[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]
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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
