secretary.

In consideration of the foregoing, the Commission amends Part 2 and

Part 35 of Title 18 of the Code of Federal Regulations as set forth

below.

PART 2--GENERAL POLICY AND INTERPRETATIONS

1. The authority citation for Part 2 continues to read as follows:

Authority: 15 U.S.C. 717-717w, 3301-3432; 16 U.S.C. 792-825y,

2601-2645; 42 U.S.C. 4321-4361, 7101-7352.

2. Part 2 is amended by adding Sec. 2.25, to read as follows:

Sec. 2.25 Ratemaking Treatment of the Cost of Emissions Allowances in

Coordination Transactions.

(a) General Policy. This Statement of Policy is adopted in

furtherance of the goals of Title IV of the Clean Air Act Amendments of

1990, Pub. L. 101-549, Title IV, 104 Stat. 2399, 2584 (1990).

(b) Costing Emissions Allowances in Coordination Sales. If a public

utility's coordination rate on file with the Commission provides for

recovery of variable costs on an incremental basis, the Commission will

allow recovery of the incremental costs of emissions allowances

associated with a coordination sale. If a coordination rate does not

reflect incremental costs, the public utility should propose

alternative allowance costing methods or demonstrate that the

coordination rate does not produce unreasonable results. The Commission

finds that the cost to replace an allowance is an appropriate basis to

establish the incremental cost.

(c) Use of Indices. The Commission will allow public utilities to

determine emissions allowance costs on the basis of an index or

combination of indices of the current price of emissions allowances,

provided that the public utility affords purchasing utilities the

option of providing emissions allowances. Public utilities should

explain and justify any use of different incremental cost indices for

pricing coordination sales and making dispatch decisions.

(d) Calculation of Amount of Emissions Allowances Associated With

Coordination Transactions. Public utilities should explain the methods

used to compute the amount of emissions allowances included in

coordination transactions.

(e) Timing. Public utilities should provide information to

purchasing utilities regarding the timing of opportunities for

purchasers to stipulate whether they will purchase or return emissions

allowances.

(f) Other Costing Methods Not Precluded. The ratemaking treatment

of emissions allowance costs endorsed in this Policy Statement does not

preclude other approaches proposed by individual utilities on a case-

by-case basis.

PART 35--FILING OF RATE SCHEDULES

1. The authority citation for Part 35 continues to read as follows:

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42

U.S.C. 7101-7352.

2. Section 35 is amended by adding Section 35.23, to read as

follows:

Sec. 35.23 General Provisions.

(a) Applicability. This subpart applies to any wholesale sale of

electric energy in a coordination transaction by a public utility if

that sale requires the use of an emissions allowance.

(b) Implementation Procedures. (1) If a public utility has a

coordination rate schedule on file that expressly provides for the

recovery of all incremental or out-of-pocket costs, such utility may

make an abbreviated rate filing detailing how it will recover emissions

allowance costs. Such filing must include the following: the index or

combination of indices to be used; the method by which the emission

allowance amounts will be calculated; timing procedures; how

inconsistencies, if any, with dispatch criteria will be reconciled; and

how any other rate impacts will be addressed. In addition, a utility

making an abbreviated filing must:

(i) clearly identify the filing as being limited to an amendment to

a coordination rate to reflect the cost of emissions allowances, in the

first paragraph of the letter of transmittal accompanying the filing;

(ii) submit revised pages that can be inserted into each rate

schedule; and

(iii) identify each rate schedule to which the amendment applies.

(2) The abbreviated filing must apply consistent treatment to all

coordination rate schedules. If the filing does not apply consistent

rate treatment, the public utility must explain why it does not do so.

(3) If a public utility wants to charge incremental costs for

emissions allowances, but its rate schedule on file with the Commission

does not provide for the recovery of all incremental costs, the selling

public utility may submit an abbreviated filing if all customers agree

to the rate change. If customers do not agree, the selling public

utility must tender its emissions allowance proposal in a separate

section 205 rate filing, fully justifying its proposal.

[FR Doc. 94-31324 Filed 12-21-94; 8:45 am]

BILLING CODE 6717-01-P