21132 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

Anyone wishing to object to the grant

of this license has 60 days from the date

of this notice to file written objections

along with supporting evidence, if any.

Written objections are to be filed with

the Office of Naval Research, ONR

00CC, Ballston Tower One, Arlington,

Virginia 22217–5660.

FOR FURTHER INFORMATION CONTACT: Mr.

R.J. Erickson, Staff Patent Attorney,

Office of Naval Research, ONR 00CC,

Ballston Tower One, 800 North Quincy

Street, Arlington, Virginia 22217–5660,

telephone (703) 696–4001.

Dated: April 21, 1995.

M.D. Schetzsle,

LT, JAGC, USNR, Alternate Federal Register

Liaison Officer.

[FR Doc. 95–10553 Filed 4–28–95; 8:45 am]

BILLING CODE 3810–AE–M

DEPARTMENT OF ENERGY

Bonneville Power Administration 1995

Wholesale Power and Transmission

Rates, Variable Industrial Power Rate

Extension (VI–95), and Pacific

Northwest Coordination Agreement

(PNCA) Rates

AGENCY: Bonneville Power

Administration (BPA), DOE.

ACTION: Availability of proposed 1995

wholesale power and transmission rates,

variable industrial rate extension (VI–

95), Pacific Northwest Coordination

Agreement (PNCA) Rates, and order

establishing schedule.

SUMMARY: BPA File No: WP–95/TR–95,

WP–96, TR–96, TC–96. On December

28, 1994, Bonneville Power

Administration (BPA) published a

Notice of Intent to Revise Transmission

Rates, 59 FR 66946 (1994), and Notice

of Intent to Revise Wholesale Power

Rates, 59 FR 66947 (1994).

Subsequently, BPA published Federal

Register Notices of Proposed Wholesale

Power Rate Adjustment, 60 FR 8496

(1995), Proposed Transmission Rate

Adjustment, 60 FR 8505 (1995), and

Hearing and Opportunity for Public

Comment Regarding Proposed

Comparable Transmission Terms and

Conditions, 60 FR 8511 (1995). On

March 3, 1995, BPA published a Notice

of Additional Prehearing/Settlement

Conference for March 15, 1995, 60 FR

11962 (1995). At that prehearing

conference, the Hearing Officers were

expected to act on several procedural

matters and to establish a procedural

schedule. The March 3, 1995, Notice

also included schedules for a New Rates

and Terms and Conditions Proceeding

and for an Extension of Current Rates

Proceeding. Notice also was given that

some issues might be settled by the

litigants, causing the proposed schedule

to change.

At the Prehearing/Settlement

Conference on March 15, 1995, the

litigants reported to Hearing Officers

about settlement discussions that had

been taking place between BPA and its

customers. The parties requested, and

the Hearing Officers allowed, additional

time to complete the settlement process.

The Hearing Officers set an additional

Scheduling Conference for March 22,

1995, at which time parties to the rate

case would be asked to report on the

status of the settlement and the Hearing

Officers would rule on procedural

matters. On March 17, 1995, most

parties to the rate case signed a

Settlement Agreement agreeing that

BPA would propose to surcharge BPA’s

current rates for a 1-year period, October

1, 1995, through September 30, 1996,

and to extend the Variable Industrial

Power (VI) rate which was scheduled to

expire on June 30, 1996, through

September 30, 1996. The parties also

agreed to establish a separate

subsequent process to establish a 2-year

rate proposal, a 5-year rate proposal,

and a proposal for transmission services

terms and conditions.

By this notice, BPA announces its

proposed 1995 rates to be effective for

1 year beginning on October 1, 1995,

and extending through September 1996,

and its proposed rates for transactions

under the Pacific Northwest

Coordination Agreement (PNCA). BPA

will publish a separate notice in the

Federal Register to announce its

proposed new power and transmission

rates to be effective on October 1, 1996,

including new 2- and 5-year rates, and

its new transmission services terms and

conditions on or around the July 10,

1995, Filing Date established for Docket

Numbers WP–96, TR–96, and TC–96.

In separate orders issued March 22,

1995, the Hearing Officers: (1) adopted

a service list for BPA’s 1995 Wholesale

Power and Transmission Rate

Adjustment Proceeding, 1996 Wholesale

Power and Transmission Rate

Adjustment Proceeding and 1996

Transmission Terms and Conditions

Proceedings; and (2) adopted other

procedural rules governing these

proceedings. Copies of all orders,

including the Order Establishing

Schedules, may be obtained by

contacting: Francis (Jamie) Troy,

Hearing Clerk—LQ, Bonneville Power

Administration, 905 NE. 11th Ave., PO

Box 12999, Portland, Oregon 97212.

Schedule for WP–95/TR–95:

May 1, 1995—BPA Files Direct Case

May 30, 1995—Parties File Direct Case

June 9, 1995—Close of Participant

Comments

June 19, 1995—Litigants File Rebuttal

Testimony

June 30, 1995—Cross-Examination

July 10, 1995—Initial Briefs Filed

July 31, 1995—Final Record of Decision

Schedule for WP–96/TR–96 and TC–

96:

July 10, 1995—BPA Files Direct Case/

Prehearing Conference

September 8, 1995—Parties File Direct

Case

October 2, 1995—Close of Participant

Comments

October 25, 1995—Litigants File

Rebuttal Testimony/BPA

Supplemental Testimony

December 4, 1995—Litigants File

Rebuttal to Supplemental Testimony

January 3–February 3, 1996—CrossExamination

February 21, 1996—Initial Briefs Filed

February 28, 1996—Oral Argument

March 25, 1996—BPA Draft Record of

Decision/Hearing Officers

Recommended Decision

April 15, 1996—Briefs on Exceptions

April 30, 1996—Final Record of

Decision

BPA also will be conducting public

field hearings. A notice of the dates,

times, and locations of the field hearings

will be made later through mailings and

public advertising.

ADDRESSES: Written comments by

participants must be received by June 9,

1995, for WP–95/TR–95 and by October

2, 1995, for WP–96/TR–96/TC–96 to be

considered in the Record of Decision

(ROD). Written comments should be

submitted to the Manager, Corporate

Communications—CK; Bonneville

Power Administration; PO Box 12999;

Portland, Oregon 97212.

FOR FURTHER INFORMATION CONTACT: Mr.

Michael Hansen, Public Involvement

and Information Specialist, at the

address listed immediately above, (503)

230–4328 or call toll-free 1–800–622–

4519. Information also may be obtained

from:

Mr. Steve Hickok; Group Vice President,

Sales and Customer Service; PO Box

3621; Portland, OR 97232 (503–230–

5356)

Mr. George Eskridge; Manager, SE Sales

and Customer Service District; 1101

W. River, Suite 250; Boise, ID 83702

(208–334–9137)

Mr. Ken Hustad; Manager, NE Sales and

Customer Service District; Crescent

Court, Suite 500; 707 Main; Spokane,

WA 99201 (509–353–2518)

Ms. Ruth Bennett; Manager, SW Sales

and Customer Service District; 703
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21133

Broadway; Vancouver, WA 98660

(360–418–8600)

Ms. Marg Nelson; Manager, NW Sales

and Customer Service District; 201

Queen Anne Ave. N., Suite 400;

Seattle, WA 98109–1030 (206–216–

4272).

Responsible Official: Mr. Geoff

Moorman, Manager for Pricing,

Marginal Cost and Ratemaking, is the

official responsible for the development

of BPA’s rates. Mr. Dennis Metcalf, BPA

Transmission Team Lead, is the official

responsible for the development of

BPA’s transmission terms and

conditions.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction

II. Background

III. Major Studies

IV. Wholesale Power Rate Schedules and

General Rate Schedule Provisions

A. Introduction

B. Summary of Rate Schedules

C. Wholesale Power Rate Schedules

D. General Rate Schedule Provisions

(GRSPs)

V. Transmission Rate Schedules and General

Transmission Rate Schedule Provisions

(GTRSPs)

A. Summary of Rate Schedules

B. Transmission Rate Schedules

C. General Transmission Rate Schedule

Provisions (GTRSPs)

VI. Charges Under the Amended and

Integrated Pacific Northwest

Coordination Agreement

I. Introduction

Prior to the March 15, 1995,

prehearing conference, BPA determined

that its initial proposal should include

new 2-year and 5-year rates. On

February 14, 1995, BPA published a

preliminary rate proposal in the Federal

Register, 60 FR 8496. In that proposal,

BPA noted that competitive forces are

causing a fundamental and significant

change in the Pacific Northwest

wholesale power market. In light of

these competitive forces, BPA

determined that its initial proposal

should include a 5-year rate as well as

a 2-year rate. BPA anticipated that the

work necessary to develop such a

proposal would take until July of 1995.

As part of the settlement discussions,

the parties expressed a need for

additional time to respond to BPA’s new

rate designs. BPA believes that without

an adjustment to its wholesale and

transmission rates for the period

October 1, 1995, through September 30,

1996, BPA’s ability to satisfy its

statutory obligations could be impaired.

The rate case schedule adopted by the

Hearing Officers on March 22, 1995,

meets both BPA’s and the parties’ needs.

The schedule affords the parties a

hearing process that encompasses a

period of eight months for establishment

of BPA new rate designs including new

2- and 5-year rates. The effective date

for the establishment of new 2- and 5-

year rates is October 1, 1996.

In order to have sufficient time to

conduct a full rate proceeding for new

2- and 5-year rate proposals, BPA and

most parties to the 1995 rate proceeding

agreed that BPA would propose to

extend BPA’s current adjustable rates

with a 4 percent surcharge for a 1-year

period, October 1, 1995, through

September 30, 1996. The extension of

rates requires a separate expedited

proceeding and procedural schedule.

After the March 22, 1995, Scheduling

Conference, the Hearing Officers issued

an Order (the March 22 order) that

divided the proceedings previously

designated as WP–95, TR–95, and TC–

95 into three separate dockets as

follows:

(1) The 1995 Wholesale Power and

Transmission Rates Proceeding is

designated WP–95/TR–95, and will be a

90-day expedited rate proceeding

conducted pursuant to section 1010.10

of the Procedures Governing Bonneville

Power Administration Rate Hearings, 51

FR 7611 (1986) (hereinafter Procedures).

This proceeding will extend current

rates with a surcharge and establish the

3rd AC, annual cost rate, and the Pacific

Northwest Coordination Agreement

(PNCA) rate.

(2) The March 22 Order also

established a subsequent 8 month

procedural schedule beginning July 10,

1995, to establish BPA’s power and

transmission rates for the period

beginning October 1, 1996, and new

transmission services terms and

conditions. The 1996 Wholesale Power

Proceeding is designated WP–96, and

Transmission Rates Proceeding is

designated TR–96 and both will be

conducted pursuant to section 1010.9 of

the Procedures.

(3) The 1996 Transmission Services

Terms and Conditions Proceeding is

designated TC–96 and will be

conducted pursuant to section 1010.9 of

the Procedures concurrently with WP–

96/TR–96.

In the March 22 Order, the Hearing

Officers ruled that after March 22, 1995,

separate official records will be

maintained and separate decisions will

be issued for each of the three

proceedings designated above. In

addition, the Hearing Officers ruled that

intervenors who intervened in the

dockets designated WP–95/TR–95 and

TC–95 on or before March 15, 1995,

were admitted as parties for all

proceedings noted above.

Finally, the Hearing Officers

established the final rate case schedules

for Docket Numbers WP–95/TR–95,

WP–96/TR–96, and TC–96. The

schedule established by the Hearing

Officers for Docket Number WP–95/TR–

95 provides an opportunity for

interested persons to review BPA

proposed rates, to participate in the rate

hearing, and to submit oral and written

comments. All comments and

documents intended to become part of

the Official Record in this process

should contain the file number

designation WP–95/TR–95.

Consideration of comments may result

in a final rate proposal differing from

the rates proposed in this Notice.

II. Background

The Pacific Northwest Electric Power

Planning and Conservation Act

(Northwest Power Act) provides that

BPA must establish and periodically

review its rates so that they are adequate

to recover, in accordance with sound

business principles, the costs associated

with the acquisition, conservation, and

transmission of electric power, and to

recover the Federal investment in the

Federal Columbia River Power System

(FCRPS) and other costs incurred by

BPA.

On March 9, 1995, BPA published in

the Federal Register a notice of

availability of BPA’s preliminary

proposed Wholesale Power and

Transmission Rate schedules, 60 FR

12915. Since that time, BPA has

continued to study the adequacy of its

preliminary rate proposal, including its

proposal to tier rates for requirements

service. On March 17, 1995, BPA and

most parties to the 1995 rate

proceedings agreed to a settlement

whereby BPA would propose that

current rates be extended for 1 year and

surcharged 4 percent to meet BPA

revenue requirements. The Settlement

Agreement was an attempt to balance a

number of interests, including concerns

expressed by customer representatives

to BPA’s Power Sale Contract

renegotiations. These representatives

suggested that BPA’s new Power Sales

Contracts and new rate structures

should be coordinated to allow

customers to carefully consider the new

rates and contracts package in detail

before making any long-term

commitments.

BPA’s initial proposal for the 1995

rate case proposes to surcharge by 4

percent each component of its current

adjustable rates, including a Variable

Industrial Power (VI) rate extended

through September 30, 1996, for 1 year,

from October 1, 1995, through

September 30, 1996.
21134 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

III. Major Studies

The studies that have been prepared

to support the 1995 initial proposal will

be served on all parties of record and

available for examination on May 1,

1995, at BPA’s Public Information

Center, BPA Headquarters Building, 1st

Floor; 905 NE. 11th, Portland, OR. The

studies and documents are:

A. Loads and Resources Study and

Documentation

B. Revenue Requirement Study and

Documentation

C. Revenue Forecast Study and

Documentation

D. Section 7(b)(2) Rate Test Study and

Documentation

To request any of the above

documents by telephone, call BPA’s

document request line: (503) 230–3478

or call toll-free 1–800–622–4520. Please

request the document by its above-listed

title. Also state whether you require the

accompanying documentation (these

can be quite lengthy); otherwise, the

study alone will be provided. (For

example, ask for the ‘‘Revenue

Requirement Study and

Documentation.’’)

A. Loads and Resources Study

BPA’s forecasts of regional loads by

customer group are the basis from

which public utility and direct service

industry (DSI) customer purchases from

BPA (Federal system firm loads) are

projected. BPA also projects Federal

transmission losses, obligations to

regional investor-owned utilities (IOUs)

under their power sales contracts, and

other inter- and intraregional

contractual obligations.

BPA develops forecasts of regional

non- and small generating public utility

(NSGPU) and generating public utility

(GPU) loads using standard econometric

techniques. Regional NSGPU and GPU

loads are forecasted as a function of

average retail electricity prices, weatherrelated variables, and nonagricultural

employment. The regional load forecasts

then are adjusted to account for factors

such as effects from conservation

programs and utility purchases from

alternative (non-BPA) power suppliers

to derive a projection of NSGPU and

GPU purchases from BPA. The IOU load

forecast was produced by updating the

economic assumptions from the 1991

joint BPA/Northwest Power Planning

Council (NPPC) forecast.

Forecasts of aluminum DSI purchases

from BPA are prepared by analyzing

smelter production costs relative to

aluminum prices, and by considering

other factors affecting smelter loads,

including DSI purchases from

alternative (non-BPA) power suppliers.

Forecasted non-aluminum DSI

purchases from BPA are prepared by

analyzing historical and technical plant

information, forecasted market

conditions, and potential purchases

from alternative power suppliers.

BPA’s resource acquisition plans are

based on work by BPA and the NPPC

staff and reflect extensive input and

review by the general public and the

region’s utilities. The specific resource

acquisitions and associated costs

included in this proposal are based on

BPA’s 1994 Draft Strategic Business

Plan. Besides emphasizing a diverse

resource portfolio, including both

conservation and generating resources,

BPA is committed to moving toward a

blend of acquisition methods, including

BPA-designed, utility-designed, and

developer-initiated programs. This

combination of resource diversity and

acquisition approaches allows BPA to

better deal with varying circumstances

and uncertainties.

The ratemaking load/resource balance

represents BPA’s projected service to

firm loads during the test years under

1930 water conditions. The ratemaking

load/resource balance is used in the

calculation of the supply of surplus firm

power in the region and on the Federal

system during the test period. A related

hydro regulation study incorporates the

operation of thermal plants, exports and

imports of power, projected resource

acquisitions, and system constraints

such as the Columbia River flow

augmentation project and ‘‘spill.’’ For

this proposal, a 50-year hydro study was

completed, which includes assumptions

regarding the Columbia River flow

augmentation. The hydro study starts in

August 1995. The 50-year study

determines expected nonfirm energy

availability for the region.

B. Revenue Requirement Study

The Bonneville Project Act, the Flood

Control Act of 1944, the Transmission

System Act, and the Northwest Power

Act require BPA to set rates that are

projected to collect revenues sufficient

to recover the cost of acquiring,

conserving, and transmitting the electric

power that BPA markets, including

amortization of the Federal investment

in the FCRPS over a reasonable period,

and to recover BPA’s other costs and

expenses. The Revenue Requirement

Study includes a demonstration of

whether current rates will produce

enough revenues to recover all BPA

costs and expenses, including BPA’s

repayment requirements to the U.S.

Treasury. Revenue requirements are a

major factor in determining the overall

level of BPA’s proposed power and

transmission rates.

The Transmission System Act and the

Northwest Power Act require that

transmission rates be based on an

equitable allocation of the costs of the

Federal transmission system between

Federal and non-Federal power using

the system. In compliance with a FERC

order dated January 27, 1984, 26 FERC

¶ 61,096, the Revenue Requirement

Study incorporates the results of

separate repayment studies for the

generation and transmission

components of the FCRPS. The

repayment studies for generation and

transmission demonstrate the adequacy

of the projected revenues at proposed

rates to recover the Federal investment

in the FCRPS over the allowable

repayment period. Separate generation

and transmission revenue requirements

are developed in the Revenue

Requirement Study. The adequacy of

projected revenues to recover test period

revenue requirements and to meet

repayment period recovery of the

Federal investment is tested and

demonstrated separately for the

generation and transmission functions.

The Revenue Requirement Study for

the 1995 initial rate proposal is based on

cost and revenue estimates for FY 1996.

The cost estimates include an

undistributed reduction of $80 million.

This reflects BPA’s decision to reduce

revenue requirements by this amount to

enable it to set rates at a level which

recover its costs but also meet current

market conditions, although specific

program and/or organizational spending

cuts have not been finalized. This study

also includes planned net revenues to

mitigate financial risk, to ensure that

cash flows are adequate to demonstrate

timely repayment of the Federal

investment including irrigation

assistance, and finance a portion of

BPA’s capital investments. BPA’s

Revenue Requirement Study reflects

actual amortization and interest

payments paid through September 30,

1994. In addition, it reflects all FCRPS

obligations incurred pursuant to the

Northwest Power Act, including

residential exchange program costs.

Also part of the Revenue Requirement

Study is a risk analysis that evaluates

the impact that various economic and

generation resource capability

conditions could have on BPA’s ability

to make annual U.S. Treasury payments

during the rate test period. It measures

the financial risks surrounding the

revenue and expense forecasts used to

set rates. Results of the risk analysis are

used to determine the amount of

planned net revenue required for risk

mitigation.
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21135

C. Revenue Forecast Study

The revenue forecast determines

BPA’s expected level of sales and

revenue for the rate period, fiscal year

1996. Revenues are forecasted primarily

by applying rates to a load forecast. In

addition, because the load forecast

assumes critical water, and streamflows

usually are greater-than-critical, the

revenue forecast reflects the effect of

greater-than-critical streamflows (the

product of which is secondary energy)

on BPA’s revenues. Secondary energy

affects the revenue forecast by

increasing or decreasing estimated

revenues from the generating public

utilities, direct-service industries, open

market sales, and incidental wheeling.

The revenue forecast is based on the

average of 50 historical water years.

BPA prepares two types of revenue

forecasts: (1) Revenues forecasted under

current rates; and (2) revenues

forecasted under proposed rates. The

rates in effect since October 1993 are

used in the calculation of forecasted

revenues at current rates for the rate test

period, fiscal year 1996. BPA also

develops price forecasts for certain

prices that are not set by the rate

schedules to determine revenues under

the Variable Industrial Power (VI) rate,

for contractual sales of surplus firm

power, for sales at the Nonfirm Energy

rate, and for rates applicable to the

WNP–1 and WNP–3 Exchange

Agreements.

Included in the Revenue Forecast

Study are the proposed wholesale

power and transmission rate schedules,

which are summarized below.

D. Section 7(b)(2) Rate Test Study

Section 7(b)(2) of the Northwest

Power Act directs BPA to assure that the

wholesale power rates effective after

July 1, 1985, to be charged its public

body, cooperative, and Federal agency

customers (the 7(b)(2) customers) for

their general requirements for the rate

test period, plus the ensuing 4 years, are

no higher than the costs of power to

those customers would be for the same

time period if specified assumptions are

made. The effect of the rate test is to

protect the 7(b)(2) customers’ wholesale

firm power rates from certain costs

resulting from provisions of the

Northwest Power Act. The rate test can

result in a reallocation of costs from the

7(b)(2) customers to other rate classes.

The section 7(b)(2) Rate Test Study

describes the application and results of

the section 7(b)(2) rate test

implementation methodology.

The rate projections and the actual

rate test itself are performed using

BPA’s Supply Pricing Model (SPM). The

SPM simulates BPA’s rate development

process, using load, resource, and cost

data consistent with that used in this

rate proposal. The SPM calculates two

sets of wholesale power rates for BPA’s

preference customers: (1) A set of rates

for the test period and the ensuing 4

years, assuming that section 7(b)(2) is

not in effect (program case rates); and

(2) a set for the same period considering

the five assumptions listed in section

7(b)(2) (7(b)(2) case rates). Certain costs

specified in section 7(g) of the

Northwest Power Act (7(g) costs) are

subtracted from the program case rates.

The SPM then discounts each year’s

rates to the test year of the relevant rate

case, averages each set of discounted

rates, and compares the two resulting

averages rounded to the nearest tenth of

a mill. If the average of the discounted

program case rates, less the 7(g) costs, is

larger than the average discounted

7(b)(2) case rates, the rate test triggers.

If the rate test triggers, the amount of

dollars to be reallocated in the test

period (7(b)(2) amount) is calculated by

multiplying the difference between the

discounted program case and 7(b)(2)

case rates by the general requirements

loads of the preference customers. The

7(b)(2) amount, if any, is used as an

adjustment to the allocated costs in the

rate case test period.

IV. Wholesale Power Rate Schedules

and General Rate Schedule Provisions

Table of Contents

Introduction

Summary of Rate Schedules

Wholesale Power Rate Schedules

PF–95. Priority Firm Power Rate

IP–95. Industrial Firm Power Rate

VI–95. Variable Industrial Power Rate

SI–95. Special Industrial Power Rate

CE–95. Emergency Capacity Rate

NR–95. New Resource Firm Power Rate

NF–95. Nonfirm Energy Rate

SS–95. Share-the-Savings Energy Rate

PS–95. Power Shortage Rate

RP–95. Reserve Power Rate

General Rate Schedule Provisions (GRSPs)

Section I. Adoption of Revised Rate

Schedules and General Rate Schedule

Provisions

Section II. Types of BPA Service

Section III. Billing Factors and Billing

Adjustments

Section IV. Other Definitions

Section V. Application of Rates Under

Special Circumstances

Section VI. Billing Information

Section VII. Variable Industrial Rate

Parameters and Adjustments

A. Introduction

The proposed wholesale power rate

schedules are published as part of the

Revenue Forecast Study. BPA agreed in

the Settlement Agreement that its 1995

initial rate proposal would propose to

apply a 4 percent surcharge to each

component of its current adjustable

rates, including the Variable Industrial

Power (VI) rate which BPA would

propose to extend through September

30, 1995. The current VI–91 rate expires

June 30, 1996. BPA also agreed to

propose that the surcharged rates would

be effective for the period October 1,

1995, through September 30, 1996.

Consistent with the Settlement

Agreement, BPA proposes to retain its

current rate design, including most of

the rate adjustments contained in the

1993 Wholesale Power Rate Schedules.

BPA proposes to adjust each rate

component contained in the Priority

Firm Power (PF) rate, Industrial Firm

Power (IP) rate, Variable Industrial

Power (VI) rate, and New Resources

(NR) rate such that the overall effective

rate increase for sales under these rate

schedules is 4 percent. BPA proposes to

increase the demand and energy charges

in these rates by 4 percent and also to

increase by 4 percent the Irrigation

Discount and First Quartile Discount.

BPA proposes to increase the Energy

Return Surcharge based on the changes

in the PF demand charge.

BPA is proposing to retain the current

percentages for the Low Density

Discount and Availability Charge

without further adjustments. Any

change to these rate adjustments could

result in an overall rate increase to

customers different from 4 percent. In

addition, BPA is proposing to maintain

the Unauthorized Increase Charge at its

current level. The Unauthorized

Increase Charge is designed to deter

customers from taking more power than

they are entitled to take. The level of

current Unauthorized Increase Charge

achieves that purpose and as such a

further increase is unnecessary.

BPA has some long-term contract

rates that are tied to changes in BPA’s

PF rate. BPA is proposing to increase

these rates by 4 percent. In addition,

BPA has rates that depend on changes

in BPA’s Average System Cost (BASC).

BPA also is proposing to increase BASC

by 4 percent and consequently any rates

that are based on changes in BASC also

will be increased by 4 percent.

BPA also proposes to adjust the rate

components contained in its Emergency

Capacity (CE) rate and Nonfirm Energy

rate schedules. Since the price BPA can

obtain from these rates is based on

market conditions, these rate schedules

do not contain fixed rates but rather

contain caps or ceilings. BPA proposes

to increase the CE rate cap and the

Intertie Charge by 4 percent. In the NF

rate, BPA is proposing to increase the
21136 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

average cost of nonfirm energy, which

triggers the Intertie adder charge, and

retain the upper limit on its Standard

nonfirm energy rate by 4 percent. Given

current market conditions, increasing

the cap on the NF Standard rate is not

expected to result in increased revenues

during the rate period. BPA also is

proposing to increase the Intertie Charge

and the NF Contract rate by 4 percent.

BPA is proposing to extend the

Reserve Power (RP) rate, the Share-theSavings (SS) rate and the Power

Shortage (PS) rate unchanged for the 1

year period. These rates normally are

not adjusted to reflect changes in BPA’s

costs. The RP rate is based on BPA’s

estimate of its long-term marginal cost.

This rate has not been adjusted since

1987. The SS rate is an experimental

nonfirm energy rate that allows for a

mutually agreed-to formula rate. The PS

rate is a contractually agreed-to rate and

is available for sales under the Shortage

Agreement. The parties to the Shortage

Agreement recently agreed to extend

that agreement for another year.

Unlike its other rates, BPA’s current

Surplus Power (SP–93) rate does not

expire on September 30, 1995. FERC has

approved the SP–93 rate through

September 30, 1998. 67 FERC ¶ 61351

(June 20, 1994). Therefore, since the SP

rate continues to be in effect during the

1-year rate period, BPA proposes to

retain its current SP–93 rate and not

refile a new SP rate for the 1-year rate

period agreed to in the Settlement

Agreement. The current SP–93 rate

contains a contract rate and a flexible

rate. BPA does not expect to make any

sales at the contract rate during the rate

period. The flexible rate is capped at

BPA’s highest cost resource, which is

significantly above the expected market

price during the rate period. As such

increasing the SP flexible rate by 4

percent would not advance the

settlement’s cost recovery objectives.

B. Summary of Rate Schedules

A summary of the proposed 1995

Wholesale Power Rate Schedules is

provided below. Each of the rate

schedules includes sections specifying

the customer class and the service

available under the rate schedule, the

rates for the sales offered under the

schedule, the billing factors, other

special provisions for rate adjustments,

such discounts or penalties that apply to

that rate schedule, and the cost basis of

the rates in the schedule (resource

contribution). Because the 1995 rates

will be effective for a 1-year period, BPA

is not proposing an Interim Rate

Adjustment for these rates.

1. Priority Firm Power rate: The

proposed Priority Firm Power (PF–95)

rate schedule would replace the PF–93

rate schedule. Power is available under

the PF–95 rate schedule to public

bodies, cooperatives, Federal agencies,

and utilities participating in the

residential exchange under section 5(c)

of the Northwest Power Act. Priority

Firm power must be used to meet firm

loads within the Pacific Northwest. The

PF rate consists of diurnally

differentiated demand charges and

seasonally differentiated energy charges.

Other rate adjustments include an

Irrigation Discount, a Low Density

Discount, an Energy Return Surcharge,

Unauthorized Increase Charge,

Conservation Surcharge, Outage Credit

and Power Factor Adjustment.

2. New Resource Firm Power rate: The

proposed New Resource Firm Power

(NR–95) rate schedule would replace

the NR–93 rate schedule. The NR–95

rate schedule is available to investorowned utilities under net requirements

contracts for resale to consumers, and to

publicly owned utilities for New Large

Single Loads. The NR rate consists of

diurnally differentiated demand charges

and seasonally differentiated energy

charges. Other rate adjustments include

an Irrigation Discount, a Low Density

Discount, an Energy Return Surcharge,

Unauthorized Increase Charge,

Conservation Surcharge, Outage Credit

and Power Factor Adjustment.

3. Industrial Firm Power rate: The

proposed Industrial Firm Power Rate

(IP–95) rate would replace the IP–93

rate. The IP–95 rate schedule is

available to BPA’s direct-service

industrial customers for firm power to

be used in their industrial operations.

The IP rate consists of diurnally

differentiated demand charges and

seasonally differentiated energy charges.

Other rate adjustments include a First

Quartile Discount, Curtailment Charge,

Unauthorized Increase Charge, Outage

Credit and Power Factor Adjustment.

4. Variable Industrial Power rate: The

Variable Industrial Power (VI–95) rate

schedule is available to DSIs purchasing

from BPA under the 1986 Variable Rate

Contract. The proposed VI–95 rate

schedule is unchanged from prior years

other than to update the rates and rate

parameters based on the rate adjustment

criteria established in 1991 and the 1995

rate case. The proposed base rate

components of the VI–95 rate include

the 4 percent surcharge, as do the First

Quartile Discount and the Lower and

Upper Rate Limits. The Lower and

Upper Pivot Aluminum Prices are those

that were effective July 1, 1995,

pursuant to the VI–91 rate. They will be

adjusted again on July 1, 1996. The VI

rate is proposed to be extended three

months past its expiration date, June 30,

1996, so that its term will be consistent

with the other rates proposed for fiscal

year 1996. The term of the proposed VI–

95 rate thus would be October 1, 1995,

through September 30, 1996.

5. Special Industrial Power rate: The

proposed Special Industrial Power (SI–

95) rate would replace the SI–93 rate.

The SI rate is available to any DSI

purchaser which uses a raw mineral

indigenous to the region as its primary

resource and which qualifies for the

special rate under the procedures

established in section 7(d)(2) of the

Northwest Power Act. The SI rate

consists of diurnally differentiated

demand charges and seasonally

differentiated energy charges. Other rate

adjustments include a Curtailment

Charge, Unauthorized Increase Charge,

Outage Credit, and Power Factor

Adjustment.

6. Nonfirm Energy rate: The proposed

Nonfirm Energy (NF–95) rate schedule

replaces the NF–93 rate. The NF–95 rate

schedule is available for purchases of

nonfirm energy inside and outside the

Pacific Northwest for resale to

consumers, direct consumption, and

resale under Western Systems Power

Pool agreements. The NF–95 rate

schedule includes four rate components:

A flexible Standard rate, a flexible

Market Expansion rate, a flexible

Incremental rate, and a fixed Contract

rate. Other adjustments include a

Guaranteed Surcharge and an Intertie

Charge. The NF Rate Cap continues to

apply to all sales under the NF–95 rate

schedule. The NF Rate Cap defines the

maximum nonfirm energy price for

general application. The level of the NF

Rate Cap is based on a formula tied to

BPA’s Average System Cost and

California fuel costs.

7. The Reserve Power rate: The

Reserve Power (RP–95) rate schedule

replaces the RP–93 rate schedule. The

RP rate is available in cases where a

purchaser’s power sales contract states

that the rate for Reserve Power shall be

applied; when BPA determines no other

rate schedule is applicable; or to serve

a purchaser’s firm power load when

BPA does not have a power sales

contract in force with such a purchaser,

and BPA determines that this rate

should be applied. The RP rate consists

of diurnally differentiated demand

charges and a flat energy charge. Other

rate adjustments include a Power Factor

Adjustment.

8. The Power Shortage rate: The

Power Shortage (PS–95) rate schedule is

available for sales under the Share-theShortage agreement or when BPA

arranges for purchased energy at the

request of a Northwest customer. BPA is

not obligated to make Shortage Power
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21137

available or to broker power under the

PS–95 rate schedule unless specified by

contract. The PS rate contains two rate

components: a flexible Power Rate not

to exceed 100 mills/kWh and a flexible

Brokering Rate not to exceed 1 mill/

kWh. Other rate adjustments include a

Power Factor Adjustment.

C. Wholesale Power Rate Schedules

Schedule PF–95

Priority Firm Power Rate

Section I. Availability

This schedule is available for the

contract purchase of firm power or

capacity to be used within the Pacific

Northwest. Priority Firm Power may be

purchased by public bodies,

cooperatives, and Federal agencies for

resale to ultimate consumers for direct

consumption, construction, test and

startup, and station service.

Utilities participating in the exchange

under section 5(c) of the Northwest

Power Act may purchase Priority Firm

Power pursuant to their Residential

Purchase and Sale Agreements.

In addition, BPA may make power

available to those parties participating

in exchange agreements which use this

rate schedule as the basis for

determining the amount or value of

power to be exchanged.

This schedule supersedes Schedule

PF–93, which went into effect on

October 1, 1993. Sales under this

schedule are made subject to BPA’s

General Rate Schedule Provisions

(GRSPs).

Section II. Rate

This rate schedule includes the

Preference rate and the Exchange rate.

The Preference rate is available for the

general requirements of public body,

cooperative and Federal agency

customers. The Exchange rate is

available for all purchases of residential

and small farm exchange power

pursuant to the Residential Purchase

and Sale Agreements.

A. Preference Rate

1. Demand Charge

a. $4.307 per kilowatt of billing

demand occurring during all Peak

Period hours during a billing month.

b. No demand charge during Offpeak

Period hours during a billing month.

2. Energy Charge

a. 23.06 mills per kilowatt-hour of

billing energy for the billing months

September through March.

b. 16.94 mills per kilowatt-hour of

billing energy for the billing months

April through August.

B. Exchange Rate

1. Demand Charge

a. $4.307 per kilowatt of billing

demand occurring during all Peak

Period hours during a billing month.

b. No demand charge during Offpeak

Period hours during a billing month.

2. Energy Charge

a. 23.06 mills per kilowatt-hour of

billing energy for the billing months

September through March.

b. 16.94 mills per kilowatt-hour of

billing energy for the billing months

April through August.

Section III. Billing Factors

In this section, billing factors are

listed for each of the following types of

purchasers: computed requirements

purchasers (section III.A), purchasers of

residential exchange power pursuant to

the Residential Purchase and Sale

Agreements (section III.B), and metered

requirements purchasers and those

Priority Firm Power purchasers not

covered by sections III.A and III.B

(section III.C).

A. Computed Requirements Purchasers

Purchasers designated by BPA as

computed requirements purchasers

pursuant to power sales contracts shall

be billed in accordance with the

provisions of this subsection.

1. Billing Demand

The billing demand for actual,

planned, and contracted computed

requirements purchasers shall be the

higher of the billing factors ‘‘a’’ and ‘‘b,’’

below:

a. The lower of:

(1) The larger of the Computed Peak

Requirement or the Computed Average

Energy Requirement; or

(2) The Measured Demand, before

adjustment for power factor.

b. The lower of:

(1) The Computed Peak Requirement;

or

(2) 60 percent of the highest

Computed Peak Requirement during the

previous 11 billing months (Ratchet

Demand).

2. Billing Energy

The billing energy for actual, planned,

and contracted computed requirements

purchasers shall be:

a. For the months September through

March, the sum of:

(1) 76 percent of the Measured Energy

(excluding unauthorized increase); and

(2) 24 percent of the Computed

Energy Maximum.

b. For the months April through

August, the sum of:

(1) 63 percent of the Measured Energy

(excluding unauthorized increase); and

(2) 37 percent of the Computed

Energy Maximum.

B. Purchasers of Residential Exchange

Power

Purchasers buying Priority Firm

Power under the terms of a Residential

Purchase and Sale Agreement shall be

billed as follows:

1. Billing Demand

The billing demand shall be the

demand calculated by applying the load

factor, determined as specified in the

Residential Purchase and Sale

Agreement, to the billing energy for

each billing period.

2. Billing Energy

The billing energy shall be the energy

associated with the utility’s residential

load for each billing period. Residential

load shall be computed in accordance

with the provisions of the purchaser’s

Residential Purchase and Sale

Agreement.

C. Metered Requirements Purchasers,

Other Purchasers Not Covered by

Sections III.A and III.B, Above

Purchasers designated as metered

requirements customers and purchasers

taking or exchanging power under this

rate schedule who are not otherwise

covered by sections III.A and III.B shall

be billed as follows:

1. Billing Demand

The billing demand shall be the

Measured Demand as adjusted for

power factor, unless otherwise specified

in the power sales contract.

2. Billing Energy

The billing energy shall be the

Measured Energy, unless otherwise

specified in the power sales contract.

Section IV. Adjustments And Special

Provisions

A. Power Factor Adjustment

The adjustment for power factor,

when specified in this rate schedule or

in the power sales contract, shall be

made in accordance with the provisions

of both this section and section III.C.1

of the GRSPs. The adjustment shall be

made if the average leading power factor

or average lagging power factor at which

energy is supplied during the billing

month is less than 95 percent.

To make the power factor adjustment,

BPA shall increase the billing demand

by 1 percentage point for each

percentage point or major fraction

thereof (0.5 or greater) by which the

average leading power factor or average
21138 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

lagging power factor is below 95

percent. BPA may elect to waive the

adjustment for power factor in whole or

in part.

B. Low Density Discount (LDD)

BPA shall apply a discount to the

charges for all Priority Firm Power sold

to purchasers who are eligible for an

LDD. Eligibility for the LDD and the

amount of the discount (3, 5, or 7

percent) shall be determined pursuant

to section III.C.3 of the GRSPs.

C. Irrigation Discount

BPA shall apply an irrigation

discount, equal to 4.90 mills per

kilowatt-hour, to the charges for

qualifying energy purchased under this

rate schedule. The irrigation discount

shall be applied after calculation of the

LDD. The discount shall apply only to

energy purchased during the billing

months of April through October.

Eligibility for the irrigation discount and

reporting requirements shall be

determined pursuant to section III.C.4 of

the GRSPs.

D. Conservation Surcharge

The Northwest Power Planning

Council has recommended that a

conservation surcharge be imposed on

those customers subject to such

surcharge as determined by the

Administrator in accordance with BPA’s

Policy to Implement the CouncilRecommended Conservation Surcharge.

The Conservation Surcharge shall be

applied pursuant to section III.C.6 of the

GRSPs and subsequent to any other rate

adjustments.

E. Outage Credit

Pursuant to section 7 of the General

Contract Provisions, BPA shall provide

an outage credit to any purchaser for

those hours for which BPA is unable to

deliver the full billing demand during

that billing month due to an outage on

the facilities used by BPA to deliver

Priority Firm Power. Such credit shall

not be provided if BPA is able to serve

the purchaser’s load through the use of

alternative facilities or if the outage is

for less than 30 minutes. The amount of

the credit shall be calculated according

to the provisions of section III.C.2 of the

GRSPs.

F. Unauthorized Increase

BPA shall apply the charge for

Unauthorized Increase to any purchaser

of Priority Firm Power taking demand

and energy in excess of its contractual

entitlement.

1. Rate for Unauthorized Increase

a. 100.00 mills per kilowatt-hour

during the billing months August

through March.

b. 57.40 mills per kilowatt-hour

during the billing months April through

July.

2. Calculation of the Amount of

Unauthorized Increase

Each 60-minute clock-hour integrated

or scheduled demand shall be

considered separately in determining

the amount that may be considered an

unauthorized increase. BPA first shall

determine the amount of unauthorized

increase related to demand and shall

treat any remaining unauthorized

increase as energy-related.

a. Unauthorized Increase in Demand

That portion of any Measured

Demand during Peak Period hours,

before adjustment for power factor,

which exceeds the demand that the

purchaser is contractually entitled to

take during the billing month and which

cannot be assigned:

(1) To a class of power that BPA

delivers on such hour pursuant to

contracts between BPA and the

purchaser; or

(2) To a type of power that the

purchaser acquires from sources other

than BPA and that BPA delivers during

such hour, shall be billed:

(a) In accordance with the provisions

of the ‘‘Relief from Overrun’’ exhibit to

the power sales contract; or

(b) If such exhibit does not apply or

is not a part of the purchaser’s power

sales contract, at the rate for

Unauthorized Increase, based on the

amount of energy associated with the

excess demand.

b. Unauthorized Increase in Energy

The amount of Measured Energy

during a billing month which exceeds

the amount of energy which the

purchaser is contractually entitled to

take during that month and which

cannot be assigned:

(1) To a class of power which BPA

delivers during such month pursuant to

contracts between BPA and the

purchaser; or

(2) To a type of power which the

purchaser acquires from sources other

than BPA and which BPA delivers

during such month, shall be billed:

(a) In accordance with the provisions

of the ‘‘Relief from Overrun’’ exhibit to

the power sales contract; or

(b) As unauthorized increase if such

exhibit does not apply or is not a part

of the purchaser’s power sales contract.

G. Coincidental Billing Adjustment

Purchasers of Priority Firm Power

who are billed on a coincidental basis

and who have diversity charges or

diversity factors specified in their power

sales contracts shall have their charges

for billing demand adjusted according to

the provisions of section III.C.5 of the

GRSPs. Computed requirements

purchasers are not subject to the

Coincidental Billing Adjustment for

scheduled power.

H. Energy Return Surcharge

Any purchaser who preschedules in

accordance with sections 2(a)(4) and

2(c)(2) of Exhibit E of the power sales

contract and who returns, during a

single offpeak hour, more than 60

percent of the difference between that

purchaser’s billing demand and

computed average energy requirement

for the billing month shall be subject to

the following surcharge for each

additional kilowatt-hour so returned:

1. 4.25 mills per kilowatt-hour for the

months of April through October;

2. 1.80 mills per kilowatt-hour for the

months of November through March.

Section V. Resource Cost Contribution

BPA has made the following

determinations:

A. The approximate cost contribution

of different resource categories to the

PF–95 rate is 72.2 percent FBS and 27.8

percent Exchange.

B. The forecasted average cost of

resources available to BPA under

average water conditions is 19.80 mills

per kilowatt-hour.

C. The forecasted cost of resources to

meet load growth is 60.64 mills per

kilowatt-hour.

Schedule IP–95

Industrial Firm Power Rate

Section I. Availability

This schedule is available to direct

service industrial (DSI) customers for

both the contract purchase of Industrial

Firm Power and the purchase of

Auxiliary Power if requested by the DSI

customer and made available by BPA. If

a DSI customer purchasing power under

this rate schedule requests and BPA

makes available power under another

applicable wholesale rate schedule, the

IP–95 rate schedule is available for that

portion of power purchased not covered

under the alternative rate schedule. This

rate schedule supersedes Schedule IP–

93, which went into effect on October 1,

1993. Sales under this schedule are

made subject to BPA’s General Rate

Schedule Provisions (GRSPs).
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21139

Section II. Rate

The following rates shall be applied

when first quartile service is provided

under this rate schedule in accordance

with the terms of a purchaser’s Power

Sales Contract dated August 25, 1981. A

separate billing adjustment for the

reserves provided by the purchasers of

Industrial Firm Power is not contained

in this rate schedule; the value of

reserves credit has been included in the

determination of the demand and

energy charges.

Any contractual reference to the IP

Premium rate shall be deemed to refer

to the demand and energy charges set

forth below. Any reference to the IP

Standard rate shall be deemed to refer

to the same demand and energy charges

minus the Discount for Quality of First

Quartile Service.

A. Demand Charge

1. $5.316 per kilowatt of billing

demand occurring during all Peak

Period hours during a billing month.

2. No demand charge during Offpeak

Period hours.

B. Energy Charge

1. 21.90 mills per kilowatt-hour of

billing energy for the billing months

September through March.

2. 18.02 mills per kilowatt-hour of

billing energy for the billing months

April through August.

Section III. Billing Factors

A. Billing Demand

The billing demand shall be the BPA

Operating Level during the Peak Period

as adjusted for power factor. If there is

more than one BPA Operating Level

during the Peak Period within a billing

month, the billing demand shall be a

weighted average of the BPA Operating

Levels during the Peak Period for the

billing month. The BPA Operating Level

is defined in section III.A.10 of the

GRSPs. If BPA has agreed to serve a

portion of a DSI load under an

alternative rate schedule, the billing

demand under the IP–95 rate schedule

shall be specified in the contract

initiating such arrangement.

However, if BPA has agreed, pursuant

to section 4 of the DSI power sales

contract, to sell Industrial Firm Power

on a daily demand basis (transitional

service), then BPA shall bill the

purchaser in accordance with the

provisions of section V.C.3 of the

GRSPs.

B. Billing Energy

The billing energy shall be the

Measured Energy for the billing month,

minus any kilowatt-hours on which

BPA assesses the charge for

unauthorized increase.

However, if BPA has agreed to serve

only a portion of the DSI’s load under

the IP rate schedule, the billing energy

for the power purchased under the IP

rate shall be specified in the contract

initiating such arrangement.

Section IV. Adjustments and Special

Provisions

A. Discount for Quality of First Quartile

Service

1. Application and Amount of First

Quartile Discount

If a purchaser requests discounted

rate service, a discount of 0.72 mills per

kilowatt-hour of billing energy shall be

granted. This billing credit shall be

applied to the monthly billing energy

under section III.B for all power

purchased under this rate schedule. No

credit shall be applied to those

purchases subject to unauthorized

increase charges under section IV.D of

this rate schedule.

2. Eligibility Requirements for First

Quartile Discount

To qualify for the First Quartile

Discount the purchaser must request

discounted rate service in writing by

April 2 of each calendar year. By virtue

of making such request, the Purchaser is

agreeing to accept the level and quality

of First Quartile service described in

section 6 of the Variable Industrial rate

contract. Such acceptance includes the

waiver of contract rights provided in

section 6.a(2)(a) of said contract.

B. Curtailments

BPA shall charge the DSI for

curtailments of the lower three quartiles

in accordance with the provisions of

section 9 of the power sales contract.

BPA shall apply the demand charge in

effect at the time of the curtailment in

the computation of the amount of the

curtailment charge. In the event that a

purchaser is found to be eligible to have

a portion of their load served under an

alternative rate schedule, application of

the curtailment charge shall be specified

in the contract instituting such

arrangement.

C. Unauthorized Increase

1. Rate for Unauthorized Increase

a. 100.00 mills per kilowatt-hour

during billing months August through

March.

b. 57.40 mills per kilowatt-hour

during billing months April through

July.

2. Application of the Charge

During any billing month, BPA may

assess the unauthorized increase charge

on the number of kilowatt-hours

associated with the DSI Measured

Demand in any one 60-minute clockhour, before adjustment for power

factor, that exceed the BPA Operating

Level for that clock-hour, regardless of

whether such Measured Demand occurs

during the Peak or Offpeak Period.

D. Power Factor Adjustment

The adjustment for power factor,

when specified in this rate schedule or

in the power sales contract, shall be

made in accordance with the provisions

of both this section and section III.C.1

of the GRSPs. The adjustment shall be

made if the average leading power factor

or average lagging power factor at which

energy is supplied during the billing

month is less than 95 percent.

To make the power factor adjustment,

BPA shall increase the billing demand

by 1 percentage point for each

percentage point or major fraction

thereof (0.5 or greater) by which the

average leading power factor or average

lagging power factor is below 95

percent. BPA may elect to waive the

adjustment for power factor in whole or

in part.

E. Outage Credit

Pursuant to section 7 of the General

Contract Provisions, BPA shall provide

an outage credit to any DSI for those

hours for which BPA is unable to

deliver the full billing demand during

that billing month due to an outage on

the facilities used by BPA to deliver

Industrial Firm Power. Such credit shall

not be provided if BPA is able to serve

the DSI’s load through the use of

alternative facilities or if the outage is

for less than 30 minutes. The amount of

the credit shall be calculated according

to the provisions of section III.C.2 of the

GRSPs.

Section V. Resource Cost Contribution

BPA has made the following

determinations:

A. The approximate cost contribution

of different resource categories to the

IP–95 rate is 85.8 percent Exchange and

14.2 percent New Resources.

B. The forecasted average cost of

resources available to BPA under

average water conditions is 19.80 mills

per kilowatt-hour.

C. The forecasted cost of resources to

meet load growth is 60.64 mills per

kilowatt-hour.
21140 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

Schedule VI–95

Variable Industrial Power Rate

Section I. Availability

This schedule is available to DSI

customers for purchases under the

Power Sales Contract implementing the

VI rate schedule (Variable Rate Contract)

of: (1) Industrial Firm Power; and (2)

Auxiliary Power if requested by the DSI

customer and made available by BPA.

This schedule is available only for that

portion of a DSI’s load used in primary

aluminum reduction including

associated administrative facilities, if

any. By virtue of incorporation of this

rate schedule and associated GRSPs in

the Variable Rate Contract, DSIs electing

to purchase power under this rate

schedule contractually agree to the

terms and conditions of this rate

schedule. A DSI further agrees to waive,

for that portion of their load designated

to purchase power at the VI rate, all

rights they might otherwise have to

purchase power at the Industrial Firm

Power Rate Schedule for the duration of

the Variable Rate Contract. Sales under

this schedule are made subject to BPA’s

GRSPs.

Section II. Term of the Rate

This rate schedule shall take effect on

October 1, 1995, and shall terminate at

midnight September 30, 1996.

Section III. Rate

A. Base Rate

The formula to be used in the

calculation of the monthly power bill is

contained in section IV. A separate

billing adjustment for the value of the

reserves provided by purchasers of

Industrial Firm Power is not contained

in this rate schedule; the value of

reserves credit has been included in the

determination of the Plateau Energy

Charge.

1. Base Variable Industrial Rate

a. Demand Charge

$6.233 per kilowatt of billing demand,

as adjusted, occurring during the Peak

Period during a billing month. No

demand charge is applied during

Offpeak Period hours.

b. Plateau Energy Charge

18.83 mills per kilowatt-hour of

billing energy, as adjusted.

2. First Quartile Service Discount

0.59 mills per kilowatt-hour of billing

energy.

3. Lower Rate Limit

15.03 mills per kilowatt-hour of

billing energy.

4. Upper Rate Limit

24.63 mills per kilowatt-hour of

billing energy.

B. Base Rate Parameters Subject to

Annual Adjustments

The following base rate parameters

shall be used to determine power bills

for DSI customers purchasing power

under the Variable Rate Contract. These

parameters will be adjusted July 1, 1996,

in accordance with the procedures

contained in section VII.B of the GRSPs.

1. Lower Pivot Aluminum Price

75.4 cents per pound.

2. Upper Pivot Aluminum Price

91.6 cents per pound.

Section IV. Formula

The Variable Industrial Power rate is

a formula rate tied to the U.S. market

price of aluminum. Under this rate

schedule, the monthly energy charge

varies in response to changes in the

average price of aluminum in U.S.

markets.

A. Demand Charge

1. The Demand Charge, as stated in

section III.A.1.a of this rate schedule,

remains constant over all aluminum

prices. The demand charge is applied to

billing demand occurring during all

Peak Period hours for all billing months.

2. No demand charge during Offpeak

Period hours.

B. Energy Charge

1. Plateau Energy Charge

When the monthly billing aluminum

price (described in section VII.A of the

GRSPs) is between the Lower Pivot

Aluminum Price and the Upper Pivot

Aluminum Price inclusive (as stated in

sections III.B.1 and III.B.2 of this rate

schedule), the monthly energy charge

shall be the Plateau Energy Charge as

stated in section III.A.1.b of this rate

schedule.

2. Reductions to Plateau Energy Charge

When the monthly billing aluminum

price is less than the Lower Pivot

Aluminum Price, the monthly energy

charge shall be the greater of:

a. The Plateau Energy Charge - (LPMAP) * (LS)

where:

LP=the Lower Pivot Aluminum Price as

stated in section III.B.1 of this rate

schedule.

MAP=the monthly billing aluminum

price in cents per pound

determined pursuant to section

VII.A of the GRSPs

LS=lower slope=1 mill per kilowatthour

llllllllllll

1 cent per pound

or

b. The Lower Rate Limit as stated in

section III.A.3 of this rate schedule.

3. Increases to Plateau Energy Charge

When the monthly billing aluminum

price is greater than the Upper Pivot

Aluminum Price, the monthly energy

charge shall be the lesser of:

a. The Plateau Energy Charge+(MAPUP) * (US)

where:

MAP=the monthly billing aluminum

price in cents per pound, as

determined according to section

VII.A of the GRSPs.

UP=the Upper Pivot Aluminum Price as

stated in section III.B.2 of this rate

schedule.

US=upper slope=0.75 mills per

kilowatt-hour

llllllllllllll

1 cent per pound

b. The Upper Rate Limit, as stated in

section III.A.4 of this rate schedule.

Section V. Billing Factors

A. Billing Demand

1. Billing Demand for Customers Whose

Entire BPA Load Is Served at the VI Rate

The billing demand for power

purchased shall be the BPA Operating

Level during the Peak Period as adjusted

for power factor. If there is more than

one BPA Operating Level during the

Peak Period within a billing month, the

billing demand shall be a weighted

average of the BPA Operating Levels

during the Peak Period for the billing

month. The BPA Operating Level is

defined in section III.A.10 of the GRSPs.

2. Billing Demand or Customers When

Only a Portion of Their Total BPA Load

Is Served at the Variable Rate

The Billing Demand shall be the

portion of the BPA Operating Level

attributable to the VI rate as determined

by the method specified in the Variable

Rate Contract.

3. Billing Demand During Periods of

Transitional Service

If BPA has agreed, pursuant to section

4 of the DSI power sales contract, to sell

Industrial Firm Power on a daily

demand basis (transitional service),

sections V.A.1 and V.A.2 of the rate

schedule shall not apply, and BPA shall

bill the purchaser in accordance with

the provisions of section V.C of the

GRSPs.
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21141

B. Billing Energy

The billing energy for power

purchased shall be the Measured Energy

for the billing month, minus any

kilowatt-hours on which BPA assesses

the charge for unauthorized increase.

Section VI. Other Adjustments and

Special Provisions

A. Lower and Upper Pivot Aluminum

Prices

Effective July 1, 1991, and every July

1 thereafter, the Lower and Upper Pivot

Aluminum Prices set forth in section

III.B of the rate schedule shall be

adjusted following the procedures set

forth in section VII.B of the GRSPs. The

adjusted Lower and Upper Pivot

Aluminum Prices shall supersede the

Lower and Upper Pivot Aluminum

Prices contained in section III.B of the

rate schedule.

B. Discount for Quality of First Quartile

Service

If a purchaser requests First Quartile

service with other than Surplus Firm

Energy Load Carrying Capability

(FELCC), a discount contained in

section III.A.2 of this rate schedule shall

be granted. This billing credit shall be

applied to the monthly billing energy

under section V.B for all power

purchased under this rate schedule. No

credit shall be applied to those

purchases subject to unauthorized

increase charges under section VI.F of

this rate schedule. To qualify for the

First Quartile Discount, the purchaser

must request discounted rate service in

writing by April 2 of each calendar year.

By virtue of making such request, the

Purchaser is agreeing to accept the level

and quality of First Quartile service

described in section 6 of the Variable

Rate Contract. Such acceptance includes

the waiver of contract rights provided in

section 6.a(2)(a) of said contract.

C. Unauthorized Increase

1. Rate for Unauthorized Increase

a. 100.00 mills per kilowatt-hour

during the billing months August

through March.

b. 57.40 mills per kilowatt-hour

during the billing months April through

July.

2. Application of the Charge

During any billing month, BPA may

assess the unauthorized increase charge

on the number of kilowatt-hours

associated with the DSI Measured

Demand in any one 60-minute clockhour, before adjustment for power

factor, that exceed the BPA Operating

Level for that clock-hour, regardless of

whether such Measured Demand occurs

during the Peak or Offpeak Period.

D. Power Factor Adjustment

The adjustment for power factor,

when specified in this rate schedule or

in the power sales contract, shall be

made in accordance with the provisions

of both this section and section III.C.1

of the GRSPs. The adjustment shall be

made if the average leading power factor

or average lagging power factor at which

energy is supplied during the billing

month is less than 95 percent.

To make the power factor adjustment,

BPA shall increase the BPA Operating

Level by 1 percentage point for each

percentage point or major fraction

thereof (0.5 or greater) by which the

average leading power factor or average

lagging power factor is below 95

percent. BPA may elect to waive the

adjustment for power factor in whole or

in part.

E. Outage Credit

Pursuant to section 7 of the General

Contract Provisions, BPA shall provide

an outage credit to any DSI to whom

BPA is unable to deliver the full billing

demand during that billing month due

to an outage on the facilities used by

BPA to deliver Industrial Firm Power.

Such credit shall not be provided if BPA

is able to serve the DSI’s load through

the use of alternative facilities or if the

outage is for less than 30 minutes. The

amount of the credit shall be calculated

according to the provisions of section

III.C.2 of the GRSPs.

Section VII. Resource Cost Contribution

BPA has made the following

determinations:

A. The approximate cost contribution

of different resource categories to the

VI–95 rate is 85.8 percent Exchange and

14.2 percent New Resources.

B. The forecasted average cost of

resources available to BPA under

average water conditions is 19.80 mills

per kilowatt-hour.

C. The forecasted cost of resources to

meet load growth is 60.64 mills per

kilowatt-hour.

Schedule SI–95

Special Industrial Power Rate

Section I. Availability

This rate schedule is available to any

DSI purchaser using raw minerals

indigenous to the region as its primary

resource and qualifying for this special

power pursuant to the procedures

established in section 7(d)(2) of the

Northwest Power Act. This schedule is

available for the contract purchase of

this special class of industrial power

and also for the purchase of Auxiliary

Power if requested by the DSI and made

available by BPA. Schedule SI–95

supersedes schedule SI–93, which went

into effect on October 1, 1993. Sales

under this schedule are made subject to

BPA’s General Rate Schedule Provisions

(GRSPs).

Section II. Rate

A separate billing adjustment for the

value of the reserves provided by

purchasers of this special class of

Industrial Power is not contained in the

rate schedule; the adjustment is

reflected in the Special Industrial Power

Rate charges.

A. Demand Charge

1. $3.827 per kilowatt of billing

demand occurring during all Peak

Period hours during a billing month.

2. No demand charge during Offpeak

Period hours.

B. Energy Charge

1. 21.20 mills per kilowatt-hour of

billing energy for the billing months

September through March;

2. 15.08 mills per kilowatt-hour of

billing energy for the billing months

April through August.

Section III. Billing Factors

A. Billing Demand

The billing demand for power

purchased under the Standard Special

Industrial Power rate shall be the BPA

Operating Level during the Peak Period

as adjusted for power factor. If there is

more than one BPA Operating Level

during the Peak Period within a billing

month, the billing demand shall be a

weighted average of the Peak Period

BPA Operating Levels for the billing

month. The BPA Operating Level is

defined in section III.A.10 of the GRSPs.

However, if BPA has agreed, pursuant

to section 4 of the direct service

industrial power sales contract, to sell

Special Industrial Power on a daily

demand basis (transitional service), BPA

shall instead bill the purchaser in

accordance with the provisions of

section V.C of the GRSPs.

B. Billing Energy

The billing energy under the Special

Industrial rate shall be the Measured

Energy for the billing month, minus any

kilowatt-hours on which BPA assesses

the charge for unauthorized increase.

Section IV. Adjustments and Special

Provisions

A. Curtailments

BPA shall charge the DSI for

curtailments in accordance with the
21142 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

provisions of the DSI’s power sales

contract. Any curtailment charge levied

shall be computed using the Special

Industrial Power rate.

B. Unauthorized Increase Charge

1. Rate for Unauthorized Increase

a. 100.00 mills per kilowatt-hour

during billing months August through

March.

b. 57.40 mills per kilowatt-hour

during billing months April through

July.

2. Application of the Charge

During any billing month, BPA may

assess the unauthorized increase charge

on the number of kilowatt-hours

associated with the DSI Measured

Demand in any one 60-minute clockhour, before adjustment for power

factor, that exceed the BPA Operating

Level for that clock-hour, regardless of

whether such Measured Demand occurs

during the Peak or Offpeak Period.

C. Power Factor Adjustment

The adjustment for power factor,

when specified in this rate schedule or

in the power sales contract, shall be

made in accordance with the provisions

of both this section and section III.C.1

of the GRSPs. The adjustment shall be

made if the average leading power factor

or average lagging power factor at which

energy is supplied during the billing

month is less than 95 percent.

To make the power factor adjustment

for service under the Special Industrial

Power rate, BPA shall increase the

billing demand by 1 percentage point

for each percentage point or major

fraction thereof (0.5 or greater) by which

the average leading power factor or

average lagging power factor is below 95

percent. BPA may elect to waive the

adjustment for power factor in whole or

in part.

D. Outage Credit

Pursuant to section 7 of the General

Contract Provisions, BPA shall provide

an outage credit to any purchaser for

those hours for which BPA is unable to

deliver the full billing demand during

that billing month due to an outage on

the facilities used by BPA to deliver

Special Industrial Power. Such credit

shall not be provided if BPA is able to

serve the purchaser’s load through the

use of alternative facilities or if the

outage is for less than 30 minutes. The

amount of the credit shall be calculated

according to the provisions of section

III.C.2 of the GRSPs.

Section V. Resource Cost Contribution

BPA has made the following

determinations:

A. The SI–95 rate is not based on the

cost of resources.

B. The forecasted average cost of

resources available to BPA under

average water conditions is 19.80 mills

per kilowatt-hour.

C. The forecasted cost of resources to

meet load growth is 60.64 mills per

kilowatt-hour.

Schedule CE–95

Emergency Capacity Rate

Section I. Availability

This schedule is available for the

purchase of capacity provided the

purchaser requests such capacity and

BPA has determined that capacity is

available for such purpose. This

schedule is available when:

A. An emergency exists on the

purchaser’s system, or

B. The purchaser wishes to displace

higher-cost firm capacity resources

which are otherwise available to meet

the purchaser’s load.

This schedule supersedes Schedule

CE–93 which went into effect on

October 1, 1993. Sales under this

schedule are made subject to BPA’s

General Rate Schedule Provisions.

Section II. Rate

A. Demand Charge

As mutually agreed by BPA and the

purchaser, up to $0.321 per kilowatt of

demand per calendar day or portion

thereof.

B. Intertie Charge

The demand charge specified above

shall be increased by $0.044 per

kilowatt per day for capacity made

available at the Oregon-California or

Oregon-Nevada border for delivery over

the Pacific Northwest-Pacific Southwest

(Southern) Intertie.

Section III. Billing Factors

The billing demand shall be the

maximum amount requested by the

purchaser and made available by BPA

during a calendar day. If BPA is unable

to meet subsequent requests by a

purchaser for delivery at the demand

previously established during such day,

the billing demand for that day shall be

the lower demand which BPA is able to

supply.

Section IV. Billing Period

Bills shall be rendered monthly.

Section V. Special Provision

Energy delivered with such capacity

shall be returned to BPA within 7 days

of the date of delivery and shall be

returned at times and rates of delivery

agreed to by both the purchaser and

BPA prior to delivery. BPA may agree to

accept the return energy after the

normal 7 day return period provided

that such delay has been mutually

agreed upon prior to delivery.

Section VI. Resource Cost Contribution

BPA has made the following

determinations:

A. The approximate cost contribution

of different resource categories to the

CE–95 rate is 85.8 percent Exchange and

14.2 percent New Resources.

B. The forecasted average cost of

resources available to BPA under

average water conditions is 19.6 mills

per kilowatt-hour.

C. The forecasted cost of resources to

meet load growth is 55.7 mills per

kilowatt-hour.

Schedule NR–95

New Resource Firm Power Rate

Section I. Availability

This schedule is available for the

contract purchase of firm power or

capacity to be used within the Pacific

Northwest. New Resource Firm Power is

available to investor-owned utilities

(IOUs) under net requirements contracts

for resale to ultimate consumers, direct

consumption, or use in construction,

test and start up, and station service.

New Resource Firm Power also is

available to any public body,

cooperative, or Federal agency to the

extent such power is needed to serve

any New Large Single Load. In addition,

BPA may make this rate available to

those parties participating in exchange

agreements that use this rate schedule as

the basis for determining the amount or

value of power to be exchanged. This

schedule supersedes Schedule NR–93,

which went into effect on October 1,

1993. Sales under this schedule are

made subject to BPA’s General Rate

Schedule Provisions (GRSPs).

Section II. Rate

A. Demand Charge

1. $5.357 per kilowatt of billing

demand occurring during all Peak

Period hours during a billing month.

2. No demand charge during Offpeak

Period hours.

B. Energy Charge

1. 28.66 mills per kilowatt-hour of

billing energy for the billing months

September through March.

2. 25.10 mills per kilowatt-hour of

billing energy for the billing months

April through August.

Section III. Billing Factors

In this section billing factors are listed

for computed requirements purchasers
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21143

(section III.A), metered requirements

purchasers, and those purchasers not

covered by section III.A (section III.B).

A. Computed Requirements Purchasers

Purchasers designated by BPA as

computed requirements purchasers

pursuant to power sales contracts shall

be billed in accordance with the

provisions of this section.

1. Billing Demand

The billing demand for actual,

planned, and contracted computed

requirements purchasers shall be the

higher of the billing factors ‘‘a’’ and ‘‘b,’’

below:

a. The lower of:

(1) The larger of the Computed Peak

Requirement or the Computed Average

Energy Requirement; or

(2) The Measured Demand, before

adjustment for power factor.

b. The lower of:

(1) The Computed Peak Requirement;

or

(2) 60 percent of the highest

Computed Peak Requirement during the

previous 11 billing months (Ratchet

Demand).

2. Billing Energy

The billing energy for actual, planned,

and contracted computed requirements

purchasers shall be:

a. For the months September through

March, the sum of:

(1) 55 percent of the Measured

Energy; and

(2) 45 percent of the Computed

Energy Maximum.

b. For the months April through

August, the sum of:

(1) 43 percent of the Measured

Energy; and

(2) 57 percent of the Computed

Energy Maximum.

B. Metered Requirements Purchasers

and Other Purchasers Not Covered by

Section III.A, Above

Purchasers designated as metered

requirements customers and purchasers

taking power under this rate schedule

who are not otherwise covered by

section III.A shall be billed as follows:

1. Billing Demand

The billing demand shall be the

Measured Demand as adjusted for

power factor, unless otherwise specified

in the power sales contract. However,

purchasers who previously used the

Firm Energy rate schedule, FE–2, either

in the computation of their power bills

or in the determination of the value of

an exchange account, shall not be

charged for demand under this rate

schedule.

2. Billing Energy

The billing energy shall be the

Measured Energy, unless otherwise

specified in the power sales contract.

Section IV. Adjustments and Special

Provisions

A. Power Factor Adjustment

The adjustment for power factor,

when specified in this rate schedule or

in the power sales contract, shall be

made in accordance with the provisions

of both this section and section III.C.1

of the GRSPs. The adjustment shall be

made if the average leading power factor

or average lagging power factor at which

energy is supplied during the billing

month is less than 95 percent.

To make the power factor adjustment,

BPA shall increase the billing demand

by 1 percentage point for each

percentage point or major fraction

thereof (0.5 or greater) by which the

average leading power factor or average

lagging power factor is below 95

percent. BPA may elect to waive the

adjustment for power factor in whole or

in part.

B. Irrigation Discount

BPA shall apply an irrigation

discount, equal to 4.90 mills per

kilowatt-hour, to the charges for

qualifying energy purchased under this

rate schedule. The discount shall apply

only to energy purchased during the

billing months of April through October.

Eligibility for the irrigation discount and

reporting requirements shall be

determined pursuant to section III.C.4 of

the GRSPs.

C. Conservation Surcharge

The Conservation Surcharge shall be

applied in accordance with section

III.C.6 of the GRSPs and subsequent to

any other rate adjustments.

D. Unauthorized Increase

BPA shall apply the charge for

Unauthorized Increase to any purchaser

of New Resource Firm Power taking

demand and/or energy in excess of its

contractual entitlement.

1. Rate for Unauthorized Increase

a. 100.00 mills per kilowatt-hour

during billing months August through

March.

b. 57.40 mills per kilowatt-hour

during billing months April through

July.

2. Calculation of the Unauthorized

Increase

Each 60-minute clock-hour integrated

or scheduled demand shall be

considered separately in determining

the amount which may be considered an

unauthorized increase. BPA shall first

determine the amount of unauthorized

increase related to demand and shall

then treat any remaining unauthorized

increase as energy-related.

a. Unauthorized Increase in Demand

That portion of any Measured

Demand during Peak Period hours,

before adjustment for power factor, that

exceeds the demand which the

purchaser is contractually entitled to

take during the billing month and that

cannot be assigned:

(1) To a class of power which BPA

delivers on such hour pursuant to

contracts between BPA and the

purchaser; or

(2) To a type of power which the

purchaser acquires from sources other

than BPA and which BPA delivers

during such hour, shall be billed:

(a) In accordance with the provisions

of the ‘‘Relief from Overrun’’ exhibit to

the power sales contract; or

(b) If such exhibit does not apply or

is not a part of the purchaser’s power

sales contract, at the rate for

Unauthorized Increase, based on the

amount of energy associated with the

excess demand.

b. Unauthorized Increase in Energy

The amount of Measured Energy

during a billing month that exceeds the

amount of energy which the purchaser

is contractually entitled to take during

that month and that cannot be assigned:

(1) To a class of power that BPA

delivers during such month pursuant to

contracts between BPA and the

purchaser; or

(2) To a type of power that the

purchaser acquires from sources other

than BPA and that BPA delivers during

such month, shall be billed:

(a) In accordance with the provisions

of the ‘‘Relief from Overrun’’ exhibit to

the power sales contract, or

(b) As unauthorized increase if such

exhibit does not apply or is not a part

of the purchaser’s power sales contract.

E. Coincidental Billing Adjustment

Purchasers of New Resource Firm

Power who are billed on a coincidental

basis and who have diversity charges or

diversity factors specified in their power

sales contracts shall have their charges

for billing demand adjusted according to

the provisions of section III.C.5 of the

GRSPs. Computed requirements

purchasers are not subject to the

Coincidental Billing Adjustment for

scheduled power.

F. Outage Credit

Pursuant to section 7 of the General

Contract Provisions, BPA shall provide
21144 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

an outage credit to any purchaser for

those hours for which BPA is unable to

deliver the full billing demand during

the billing month due to an outage on

the facilities used by BPA to deliver

New Resource Firm Power. Such credit

shall not be provided if BPA is able to

serve the purchaser’s load through the

use of alternative facilities or if the

outage is for less than 30 minutes. The

amount of the credit shall be calculated

according to the provisions of section

III.C.2 of the GRSPs.

G. Energy Return Surcharge

Any purchaser who preschedules in

accordance with sections 2(a)(4) and

2(c)(2) of Exhibit E of the Power Sales

contract and who returns, during a

single offpeak hour, more than 60

percent of the difference between that

purchaser’s billing demand and

estimated computed average energy

requirement for the billing month shall

be subject to the following surcharge for

each additional kilowatt-hour so

returned:

1. 4.25 mills per kilowatt-hour for the

months of April through October; and

2. 1.80 mills per kilowatt-hour for the

months of November through March.

Section V. Resource Cost Contribution

BPA has made the following

determinations:

A. The approximate cost contribution

of different resource categories to the

NR–95 rate is 89.7 percent Exchange

and 10.3 percent New Resources.

B. The forecasted average cost of

resources available to BPA under

average water conditions is 19.80 mills

per kilowatt-hour.

C. The forecasted cost of resources to

meet load growth is 60.64 mills per

kilowatt-hour.

Schedule NF–95

Nonfirm Energy Rate

Section I. Availability

This schedule is available for the

purchase of nonfirm energy to be used

both inside and outside the United

States including sales under the

Western Systems Power Pool (WSPP)

agreements and sales to consumers. This

schedule also applies to energy

delivered for emergency use under the

conditions set forth in section V.A of the

General Rate Schedule Provisions

(GRSPs). BPA is not obligated to offer

nonfirm energy to any purchaser that

results in displacement of firm power

purchases under BPA’s Power Sales

Contracts. The offer of nonfirm energy

under this schedule shall be determined

by BPA. Schedule NF–95 supersedes

Schedule NF–93, which went into effect

on October 1, 1993. Sales under this

schedule are made subject to BPA’s

GRSPs.

Section II. Rates

The average cost of nonfirm energy is

23.31 mills per kilowatt-hour. The NF–

95 rate schedule provides for upward

and downward pricing flexibility from

this average nonfirm energy cost. All

rates and any subsequent adjustments

contained in this rate schedule shall not

exceed in total the NF Rate Cap defined

in section IV.C of the GRSPs.

A. Standard Rate

The Standard rate is any offered rate

not to exceed 27.97 mills per kilowatthour.

B. Market Expansion Rate

The Market Expansion rate is any

offered rate below the Standard rate in

effect. BPA may have one or more

Market Expansion rates in effect

simultaneously.

C. Incremental Rate

The Incremental rate is the

Incremental Cost of energy plus 2.00

mills per kilowatt-hour, where the

Incremental Cost is defined as all

identifiable costs (expressed in mills per

kilowatt-hour) that BPA would have

avoided had it not produced or

purchased the energy being sold under

this rate.

D. Contract Rate

The Contract rate is 14.83 mills per

kilowatt-hour of billing energy.

Section III. Adjustments to Rates

A. Guaranteed Delivery Surcharge

A surcharge of 2.00 mills per kilowatthour of billing energy is applied to

guaranteed delivery of nonfirm energy

under the Standard rate and Market

Expansion rate.

B. Intertie Charge

The Intertie Charge, on rate offers

under any of the rates specified above,

for sales of nonfirm energy scheduled

for delivery over the Pacific NorthwestPacific Southwest Intertie shall be:

1. Inapplicable for rate offers of less

than 23.31 mills per kilowatt-hour;

2. At the discretion of BPA, from zero

through 3.23 mills per kilowatt-hour, for

rate offers of 23.31 mills per kilowatthour; or

3. 3.23 mills per kilowatt-hour, for

rate offers greater than 23.31 mills per

kilowatt-hour.

Section IV. Billing Factors

The billing energy for nonfirm energy

purchased under this rate schedule shall

be the Measured Energy unless

otherwise specified by contract.

Section V. Application and Eligibility

Any time that BPA has nonfirm

energy for sale, the Standard rate, the

Market Expansion rate, the Incremental

rate, the Contract rate, or a combination

of these rates may be in effect.

A. Standard Rate

The Standard rate:

1. Is available for all purchases of

nonfirm energy; and

2. Applies to nonfirm energy

purchased pursuant to the Relief from

Overrun Exhibit to the power sales

contract.

B. Market Expansion Rate

1. Application of the Market

Expansion Rate

The Market Expansion rate applies

when BPA determines that all markets

at the Standard rate have been satisfied

and BPA offers additional nonfirm

energy.

2. Market Expansion Rate

Qualification Criteria

In order to purchase nonfirm energy

at the Market Expansion rate, a

purchaser must:

a. Have a displaceable resource,

displaceable purchase of electricity, or

b. Be an end-user load with a

displaceable alternative fuel source.

In addition, a purchaser must

demonstrate one of the following:

a. Shutdown or reduction of the

output of the displaceable resource in

an amount equal to the amount of

Market Expansion rate energy

purchased; or

b. Reduction of a displaceable

purchase and the output of the resource

associated with that purchase, in an

amount equal to the amount of Market

Expansion rate energy purchased; or

c. Shutdown or reduction of the

identified output of the resource(s)

indirectly in an amount equal to the

amount of Market Expansion rate energy

purchased (for example, the purchase

may be used to run a pumped storage

unit); or

d. Decrease of an end-user alternate

fuel source in an amount equivalent to

the amount of Market Expansion rate

energy purchased.

3. Eligibility Criteria for Market

Expansion Rate

a. When only one Market Expansion

rate is offered:

Purchasers qualifying under section

V.B.2 who purchased nonfirm energy

directly from BPA are eligible to

purchase power under the Market

Expansion rate offered if the

decremental cost of the qualifying
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21145

resource, purchase, or qualifying

alternative fuel source is lower than the

Standard rate in effect plus 2.0 mills per

kilowatt-hour.

Purchasers qualifying under section

V.B.2 who purchase nonfirm energy

through a third party are eligible to

purchase power under the Market

Expansion rate offered if the cost of the

qualifying alternative fuel source is

lower than the Standard rate in effect

plus 4.0 mills per kilowatt-hour.

b. When more than one Market

Expansion rate is offered:

Purchasers qualifying under section

V.B.2 who purchase nonfirm energy

directly from BPA are eligible to

purchase power under the Market

Expansion rate if the decremental cost

of the qualifying resource, purchase, or

qualifying alternative fuel source is

lower than the Standard rate in effect

plus 2.00 mills per kilowatt-hour. The

rate applicable to a purchaser shall be

the highest Market Expansion rate

offered that is below the purchaser’s

qualifying decremental cost minus 2.00

mills per kilowatt-hour.

Purchasers qualifying under section

V.B.2 who purchase nonfirm energy

through a third party are eligible to

purchase power under the Market

Expansion rate if the decremental cost

of the qualifying alternative fuel source

is lower than the Standard rate plus 4.00

mills per kilowatt-hour. The rate

applicable to a purchaser shall be the

highest Market Expansion rate offered

that is below purchaser’s qualifying

decremental cost minus 4.0 mills per

kilowatt-hour.

C. Incremental Rate

The Incremental rate applies to sales

of energy:

1. That is produced or purchased by

BPA concurrently with the nonfirm

energy sale;

2. That BPA may at its option not

produce or purchase; and

3. That has an Incremental Cost

greater than the Standard rate (plus the

Intertie Charge, if applicable) less 2.00

mills per kilowatt-hour.

D. Contract Rate

The Contract rate applies to contracts

(except power sales contracts offered

pursuant to sections 5(b), 5(c), and 5(g)

of the Northwest Power Act) that refer

to the Contract rate:

1. For the sale of nonfirm energy; or

2. For determining the value of

energy.

E. Western Systems Power Pool

Transactions (WSPP)

BPA may make available nonfirm

energy for transactions under the WSPP

agreement. WSPP sales shall be subject

to the terms and conditions specified in

the WSPP agreement and shall be

consistent with regional and public

preference. The rate for transactions

under the WSPP agreement is any rate

within the limits specified by the

Standard, Market Expansion, and

Incremental rates but may not exceed

the maximum rate specified in the

WSPP Agreement. The rate for WSPP

sales may differ from the actual rate

offered for non-WSPP transactions in

any hour. The rate for WSPP

transactions is independent of any other

rate offered concurrently under this rate

schedule outside that agreement.

F. End-User Rate

BPA may agree to a rate or rate

formula for nonfirm energy purchases

by end-users. Such rate or rate formula

shall be within the limits specified for

the Standard and Market Expansion

rates but may differ from the actual rates

offered during any hour.

Section VI. Delivery

A. Rate of Delivery

BPA shall determine the amount of

nonfirm energy to be made available for

each hour. Such determination shall be

made for each applicable nonfirm

energy rate.

B. Guaranteed Delivery

1. Availability

BPA will determine the amount and

duration of nonfirm energy to be offered

on a guaranteed basis. Such daily or

hourly amounts may be as small as zero

or as much as all the nonfirm energy

that BPA plans to offer for sale on such

days.

2. Conditions

Scheduled amounts of guaranteed

nonfirm energy may not be changed

except:

a. When BPA and the purchaser

mutually agree to increase or decrease

the scheduled amounts; or

b. When BPA must reduce nonfirm

energy deliveries in order to serve firm

loads because of unexpected generation

or transmission losses.

Section VII. Resource Cost Contribution

BPA has made the following

determinations:

A. The approximate cost contribution

of different resource categories to the

average cost of nonfirm energy is 92.7

percent FBS and 7.3 percent New

Resources.

B. The forecasted average cost of

resources available to BPA under

average water conditions is 19.80 mills

per kilowatt-hour.

C. The forecasted cost of resources to

meet load growth is 60.64 mills per

kilowatt-hour.

Schedule SS–95

Share-the-Savings Rate

Section I. Availability

This rate schedule is available for the

contract purchase of Nonfirm Energy

under an experimental rate and is

limited to the term of the rate

experiment. Nonfirm Energy will be

made available under this rate schedule

for use both inside and outside the

United States for the displacement of a

qualifying resource, displaceable

purchase of electricity, or end-user load

that can be served with alternate fuel

sources. This rate schedule is only

available to purchasers who execute a

contract with BPA specifying use of the

Share-the-Savings Rate. BPA is not

obligated to offer Nonfirm Energy to any

purchaser that results in displacement

of firm power purchases under BPA’s

Power Sales Contracts. Schedule SS–95

supersedes Schedule SS–93, which

went into effect on October 1, 1993.

Sales under this schedule are made

subject to BPA’s General Rate Schedule

Provisions (GRSPs).

Section II. Rate

The rate shall be a formula rate based

solely or in part on decremental cost

information submitted by the purchaser.

The rate formula and decremental cost,

for purposes of establishing charges

under this rate schedule, shall be

defined in the applicable contract. The

rate formula agreed upon by BPA and

the purchaser shall in no event result in

a rate higher than the NF Rate Cap

defined in section IV.C of the GRSPs or

lower than 1.00 mill per kilowatt-hour.

Section III. Billing Factor

The billing energy for Nonfirm Energy

purchased under this rate schedule shall

be the Measured Energy unless

otherwise specified in the Share-theSavings rate contract.

Section IV. Application and Eligibility

A. General Requirements

In order to purchase Nonfirm Energy

under the Share-the-Savings Rate, the

purchaser must:

1. Have executed a contract specifying

application of the Share-the-Savings

Rate Schedule, and

2. Have a displaceable resource,

displaceable purchase of electricity, or

be an end-user load with a displaceable

alternate fuel source. End-user loads

with alternate fuel sources may not use

the Decremental Cost of a displaceable
21146 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

purchase of electricity to qualify for this

rate.

B. BPA Service Priority

Offers of Nonfirm Energy under this

rate schedule shall be made pursuant to

the terms and conditions set forth in the

Share-the-Savings rate contract. BPA

will sell Nonfirm Energy under this rate

schedule consistent with regional and

public preference.

Section V. Resource Cost Contribution

BPA has made the following

determinations:

A. The SS–95 rate is not based on the

cost of BPA resources.

B. The forecasted average cost of

resources available to BPA under

average water conditions is 19.80 mills

per kilowatt-hour.

C. The forecasted cost of resources to

meet load growth is 60.64 mills per

kilowatt-hour.

Schedule PS–95

Power Shortage Rate

Section I. Availability

This schedule is available inside the

Pacific Northwest for the purchase of

Shortage Power to a utility when a

shortage exists on its system and the

utility requests Shortage Power under

this rate schedule, or when Shortage

Power is being delivered to a utility as

the result of statewide or regionwide

curtailment. This schedule is also

available for sales under the Share-theShortage agreement, or a similar

substitute agreement.

This rate schedule is also available

inside the Pacific Northwest when BPA

arranges for purchase energy at the

request of a customer. BPA is not

obligated to make Shortage Power

available or broker power under this

rate schedule unless specified by

contract. Sales under this schedule are

made subject to BPA’s General Rate

Schedule Provisions.

Section II. Rates

A. Power Rate

The power rate is any offered rate not

to exceed 100.00 mills per kilowatthour. The offered rate may be specified

as an energy charge only or as demand

and energy charges.

B. Brokering Rate

The brokering rate may be up to 1.00

mill per kilowatt-hour for services

provided when BPA arranges for energy

purchases for a customer from a seller

other than BPA.

Section III. Billing Factors

The billing factors shall be:

A. Power Purchases

The factors to be used in determining

the billings for power purchases under

this rate schedule are as follows:

1. Billing Demand

The billing demand shall be the

Contract Demand as specified in the

contract initiating such arrangement or

as mutually agreed to by the parties.

Otherwise the billing demand shall be

the Measured Demand as adjusted for

power factor.

2. Billing Energy

The billing energy shall be the

Contract Energy as specified in the

contract initiating such arrangement or

as mutually agreed to by the parties.

Otherwise the billing energy shall be the

Measured Energy.

B. Brokering Services

When BPA arranges for energy

purchases at the request of a customer,

the purchaser shall be billed for such

services based on the total amount of

kilowatt-hours purchased.

Section IV. Adjustments and Special

Provisions

A. Power Factor Adjustment

The adjustment for power factor for

BPA customers that are billed for

shortage power on metered amounts,

when specified in this rate schedule or

in the contracts, shall be made in

accordance with the provisions of both

this section and section III.C.1 of the

GRSPs. The adjustment shall be made if

the average leading power factor or

average lagging power factor at which

energy is supplied during the billing

month is less than 95 percent.

To make the power factor adjustment,

BPA shall increase the billing energy by

1 percentage point for each percentage

point or major fraction thereof (0.5 or

greater) by which the average leading

power factor or average lagging power

factor is below 95 percent. BPA may

elect to waive the adjustment for power

factor in whole or in part.

B. Power Brokering

The charge for power brokering only

applies to the service provided by BPA

of finding purchased power for a

customer from a seller other than BPA.

BPA may agree to provide other services

in addition to finding purchased power,

but these services shall be billed

separately at charges specified in the

appropriate rate schedule(s) or

agreement(s). Such services may

include, but are not limited to, wheeling

and load shaping.

C. Share-the-Shortage Transactions

In the event a Share-the-Shortage type

agreement is executed, BPA may make

shortage power available to participants

under such agreement. Any transactions

entered into by BPA pursuant to the

Share-the-Shortage agreement shall be

subject to the terms and conditions

specified in that agreement. The PS–95

rate does not incorporate the agreement

but the agreement controls if there is

any conflict between the PS–95 rate and

the agreement. The rate for transactions

under the Share-the-Shortage agreement

is any rate within the limits specified by

the power rate but may not exceed the

maximum rate specified in the

agreement. The rate for Share-theShortage transactions is independent of

any rate offered under this rate schedule

for sales that do not fall under the

agreement. The PS–95 power rate shall

not be available for transactions with a

party who triggers the Share-theShortage agreement if BPA elects to

meet its required service obligations

under the agreement by entering into an

alternative agreement.

Section V. Resource Cost Contribution

BPA has made the following

determinations:

A. The approximate cost contribution

of different resource categories to the

PS–95 rate is based upon the BPA’s

highest cost resource which currently is

an FBS resource.

B. The forecasted average cost of

resources available to BPA under

average water conditions is 19.80 mills

per kilowatt-hour.

C. The forecasted cost of resources to

meet load growth is 60.64 mills per

kilowatt-hour.

Schedule RP–95

Reserve Power Rate

Section I. Availability

This schedule is available for the

purchase of power:

A. In cases where a purchaser’s power

sales contract states that the rate for

Reserve Power shall be applied;

B. For which BPA determines no

other rate schedule is applicable; or

C. To serve a purchaser’s firm power

load in circumstances where BPA does

not have a power sales contract in force

with such purchaser, and BPA

determines that this rate should be

applied.

This rate schedule may be applied to

power purchased by entities outside the

United States. This rate schedule

supersedes Schedule RP–93, which

went into effect on October 1, 1993.

Sales under this schedule are made
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21147

subject to BPA’s General Rate Schedule

Provisions (GRSPs).

Section II. Rate

A. Demand Charge

1. $3.640 per kilowatt of billing

demand occurring during all Peak

Period hours during a billing month.

2. No demand charge during Offpeak

Period hours.

B. Energy Charge

25.30 mills per kilowatt-hour of

billing energy.

Section III. Billing Factors

The factors to be used in determining

the billing for power purchased under

this rate schedule are as follows:

A. Billing Demand

If applicable, the billing demand shall

be the Contract Demand as specified in

the power sales contract. Otherwise the

billing demand shall be the Measured

Demand as adjusted for power factor.

B. Billing Energy

The billing energy shall be the

Contract Demand multiplied by the

number of hours in the billing month,

if use of the Contract Demand for

determining billing energy is specified

in the power sales contract. Otherwise

the billing energy for such purchasers

shall be the Measured Energy.

Section IV. Power Factor Adjustment

The adjustment for power factor,

when specified in this rate schedule or

in the power sales contract, shall be

made in accordance with the provisions

of both this section and section III.C.1

of the GRSPs. The adjustment shall be

made if the average leading power factor

or average lagging power factor at which

energy is supplied during the billing

month is less than 95 percent.

To make the power factor adjustment,

BPA shall increase the billing demand

by 1 percentage point for each

percentage point or major fraction

thereof (0.5 or greater) by which the

average leading power factor or average

lagging power factor is below 95

percent. BPA may elect to waive the

adjustment for power factor in whole or

in part.

Section V. Resource Cost Contribution

BPA has made the following

determinations:

A. The RP–95 rate is not based on the

cost of resources.

B. The forecasted average cost of

resources available to BPA under

average water conditions is 19.80 mills

per kilowatt-hour.

C. The forecasted cost of resources to

meet load growth is 60.64 mills per

kilowatt-hour.

D. General Rate Schedule Provisions

(GRSPs)

Table of Contents

I. Adoption of Revised Rate Schedules and

General Rate Schedule Provisions

A. Approval of Rates

B. General Provisions

II. Types of BPA Service

A. Priority Firm Power

B. New Resource Firm Power

C. Industrial Firm Power

D. Special Industrial Power

E. Auxiliary Power

F. Shortage Power

G. Surplus Firm Power

H. Nonfirm Energy

I. Reserve Power

III. Billing Factors and Billing Adjustments

A. Billing Factors for Demand

B. Billing Factors for Energy

C. Billing Adjustments

D. Billing-Related Definitions

IV. Other Definitions

A. Computed Requirements Purchasers

B. Definitions Relating to Nonfirm Energy

C. NF Rate Cap

D. Determination of BPA’s Average System

Cost

V. Application of Rates Under Special

Circumstances

A. Energy Supplied for Emergency Use

B. Construction, Test and Start-up, and

Station Service

C. Application of Rates During Initial

Operation Period-Transitional Service

D. Changes in a DSI’s BPA Operating Level

E. Restriction of Deliveries

VI. Billing Information

A. Determination of Estimated Billing Data

B. Load Shift and Outage Reports

C. Billing for New Large Single Loads

D. Determination of Measured Demand

E. Determination of Measured Energy

F. Billing Month

G. Payment of Bills

VII. Variable Industrial Rate Parameters and

Adjustments

A. Monthly Average Aluminum Price

Determination

B. Annual Adjustments to the Lower and

Upper Pivot Aluminum Prices

Section I. Adoption of Revised Rate

Schedules and General Rate Schedule

Provisions

A. Approval of Rates

These 1995 rate schedules and

General Rate Schedule Provisions

(GRSPs) shall become effective upon

interim approval or upon final

confirmation and approval by the

Federal Energy Regulatory Commission

(FERC). BPA will request FERC

approval effective October 1, 1995. BPA

proposes that the following schedules,

and the GRSPs associated with these

schedules, be effective for 1 year: PF–95,

IP–95, VI–95, SI–95, CE–95, NR–95, SS–

95, NF–95, PS–95, and RP–95.

B. General Provisions

These 1995 rate schedules, and the

GRSPs associated with these rate

schedules, supersede BPA’s 1993 rate

schedules (which became effective

October 1, 1993) to the extent stated in

the Availability section of each rate

schedule. These schedules and GRSPs

shall be applicable to all BPA contracts,

including contracts executed both prior

to and subsequent to enactment of the

Northwest Power Act. All sales of power

made under these rate schedules are

subject to the following acts as

amended: the Bonneville Project Act,

the Regional Preference Act (Pub. L. 88–

552), the Federal Columbia River

Transmission System Act, and the

Northwest Power Act.

Section II. Types of BPA Service

A. Priority Firm Power

Priority Firm Power is electric power

(capacity, energy, or capacity and

energy) that BPA will make

continuously available for resale to

ultimate consumers for direct

consumption, construction, test and

startup, and station service by public

bodies, cooperatives, and Federal

agencies. (Construction, test and startup, and station service are defined in

section V.B of these GRSPs.)

Utilities participating in the exchange

under section 5(c) of the Northwest

Power Act may purchase Priority Firm

Power pursuant to their Residential

Purchase and Sale Agreements.

In addition, BPA may make Priority

Firm Power available to those parties

participating in exchange agreements

specifying use of the Priority Firm rate

for determining the amount or value of

power to be exchanged.

Power purchased under the rate

schedule is to be used to meet the

purchaser’s actual firm load within the

Pacific Northwest. Such power may be

restricted in accordance with the

Restriction of Deliveries section of these

GRSPs (section V.E). However, BPA

shall not restrict Priority Firm Power

until Industrial Firm Power has been

restricted in accordance with the

provisions of section II.C of these

GRSPs.

Priority Firm Power is not available to

serve New Large Single Loads.

B. New Resource Firm Power

New Resource Firm Power is electric

power (capacity, energy, or capacity and

energy) that BPA will make

continuously available:

1. For any New Large Single Load,

2. For firm power purchased by

investor-owned utilities (IOUs) pursuant

to power sales contracts with BPA, and
21148 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

3. For construction, test and start-up,

and station service for facilities owned

or operated by IOUs.

New Resource Firm Power is to be

used to meet the purchaser’s actual firm

load within the Pacific Northwest. Such

power may be restricted in accordance

with the Restriction of Deliveries

section of these GRSPs (section V.E).

However, BPA shall not restrict New

Resource Firm Power until Industrial

Firm Power has been restricted in

accordance with the provisions of

section II.C of these GRSPs.

C. Industrial Firm Power

Industrial Firm Power is electric

power that BPA will make continuously

available to a direct service industrial

(DSI) purchaser pursuant to the DSI’s

power sales contract and subject to:

1. The restriction applicable to

deliveries of all firm power pursuant to

the Uncontrollable Forces and

Continuity of Service provisions of the

General Contract Provisions of the

power sales contract, and

2. The restrictions given in the

Restriction of Deliveries section of the

power sales contract.

D. Special Industrial Power

Special Industrial Power is electric

power which BPA will make

continuously available to any DSI that

qualifies for the Special Industrial

Power rate pursuant to section 7(d)(2) of

the Northwest Power Act. This power is

similar in nature to Industrial Firm

Power, but is subject to greater

restriction by BPA. Special Industrial

Power is made available to the

qualifying DSI upon adoption of, and

subject to, an amendment modifying its

power sales contract.

E. Auxiliary Power

Auxiliary Power is that power which

a DSI requests and which BPA agrees to

make available to serve that portion of

the DSI’s load which is in excess of the

DSI’s Operating Demand for Industrial

Firm Power or Special Industrial Power.

F. Shortage Power

Shortage Power is energy or energy

with capacity, provided by BPA to a

purchaser to serve such purchaser’s

regional load under circumstances

where the purchaser is in danger of

curtailing firm load even though the

purchaser is operating all available

resources and exercising all contractual

rights to firm power to the maximum

level feasible. In the event of a state

ordered or regionwide load curtailment,

a power deficiency is deemed to exist

for those purchasers whose power

supply condition is in part causally

related to the state(s) initiated load

curtailment.

G. Surplus Firm Power

Surplus Firm Power is firm energy,

firm power (firm energy with capacity),

and firm capacity (capacity with energy

return requirements) in excess of the

amount required to meet BPA’s existing

contractual obligations to provide firm

service. Surplus Firm Power may be

used either for resale or direct

consumption by purchasers both inside

and outside the United States. Such

power, however, may be restricted

pursuant to the Restriction of Deliveries

section of these GRSPs (section V.E).

H. Nonfirm Energy

Nonfirm Energy is supplied or made

available by BPA to a purchaser under

an arrangement that does not have the

guaranteed continuous availability

feature of firm power. Nonfirm energy is

mostly sold under the Nonfirm Energy

rate schedule, NF–95. Nonfirm energy

also may be supplied under the Sharethe-Savings rate schedule, SS–95, which

is available as an experimental rate for

contract purchase.

In addition, BPA also can make

nonfirm energy available under the

Nonfirm Energy rate schedule to the

Western Systems Power Pool (WSPP)

subject to terms and conditions agreed

upon by the members participating in

the WSPP and in accordance with BPA

policy for such arrangements.

However, Nonfirm Energy that has

been purchased under a guarantee

provision in the Nonfirm Energy rate

schedule shall be provided to the

purchaser in accordance with the

provisions of that schedule and the

power sales contract if applicable. BPA

may make Nonfirm Energy available to

purchasers both inside and outside the

United States.

I. Reserve Power

Reserve Power is firm power sold to

a purchaser:

1. In cases where the purchaser’s

power sales contract states that the rate

for Reserve Power shall be applied;

2. To provide service when no other

type of power is deemed applicable; or

3. To serve the purchaser’s firm power

loads under circumstances where BPA

does not have a power sales contract in

force with the purchaser.

Sales of Reserve Power are subject to

the Restriction of Deliveries section of

these GRSPs (section V.E).

Section III. Billing Factors and Billing

Adjustments

A. Billing Factors for Demand

1. Measured Demand

The purchaser’s Measured Demand

shall be determined in the manner

described in this section. Measured

Demand shall be that portion of the

metered or scheduled demand that is

purchased from BPA under the

applicable rate schedule. For those

contracts to which BPA is a party and

that provide for delivery of more than

one class of electric power to the

purchaser at any point of delivery, the

portion of each 60-minute clock-hour

integrated demand assigned to any class

of power shall be determined pursuant

to the power sales contract. The portion

of the total Measured Demand so

assigned shall constitute the Measured

Demand for each such class of power.

The Measured Demand shall be

determined from the metered demand or

the scheduled demand, as hereinafter

defined. The Measured Demand shall be

determined on either a coincidental or

a noncoincidental basis, as provided in

the purchaser’s power sales contract.

a. Metered Demand

The metered demand in kilowatts

shall be the largest of the 60-minute

clock-hour integrated demands,

adjusted as specified in the power sales

contract, at which electric energy is

delivered to a purchaser:

(1) At each point of delivery for which

the metered demand is the basis for

determination of the Measured Demand,

(2) During each time period specified

in the applicable rate schedule, and

(3) During any billing period.

Such largest integrated demand shall

be determined from measurements

made either in the manner specified in

the power sales contract or as provided

in section VI.A herein. In determining

the metered demand, BPA shall exclude

any abnormal integrated demands due

to or resulting from:

(1) Emergencies or breakdowns on, or

maintenance of, the Federal system

facilities; and

(2) Emergencies on the purchaser’s

facilities, provided that such facilities

have been adequately maintained and

prudently operated, as determined by

BPA.

b. Scheduled Demand

The scheduled demand in kilowatts

shall be the largest of the hourly

demands at which electric energy is

scheduled for delivery to a purchaser:

(1) To each system for which

scheduled demand is the basis for

determination of the Measured Demand;
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21149

(2) During each time period specified

in the applicable rate schedule; and

(3) During any billing period.

Scheduled amounts are deemed

delivered for the purpose of determining

billing demand.

2. Ratchet Demand

The Ratchet Demand in kilowatts

shall be the maximum demand

established during a specified period of

time either during or prior to the current

billing period. The demand on which

the ratchet is based is specified in the

relevant rate schedule or in these

GRSPs. For utilities purchasing under

the PF or NR rate schedules, the Ratchet

Demand is based on the highest demand

during prior billing months. When the

Ratchet Demand is used as a billing

factor, BPA shall have specified in the

appropriate schedules or GRSPs:

a. The period of time over which the

ratchet shall be calculated;

b. The type of demand to be used in

the calculation; and

c. The percentage (if any) of that

demand which will be used to calculate

the Ratchet Demand.

3. Contract Demand

The Contract Demand shall be the

maximum number of kilowatts that the

purchaser agrees to purchase and BPA

agrees to make available, subject to any

limitations included in the power sales

contract. BPA may agree to make

deliveries at a rate in excess of the

Contract Demand at the request of the

purchaser, but shall not be obligated to

continue such excess deliveries. Any

contractual or other reference to

Contract Demand as expressed in

kilowatt-hours shall be deemed, for the

purpose of these GRSPs, to refer to the

term ‘‘Contract Energy.’’

4. Computed Peak Requirement

For purchasers designated to purchase

on the basis of computed requirements,

the Computed Peak Requirement shall

be determined as specified in the

purchaser’s power sales contract. That

specification is provided in:

a. Sections 16, 17(c), and 17(f), as

adjusted by other sections of the

contract, for actual computed

requirements purchasers;

b. Sections 16, 17(a), and 17(f), as

adjusted by other sections of the

contract, for planned computed

requirements purchasers; and

c. Sections 16 and 17(b), as adjusted

by other sections of the contract, for

contracted computed requirements

purchasers.

5. Computed Average Energy

Requirement

For computed requirements

purchasers, the Computed Average

Energy Requirement shall be

determined as specified in the

purchaser’s power sales contract. That

specification is provided in:

a. Sections 16, 17(c), and 17(f), as

adjusted by other sections of the

contract, for actual computed

requirements purchasers;

b. Sections 16, 17(a), and 17(f), as

adjusted by other sections of the

contract, for planned computed

requirements purchasers; and

c. Sections 16 and 17(b), as adjusted

by other sections of the contract, for

contracted computed requirements

purchasers.

6. Operating Demand

The Operating Demand is that

demand which is established by each

DSI in accordance with section 5(b) of

the DSI’s power sales contract. Unless

the DSI has requested, and BPA has

granted, an Auxiliary Demand, the

Operating Demand establishes a limit

with respect to:

a. The demand which the purchaser

may impose on BPA; and

b. The total amount of energy during

a billing month which the DSI is

entitled to purchase from BPA.

7. Curtailed Demand

A Curtailed Demand is the number of

kilowatts of industrial power (Industrial

Firm Power or Special Industrial Power)

during the billing month which results

from the DSI’s request for such power in

amounts less than the Operating

Demand therefor. Each purchaser of

industrial power may curtail its demand

according to the terms of its power sales

contract (which permits up to three

levels of Curtailed Demand each

month).

8. Restricted Demand

Restricted Demand is the number of

kilowatts of industrial power (either

Industrial Firm Power or Special

Industrial Power) that results when BPA

has restricted delivery of such power for

one clock-hour or more. BPA shall make

such restrictions according to the terms

of the DSI’s power sales contract. In a

given billing month, there are as many

possible levels of Restricted Demand for

a DSI as there are number of restrictions.

9. Auxiliary Demand

Auxiliary Demand is the number of

kilowatts of Auxiliary Power that a DSI

requests and that BPA agrees to make

available to serve a portion of the DSI’s

load during the period specified in the

DSI’s request. The DSI may request up

to three levels of Auxiliary Demand

during a billing month.

If BPA agrees to a request for

Auxiliary Power but later becomes

unable to supply such demand, the

Restricted Demand for Auxiliary Power

is deemed to be the Auxiliary Demand

for such period of restriction. Auxiliary

Power may be curtailed by the DSI

according to the provisions of section

9(a) of the DSI’s power sales contract.

BPA shall make Auxiliary Power

available to Industrial Firm Power

purchasers under the Industrial Firm

Power rate schedule at the Standard

Industrial rate. Auxiliary Power sales to

DSIs electing to purchase under the

Variable Industrial Power rate schedule

(VI–95) shall be made at the rate

determined pursuant to section III of the

VI–95 rate schedule. Auxiliary Power

sales to DSIs purchasing under the

Special Industrial rate will be made

only at the Standard Special Industrial

Power rate.

10. BPA Operating Level

The BPA Operating Level is, for the

purpose of these rate schedules and

GRSPs, an hourly amount of industrial

power (Industrial Firm Power or Special

Industrial Power) for a DSI that is equal

to the lowest of the following demands

during that hour:

a. Operating Demand plus Auxiliary

Demand, if any;

b. Curtailed Demand; or

c. Restricted Demand.

The weighted average BPA Operating

Level for each DSI can be determined by

summing the hourly BPA Operating

Levels and dividing by the number of

hours in the billing month.

Each DSI must request service from

BPA for each billing month in

accordance with the terms of the power

sales contract. The requested level of

service will be the BPA Operating Level,

provided BPA does not need to restrict

the DSI and provided BPA agrees to

supply any requested Auxiliary

Demand. Each requested level of service

may include a designation for both the

Peak Period and the Offpeak Period. A

DSI may request and BPA may agree to

a level of service for the Offpeak Periods

other than that in the Peak Period. If a

DSI does not separately designate a

requested level of service for the Peak

and Offpeak Periods, the BPA Operating

Level is the basis for determining if a

DSI has incurred an unauthorized

increase.

Any DSI whose Measured Demand,

before adjustment for power factor,

during any 1 hour exceeds the BPA

Operating Level for that hour shall be

subject to unauthorized increase charges
21150 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

for each kilowatt-hour of unauthorized

increase associated with each overrun.

Only the BPA Operating Level

applicable during the Peak Period will

be used in determining the Billing

Demand for power purchased under the

Industrial Firm Power rate schedule, the

Variable Industrial Power rate schedule,

and the Standard rate under the Special

Industrial rate schedule. During the

Peak Period the BPA Operating Level

may be no greater than the Operating

Demand for the billing month unless the

customer has requested, and BPA has

agreed to supply, the Auxiliary Demand.

B. Billing Factors for Energy

1. Measured Energy

Measured Energy shall be that portion

of the metered or scheduled energy that

is purchased from BPA under the

applicable rate schedule. For those

contracts to which BPA is a party and

that provide for delivery of more than

one class of electric power to the

purchaser at any point of delivery, the

portion of each 60-minute clock-hour

integrated demand assigned to any class

of power shall be determined pursuant

to the power sales contract. The sum of

the portions of the demands so assigned

shall constitute the Measured Energy for

each such class of power.

The Measured Energy shall be

determined from the metered energy or

the scheduled energy, as hereinafter

defined.

a. Metered Energy

The metered energy for a purchaser

shall be the number of kilowatt-hours

that are recorded on the appropriate

metering equipment, adjusted as

specified in the power sales contract,

and delivered to a purchaser:

(1) At all points of delivery for which

metered energy is the basis for

determination of the Measured Energy,

and

(2) During any billing period.

The metered energy shall be

determined from measurements made

either in the manner specified in the

power sales contract or as provided in

section VI.A herein.

b. Scheduled Energy

The scheduled energy in kilowatthours shall be the sum of the hourly

demands at which electric energy is

scheduled for delivery to a purchaser:

(1) For each system for which

scheduled energy is the basis for

determination of the Measured Energy,

and

(2) During any billing period.

Scheduled amounts are deemed

delivered for the purpose of determining

billing energy.

2. Computed Energy Maximum

The Computed Energy Maximum

equals the product of the number of

hours in the billing month and the

Computed Average Energy Requirement.

3. Contract Energy

The Contract Energy shall be the

maximum number of kilowatt-hours

that the purchaser agrees to purchase

and BPA agrees to make available,

subject to any limitations included in

the power sales contract.

C. Billing Adjustments

1. Power Factor Adjustment

The formula for determining average

power factor is as follows:

Average Power Factor

Kilowatt - hours

Kilowatt - hours (Reactive kilovoltamperehours) 2 2 =( ) +

The data used in the above formula

shall be obtained from meters that are

ratcheted to prevent reverse registration.

These data then shall be adjusted for

losses, if applicable, before

determination of the average power

factor.

When deliveries to a purchaser at any

point of delivery either:

a. Include more than one class of

power; or

b. Are provided under more than one

rate schedule and it is impracticable to

meter the kilowatt-hours and reactive

kilovoltamperehours for each class or

rate schedule separately, the average

power factor of the total deliveries for

the month will be used, where

applicable, as the power factor for all

power delivered to such point of

delivery.

To maintain acceptable operating

conditions on the Federal system, BPA

may, unless specifically otherwise

agreed, restrict deliveries of power to a

purchaser with a low power factor. Such

restriction may be made to a point of

delivery or to a purchaser’s system at

any time that the average leading power

factor or average lagging power factor

for all classes of power delivered to

such point or to such system is below

75 percent.

2. Outage Credit

To the extent that BPA is unable to

provide full service to a purchaser

during the billing month as a result of

interruptions in service due to reasons

cited in the General Contract Provisions,

BPA shall adjust the charges for those

hours for billing demand for such

purchaser to reflect BPA’s inability to

provide full service, provided such

adjustment is mandated by the

purchaser’s power sales contract. The

adjustment is provided on a point of

delivery basis. To compute the

adjustment for noncoincidentally billed

systems, BPA shall determine the

monthly demand charge(s) for the

point(s) of delivery where the outage(s)

occurred, multiply by the number of

hours of outage, and divide by the total

number of hours in the billing month.

For coincidentally billed points of

delivery, the adjustment shall apply

only to those points of delivery at which

BPA was unable to provide full service.

For partial outages (such as an outage on

one feeder in a substation with several

feeders), BPA shall determine an

equivalent interruption in order to

arrive at the number of hours to be used

in the calculation of the credit.

3. Low Density Discount (LDD)

a. Basic LDD Principles

A predetermined discount shall be

applied each billing month to the

charges for all power purchased under

the Priority Firm Power rate schedule by

eligible purchasers as defined in section

b, below. The discount shall be

calculated on an annual basis and shall

become effective with the first billing

period in the calendar year. Retroactive

billing for the LDD may be required if

the data are not available by the January

billing date. The level of the discount

shall be determined from the following

ratios:

(1) The purchaser’s total electric

energy requirements during the

previous calendar year (the purchaser’s

firm sales, nonfirm sales to firm retail

loads, sales for resale, and associated

losses, but excluding nonfirm sales to

nonfirm retail loads, such as boiler

loads served under BPA’s alternate fuel

policy) divided by the value of the

purchaser’s depreciated electric plant

(excluding generation plant) at the end

of such year, and
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21151

(2) The average number of consumers

(annual and seasonal consumers with

residential, industrial, commercial, and

irrigation accounts, but excluding

separately billed services for water

heating, electric space heating, and

security lights) during the previous

calendar year divided by the number of

pole miles of distribution line at the end

of such year. Distribution lines are

defined as those that deliver electric

energy from a substation or metering

point, at a voltage of 34.5 kV or less, to

the point of attachment to the

consumer’s wiring and include primary,

secondary, and service facilities.

These calculations shall be based on

data provided in the purchaser’s annual

financial and operating report. In

calculating these ratios, BPA shall use

data pertaining to the purchaser’s entire

electric utility system within the region.

Results of the calculations shall not be

rounded.

Customers who have not provided

BPA with all four requisite pieces of

annual data (see a.(1) and a.(2) above) by

June 30 of each year shall be declared

ineligible for the LDD effective with the

June billing period for that year. BPA

shall extend a customer’s eligibility

from the previous year through the June

billing period of the following year and

shall make any necessary retroactive

adjustments once the new data have

been processed. If no data have been

received by December 31 for the

previous calendar year, BPA shall

assume that the utility did not qualify

for an LDD for that year. LDDs issued

from January 1 to June 30 shall be

assumed to have been in error, and the

utility shall be billed for any such

discounts issued.

Revisions to the data used to calculate

the amount of the LDD may be made by

the purchaser for a period of up to 2

years from the first day to which the

data apply. However, such revisions

shall not apply to periods when the

customer was ineligible for a discount

due to late data submission.

b. Eligibility Criteria

To qualify for a discount, the

purchaser must meet all six of the

following eligibility criteria:

(1) The purchaser must serve as an

electric utility offering power for resale;

(2) The purchaser must agree to pass

the benefits of the discount through to

the purchaser’s consumers within the

region served by BPA;

(3) The purchaser’s average retail rate

for the reporting year must exceed the

average Priority Firm Power rate in

effect for the qualifying period by 10

percent. For Calendar Year (CY) 1995,

the average Priority Firm Power rate

shall be the average of the PF–93

Preference rate for 9 months and the

PF–95 Preference rate for 3 months;

(4) The purchaser’s kilowatt-hour-toinvestment ratio (Ratio 3.a.(1)) must be

less than 100;

(5) The purchaser’s consumers-permile ratio (Ratio 3.a.(2)) must be less

than 12; and

(6) The purchaser must qualify for a

discount based on the criteria in section

c, below.

c. Discounts

The purchaser shall be awarded the

greatest discount for which that

purchaser qualifies. The discounts and

the qualifying criteria for those

discounts are listed below.

(1) Three percent, for any purchaser

for whom:

(a) The kilowatt-hour-to-investment

ratio is equal to or greater than 25 but

less than 35; or

(b) The consumers-per-mile ratio is

equal to or greater than 5 but less than

7.

(2) Five percent, for any purchaser for

whom:

(a) The kilowatt-hour-to-investment

ratio is equal to or greater than 15 but

less than 25; or

(b) The consumers-per-mile ratio is

equal to or greater than 3 but less than

5.

(3) Seven percent, for any purchaser

for whom:

(a) The kilowatt-hour-to-investment

ratio is less than 15; or

(b) The consumers-per-mile ratio is

less than 3.

4. Irrigation Discount

a. Basic Irrigation Discount Principles

A discount of 4.90 mills per kilowatthour shall be applied to the charges for

qualifying irrigation energy purchased

under the Priority Firm Power and New

Resource Firm Power rate schedules,

during the billing months of April

through October. This discount shall be

applied subsequent to calculation of the

LDD, if applicable. Any energy on

which the irrigation discount is claimed

shall be metered separately by the

Purchaser, and used exclusively for

agricultural irrigation or drainage

pumping.

b. Qualifying Energy Purchases

The qualifying irrigation energy shall

be determined as follows:

(1) All irrigation energy must be used

exclusively for the purpose of irrigation

and drainage pumping on agricultural

land and be measured at the end-use

irrigation customer’s meter. The

discount shall apply to the measured

energy sales at the end-use.

(2) Energy subject to the discount

must be purchased during the billing

months of April through October.

(3) Purchasers of exchange energy

under the Residential Purchase and Sale

Agreement (RPSA) are eligible for the

irrigation discount for the portion of

their irrigation sales qualifying for the

exchange under the RPSA contracts.

However, if the purchaser also

purchases energy from BPA for general

requirements, and receives an irrigation

discount on those purchases, a second

irrigation discount will not be applied

to that energy through the RPSA

exchange. Therefore, the irrigation

discount will not be applied to any

portion of the purchaser’s irrigation

sales qualifying for the RPSA exchange

that receives the discount as a general

requirements purchase.

(4) General requirements customers

are eligible for an irrigation discount for

a portion of their irrigation sales equal

to the share of their total sales served by

BPA firm purchases (i.e., total irrigation

and drainage pumping sales multiplied

by BPA billing energy for Priority Firm

or New Resources firm purchases

divided by the total firm utility system

requirements for the billing month).

c. Initial Reporting Requirements

Requests for the Irrigation Discount

must include the following information:

(1) To receive an irrigation discount,

a purchaser must file a request for the

discount with its local BPA regional

office by April 1 each year.

(2) In the request, the purchaser must

certify that the irrigation energy is sold

exclusively for use in irrigation and

drainage pumping on agricultural land

and that the discount is passed, in its

entirety, to the irrigation consumer,

regardless of whether the utility has

raised its rates. BPA retains the right to

verify, in a manner satisfactory to the

Administrator, that the discounted

energy is used for the sole benefit of the

purchaser’s irrigation load.

d. Annual Reporting Requirements

Purchasers shall submit an annual

irrigation report to their local BPA

regional office in order to receive the

irrigation discount. Purchasers are

required to report information related to

monthly irrigation energy sales. If a

utility does not read its irrigation meters

monthly, the utility must estimate its

monthly irrigation sales. These

estimates shall be reviewed by BPA

regional offices. Purchasers must read

their meters within 3 working days of

the beginning and ending of the

irrigation discount period (AprilOctober). In order to qualify for the

discount, the purchaser must submit all
21152 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

data to BPA by December 31 of the

calendar year in which the sales

occurred. Irrigation reports to BPA shall

include the following monthly

information for the reporting period:

(1) Utility name and period for which

the report is being made;

(2) Total irrigation sales and total

qualifying irrigation energy sales (in

kilowatt-hours) by month;

(3) Total qualifying irrigation sales (in

kilowatt-hours) by month under 400

horsepower, for exchanging utilities;

(4) Total utility firm system

requirements for other than full

requirement customers by month (in

kilowatt-hours);

(5) Total energy purchased from BPA

under the Priority Firm or New

Resource rate by month in kilowatthours; and

(6) The Purchaser shall list each

irrigation and drainage account number

in its annual report and whether each

irrigation consumer is billed monthly,

bimonthly, or seasonally. If the

Purchaser is an exchanging utility, the

Purchaser shall also identify the size (in

horsepower) of the connected load for

each active account. A utility may

submit monthly reports, if it chooses. In

that case, the active list of accounts

should be included in the last monthly

report submitted.

5. Coincidental Billing

Purchasers of Priority Firm Power and

New Resource Firm Power shall be

billed on a noncoincidental demand

basis for power purchased at each point

of delivery under the applicable rate

schedule(s) unless the power sales

contract specifically provides for

coincidental demand billing among

particular points of delivery. For the

purpose of these rate schedules and

GRSPs, the purchaser’s noncoincidental

demand is the sum of the highest hourly

peak demands during the billing month

for each of the purchaser’s points of

delivery. The purchaser’s coincidental

demand is the highest demand for the

billing month calculated by summing,

for each hour of every day, the

purchaser’s demands for power

purchased under the applicable rate

schedule at all coincidentally billed

points of delivery. See Special

Provisions Exhibits of the Power Sales

Contract, GCP E 17.

6. Conservation Surcharge

The Conservation Surcharge shall be

applied monthly and shall equal 10

percent of the customer’s total monthly

charge for all power purchased under

each rate schedule subject to the

surcharge. The PF and NR rate

schedules are subject to the

Conservation Surcharge. If only a

portion of the customer’s service area is

subject to the surcharge, then the

amount of the surcharge shall equal 10

percent of the total charge for all power

purchases multiplied by: (a) The portion

of the customer’s total retail load that is

subject to the surcharge, divided by (b)

the customer’s total retail load.

D. Billing-Related Definitions

1. Peak Period

The Peak Period includes the hours

from 7 a.m. through 10 p.m. on any day

Monday through Saturday inclusive.

There are no exceptions to this

definition; that is, it does not matter

whether the day is a normal working

day or a holiday. Any charges based on

Peak Period hours shall be computed

starting with the 8 a.m. meter reading

since this reading applies to the 7

o’clock hour (7 a.m. to 8 a.m.). The 10

p.m. meter reading (for the 9 p.m. to 10

p.m. period) is the last meter reading of

the day applicable to the Peak Period.

2. Offpeak Period

The Offpeak Period includes all hours

which do not occur during the Peak

Period. Thus, the Offpeak Period

consists of the hours from 10 p.m. to 7

a.m., Monday through Saturday and all

hours on Sunday.

Section IV. Other Definitions

A. Computed Requirements Purchasers

1. Designation as a Computed

Requirements Purchaser

A purchaser shall be designated as a

computed requirements purchaser if it

is so designated pursuant to the

provisions of its power sales contract.

When a purchaser operates two or

more separate systems, only those

systems designated by BPA will be

covered by this section.

2. Purpose of the Computed

Requirements Designation

Use of the computed requirements

designation is intended to assure that

each purchaser who purchases power

from BPA to supplement its own firm

resources will purchase amounts of firm

capacity and firm energy substantially

equal to that which the purchaser would

otherwise have to provide on the basis

of normal and prudent operations.

The amount of capacity and energy

required for normal and prudent

operations shall be determined pursuant

to the purchaser’s power sales contract.

B. Definitions Relating to Nonfirm

Energy Decremental Cost

Unless otherwise specified in a

contractual arrangement, decremental

cost as applied to Nonfirm Energy

transactions shall be defined as:

1. All identifiable costs (expressed in

mills per kilowatt-hour) associated with

the use of a displaceable thermal

resource or end-user load with alternate

fuel source to serve a purchaser’s load

that the purchaser is able to avoid by

purchasing power from BPA, rather than

generating the power itself or using an

alternate fuel source; or

2. All identifiable costs (expressed in

mills per kilowatt-hour) to serve the

load of a displaceable purchase of

energy that the purchaser is able to

avoid by choosing not to make the

alternate energy purchase.

All identifiable costs as used in the

above definition may be reduced to

reflect costs of purchasing BPA energy

such as transmission costs, losses, or

loopflow constraints that are agreed to

by BPA and the purchaser.

C. NF Rate Cap

1. Application of the NF Rate Cap

The NF Rate Cap defines the

maximum nonfirm energy price for

general application. At no time shall the

total price for nonfirm energy, including

any applicable service charges or rate

adjustment, sold under any applicable

rate schedule exceed the NF Rate Cap.

The level of the NF Rate Cap is based

on a formula tied to BPA’s system cost

and California fuel costs. The NF Rate

Cap applies to all sales of nonfirm

energy under any applicable rate

schedule for a 12-year period beginning

October 1, 1987.

2. Monthly Notification of the NF Rate

Cap

Prior to the beginning of a calendar

month BPA shall perform the

calculations contained in section IV.C.3

of these GRSPs to determine the

effective NF Rate Cap for that calendar

month. BPA is obligated to provide

advance notification of the NF Rate Cap

level to purchasers of nonfirm energy.

BPA may waive this requirement only if

BPA does not intend to offer Nonfirm

Energy at prices above BPA’s Average

System Cost (BASC) at any time during

a month. The notification will be given

at least 10 calendar days prior to the

first day of any calendar month in

which the NF Rate Cap applies. BPA

shall also maintain, on file for public

review, a record of the NF Rate Cap by

month throughout the period the cap is

in effect.

3. NF Rate Cap Formula

The NF Rate Cap shall be equal to the

greater of the following:

a. BASC; or
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21153

b. BASC + .30(DEC¥BASC)

Where:

BASC=BPA’s average system cost,

determined by dividing BPA’s total

system costs by BPA’s total system

sales. For this rate period BASC has

been determined to be 29.41 mills

per kilowatt-hour.

DEC=The Decremental Fuel Cost as

determined in accordance with

section IV.C.5 of these GRSPs.

4. Determination of BASC

For purposes of determining BASC,

the following definition shall apply:

a. BPA’s total system costs shall be

the sum of all BPA’s costs forecasted in

each general rate case for the applicable

rate period, including total transmission

costs, Federal base system costs, new

resource costs, exchange resource costs,

and other costs not specifically

allocated to a rate pool, such as section

7(g) costs.

b. BPA’s total annual system sales

shall be the sum of all BPA’s system

firm and nonfirm sales forecasted each

general rate case for the applicable test

period. BASC shall be redetermined in

each subsequent general rate case

according to the above formula and will

be in effect for the entire rate period

over which the rates are in effect.

5. Determination of Decremental Fuel

Cost

The Decremental Fuel Cost shall be

determined monthly by BPA. For

purposes of calculating the NF Rate Cap,

a weighted average of gas and petroleum

prices for California will be used for

approximating decremental fuel costs.

The monthly decremental fuel cost shall

be:

a. the sum of:

(1) The average California price for

gas determined by multiplying the

monthly gas use (WGU) developed

pursuant to section IV.C.8.a times the

monthly California gas price (MGP)

determined pursuant to section IV.C.6

rounded to the nearest tenth of a mill;

and

(2) The average California price for

petroleum determined by multiplying

the monthly petroleum use (WOU)

developed pursuant to section IV.C.8.b

times the monthly California petroleum

price (MOP) determined pursuant to

section IV.C.7 rounded to the nearest

tenth of a mill.

b. Divided by the sum of the WGU

and WOU developed in sections

IV.C.8.a and b, respectively, rounded to

the nearest tenth of a mill.

6. California Gas Price

The MGP for purposes of calculating

the decremental cost component of the

rate cap shall be based on the following

formula:

MGP

AGP * HGP

10 =

Where:

AGP=the average gas price for California

electric utility plants expressed in

cents per million Btu as reported in

the most recent monthly issue of

Electric Power Monthly (EPM)

published by the Energy

Information Administration (EIA),

U.S. Department of Energy. Prices

shall be rounded to the nearest onetenth of a cent.

HGP=the historical relationship

between gas prices in the effective

month of the NF Rate Cap (month

t) and the month in which the gas

prices are reported in EPM (month

r) using the following procedures:

a. Summing all California gas prices,

expressed in the nearest one-tenth of a

cent per million Btu, reported in EPM

for month t for the years beginning with

calendar year 1982 up to and including

the prior calendar year. The sum of the

historical monthly California gas prices

shall be divided by the number of years

for which MGPs were reported and

rounded to the nearest one-tenth of a

cent;

b. Summing all California gas prices,

expressed in the nearest one-tenth of a

cent per million Btu, reported in EPM

for month r for the years beginning with

calendar year 1982 up to and including

the prior calendar year. The sum of the

historical monthly California gas prices

shall be divided by the number of years

for which MGPs were reported and

rounded to the nearest one-tenth of a

cent; and

c. Dividing the average monthly

California gas price in a. above, by the

average monthly California gas price in

b. above, and rounding to the nearest

one-tenth, or three significant places.

10=the factor for converting gas prices

stated in cents per million Btu to

mills per kWh. The factor assumes

a heat rate of 10,000 Btu per

kilowatt-hour.

7. California Petroleum Price

The MOP for purposes of calculating

the decremental cost component of the

rate cap shall based on the following

formula:

MOP =

AOP * HOP

10

Where:

AOP=the last available average oil price

for California electric utility plants

expressed in cents per million Btu

reported in EPM published by the

EIA, U.S. Department of Energy.

Prices shall be rounded to the

nearest one-tenth of a cent.

HOP=the historical relationship

between petroleum prices in the

effective month of the NF Rate Cap

(month t) and the last month in

which the petroleum prices are

reported in EPM (month r) using the

following procedures:

a. Summing all California petroleum

prices, expressed in the nearest onetenth of a cent per million Btu, reported

in EPM for month t for the years

beginning with calendar year 1982 up to

and including the prior calendar year.

The sum of the historical monthly

California petroleum prices shall be

divided by the number of years for

which monthly petroleum prices were

reported and rounded to the nearest

one-tenth of a cent;

b. Summing all California petroleum

prices, expressed in the nearest onetenth of a cent per million Btu, reported

in EPM for month r for the years

beginning with calendar year 1982 up to

and including the prior calendar year.

The sum of the historical monthly

California petroleum prices shall be

divided by the number of years for

which monthly petroleum prices were

reported and rounded to the nearest

one-tenth of a cent; and

c. Dividing the average monthly

California petroleum price in a. above,

by the average monthly California

petroleum price in b. above, and

rounding to the nearest one-tenth of a

percent, or three significant places.

10=the factor for converting petroleum

prices stated in cents per million

Btu to mills per kWh. The factor

assumes a heat rate of 10,000 Btu

per kilowatt-hour.

8. Weighting Factors

For purposes of determining

California fuel prices for the month, gas

and petroleum prices will be weighted

based on California’s historical use of

these two alternative fuels.

a. Historical Gas Use in California.

The following formula shall be used to

determine the weighting factor for gas

prices (WGU):

WGU=CGU*HGU

Where:

CGU=the monthly net gas-fired

generation, expressed in

gigawatthours, for California in the

most recent monthly issue of EPM

published by the EIA, U.S.

Department of Energy.

HGU=the historical relationship

between gas consumptions in the
21154 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

effective month of the NF Rate Cap

(month t) and the month for which

gas consumption is reported in EPM

(month r) using the following

procedures:

(1) Summing the reported net-gas

fired generation for California,

expressed in gigawatthours, from EPM

for month t for the years beginning with

calendar year 1982 up to and including

the prior calendar year. The sum of

California’s historical monthly

consumption shall be divided by the

number of years for which gas

consumption was reported and rounded

to the nearest gigawatthour;

(2) Summing the reported net gasfired generation for California,

expressed in gigawatthours, from EPM

for month r for the years beginning with

calendar year 1982 up to and including

the prior calendar year. The sum of

California’s historical monthly

consumption shall be divided by the

number of years for which gas

consumption was reported and rounded

to the nearest gigawatthour; and

(3) Dividing the average consumption

of gas in California for the month t as

determined in (1) above by the average

consumption of gas for the month r as

determined in (2) above and rounding to

the nearest one-tenth, or three

significant places.

b. Historical Petroleum Use in

California. The following formula shall

be used to determine the weighting

factor for petroleum prices (WOU):

WOU=COU*HOU

Where:

COU=the monthly net petroleum-fired

generation, expressed in

gigawatthours, in California in the

most recent monthly issue of EPM

published by the EIA, U.S.

Department of Energy.

HOU=the historical relationship

between petroleum consumptions

in the effective month of the NF

Rate Cap (month t) and the month

for which petroleum consumption

is reported in EPM (month r) using

the following procedures:

(1) Summing the reported netpetroleum generation for California,

expressed in gigawatthours, from EPM

for month t for the years beginning with

calendar year 1982 up to and including

the prior calendar year. The sum of

California’s historical monthly

consumption shall be divided by the

number of years for which petroleum

consumption was reported and rounded

to the nearest gigawatthour;

(2) Summing the reported netpetroleum generation for California,

expressed in gigawatthours, from EPM

for month r for the years beginning with

calendar year 1982 up to and including

the prior calendar year. The sum of

California’s historical monthly

consumption shall be divided by the

number of years for which petroleum

consumption was reported and rounded

to the nearest gigawatthour; and

(3) Dividing the average consumption

of petroleum in California for the month

t as determined in (1) above by the

average consumption of petroleum for

the month r or as determined in (2)

above and rounding to the nearest onetenth, or three significant places.

D. Determination of BPA’s Average

System Cost

For purposes of determining BASC,

the following definitions shall apply:

1. BPA’s total system costs shall be

the sum of all BPA’s costs forecasted in

each general rate case for the applicable

rate period, including total transmission

costs, Federal base system costs, new

resource costs, exchange resource costs,

and other costs not specifically

allocated to a rate pool, such as section

7(g) costs.

2. BPA’s total annual system sales

shall be the sum of all BPA’s system

firm and nonfirm sales forecasted in

each general rate case for the applicable

test period.

BASC shall be redetermined in each

subsequent general rate case according

to the above formula and will be in

effect for the entire rate period over

which the rates are in effect.

Section V. Application of Rates Under

Special Circumstances

A. Energy Supplied for Emergency Use

A purchaser taking Priority Firm or

New Resource Firm Power shall pay in

accordance with the Nonfirm Energy

rate schedule, NF–95, and Emergency

Capacity rate schedule, CE–95, for any

electric energy or capacity which has

been supplied:

1. For use during an emergency on the

purchaser’s system, or

2. Following an emergency to replace

energy secured from sources other than

BPA during such emergency.

Mutual emergency assistance may,

however, be provided and payment

therefore settled under exchange

agreements.

B. Construction, Test and Start-Up, and

Station Service

Power for the purpose of construction,

test and start-up, and station service

shall be made available to eligible

purchasers under the Priority Firm and

New Resource Firm Power Rate

Schedules. Such power must be used in

the manner specified below:

1. Power sold for construction is to be

used in the construction of the project.

2. Power sold for test and start-up

may be used prior to commercial

operation both to bring the project on

line and to ensure that the project is

working properly.

3. Power sold for station service may

be purchased at any time following

commercial operation of the project.

Station service power may be used for

project start-up, project shut-down,

normal plant operations, and operations

during a plant shut-down period.

C. Application of Rates During Initial

Operation Period—Transitional Service

1. Eligibility for Transitional Service

For an initial operating period, as

specified in the power sales contract,

beginning with the commencement of

operation of a new industrial plant, a

major addition to an existing plant, or

reactivation of an existing plant or

important part thereof, BPA may agree

to bill the purchaser in accordance with

the provisions of this section. This

section shall apply to both:

a. DSIs having new, additional or

reactivated plant facilities, and

b. Utility purchasers serving

industrial purchasers with power

purchased from BPA. BPA will provide

transitional service to utilities for only

those industrial loads for which the

demand can be separately metered by

the utility and recorded on a daily basis.

2. Calculation of the Daily Demand

If the purchaser requests billing on a

Daily Demand basis pursuant to its

power sales contract and if BPA agrees

to such billing, the billing demand for

the billing month shall be the average of

the Daily Demands as adjusted for

power factor.

Demand for each day shall be defined

as 100 percent of the Measured Demand

for the day (regardless of whether such

Measured Demand occurs during the

Peak Period or the Offpeak Period).

3. Billing for Transitional Service

Utilities receiving transitional service

shall provide BPA with Daily Demand

information for the industrial consumer

for whom transitional service is

provided. To compute the power bill for

the point of delivery which includes the

load being served with transitional

service, BPA shall, at its discretion,

either:

a. Determine the demand for the

pertinent point of delivery without the

industrial load and then add the average

daily demand for such industrial load;

or

b. Bill the entire point of delivery on

a daily demand basis.
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21155

Daily demand billing shall not affect

the level of any curtailment charge or

energy charge assessed by BPA.

D. Changes in a DSI’s BPA Operating

Level

If a DSI requests a waiver regarding

the notice requirements specified in the

DSI’s power sales contract for a

voluntary change in its BPA Operating

Level, and if BPA does not grant the

waiver, or if the DSI fails to give notice

of such a change and does not request

a waiver, the DSI shall be billed as if no

notice has been provided until such

time as the number of days in the notice

period have passed. If, however, BPA

agrees to waive the notice requirement,

the power bill shall reflect the requested

changes as of the requested effective

date specified in the notice or, at BPA’s

discretion, a date of BPA’s choosing

within the notice period.

E. Restriction of Deliveries

Deliveries of capacity or energy to any

purchaser may be restricted when

operation of the facilities used by BPA

to serve such purchaser is:

1. Suspended,

2. Interrupted,

3. Interfered with,

4. Curtailed, or

5. Restricted by the occurrence of any

condition described in the

Uncontrollable Forces or Continuity of

Service sections of the General Contract

Provisions of the power sales contract.

Section VI. Billing Information

A. Determination of Estimated Billing

Data

If the amounts of capacity, energy, or

the 60-minute integrated demands for

energy purchased from BPA must be

estimated from data other than metered

or scheduled quantities, historical

patterns, and pertinent weather data,

BPA and the purchaser will agree on

billing data to be used in preparing the

bill. If the parties cannot agree on

estimated billing quantities, derived by

any method, a determination binding on

both parties shall be made in

accordance with the arbitration

provisions of the power sales contract.

B. Load Shift and Outage Reports

Load shift and outage reports must be

submitted to BPA within 4 days of the

corresponding load shift or outage.

Reports may be made by telephone,

mail, or other electronic processes

where available. If customer reports are

not received in a timely manner, BPA

has the option to withhold load shift or

outage credit.

C. Billing for New Large Single Loads

Any BPA customer whose actual firm

load includes one or more New Large

Single Loads (NLSL) shall be billed for

the NLSL(s) at the New Resource Firm

Power Rate. The power requirements

associated with the NLSL shall be

established in a manner consistent with

the provisions of this section.

The purchaser shall warrant to BPA

that NLSLs are separately metered. The

metering must include provisions for

determining:

1. The NLSL demand during BPA’s

diurnal capacity billing periods,

2. The NLSL energy during BPA’s

energy billing periods, and

3. The NLSL reactive energy for the

billing month.

The design for the metering

equipment for the NLSL must be

approved by BPA. Testing and

inspections of such metering

installations shall be as provided in the

General Contract Provisions.

On a monthly basis, each purchaser of

New Resource Firm Power shall report

to BPA the quantity of power used by

the NLSL during the purchaser’s billing

period. Data provided to BPA by the

purchaser must be submitted to BPA

within 2 normal working days of the

date the purchaser reads the meters.

BPA may elect to adjust the NLSL data

for losses from the point of metering to

the closest BPA point of delivery for the

purchaser.

D. Determination of Measured Demand

1. For points of delivery with fully

operational metering under the Revenue

Metering System (RMS), demand shall

be measured from 0000 hours on the

first day of the billing period through

2400 hours on the last day of the billing

period.

2. For points of delivery that do not

have RMS metering, demand shall be

measured from 0000 hours on the first

complete (24 hour) day of the available

metering data through 2400 hours on

the last complete day of the available

metering data. Billing demand will be

determined from the period of available

metering data that most closely matches

the official billing period of the

customer.

E. Determination of Measured Energy

1. For points of delivery with fully

operational metering under RMS, energy

shall be measured from 0000 hours on

the first day of the billing period

through 2400 hours on the last day of

the billing period.

2. For points of delivery that do not

have RMS metering, measured energy

shall be the quantity of usage recorded

on the meter between meter readings.

F. Billing Month

Meters normally will be read and bills

computed at intervals of 1 month. A

month is defined as the interval

between scheduled meter-reading dates.

The billing month will not exceed 31

days in any case. While it may be

necessary to read meters on a day other

than the scheduled meter-reading date,

for determination of billing demand, the

billing month will cease at 2400 hours

on the last scheduled meter-reading

date. Schedules will be predetermined.

The customer must give 30 days notice

to request a change to the schedule.

G. Payment of Bills

Bills for power shall be rendered

monthly by BPA. Failure to receive a

bill shall not release the purchaser from

liability for payment. Bills for amounts

due BPA of $50,000 or more must be

paid by direct wire transfer; customers

who expect that their average monthly

bill will not exceed $50,000 and who

expect special difficulties in meeting

this requirement may request, and BPA

may approve, an exemption from this

requirement. Bills for amounts due BPA

under $50,000 may be paid by direct

wire transfer or mailed to the Bonneville

Power Administration, P.O. Box 6040,

Portland, Oregon 97228–6040, or to

another location as directed by BPA.

The procedures to be followed in

making direct wire transfers will be

provided by Financial Services and

updated as necessary.

1. Computation of Bills

Demand and energy billings for power

purchased under each rate schedule

shall be rounded to whole dollar

amounts, by eliminating any amount

which is less than 50 cents and

increasing any amount from 50 cents

through 99 cents to the next higher

dollar.

2. Estimated Bills

At its option, BPA may elect to render

an estimated bill for that month to be

followed at a subsequent billing date by

a final bill. Such estimated bill shall

have the validity of and be subject to the

same payment provisions as a final bill.

3. Due Date

Bills shall be due by close of business

on the 20th day after the date of the bill

(due date). This requirement holds also

for revised bills (see section 6 below).

Should the 20th day be a Saturday,

Sunday, or holiday (as celebrated by the

purchaser), the due date shall be the

next following business day.
21156 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

4. Late Payment

Bills not paid in full on or before

close of business on the due date shall

be subject to a penalty charge of $25. In

addition, an interest charge of onetwentieth percent (0.05 percent) shall be

applied each day to the sum of the

unpaid amount and the penalty charge.

This interest charge shall be assessed on

a daily basis until such time as the

unpaid amount and penalty charge are

paid in full.

Remittances received by mail will be

accepted without assessment of the

charges referred to in the preceding

paragraph provided the postmark

indicates the payment was mailed on or

before the due date. Whenever a power

bill or a portion thereof remains unpaid

subsequent to the due date and after

giving 30 days’ advance notice in

writing, BPA may cancel the contract for

service to the purchaser. However, such

cancellation shall not affect the

purchaser’s liability for any charges

accrued prior thereto under such

contract.

5. Disputed Billings

In the event of a disputed billing, full

payment shall be rendered to BPA and

the disputed amount noted. Disputed

amounts are subject to the late payment

provisions specified above. BPA shall

separately account for the disputed

amount. If it is determined that the

purchaser is entitled to the disputed

amount, BPA shall refund the disputed

amount with interest, as determined by

BPA’s financial services group.

BPA retains the right to verify, in a

manner satisfactory to the

Administrator, all data submitted to

BPA for use in the calculation of BPA’s

rates and corresponding rate

adjustments. BPA also retains the right

to deny eligibility for any BPA rate or

corresponding rate adjustment until all

submitted data have been accepted by

BPA as complete, accurate, and

appropriate for the rate or adjustment

under consideration.

6. Revised Bills

As necessary, BPA may render a

revised bill.

a. If the amount of the revised bill is

less than or equal to the amount of the

original bill, the revised bill shall

replace all previous bills issued by BPA

that pertain to the specified customer

for the specified billing period and the

revised bill shall have the same date as

the replaced bill.

b. If a revision causes an additional

amount to be due BPA or the specified

customer beyond the amount of the

original bill, a revised bill will be issued

for the difference and the date of the

revised bill shall be its date of issue.

Section VII. Variable Industrial Rate

Parameters and Adjustments

A. Monthly Average Aluminum Price

Determination

1. Calculation of the Monthly Billing

Aluminum Price

The monthly billing aluminum price

shall be determined by BPA for each

billing month. For purposes of this rate

schedule, the monthly billing aluminum

price shall be based on the average price

of aluminum in U.S. markets during the

third calendar month prior to the billing

month. The average price of aluminum

in U.S. markets shall be defined as the

average U.S. Transaction Price reported

for the month by ‘‘Metals Week,’’ in

cents per pound, rounded to the nearest

tenth of a cent.

2. Notification of the Monthly Average

Aluminum Price

BPA shall provide, 45 days prior to

the billing month, written notification to

purchasers under this rate schedule of

the monthly billing aluminum price to

be used for billing purposes. Upon

written request supporting

documentation shall be provided.

3. Changes in Aluminum Price

Indicators

In the event that BPA determines that

factors outside its control render the

monthly average U.S. Transaction Price

unusable as an approximation of U.S.

market prices, BPA may develop and

substitute another indicator for prices in

U.S. markets. BPA shall notify

interested parties of its intent to do so

at least 120 days prior to the billing

month in which the change would

become effective. In this notification,

BPA shall explain the reason for the

substitution and specify the

replacement indicator it intends to use.

BPA also shall describe the

methodology to determine the monthly

billing aluminum price to be used for

billing purposes under this rate

schedule and shall provide the

necessary data to be used in the

calculation. Interested persons will have

until close of business 3 weeks from the

date of the notification to provide

comments. Consideration of comments

and more current information may

cause the final methodology and the

substitute aluminum price index to

differ from those proposed. BPA shall

notify all affected parties, and those

parties that submitted comments, of its

final determination 90 days prior to the

billing month the new indicator shall be

effective.

B. Annual Adjustments to the Lower

and Upper Pivot Aluminum Prices

On July 1, 1991, and every July 1,

thereafter, the Lower and Upper Pivot

Aluminum Prices, as stated in section

III.B of the rate schedule, shall be

subject to change for billing purposes as

herein described. The term ‘‘annual

adjustment date’’ shall refer to July 1 of

each year.

1. Implementation Procedures

Beginning in 1991 and every year

thereafter, prior to April 1 of that year,

BPA shall provide the purchasers under

this rate schedule preliminary written

estimates of proposed adjustments to

the Lower and Upper Pivot Aluminum

Prices. By the last working day of the

month of April, BPA shall notify

interested parties in writing of BPA’s

revised determinations concerning

changes to the Lower and Upper Pivot

Aluminum Prices. BPA shall describe

how the adjustments were determined

and provide the data used in the

calculations. In addition to written

notification, BPA may, but is not

obligated to, hold a public comment

forum to clarify its determination and

solicit comments. Interested persons

may submit comments on the

determinations to BPA and other

parties. Comments will be accepted

until close of business on the last

working Friday in May. Consideration

of comments and more current

information may result in the final

adjustment differing from the proposed

adjustment. By June 30 of each year,

BPA shall notify all VI purchasers, those

parties that submitted comments, and

parties that requested notification, of the

final determination.

2. Annual Adjustment Procedures

a. Annual Adjustment of the Lower

Pivot Aluminum Price

Beginning with the July 1, 1991,

annual adjustment date, for each year

that the Variable Industrial rate is in

effect, the Lower Pivot Aluminum Price

as stated in section III.B.1 of the rate

schedule shall be adjusted on the July

1 annual adjustment date. The Lower

Pivot Aluminum Price shall be revised

by multiplying 59 cents per pound by

the Cost Escalation Index described in

section VII.B.3.b of these GRSPs and

rounded to the nearest tenth of a cent.

The revised Lower Pivot Aluminum

Price shall replace the Lower Pivot

Aluminum Price as stated in section

III.B.1 of the rate schedule and shall be

used to determine the energy rate in the

subsequent 12 billing months.

b. Annual Adjustment of the Upper

Pivot Aluminum Price
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21157

For each year that the Variable

Industrial rate is in effect, the Upper

Pivot Aluminum Price as stated in

section III.B.2 of the rate schedule shall

be adjusted on the July 1 annual

adjustment date. The Upper Pivot

Aluminum Price will be adjusted such

that the Average Historical Aluminum

Price described in section VII.B.4 of

these GRSPs is the midpoint between

the adjusted Upper Pivot Aluminum

Price and the Average Historical Lower

Pivot Aluminum Price described in

section VII.B.5 below, except as limited

to the greater of 65 cents per pound or

the adjusted Lower Pivot Point for the

year.

The Upper Pivot Aluminum Price

shall equal the greater of:

(1) (2)*(AAP)–ALP:

where

AAP=the Average Historical Aluminum

Price described in section VII.B.4 of

these GRSPs.

ALP=the Average Historical Lower Pivot

Aluminum Price described in

section VII.B.5 of these GRSPs.

(2) 65.0 cents per pound escalated to

current dollars using the Cost Escalator

for the Upper Pivot Aluminum Price

described in section VII.B.3.c of these

GRSPs.

or

(3) The adjusted Lower Pivot

Aluminum Price for the year.

The revised Upper Pivot Aluminum

Price shall supersede the Upper Pivot

Aluminum Price as stated in section

III.B.2 of the rate schedule and shall be

used to determine the energy rate in the

subsequent 12 months.

3. Cost Escalators

a. The cost indices described below

shall be used in calculating the

appropriate cost escalators. Each index

shall be rounded to the nearest onetenth of a percent, or three significant

places.

(1) Electricity Cost Index

The average VI rate in mills per

kilowatt-hour based on the Plateau

Energy Charge and the Discount for

Quality of First Quartile Service in

effect on the April 1 preceding the

annual adjustment date and a load

factor of 98.5 percent; divided by 22.8

mills per kilowatt-hour (the average VI–

86 rate assuming the plateau energy

charge and the Discount for Quality of

First Quartile Service in 1986).

(2) Labor Cost Index

The annual average hourly earnings

for the U.S. primary aluminum industry

(SIC 3334) over the previous complete

calendar year, from the Employment

and Earnings, published by the U.S.

Department of Labor, Bureau of Labor

Statistics (BLS), divided by $14.20 per

hour (the value of SIC 3334 earnings

reported for 1985).

(3) Alumina Cost Index

The annual average of the monthly

billing aluminum prices described in

section VII.A of the GRSPs for the

previous 1-year period beginning July 1

through June 30 divided by 50.8 cents

per pound (the average U.S. Transaction

price over the period April 1985

through March 1986).

(4) Other Costs Index

The annual average GNP Implicit

Price Deflator for the previous complete

calendar year, as published by the U.S.

Department of Commerce, Bureau of

Economic Analysis, divided by 0.944

(the value of the GNP Implicit Price

Deflator for 1985 with 1987=1.000).

In the event the indices delineated

above are discontinued or revised in a

manner that BPA determines renders

them unusable for calculating a

consistent cost index, BPA will adjust or

substitute another similar price index,

following advance notification and

opportunity for public comment as

described in section VII.B.1 of these

GRSPs.

b. The Cost Escalator for the Lower

Pivot Aluminum Price shall be a

weighted average of the four indices

contained in section VII.B.3.a above.

The following weights shall be assigned

each index:

Electricity Cost Index .30

Labor Cost Index .20

Alumina Cost Index .20

Other Costs Index .30

c. The Cost Escalator for the Upper

Pivot Aluminum Price shall be a

weighted average of the Electricity Cost

and Other Cost Escalators as stated in

sections VII.B.3.a.(1) and VII.B.3.a.(4)

above. The following weights shall be

assigned each index:

Electricity Cost Index .25

Other Costs Index .75

4. Average Historical Aluminum Price

Prior to the July 1, 1991, annual

adjustment date and every annual

adjustment date thereafter, an average

historical aluminum price shall be

calculated for the period the VI rate has

been in effect beginning August 1986.

The average historical aluminum price

shall be determined following the

procedures set forth below:

a. Each monthly billing aluminum

price determined pursuant to section

VII.A of these GRSPs for the period

August 1, 1986, through June 30

immediately preceding the annual

adjustment date, shall be escalated to

the current year dollars using the Price

Deflator procedures described in section

VII.B.6 below.

b. The sum of the escalated monthly

billing aluminum prices shall be

divided by the number of months in the

period and rounded to the nearest tenth

of a cent to obtain the Average

Historical Aluminum Price.

5. Average Historical Lower Pivot

Aluminum Price

Prior to the July 1, 1991, annual

adjustment date and every annual

adjustment date thereafter, the average

of the Lower Pivot Aluminum Prices for

the period the VI rate has been in effect

beginning August 1986, shall be

calculated following the procedures set

forth below:

a. The Lower Pivot Aluminum Price

in each month for the period August 1,

1986, through June 30 of the calendar

year preceding the annual adjustment

date, shall be escalated to the current

year’s dollars using the Price Deflator

procedures described in section VII.B.6

below.

b. The sum of the escalated monthly

Lower Pivot Aluminum Prices shall be

divided by the number of months in the

period, and rounded to the nearest tenth

of a cent to obtain an Average Historical

Lower Pivot Aluminum Price.

6. Price Deflator Procedures

For purposes of converting nominal

dollars to real dollars in the calculation

of the Average Historical Aluminum

Price and the Average Historical Lower

Pivot Aluminum Price, the following

Price Deflator procedures shall be used:

a. Monthly billing aluminum prices

and Lower Pivot Aluminum Prices for

any calendar months July through

December shall be inflated by

multiplying the price by the ratio of the

GNP Implicit Price Deflator for the

calendar year prior to the annual

adjustment date divided by the Implicit

Price Deflator for the calendar year in

which the price occurred.

b. Monthly billing aluminum prices

and Lower Pivot Aluminum Prices for

any calendar months January through

June shall be inflated by multiplying the

price by the ratio of the Implicit Price

Deflator for the calendar year prior to

the annual adjustment date divided by

the Implicit Price Deflator for the

calendar year prior to the year in which

the price occurred. Each price shall be

rounded to the nearest tenth of a cent.
21158 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

V. Transmission Rate Schedules And

General Transmission Rate Schedule

Provisions (GTRSPs)

Table Of Contents

Summary of Rate Schedules

Transmission Rate Schedules

FPT–95.1 Formula Power Transmission

FPT–95.3 Formula Power Transmission

IR–95 Integration of Resources

IS–95 Southern Intertie Transmission

IN–95 Northern Intertie Transmission

IE–95 Eastern Intertie Transmission

ET–95 Energy Transmission

MT–95 Market Transmission

UFT–95 Use-of-Facilities Transmission

TGT–95 Townsend-Garrison Transmission

AC–95 Southern Intertie Annual Costs Rate

and Billing Provisions

General Transmission Rate Schedule

Provisions

Section I Adoption of Revised Transmission

Rate Schedules and General

Transmission Rate Schedule Provisions

Section II Billing Factor Definitions and

Billing Adjustments

Section III Other Definitions

Section IV Billing Information

A. Summary of Rate Schedules

BPA is proposing to surcharge by 4

percent the following transmission rate

schedules: Formula Power

Transmission; Integration of Resources;

Southern Intertie Transmission;

Northern Intertie Transmission; Eastern

Intertie Transmission; and Energy

Transmission. Pursuant to the

Settlement Agreement, BPA proposes to

increase the components of the FPT 95.3

rate by 4 percent for the October 1,

1995–September 30, 1996 period. The

increase to this rate for the 1-year

period, however, does not preclude BPA

from increasing the 3-year FPT rate, as

necessary, in its 1996 rate case. BPA

also is proposing extension of the

Market Transmission (MT) rate, Use of

Facilities (UFT) rate, and TownsendGarrison Transmission (TGT) rate with

no changes. The MT rate was developed

for use among Western Systems Power

Pool (WSPP) participants to allow for

flexible hourly, daily, weekly, and

monthly charges. The UFT and TGT rate

schedules are formula rates. The UFT

rate recovers the annual cost of

identified facilities over which specific

wheeling transactions occur. The TGT

rate is a contract rate that recovers the

cost of the Montana (Eastern) Intertie.

In addition, BPA is proposing the

Southern Intertie Annual Costs (AC–95)

rate to be applied to owners of Pacific

Northwest (PNW) Alternating Current

(AC) Intertie capacity. This rate recovers

the capacity owner’s pro-rata share of

actual PNW AC Intertie costs:

operations, maintenance, general plant,

and other identified expenses, as well as

capital costs of replacements and

reinforcements. The proposed AC–95

rate takes the place of the AC–93 rate,

which was a ‘‘bridge’’ rate until

Capacity Ownership contracts were

complete. Copies of the Ownership

Agreement are available for examination

at BPA’s Public Information Center at

the address listed at the beginning of

this notice.

B. Transmission Rate Schedules

Schedule FPT–95.1

Formula Power Transmission

Section I. Availability

This schedule supersedes schedule

FPT–93.1 for all firm transmission

agreements which provide that rates

may be adjusted not more frequently

than once a year. It is available for firm

transmission of electric power and

energy using the Main Grid and/or

Secondary System of the Federal

Columbia River Transmission System

(FCRTS). This schedule is for full-year

and partial-year service and for either

continuous or intermittent service when

firm availability of service is required.

For facilities at voltages lower than the

Secondary System, a different rate

schedule may be specified. Service

under this schedule is subject to BPA’s

General Transmission Rate Schedule

Provisions (GTRSPs).

Section II. Rate

A. Full-Year Service

The monthly charge per kilowatt of

billing demand shall be one-twelfth of

the sum of the Main Grid Charge and

the Secondary System Charge, as

applicable and as specified in the

Agreement.

1. Main Grid Charge

The Main Grid Charge per kilowatt of

billing demand shall be the sum of one

or more of the following component

factors as specified in the Agreement:

a. Main Grid Distance Factor: The

amount computed by multiplying the

Main Grid Distance by $0.0386 per mile

b. Main Grid Interconnection

Terminal Factor: $0.28

c. Main Grid Terminal Factor: $0.46

d. Main Grid Miscellaneous Facilities

Factor: $1.96

2. Secondary System Charge

The Secondary System Charge per

kilowatt of billing demand shall be the

sum of one or more of the following

component factors as specified in the

Agreement:

a. Secondary System Distance Factor:

The amount determined by multiplying

the Secondary System Distance by

$0.2895 per mile

b. Secondary System Transformation

Factor: $4.26

c. Secondary System Intermediate

Terminal Factor: $1.34

d. Secondary System Interconnection

Terminal Factor: $0.71

B. Partial-Year Service

The monthly charge per kilowatt of

billing demand shall be as specified in

Section II.A. for all months of the year

except for agreements with terms 5

years or less and which specify service

for fewer than 12 months per year. The

monthly charge shall be:

1. During months for which service is

specified, the monthly charge defined in

Section II.A., and

2. During other months, the monthly

charge defined in Section II.A.

multiplied by 0.2.

Section III. Billing Factors

Unless otherwise stated in the

Agreement, the billing demand shall be

the largest of:

A. The Transmission Demand;

B. The highest hourly Scheduled

Demand for the month; or

C. The Ratchet Demand.

Schedule FPT–95.3

Formula Power Transmission

Section I. Availability

This schedule supersedes schedule

FPT–91.3 for all firm transmission

agreements which provide that rates

may be adjusted not more frequently

than once every 3 years. It is available

for firm transmission of electric power

and energy using the Main Grid and/or

Secondary System of the Federal

Columbia River Transmission System.

This schedule is for full-year and

partial-year service and for either

continuous or intermittent service when

firm availability of service is required.

For facilities at voltages lower than the

Secondary System, a different rate

schedule may be specified. Service

under this schedule is subject to BPA’s

General Transmission Rate Schedule

Provisions.

Section II. Rate

A. Full-Year Service

The monthly charge per kilowatt of

billing demand shall be one-twelfth of

the sum of the Main Grid Charge and

the Secondary System Charge, as

applicable and as specified in the

Agreement.

1. Main Grid Charge

The Main Grid Charge per kilowatt of

billing demand shall be the sum of one

or more of the following component

factors as specified in the Agreement:
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21159

a. Main Grid Distance Factor: The

amount computed by multiplying the

Main Grid Distance by $0.0292 per mile

b. Main Grid Interconnection

Terminal Factor: $0.28

c. Main Grid Terminal Factor: $0.31

d. Main Grid Miscellaneous Facilities

Factor: $1.36

2. Secondary System Charge

The Secondary System Charge per

kilowatt of billing demand shall be the

sum of one or more of the following

component factors as specified in the

Agreement:

a. Secondary System Distance Factor:

The amount determined by multiplying

the Secondary System Distance by

$0.2039 per mile

b. Secondary System Transformation

Factor: $2.63

c. Secondary System Intermediate

Terminal Factor: $0.87

d. Secondary System Interconnection

Terminal Factor: $0.46

B. Partial-Year Service

The monthly charge per kilowatt of

billing demand shall be as specified in

Section II.A. for all months of the year

except for agreements with terms 5

years or less and which specify service

for fewer than 12 months per year. The

charge shall be:

1. During months for which service is

specified, the monthly charge defined in

Section II.A., and

2. During other months, the monthly

charge defined in Section II.A.

multiplied by 0.2.

Section III. Billing Factors

Unless otherwise stated in the

Agreement, the billing demand shall be

the largest of:

A. The Transmission Demand;

B. The highest hourly Scheduled

Demand for the month; or

C. The Ratchet Demand.

Schedule IR–95

Integration of Resources

Section I. Availability

This schedule supersedes IR–93 and

is available for firm transmission service

for electric power and energy using the

Main Grid and/or Secondary System of

the Federal Columbia River

Transmission System. The definitions of

Main Grid and Secondary Systems are

the same as for the FPT–95.1 and FPT–

95.3 rate schedules and are contained in

the General Transmission Rate Schedule

Provisions (GTRSPs). For facilities at

voltages lower than the Secondary

System, a different rate schedule may be

specified. Service under this schedule is

subject to BPA’s GTRSPs.

Section II. Rate

The monthly charge shall be the sum

of A and B where:

A. Demand Charge

1. $0.441 per kilowatt of billing

demand; or

2. For Points of Integration (POI)

specified in the Agreement as being

short distance POIs, for which Main

Grid and Secondary System facilities are

used for a distance of less than 75

circuit miles, the following formula

applies: [0.2 + (0.8 * transmission

distance/75)] * ($0.441 per kilowatt of

billing demand)

Where:

the billing demand for a short

distance POI is the demand level

specified in the Agreement for such POI,

and the transmission distance is the

circuit miles between the POI for a

generating resource of the customer and

a designated Point of Delivery serving

load of the customer. Short distance

POIs are determined by BPA after

considering factors in addition to

transmission distance.

B. Energy Charge

1.10 mills per kilowatthour of billing

energy.

Section III. Billing Factors

To the extent that the Agreement

provides for the customer to be billed

for transmission in excess of the

Transmission Demand or Total

Transmission Demand, as defined in the

Agreement, at the nonfirm transmission

rate (currently ET–95), such

transmission service shall not contribute

to either the Billing Demand or the

Billing Energy for the IR rate provided

that the customer requests such

treatment and BPA approves in

accordance with the prescribed

provisions in the Agreement.

A. Billing Demand

The billing demand shall be the

largest of:

1. The Transmission Demand, except

under General Transmission

Agreements where a Total Transmission

Demand is defined;

2. The highest hourly Scheduled

Demand for the month; or

3. The Ratchet Demand.

B. Billing Energy

The billing energy shall be the

monthly sum of scheduled

kilowatthours.

Schedule IS–95

Southern Intertie Transmission

Section I. Availability

This schedule supersedes IS–93 and

is available for all transmission on the

Southern Intertie. Service under this

schedule is subject to BPA’s General

Transmission Rate Schedule Provisions.

Section II. Rate

A. Nonfirm Transmission Rate

The charge for nonfirm transmission

of non-BPA power shall be 3.23 mills

per kilowatthour of billing energy. This

charge applies for both north-to-south

and south-to-north transactions.

B. Firm Transmission Rate

The charge for firm transmission

service shall be $0.734 per kilowatt per

month of billing demand and 1.76 mills

per kilowatthour of billing energy. Firm

transmission will only be made

available to customers under this rate

schedule who have executed a contract

with BPA specifying use of the Firm

Transmission rate for either north-tosouth or south-to-north transactions.

Section III. Billing Factors

A. For services under Section II.A, the

billing energy shall be the monthly sum

of the scheduled kilowatthours, plus the

monthly sum of kilowatthours allocated

but not scheduled. The amount of

allocated but not scheduled energy that

is subject to billing may be reduced pro

rata by BPA due to forced Intertie

outages and other uncontrollable forces

that may reduce Intertie capacity.

The amount of allocated but not

scheduled energy that is subject to

billing also may be reduced upon

mutual agreement between BPA and the

customer.

B. For services under Section II.B, the

billing demand shall be the

Transmission Demand as defined in the

Agreement. The billing energy shall be

the monthly sum of scheduled

kilowatthours, unless otherwise

specified in the Agreement.

Schedule IN–95

Northern Intertie Transmission

Section I. Availability

This schedule supersedes IN–93 and

is available for all transmission on the

Northern Intertie pursuant to an

Agreement. Service under this schedule

is subject to BPA’s General

Transmission Rate Schedule Provisions.

Section II. Rate

The charge for transmission of nonBPA power on the Northern Intertie

shall be 0.89 mills per kilowatthour.
21160 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

Section III. Billing Factors

Billing Energy

The billing energy shall be the

monthly sum of the scheduled

kilowatthours.

Schedule IE–95

Eastern Intertie Transmission

Section I. Availability

This schedule supersedes IE–93 and

is available for all nonfirm transmission

on the Eastern Intertie. Service under

this schedule is subject to BPA’s

General Transmission Rate Schedule

Provisions.

Section II. Rate

The charge for nonfirm transmission

on the Eastern Intertie shall be 2.12

mills per kilowatthour.

Section III. Billing Factors

Billing Energy

The billing energy shall be the

monthly sum of the scheduled

kilowatthours.

Schedule ET–95

Energy Transmission

Section I. Availability

This schedule supersedes ET–93,

unless otherwise specified in the

Agreement, with respect to delivery

using Federal Columbia River

Transmission System facilities other

than the Southern Intertie, Eastern

Intertie, or the Northern Intertie, and is

available for firm (of not more than 1

year duration) or nonfirm transmission

between points within the Pacific

Northwest. BPA may interrupt nonfirm

service which is provided under this

rate schedule. Service under this

schedule is subject to BPA’s General

Transmission Rate Schedule Provisions.

Section II. Rate

The charge for transmission of nonBPA power shall be 2.10 mills per

kilowatthour.

Section III. Billing Factors

Billing Energy

The billing energy shall be the

monthly sum of scheduled

kilowatthours.

Schedule MT–95

Market Transmission

Section I. Availability

This schedule supersedes MT–91 and

is available for Transmission Service for

transactions using Federal Columbia

River Transmission System facilities

pursuant to the Western Systems Power

Pool (WSPP) Agreement. General

Transmission Rate Schedule Provisions.

Section II. Rate

The charge shall be determined in

advance by BPA. The charge shall be

based on the duration of the proposed

transaction and shall not exceed the

following rates.

A. Hourly Rate

The maximum charge shall be 6.5

mills per kilowatthour where the total

hourly revenues from a given

transaction during a calendar day shall

not exceed the product of the Daily rate

and the maximum demand scheduled

during such day.

B. Daily Rate

The maximum charge shall be $.105

per kilowattday where the total demand

charge revenues in any consecutive 7-

day period shall not exceed the product

of the Weekly rate and the highest

demand experienced on any day in the

7-day period.

C. Weekly Rate

The maximum charge shall be $.52

per kilowattweek.

D. Monthly Rate

The maximum charge shall be $2.27

per kilowattmonth.

Section III. Billing Factors

The billing factors shall be specified

in advance by BPA, as to representing

the Transmission Service use or

reservation.

Schedule UFT–95

Use-of-Facilities Transmission

Section I. Availability

This schedule supersedes UFT–83

unless otherwise provided in the

Agreement, and is available for firm

transmission over specified Federal

Columbia River Transmission System

facilities. Service under this schedule is

subject to BPA’s General Transmission

Rate Schedule Provisions.

Section II. Rate

The monthly charge per kilowatt of

Transmission Demand specified in the

Agreement shall be one-twelfth of the

annual cost of capacity of the specified

facilities divided by the sum of

Transmission Demands (in kilowatts)

using such facilities. Such annual cost

shall be determined in accordance with

Section III.

Section III. Determination of

Transmission Rate

A. From time to time, but not more

often than once in each Contract Year,

BPA shall determine the following data

for the facilities which have been

constructed or otherwise acquired by

BPA and which are used to transmit

electric power:

1. The annual cost of the specified

FCRTS facilities, as determined from the

capital cost of such facilities and annual

cost ratios developed from the Federal

Columbia River Power System financial

statement, including interest and

amortization, operation and

maintenance, administrative and

general, and general plant costs.

2. The yearly noncoincident peak

demands of all users of such facilities or

other reasonable measurement of the

facilities’ peak use.

B. The monthly charge per kilowatt of

billing demand shall be one-twelfth of

the sum of the annual cost of the FCRTS

facilities used divided by the sum of

Transmission Demands. The annual cost

per kilowatt of Transmission Demand

for a facility constructed or otherwise

acquired by BPA shall be determined in

accordance with the following formula:

A

D

Where:

A = The annual cost of such facility as

determined in accordance with A.1.

above.

D = The sum of the yearly

noncoincident demands on the

facility as determined in accordance

with A.2. above.

The annual cost per kilowatt of

facilities listed in the Agreement which

are owned by another entity, and used

by BPA for making deliveries to the

transferee, shall be determined from the

costs specified in the Agreement

between BPA and such other entity.

Section IV. Determination of Billing

Demand

Unless otherwise stated in the

Agreement, the factor to be used in

determining the kilowatts of billing

demand shall be the largest of:

A. The Transmission Demand in

kilowatts specified in the Agreement;

B. The highest hourly Measured or

Scheduled Demand for the month, the

Measured Demand being adjusted for

power factor; or

C. The Ratchet Demand.

Schedule TGT–95

Townsend-Garrison Transmission

Section I. Availability

This schedule supersedes TGT–1 and

shall apply to all agreements which

provide for the firm transmission of

electric power and energy over

transmission facilities of BPA’s section
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21161

of the Montana [Eastern] Intertie.

Service under this schedule is subject to

BPA’s General Transmission Rate

Schedule Provisions.

Section II. Rate

The monthly charge shall be onetwelfth of the sum of the annual charges

listed below, as applicable and as

specified in the agreements for firm

transmission. The Townsend-Garrison

500-kV lines and associated terminal,

line compensation, and communication

facilities are a separately identified

portion of the Federal Transmission

System. Annual revenues plus credits

for government use should equal annual

costs of the facilities, but in any given

year there may be either a surplus or a

deficit. Such surpluses or deficits for

any year shall be accounted for in the

computation of annual costs for

succeeding years. Revenue requirements

for firm transmission use will be

decreased by any revenues received

from nonfirm use and credits for all

government use. The general

methodology for determining the firm

rate is to divide the revenue

requirement by the total firm capacity

requirements. Therefore, the higher the

total capacity requirements, the lower

will be the unit rate.

If the government provides firm

transmission service in its section of the

Montana (Eastern) Intertie in exchange

for firm transmission service in a

customer’s section of the Montana

Intertie, the payment by the government

for such transmission services provided

by such customer will be made in the

form of a credit in the calculation of the

Intertie Charge for such customer.

During an estimated 1- to 3-year period

following the commercial operation of

the third generating unit at the Colstrip

Thermal Generating Plant at Colstrip,

Montana, the capability of the Federal

Transmission System west of Garrison

Substation may be different from the

long-term situation. It may not be

possible to complete the extension of

the 500-kV portion of the Federal

Transmission System to Garrison by

such commercial operation date. In such

event, the 500/230 kV transformer will

be an essential extension of the

Townsend-Garrison Intertie facilities,

and the annual costs of such transformer

will be included in the calculation of

the Intertie Charge.

However, starting 1 month after

extension to Garrison of the 500-kV

portion of the Federal Transmission

System, the annual costs of such

transformer will no longer be included

in the calculation of the Intertie Charge.

A. Nonfirm Transmission Charge:

This charge will be filed as a separate

rate schedule and revenues received

thereunder will reduce the amount of

revenue to be collected under the

Intertie Charge below.

B. Intertie Charge for Firm

Transmission Service:

Intertie Charge [((TAC / 12) NFR) (CR EC)

TCR

= − × − ]

Section III. Definitions

A. TAC = Total Annual Costs of

facilities associated with the

Townsend-Garrison 500-kV

Transmission line including

terminals, and prior to extension of the

500-kV portion of the Federal

Transmission System to Garrison, the

500/230 kV transformer at Garrison.

Such annual costs are the total of: (1)

Interest and amortization of associated

Federal investment and the appropriate

allocation of general plant costs; (2)

operation and maintenance costs; (3)

allowance for BPA’s general

administrative costs which are

appropriately allocable to such

facilities, and (4) payments made

pursuant to section 7(m) of Pub. L. 96–

501 with respect to these facilities. Total

Annual Costs shall be adjusted to reflect

reductions to unpaid total costs as a

result of any amounts received, under

agreements for firm transmission service

over the Montana Intertie, by the

government on account of any reduction

in Transmission Demand, termination

or partial termination of any such

agreement or otherwise to compensate

BPA for the unamortized investment,

annual cost, removal, salvage, or other

cost related to such facilities.

B. NFR = Nonfirm Revenues, which

are equal to: (1) The product of the

Nonfirm Transmission Charge described

in II(A) above, and the total nonfirm

energy transmitted over the TownsendGarrison line segment under such

charge for such month; plus (2) the

product of the Nonfirm Transmission

Charge and the total nonfirm energy

transmitted in either direction by the

Government over the TownsendGarrison line segment for such month.

C. CR = Capacity Requirement of a

customer on the Townsend-Garrison

500-kV transmission facilities as

specified in its firm transmission

agreement.

D. TCR = Total Capacity Requirement

on the Townsend-Garrison 500-kV

transmission facilities as calculated by

adding (1) the sum of all Capacity

Requirements (CR) specified in

transmission agreements described in

section I; and (2) the Government’s firm

capacity requirement. The

Government’s firm capacity requirement

shall be no less than the total of the

amounts, if any, specified in firm

transmission agreements for use of the

Montana Intertie.

E. EC = Exchange Credit for each

customer which is the product of: (1)

The ratio of investment in the

Townsend-Broadview 500-kV

transmission line to the investment in

the Townsend-Garrison 500-kV

transmission line; and (2) the capacity

which the Government obtains in the

Townsend-Broadview 500-kV

transmission line through exchange

with such customer. If no exchange is in

effect with a customer, the value of EC

for such customer shall be zero.

Schedule AC–95

Southern Intertie Annual Costs Rate

and Billing Provisions

Section I. Availability

This schedule is applicable to each

party (Capacity Owner) that executes a

PNW AC Intertie Capacity Ownership

Agreement (Agreement). Billings

pursuant to this schedule are subject to

the Billing Provisions in Exhibit B of the

Agreement. This rate schedule shall be

effective on the first day of the fiscal

year following the earlier of interim or

final FERC approval of this rate

schedule. Unless otherwise defined in

this rate schedule, capitalized terms

used in this rate schedule shall have the

respective definitions set forth in

section 1 of this Agreement.

Section II. Rate

A. Operations

The monthly charge equals:
21162 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

Operations Cost * Capacity Ownership Percentage

Months

Where

‘‘Months’’ is equal to 12, or, if the

Operating Plan has, during the fiscal

year to which such Operating Plan

pertains, been amended with respect to

Operations Cost, the number of full

months remaining in the fiscal year after

such amended Operating Plan becomes

effective for which Capacity Owners

have not been billed.

‘‘Operations Cost’’ means, upon and

after the effective date of Exhibit B

pursuant to this Agreement, for any

fiscal year any Allocated Direct Costs for

Bonneville’s PNW AC Intertie,

operations Indirect Costs for

Bonneville’s PNW AC Intertie, and

operations Overhead Costs for

Bonneville’s PNW AC Intertie for such

fiscal year, each being determined in

accordance with section I of Exhibit I.

‘‘Capacity Ownership Percentage’’ is

as defined in subsection 1(k) of each

Capacity Owner’s Agreement.

The monthly charge for the

Operations rate shall be calculated using

the forecast Operations Cost in the

Operating Plan in effect during the

month for which the monthly charge is

calculated; provided, however, if the

Operating Plan is amended during the

fiscal year to which such Operating Plan

pertains, the monthly charge for

Operations Cost shall be calculated

using the forecast Operations Cost less

the Operations Cost already billed for

such fiscal year for the remaining

months of the fiscal year following such

amendment.

B. Maintenance

The monthly charge equals:

Maintenance Cost * Capacity Ownership Percentage

Months

Where

‘‘Months’’ is equal to 12, or, if the

Operating Plan has, during the fiscal

year to which such Operating Plan

pertains, been amended with respect to

Maintenance Cost, the number of full

months remaining in the fiscal year after

such amended Operating Plan becomes

effective for which Capacity Owners

have not been billed.

‘‘Maintenance Cost’’ means, upon and

after the effective date of Exhibit B

pursuant to this Agreement, for any

fiscal year any maintenance Direct Costs

for Bonneville’s PNW AC Intertie,

maintenance Indirect Costs for

Bonneville’s PNW AC Intertie, and

maintenance Overhead Costs for

Bonneville’s PNW AC Intertie for such

fiscal year, each being determined in

accordance with section II of Exhibit I.

‘‘Capacity Ownership Percentage’’ is

as defined in subsection 1(k) of each

Capacity Owner’s Agreement.

The monthly charge for the

Maintenance rate shall be calculated

using the forecast Maintenance Cost in

the Operating Plan in effect during the

month for which the monthly charge is

calculated; provided, however, if the

Operating Plan is amended during the

fiscal year to which such Operating Plan

pertains, the monthly charge for

Maintenance Cost shall be calculated

using the forecast Maintenance Cost less

the Maintenance Cost already billed for

such fiscal year for the remaining

months of the fiscal year following such

amendment.

C. General Plant

The monthly charge equals:

MOP =

AOP * HOP

10

Where

‘‘Months’’ is equal to 12, or, if the

Operating Plan has, during the fiscal

year to which such Operating Plan

pertains, been amended with respect to

General Plant Cost, the number of full

months remaining in the fiscal year after

such amended Operating Plan becomes

effective for which Capacity Owners

have not been billed.

‘‘General Plant Cost’’ means, upon

and after the effective date of Exhibit B

pursuant to this Agreement, for any

fiscal year any costs (including direct

costs, indirect costs, overhead costs, and

AFUDC) for Bonneville’s general plant

investment for such fiscal year. The

method for determining General Plant

Cost is set forth in section IV of Exhibit

I.

‘‘Capacity Ownership Percentage’’ is

as defined in subsection 1(k) of each

Capacity Owner’s Agreement.

The monthly charge for the General

Plant rate shall be calculated using the

General Plant Cost in the Operating Plan

in effect during the month for which the

monthly charge is calculated; provided,

however, if the Operating Plan is

amended during the fiscal year to which

such Operating Plan pertains, the

monthly charge for General Plant Cost

shall be calculated using the General

Plant Cost less the General Plant Cost

already billed for such fiscal year for the

remaining months of the fiscal year

following such amendment.

D. Other Costs

The monthly charge equals:

Other Costs * Capacity Ownership Percentage

Months

Where ‘‘Months’’ is equal to 12, or, if the

Operating Plan has, during the fiscal

year to which such Operating Plan

pertains, been amended with respect to

Other Cost, the number of full months

remaining in the fiscal year after such
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21163

amended Operating Plan becomes

effective for which Capacity Owners

have not been billed.

‘‘Other Costs’’ means, upon and after

the effective date of Exhibit B pursuant

to this Agreement, Bonneville’s other

costs for Bonneville’s PNW AC Intertie

described in and determined pursuant

to section V of Exhibit I.

‘‘Capacity Ownership Percentage’’ is

as defined in subsection 1(k) of each

Capacity Owner’s Agreement.

The monthly charge for the Other

Costs rate shall be calculated using the

forecast Other Costs in the Operating

Plan in effect during the month for

which the monthly charge is calculated;

provided, however, if the Operating

Plan is amended during the fiscal year

to which such Operating Plan pertains,

the monthly charge for Other Costs shall

be calculated using the forecast Other

Costs less the Other Costs already billed

for such fiscal year for the remaining

months of the fiscal year following such

amendment.

E. Contracts and Rates

The monthly charge equals:

Contracts and Rates Costs * Capacity Ownership Percentage

Months

Where

‘‘Months’’ is equal to 12, or, if the

Operating Plan has, during the fiscal

year to which such Operating Plan

pertains, been amended with respect to

Contracts and Rates Cost, the number of

full months remaining in the fiscal year

after such amended Operating Plan

becomes effective for which Capacity

Owners have not been billed.

‘‘Contracts and Rates Costs’’ means,

upon and after the effective date of

Exhibit B pursuant to this Agreement,

for any fiscal year Bonneville’s total

contracts and rates costs (as described in

section VI of Exhibit I) for such fiscal

year as functionalized and allocated in

accordance with section VI of Exhibit I

to determine Contracts and Rates Costs

for Bonneville’s PNW AC Intertie.

‘‘Capacity Ownership Percentage’’ is

as defined in subsection 1(k) of each

Capacity Owner’s Agreement.

Contracts and Rates Cost is

determined in accordance with section

VI of Exhibit I as of the Effective Date.

If Exhibit I is amended pursuant to

subsection 19(k) of the Agreement to

provide that the Contracts and Rates

Cost determined in accordance with

section VI of Exhibit I (and reflected in

the Operating Plan for the fiscal year to

which such Operating Plan pertains) is

directly assigned to the Capacity

Owners pursuant to such amended

Exhibit I (and reflected in the Operating

Plan for the fiscal year to which such

Operating Plan pertains), the Capacity

Ownership Percentage in the monthly

charge calculation for such fiscal year

shall be replaced by the ratio of (a) each

Capacity Ownership Share to (b) the

sum of all Capacity Ownership Shares.

The monthly charge for the Contracts

and Rates rate shall be calculated using

the forecast Contracts and Rates Costs in

the Operating Plan in effect during the

month for which the monthly charge is

calculated; provided, however, if the

Operating Plan is amended during the

fiscal year to which such Operating Plan

pertains, the monthly charge for

Contracts and Rates Cost shall be

calculated using the forecast Contracts

and Rates Cost less the Contracts and

Rates Cost already billed for such fiscal

year for the remaining months of the

fiscal year following such amendment.

F. Power Scheduling

The monthly charge equals:

Power Scheduling Costs * Capacity Ownership Percentage

Months

Where

‘‘Months’’ is equal to 12, or, if the

Operating Plan has, during the fiscal

year to which such Operating Plan

pertains, been amended with respect to

Power Scheduling Cost, the number of

full months remaining in the fiscal year

after such amended Operating Plan

becomes effective for which Capacity

Owners have not been billed.

‘‘Power Scheduling Costs’’ means,

upon and after the effective date of

Exhibit B pursuant to this Agreement,

Bonneville’s total power scheduling

costs (as described in section VII of

Exhibit I) as functionalized and

allocated in accordance with section VII

of Exhibit I to determine Power

Scheduling Costs for Bonneville’s PNW

AC Intertie.

‘‘Capacity Ownership Percentage’’ is

as defined in subsection 1(k) of each

Capacity Owner’s Agreement.

Power Scheduling Cost is determined

in accordance with section VII of

Exhibit I as of the Effective Date. If

Exhibit I is amended pursuant to

subsection 19(k) of the Agreement to

provide that the Power Scheduling Cost

determined in accordance with section

VII of Exhibit I (and reflected in the

Operating Plan for the fiscal year to

which such Operating Plan pertains) is

directly assigned to the Capacity

Owners pursuant to such amended

Exhibit I (and reflected in the Operating

Plan for the fiscal year to which such

Operating Plan pertains), the Capacity

Ownership Percentage in the monthly

charge calculation for such fiscal year

shall be replaced by the ratio of (a) each

Capacity Ownership Share to (b) the

sum of all Capacity Ownership Shares.

The monthly charge for the Power

Scheduling rate shall be calculated

using the forecast Power Scheduling

Costs in the Operating Plan in effect

during the month for which the monthly

charge is calculated; provided, however,

if the Operating Plan is amended during

the fiscal year to which such Operating

Plan pertains, the monthly charge for

Power Scheduling Cost shall be

calculated using the forecast Power

Scheduling Cost less the Power

Scheduling Cost already billed for such

fiscal year for the remaining months of

the fiscal year following such

amendment.

G. End of Term

The monthly charge equals:
21164 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

End of Term Costs * Capacity Ownership Percentage

Months

Where

‘‘Months’’ is equal to 12, or, if the

Operating Plan has, during the fiscal

year to which such Operating Plan

pertains, been amended with respect to

End of Term Costs, the number of full

months remaining in the fiscal year after

such amended Operating Plan becomes

effective for which Capacity Owners

have not been billed.

‘‘End of Term Costs’’ means, upon

and after the effective date of Exhibit B

pursuant to this Agreement,

Bonneville’s costs associated with

decommissioning the PNW AC Intertie

determined in accordance with section

VIII of Exhibit I.

‘‘Capacity Ownership Percentage’’ is

as defined in subsection 1(k) of each

Capacity Owner’s Agreement.

The monthly charge for the End of

Term rate shall be calculated using the

forecast End of Term Costs in the

Operating Plan in effect during the

month for which the monthly charge is

calculated; provided, however, if the

Operating Plan is amended during the

fiscal year to which such Operating Plan

pertains, the monthly charge for End of

Term Costs shall be calculated using the

forecast End of Term Costs less the End

of Term Cost already billed for such

fiscal year for the remaining months of

the fiscal year following such

amendment.

H. Replacements and Reinforcements

1. For each Replacement, the charge

equals: Replacement Cost * Capacity

Ownership Percentage.

2. For each Reinforcement, the charge

equals: Reinforcement Cost * Capacity

Ownership Percentage.

Where

‘‘Replacement Cost’’ means, upon and

after the effective date of Exhibit B

pursuant to this Agreement, for any

Replacement, the Direct Costs, Indirect

Costs, Overhead Costs, and AFUDC for

such Replacement, all capitalized to

plant-in-service together with (1) simple

interest on the foregoing costs accrued

from the date on which Bonneville stops

accruing AFUDC on the foregoing costs

until the due date of the bill to Capacity

Owner for the foregoing costs pursuant

to subparagraph 9(b)(2)(B) and (2) the

costs of removal and any salvage credit

associated with removal or replacement

of existing facilities. Replacement Cost

does not include capitalized general

plant cost. The method for determining

Replacement Costs for Bonneville’s

PNW AC Intertie is set forth in section

III of Exhibit I.

‘‘Reinforcement Cost’’ means, upon

and after the effective date of Exhibit B

pursuant to this Agreement, for any

Reinforcement, the Direct Costs, Indirect

Costs, Overhead Costs, and AFUDC for

such Reinforcement, all capitalized to

plant-in-service together with (1) simple

interest on the foregoing costs accrued

from the date on which Bonneville stops

accruing AFUDC on the foregoing costs

until the due date of the bill to Capacity

Owner for the foregoing costs pursuant

to subparagraph 9(b)(2)(B) and (2) the

costs of removal and any salvage credit

associated with removal or replacement

of existing facilities. Reinforcement Cost

does not include capitalized general

plant cost. The method for determining

Reinforcement Costs for Bonneville’s

PNW AC Intertie is set forth in section

III of Exhibit I.

‘‘Capacity Ownership Percentage’’ is

as defined in subsection 1(k) of each

Capacity Owner’s Agreement.

The charge for the Replacements and

Reinforcements rate shall use the actual

Replacement Cost and Reinforcement

Cost in the Operating Plan.

Section III. Adjustments

If an amendment to the Operating

Plan results in a net amount that

Bonneville owes the Capacity Owners

pursuant to sections II.A–G or pursuant

to section II.H, Bonneville shall refund

such net amount pursuant to paragraph

9(f)(4) of the Agreement.

The monthly charges assessed

Capacity Owners under sections II.A–G

shall be adjusted, and payment or

refund made with interest, pursuant to

paragraph 9(b)(2) or 9(f)(4) of the

Agreement, to reflect amendments to the

Operating Plan that occur after the year

to which such Operating Plan pertains.

A Capacity Owner’s share of the

adjustment shall be determined using

the same Capacity Ownership

Percentage used in the billings under

sections II.A–G during the fiscal year

that such Operating Plan is effective.

Annual Costs Rate

Billing Provisions

I. General Provisions

A. Approval of Rates

The annual costs rate shall become

effective upon interim approval or upon

final confirmation and approval by

FERC. Bonneville will request FERC

approval of such rate schedule effective

on the first day of a Bonneville fiscal

year.

B. Application of Billing Provisions

These Billing Provisions shall apply

to bills rendered by Bonneville pursuant

to the annual costs rate.

C. Definition of Terms

The meaning of terms used in the

annual costs rate shall be as defined in

the Agreement or, if no definition is

provided by the Agreement, such terms

shall be defined according to applicable

Federal law.

II. Billing Information

Payment of Bills

Charges pursuant to the annual costs

rate shall be included in Bonneville’s

monthly power bill to Capacity Owner.

Failure to receive a power bill shall not

release Capacity Owner from liability

for payment. Power bills for amounts

due of $50,000 or more must be paid by

direct wire transfer. If Capacity Owner

anticipates special difficulties in

meeting this requirement, Capacity

Owner may request and Bonneville may

approve an exemption from this

requirement. Power bills for amounts

due Bonneville under $50,000 may be

paid by direct wire transfer or mailed to

the Bonneville Power Administration,

P.O. Box 6040, Portland, Oregon 97228–

6040, or to another location as directed

by Bonneville. The procedures to be

followed in making direct wire transfers

will be provided by Bonneville’s

Financial Services Group and updated

as necessary.

A. Computation of Bills

1. Bonneville shall bill Capacity

Owner in accordance with the annual

costs rate.

2. Capacity Owner shall provide

necessary information to Bonneville for

any computation required to determine

proper charges pursuant to the

Agreement and shall cooperate with

Bonneville in the exchange of additional

information which may be reasonably

useful for respective operations.

3. Bills rendered pursuant to this

Agreement shall be rounded to whole

dollar amounts, by eliminating any

amount which is less than 50 cents and

increasing any amounts from 50 cents to

99 cents to the next higher whole dollar.

B. Billing Month

For charges pursuant to the annual

costs rate the billing month shall be the
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21165

same as for the power bill rendered by

Bonneville to Capacity Owner.

C. Due Date

Charges pursuant to the annual costs

rate shall be included in the power bill

rendered by Bonneville to Capacity

Owner and shall be due as part of the

power bill when such power bill is due.

D. Late Payment

The penalties for failure to pay a bill

in full on or before close of business on

the due date shall be the same as those

contained in the late payment

provisions in Bonneville’s General Rate

Schedule Provisions in effect on the

date of the bill; provided, however, that

no other provision of any such General

Rate Schedule Provisions, including,

but not limited to, provisions regarding

cancellation, termination, or suspension

of service, shall have application with

respect to the payment of any rate or

charge pursuant to the annual costs rate

set forth in Exhibit B. Bonneville’s right

to suspend service for late payment

under the Agreement shall be pursuant

to paragraph 9(e)(1) of this Agreement,

which right shall in no way be limited

by this section.

E. Disputed Bills

In the event of a disputed bill, full

payment shall be rendered to Bonneville

and the disputed amount noted.

Disputed amounts are subject to the late

payment provisions specified in section

II(4) of the Billing Provisions of this

Exhibit B. Bonneville shall separately

account for the disputed amount. If it is

determined that Capacity Owner is

entitled to the disputed amount,

Bonneville shall refund the disputed

amount with interest, such interest to be

determined by Bonneville’s Financial

Services Group. In the event that

Bonneville and Capacity Owner do not

resolve such dispute, Capacity Owner

shall not be prevented by this section

II(5) of the Billing Provisions of this

Exhibit B from initiating arbitration

pursuant to and to the extent allowed by

section 15 of this Agreement.

F. Revised Bills

If Bonneville determines that it has

over- or under-charged Capacity Owner

due to a computational error or because

of an amendment to the Operating Plan

in any given billing month, Bonneville

may render to Capacity Owner a revised

bill.

1. If the amount of the revised bill is

less than or equal to the amount of the

original bill for such billing month, the

revised bill shall replace the original bill

issued by Bonneville. The revised bill

shall have the same date as the original

bill.

2. If the amount of the revised bill is

greater than the amount of the original

bill for such billing month, a new bill

will be issued for the difference between

the revised bill and the original bill. The

date of the new bill shall be its date of

issuance, and Capacity Owner shall

make payment to Bonneville as

specified in the Billing Provisions of

this Exhibit B.

C. General Transmission Rate Schedule

Provisions (GTRSPs)

Table of Contents

I. Adoption of Revised Transmission Rate

Schedules and General Transmission

Rate Schedules Provision

A. Approval of Rates

B. General Provisions

C. Interpretation

II. Billing Factor Definitions and Billing

Adjustments

A. Billing Factors

B. Billing Adjustments

III. Other Definitions

A. Agreement

B. Eastern Intertie

C. Electric Power

D. Federal Columbia River Transmission

System

E. Firm Transmission Service

F. Integrated Network

G. Main Grid

H. Main Grid Distance

I. Main Grid Interconnection Terminal

J. Main Grid Miscellaneous Facilities

K. Main Grid Terminal

L. Nonfirm Transmission Service

M. Northern Intertie

N. Point of Integration (POI)

O. Point of Delivery (POD)

P. Secondary System

Q. Secondary System Distance

R. Secondary System Interconnection

Terminal

S. Secondary System Intermediate

Terminal

T. Secondary Transformation

U. Southern Intertie

V. Transmission Service

IV. Billing Information

A. Payment of Bills

V. Charges Under the Amended and

Integrated Pacific Northwest

Coordination Agreement

A. Interchange Energy Imbalances

B. Interchange Energy Service Charge

C. Interchange Capacity Imbalances

D. Transfers Due to Forced Outages

E. Holding Interchange Energy Service

Charge

F. Stored Energy Service Charge

G. Transfers to Avoid Spill

H. Transmission Service Charges

I. Special Storage Agreements

Section I. Adoption of Revised

Transmission Rate Schedules and

General Transmission Rate Schedule

Provisions (GTRSPs)

A. Approval of Rates

These rate schedules and GTRSPs

shall become effective upon interim

approval or upon final confirmation and

approval by FERC. BPA will request

FERC approval effective October 1,

1995.

B. General Provisions

These 1995 Transmission Rate

Schedules and associated GTRSPs

supersede BPA’s 1993 Transmission

Rate Schedules and GTRSPs (which

became effective October 1, 1993) but do

not supersede prior rate schedules

required by agreement to remain in

force.

Transmission service provided shall

be subject to the following Acts, as

amended: the Bonneville Project Act,

the Regional Preference Act (Pub. L. 88–

552), the Federal Columbia River

Transmission System Act, and the

Pacific Northwest Electric Power

Planning and Conservation Act, and the

Energy Policy Act of 1992, Pub. L. 102–

486, 106 Stat. 2776 (1992).

The meaning of terms used in the

transmission rate schedules shall be as

defined in agreements or provisions

which are attached to the Agreement or

as in any of the above Acts.

C. Interpretation

If a provision in the executed

Agreement is in conflict with a

provision contained herein, the former

shall prevail.

Section II. Billing Factor Definitions

and Billing Adjustments

A. Billing Factors

1. Scheduled Demand

The largest of hourly amounts

wheeled which are scheduled by the

customer during the time period

specified in the rate schedules.

2. Metered Demand

The Metered Demand in kilowatts

shall be the largest of the 60-minute

clock-hour integrated demands

measured by meters installed at each

POD during each time period specified

in the applicable rate schedule. Such

measurements shall be made as

specified in the Agreement. BPA, in

determining the Metered Demand, will

exclude any abnormal readings due to

or resulting from: (a) emergencies or

breakdowns on, or maintenance of, the

FCRTS; or (b) emergencies on the

customer’s facilities, provided that such
21166 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

facilities have been adequately

maintained and prudently operated as

determined by BPA. If more than one

class of power is delivered to any POD,

the portion of the metered quantities

assigned to any class of power shall be

as agreed to by the parties. The amount

so assigned shall constitute the Metered

Demand for such class of power.

3. Transmission Demand

The demand as defined in the

Agreement.

4. Total Transmission Demand

The sum of the transmission demands

as defined in the Agreement.

5. Ratchet Demand

The maximum demand established

during the previous 11 billing months.

Exception: If a Transmission Demand or

Total Transmission Demand has been

decreased pursuant to the terms of the

Agreement during the previous 11

billing months, such decrease will be

reflected in determining the Ratchet

Demand.

B. Billing Adjustments

Average Power Factor

The adjustment for average power

factor, when specified in a transmission

rate schedule or in the Agreement, shall

be made in accordance with the average

power factor section of the General

Wheeling Provisions.

To maintain acceptable operating

conditions on the Federal system, BPA

may restrict deliveries of power at any

time that the average leading power

factor or average lagging power factor

for all classes of power delivered to

such point or to such system is below

85 percent.

Section III. Other Definitions

Definitions of the terms below shall

be applied to these provisions and the

Transmission Rate Schedules, unless

otherwise defined in the Agreement.

A. Agreement

An agreement between BPA and a

customer to which these rate schedules

and provisions may be applied.

B. Eastern Intertie

The segment of the FCRTS for which

the transmission facilities consist of the

Townsend-Garrison double-circuit 500

kV transmission line segment including

related terminals at Garrison.

C. Electric Power

Electric peaking capacity (kW) and/or

electric energy (kWh).

D. Federal Columbia River Transmission

System

The transmission facilities of the

Federal Columbia River Power System,

which include all transmission facilities

owned by the government and operated

by BPA, and other facilities over which

BPA has obtained transmission rights.

E. Firm Transmission Service

Transmission service which BPA

provides for any non-BPA power except

for transmission service which is

scheduled as nonfirm. If the firm service

is provided pursuant to the Agreement,

the terms of the Agreement may further

define the service.

F. Integrated Network

The segment of the FCRTS for which

the transmission facilities provide the

bulk of transmission of electric power

within the Pacific Northwest, excluding

facilities not segmented to the network

as shown in the Wholesale Power Rate

Development Study used in BPA’s rate

development.

G. Main Grid

As used in the FPT and IR rate

schedules, that portion of the Integrated

Network with facilities rated 230 kV and

higher.

H. Main Grid Distance

As used in the FPT rate schedules, the

distance in airline miles on the Main

Grid between the POI and the POD,

multiplied by 1.15.

I. Main Grid Interconnection Terminal

As used in the FPT rate schedules,

Main Grid terminal facilities that

interconnect the FCRTS with non-BPA

facilities.

J. Main Grid Miscellaneous Facilities

As used in the FPT rate schedules,

switching, transformation, and other

facilities of the Main Grid not included

in other components.

K. Main Grid Terminal

As used in the FPT rate schedules, the

Main Grid terminal facilities located at

the sending and/or receiving end of a

line exclusive of the Interconnection

terminals.

L. Nonfirm Transmission Service

Interruptible transmission service

which BPA may provide for non-BPA

power.

M. Northern Intertie

The segment of the FCRTS for which

the transmission facilities consist of two

500 kV lines between Custer Substation

and the United States-Canadian border,

one 500 kV line between Custer and

Monroe Substations, and two 230 kV

lines from Boundary Substation to the

United States-Canadian border, and the

associated substation facilities.

N. Point of Integration (POI)

Connection points between the

FCRTS and non-BPA facilities where

non-Federal power is made available to

BPA for wheeling.

O. Point of Delivery (POD)

Connection points between the

FCRTS and non-BPA facilities where

non-Federal power is delivered to a

customer by BPA.

P. Secondary System

As used in the FPT and IR rate

schedules, that portion of the Integrated

Network facilities with operating

voltage of 115 kV or 69 kV.

Q. Secondary System Distance

As used in the FPT rate schedules, the

number of circuit miles of Secondary

System transmission lines between the

secondary POI and the Main Grid or the

secondary POD, or the Main Grid and

the secondary POD.

R. Secondary System Interconnection

Terminal

As used in the FPT rate schedules, the

terminal facilities on the Secondary

System that interconnect the FCRTS

with non-BPA facilities.

S. Secondary System Intermediate

Terminal

As used in the FPT rate schedules, the

first and final terminal facilities in the

Secondary System transmission path

exclusive of the Secondary System

Interconnection terminals.

T. Secondary Transformation

As used in the FPT rate schedules,

transformation from Main Grid to

Secondary System facilities.

U. Southern Intertie

The segment of the FCRTS for which

the major transmission facilities consist

of two 500 kV AC lines from John Day

Substation to the Oregon-California

border; a portion of the 500 kV AC line

from Buckley Substation to Summer

Lake Substation; when completed, the

Third AC facilities, which include

Captain Jack Substation and the AlveyMeridian 500 kV AC line; one 1,000 kV

DC line between the Celilo Substation

and the Oregon-Nevada border; and

associated substation facilities.

V. Transmission Service

As used in the MT rate schedule,

Transmission Service is as defined in
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21167

the Western Systems Power Pool

Agreement.

Section IV. Billing Information

A. Payment of Bills

Bills for transmission service shall be

rendered monthly by BPA. Failure to

receive a bill shall not release the

customer from liability for payment.

Bills for amounts due of $50,000 or

more must be paid by direct wire

transfer; customers who expect that

their average monthly bill will not

exceed $50,000 and who expect special

difficulties in meeting this requirement

may request, and BPA may approve, an

exemption from this requirement. Bills

for amounts due BPA under $50,000

may be paid by direct wire transfer or

mailed to the Bonneville Power

Administration, P.O. Box 6040,

Portland, Oregon 97228–6040, or to

another location as directed by BPA.

The procedures to be followed in

making direct wire transfers will be

provided by the Office of Financial

Management and updated as necessary.

1. Computation of Bills

The transmission billing determinant

is the electric power quantified by the

method specified in the Agreement or

Transmission Rate Schedule. Scheduled

power or metered power will be used.

The transmission customer shall

provide necessary information to BPA

for any computation required to

determine the proper charges for use of

the FCRTS, and shall cooperate with

BPA in the exchange of additional

information which may be reasonably

useful for respective operations.

Demand and energy billings for

transmission service under each

applicable rate schedule shall be

rounded to whole dollar amounts, by

eliminating any amount which is less

than 50 cents and increasing any

amounts from 50 cents through 99 cents

to the next higher dollar.

2. Estimated Bills

At its option, BPA may elect to render

an estimated bill to be followed at a

subsequent billing date by a final bill.

The estimated bill shall have the

validity of and be subject to the same

payment provisions as a final bill.

3. Billing Month

For charges based on scheduled

quantities, the billing month is the

calendar month. For charges based on

metered quantities, the billing month is

defined as the interval between

scheduled meter-reading dates. The

billing month will not exceed 31 days

in any case. While it may be necessary

to read meters on a day other than the

scheduled meter-reading date, for

determination of billing demand, the

billing month will cease at 2400 hours

on the last scheduled meter-reading

date. Schedules will be predetermined.

The customer must give 30 days notice

to request a change to the schedule.

4. Due Date

Bills shall be due by close of business

on the 20th day after the date of the bill

(due date). Should the 20th day be a

Saturday, Sunday, or holiday (as

celebrated by the customer), the due

date shall be the next following business

day.

5. Late Payment

Bills not paid in full on or before

close of business on the due date shall

be subject to a penalty charge of $25. In

addition, an interest charge of onetwentieth percent (0.05 percent) shall be

applied each day to the sum of the

unpaid amount and the penalty charge.

This interest charge shall be assessed on

a daily basis until such time as the

unpaid amount and penalty charge are

paid in full.

Remittances received by mail will be

accepted without assessment of the

charges referred to in the preceding

paragraph provided the postmark

indicates the payment was mailed on or

before the due date. Whenever a power

bill or a portion thereof remains unpaid

subsequent to the due date and after

giving 30 days’ advance notice in

writing, BPA may cancel the contract for

service to the customer. However, such

cancellation shall not affect the

customer’s liability for any charges

accrued prior thereto under such

agreement.

6. Disputed Billings

In the event of a disputed billing, full

payment shall be rendered to BPA and

the disputed amount noted. Disputed

amounts are subject to the late payment

provisions specified above. BPA shall

separately account for the disputed

amount. If it is determined that the

customer is entitled to the disputed

amount, BPA shall refund the disputed

amount with interest, as determined by

BPA’s Office of Financial Management.

BPA retains the right to verify, in a

manner satisfactory to the

Administrator, all data submitted to

BPA for use in the calculation of BPA’s

rates and corresponding rate

adjustments. BPA also retains the right

to deny eligibility for any BPA rate or

corresponding rate adjustment until all

submitted data have been accepted by

BPA as complete, accurate, and

appropriate for the rate or adjustment

under consideration.

7. Revised Bills

As necessary, BPA may render a

revised bill.

a. If the amount of the revised bill is

less than or equal to the amount of the

original bill, the revised bill shall

replace all previous bills issued by BPA

that pertain to the specified customer

for the specified billing period and the

revised bill shall have the same date as

the replaced bill.

b. If a revision causes an additional

amount to be due BPA or the specified

customer beyond the amount of the

original bill, a revised bill will be issued

for the difference and the date of the

revised bill shall be its date of issue.

V. Charges Under The Amended and

Integrated Pacific Northwest

Coordination Agreement

The Pacific Northwest Coordination

Agreement (PNCA) is an agreement for

planned operations among the utilities

and other entities that operate the major

electric generating facilities and systems

in the Pacific Northwest. The parties

jointly and cooperatively plan and

coordinate their combined generation

facilities so as to produce the optimum

firm load carrying capability (FLCC) of

the coordinated system. FLCC is the

firm load that could be carried under

coordinated operation with critical

streamflow conditions and with the use

of all reservoir storage.

In order to coordinate operations, and

so that each party can meet its

individual FLCC, the PNCA provides for

exchanges of energy and capacity among

the parties. The agreement sets up

charges for each form of exchange. The

parties are negotiating a successor

agreement to the PNCA, and have

agreed on charges to apply under the

new agreement.

All terms contained herein have the

meaning accorded them in the

Amended and Integrated Pacific

Northwest Coordination Agreement.

These rates are to be effective on the

date on which rates are effective under

the Amended and Integrated Pacific

Northwest Coordination Agreement, as

provided in such Agreement. They will

remain in effect until revised rates are

approved.

A. Interchange Energy Imbalances

1. Initial Deliveries of Interchange

Energy
21168 Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices

Energy Charge = heat rate * fuel price + adder ( )

1 000 ,

Heat rate = 10,000 BTU/kWh

Fuel price = Average mainline

interruptible or spot market natural

gas price at Sumas, Washington, in

$/MMBTU (dollars per million

BTUs), for the twelve months

ending the immediately preceding

June 30, as published in Inside

FERC, or, in the event that Inside

FERC is no longer published, a

similar replacement publication.

Adder = 4.75 mills/kWh, adjusted each

August 1 beginning August 1, 1997,

by the change in the Consumer

Price Index (for all urban

consumers as published by the

Bureau of Labor Statistics) for

Portland, Oregon, for the twelvemonth period ending the

immediately preceding June 30.

2. Return of Interchange Energy

The Energy Charge for Return of

Interchange Energy shall be the charge

in effect for initial deliveries of

Interchange Energy at the time the

energy being delivered as Return of

Interchange Energy was delivered as an

initial delivery of Interchange Energy.

B. Interchange Energy Service Charge

1. No charge for energy returned between

7:00 a.m. and 10:00 p.m., Monday through

Saturday.

2. 2.50 mills per kilowatthour of energy

returned at other hours, unless such energy

was supplied during such other hours, or its

return during such other hours was

requested, in either of which events there

shall be no charge.

C. Interchange Capacity Imbalances

$2.00 per kilowatt week of demand.

D. Transfers Due to Forced Outage

1. Transfer Due to Loss of Thermal

Capability

$2.00 per kilowatt week of demand

plus the greater of (a) the charge for

Interchange Energy Imbalances and (b)

the incremental costs of operating the

resource used to supply the requested

energy plus an adder of 4.00 mills per

kilowatthour. The adder shall be

adjusted each August 1 beginning

August 1, 1997 by the change in the

Consumer Price Index (for all urban

consumers as published by the Bureau

of Labor Statistics) for Portland, Oregon,

for the twelve-month period ending the

immediately preceding June 30.

2. Transfer of Emergency Capacity

$2.00 per kilowatt week of demand

plus the greater of (a) the charge for

Interchange Energy Imbalances and (b)

the incremental costs of operating the

resource used to supply the requested

energy. In the event that BPA requires

the receiving party to return the energy

associated with the transfer of

emergency capacity, only the demand

charge shall apply.

E. Holding Interchange Energy Service

Charge

1. Basic Charge

2.00 mills per kilowatthour of

Holding Interchange Energy on delivery

to BPA and 1.50 mills per kilowatthour

of Holding Interchange Energy on return

from BPA (3.50 mills per kilowatthour

total). A loss of Holding Interchange

Energy because of spill will result in a

refund of 2.00 mills per kilowatthour of

Holding Interchange Energy that is

converted to Stored Energy and spilled.

2. Reshaping Charge

2.50 mills per kilowatthour of energy.

This charge shall apply, in each Light

Load Hour during which the energy

delivered or returned is greater than the

average hourly amount of energy

delivered or returned that day, to the

amount of energy delivered or returned

during such hour that exceeds the daily

hourly average. This charge applies in

addition to the basic charge.

F. Stored Energy Service Charge

For the purposes of this rate, light

load hours and heavy load hours shall

not include any hours designated by the

reservoir party as peak load hours.

1. Charges Paid on Delivery of Energy to

a Reservoir Party

a. 2.00 mills per kilowatthour of

energy delivered to BPA on Light Load

Hours.

b. 1.00 mill per kilowatthour of

energy delivered to BPA on Heavy Load

Hours.

c. No charge for energy delivered to

BPA on Peak Load Hours.

2. Charges Paid on Return of Energy

Stored Less Than Two Weeks

a. 1.00 mill per kilowatthour of energy

returned from BPA on Light Load

Hours.

b. 3.50 mills per kilowatthour for

energy returned from BPA on Heavy

Load Hours.

c. 5.00 mills per kilowatthour for

energy returned from BPA on Peak Load

Hours.

3. Charges Paid on Return of Energy

Stored for Two Weeks or More

a. No charge for energy returned from

BPA on Light Load Hours.

b. 2.50 mills per kilowatthour for

energy returned from BPA on Heavy

Load Hours.

c. 4.00 mills per kilowatthour for

energy returned from BPA on Peak Load

Hours.

4. Charges Paid on Return of Energy in

Cases of Imminent Spill

a. No charge for energy returned from

BPA on Light Load Hours.

b. 2.50 mills per kilowatthour for

energy returned from BPA on Heavy

Load Hours.

c. 2.50 mills per kilowatthour for

energy returned from BPA on Peak Load

Hours.

5. Refund of Storage Charges in Cases of

Spill

In the event that stored energy is not

returned to a party because of spill on

BPA’s system, or in the event that BPA

transfers the stored energy to another

Reservoir Party to avoid spill and the

transferred energy is later spilled, BPA

will refund the charges paid under

section F.1. in an amount equal to the

charges paid under such section,

divided by the kilowatthours of energy

delivered to BPA, multiplied by the

kilowatthours of stored energy that is

spilled.

G. Transfers To Avoid Spill

1. No charge for stored energy

transferred by a Reservoir Party to BPA

in order to avoid spill.

2. The applicable Stored Energy

Service charge shall apply in the event

that BPA accepts the transfer of stored

energy to avoid spill and then returns

the stored energy to the original

delivering party.

H. Transmission Service Charges

In any energy or capacity transaction

that utilizes BPA transmission facilities

where BPA acts solely as a transferor the

following charges shall apply to both

delivery and return of the energy, if

applicable:

1. 1.60 mills per kilowatthour of

Interchange Energy or Generation

Impact Replacement Energy paid by the

receiving party.

2. 1.75 mills per kilowatthour of

Holding Interchange and Storage Energy

paid by the party requesting the return.

3. No charge for In Lieu Energy,

except when the supplying or receiving
Federal Register / Vol. 60, No. 83 / Monday, May 1, 1995 / Notices 21169

party requires BPA, under the terms of

the PNCA, to provide transmission, in

which case the charge shall be 2.00

mills per kilowatthour of In Lieu Energy

paid by the party requiring BPA to

provide such transmission.

4. 2.00 mills per kilowatthour of

Provisional Energy paid by the

Reservoir Party.

5. 2.00 mills per kilowatthour of

energy associated with Transfers Due to

Cross-Border Flow Deviations paid by

the party receiving the transfer.

6. 2.00 mills per kilowatthour of

energy associated with Interchange

Capacity and FOR Capacity paid by the

party requesting the delivery.

I. Special Storage Arrangements

1. Suggested Rate

a. 1.00 mills per kilowatthour for

energy returned during Light Load

Hours.

b. 3.00 mills per kilowatthour for

energy returned during other hours.

2. Flexible Rate

The charges for special storage

arrangements may be specified at a

higher rate as mutually agreed between

the party requesting the special storage

arrangement and BPA.

Issued in Portland, Oregon, on April 17,

1995.

Randall W. Hardy,

Administrator and Chief Executive Officer.

[FR Doc. 95–10065 Filed 4–28–95; 8:45 am]

BILLING CODE 6450–01–P

Federal Energy Regulatory

Commission

[Docket No. ER95–727–000, et al.]

PacifiCorp, et al.; Electric Rate and

Corporate Regulation Filings

April 24, 1995.

Take notice that the following filings

have been made with the Commission:

1. PacifiCorp

[Docket No. ER95–727–000]

Take notice that on April 10, 1995,

PacifiCorp tendered for filing an

amendment in the above-referenced

docket.

Copies of this filing were supplied to

AES Power Inc., Engelhard Power

Marketing, Inc. InterCoast Energy

Marketing Company, Gulfstream Energy,

LLC, the Washington Utilities and

Transportation Commission and the

Public Utility Commission of Oregon.

Comment date: May 8, 1995, in

accordance with Standard Paragraph (E)

at the end of this notice.

2. PacifiCorp

[Docket No. ER95–728–000]

Take notice that on April 10, 1995,

PacifiCorp tendered for filing an

amendment in the above-referenced

docket.

Copies of this filing were supplied to

Bountiful, Rainbow, InterCoast, the

Washington Utilities and Transportation

Commission and the Public Utility

Commission of Oregon.

Comment date: May 8, 1995, in

accordance with Standard Paragraph (E)

at the end of this notice.

3. C.C. Pace Energy Services

[Docket No. ER94–1181–003]

Take notice that on April 5, 1995 C.C.

Pace Energy Services (C.C. Pace) filed

certain information as required by the

Commission’s July 25, 1994, letter order

in Docket No. ER94–1181–000. Copies

of C.C. Pace’s informational filing are on

file with the Commission and are

available for public inspection.

4. NorAm Energy Services Inc.

[Docket No. ER94–1247–004]

Take notice that on April 14, 1995,

NorAm Energy Services, Inc. tendered

for filing its quarterly report in the

above-referenced docket reporting the

following transactions:

1. Cajun Electric purchased from NES,

50 MWh at $21.00, non-firm energy,

delivered to the Cajun/Entergy

interconnect.

2. Associated Electric Coop.

purchased from NES, 1600 Mwh at

$17.00, non-firm energy, delivered to

Associated Electric/TVA interconnect.

3. Associated Electric purchased from

NES, 800 Mwh at $23.00, non-firm

entergy, delivered to Associated

Electric/Entergy interconnect.

4. Central Illinois Public Service sold

to NES, 54 Mwh at $16.50, non-firm

energy, delivered to CIPS/TVA

interconnect.

5. Louisville Gas & Electric sold to

NES, 1648 Mwh at $15.50, non-firm

energy, delivered to LG&E/TVA

interconnect.

6. Cajun Electric Co-op sold to NES,

824 Mwh at $19.00, non-firm energy,

delivered to Cajun/Entergy interconnect.

5. American Power Exchange, Inc Inc.

[Docket No. ER94–1578–002]

Take notice that on April 17, 1995,

American Power Exchange, Inc.

tendered for filing its quarterly report in

the above-referenced docket reporting

no purchases or sales of electricity in

the quarter ending March 31, 1995.

6. Wickland Power Services

[Docket No. ER95–300–001]

Take notice that on April 14, 1995,

Wickland Power Services, tendered for

filing its quarterly report in the abovereferenced docket, reporting no

purchases or sales of electricity in the

quarter ending March 31, 1995.

7. South Eastern Energy Resources, Inc.

[Docket No. ER95–385–001]

Take notice that on April 17, 1995,

South Eastern Energy Resources, Inc.

tendered for filing its quarterly report in

the above-referenced docket reporting

no purchases or sales of electricity in

the quarter ending March 31, 1995.

8. Consolidated Edison Company of

New York, Inc.

[Docket No. ER95–509–000]

Take notice that on April 17, 1995,

Consolidated Edison Company of New

York, Inc. (Con Edison), tendered for

filing revised proposed supplements to

its Rate Schedules FERC No. 96 and

FERC No. 92.

The revised proposed Supplement

No. 7 to Rate Schedule FERC No. 96

applicable to electric delivery service to

public customers and to non-public,

economic development customers of the

New York Power Authority (NYPA), and

the revised proposed Supplement No. 4

to Rate Schedule FERC No. 92,

applicable to electric delivery service to

commercial and industrial economic

development customers of the County of

Westchester Public Service Agency

(COWPUSA) and the New York City

Public Utility Service (NYCPUS), set

forth the terms of a settlement

agreement under which Con Edison’s

base rates and charges for these services

will neither increase nor decrease

during the 12-month period ending

March 31, 1996. The settlement

agreement also provides that changes in

rates for these services will be

implemented for the 12-month periods

ending March 31, 1997 and March 31,

1998, with the possibility of additional

limited changes in these rates in

succeeding annual periods.

These supplements would supersede

proposed Supplement No. 6 and

Supplement No. 7 to Rate Schedule

FERC No. 96 and proposed Supplement

No. 4 to Rate Schedule FERC No. 92

which Con Edison tendered to the

Commission on January 30, 1995. These

supplements have never been made

effective and should be deemed

superseded upon grant of the relief

requested in the present filing.

A copy of this filing has been served

on NYPA, COWPUSA, NYCPUS, and