Federal Register / Vol. 65, No. 213 / Thursday, November 2, 2000 / Rules and Regulations 65757

1 42 U.S.C. 7178.

2This 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).

4The 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).

5See Conference Report at 238.

6 42 U.S.C. 7178(c).

respectively; and a new paragraph (e)(5)

is added, to read as follows:

§ 157.22 Collaborative procedures for

applications for certificates of public

convenience and necessity and for orders

permitting and approving abandonment.

* * * * *

(e) * * *

(1) The Commission will publish

notice of its authorization to use the prefiling process in the Federal Register;

the applicant will publish notice of the

Commission’s authorization to use the

pre-filing process in a local newspaper

of general circulation in the county or

counties in which the proposed project

is to be located. To the extent feasible,

the applicants’ notice will specify the

time and place of the initial information

meeting(s) and the scoping of

environmental issues and will be sent to

a mailing list approved by the

Commission that includes the names

and addresses of landowners affected by

the project.

* * * * *

(5) Every three months, the applicant

shall file with the Commission a report

summarizing the progress made in the

pre-filing collaborative process,

referencing the public file maintained

by the applicant as provided in

paragraph (e)(4), of this section where

additional information on that process

can be obtained. Summaries or minutes

of meetings held as part of the

collaborative process may be used to

satisfy this filing requirement.

* * * * *

[FR Doc. 00–28082 Filed 11–01–00; 8:45 am]

BILLING CODE 6717–01–P

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.

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 He ́bert, 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:

[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

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

65758 Federal Register / Vol. 65, No. 213 / Thursday, November 2, 2000 / Rules and Regulations

7 Id. at 7178(f). Congress approves the

Commission’s budget through annual and

supplemental appropriations.

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 ¶ 30,746 (1987), clarified, Order No.

472–A, 52 FR 23650 (June 24, 1987), FERC Stats.

& Regs., Regulations Preambles 1986–1990 ¶ 30,750,

order on reh’g, Order No. 472–B, 52 FR 36013 (Sept.

25, 1987), FERC Stats. & Regs., Regulations

Preambles 1986–1990 ¶ 30,767 (1987), order on

reh’g, Order No. 472–C, 53 FR 1728 (Jan. 22, 1988),

42 FERC ¶ 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 ¶ 30,839 at 31,263–64 (1988); Texas

Utilities Electric Company, 45 FERC ¶ 61,007 at

61,027 (1988) (Texas Utilities).

10 18 CFR 382.201; see Annual Charges Under the

Omnibus Budget Reconciliation Act of 1986 (Phibro

Inc.), 81 FERC ¶ 61,308 at 62,424–25 (1997). 11 18 CFR 382.201(b)(4). 12See Texas Utilities, 45 FERC at 61,026. 13See 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. ¶ 31,036 (1996), order on

reh’g, Order No. 888–A, 62 FR 12274 (Mar. 14,

1997), FERC Stats. & Regs. ¶ 31,048 (1997), order on

reh’g, Order No. 888–B, 62 FR 64688 (Mar. 14,

1997), 81 FERC ¶ 61,248 (1997), order on reh’g,

Order No. 888–C, 82 FERC ¶ 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).

14Revision of Annual Charges Assessed to Public

Utilities, Notice of Proposed Rulemaking, 65 FR

5289 (Jan. 28, 2000), FERC Stats. & Regs. ¶ 32,550

(2000).

15FERC Stats. & Regs. ¶ 32,550 at 33,921.

16 Id.

17The commenters, and the abbreviations for

them used herein, are listed in an appendix to this

Final Rule.

States Treasury for the Commission’s

expenses.7

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

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 shortterm 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

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

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 standalone 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.

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

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.

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

Federal Register / Vol. 65, No. 213 / Thursday, November 2, 2000 / Rules and Regulations 65759

18 16 U.S.C. 824–825r.

19Under 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.

21 16 U.S.C. 824d.

22 16 U.S.C. 824e.

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.

27Flood 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.

28 16 U.S.C. 824a–3.

29 18 CFR Part 292.

30The issue of filing fees is not before the

Commission. In fact, however, QFs are assessed

filing fees. 18 CFR 381.505.

adopts a Final Rule that follows the

approach of the NOPR.

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 underrecovery 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 investorowned 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).

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.

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

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.

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

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.

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

65760 Federal Register / Vol. 65, No. 213 / Thursday, November 2, 2000 / Rules and Regulations

31See 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. 33See 18 CFR 292.601. 34See 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

¶ 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). 36Based 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 ¶ 61,060 (1994);

City of College Station, Texas, 86 FERC ¶ 61,165

(1999).

37E.g., British Columbia Power Exchange

Corporation, 80 FERC ¶ 61,343 at 62,137, 62,141

(1997) (sales in foreign commerce or within another

country are excluded from annual charges

calculations).

38Williams 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.

39These 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).

41The 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.

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.

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.

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

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 nondiscriminatory, 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.

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

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.

A number of commenters state that

they generally support the

Federal Register / Vol. 65, No. 213 / Thursday, November 2, 2000 / Rules and Regulations 65761

42Avista 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.

43APS 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.

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.

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 transmissionowning 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, transmissionowning 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.

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 longterm firm sales and transmission, and

short-term sales and transmission and

exchanges for all assessable public

65762 Federal Register / Vol. 65, No. 213 / Thursday, November 2, 2000 / Rules and Regulations

44Long-term firm sales and transmission

activities, and short-term sales and transmission

and exchange activities were defined in 18 CFR

382.102.

45The 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.

46See supra note 13.

47Regional Transmission Organizations, Order

No. 2000, 65 FR 810 (Jan. 6, 2000), FERC Stats. &

Regs. ¶ 31,089 (1999), order on reh’g, Order No.

2000–A, 65 FR 12088 (Mar. 8, 2000), FERC Stats.

& Regs. ¶ 31,092 (2000).

48This approach is essentially the same as how

annual charges are, in practice, assessed against gas

pipelines.

49The 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.

50With 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.

51See supra note 13, Order No. 888, FERC Stats.

& Regs. ¶ 31,036, at 31,780–85, Order No. 888-A,

FERC Stats. & Regs. ¶ 31,043 at 30,334–46; TAPSG,

slip op. at 24–35.

52Annual 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 ¶ 61,044 (1996),

reh’g denied, 83 FERC ¶ 61,203 (1998); New

England Power Co., et al., 75 FERC ¶ 61,207 (1996),

76 FERC ¶ 61,008 (1996), reh’g denied, 85 FERC

¶ 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.

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.

54These data include all transmission of power

for other entities.

55 :These data include power delivered by the

utility to others in power exchange transactions.

56These 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.

57The 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

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.

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

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

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:

(1) Transmission of Electricity for

Others, Transfer of Energy, MWh

Delivered (Form No. 1, Pg. 328–329,

Col. (j)); 54

(2) Purchased Power, Power

Exchanges, MWh Delivered (Form No.

1, Pg. 326–327, Col. (i)); 55 and

(3) Sales for Resale, MWh Sold (Form

No. 1, Pg. 310–311, Col. (g)).56

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

Federal Register / Vol. 65, No. 213 / Thursday, November 2, 2000 / Rules and Regulations 65763

example, power marketers are not providing

transmission service, they will not need to file

FERC–582 or pay annual charges.

58E.g., supra note 13, Order No. 888–A, FERC

Stats. & Regs. ¶ 31,048 at 30,217.

59For 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).

60The 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.

61The 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.

62See supra note 60.

63Based 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.

64Based 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.

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.

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.

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

65764 Federal Register / Vol. 65, No. 213 / Thursday, November 2, 2000 / Rules and Regulations

65Based 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. 66See supra note 52.

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.

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

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

Federal Register / Vol. 65, No. 213 / Thursday, November 2, 2000 / Rules and Regulations 65765

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. 69We 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 nonjurisdictional. 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.

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 nonjurisdictional 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 transmissionowning 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

65766 Federal Register / Vol. 65, No. 213 / Thursday, November 2, 2000 / Rules and Regulations

70Likewise, 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).

71 18 CFR Part 35; see 16 U.S.C. 824d (allowing

utilities to seek to change their rates).

72Williams EM&T commented that it believed

that as a public utility under the FPA, it would still

assessed annual charges based on the

respective services provided.70

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.

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 megawatthours and the total short-term sales,

transmission, and exchange megawatthours. 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

Federal Register / Vol. 65, No. 213 / Thursday, November 2, 2000 / Rules and Regulations 65767

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.

73 18 CFR 380.4.

74 18 CFR 380.4(a)(2)(ii).

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

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

77 5 CFR 1320.11.

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.

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.’’

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.

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:

Data collection Number of

respondents

Number of

responses

Hours per

response

Total annual

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)

× $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.

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

65768 Federal Register / Vol. 65, No. 213 / Thursday, November 2, 2000 / Rules and Regulations

78Our 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)).

79 5 U.S.C. 804(2).

80 5 U.S.C. 801(a)(1)(A).

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:

mike.miller@ferc.fed.us].

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

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

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

WebMaster@ferc.fed.us) or the Public

Reference Room at (202) 208–1371 (Email to

public.referenceroom@ferc.fed.us).

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 § 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:

§ 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

Federal Register / Vol. 65, No. 213 / Thursday, November 2, 2000 / Rules and Regulations 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 § 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 megawatthours 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

DEPARTMENT OF THE TREASURY

Customs Service

19 CFR 10, 12, 18, 24, 111, 113, 114,

125, 134, 145, 162, 171, and 172

[T.D. 00–57]

RIN 1515–AC01

Petitions for Relief: Seizures,

Penalties, and Liquidated Damages;

Correction

AGENCY: Customs Service, Treasury.

ACTION: Final rule; correction.

SUMMARY: Customs published in the

Federal Register of September 5, 2000,

a document that revised the Customs

Regulations relating to the filing of

petitions in penalty, liquidated

damages, and seizure cases.

Inadvertently, Appendix C to Part 171

was incorrectly amended. This

document corrects the amendment of

that Appendix.

EFFECTIVE DATE: November 2, 2000.

FOR FURTHER INFORMATION CONTACT:

Jeremy Baskin, Penalties Branch, Office

of Regulations and Rulings, (202) 927–

2344.

SUPPLEMENTARY INFORMATION:

Background

On September 5, 2000, Customs

published in the Federal Register (65

FR 53565) T.D. 00–57 that revised the

Customs Regulations relating to the

filing of petitions in penalty, liquidated

damages, and seizure cases. Parts 171

and 172 of the Customs Regulations

were recrafted in that document to

include petition processing in seizure

and unsecured penalty cases under part

171 and liquidated damages and

secured penalty petition processing

under part 172. It has come to Customs

attention that the amendatory

instructions regarding appendix C to

part 171 set forth in that document

inadvertently failed to remove a section

and a note in the Appendix which were