[Federal Register Volume 59, Number 245 (Thursday, December 22, 1994)]
[Unknown Section]
[Page 0]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 94-31324]


[[Page Unknown]]

[Federal Register: December 22, 1994]


=======================================================================
-----------------------------------------------------------------------

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.

-----------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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
---------------------------------------------------------------------------

    \4\The Commission addresses certain jurisdictional issues raised 
by EEI in a separate order issued concurrently.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

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

    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
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \1\3EEI Petition, Appendix A.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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
---------------------------------------------------------------------------

    \2\5Utility Environment Report, Cantor Fitzgerald, Compliance 
Strategies Review and Emission Exchange.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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
---------------------------------------------------------------------------

    \3\6Indeed, several affiliated pooling groups have already made 
filings and their proposals reflect these types of significant 
distinctions.
---------------------------------------------------------------------------

    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
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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