Federal Register / Vol. 60, No. 87 / Friday, May 5, 1995 / Rules and Regulations 22257

1 ‘‘Community development financial institution’’

is defined in the Community Development Banking

and Financial Institutions Act of 1994 (Title I of

Pub. L. 103–325, 108 Stat. 2160, section 103(5)).

Braunstein, Manager for Community

Affairs (202–452–3378), Division of

Consumer and Community Affairs;

Larry Cunningham, Supervisory

Financial Analyst, Division of Banking

Supervision and Regulation (202–452–

2701); for users of the

Telecommunications Device for the Deaf

(TDD) only, Dorothea Thompson (202–

452–3544); Board of Governors of the

Federal Reserve System, Washington,

DC 20551.

SUPPLEMENTARY INFORMATION: Section

9(23) of the Federal Reserve Act (12

U.S.C. 338a) allows state member banks,

under certain conditions, to make

investments designed primarily to

promote the public welfare. Section

9(23) provides that public welfare

investments must not violate state law

or expose the bank to unlimited

liability. Section 9(23) limits the

aggregate of the bank’s public welfare

investments to 5 percent of the bank’s

capital stock and surplus, but allows the

Board to increase this limit to as much

as 10 percent on a case-by-case basis.

The Board’s Regulation H (12 CFR

208.21) permits state member banks to

make public welfare investments

without prior approval if the investment

is one that is listed in the regulation and

if the bank meets the regulation’s capital

and condition requirements.

Specifically, a state member bank may

make an investment, without prior

approval, that the Board or the

Comptroller of the Currency (OCC)

previously has determined to be a

public welfare investment or that is an

investment in a community

development financial institution.1 In

addition, Regulation H allows state

member banks to invest without prior

approval in an entity established solely

to engage in certain community

development activities, such as lowand moderate-income housing,

nonresidential real estate development,

small business development, and job

training.

In order to make a public welfare

investment without prior approval, a

state member bank must (1) Limit any

single investment to not more than 2

percent of the bank’s capital stock and

surplus, (2) be at least adequately

capitalized, (3) be rated a composite

CAMEL ‘‘1’’ or ‘‘2,’’ (4) be rated at least

‘‘satisfactory’’ (i.e., ‘‘2’’) in its last

consumer compliance examination, and

(5) not be subject to any written

agreement, cease and desist order,

capital directive, or prompt corrective

action directive.

The Board is delegating to the Federal

Reserve Banks the authority to approve

certain public welfare investments by

state member banks that do not meet the

‘‘no-prior-approval’’ conditions in

Regulation H. Specifically, Reserve

Banks may approve investments that

meet all the conditions in § 208.21(b) of

Regulation H, except that:

• The bank’s compliance rating is

‘‘3;’’

• The investment would exceed 2

percent (but not 5 percent) of the bank’s

capital and surplus; or

• The aggregate of all such

investments of the bank exceeds 5

percent (but not 10 percent) of its

capital stock and surplus.

Administrative Procedure Act

The Administrative Procedure Act (5

U.S.C. 553(b)(A)) exempts ‘‘rules of

agency organization, procedure, or

practice’’ from the notice of proposed

rulemaking and public comment

requirements. As the Board’s delegation

rules fall under this exemption, the

Board is adopting these amendments

without notice-and-comment

procedures.

List of Subjects in 12 CFR Part 265

Authority delegations (Government

agencies), Banks, banking, Federal

Reserve System.

For the reasons set forth in the

preamble, the Board is amending 12

CFR Part 265 as set forth below:

PART 265—RULES REGARDING

DELEGATION OF AUTHORITY

1. The authority citation for Part 265

continues to read as follows:

Authority: 12 U.S.C. 248 (i) and (k).

2. Section 265.11 is amended by

adding a new paragraph (e)(12) to read

as follows:

§ 265.11 Functions delegated to Federal

Reserve Banks.

* * * * *

(e) * * *

(12) Public welfare investments. To

permit a state member bank to make a

public welfare investment that meets

the conditions set forth in § 208.21(b)

(1)–(8) of Regulation H (12 CFR 208),

except that:

(i) The state member bank received an

overall rating of ‘‘3’’ as of its most recent

consumer compliance examination;

(ii) The investment exceeds 2 percent,

but does not exceed 5 percent, of the

state member bank’s capital stock and

surplus as defined under 12 CFR

250.162; or

(iii) The aggregate of all such

investments of the state member bank

exceeds 5 percent, but does not exceed

10 percent, of its capital stock and

surplus as defined under 12 CFR

250.162.

* * * * *

By order of the Board of Governors of the

Federal Reserve System, May 1, 1995.

William W. Wiles,

Secretary of the Board.

[FR Doc. 95–11087 Filed 5–4–95; 8:45 am]

BILLING CODE 6210–01–P

DEPARTMENT OF ENERGY

Federal Energy Regulatory

Commission

18 CFR Parts 2 and 35

[Docket No. PL95–1–000]

Ratemaking Treatment of the Cost of

Emissions Allowances in Coordination

Rates; Order No. 579

Issued April 26, 1995.

AGENCY: Federal Energy Regulatory

Commission, DOE.

ACTION: Final rule amendment and

confirmation of interim rules as final.

SUMMARY: On December 15, 1994, the

Commission issued a Policy Statement

and Interim Rule Regarding Ratemaking

Treatment of the Cost of Emissions

Allowances in Coordination Rates. In

the Policy Statement, codified in § 2.25,

the Commission set forth the elements

of what generally constitutes

appropriate ratemaking treatment of

sulfur dioxide emissions allowances in

coordination transactions under the

Federal Power Act. The Interim Rule,

codified in § 35.23, implemented the

filing guidelines set forth in the Policy

Statement.

This order is issued in response to

comments on the Interim rule (§ 35.23).

It clarifies the Policy Statement (§ 2.25)

in certain respects and adopts the

Interim Rule, without modification, as a

Final Rule.

EFFECTIVE DATE: June 5, 1995.

FOR FURTHER INFORMATION CONTACT:

Wayne W. Miller (Legal Information),

Office of the General Counsel, Federal

Energy Regulatory Commission, 825

North Capitol Street NE., Washington,

DC 20426, Telephone: (202) 208–0466

Moira Notargiacomo (Technical

Information), Office of Electric Power

Regulation, Federal Energy Regulatory

Commission, 825 North Capitol Street

NE., Washington, DC 20426,

Telephone: (202) 208–1079.
22258 Federal Register / Vol. 60, No. 87 / Friday, May 5, 1995 / Rules and Regulations

1Policy Statement and Interim Rule Regarding

Ratemaking Treatment of the Cost of Emissions

Allowances in Coordination Rates, 59 FR 65930

(December 15, 1994), III FERC Stats. and Regs.,

Regulations Preambles ¶ 31,009 (1994).

2See infra note 4 (describing ‘‘true-up’’

requirements). 3 18 CFR 385.207.

4On January 30 (or the first subsequent business

day) of each calendar year, EPA determines whether

companies have the right number of emissions,

allowances of appropriate vintage on hand for each

ton of sulfur dioxide emitted during the previous

calendar year. See Policy Statement and Interim

Rule, III FERC States. and Regs., Regulations

Preambles at 31,201, 31,203 n.18 Utilities must

‘‘true up’’ their emissions allowance accounts by

the EPA reporting date so that they will have a

sufficient number of allowances on hand to avoid

EPA penalties. The penalty for not having the

requisite number of allowances on hand by the EPA

reporting date is $2,000 per ton plus surrender of

SUPPLEMENTARY INFORMATION: In

addition to publishing the full text of

this document in the Federal Register,

the Commission also provides all

interested persons an opportunity to

inspect or copy the contents of this

document during normal business hours

in Room 3104, 941 North Capitol Street

NE., Washington, DC 20426.

The Commission Issuance Posting

System (CIPS), an electronic bulletin

board service, provides access to the

texts of formal documents issued by the

Commission. CIPS is available at no

charge to the user and may be accessed

using a personal computer with a

modem by dialing (202) 208–1397. To

access CIPS, set your communications

software to 19200, 14400, 12000, 9600,

7200, 4800, 2400, 1200 or 300 bps, full

duplex, no parity, 8 data bits, and 1 stop

bit. The full text of this document will

be available on CIPS for 60 days from

the date of issuance in ASC II and

WordPerfect 5.1 format. After 60 days,

the document will be archived, but still

accessible. The complete text on

diskette in WordPerfect format may also

be purchased from the Commission’s

copy contractor, LaDorn Systems

Corporation, also located in Room 3104,

941 North Capitol Street NE.,

Washington, DC 20426.

I. Introduction

On January 23, 1995, Illinois Power

Company (Illinois Power), the

Pennsylvania Public Utility Commission

(Pennsylvania Commission), and the

Edison Electric Institute (EEI) filed

comments requesting clarification of the

Policy Statement and Interim Rule

issued on December 15, 1994.1

After considering the comments, the

Federal Energy Regulatory Commission

(Commission) is revising its Policy

Statement on the Ratemaking Treatment

of the Cost of Emissions Allowances in

Coordination Transactions. Specifically,

the Commission is revising the Policy

Statement to provide that public

utilities may require customers to

declare, no later than the beginning of

the coordination transaction, whether

they will pay for the cost of emission

allowances reflected in the purchased

electric energy or, in the alternative,

deliver emissions allowances in time for

‘‘true-up,’’ 2 and to provide that public

utilities may structure arrangements

when customers provide allowances so

as to remain risk neutral (i.e., neutral as

to risks of non-delivery). The

Commission rejects Illinois Power’s

request to clarify the Policy Statement

and Interim Rule to provide that selling

public utilities need not designate

indices in their rate filings. The

Commission also addresses the

Pennsylvania Commission’s concerns

regarding Federal and state jurisdiction

over emissions allowance costs in

wholesale and retail rates.

II. Public Reporting Burden

The Final Rule would clarify how

existing filing requirements apply to

public utilities filing amendments to

coordination rate schedules to provide

for the recovery of emissions allowance

costs. Because this Final Rule only

clarifies, and does not amend, how

existing filing requirements are to be

implemented, the public reporting

burden for these information collections

(including the time for reviewing

instructions, searching existing data

sources, gathering and maintaining the

data needed, and completing and

reviewing the collection of information)

is not estimated to increase the number

of hours per response for each public

utility currently involved in the filing of

rate schedule amendments. Send

comments regarding these burden

estimates or any other aspect of these

collections of information, including

suggestions for reducing the burden, by

contacting the Federal Energy

Regulatory Commission, 941 North

Capitol Street NE., Washington, DC

20426 [Attention: Michael Miller,

Information Services Division, (202)

208–1415], and to the Office of

Management and Budget, Washington,

DC 20503 (Attention: Desk Officer for

the Federal Energy Regulatory

Commission), FAX: (202) 395–5167.

III. Background

On October 14, 1994, EEI filed a

petition under section 207 of the

Commission’s Rules of Practice and

Procedure,3 requesting a policy

statement regarding the ratemaking

treatment of emissions allowances in

coordination transactions under the

Federal Power Act (FPA). EEI also

requested the Commission to clarify that

the sale or transfer of emissions

allowances does not require

Commission authorization under

section 203 of the FPA and does not

require filing under section 205 of the

FPA.

In the Policy Statement, the

Commission adopted, with certain

modifications to reflect the concerns

raised by intervenors, EEI’s proposals.

Specifically, the Commission found that

it would allow the recovery of

incremental costs of emissions

allowances in coordination rates

whenever the coordination rate also

provides for recovery of other variable

costs on an incremental basis. If a

coordination rate does not reflect

incremental cost pricing for other costs,

the Commission stated that it would

require the seller to propose an

alternative costing method for emissions

allowances, or demonstrate that any

inconsistency between the proposed

costing method and the coordination

rate does not produce unreasonable

results.

In support of these determinations,

the Commission made a number of

related findings. First, it found that the

cost to replace an allowance is an

appropriate basis to establish

incremental cost. Second, the

Commission found that sellers of

emissions allowances should be

permitted to choose their own index or

a combination of indices, if done

consistently, in pricing allowances in

coordination transactions. Third, the

Commission found that the use of

incremental costing for emissions

allowances should be consistent with

the use of incremental costing for

economic dispatch decisions, and stated

that any differences between

incremental costing for coordination

sales and dispatch decisions regarding

emissions allowances should be

explained and reconciled. Fourth, the

Commission found that sellers of

emissions allowances should explain

how they will compute the amount of

emissions allowances that will be

attributed to each coordination

transaction. Fifth, the Commission

found that public utilities should

provide information to purchasing

utilities regarding the timing of

opportunities for purchasers to stipulate

whether they will purchase or return

emissions allowances. The Commission

stated that customers that choose to

provide allowances in kind should be

permitted to do so by the appropriate

Environmental Protection Agency (EPA)

reporting date.,4 rather than at the time
Federal Register / Vol. 60, No. 87 / Friday, May 5, 1995 / Rules and Regulations 22259

an emissions allowance equivalent in the following

year, plus other possible punishments depending

on the degree of violation. Id. at 31,201.

5Edison Electric Institute, 69 FERC ¶ 61,344

(1994).

6 Illinois Power also refers to the findings in the

Policy Statement and Interim Rule regarding the

calculation of the amount of emissions allowances

associated with a coordination transaction and

reconciliation of inconsistencies in dispatch

criteria, but does not suggest any modifications to

these findings.

7 Illinois Power notes the Commission’s order in

Southern Company Services, Inc., 69 FERC ¶61,437

(1994), reh’g pending, in which the Commission,

consistent with the Policy Statement and Interim

Rule, directed the Southern Companies to modify

their submittal to allow customers that choose to

return allowances in kind to do so up to the EPA

reporting date rather than at the time of the

transaction.

8See supra note 4.

9EEI emphasizes that because of EPA’s

administrative requirements, utilities must have the

requisite number of allowances on hand several

weeks before the ‘‘true-up’’ deadline. Similarly,

Illinois Power argues that providing a utility the

option to make an in-kind return of allowances ‘‘up

to the EPA reporting date,’’ does not necessarily

allow for sufficient time to complete a transfer

through EPA’s Allowance Tracking System. Illinois

Power also argues that allowing customers who

return allowances in kind to do so up to the EPA

reporting date conflicts with payment terms

previously established by mutual agreement of the

affected parties.

10Such date should afford the selling public

utility sufficient time to meet its requirements to

EPA. The close of the calendar year would appear

to be more than adequate. However, customers

should be allowed to designate a date comparable

to that which the utility itself would internally

designate if it were purchasing allowances to meet

its EPA requirements. In other words, the selling

utility may not require its customers to provide

allowances any earlier than the utility’s internal

deadlines for purchasing allowances to meet EPA

requirements for the prior calendar year. Thus, if

the public utility purchases allowances on, for

example, January 15, we see no reason to require

customers to provide allowances any earlier.

11Such indemnification provisions should be

applied in a non-discriminatory manner. While EEI

notes that power marketers and brokers may

become insolvent, we note that such a entities are

not the only entities that may become insolvent; a

few traditional utilities have sought bankruptcy

protection in recent years.

of the transaction. The Commission also

stated that the seller should explain

how fractional allowances will be

handled, and suggested a ‘‘rounding’’

approach, i.e., rounding up to the next

whole number if the fraction is greater

than one-half, or down if the fraction is

less than one-half. Finally, the

Commission stated that the ratemaking

treatment of emissions allowance costs

endorsed in the Policy Statement does

not preclude other approaches proposed

by individual public utilities on a caseby-case basis.

In the Interim Rule (codified in

§ 35.23 of its regulations), the

Commission stated that if public

utilities have rate schedules on file that

expressly provide for the recovery of all

incremental or out-of-pocket costs, these

utilities may make abbreviated rate

filings, limited to detailing how they

would recover emissions allowance

costs. Regarding coordination rates that

do not provide for the recovery of all

incremental costs, the Commission

concluded that the public utility may

include rate schedule amendments

together with the abbreviated filing if

customers agree to the rate change; if the

customers do not agree to revise such

rates, the Commission stated that the

public utility must tender its emissions

allowance proposal in a separate section

205 rate filing, fully justifying its

proposal.

In a separate order disclaiming

jurisdiction,5 the Commission

concluded that emissions allowances

are not facilities subject to the

Commission’s jurisdiction under section

203. The Commission further concluded

that a sale or transfer of emissions

allowances does not require a filing

under section 205 when that sale or

transfer occurs outside of a sale by a

public utility for resale in interstate

commerce.

The Commission invited interested

persons to submit additional written

comments on the matters addressed in

the Interim Rule by January 23, 1995.

EEI, Illinois Power and the

Pennsylvania Commission timely

submitted comments. As explained in

greater detail below, EEI and Illinois

Power suggest clarification of the Policy

Statement provision regarding timing.

Illinois Power also suggests clarification

of the Policy Statement and Interim

Rule regarding the use of indices.6

The Pennsylvania Commission

request clarification of the Interim Rule

to state that the Rule applies to

jurisdictional rates only, and does not

contemplate preemption of the states’

ratemaking treatment of emissions

allowances.

IV. Discussion

A. Timing

EEI and Illinois Power maintain that

the Policy Statement, as issued, could

be construed to give customers the

option of waiting until the ‘‘true-up’’

date to declare whether they will pay or

return emissions allowances in kind.7

Thus, EEI argues, utilities might not

know how many allowances the

customers would return until it is too

late to avoid incurring EPA penalties.8

EEI maintains that to assure that they

have sufficient emissions allowances on

hand, and thus avoid penalties, utilities

would have to either: (1) tie up their

own capital to create an allowance

reserve, or (2) be prepared to purchase

allowances at the last minute, possibly

paying a premium in the form of a

scarcity rent. To remedy this situation,

EI suggests clarifying the Policy

Statement to state that utilities may

require customers, to declare, at or near

the time of the coordination transaction

(or earlier), whether they will pay or

return emissions allowances in kind,

and, if they return allowances in kind,

the time at which they will do so.9

EEI further notes the public utilities

face risks associated with the timing of

the return of allowances in kind,

including: (a) the risk that if a sale is

arranged by a power broker or marketer,

that entity may become insolvent and

not deliver allowances; and (b) the risk

associated with the failure of customers

to settle their accounts within the

standard billing period. For these

reasons, EEI asks the Commission to

clarify the Policy Statement to state that

utilities may propose arrangements with

their customers for indemnification

from such risks.

Commission Ruling

In the Policy Statement and Interim

Rule, the Commission stated that

purchasing utilities that choose to

return allowances in kind should be

allowed to return the allowances by the

appropriate EPA reporting date, rather

than at the time of the transaction, i.e.,

a ‘‘timing option.’’ However, if

purchasing utilities wait until the time

of ‘‘true-up’’ before declaring whether

they will pay cash or return emissions

allowances in kind, this accords the

selling public utilities little, if any,

opportunity to determine how many

emissions allowances they will need to

avoid EPA penalties. To remedy this

situation, the Commission will clarify

18 CFR 2.25(e) to state that public

utilities may require purchasing utilities

to declare, no later than the beginning

of the coordination transaction: (a)

whether they will pay or return

allowances in kind; and (b) if they

return allowances in kind, to specify a

date by which they will return the

allowances.10 The Commission also will

clarify section 2.25(e) to state that

public utilities may include, in their

agreements, provisions to indemnify

themselves if customers do not return

allowances when they have declared

they will do so.11

B. Use of Indices

Illinois Power argues that the

requirement in the Policy Statement and

Interim Rule (see 18 CFR 2.25(c)) that

utilities use the same incremental cost

index or indices in pricing coordination

sales and in dispatch decisions (or
22260 Federal Register / Vol. 60, No. 87 / Friday, May 5, 1995 / Rules and Regulations

12Regulations Implementing the National

Environmental Policy Act, 52 FR 47897 (Dec. 17,

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

1986–90 ¶ 30,783 (1987).

13 18 CFR 380.4.

14 18 CFR 380.4(15).

15 5 U.S.C. 601–12.

16 5 U.S.C. 601(13) (citing section 3 of the Small

Business Act, 15 U.S.C. 632). Section 3 of the Small

Business Act defines a small business concern as

a business that is independently owned and

operated and that is not dominant in its field of

operation. 15 U.S.C. 632(a).

17 5 CFR 1320.13.

explain and justify the use of different

indices for pricing coordination sales

and dispatch) makes the source of the

index irrelevant. Accordingly, Illinois

Power argues, utilities should not be

burdened with having to make rate

filings with the Commission (see 18 CFR

35.23(b)) indicating their choice of

indices.

Commission Ruling

We disagree. Public utilities must

indicate their choice of indices so that

the Commission can determine whether

the selling utility is using consistent

criteria for pricing coordination sales

and in dispatch decisions. If the selling

public utility is not using the same

index in its dispatch decisions as in

pricing coordination sales (or does not

explain and justify the difference if it

uses different indices), there is no

assurance that the index reflects the

utility’s incremental costs. Also, if there

is no requirement that the selling utility

indicate the index or combination of

indices to be used in its filing, the seller

may simply choose an index with the

highest price at the time of the

transaction, rather than the index that

best reflects its incremental cost.

Finally, the index or indices must be

filed since they are part of the formula

rate. Accordingly, we will not clarify the

Policy Statement and Interim Rule as

Illinois Power requests.

C. Federal vs. State Jurisdiction

The Pennsylvania Commission

commends this Commission for its

prompt consideration of EEI’s

application and for expedited issuance

in this proceeding of the Policy

Statement and Interim Rule.

Nevertheless, the Pennsylvania

Commission expresses concern that the

Commission did not fully address all

jurisdictional issues arising from EEI’s

application.

Specifically, the Pennsylvania

Commission expresses concern with the

Commission’s decision in the Policy

Statement to allow utilities to value

emissions allowances at their

incremental price, based on a market

index. The Pennsylvania Commission

states that it fully understands, and does

not challenge, the basis for this

decision—to encourage the

development of a vigorous trading

market and to provide for consistent rate

treatment for emissions allowances in

coordination sales rates. The

Pennsylvania Commission also states,

however, that it is compelled under

Pennsylvania state law to value

emissions allowances on the basis of

historic costs for retail ratemaking

purposes. Citing ‘‘jurisdictional

uncertainty,’’ the Pennsylvania

Commission urges this Commission to

clarify that the Policy Statement is

limited in scope to Commissionjurisdictional rates and is not intended

to preempt state ratemaking treatment of

emissions allowances in state

jurisdictional rates.

Commission Ruling

We clarify that the general

jurisdictional pronouncements made in

the Policy Statement and Interim Rule

are intended to address only the

Commission’s consideration of FERCjurisdictional rates. The Commission

has not made any preemptive

determination as to any ratemaking

treatment of emissions allowances to be

applied at the retail level by the States.

Whether there would be any preemption

would have to be determined based on

the facts of a particular case.

V. Environmental Statement

Commission regulations require that

an environmental assessment or an

environmental impact statement be

prepared for any Commission action

that may have a significant adverse

effect on the human environment.12 The

Commission has categorically excluded

certain actions from this requirement as

not having a significant effect on the

human environment.13 No

environmental consideration is

necessary for the promulgation of a rule

that involves electric rate filings that

public utilities submit under sections

205 and 206 of the FPA and the

establishment of just and reasonable

rates.14 Because this final rule involves

such filings submitted under sections

205 and 206 of the FPA and the

establishment of just and reasonable

rates, no environmental consideration is

necessary.

VI. Regulatory Flexibility Act

Certification

The Regulatory Flexibility Act

(RFA) 15 requires rulemakings to either

contain a description and analysis of the

effect that the rule will have on small

entities or to certify that the rule will

not have a substantial economic impact

on a substantial number of small

entities. Because most, if not all, of the

entities that would be required to

comply with this rule are large public

utilities that do not fall within the

RFA’s definition of small entities,16 the

Commission certifies that this rule will

not have a ‘‘significant impact on a

substantial number of small entities.’’

VII. Information Collection Statement

The Office of Management and

Budget’s (OMB) regulations 17 require

that OMB approve certain information

collection requirements imposed by an

agency. This rule neither contains new

information collection requirements nor

significantly modifies any existing

information collection requirements in

Part 35; therefore, it is not subject to

OMB approval. However, the

Commission will submit a copy of this

rule to OMB for information purposes

only.

VIII. Effective Date

This document adopts the interim

rule in part 35 as final and amends the

policy statement in part 2 effective June

5, 1995.

List of Subjects

18 CFR Part 2

Administrative practice and

procedure, Electric power, Natural gas

pipelines, Reporting and recordkeeping

requirements.

18 CFR Part 35

Electric power rates, Electric utilities,

Reporting and recordkeeping

requirements.

By the Commission.

Lois D. Cashell,

Secretary.

In consideration of the foregoing, the

interim rule amending 18 CFR Part 35

which was published at 59 FR 65930 on

December 22, 1994, is adopted as a final

rule without change and 18 CFR Part 2

which was amended as a final rule at 59

FR 65930 is further amended as set forth

below.

PART 2—GENERAL POLICY AND

INTERPRETATIONS

1. The authority citation for part 2

continues to read as follows:

Authority: 15 U.S.C. 717–717w, 3301–

3432; 16 U.S.C. 791a–825r, 2601–2645; 42

U.S.C. 4321–4361, 7101–7352.

2. Part 2, § 2.25, is amended by

revising § 2.25(e) to read as follows:
Federal Register / Vol. 60, No. 87 / Friday, May 5, 1995 / Rules and Regulations 22261

§ 2.25 Ratemaking Treatment of Cost of

Emissions Allowances in Coordination

Transactions.

* * * * *

(e) Timing. (1) Public utilities should

provide information to purchasing

utilities regarding the timing of

opportunities for purchasers to stipulate

whether they will purchase or return

emissions allowances. A public utility

may require a purchasing utility to

declare, no later than the beginning of

the coordination transaction:

(i) whether it will purchase or return

emissions allowances; and

(ii) if it will return emissions

allowances, the date on which those

allowances will be returned.

(2) Public utilities may include in

agreements with purchasing utilities

non-discriminatory provisions for

indemnification if the purchasing utility

fails to provide emissions allowances by

the date on which it declares that the

allowances will be returned.

* * * * *

[FR Doc. 95–10718 Filed 5–4–95; 8:45 am]

BILLING CODE 6717–01–M

RAILROAD RETIREMENT BOARD

20 CFR Parts 226 and 232

RIN 3220–AA58

Computing Employee, Spouse, and

Divorced Spouse Annuities

AGENCY: Railroad Retirement Board.

ACTION: Final rule.

SUMMARY: The Railroad Retirement

Board (Board) hereby revises its

regulations dealing with the

computation of retirement annuities

under the Railroad Retirement Act of

1974 (Act). The regulations regarding

the computation of these annuities,

which are being replaced, were

promulgated under the Railroad

Retirement Act of 1937 and no longer

reflect the computational provisions

contained in the Act.

EFFECTIVE DATE: May 5, 1995.

ADDRESSES: Secretary to the Board,

Railroad Retirement Board, 844 North

Rush Street, Chicago, Illinois 60611.

FOR FURTHER INFORMATION CONTACT:

Thomas W. Sadler, Assistant General

Counsel, Railroad Retirement Board,

844 North Rush Street, Chicago, Illinois

60611, telephone (312) 751–4513, TTD

(312) 751–4701.

SUPPLEMENTARY INFORMATION: The

revision to part 226 (formerly

‘‘Computation of Annuity’’) provides

the rules for computing the amount of

the employee, spouse and divorced

spouse annuity, under the Railroad

Retirement Act of 1974. In general, the

annuity consists of two components or

tiers. The first tier (tier I) is a social

security level benefit that is computed

under social security rules based on the

employee’s earnings under both the

railroad retirement and the social

security systems and is reduced by the

amount of any social security benefit

payable. The second tier (tier II) is based

solely on the employee’s railroad

earnings.

In limited circumstances the

employee annuity may be increased by

a ‘‘vested dual benefit’’. An employee

who has completed 25 years of railroad

service may also be eligible for a

supplemental annuity.

The rule is divided into seven (7)

subparts:

Subpart A sets forth definitions and

lists other regulations related to this

part.

Subpart B describes the computation

of the employee annuity which includes

the social security level component (tier

I) (§ 226.10), the component based

solely on railroad service (tier II)

(§ 226.11); the vested dual benefit

(§ 226.12), and a supplemental annuity

(§ 226.16). Section 226.13 describes how

cost-of-living increases apply to the

annuity.

Subpart C (§§ 226.30–226.35) parallels

subpart B and describes the

computation of the spouse and divorced

spouse annuities. However, the

divorced spouse is not entitled to a tier

II benefit and no supplemental annuity

or vested dual benefits are payable to

spouses. Section 226.31 explains how

the spouse and divorced spouse annuity

are reduced due to receipt of a public

pension which was not based upon

employment covered by the Social

Security Act on the last day of

employment.

Subpart D (§§ 226.50–226.52)

describes the Railroad Retirement

Family Maximum which is a statutory

‘‘cap’’ placed upon the total benefits

payable under the RRA. Section 226.51

describes how the maximum is

determined (the higher of $1,200 or an

amount based upon the employee’s final

average monthly compensation

(FAMC)). Section 226.52 describes how

the ‘‘reduction amount’’ is computed

when the maximum is exceeded and

§ 226.50 describes how the spouse, then

the employee annuity is reduced until

the total employee and spouse annuity

equal the maximum. The railroad

retirement maximum is computed at the

employee’s annuity beginning date but

will be recomputed if the spouse later

divorces the employee or the employee

later becomes entitled to a vested dual

benefit or supplemental annuity. A

divorced spouse annuity is not counted

in determining whether the RRA

maximum is exceeded.

Subpart E (§§ 226.60–226.63) explains

how years of service and average

monthly compensation (AMC) are

determined. The tier II of the employee

annuity is seven tenths of 1% (.007)

times the product of an employee’s

years of service times his or her AMC.

The spouse’s tier II is 45% of the

employee’s tier II. See §§ 226.11 and

226.32.

Subpart F (§§ 226.70–226.74)

describes the reduction required due to

receipt of workers’ compensation

benefits. The tier I of an employee,

spouse, or divorced spouse annuity is

reduced if the employee is under age 65

and is entitled to a disability annuity

and another periodic benefit based upon

disability pursuant to some other

Federal or state law or plan (§ 226.70).

The reduction amount is first applied to

the tier I of any spouse or divorced

spouse annuity payable, then to the

employee tier I (§ 226.71). Certain

disability payments do not cause a

reduction. These are listed in § 226.72.

The formula for the reduction amount

is found at § 226.71. The reduction

provided for in this part applies if the

total tier I components payable to the

employee and spouse (or divorced

spouse) plus workers’ compensation or

public disability benefit exceed 80% of

the employee’s prior average current

earnings. Section 226.73 explains what

events cause a change in the reduction

amount. Section 226.74 provides that

‘‘average current earnings’’ must be

recomputed periodically to take into

account inflation. The redetermined

average current earnings are used only

if it results in a lower reduction amount.

Subpart G of the rule (§§ 226.90–

226.92) explains how and when an

annuity is recomputed to take into

account railroad service and social

security earnings after an annuitant

retires.

PART 232—SPOUSES’ ANNUITIES is

obsolete and is removed.

On February 9, 1995, the Board

published this rule as a proposed rule

(60 FR 7729), inviting comments on or

before March 13, 1995. No comments

were received.

The Board, in conjunction with the

Office of Management and Budget, has

determined that this is not a significant

regulatory action under Executive Order

12866; therefore, no regulatory impact

analysis is required. There are no

information collections associated with

this rule.