[Federal Register Volume 65, Number 213 (Thursday, November 2, 2000)]
[Rules and Regulations]
[Pages 65757-65769]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-27992]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 382

[Docket No. RM00-7-000; Order No. 641]


Revision of Annual Charges Assessed to Public Utilities Issued 
October 26, 2000

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final Rule.

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SUMMARY: In an effort to reflect changes in the electric industry and 
in the way the Federal Energy Regulatory Commission (Commission) 
regulates the electric industry, the Commission is amending its 
regulations to establish a new methodology for the assessment of annual 
charges to public utilities. The regulation provides that annual 
charges will be assessed to public utilities that provide transmission 
service based on the volume of electricity transmitted by those public 
utilities. The regulation thus will result in the Commission's now 
assessing annual charges on transmission rather than, as previously, 
assessing annual charges on both power sales and transmission.

EFFECTIVE DATE: This Final Rule will become effective January 1, 2001.

FOR FURTHER INFORMATION CONTACT:   
    Herman Dalgetty (Technical Information), Office of the Executive 
Director and Chief Financial Officer, 888 First Street, N.E., 
Washington, D.C. 20426, (202) 219-2918.
    Jennifer Lokenvitz Schwitzer (Legal Information), Office of the 
General Counsel, 888 First Street, N.E., Washington, D.C. 20426, (202) 
219-4471

SUPPLEMENTARY INFORMATION: Before Commissioners: James J. Hoecker, 
Chairman; William L. Massey, Linda Breathitt, and Curt Hebert, Jr.

Table of Contents

I. Introduction
II. Background
    A. Commission Authority
    B. Current Annual Charge Billing Procedure
    C. Reasons for this Rule
    D. Notice of Proposed Rulemaking
III. Discussion
    A. The Types of Companies to be Billed
    1. Public Utilities
    2. Federal Power Marketing Agencies
    3. Qualifying Facilities
    4. Discussion
    a. Proposed New Methodology
    b. Comments
    c. Commission Conclusion
    B. New Apportionment
    1. Proposed New Methodology
    2. Comments
    3. Commission Conclusion
    4. Independent System Operators and Regional Transmission 
Organizations
    a. Proposed New Methodology
    b. Comments
    c. Commission Conclusion
    C. Other Matters
    1. Rate Recovery
    2. Reporting Requirements
    3. Standards for Waiving All or Part of an Annual Charge
IV. Environmental Statement
V. Regulatory Flexibility Act Certification
VI. Public Reporting Burden and Information Collection Statement
VII. Effective Date and Congressional Notification
VIII. Document Availability
Regulatory Text
List of Abbreviations

I. Introduction

    In an effort to reflect changes in the electric industry and in the 
way the Federal Energy Regulatory Commission (Commission) regulates the 
electric industry, the Commission is amending its regulations to 
establish a new methodology for the assessment of annual charges to 
public utilities. The regulation provides that annual charges will be 
assessed to public utilities that provide transmission service based on 
the volume of electricity transmitted by those public utilities. The 
regulation thus will result in the Commission's now assessing annual 
charges on transmission rather than, as previously, assessing annual 
charges on both power sales and transmission.

II. Background

A. Commission Authority

    The Commission is required by section 3401 of the Omnibus Budget 
Reconciliation Act of 1986 (Budget Act) \1\ to ``assess and collect 
fees and annual charges in any fiscal year in amounts equal to all of 
the costs incurred * * * in that fiscal year.'' \2\ The annual charges 
must be computed based on methods which the Commission determines to be 
``fair and equitable.'' \3\ The Conference Report accompanying the 
Budget Act provides the Commission with the following guidance as to 
this phrase's meaning:

    \1\ 42 U.S.C. 7178.
    \2\ This authority is in addition to that granted to the 
Commission in sections 10(e) and 30(e) of the Federal Power Act 
(FPA). 16 U.S.C. 803(e), 823a(e).
    \3\ 42 U.S.C. 7178(b).
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    [A]nnual charges assessed during a fiscal year on any person may 
be reasonably based on the following factors: (1) The type of 
Commission regulation which applies to such person such as a gas 
pipeline or electric utility regulation; (2) the total direct and 
indirect costs of that type of Commission regulation incurred during 
such year; \4\ (3) the amount of energy--electricity, natural gas, 
or oil--transported or sold subject to Commission regulation by such 
person during such year; and (4) the total volume of all energy 
transported or sold subject to Commission regulation by all 
similarly situated persons during such year.\5\
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    \4\ The Commission is required to collect not only all its 
direct costs but also all its indirect expenses such as hearing 
costs and indirect personnel costs. See H.R. Conf. Rep. No. 99-1012 
at 238 (1986), reprinted in 1986 U.S.C.C.A.N. 3868, 3883 (Conference 
Report); see also S. Rep. No. 99-348 at 56, 66 and 68 (1986).
    \5\ See Conference Report at 238.

The Commission may assess these charges by making estimates based upon 
data available to it at the time of the assessment.\6\
    The annual charges do not enable the Commission to collect amounts 
in excess of its expenses, but merely serve as a vehicle to reimburse 
the United

[[Page 65758]]

States Treasury for the Commission's expenses.\7\
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    \6\ 42 U.S.C. 7178(c).
    \7\ Id. at 7178(f). Congress approves the Commission's budget 
through annual and supplemental appropriations.
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B. Current Annual Charge Billing Procedure

    As required by the Budget Act, the Commission's regulations provide 
for the payment of annual charges by public utilities.\8\ The 
Commission intends that these electric annual charges in any fiscal 
year will recover the Commission's estimated electric regulatory 
program costs (other than the costs of regulating Federal Power 
Marketing Agencies (PMAs) and electric regulatory program costs 
recovered through electric filing fees) for that fiscal year. In the 
next fiscal year, the Commission adjusts its annual charges up or down, 
as appropriate, both to eliminate any over-or under-recovery of the 
Commission's actual costs and to eliminate any over-or under-charging 
of any particular person.\9\
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    \8\ 18 CFR Part 382; see Annual Charges Under the Omnibus Budget 
Reconciliation Act of 1986, Order No. 472, 52 FR 21263 and 24153 
(June 5 and 29, 1987), FERC Stats. & Regs., Regulations Preambles 
1986-1990 para. 30,746 (1987), clarified, Order No. 472-A, 52 FR 
23650 (June 24, 1987), FERC Stats. & Regs., Regulations Preambles 
1986-1990 para. 30,750, order on reh'g, Order No. 472-B, 52 FR 36013 
(Sept. 25, 1987), FERC Stats. & Regs., Regulations Preambles 1986-
1990 para. 30,767 (1987), order on reh'g, Order No. 472-C, 53 FR 
1728 (Jan. 22, 1988), 42 FERC para. 61,013 (1988).
    \9\ 18 CFR 382.201; see Order No. 472, 52 FR at 21263 and 24153, 
FERC Stats. & Regs., Regulations Preambles 1986-1990 at 30,612-18; 
accord Annual Charges Under the Omnibus Budget Reconciliation Act of 
1986, Order No. 507, 53 FR 46445 (Nov. 17, 1985), FERC Stats. & 
Regs. , Regulations Preambles 1986-1990 para. 30,839 at 31,263-64 
(1988); Texas Utilities Electric Company, 45 FERC para. 61,007 at 
61,027 (1988) (Texas Utilities).
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    In calculating annual charges, the Commission first determines the 
total costs of its electric regulatory program and subtracts all PMA-
related costs and electric filing fee collections to determine total 
collectible electric regulatory program costs. It then uses the data 
submitted under FERC Reporting Requirement No. 582 (FERC-582) to 
determine the total volumes of long-term firm wholesale sales and 
transmission, and short-term sales and transmission and exchanges for 
all assessable public utilities. The Commission divides those 
transaction volumes into its collectible electric regulatory program 
costs to determine the unit charge per megawatt-hour for each category 
of long-term and short-term transactions. Finally, the Commission 
multiplies the transaction volume in each category for each public 
utility by the relevant unit charge per megawatt-hour to determine the 
annual charges for all assessable public utilities.\10\
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    \10\ 18 CFR 382.201; see Annual Charges Under the Omnibus Budget 
Reconciliation Act of 1986 (Phibro Inc.), 81 FERC para. 61,308 at 
62,424-25 (1997).
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    Public utilities subject to these annual charges must submit FERC-
582 to the Office of the Secretary by April 30 of each year.\11\ The 
Commission issues bills for annual charges, and public utilities then 
must pay the charges within 45 days of the date on which the Commission 
issues the bills.\12\
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    \11\ 18 CFR 382.201(b)(4).
    \12\ See Texas Utilities, 45 FERC at 61,026.
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C. Reasons for This Rule

    Since the issuance of Order No. 472, in 1987, the industry has 
undergone sweeping changes, including: the Commission's establishment 
of open access transmission as a foundation for competitive wholesale 
power markets;\13\ a movement by many states to develop retail 
competition; the growing divestiture of generation assets by 
traditional public utilities; the entry of new market participants into 
the industry in the form of independent and affiliated power marketers 
and stand-alone merchant plant generators; and the establishment of 
Independent System Operators (ISOs), the expected establishment of 
Regional Transmission Organizations (RTOs), and also the establishment 
of transmission companies (transcos) and power exchanges as managers of 
transmission systems and power markets respectively.
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    \13\ See Promoting Wholesale Competition Through Open Access 
Non-discriminatory Transmission Services by Public Utilities and 
Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities, Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & 
Regs. para. 31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 
12274 (Mar. 14, 1997), FERC Stats. & Regs. para. 31,048 (1997), 
order on reh'g, Order No. 888-B, 62 FR 64688 (Mar. 14, 1997), 81 
FERC para. 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC 
para. 61,046 (1998), aff'd in relevant part sub nom, Transmission 
Access Policy Study Group, et al. v. FERC, No. 97-1715 et al. (D.C. 
Cir. June 30, 2000) (TAPSG) (Order No. 888).
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    As the landscape of the industry has changed and continues to 
change, the nature of the work of the Commission likewise has changed. 
This rule, as described below, reflects these changes--changing the way 
in which the Commission assesses annual charges to recover its electric 
regulatory program costs to reflect recent industry and Commission 
changes, by assessing annual charges to public utilities that provide 
transmission service based on the volumes of electric energy 
transmitted.

D. Notice of Proposed Rulemaking

    On January 28, 2000, the Commission issued a Notice of Proposed 
Rulemaking (NOPR) proposing revisions to the Commission's annual 
charges regulations.\14\ In the NOPR, the Commission proposed a new 
methodology for the assessment of annual charges to public utilities. 
The Commission proposed to assess its electric regulatory program costs 
solely on the MWh of electric energy transmitted in interstate commerce 
by public utilities, rather than, as the Commission had done in the 
past, on both jurisdictional power sales and transmission volumes. 
Specifically, the Commission proposed to assess annual charges to 
public utilities based on their transmission of electric energy in 
interstate commerce, as measured by (1) unbundled wholesale 
transmission, (2) unbundled retail transmission, and (3) bundled 
wholesale power sales, which for this purpose, by definition, include a 
transmission component.\15\
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    \14\ Revision of Annual Charges Assessed to Public Utilities, 
Notice of Proposed Rulemaking, 65 FR 5289 (Jan. 28, 2000), FERC 
Stats. & Regs. para. 32,550 (2000).
    \15\ FERC Stats. & Regs. para. 32,550 at 33,921.
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    As to ISOs, and potential RTOs, that have members that retain 
ownership of transmission facilities, the Commission stated in the NOPR 
that it was concerned that the assessment of annual charges to ISOs and 
RTOs could result in a ``double counting'' of transactions--by counting 
a single transaction both to the transmission-owning public utility and 
to the ISO or RTO. In the NOPR, the Commission proposed two solutions 
to prevent ``double counting'': (1) Not charge the ISO or RTO annual 
charges, but instead charge each individual transmission-owning public 
utility based on the MWh of transmission service provided on their 
lines; or (2) allow the ISO or RTO to act as an agent for all of the 
individual transmission owners and have the ISO or RTO pay the annual 
charges rather than the individual transmission owners.\16\ The 
Commission, noting that either of these approaches may be acceptable, 
solicited comments on these two approaches, as well as any other 
approach that would allow the Commission to collect annual charges on 
MWh of transmission service in the most administratively efficient 
manner.
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    \16\ Id.
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    Comments on the NOPR were due on April 3, 2000.\17\ The Commission 
received 35 initial and reply comments in response to the NOPR. Based 
on consideration of the comments submitted in response to the NOPR, as 
discussed below, the Commission

[[Page 65759]]

adopts a Final Rule that follows the approach of the NOPR.
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    \17\ The commenters, and the abbreviations for them used herein, 
are listed in an appendix to this Final Rule.
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III. Discussion

    In Order No. 472, to implement the Budget Act, the Commission 
formulated an annual charge billing procedure. To do this, the 
Commission had to determine: (1) The types of companies which the 
Commission should bill; (2) how to estimate and then allocate the 
Commission's costs among its different regulatory programs; and (3) how 
to allocate each program's costs among the companies under each 
program. After the annual charge billing procedure was formulated, the 
Commission then had to determine (1) how to adjust the annual charges 
at the end of a fiscal year ``to eliminate any over-recovery or under-
recovery of [the Commission's] total costs, and any overcharging or 
undercharging of any person'' pursuant to section 3401(e) of the Budget 
Act; and (2) the standards for waiving all or part of an annual charge 
pursuant to section 3401(g) of the Budget Act.
    We note at the outset that this Final Rule is only for the 
determination of annual charges to recover the costs of the 
Commission's electric regulatory program. Therefore, how to apportion 
the Commission's total costs among the Commission's different 
regulatory programs is not before the Commission.
    Below, we will discuss the types of companies to be billed, the 
apportionment of our electric regulatory program costs among such 
companies, and other matters related to the changes to the Commission's 
regulations on annual charges.

A. The Types of Companies to Be Billed

    The Commission's electric regulatory program includes: 
administering the provisions of Parts II and III of the Federal Power 
Act (FPA) \18\ as they apply to the activities of public utilities 
(traditionally, principally investor-owned utilities); \19\ discharging 
its responsibilities under various statutes involving the PMAs; and 
implementing various provisions of the Public Utility Regulatory 
Policies Act of 1978 (PURPA) \20\ involving qualifying cogenerators and 
small power producers (QFs).
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    \18\ 16 U.S.C. 824-825r.
    \19\ Under sections 211, 212 and 213 of the FPA, 16 U.S.C. 824j-
l, the Commission also has authority over transmitting utilities 
that are not public utilities. Compare 16 U.S.C. 796(23) with 16 
U.S.C. 824(b), (e).
    \20\ 16 U.S.C. 2601-2645.
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1. Public Utilities
    Pursuant to section 205 of the FPA,\21\ the Commission regulates 
the rates, terms and conditions of service of public utilities making 
sales for resale or transmitting electric energy in interstate 
commerce. All jurisdictional rates, terms and conditions must be on 
file with the Commission, and may be approved by the Commission only if 
they are just and reasonable and not unduly discriminatory or 
preferential. Under section 206 of the FPA,\22\ the Commission may 
change any rates, terms or conditions that it finds to be unjust, 
unreasonable, or unduly discriminatory or preferential.
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    \21\ 16 U.S.C. 824d.
    \22\ 16 U.S.C. 824e.
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    The Commission also regulates certain accounting and corporate 
activities of public utilities pursuant to the FPA. Examples include 
the following: Under section 203,\23\ the Commission reviews 
applications filed by public utilities seeking to merge or to dispose 
of jurisdictional facilities. Pursuant to section 204,\24\ the 
Commission reviews the proposed securities issuances of public 
utilities whose securities issuances are not regulated by a state 
commission within the meaning of section 204(f). Under sections 301 and 
302,\25\ the Commission has authority over a public utility's 
accounting and its depreciation. Section 304 outlines the Commission's 
authority to direct public utilities (and also licensees) to report 
information, including information on transmission of electric energy 
to the Commission.\26\
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    \23\ 16 U.S.C. 824b.
    \24\ 16 U.S.C. 824c.
    \25\ 16 U.S.C. 825, 825a.
    \26\ 16 U.S.C. 825c.
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2. Federal Power Marketing Agencies
    The Commission reviews the rates established by the Department of 
Energy for the PMAs (Bonneville Power Administration (BPA), 
Southeastern Power Administration, Southwestern Power Administration, 
and Western Area Power Administration). While regulation of public 
utility rates is guided by the FPA, regulation of the PMAs' rates is 
subject to the standards enumerated in a number of other statutes.\27\ 
Essentially, the statutes require that the rates established by the 
PMAs must be devised with regard for the recovery of the cost of 
generation and transmission of electric energy, the encouragement of 
the most widespread use of the power, the provision of the lowest 
possible rates to customers consistent with sound business principles, 
and the protection of the interests of the United States in amortizing 
its investment in the projects within a reasonable period of time. The 
Commission is also authorized, pursuant to the Northwest Power Act, to 
review the Average System Cost methodology used to determine rates for 
exchange sales by utilities to BPA.
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    \27\ Flood Control Act of 1944, 16 U.S.C. 825s; Federal Columbia 
River Transmission System Act, 16 U.S.C. 838g; Pacific Northwest 
Power Preference Act, 16 U.S.C. 837; Pacific Northwest Electric 
Power Planning and Conservation Act of 1980, 16 U.S.C. 839; 
Bonneville Project Act, 16 U.S.C. 832f (Northwest Power Act); 
Reclamation Act of 1939, 43 U.S.C. 485h; Department of Energy 
Organization Act, 42 U.S.C. 7101; see also DOE Delegation Order No. 
0204-108, 48 FR 55664 (Dec. 14, 1983); 18 CFR Parts 300 and 301.
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3. Qualifying Facilities
    Section 210 of PURPA \28\ requires the Commission to prescribe 
rules to encourage cogeneration and small power production of 
electricity. In particular, the section directs the Commission to adopt 
rules requiring utilities to purchase power from and sell power to 
qualifying cogeneration and small power production facilities. The 
Commission reviews applications filed by cogenerators and small power 
producers requesting QF certification, and either grants or rejects 
such applications based on criteria set forth in the Commission's 
regulations.\29\
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    \28\ 16 U.S.C. 824a-3.
    \29\ 18 CFR Part 292.
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4. Discussion
    a. Proposed New Methodology. In the NOPR, the Commission proposed 
to assess annual charges only to public utilities involved in the 
transmission of electric energy in interstate commerce.
    b. Comments. Avista argues that the Commission should ensure that 
filings by PMAs and QFs carry an appropriate filing fee so that the 
majority of the cost of regulating those entities is paid for by those 
entities directly.\30\ Avista and AEP argue that all costs will be 
borne by regulated transmission-owning public utilities, while other 
transmitting entities (non-jurisdictional) will not bear a comparable 
burden.
    c. Commission Conclusion. The Commission will adopt the approach 
taken in the NOPR. That is, it will assess annual charges only to 
public utilities that provide transmission service.
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    \30\ The issue of filing fees is not before the Commission. In 
fact, however, QFs are assessed filing fees. 18 CFR 381.505.
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    The Commission is not persuaded that any change is warranted with 
respect to the Commission's existing policy as to assessment of annual 
charges to PMAs; the costs associated with the Commission's regulation 
of

[[Page 65760]]

PMAs are separately identified and separately recovered.\31\
    The Commission will continue to excuse qualifying cogenerators and 
small power producers from the direct assessment of annual charges.\32\ 
We already have exempted them from regulation under most sections of 
the FPA, including sections 205 and 206 of the FPA.\33\ While these 
entities could be transmitting utilities subject to our authority under 
sections 211, 212, and 213 of the FPA, in fact, we have not exercised 
this limited authority as to any such entities.
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    \31\ See 18 CFR 382.201(c).
    \32\ 18 CFR 382.102(b); see Order No. 472, FERC Stats. & Regs., 
Regulations Preambles 1986-1990 at 30,637. As transmission customers 
they may, of course, be charged rates by the transmission provider 
that reflect annual charges assessed to the transmission provider.
    \33\ See 18 CFR 292.601.
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    The Commission will continue its existing policy that municipal 
utility systems and rural electric cooperative utility systems that are 
financed by the Rural Utilities Service will not be required to pay 
annual charges.\34\ While these entities may be transmitting utilities 
subject to our authority under sections 211, 212 and 213 of the FPA, 
they are not public utilities under the FPA.\35\ In addition, the 
number of such entities that we, in fact, regulate under this limited 
authority is very small, as is the amount of transmission they provide 
under section 211 of the FPA.\36\ The Commission also will continue its 
practice of not assessing annual charges to utilities operating in 
Alaska or Hawaii. They are not public utilities under the FPA because 
they do not make wholesale sales or transmit electric energy in 
interstate commerce.
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    \34\ See supra note 32. As transmission customers they may, of 
course, be charged rates by the transmission provider that reflect 
annual charges assessed to the transmission provider.
    \35\ 18 CFR 382.102(b); see 16 U.S.C. 284; South Carolina Public 
Service Authority, 75 FERC para. 61,209 at 61,696 (1996); Dairyland 
Power Corporation, 37 FPC 12, 15 (1967); accord, Salt River Project 
Agricultural Improvement and Power District v. FPC, 391 F.2d 470, 
474 (D.C. Cir.), cert. denied, 393 U.S. 857 (1968).
    \36\ Based upon a review of our records, it appears that we have 
only twice issued final orders directing such entities to provide 
transmission service under section 211. See Minnesota Municipal 
Power Agency v. Southern Minnesota Municipal Power Agency, 68 FERC 
para. 61,060 (1994); City of College Station, Texas, 86 FERC para. 
61,165 (1999).
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    Lastly, the Commission will not assess annual charges to foreign 
electric utilities to the extent that their transactions are in foreign 
commerce or wholly within another country.\37\
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    \37\ E.g., British Columbia Power Exchange Corporation, 80 FERC 
para. 61,343 at 62,137, 62,141 (1997) (sales in foreign commerce or 
within another country are excluded from annual charges 
calculations).
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B. New Apportionment

1. Proposed New Methodology
    The Commission, given the changes in the electric industry and in 
the Commission's regulation of the electric industry, proposed that 
annual charges be assessed based solely on volumes of electric energy 
transmitted, rather than, as in the past, based on volumes of electric 
energy both sold and transmitted.
2. Comments
    Many comments received in support of the NOPR stated that the 
proposal properly recognizes that the Commission's regulatory efforts 
in electricity are now predominately focused on ensuring non-
discriminatory, open access transmission service.\38\ APX states that 
targeting annual charges to power sales and exchanges cannot be 
justified in relation to the Commission's current workload. PNGC 
supports the Commission's proposal, stating that it will eliminate a 
disparity in costs faced by power sellers depending upon their 
jurisdictional status, eliminate problems faced by power sellers in 
recovering these costs as part of market prices for power, more 
accurately assess costs to those services, i.e., transmission, which 
require much more of its resources, and eliminate multiple assessments 
currently faced by power sellers.
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    \38\ Williams EM&T states that it strongly supports the 
Commission's proposal and notes that that proposal substantially 
addresses the issues previously raised by Williams EM&T and other 
power marketers in a petition for rulemaking in Docket No. RM98-14-
000, to initiate a rulemaking to modify the methodology for 
assessing annual charges.
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    The Commission notes that the instant rulemaking on annual charges 
moots the petition for rulemaking and the petition can therefore be 
terminated.
    NYMEX and MLCS support the proposed revisions, stating that for a 
competitive wholesale power market to continue to develop, electricity 
must be considered a fungible commodity that can be bought and sold in 
a competitive open market without incurring excessive transaction 
costs. They urge that the proposed rule be adopted, as it promotes, 
rather than stymies, competitive electric wholesale transactions. The 
rules proposed will reduce transaction costs, better enable the 
wholesale electric market to respond efficiently to market-driven 
forces, and promote liquidity and price transparency in the industry.
    A number of commenters cautioned that the proposed method is not 
clear and does not allow public utilities to make a proper analysis as 
to how the method proposed will impact their companies. These 
commenters request that the Commission defer final action, provide 
additional detail and analysis, and allow another opportunity to 
comment.
    EEI states that, at best, it and its members can only guess at 
three possible Form No. 1 data line items that may qualify under the 
proposed method of assessing annual charges.\39\ EEI argues that the 
Commission's clarification regarding the exact line items required to 
make the proposed annual assessment calculation is needed in order for 
those entities subject to the rule to evaluate its impact and be in a 
position to comment other than on the concept. Otherwise, EEI argues, 
the proposed method cannot be considered ``fair and equitable,'' as 
required.\40\
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    \39\ These include: (1) MWh Delivered/Transfer of Energy-Page 
329, Column J; (2) MWh Delivered/Power Exchanges-Page 327, Column I; 
and (3) MWh Sold-Page 311, Column G. EEI points out that only a part 
of Column G on page 311 would pick up transmission, and would act as 
a ``catch all'' for what is not captured from the line items on 
pages 327 and 329.
    \40\ 42 U.S.C. 7178(b).
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    Some commenters argue that because the Commission regulates a 
certain sector of the industry, i.e., transmission, that does not 
necessarily imply that it is fair or equitable to burden only that 
sector with all costs associated with the Commission's regulatory 
activity. They assert that Commission's open access regulations also 
benefit generators and consumers. Avista argues that more costs of 
FERC's electric regulatory program are associated with transmission 
does not mean that all costs associated with all aspects of electric 
regulation should be recovered only from transmission providers. Avista 
argues that the Commission should ensure that filings by power 
marketers and generators carry an appropriate filing fee so that the 
majority of the cost of regulating those entities is paid for by those 
entities directly.\41\ NEP asserts that the Commission's principle of 
cost causation provides that entities whose actions give rise to costs 
should bear the responsibility for those costs. NEP asserts that when 
the party that causes costs to be incurred is no longer responsible for 
paying them, there is no incentive for that party to control or reduce 
those costs; there is no incentive for that party to act efficiently.
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    \41\ The issue of filing fees is not before the Commission. In 
fact, power marketers and generators seeking exempt wholesale 
generator status are assessed filing fees. 18 CFR 381.801.
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    A number of commenters state that they generally support the

[[Page 65761]]

Commission's approach, but assert that because the NOPR seeks to assess 
annual charge cost responsibility to unbundled retail transmission, but 
not bundled retail transmission, the NOPR methodology could be unfairly 
prejudicial to the public utilities that have unbundled their retail 
transmission service to date because it would force these utilities to 
absorb a disproportionately large percentage of the FERC's electric 
regulatory program costs. These commenters add that the proposed 
methodology may serve as a disincentive for additional utilities to 
unbundle their retail transmission services. Thus, they request that 
the Commission clearly define and provide the industry with clear 
criteria for what constitutes unbundled retail transmission services 
for the purposes of the annual charge calculation.
    EEI and ComEd, in this regard, recommend that the Commission 
clarify that ``unbundled retail transmission,'' as a category of 
transactions qualifying for annual assessment, does not include bundled 
retail transmission service in states that have adopted retail 
competition. EEI notes that some states have adopted retail competition 
but permit retail customers to elect to continue to receive bundled 
service.
    EPSA and APX urge the Commission to include bundled retail service 
in its measurement of annual charges, otherwise the NOPR will result in 
the Commission's costs being spread only to a small fraction of 
transmission service. EPSA argues that bundled retail customers, like 
wholesale customers, benefit from the Commission's regulation of open 
access transmission service.
    Cal ISO and FirstEnergy request that the Commission consider 
exempting unbundled retail transmission from the annual charge 
assessments, at least on an interim basis until a greater proportion of 
the country has undergone restructuring. The Midwest ISO states that it 
does not want to see assignment of cost responsibility to bundled 
retail customers in states that have not unbundled their retail 
customers through state customer choice legislation.
    SoCal Edison proposes that the unbundled transmission component of 
the annual charge assessment be phased-in over a five year period. 
NUSCO asserts that the Commission should recognize that industry 
restructuring is in different stages throughout the country, and argues 
that the Commission should provide for a gradual transition to the new 
methodology. Specifically, NUSCO argues that the Commission should 
consider adopting a five-year transition to account for transitioning 
retail markets.
    Avista argues that the Commission's proposal is likely to result in 
other forms of double counting.\42\ Avista asserts that a better method 
would be to assess the charge either at the point of generation or the 
point of consumption, and argues that a charge on generation would be 
administratively simpler.
---------------------------------------------------------------------------

    \42\ Avista gives three examples of how double counting may 
occur. First, the proposal appears vulnerable to double counting 
with respect to multiple transactions in the same unit of energy, 
where the transactions include a transmission component. This issue 
is resolved in our discussion of reassignment. See infra note 50. 
Second, the Commission identified the possibility that the same 
transaction could be attributed to both an RTO and a transmission-
owning member of the RTO. We address this argument below in our 
discussion of RTOs. Third, a transaction may call for energy to flow 
over the transmission lines of two or more transmitting utilities or 
entities, which could result in an assessment of a charge for each 
entity. We resolve this argument below by assessing annual charges 
based on transmission tariffs and rate schedules.
---------------------------------------------------------------------------

    FirstEnergy and NEP argue that the NOPR ignores the occurrence of 
cost shifting that results because annual charges will not be imposed 
on other sellers of power. FirstEnergy, APS and GPU Energy assert that 
cost shifting results in an additional burden in that it will be 
necessary for the utility to revise its OATT on an annual basis--which 
is overly burdensome for the public utility, interested parties and the 
regulatory review process. Member Systems argue that the Commission 
should allow jurisdictional public utilities to defer collection of any 
increased assessment until their next section 205 rate increase 
proceeding.
    Avista urges the Commission to consider whether a transmission-
owning utility should be assessed annual charges based on the 
transmission of power generated by a PMA to serve the PMA's load, 
asserting that a jurisdictional, transmission-owning public utility 
should not be required to pay annual charges that it cannot recover 
from its transmission customers or recover such charges from its native 
load customers. Avista also asserts that the presence of PMAs in some 
areas of the country raises the possibility that the proposal will have 
uneven regional impacts noting that PMAs do not operate in all regions 
of the country.
    APS and NEP argue that the Commission's contention that annual 
charges are ultimately charged to customers through transmission rates, 
albeit indirectly, is erroneous and flawed.\43\ NEM expresses 
reservations that the proposed methodology could increase costs to 
power marketers significantly and cautions the Commission on the 
potentially negative impact on power marketers of blending short- and 
long-term transactions and effectively increasing the assessments' 
impact on power marketers that primarily engage in short-term 
contracts. Thus, NEM requests that the Commission clarify that the 
proposed methodology is applicable only to transmission facility owners 
and that only such entities will receive annual bills. NEM asserts that 
the rulemaking needs to explicitly address the applicability of annual 
charges to other entities, such as power marketers. NEM expects that it 
is not the Commission's intention to treat power marketers that do not 
provide transmission services but engage in power sales, which include 
a transmission component, like public utilities that own transmission 
facilities. NEM also asserts that it is critical that the charge be on 
a per unit basis, not on a per transaction basis since power marketers 
will be impacted when the transmission owners pass along the assessment 
charges.
---------------------------------------------------------------------------

    \43\ APS and NEP cite two examples: (1) Where marketers and EWGs 
sell their power at the bus bar of a switchyard adjacent to a power 
plant where different utility systems are interconnected, and (2) 
where a marketer secures power that is wheeled over a non-
jurisdictional entity's system to a jointly owned switchyard where a 
number of different entities are interconnected.
---------------------------------------------------------------------------

    SDG&E argues that the proposed rule should clarify that the 
``transmission of electric energy'' for purposes of assessing annual 
charges should not include its retail load (SDG&E notes that it is 
obligated to bid all of its retail customers' demand into the 
California power exchange). SDG&E asserts that such an interpretation 
would result in its retail customers experiencing a substantial 
increase in the annual charge over that which they currently bear.
3. Commission Conclusion
    The Commission is persuaded that it should change the way in which 
it apportions annual charges among the entities it regulates, and as a 
consequence, it will adopt the approach proposed in the NOPR.
    As previously stated, at present, the Commission first determines 
the total costs of its electric regulatory program and subtracts all 
PMA-related costs and electric filing fee collections to determine the 
total collectible electric regulatory program costs. It then uses the 
data submitted under FERC-582 to determine the total volumes of long-
term firm sales and transmission, and short-term sales and transmission 
and exchanges for all assessable public

[[Page 65762]]

utilities.\44\ The Commission next divides into its collectible 
electric regulatory program costs those transaction volumes to 
determine the unit charge per megawatt-hour for each category of 
transactions. Finally, the Commission multiplies the transaction volume 
in each category for each public utility by the relevant unit charge 
per megawatt-hour to determine the annual charges for each assessable 
public utility.\45\ This methodology for assessing annual charges 
worked well given the industry structure that existed at the time it 
was adopted. However, because there have been such dramatic changes in 
the industry, and the Commission's regulation of the industry, this 
approach is no longer appropriate.
---------------------------------------------------------------------------

    \44\ Long-term firm sales and transmission activities, and 
short-term sales and transmission and exchange activities were 
defined in 18 CFR 382.102.
    \45\ The Commission also carries over any over- or under-charge 
from the prior year as a credit or debit on the current year's 
annual charge bill.
---------------------------------------------------------------------------

    With open-access transmission, functional unbundling and the rapid 
movement to market-based power sales rates brought about by, inter 
alia, Order No. 888,\46\ state retail unbundling efforts, and the 
recently issued Order No. 2000,\47\ the time and effort of our electric 
regulatory program is now increasingly devoted to assuring open and 
equal access to public utilities' transmission systems. Wholesale power 
sales rates are now increasingly being disciplined by competitive 
market forces and less by the Commission directly. As a consequence, we 
believe it appropriate to now assess our electric regulatory program 
costs solely on the MWh of electric energy transmitted in interstate 
commerce by public utilities providing transmission service,\48\ rather 
than, as in the past, on both jurisdictional power sales and 
transmission volumes.\49\
---------------------------------------------------------------------------

    \46\ See supra note 13.
    \47\ Regional Transmission Organizations, Order No. 2000, 65 FR 
810 (Jan. 6, 2000), FERC Stats. & Regs. para. 31,089 (1999), order 
on reh'g, Order No. 2000-A, 65 FR 12088 (Mar. 8, 2000), FERC Stats. 
& Regs. para. 31,092 (2000).
    \48\ This approach is essentially the same as how annual charges 
are, in practice, assessed against gas pipelines.
    \49\ The Commission believes that this approach of directly 
charging only those public utilities that provide transmission 
service is both fair and equitable. All parties involved in the 
generation and sale of electric energy rely on the transmission 
system to move their product. Thus, power sellers will be 
contributing to the Commission's recovery of its electric regulatory 
program costs in that they will be using the transmission system 
and, in any cost-based rates that they pay for transmission service 
that they may take, will pay, albeit indirectly, their share of the 
Commission's costs.
---------------------------------------------------------------------------

    As stated above, the Commission will now assess annual charges to 
all jurisdictional public utilities, as defined by the FPA, that 
provide transmission service. Such annual charges will be based on the 
MWh of unbundled transmission service (both wholesale \50\ as well as 
retail \51\) and on bundled wholesale power sales (which, by 
definition, include a transmission component, assuming that the public 
utility is not separately reporting the transmission component as 
unbundled transmission).\52\
---------------------------------------------------------------------------

    \50\ With respect to the issue of reassignment of transmission 
service, we would anticipate that the original provider of the 
service would report the MWh of transmission service and would 
therefore be assessed the annual charges associated with that 
transmission. This approach is, we believe, the only workable 
approach.
    \51\ See supra note 13, Order No. 888, FERC Stats. & Regs. para. 
31,036, at 31,780-85, Order No. 888-A, FERC Stats. & Regs. para. 
31,043 at 30,334-46; TAPSG, slip op. at 24-35.
    \52\ Annual charges will be assessed based on all transmission 
by public utilities, with no distinction made between so-called 
unbundled retail and unbundled wholesale transmission. See New York 
State Electric & Gas Corp., 77 FERC para. 61,044 (1996), reh'g 
denied, 83 FERC para. 61,203 (1998); New England Power Co., et al., 
75 FERC para. 61,207 (1996), 76 FERC para. 61,008 (1996), reh'g 
denied, 85 FERC para. 61,181 (1998); supra note 13, Order No. 888-A 
at 30,214-16. This transmission would include all unbundled retail 
transmission in states with retail choice, even when the retail 
customer purchases retail power service from its original power 
supplier. This transmission would also include MWh delivered in 
wheeling transactions and the MWh delivered in exchange 
transactions.
    If the bundled wholesale power sale involves the use of non-
affiliated, third-party transmission systems, any transmission by 
such systems would be picked up through the non-affiliated, third-
party transmission providers' reporting of the MWhs of transmission 
service they provided. If the bundled wholesale power sale involves 
the use of the power seller's or its affiliate's transmission 
system, the transmission component might conceivably be separately 
reported as unbundled transmission. If, however, this is not the 
case, the MWhs would need to be reported as a bundled wholesale 
power sale.
    The annual charge will be on a per unit basis, MWh, and not on a 
per transaction basis.
---------------------------------------------------------------------------

    We believe that public utilities know the MWh of transmission they 
are providing (and that need to be reported on their FERC-582), as they 
do so pursuant to tariffs and rate schedules on file at the Commission 
and they bill their customers under these tariffs and rate schedules 
accordingly.\53\ Nevertheless, to aid them in completing their FERC-
582s, we will identify specific pages and columns where data may be 
found that, for the purposes of annual charge calculations, corresponds 
to the transmission services identified in the above narrative 
description. The classifications of transactions can be obtained from 
the FERC Annual Report Form No. 1. They include:
---------------------------------------------------------------------------

    \53\ Insofar as utilities currently bill for the transmission 
services they provide, these utilities would know how much 
transmission they are providing and should have little difficulty 
reporting transmission volumes to the Commission.
    We recognize that in some instances public utilities may arrange 
for agents to act on their behalf in, for example, scheduling 
transmission service or billing for transmission service. We would 
anticipate that the public utility itself, rather than the agent, 
would report the transaction and therefore be responsible for the 
annual charge assessment. This would be due to the fact that it is 
the public utility itself that is providing the transmission 
service, and has the transmission tariff and rate schedules on file 
with the Commission.
---------------------------------------------------------------------------

    (1) Transmission of Electricity for Others, Transfer of Energy, MWh 
Delivered (Form No. 1, Pg. 328-329, Col. (j)); \54\
---------------------------------------------------------------------------

    \54\ These data include all transmission of power for other 
entities.
---------------------------------------------------------------------------

    (2) Purchased Power, Power Exchanges, MWh Delivered (Form No. 1, 
Pg. 326-327, Col. (i)); \55\ and
---------------------------------------------------------------------------

    \55\ :These data include power delivered by the utility to 
others in power exchange transactions.
---------------------------------------------------------------------------

    (3) Sales for Resale, MWh Sold (Form No. 1, Pg. 310-311, Col. 
(g)).\56\
---------------------------------------------------------------------------

    \56\ These data include all sales for resale. The data reported 
on pages 310-311 and the data reported on pages 328-329 may double 
count MWh since these MWh might be reported first as sales for 
resale and secondly as energy transmission transactions. This double 
counting can be overcome by adjusting the volumes on either pages 
310-311 or pages 328-329. See supra note 52 and accompanying text.
---------------------------------------------------------------------------

    For those public utilities, if any, that do not file a Form 1, our 
narrative description of how, and on what, the annual charges are to be 
assessed is sufficiently clear to allow them to complete their FERC-
582s on a a timely basis.
    The Commission also believes that the new assessment methodology is 
``fair and equitable,'' as required by the Budget Act. The Commission 
believes that it is appropriate that annual charge assessments be 
exclusively based on transmission volumes as regulation of transmission 
is increasingly the work the Commission is doing and will be doing in 
the future. This trend, moreover, will only accelerate as the industry 
moves forward with the formation of RTOs. Given that the annual charge 
assessment methodology being adopted here will first be effective for 
annual charge bills to be paid in calendar year 2002, we believe it 
appropriate to recover our costs based solely on transmission and 
solely from transmission providers. In addition, as noted above, the 
Commission believes that power sellers will continue to contribute to 
the Commission's recovery of its electric regulatory program costs, 
albeit indirectly, through the cost-based transmission rates (and 
annual charges are, we find, a legitimate cost of providing 
transmission service) they pay for the transmission service they may 
take.\57\
---------------------------------------------------------------------------

    \57\ The Commission notes that public utilities will only need 
to file FERC-582 and pay annual charges if they provide transmission 
of electric energy in interstate commerce. In other words, if, for 
example, power marketers are not providing transmission service, 
they will not need to file FERC-582 or pay annual charges.

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

[[Page 65763]]

    The new methodology adopted here addresses concerns over potential 
``double-counting.'' Because only the entity that is providing the 
transmission service pursuant to its transmission tariff or rate 
schedule would report the transmission volumes and accordingly be 
assessed an annual charge, the risk of charging more than one entity 
for the same transmission volume disappears. This eliminates the 
concern that if a transaction, in fact, involves energy flowing over 
the transmission lines of two or more transmitting entities (even 
though the contract that calls for the transmission service calls for 
that service to be provided by only one entity) both entities could be 
assessed an annual charge for the same transmission volumes.
    A number of commenters assert that the Commission needs to clarify 
that ``unbundled retail transmission'' does not include bundled retail 
service, while EPSA and APX urge the Commission to include bundled 
retail service in its calculation of annual charges. In Order No. 888, 
the Commission held that bundled retail service is not subject to 
Commission regulation.\58\ With this Final Rule we continue the 
approach taken in Order No. 888 and, in the absence of transmission in 
an ISO or RTO context (which we discuss below, see infra note 68) we 
will not include bundled retail service in the annual charges 
calculation.
---------------------------------------------------------------------------

    \58\ E.g., supra note 13, Order No. 888-A, FERC Stats. & Regs. 
para. 31,048 at 30,217.
---------------------------------------------------------------------------

    A few commenters argue that the Commission should consider 
exempting unbundled retail transmission from the annual charge 
assessments, at least on an interim basis until a greater proportion of 
the country has undergone restructuring. These commenters assert that 
the NOPR methodology could be unfairly prejudicial to public utilities 
that have unbundled their retail transmission service to date. The 
Commission notes, however, that more than half of the states are 
already moving, or have moved to, unbundle transmission.\59\ SoCal 
Edison comments that the proposed methodology may serve as a 
disincentive for individual utilities to unbundle their retail 
services. The Commission recognizes that this may increase costs to 
some public utilities, but nonetheless, the new methodology should not 
act as a disincentive because of the small magnitude of these costs 
\60\ as compared to the revenues currently being collected for 
unbundled retail transmission itself.\61\ The amount of money covered 
by this rule, the cost of the Commission's electric regulatory program 
minus PMA costs and filing fee collections, is also not a large sum 
\62\ in comparison to the revenues being collected for other, wholesale 
transmission services,\63\ and it also will be spread across all public 
utilities providing transmission service, thus resulting in only a 
small addition to transmission rates (with, unlike as in the past, no 
addition to power sales rates). In addition, in the past the regulation 
of transmission associated with retail power sales was done by the 
states, and any costs associated with that regulation would have been 
incurred by state regulatory commissions and would have been subject to 
whatever regulatory assessments were imposed by those commissions.\64\ 
Now, with the regulation of transmission associated with unbundled 
retail power sales being done by this Commission, the costs associated 
with this regulation are incurred by this Commission and are 
appropriately reflected in our annual charge assessments. In short, 
what is occurring is more a shifting of costs and assessments, rather 
than an absolute increase.
---------------------------------------------------------------------------

    \59\ For more specific information on the status of state 
electric industry restructuring activity see, e.g., http://www.eia.doe.gov/cneaf/electricity/chg_str/regmap.html> (August 
2000).
    \60\ The Commission's total collectible electric regulatory 
program costs collected in annual charges in 1999 (based on data 
reported for calendar year 1998) were $54,596,000.
    \61\ The data reported to us on Form No. 1 do not allow us to 
estimate what percentage of total retail revenues reflect 
transmission-related costs. However, the Energy Information 
Administration of the Department of Energy estimates that 
transmission accounts for 7 percent of the total cost of delivered 
power. See Electricity Prices in a Competitive Environment: Marginal 
Cost Pricing of Generation Services and Financial Status of Electric 
Utilities, A Preliminary Analysis Through 2015, ``Pricing 
Electricity in a Competitive Market,'' EIA/DOE-0614, p. 11 (August 
1997). Thus, the transmission-related revenues would be 
substantially higher than our total collectible electric regulatory 
program costs.
    \62\ See supra note 60.
    \63\ Based on a review of Form No. 1 data for 1998, the total 
revenues collected just for ``transmission for others'' were 
approximately 2 billion dollars. Based on a review of the same data, 
the total revenues collected for ``sales for resale'' (which would 
include a transmission component) were in excess of 29 billion 
dollars.
    \64\ Based on a review of Form No. 1 data for 1999, it appears 
that 36 of the lower 48 states, or \3/4\ of the lower 48 states, 
collect such regulatory assessments.
---------------------------------------------------------------------------

    Some commenters argue that the NOPR ignores the occurrence of cost 
shifting that results because annual charges are imposed solely on 
public utilities providing transmission service and not on other 
sellers of power. In response, the Commission notes that the current 
system for assessing annual charges places a heavy emphasis on power 
sales--reflecting the Commission's traditional focus. As stated 
earlier, the Commission has been reducing its regulation of the power 
sale business and that trend is continuing and even accelerating. We 
thus believe that it is appropriate that the annual charges be borne by 
the entities and services on which we are now increasingly focusing.
    FirstEnergy and NEP argue that cost shifting will result in public 
utilities having to revise their OATTs on an annual basis. The 
Commission notes that public utilities make amendments to their OATTs 
routinely and many public utilities typically made rate change filings 
in the past. Thus, the Commission does not see the Final Rule as 
imposing any new burden on public utilities. Member Systems argue that 
the Commission should allow jurisdictional utilities to defer 
collection of any increased assessment until their next section 205 
rate increase proceeding. The Commission does not agree with the 
commenters that such deferment is necessary. The Commission believes 
that the effective date for this Final Rule, as discussed below, 
provides sufficient notice for utilities to put rates into place for 
the utilities to be able to collect sufficient monies to pay their 
annual charge bills in 2002. In fact, some utilities' rates may already 
be recovering sufficient funds to meet their new annual charge 
obligations.
    SoCal Edison proposes that the unbundled transmission component of 
the annual charge assessment be phased-in over a five year period while 
NUSCO seeks a similar phase-in. In response, the Commission believes 
that a phase-in approach is unnecessary. The Commission believes that 
the new approach reflects the new realities of the industry and of 
Commission regulation, is straightforward and easy to apply, and gives 
public utilities enough time to prepare for the bills that will be paid 
in 2002.
    SDG&E argues that the rule should clarify that the ``transmission 
of electric energy'' for purposes of assessing annual charges should 
not include its retail load (SDG&E notes that it is obligated to bid 
all of its retail customers' demand into the California power 
exchange). The Commission does not believe that rates will rise 
dramatically, because, as discussed above, the collectible costs of the 
Commission's electric regulatory program are not a large sum of money, 
and will be spread out over a large

[[Page 65764]]

number of MWhs (all of the MWhs of all transmission providers). In 
addition, in the past the regulation of transmission associated with 
retail power sales was done by the states, and any costs associated 
with that regulation would have been incurred by state regulatory 
commissions and would have been subject to whatever regulatory 
assessments were imposed by those commissions.\65\ Now, with the 
regulation of transmission associated with unbundled retail power sales 
being done by this Commission, the costs associated with this 
regulation are incurred by this Commission and are appropriately 
reflected in our annual charge assessments. In short, what is occurring 
is more a shifting of costs and assessments, rather than an absolute 
increase.
---------------------------------------------------------------------------

    \65\ Based on a review of Form No. 1 data for 1999, it appears 
that 36 of the lower 48 states, or \3/4\ of the lower 48 states, 
collect such regulatory assessments.
---------------------------------------------------------------------------

    Based on the foregoing discussion, commencing with the annual 
charges billed and paid in calendar year 2002, based on data reported 
for calendar year 2001, the Commission will now assess annual charges 
to public utilities that provide transmission service based on their 
transmission of electric energy in interstate commerce, as measured by: 
(1) Unbundled wholesale transmission, (2) unbundled retail 
transmission, and (3) bundled wholesale power sales which, by 
definition, include a transmission component, where the transmission 
component is not separately reported as unbundled transmission.\66\
---------------------------------------------------------------------------

    \66\ See supra note 52.
---------------------------------------------------------------------------

4. Independent System Operators and Regional Transmission Organizations
    a. Proposed New Methodology. As to ISOs and potential RTOs that 
have members that retain ownership of transmission facilities, the 
Commission stated in the NOPR that it was concerned that the assessment 
of annual charges could result in a ``double counting'' of 
transactions--by counting a single transaction both to the 
transmission-owning public utility and to the ISO or RTO public 
utility. The NOPR suggested that there were at least two ways to 
address this issue, and invited comments on these and any other 
solutions to this problem. One proposed method was not to charge the 
ISO or RTO itself, but instead charge each transmission-owning public 
utility based on the MWh of transmission service provided on their 
lines. The transmission-owning public utility would include the annual 
charges, as a cost element, in its revenue requirement, which, in turn, 
is recovered by the ISO or RTO through the ISO's or RTO's open access 
transmission tariff rates. The other proposed method was to allow the 
ISO or RTO to act as an agent for all of the individual transmission 
owners and have the ISO or RTO pay the annual charges rather than the 
individual transmission owners. The Commission stated that either of 
these approaches may be acceptable and solicited comments on the two 
approaches, as well as comments on any other approach that would allow 
the Commission to collect annual charges on these MWh of transmission 
service, in the most administratively efficient manner.
    b. Comments. The Commission received a number of comments on this 
issue. Williams EM&T states that although it has no specific suggestion 
regarding which approach would be preferable, it urges the Commission 
to defer to the comments of the ISOs, RTOs, and transmission-owning 
entities. TXU Electric believes that either approach would be 
acceptable, as long as there are adequate measures in place to ensure 
that there would be no double counting of transactions between the 
individual utility and the ISO/RTO.
    The commenters are generally split, with many on each side. A 
number of commenters believe that the most equitable method to assess 
the annual charge is directly to the ISO or RTO, because they are the 
transmission providers in their respective territories. Consumers 
supports assessing annual charges to the RTOs, where there is an RTO in 
place. FirstEnergy states that the only situation where transmission 
owners should be charged annual charges and allowed to collect the 
corresponding revenue requirements is where the Commission has not 
approved an RTO. EEI adds that because the RTO would actually be 
collecting annual charge costs from transmission customers, through the 
transmission rates, it makes sense to have the RTOs make the annual 
charge payments to the Commission. GPU Energy asserts that this will 
allow the Commission to collect annual charges in the most 
administratively efficient manner.
    SoCal Edison states that, specifically in the California market, 
the individual transmission owners are no longer the transmission 
providers and do not have access to information about the transmitted 
MWh associated with wheeling and existing transmission contracts 
because such transactions are, for the most part, scheduled directly 
with the ISO, and only the ISO obtains this data. Therefore, SoCal 
Edison argues that, as a matter of common sense, the ISOs and RTOs 
should file the Form 582 and be billed for annual charges. GPU Energy 
adds that an agency structure much like that proposed in the NOPR is 
already in place in PJM and that the Commission should not make any 
findings in the Final Rule that could undo this agreement.
    SoCal Edison asserts that there are other advantages to making the 
ISOs and RTOs the parties responsible for complying with the 
Commission's annual charge reporting and payment requirements. First, 
because the ISOs and RTOs are also public utilities, this approach is 
consistent with the Commission's desire to impose the initial 
responsibility for annual charges on public utilities. Second, the 
various ISOs and RTOs are in the best position to pass on annual charge 
expenses to transmission users. Third, consistent with the Commission's 
directive that ``all parties involved in the generation and sale of 
electric energy'' should ultimately bear the cost of annual charges, 
the ISOs and RTOs will be able to assure that annual charges become the 
responsibility of transmission consumers by directly billing scheduling 
coordinators for their proportionate share of the annual charge 
assessment under the ISOs' and RTOs' respective transmission tariffs.
    Avista states that it is impossible to determine exactly how the 
Commission's proposal would work in an RTO environment, because the RTO 
environment has yet to exist in most areas and is only newly formed in 
others. Avista argues that it is fundamentally premature to impose a 
rulemaking that depends so heavily on RTO formation and the Commission 
should defer action on the annual charge proposal until more is known 
about how RTOs will work.
    Several commenters state that the NOPR would place a hurdle in the 
path of RTO formation. APX Companies state that by exempting MWh of 
transmission usage that is bundled with retail sales from the 
allocation of the annual charge, the NOPR tells transmission owning 
utilities that they can still benefit from uniform rules and practices 
that the Commission adopts in its electric regulatory program, but 
escape financial responsibility for that program. Member Systems assert 
that the proposed allocation between utilities that have or have not 
joined ISOs/RTOs would be unfair and inequitable because a much larger 
percentage of the Commission's costs would be assessed to utilities 
that have joined ISOs/RTOs. Member Systems thus submit that the 
Commission should solicit additional

[[Page 65765]]

comments to address this problem. SPP requests that the Commission 
detail the mechanics as to how the assessments against transmission 
owners will be determined when an RTO is providing the service over 
their facilities as part of a regional tariff arguing that most 
transactions will involve the use of facilities from multiple 
transmission owners and the RTO will not be able to easily identify a 
particular transmission owner whose facilities were used for a specific 
transmission transaction.
    FirstEnergy adds that to eliminate the potential conflict between 
Order No. 2000 and the NOPR, and to maintain RTO open architecture, the 
Commission should give RTOs the flexibility to propose to the 
Commission other methods for assessing annual charges on a case-by-case 
basis.
    PECO asserts that the regulatory text should be revised to make it 
clear that the ISO or RTO should pay the resulting assessments and that 
the ISO or RTO should collect the funds to make those payments from its 
customers under the tariff.
    A number of commenters, on the other hand, believe that 
transmission owners should be assessed annual charges for transactions 
over their facilities. Cal ISO argues that this approach is fair and 
equitable because the transmission owners that own the transmission 
facilities operated by an ISO are traditionally the entities that have 
been assessed annual charges for transmission transactions occurring on 
those facilities, and they have mechanisms in place for accounting for 
annual charge costs and for passing through the costs to the 
appropriate parties. Cal ISO adds that this approach would also avoid 
the need, when new ISOs and RTOs are formed, to develop mechanisms to 
transfer the responsibility of payment of FERC annual charges to the 
new organization, and for that organization to recover those costs. Cal 
ISO states that while procedures and mechanisms for paying annual 
charges (and for their recovery in rates) could certainly be developed, 
it would be simpler to allow transmission owners to utilize the pass-
through mechanisms that are already in place.
    Cal ISO and the Midwest ISO state that, insofar as ISOs or RTOs 
will not own the transmission systems that are the focus of the 
Commission's revised annual charge methodology, it seems more 
appropriate to assess the annual charges against the transmission 
owners themselves. The Midwest ISO adds that shifting the cost 
responsibility to the ISO under the guise of the ISO acting as agent is 
inappropriate because the ISO does not in essence ``make sales for 
resale or transmit electric energy in interstate commerce'' using its 
own transmission assets.
    Several commenters state that an ISO/RTO will have no shareholders 
that can absorb revenue shortfalls that arise, either due to the 
inability to collect fees from all loads or the refusal of some members 
to remit what is owed. These commenters point out that an ISO/RTO has 
limited enforcement powers to compel its members to remit FERC fees.
    Cal ISO raises other concerns that would complicate the efforts 
ISOs or RTOs would need to undertake if they were assessed annual 
charges. In Order No. 2000, the Commission expressed a preference that 
RTOs include transmission systems owned by municipalities and other 
utilities that are not ``public utilities'' under the FPA. Under the 
NOPR, such entities are not subject to FERC annual charges, therefore, 
the ISO or RTO would be required to take steps to distinguish the MWh 
transmitted over purely non-jurisdictional transmission systems for 
purposes of reporting transactions subject to FERC annual charges. LIPA 
and NYPA assert that the Commission should find that annual charges 
should not be assessed with respect to transactions involving loads 
interconnected to non-public utility transmission facilities.
    SPP requests that the Commission clarify the treatment of non-FERC 
regulated transmission owners who have committed their facilities to 
RTOs, such as municipals and cooperative utility systems.
    Under either approach proposed by the Commission, PJM asserts that 
the Commission should clarify the rule to provide that the ISO/RTO is 
not subject to annual charges as a public utility. When acting as an 
agent for the transmission-owning public utilities, the annual charges 
still should be treated as a cost of the transmission-owning public 
utilities and should be collected on their behalf from ISO/RTO 
customers (and paid to the Commission) in a manner similar to the 
collection of the transmission-owning utilities' revenue requirements.
    The Midwest ISO offers a third alternative: The ISO/RTO would 
provide an accounting of transactions within its region, which would 
eliminate ``double counting,'' but actual billings and collections 
would be between the Commission and the transmission-owning public 
utilities. That is, the ISO/RTO would provide the data (act as an 
``information clearinghouse'') but that the obligation to pay annual 
charges would remain with the individual public utilities.
    One commenter suggests that annual charges be assessed to both an 
ISO or RTO and the individual transmission owner. APS believes that any 
resulting double counting of transactions should not be a consideration 
if both entities each contribute to the Commission's electric 
regulatory program costs. APS asserts that a multitude of ISO and RTO 
issues occupy the Commission's resources and attention and contribute 
to the Commission's electric regulatory program costs and those costs 
should be recovered from those entities.
    c. Commission Conclusion. After giving consideration to all of the 
comments received on this issue, the Commission finds that the best 
approach is to assess the costs of the Commission's electric regulatory 
program to each public utility \67\ that provides transmission service. 
In other words, whoever is providing the transmission service (i.e., 
has a tariff or rate schedule on file with the Commission to provide 
transmission service and thus would have rates on file for that 
transmission service) is the appropriate entity to be assessed annual 
charges. If an ISO or RTO public utility has taken over from individual 
public utilities the function of providing transmission service and 
has, accordingly, a tariff or rate schedule (and thus rates) on file 
for such service,\68\ then it is the ISO or RTO public utility that 
will be responsible for paying annual charges, and it will be assessed 
annual charges based on all transmission that it provides pursuant to 
its tariff or rate schedule.\69\ If an individual public utility 
continues to provide transmission service, however, and still has, 
accordingly, a tariff or rate schedule (and thus rates) on file for 
such service, then that individual public utility will continue to be 
responsible for paying annual charges. In those cases where, for a 
particular transmission transaction, transmission service is being 
provided both by an ISO or RTO public utility and by an individual 
public utility, then both the ISO or RTO public utility and the 
individual public utility will be

[[Page 65766]]

assessed annual charges based on the respective services provided.\70\
---------------------------------------------------------------------------

    \67\ 18 CFR 382.102(b); see 16 U.S.C. 824(e).
    \68\ It is our expectation that all individual public utilities 
(and others, as well) will join RTOs and therefore there should be 
no unfairness as between some individual public utilities and others 
in terms of assessment of annual charges.
    \69\ We do not intend to parse an ISO's or RTO's transmission 
based on whether the facilities that it is providing service over 
were previously non-jurisdictional. The ISO or RTO public utility is 
a public utility and is providing jurisdictional transmission 
service pursuant to tariffs or rate schedules on file with (and 
regulated by) the Commission. Thus, it is appropriate that annual 
charges be assessed based on the transmission that the ISO or RTO 
public utility provides.
    \70\ Likewise, if two or more different public utilities such as 
two or more RTO public utilities or two or more individual public 
utilities transmit electric energy sequentially one after the other 
(as in, for example, the case of electric energy being transmitted 
over comparatively long distances, and thus by multiple public 
utilities over their respective transmission systems one after the 
other), they will each be assessed an annual charge based on their 
respective transmission of such electric energy.
    For example, if the power seller must move power through two 
different RTOs to reach the power buyer, then each RTO would be 
assessed annual charges based on its respective transmission of that 
power. Likewise, in another example, if the power seller must move 
its power through two different individual public utilities that are 
not members of an RTO, then each public utility would be assessed 
annual charges based on its respective transmission of that power. 
In yet another example, if the power seller must move its power 
through an individual public utility that is not a member of an RTO, 
and through an RTO, then, again, the individual public utility and 
the RTO would each be assessed annual charges based on their 
respective transmission volumes.
    Finally, of course, if an RTO was providing transmission service 
pursuant to its tariff wholly within the RTO, then only that RTO 
would be assessed annual charges for that transmission (even if the 
transmission nominally involved the use of the transmission 
facilities of two or more members of the RTO).
---------------------------------------------------------------------------

    As discussed previously, the transmission on which annual charges 
are assessed includes unbundled retail transmission. In the ISO or RTO 
context, however, where regional transmission services are provided 
over the system of more than one public utility, all retail 
transactions involve an unbundled retail transmission component. For 
example, when PEPCO takes service under the PJM tariff to serve its 
native load, it makes use of the entire PJM system and, as such, 
obtains unbundled retail transmission service from other transmission-
providing members of PJM. Those transmission volumes, essentially the 
entire intra-ISO or RTO load, will need to be reported to the 
Commission in FERC-582 (along with the other transmission provided by 
the ISO or RTO, i.e., essentially so-called through or export 
transactions) and annual charges will be assessed accordingly.
    As discussed earlier, Avista argues that it is premature to adopt a 
requirement that, it claims, depends so heavily on RTO formation and 
requests that the Commission defer action on the annual charge proposal 
until more is known about how the RTOs will work. The Commission 
believes that it is appropriate to proceed with this Final Rule at this 
time for the reasons given earlier, and here we are only creating the 
mechanism by which annual charges will be assessed (and not how these 
charges are, in turn, to be recovered by the public utilities in their 
rates). The Commission believes that there are benefits that can come 
from the participants in the RTO development process knowing earlier 
rather than later as to how the Commission intends on assessing annual 
charges. We believe that proceeding with the Final Rule at this time 
will aid those who are currently in the process of developing RTOs.
    FirstEnergy states that to eliminate the potential conflict between 
Order No. 2000 and the NOPR, and to maintain RTO open architecture, the 
Commission should give the RTO flexibility to propose to the Commission 
other methods for assessing annual charges on a case-by-case basis. On 
this issue, the Commission believes that this Final Rule does not 
detract from the RTO participants' flexibility to decide how to 
structure the new entity. Rather, it simply identifies who will be 
assessed annual charges (and how those charges will be calculated). The 
Commission believes that this new approach to annual charges will avoid 
the occurrence of double counting, which should, in fact, aid the 
development of RTOs.
    Finally, the Commission believes that this approach is both fair 
and equitable, as required by the Budget Act, as it places the 
requirement to pay annual charges on the particular entities that will 
be providing the transmission services on which the annual charges will 
be assessed.

C. Other Matters

1. Rate Recovery
    A number of commenters raise concern about their ability to recover 
their annual charges in their rates. Some commenters request that the 
Commission expressly provide that public utilities can fully recover 
the annual charge assessments from their customers through surcharges 
to the transmission rates and pass through or balancing account 
mechanisms. Avista requests that the Commission specify precisely how 
and under what circumstances annual charges may be passed through to 
transmission owners.
    EEI recommends that the Commission adopt an Annual Charge 
Adjustment (ACA) surcharge, together with a ``limited Section 205'' 
rate filing. SoCal Edison requests, that in its case, the Commission 
declare that the annual charge assessment can be included as a 
component of the Transmission Revenue Balancing Account Adjustment 
(TRBAA). APS proposes that a jurisdictional public utility would file 
annually, by a specific date, an Annual Surcharge Factor reflecting the 
adjusted annual charge assessed to the utility, divided by the MWH 
included in Form 582 used to develop the assessed annual charge. 
Several commenters raise similar concerns regarding cost recovery if an 
ISO or RTO is the entity assessed annual charges.
    We note at the outset that the purpose of this Final Rule is to 
change the methodology for the assessment of annual charges to public 
utilities. The issue of rate recovery of annual charges is not within 
the scope of this Final Rule. The Commission has other regulations 
already in place that address the recovery of costs in rates, i.e., 
Part 35, which governs rate change filings.\71\ Public utilities thus 
are not without mechanisms whereby they can come to the Commission for 
a change in their rates.
---------------------------------------------------------------------------

    \71\ 18 CFR Part 35; see 16 U.S.C. 824d (allowing utilities to 
seek to change their rates).
---------------------------------------------------------------------------

    However, to allay the concerns of public utilities as to rate 
recovery, we will state here that we find that the annual charge 
assessments are costs that can be recovered in transmission rates as a 
legitimate cost of providing transmission service. We will otherwise 
leave this issue to be resolved in future rate change filings, as they 
may come before the Commission from time to time on a case-by-case 
basis; different public utilities may require different rate revisions 
to address this matter.
2. Reporting Requirements
    The Commission is changing its reporting requirements for annual 
charges. Currently, a public utility has to submit the total long-term 
firm sales for resale and transmission megawatt-hours and the total 
short-term sales, transmission, and exchange megawatt-hours. With the 
elimination of the distinction between long-term and short-term 
transactions, such distinctions in the reporting requirements are 
likewise no longer needed. Similarly, with changing the focus from 
power to transmission, only those public utilities that provide 
transmission service will need to comply with the Commission's 
reporting requirement.
    The Commission thus will now require that public utilities that 
provide transmission service must report total volumes of electric 
energy transmitted in interstate commerce (as defined above, to include 
all unbundled transmission and all bundled wholesale power sales), in 
MWh, by April 30th of each year.\72\
---------------------------------------------------------------------------

    \72\ Williams EM&T commented that it believed that as a public 
utility under the FPA, it would still be required to file a FERC-
582, although such report will contain no transmission information 
and Williams EM&T will be assessed no annual charge. Williams EM&T 
is mistaken. As noted above, only those public utilities that 
provide transmission service will need to report volumes of electric 
energy transmitted in interstate commerce. If Williams EM&T does not 
provide such service, it will not be required to file FERC-582.

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

[[Page 65767]]

    Finally, as we proposed in the NOPR, any corrections to FERC-582 
will need to be made by the end of the calendar year in which the FERC-
582 was filed.
3. Standards for Waiving All or Part of an Annual Charge
    The Commission did not propose to change and is not changing the 
standards applicable for waiving all or part of an annual charge. Thus, 
the Commission will continue to apply to annual charges the stringent 
standards for waiver currently applicable to filing fees, with a filing 
period for waiver petitions of 15 days after the issuance of the annual 
charges bill.

IV. Environmental Statement

    The Commission excludes certain actions not having a significant 
effect on the human environment from the requirement to prepare an 
environmental assessment or an environmental impact statement.\73\ The 
promulgation of a rule that is procedural or that does not 
substantially change the effect of legislation or regulations amended 
raises no environmental considerations.\74\ This Final Rule amends Part 
382 of the Commission's regulations to establish a new methodology for 
the assessment of annual charges to public utilities and does not 
substantially change the effect of the underlying legislation or the 
regulations being revised. Accordingly, no environmental consideration 
is necessary.
---------------------------------------------------------------------------

    \73\ 18 CFR 380.4.
    \74\ 18 CFR 380.4(a)(2)(ii).
---------------------------------------------------------------------------

V. Regulatory Flexibility Act Certification

    The Regulatory Flexibility Act (RFA), 5 U.S.C. 601-612, requires 
rulemakings to contain either a description and analysis of the effect 
that the proposed rule will have on small entities or a certification 
that the rule will not have a significant economic impact on a 
substantial number of small entities.
    In Mid-Tex Elec. Coop. v. FERC, 773 F.2d 327 (D.C. Cir. 1985), the 
court found that Congress, in passing the RFA, intended agencies to 
limit their consideration ``to small entities that would be directly 
regulated'' by proposed rules. Id. at 342. The court further concluded 
that ``the relevant ``economic impact'' was the impact of compliance 
with the proposed rule on regulated small entities.'' Id. at 342.
    The Commission does not believe that this Final Rule will have a 
significant direct impact on small entities. Most, if not all, public 
utilities that would be assessed annual charges under this Final Rule 
do not fall within the RFA's definition of a small entity because most 
public utilities subject to this Final Rule are too large to be 
considered ``small entities.'' \75\ Therefore, the Commission certifies 
that this Final Rule will not have a ``significant economic impact on a 
substantial number of small entities.''
---------------------------------------------------------------------------

    \75\ 5 U.S.C. 601(6).
---------------------------------------------------------------------------

VI. Public Reporting Burden and Information Collection Statement

    The OMB regulations require OMB to approve certain reporting and 
recordkeeping (collections of information) requirements imposed by 
agency rule.\76\ The NOPR was submitted to OMB at the time of issuance. 
OMB did not comment on nor did it take any action on the proposed rule.
---------------------------------------------------------------------------

    \76\ 5 CFR 1320.11; see 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    No comments from the public on the burden estimate were received. 
The filing requirements remain essentially the same as those in the 
NOPR so, therefore, the estimated annual filing burden remains the 
same. The burden estimate for complying with this final rule is as 
follows:
    Public Reporting Burden: Estimated Annual Burden:

----------------------------------------------------------------------------------------------------------------
                                                                                                        Total
                       Data collection                         Number of    Number of    Hours per      annual
                                                              respondents   responses     response      hours
----------------------------------------------------------------------------------------------------------------
FERC-582....................................................          242            1            4          968
----------------------------------------------------------------------------------------------------------------

Total Annual Hours for Collection (reporting + recordkeeping, (if 
appropriate)) = 968
    Information Collection Costs: The Commission sought comments on the 
costs to comply with these requirements, and no comments were received. 
The Commission projected the average annualized cost for all 
respondents to be:
     Annualized Capital/Startup Costs ($0) + Annualized 
Operations & Maintenance Costs ($53,687).
     (968 hours  2080 hours per year)  x  $115,357 = 
$53,687.
     The cost per respondent is equal to $222 ($53,687  
242 = $222).
    The OMB regulations require OMB to approve certain information 
collection requirements imposed by agency rule.\77\ Accordingly, the 
Commission provided notice of its proposed information collection to 
OMB. Again, the Commission received no comments from OMB.
---------------------------------------------------------------------------

    \77\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    Title: FERC-582, Electric Fees and Annual Charges.
    Action: Proposed Data Collection.
    OMB Control No.: 1902-0132.
    The applicant shall not be penalized for failure to respond to this 
collection of information unless the collection of information displays 
a valid OMB control number.
    Respondents: Business or other for profit, including small 
businesses.
    Frequency of Responses: Annually.
    Necessity of Information: The Final Rule revises the requirements 
contained in 18 CFR Part 382 to revise the method for determining the 
assessment of annual charges. The Commission is making its assessment 
for annual charges more compatible with the current industry and 
regulatory environment, including and the creation of competitive bulk 
power markets.
    The Commission has the authority under the Omnibus Budget 
Reconciliation Act of 1986 (42 U.S.C. 7178) to ``assess and collect 
fees and annual charges in any fiscal year in amounts equal to all of 
the costs incurred * * * in that fiscal year.'' The Act gives the 
Commission the flexibility to arrive at a reasonable approximation of 
its program costs. The costs are determined by a summation of all 
electric regulatory program costs and then subtracting PMA-related 
costs and electric regulatory program filing fee collections in order 
to determine the total collectible costs for the electric regulatory 
program.
    Information submitted under FERC-582 is the basis for the 
calculation of annual charges, and presently includes total volumes of 
long-term firm sales and transmission and short-term sales and 
transmission plus exchanges for all

[[Page 65768]]

public utilities, including power marketers. The Final Rule changes the 
basis for the calculation of annual charges to the total volumes of 
electricity transmitted by public utilities that provide transmission 
service.
    Internal Review: The Commission has assured itself, by means of 
internal review, that there is specific, objective support for the 
burden estimates associated with the information requirements. The 
Commission's Office of the Executive Director will use the data 
submitted under FERC-582 in order to serve as a billing determinant to 
recover costs for administering its electric regulatory program, 
including administering the provisions of Parts II and III of the 
Federal Power Act and the provisions of the Public Utility Regulatory 
Policies Act of 1987.
    The Commission received approximately 35 comments and reply 
comments on this NOPR but none on its reporting burden. The 
Commission's responses to the comments are addressed in the preamble of 
this Final Rule. The Commission is submitting a copy of the Final Rule, 
along with information collection submissions for the data collection 
identified above, to OMB for its review and approval.
    Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street, NE., Washington, DC 20426 [Attention: 
Michael Miller, Office of the Chief Information Officer, Phone: (202) 
208-1415, Fax: (202) 208-2425, E-Mail: [email protected]].
    For comments concerning the collection of information(s) and 
associated burden estimate(s), please send your comments to the contact 
listed above and to the Office of Management and Budget, Office of 
Information and Regulatory Affairs, Washington, DC 20503 [Attention: 
Desk Officer for the Federal Energy Regulatory Commission, Phone: (202) 
395-7318, Fax: (202) 395-7285].

VII. Effective Date and Congressional Notification

    This rule will take effect on January 1, 2001. We will begin 
assessing annual charges under this new methodology starting with bills 
to be paid in calendar year 2002, based on data reported on FERC-582 in 
calendar year 2002 (for transactions that occurred in calendar year 
2001, the first full year after adoption of changes in the 
regulations).\78\
---------------------------------------------------------------------------

    \78\ Our existing regulations will remain effective for prior 
submissions and annual charges assessments (i.e., for annual charge 
bills to be paid in calendar year 2001 based on data reported on 
FERC-582 in calendar year 2001 (for transactions that occurred in 
calendar year 2000)).
---------------------------------------------------------------------------

    Likewise we will make the change discussed above with respect to 
corrections to FERC-582 effective beginning with the data reported in 
FERC-582 in calendar year 2002 (for transactions that occurred in 
calendar year 2001); thus such corrections will need to be submitted on 
or before December 31, 2002.
    The Commission has determined, with the concurrence of the 
Administrator of the Office of Information and Regulatory Affairs of 
the Office of Management and Budget, that this Rule is not a ``major 
rule'' within the meaning of section 251 of the Small Business 
Regulatory Fairness Act of 1996.\79\ The Commission will submit the 
Final Rule to both houses of Congress and to the General Accounting 
Office. \80\
---------------------------------------------------------------------------

    \79\ 5 U.S.C. 804(2).
    \80\ 5 U.S.C. 801(a)(1)(A).
---------------------------------------------------------------------------

VIII. Document Availability

    In addition to publishing the full text of this document in the 
Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through FERC's Home Page (http://ferc.fed.us) and in FERC's 
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. 
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.
    From FERC's Home Page on the Internet, this information is 
available in both the Commission Issuance Posting System (CIPS) and the 
Records and Information Management System (RIMS).
     CIPS provides access to the texts of formal documents 
issued by the Commission since November 14, 1994. CIPS can be accessed 
using the CIPS link or the Energy Information Online icon. The full 
text of this document will be available on CIPS in ASCII and 
WordPerfect 8.0 format for viewing, printing and/or downloading.
     RIMS contains images of documents submitted to and issued 
by the Commission after November 16, 1981. Documents from November 1995 
to the present can be viewed and printed from FERC's Home Page using 
the RIMS link or the Energy Information Online icon. Descriptions of 
documents back to November 16, 1981, are also available from RIMS-on-
the-Web; requests for copies of these and other older documents should 
be submitted to the Public Reference Room.
    User assistance is available for RIMS, CIPS and the Website during 
normal business hours from our Help Line at (202) 208-2222 (E-mail to 
[email protected]) or the Public Reference Room at (202) 208-1371 
(E-mail to [email protected]).
    During normal business hours, documents can also be viewed and/or 
printed in FERC's Public Reference Room, where RIMS, CIPS and the FERC 
Website are available. User assistance is also available.

List of Subjects in 18 CFR Part 382

    Administrative practice and procedure, Electric utilities, 
Pipelines, Reporting and recordkeeping requirements.

    By the Commission.
David P. Boergers,
Secretary.

    In consideration of the foregoing, the Commission amends Part 382, 
Chapter I, Title 18 of the Code of Federal Regulations, as follows:

PART 382--ANNUAL CHARGES

    1. The authority citation for Part 382 continues to read as 
follows:

    Authority: 5 U.S.C. 551-557; 15 U.S.C. 717-717w, 3301-3432; 16 
U.S.C. 791a-825r, 2601-2645; 42 U.S.C. 7101-7352; 49 U.S.C. 60502; 
49 App. U.S.C. 1-85.

    2. In Sec. 382.102 paragraphs (h), (i), (j) and (k) are removed and 
paragraphs (l), (m), (n), (o) and (p) are redesignated as (h), (i), 
(j), (k) and (l), respectively.
    3. Section 382.201 is revised to read as follows:


Sec. 382.201  Annual charges under Parts II and III of the Federal 
Power Act and related statutes.

    (a) Determination of costs to be assessed to public utilities. The 
adjusted costs of administration of the electric regulatory program, 
excluding the costs of regulating the Power Marketing Agencies, will be 
assessed to public utilities that provide transmission service 
(measured, as discussed in paragraph (c) of this section, by the sum of 
the megawatt-hours of all unbundled transmission and the megawatt-hours 
of all bundled wholesale power sales (to the extent these latter 
megawatt-hours were not separately reported as unbundled 
transmission)).
    (b) Determination of annual charges to be assessed to public 
utilities. The costs determined under paragraph (a) of this section 
will be assessed as annual charges to each public utility providing 
transmission service based on the proportion of the megawatt-hours of 
transmission of electric energy in

[[Page 65769]]

interstate commerce of each such public utility in the immediately 
preceding reporting year (either a calendar year or fiscal year, 
depending on which accounting convention is used by the public utility 
to be charged) to the sum of the megawatt-hours of transmission of 
electric energy in interstate commerce in the immediately preceding 
reporting year of all such public utilities.
    (c) Reporting requirement. (1) For purposes of computing annual 
charges, as of January 1, 2002, a public utility, as defined in 
Sec. 382.102(b), that provides transmission service must submit under 
oath to the Office of the Secretary by April 30 of each year an 
original and conformed copies of the following information (designated 
as FERC Reporting Requirement No. 582 (FERC-582)): The total megawatt-
hours of transmission of electric energy in interstate commerce, which 
for purposes of computing the annual charges and for purposes of this 
reporting requirement, will be measured by the sum of the megawatt-
hours of all unbundled transmission (including MWh delivered in 
wheeling transactions and MWh delivered in exchange transactions) and 
the megawatt-hours of all bundled wholesale power sales (to the extent 
these latter megawatt-hours were not separately reported as unbundled 
transmission). This information must be reported to 3 decimal places; 
e.g., 3,105 KWh will be reported as 3.105 MWh.
    (2) Corrections to the information reported on FERC-582, as of 
January 1, 2002, must be submitted under oath to the Office of the 
Secretary on or before the end of each calendar year in which the 
information was originally reported (i.e., on or before the last day of 
the year that the Commission is open to accept such filings).
    (d) Determination of annual charges to be assessed to power 
marketing agencies. The adjusted costs of administration of the 
electric regulatory program as it applies to Power Marketing Agencies 
will be assessed against each power marketing agency based on the 
proportion of the megawatt-hours of sales of each power marketing 
agency in the immediately preceding reporting year (either a calendar 
year or fiscal year, depending on which accounting convention is used 
by the power marketing agency to be charged) to the sum of the 
megawatt-hours of sales in the immediately preceding reporting year of 
all power marketing agencies being assessed annual charges.

    Note: The following appendix will not appear in the Code of 
Federal Regulations.

Appendix to Preamble--List of Commenters

Abbreviation--Commenter

1. AEP--Operating Companies of the American Electric Power System
2. Allegheny Power--Monongahela Power Company, Potomac Edison 
Company, and West Penn Power Company
3. APS--Arizona Public Service Company
4. APX--Automated Power Exchange
5. APX Companies--Automated Power Exchange (APX), Coral Power, 
L.L.C. (Coral), Dynegy Power Marketing, Inc. (Dynegy), Enron Power 
Marketing, Inc. (EPMI), Koch Energy Trading, Inc. (Koch) and 
Merchant Energy Group of the Americas (MEGA)
6. Atlantic City--Atlantic City Electric Company, Delmarva Power & 
Light Company, Potomac Electric Power Company, PPL Electric 
Utilities Corporation, and Public Service Electric & Gas
7. Avista--Avista Corporation
8. Cal ISO--California Independent System Operator Corporation
9. ComEd--Commonwealth Edison Company
10. Consumers--Consumers Energy Company
11. EEI--Edison Electric Institute
12. EPSA--Electric Power Supply Association
13. FirstEnergy--FirstEnergy Corp.
14. GPU Energy--Jersey Central Power & Light Company, Metropolitan 
Edison Company and Pennsylvania Electric Company
15. ISO-NE--ISO New England Inc.
16. LIPA and NYPA--Long Island Power Authority and the Power 
Authority of the State of New York
17. Member Systems-- Members of the Transmission Owners Committee of 
the Energy Association of New York State (formerly known as the 
Member Systems of the New York Power Pool)
18. Midwest ISO--Midwest Independent Transmission System Operator, 
Inc.
19. Midwest ISO Participants--Alliant Utilities, Ameren (on behalf 
of Central Illinois Public Service Company and Union Electric 
Company), Central Illinois Light Company, Cinergy Corp. (on behalf 
of Cincinnati Gas & Electric Company, PSI Energy Inc., and Union 
Light, Heat & Power), Commonwealth Edison Company (including 
Commonwealth Edison Company of Indiana), Hoosier Energy Rural 
Electric Cooperative, Inc., Illinois Power Company, Kentucky 
Utilities Company, Louisville Gas & Electric Company, Northern 
States Power Company, Southern Illinois Power Cooperative, Southern 
Indiana Gas & Electric Corp., Wabash Valley Power Association, Inc., 
and Wisconsin Electric Power Company.
20. MLCS--Merrill Lynch Capital Services, Inc.
21. NEM--National Energy Marketers Association
22. NEP--New England Power Company
23. NUSCO--Northeast Utilities Service Company
24. NYISO--New York Independent System Operator, Inc.
25. NYMEX--New York Mercantile Exchange
26. PECO--PECO Energy Company
27. PJM--PJM Interconnection, L.L.C.
28. PNGC--Pacific Northwest Generating Cooperative
29. SDG&E--San Diego Gas & Electric Company
30. SoCal Edison--Southern California Edison Company
31. SPP--Southwest Power Pool, Inc.
32. TXU Electric--TXU Electric Company
33. Williams EM&T--Williams Energy Marketing & Trading Company

[FR Doc. 00-27992 Filed 11-1-00; 8:45 am]
BILLING CODE 6717-01-U