63150 Federal Register / Vol. 62, No. 228 / Wednesday, November 26, 1997 / Notices

approximately $60 million in 1998 as

compared to the test year.

Maine Yankee states that copies of its

filing have been provided to its

jurisdictional customers, secondary

customers and to state regulatory

commissions in Connecticut, New

Hampshire, Massachusetts, Maine and

Rhode Island and the Office of the

Public Advocate, State of Maine.

Comment date: December 2, 1997, in

accordance with Standard Paragraph E

at the end of this notice.

26. Indiana Michigan Power Company

[Docket No. SC98–1–000]

Take notice that on October 31, 1997,

American Electric Power Service

Corporation, as agent for Indiana

Michigan Power Company (I&M), an

operating company of the American

Electric Power System, tendered for

filing an estimate of, and a proposal to

charge, stranded costs to the City of

Dowagiac, MI (Dowagiac), through the

rates for wholesale transmission service

to Dowagiac, or to another Transmission

Customer which serves Dowagiac, upon

the termination of I&M’s Municipal

Resale Service (MRS) Agreement with

Dowagiac. I&M requests an effective

date of March 1, 1998, the day following

such termination.

Copies of the filing have been served

upon Dowagiac and the Michigan Public

Service Commission.

Comment date: December 3, 1997, in

accordance with Standard Paragraph E

at the end of this notice.

Standard Paragraph

E. Any person desiring to be heard or

to protest said filing should file a

motion to intervene or protest with the

Federal Energy Regulatory Commission,

888 First Street, N.E., Washington, D.C.

20426, in accordance with Rules 211

and 214 of the Commission’s Rules of

Practice and Procedure (18 CFR 385.211

and 18 CFR 385.214). All such motions

or protests should be filed on or before

the comment date. Protests will be

considered by the Commission in

determining the appropriate action to be

taken, but will not serve to make

protestants parties to the proceeding.

Any person wishing to become a party

must file a motion to intervene. Copies

of this filing are on file with the

Commission and are available for public

inspection.

Lois D. Cashell,

Secretary.

[FR Doc. 97–31068 Filed 11–25–97; 8:45 am]

BILLING CODE 6717–01–P

DEPARTMENT OF ENERGY

Western Area Power Administration

Parker-Davis Project Rate Adjustment;

Notice of Rate Order No. WAPA–75

AGENCY: Western Area Power

Administration, DOE.

ACTION: Notice of rate order.

SUMMARY: Notice is given of the

confirmation and approval by the

Deputy Secretary of the Department of

Energy (DOE) of Rate Order No. WAPA–

75 and Rate Schedules for Wholesale

Firm Power Service (PD–F6) , Firm

Transmission Service (PD–FT6), Firm

Transmission Service of Salt Lake City

Area Integrated Projects Power (PD–

FCT6), and Nonfirm Transmission

Service (PD–NFT6) placing into effect

the rate methodology for determining

rates for existing Parker-Davis Project

(P–DP) contractors of the Western Area

Power Administration (Western) on an

interim basis. The rate methodology will

remain in effect on an interim basis

until the Federal Energy Regulatory

Commission (FERC) confirms, approves,

and places it into effect on a final basis

or until superseded.

DATES: Rate Schedules PD–F6, PD–FT6,

PD–FCT6, and PD–NFT6 will be placed

into effect on an interim basis on the

first day of the first full billing period

beginning on or after November 1, 1997,

and will be in effect until FERC

confirms, approves, and places the rate

schedules into effect on a final basis for

a 59-month period, or until the rate

schedule is superseded.

FOR FURTHER INFORMATION CONTACT:

J. Tyler Carlson, Regional Manager,

Western Area Power Administration,

Desert Southwest Regional Office, P.O.

Box 6457, Phoenix, AZ 85005, (602)

352–2453, or Joel K. Bladow, Assistant

Administrator for Power Marketing

Liaison, Room 8G–027, 1000

Independence Avenue, SW.,

Washington, DC 20585, (202) 586–5581.

SUPPLEMENTARY INFORMATION: The

proposed rate methodology is the result

of Western, the Bureau of Reclamation,

and existing P–DP customers working

together to develop a methodology that

would recover the project costs and

accommodate advance funding for P–DP

expenses. The changes made to the P–

DP rate methodology are outlined as

follows. The first change concerns the

Cost Apportionment Study. The study,

which demonstrates the distribution of

costs between generation and

transmission, has been changed as

follows: (1) the Priority Use Power

(PUP) contractors’ delivery

commitments are now included in the

total amounts reflected in the generation

and transmission delivery commitment

figures; and (2) the amount of funds to

be repaid through the collection of

revenues through rates is now based on

the single Fiscal Year (FY) projection,

instead of a projected 5-year average

calculation. These changes were

required so the PUP contractors can

demonstrate payment of their portion of

generation and transmission costs, and

to accommodate the yearly

reconciliation of expenses under the

advance funding agreements which

have been executed with the PUP

contractors and are currently being

negotiated with the Firm Electric

Service (FES) contractors.

The second change concerns the

ratesetting methodology. The new rate

methodology includes the PUP

contractors’ delivery commitments in

the calculations of the rates. This was

necessary so the PUP contractors can

demonstrate payment of their portion of

generation and transmission costs.

The third change concerns the billing

for firm electric service. Due to the

separation of the transmission

component from the Capacity Rate, the

FES contractors will be billed a Capacity

Rate of dollars per kilowatt per month,

an Energy Rate of mills per

kilowatthour, and a Firm Transmission

Rate of dollars per kilowatt per month.

The fourth change concerns the

updating of the expense and other

revenue estimates for FY 1997 and the

cost evaluation period of FY 1998

through FY 2002 as a result of better

data.

The final change concerns the

significant decrease in the transmission

contract rate of delivery (CROD) used to

calculate the Firm Transmission Rate,

Firm Transmission Rate of Salt Lake

City Area Integrated Projects (SLCA/IP)

Power, and Nonfirm Transmission Rate.

The decrease in the CROD resulted

primarily from changes in delivery

commitments.

A comparison of the existing rates and

rates for FY 1998 calculated in

accordance with the proposed rate

methodology are as follows:
Federal Register / Vol. 62, No. 228 / Wednesday, November 26, 1997 / Notices 63151

COMPARISON OF EXISTING RATES AND PROPOSED RATE METHODOLOGY RATES

Existing Rate

(FY 1995)

Proposed

Rate (FY

1998) 1

Difference

Rate Schedule: PD–F5 PD–F6

Firm Capacity Rate ($/kW-month) ......................................................................................... $1.92 $0.56 ($1.36)

Firm Energy Rate (mills/kWh) ............................................................................................... 1.95 1.29 (0.67)

Composite Rate (mills/kWh) .................................................................................................. 6.33 2.57 (3.76)

Rate Schedule: PD–FT5 &

PD–FCT5

PD–FT6 &

PD–FCT6

Firm Transmission Rate ($/kW-month) ................................................................................. $0.96 $1.08 $0.12

Firm Transmission Rate for SLCA/IP ($/kW-month) ............................................................. $0.96 $1.08 $0.12

Rate Schedule: PD–NFT5 PD–NFT6

Nonfirm Transmission Rate (mills/kWh) ................................................................................ 2.19 2.47 0.28

1 New rates will be calculated in accordance with the rate schedules each year by September 1. These rates represent FY 1998 only.

The decrease in the Firm Energy Rate

and Firm Capacity Rate for FY 1998 can

be attributed to a large revenue

carryover balance from FY 1997, the

removal of the transmission component

from the Firm Capacity Rate which will

be billed separately, and the inclusion

of the contracted energy and capacity

for the PUP contractors. The increase in

the Firm Transmission Rate, Firm

Transmission Rate of SLCA/IP Power,

and Nonfirm Transmission Rate can be

attributed to a significant decrease in

the CROD used to calculate these rates

even though there is a large revenue

carryover balance from FY 1997.

Statement of Annual Revenue

Requirement

The Annual Revenue Requirement

Allocated to Generation and

Transmission will be based upon the net

amount between the estimated expenses

and other revenue as presented in the

Cost Apportionment Study. The Power

Repayment Study (PRS) will document

these expenses and other revenue. The

difference between the estimated and

the actual Annual Revenue Requirement

Allocated to Generation and

Transmission for the rate year will be

used to adjust the next year’s Annual

Revenue Requirement.

By Amendment No. 3 to Delegation

Order No. 0204–108, published

November 10, 1993 (58 FR 59716), the

Secretary of Energy (Secretary)

delegated (1) the authority to develop

long-term power and transmission rates

on a nonexclusive basis to the

Administrator of Western; (2) the

authority to confirm, approve, and place

such rates into effect on an interim basis

to the Deputy Secretary; and (3) the

authority to confirm, approve, and place

into effect on a final basis, to remand,

or to disapprove such rates to FERC.

Existing DOE procedures for public

participation in power rate adjustments

(10 CFR Part 903) became effective on

September 18, 1985 (50 FR 37835).

These power and transmission rates

are established pursuant to Section

302(a) of the Department of Energy

(DOE) Organization Act, 42 U.S.C.

§ 7152(a), through which the power

marketing functions of the Secretary of

the Interior and the Bureau of

Reclamation (Reclamation) under the

Reclamation Act of 1902, 43 U.S.C.

§ 371 et seq., as amended and

supplemented by subsequent

enactments, particularly Section 9(c) of

the Reclamation Project Act of 1939, 43

U.S.C. § 485h(c), and other acts

specifically applicable to the project

system involved, were transferred to

and vested in the Secretary, acting by

and through the Administrator of

Western.

Rate Order No. WAPA–75,

confirming, approving, and placing the

proposed rate methodology for

determining rates for existing

contractors from the P–DP into effect on

an interim basis, is issued, and the new

Rate Schedules PD–F6, PD–FT6, PD–

FCT6, and PD–NFT6 will be submitted

promptly to FERC for confirmation and

approval on a final basis. Western is

developing open access tariffs

consistent with FERC Order No. 888 and

intends to publish short-term rates by

November 1997, and to submit longterm rates to the FERC by April 1, 1998.

Dated: November 18, 1997.

Elizabeth A. Moler,

Deputy Secretary.

Department of Energy Deputy Secretary

Order Confirming, Approving, and

Placing the Parker-Davis Project Firm

Power Service Rate, Firm Transmission

Service Rate, and Nonfirm

Transmission Service Rate Into Effect

on an Interim Basis

November 1, 1997.

The rate methodology is established

pursuant to Section 302(a) of the

Department of Energy (DOE)

Organization Act, 42 U.S.C. § 7152(a),

through which the power marketing

functions of the Secretary of the Interior

and the Bureau of Reclamation

(Reclamation) under the Reclamation

Act of 1902, 43 U.S.C. § 371 et seq., as

amended and supplemented by

subsequent enactments, particularly

Section 9(c) of the Reclamation Project

Act of 1939, 43 U.S.C. § 485h(c), and

other acts specifically applicable to the

project system involved were

transferred to and vested in the

Secretary of Energy (Secretary), acting

by and through the Administrator of

Western.

By Amendment No. 3 to Delegation

Order No. 0204–108, published

November 10, 1993 (58 FR 59716), the

Secretary delegated (1) the authority to

develop long-term power and

transmission rates on a nonexclusive

basis to the Administrator of the

Western Area Power Administration

(Western); (2) the authority to confirm,

approve, and place such rates into effect

on an interim basis to the Deputy

Secretary; and (3) the authority to

confirm, approve, and place into effect

on a final basis, to remand, or to

disapprove such rates to the Federal

Energy Regulatory Commission. Existing

DOE procedures for public participation

in power rate adjustments (10 CFR Part

903) became effective on September 18,

1985 (50 FR 37835).

Acronyms and Definitions

As used in this rate order, the

following acronyms and definitions

apply:

$/kW-month: Monthly charge for

capacity. $/kW-season and S/kW-year

are converted to a monthly rate ($ per

kilowatt per month) for billing

purposes.

$/kW-season: Seasonal rate for

capacity ($ per kilowatt per season).

This is used with the Firm Transmission

Rate of Salt Lake City Area Integrated

Projects power.
63152 Federal Register / Vol. 62, No. 228 / Wednesday, November 26, 1997 / Notices

$/kW-year: Yearly rate for capacity ($

per kilowatt per year). This is used with

the Firm Transmission Rate and the

Capacity Rate.

Annual Revenue Requirement: The

revenue that Western needs to meet

repayment criteria, which serves as the

basis for allocation between generation

and transmission.

Annual Revenue Requirement

Allocated to Generation: The dollar

amount that has been allocated to

Generation. This amount is used to

calculate the Energy Rate, Capacity Rate,

and Composite Rate.

Annual Revenue Requirement

Allocated to Transmission: The dollar

amount that has been allocated to

Transmission. This amount is used to

calculate the Firm Transmission Rate,

Firm Transmission Rate of Salt Lake

City Area Integrated Projects, and

Nonfirm Transmission Rate.

Annual Energy: The total annual

energy entitlement for the PUP and/or

FES contractors.

Capacity Rate: Expressed in $/kWmonth and applied to each kW of the

FES contractor’s seasonal CROD and

each kW over the FES contractor’s

seasonal CROD, as applicable.

Energy Rate: Expressed in mills per

kilowatthour (mills/kWh) and applied

each billing period to each kWh of the

FES contractor’s monthly energy

entitlement, each kWh over the FES

contractor’s monthly energy

entitlement, and to each kWh of excess

energy sold, as applicable.

CIA: Compound Interest

Amortization.

Cost Apportionment Study: A study

which allocates P–DP’s total costs and

other revenue between generation and

transmission.

CROD: Contract Rate of Delivery.

Customer Brochure: A document

prepared for public distribution

explaining the background of the rate

proposal contained in this rate order.

DOE: Department of Energy.

DOE Order RA 6120.2: An order

dealing with power marketing

administration financial reporting.

FERC: Federal Energy Regulatory

Commission.

FES: Firm Electric Service.

FY: Fiscal Year.

Interior: U.S. Department of the

Interior.

kW: Kilowatt.

kW-month: Kilowatt-month.

kW-season: Kilowatt-season.

kW-year: Kilowatt-year.

kWh: Kilowatthour.

mills/kWh: Mills per kilowatthour—

the unit of charge for energy.

NEPA: National Environmental Policy

Act of 1969.

O&M: Operation and Maintenance.

P–DP: Parker-Davis Project.

Proposed Rate: A rate adjustment that

the Administrator of Western

recommends to the Deputy Secretary.

Provisional Rate: A rate which has

been confirmed, approved, and placed

into effect on an interim basis by the

Deputy Secretary.

PRS: Power Repayment Study.

PUP: Priority Use Power.

Reclamation: Bureau of Reclamation,

U.S. Department of the Interior.

Seasonal CROD: The CROD that FES

contractors are entitled to during winter

season and summer season. P–DP

winter season is October through

February and summer season is March

through September. SLCA/IP winter

season is October through March and

summer season is April through

October.

SLCA/IP: Salt Lake City Area

Integrated Projects.

Western: Western Area Power

Administration, U.S. Department of

Energy.

Effective Date

The new rate methodology for

determining the rates for existing P–DP

contractors will become effective on an

interim basis beginning November 1,

1997, and remain in effect pending

FERC’s approval on a final basis for a

59-month period, or until superseded.

Public Notice and Comment

The Procedures for Public

Participation in Power and

Transmission Rate Adjustments and

Extensions, 10 CFR Part 903, have been

followed by Western in developing the

method for determining the total

Annual Revenue Requirement, Annual

Revenue Requirement Allocated to

Generation, Annual Revenue

Requirement Allocated to Transmission,

Energy Rate, Capacity Rate, Firm

Transmission Rate, Firm Transmission

Rate of SLCA/IP Power, and Nonfirm

Transmission Rate.

The following summarizes the steps

Western took to ensure involvement of

interested parties in the rate process:

1. Review and discussion of the rate

methodology and allocating factors were

conducted at several meetings with the

contractors and interested parties. These

meetings were held October 24, 1996,

November 18, 1996, January 16, 1997,

April 21, 1997, and August 8, 1997.

2. Discussion of the changes to the

proposed rate methodology and

resulting rates were initiated at an

informal P–DP contractor meeting held

on May 7, 1997, in Phoenix, Arizona. At

this informal meeting, Western

explained the need for a change in the

estimates and methodology used to

calculate the charges and rates.

3. A Federal Register notice was

published on May 23, 1997 (62 FR

28465), officially announcing the

proposed firm power rate, firm

transmission rate, and nonfirm

transmission rate adjustment, initiating

the public consultation and comment

period, announcing the public

information and public comment

forums, and presenting procedures for

public participation.

4. On June 3, 1997, a letter was mailed

from Western to all P–DP firm power,

firm transmission, and nonfirm

transmission customers and other

interested parties providing a copy of

the P–DP Rate Brochure dated May 1997

which included a copy of the Federal

Register notice of May 23, 1997.

5. At the public information forum

held on June 10, 1997, Western and

Reclamation representatives explained

the proposed rate methodology, a

change in the proposed billing

procedures, and outlined the changes in

the Annual Revenue Requirement for

Rate Year 1998 in greater detail and

answered questions.

6. The comment forum was held on

July 14, 1997, to give the public an

opportunity to comment for the record.

Six persons representing customers and

customer groups made oral comments.

7. On August 14, 1997, a letter was

mailed from Western to all P–DP firm

power, firm transmission, and nonfirm

transmission customers and other

interested parties providing a copy of

the revised PRS and related tables. The

letter stated the final proposed rates and

reminder of the coming close of the

comment period.

8. Six comment letters were received

during the 90-day consultation and

comment period. The consultation and

comment period ended August 21, 1997.

All formally submitted comments have

been considered in the preparation of

this rate order.

Project History

The Parker Dam Power Project was

authorized by Section 2 of the Rivers

and Harbors Act of August 30, 1935 (49

Stat. 1039), and the Davis Dam Project

was authorized April 26, 1941, by the

Acting Secretary of the Interior under

provisions of the Reclamation Project

Act of 1939 (43 U.S.C. 485, et seq.). The

P–DP was formed by the consolidation

of the two Projects under the terms of

the Act of May 28, 1954 (68 Stat. 143).

Davis Dam, which creates Lake

Mohave, provides regulation, both

hourly and seasonally, of the water

releases from Lake Mead (through

Hoover Dam and Powerplant) to
Federal Register / Vol. 62, No. 228 / Wednesday, November 26, 1997 / Notices 63153

facilitate water delivery for downstream

irrigation requirements and for water

delivery beyond the boundary of the

United States as required by the

Mexican Water Treaty. Operation of the

powerplant began in January 1951 with

a generating capacity of 225,000 kW.

During the period 1974–1978 the

generator nameplate capacity was

increased to 240,000 kW by rewinding

the generator stators.

Construction of Parker Dam was

authorized for the purposes of

controlling floods, improving river

navigation, regulating the flow of the

Colorado River, providing for storage

and for the delivery of the stored waters

thereof, for the reclamation of public

lands and Indian reservations, and for

other beneficial uses, and for the

generation of electric energy as a means

of making the P–DP a self-supporting

and financially solvent undertaking.

Parker Dam was constructed by the

Bureau of Reclamation (Reclamation)

with funds advanced by the

Metropolitan Water District of Southern

California (MWD). Lake Havasu, the

reservoir created behind Parker Dam,

serves as the forebay from which water

is diverted into the MWD aqueduct. The

aqueduct delivers a major portion of

California’s entitlement of Colorado

River water to southern California and

is the diversion point for delivering

Central Arizona Project water to

Arizona. The reservoir operation is

limited to minor storage fluctuations.

The dam provides a head of

approximately 75 feet for the Parker

Powerplant. Reclamation began

operation of Parker Powerplant in

December 1942. Although the total

generator nameplate capacity is 120,000

kW, the powerplant capacity is

essentially limited to 104,000 kW

because of operating constraints of

downstream physical structures,

primarily Headgate Rock Dam. Under

contract, MWD is entitled to one-half of

the net energy generated by Parker

Powerplant at any given time.

All facilities of the P–DP were

operated and maintained by

Reclamation until the formation of the

Department of Energy pursuant to the

Department of Energy Organization Act

(DOE Act), 42 U.S.C. Sections 7101 et

seq., enacted by Congress on August 4,

1977. Pursuant to Section 302 of the

DOE Act (42 U.S.C. 7152), responsibility

for the power marketing functions of

Reclamation, including the

construction, operation, and

maintenance of substations,

transmission lines and attendant

facilities was transferred to the

Department of Energy. The

responsibility for operation and

maintenance of the dams and

powerplants remains with Reclamation.

Power Repayment Studies

A PRS is prepared each FY to

determine if power revenues will be

sufficient to repay, within the

prescribed time periods, all costs

assigned to the power function.

Repayment criteria are based on law,

policies, and authorizing legislation.

DOE Order RA 6120.2, Section 12b,

requires that:

In addition to the recovery of the

above costs (operation and maintenance

and interest expenses) on a year-by-year

basis, the expected revenues are at least

sufficient to recover (1) each dollar of

power investment at Federal

hydroelectric generating plants within

50 years after they become revenue

producing, except as otherwise

provided by law; plus, (2) each annual

increment of Federal transmission

investment within the average service

life of such transmission facilities or

within a maximum of 50 years,

whichever is less; plus, (3) the cost of

each replacement of a unit of property

of a Federal power system within its

expected service life up to a maximum

of 50 years; plus, (4) each dollar of

assisted irrigation investment within the

period established for the irrigation

water users to repay their share of

construction costs; plus, (5) other costs

such as payments to basin funds,

participating projects, or States.

Existing and Provisional Rates

A comparison of the existing rates and

rates for FY 1998 calculated in

accordance with the provisional rate

methodology are as follows:

COMPARISON OF EXISTING RATES AND PROPOSED RATE METHODOLOGY RATES

Existing Rate

(FY 1995)

Provisional

Rate (FY

1998) 1

Percent

Change (%)

Firm Power Service Rate Schedule: PD–F5 PD–F6

Capacity Rate ($/kW/month) ................................................................................................. $1.92 $0.56 ¥70.83

Energy Rate (mills/kWh) ........................................................................................................ 1.95 1.29 ¥34.36

Composite Rate (mills/kWh) .................................................................................................. 6.33 2.57 ¥59.40

Firm Transmission Service Rate Schedule: PD–FT5 PD–FT6

Firm Transmission Charge ($/kW-month) ............................................................................. $0.96 $1.08 12.50

Firm Transmission Charge for SLCA/IP ($/kW-month) ......................................................... $0.96 $1.08 12.50

Nonfirm Transmission Service Rate Schedule: PD–NFT5 PD–NFT6

Nonfirm Transmission Charge (mills/kWh) ............................................................................ 2.19 2.47 12.79

1 New rates will be calculated in accordance with the rate schedules each year by September 1. These rates represent FY 1998 only.

Certification of Rate

Western’s Administrator has certified

that the rate methodology for

determining the P–DP firm power rate,

firm transmission rate, transmission

service SLCA/IP rate, and nonfirm

transmission rate, placed into effect on

an interim basis herein are the lowest

possible consistent with sound business

principles. The rate methodology has

been developed in accordance with

administrative policies and applicable

laws.

Discussion

Western is requesting approval to

place into effect a ratesetting

methodology that will be used each year

to calculate the total Annual Revenue

Requirement, Annual Revenue

Requirement Allocated to Generation,

Annual Revenue Requirement Allocated

to Transmission, Capacity Rate, Energy

Rate, Firm Transmission Rate, Firm

Transmission Rate of SLCA/IP Power,

and Nonfirm Transmission Rate. For FY

1998, the ratesetting methodology

produces a decrease in the firm power

rates for capacity and energy, and a rate

increase for firm and nonfirm

transmission service for the P–DP on an

interim basis. Five major changes to the

rate methodology are affecting these

rates for the P–DP.

The first change concerns the Cost

Apportionment Study. The study,

which demonstrates the distribution of
63154 Federal Register / Vol. 62, No. 228 / Wednesday, November 26, 1997 / Notices

costs between generation and

transmission, has been changed as

follows: (1) the PUP contractors’

delivery commitments are now included

in the total amounts reflected in the

generation and transmission delivery

commitment figures; and (2) the amount

of funds to be repaid through the

collection of revenues through rates is

now based on the single FY projection,

instead of a projected 5-year average

calculation. These changes were

required so the PUP contractors can

demonstrate payment of their portion of

generation and transmission costs, and

to accommodate the yearly

reconciliation of expenses under the

advance funding agreements which

have been executed with the PUP

contractors and are currently being

negotiated with the FES contractors.

The second change concerns the

ratesetting methodology. The new rate

methodology includes the PUP

contractors’ delivery commitments in

the calculations of the rates. This was

necessary so the PUP contractors can

demonstrate payment of their portion of

generation and transmission costs.

The third change concerns the billing

for FES. Due to the separation of the

transmission component from the

Capacity Rate, the FES contractors will

be billed a Capacity Rate of dollars per

kilowatt per month, an Energy Rate of

mills per kilowatthour, and a Firm

Transmission Rate of dollars per

kilowatt per month.

The fourth change concerns the

updating of the expense and other

revenue estimates for FY 1997 and the

cost evaluation period of FY 1998

through FY 2002 as a result of better

data.

The final change concerns the

significant decrease in the transmission

CROD used to calculate the Firm

Transmission Rate, Firm Transmission

Rate of Salt Lake City Area Integrated

Projects Power, and Nonfirm

Transmission Rate. The decrease in the

CROD resulted primarily from changes

in delivery commitments.

With these changes to the existing

methodology, the proposed rate

methodology will yield annual revenues

sufficient to satisfy the cost-recovery

criteria set forth in DOE Order RA

6120.2. The existing Annual Revenue

Requirement and Annual Revenue

Requirement for FY 1998 for the P-DP

are as follows:

Estimated Revenue (Rounded to

Nearest $1,000)

Existing FY 1998

Annual Revenue Requirement ................... $28,522 $25,036

Annual Revenue Requirement for Generation ............................. 4,495 3,459

Annual Revenue Requirement for Transmission ....................... 24,027 21,577

Statement of Revenue and Related

Expenses

The Annual Revenue Requirement for

Generation and the Annual Revenue

Requirement for Transmission are based

upon a ratebase PRS and a Cost

Apportionment Study which estimates

the annual costs less other revenues.

The following table provides a summary

of revenue and expense data through the

5-year period FY 1998–FY 2002 at the

provisional rates, compared to the 5-

year period FY 1996–FY 2000 at the

current rates.

PARKER-DAVIS PROJECT COMPARISON

OF 5-YEAR RATE PERIOD REVENUES

AND EXPENSES

[$1,000]

Current

Rate

PRS

1996–

2000

Provisional

Rate

PRS

1998–

2002

Difference

Total Revenues .......... $180,212 $189,728 $9,516

Revenue Distribution:

O&M .......... 114,874 123,447 8,573

Purchased

Power .... 4,500 2,170 (2,330)

Other ......... 1,017 769 (248)

nterest ....... 56,452 58,342 1,890

Investment

Repayment ...... 3,014 3,496 482

Capitalized

Expenses

Repayment ...... 355 $1,504 1,149

Total ...... 180,212 189,728 9,516

Basis for Rate Development

The rates are calculated using the

Annual Revenue Requirement for

Generation and the Annual Revenue

Requirement for Transmission as

calculated in the Cost Apportionment

Study. As a result of this study for FY

1998, 86.18 percent of the P-DP costs are

to be recovered from the firm

transmission service, while the

remaining 13.82 percent of the costs are

to be recovered from firm power and

PUP service. The rate design consists of

seven steps.

1. The data in the Cost

Apportionment Study is updated yearly

with the latest (1) approved budget

plans for the next 5 years, (2) principal

and interest payments derived from the

PRS for the next 5 years, (3) estimate of

other revenue, (4) number of electric

service and transmission contractors for

the next 5 years, (5) amount of energy

commitments for the next 5 years, (6)

amount of CROD for the next 5 years, (7)

amount of in-service investments in the

plant accounts since 1987, and (8) 5-

year historical capitalized movable

property expense data.

2. From the Cost Apportionment

Study, the Annual Revenue

Requirement Allocated to Generation

and Transmission is derived on a yearly

basis.

3. The firm transmission rate is

developed by dividing the Annual

Revenue Requirement Allocated to

Transmission by the average monthly

billing CROD, rounded to the penny, to

determine the yearly rate. The monthly

billing rate is equal to the yearly rate

divided by 12, rounded to the penny.

Transmission sales include the

contracted transmission capacity with

the firm transmission service customers,

FES customers, and PUP customers.

4. The Capacity Rate, Energy Rate,

and the Composite Rate are calculated.

The Capacity Rate is calculated by

taking 50 percent of the Annual

Revenue Requirement Allocated to

Generation divided by the sum of the

Average Monthly Billing CROD for the

PUP contractors and FES contractors,

rounded to the penny, to determine the

yearly rate. The monthly billing rate is

equal to the yearly rate divided by 12,

rounded to the penny.

The Energy Rate is calculated by

taking 50 percent of the Annual

Revenue Requirement Allocated to

Generation divided by the sum of the

Annual Energy obligation for the PUP

contractors and the Annual Energy

obligation for the FES contractors,

rounded to two decimal places.

The composite rate is calculated by

taking the Annual Revenue Requirement

Allocated to Generation divided by the

sum of the Annual Energy obligation for

the PUP contractors and the Annual

Energy obligation for the FES

contractors, rounded to two decimal

places.

5. The firm transmission rate for

delivery of SLCA/IP power is

determined by dividing the firm

transmission service rate in half,

rounded to the penny to determine the

seasonal rate. The monthly billing rate
Federal Register / Vol. 62, No. 228 / Wednesday, November 26, 1997 / Notices 63155

is equal to the seasonal rate divided by

six, rounded to the penny.

6. The nonfirm transmission rate is

calculated by taking the firm

transmission rate yearly rate divided by

the product of 8,760 multiplied by 60

percent with the result multiplied by

1,000, rounded to two decimal places.

7. The FES contractors are billed

monthly an energy charge, a capacity

charge, and a transmission charge. The

contractor’s monthly energy charge is

equal to the contractor’s monthly energy

entitlement multiplied by the energy

rate. The contractor’s monthly capacity

charge is equal to the contractor’s

seasonal billing CROD multiplied by the

monthly capacity rate. The contractor’s

monthly transmission charge is equal to

the contractor’s seasonal billing CROD

multiplied by the monthly firm

transmission rate.

Comments

During the 90-day comment period,

Western received six written comments

either requesting information or

commenting on the rate adjustment. In

addition, six persons commented during

the July 14, 1997, public comment

forum. All comments were reviewed

and considered in the preparation of

this rate order.

Written comments were received from

the following sources:

R. W. Beck, Arizona Public Service

Company, Overton Power District No.

5 and Valley Electric Association,

Irrigation & Electrical Districts

Association of Arizona, K. R. Saline &

Associates, and Citizens Utilities

Company.

Representatives of the following

organizations made oral comments:

Arizona Power Authority, Citizens

Utilities Company and Arizona Public

Service Company, Salt River Project,

Irrigation & Electrical District

Association of Arizona and the City of

Needles, CA, Overton Power District

No. 5, Valley Electric Association, and

the Town of Fredonia, AZ, and K. R.

Saline & Associates.

The comments received at the public

meetings and in correspondence dealt

with (1) the development of better

allocators for apportioning the costs and

other revenues between generation and

transmission; (2) the finalization of

budget estimates and what costs should

go into those estimates; (3) the changes

in contract relationships with

contractors and their effect on the rates;

and (4) the use of the PRS. The

comments and responses, paraphrased

for brevity, are discussed below. Direct

quotes from comment letters are used

for clarification where necessary.

Issue: A contractor commented that

the ‘‘customer allocator’’ used in the

Cost Apportionment Study does not

sufficiently provide for a direct

relationship between cost-causation and

the recovery of expenses through rates.

The customer requests serious

consideration of this issue be addressed

in the future.

Response: Western has given this

issue serious consideration during this

rate process and will continue to

examine this issue during the next rate

process. Additional information

concerning the allocation factors is

discussed below.

Issue: A customer commented that a

reexamination of the cost allocation

factors would not be cost beneficial and

would result in only a minor change to

the overall allocation percentages.

Response: At this time, Western

cannot predict what the effect to the

overall allocation percentages would be

upon reexamination of the cost

allocation factors. With the overall

revenue requirement for the P–DP

approaching $30 million, even a minor

change to the overall allocation

percentages may significantly affect

some of Western’s smaller customers.

Issue: A comment was made that the

public comment period be continued for

an additional 30 to 60 days in order to

further review the cost allocation factors

and to analyze the allocation of

Western’s operation expenses.

Response: At a meeting held with

contractors and interested parties on

January 16, 1997, it was agreed the cost

allocation factors, as they currently

exist, remain functional and that a better

process does not exist. However, it was

also agreed the allocation factors may be

revisited during future rate processes.

At another meeting with the contractors

and interested parties held on August 8,

1997, it was once again agreed the

current rate process move forward using

the allocation factors that were

documented and approved during the

last rate process and reaffirmed during

this current rate process. Once again it

was agreed the cost allocation methods

be reexamined during the next rate

process.

Issue: A customer commented that

Western review its current policies or

develop new processes to mitigate the

rate impacts to remaining customers

when it enters new relationships with

existing customers.

Response: Western will continue to

seek to improve on existing procedures

or develop new processes that will meet

Western’s legislated mandates in a fair

and equitable manner. Furthermore,

Western will continue to pursue sound

business practices that produce the

lowest possible rate to the extent

possible.

Issue: A customer stated that staffing

levels, below authorized levels, allowed

a large portion of the projected current

year carryover and suggested that

Western perform a thorough review of

its staffing requirements and provide

supporting evidence to its customers of

any increased staffing over current

levels.

Response: Western is nearing

completion of a transformation process

that began in 1995 and is expected to be

complete by June of 1998. The

recommended staffing level was a result

of a detailed and in-depth analysis that

evaluated all of Western’s processes and

recommended the most effective and

efficient staffing levels to meet

Western’s needs. Any variation from

those levels would require another indepth analysis. Western will continue to

evaluate all processes for continuous

improvement and will make

adjustments to staffing levels as

necessary to meet changing

requirements.

Issue: A customer commented a

review of the cost allocation of the

Conservation and Renewable Energy

Program costs be conducted and that

these costs are not transmission related

and should be allocated to generation.

Response: It is intended the allocation

of the Conservation and Renewable

Energy Program be reviewed during the

next rate process.

Issue: A customer suggested that

Western review the methodology used

to allocate multiproject costs and

general Western administration costs.

Furthermore, another customer

commented that FTE data should be

based on actual staff levels, not

authorized positions, and where

possible, the use of direct allocations to

responsible projects.

Response: The methodology for

allocating multiproject costs was

published in a report developed in

cooperation with the DSW customers. A

meeting was held with DSW customers

in March 1997 to review the

methodology for allocating multiproject

costs. During that meeting, minor

adjustments to the methodology were

recommended and are in the process of

being implemented. Western will

continue to review the methodology to

seek improvements. Any changes to the

methodology will be done in a joint

customer forum.

The method for distributing general

Western administration costs is a

Western-wide methodology that was

implemented after a review of Western’s

operations by the firm of Deloitte and

Touche. Any change to this
63156 Federal Register / Vol. 62, No. 228 / Wednesday, November 26, 1997 / Notices

methodology would require

involvement of all offices throughout

Western, and involvement of Western’s

auditors.

Issue: A customer commented on a

recent disclosure by Western that

certain pension costs may be included

in future rate processes and is of the

opinion that these costs not be included

for repayment unless legislatively

mandated.

Response: Western will record the

costs for pension and health benefits in

the 1997 financial statements. However,

the inclusion of these costs in the PRS

will depend upon the outcome of a final

decision on Western’s legal authority to

include these costs in the rate base.

Issue: A customer commented about

waiting for several years for

Reclamation’s commitment to develop a

10-year planning process for ParkerDavis.

Response: Reclamation has begun to

develop and implement its 10-year

planning process for the Parker-Davis

Project and intends for it to be a useful

and beneficial process for obtaining

customer comments and feedback.

Issue: A customer commented on the

need to review the program function of

the PRS and on the possibility of

developing a more efficient tool for

implementing the PRS function.

Response: Western remains open to

implementing more efficient and

effective processes in the best interests

of the customers. Continual

improvement of the PRS program is a

goal and customer feedback is always

welcome. In the forthcoming fiscal year,

Western will once again look for ways

to implement changes to the PRS

program that provides for more efficient

output.

Issue: A customer commented on the

potential for large rate swings from year

to year now that the rates for the ParkerDavis Project are being calculated on an

annual basis and no longer on a 5-year

average.

Response: The calculation of the rate

on an annual basis performs two very

critical functions. It allows for a

synchronization of the costs shown in

the Cost Apportionment Study with

those in the PRS and it enables Western

to perform an annual cost reconciliation

to the Cost Apportionment Study

without causing a divergence to the data

in the PRS. In order to mitigate potential

surprises to the customers in the 5-year

out period, Western will continue to

project the rates for those years thereby

allowing contractors to adequately

budget for those future costs or to

mitigate those costs by providing

feedback through Western and

Reclamation’s 10-year planning process.

Environmental Evaluation

In compliance with the National

Environmental Policy Act of 1969, 42

U.S.C. 4321 et seq.; Council on

Environmental Quality Regulations (40

CFR Parts 1500–1508); and DOE NEPA

Regulations (10 CFR Part 1021), Western

has determined this action is

categorically excluded from the

preparation of an environmental

assessment or an environmental impact

statement.

Executive Order 12866

DOE has determined this is not a

significant regulatory action because it

does not meet the criteria of Executive

Order 12866, 58 FR 51735. Western has

an exemption from centralized

regulatory review under Executive

Order 12866; accordingly, no clearance

of this notice by OMB is required.

Availability of Information

Information regarding this rate

adjustment, including PRSs, comments,

letters, memorandums, and other

supporting material made or kept by

Western for the purpose of developing

the power rates, is available for public

review in the Desert Southwest Regional

Office, Western Area Power

Administration, Office of the Assistant

Regional Manager for Power Marketing,

615 South 43rd Avenue, Phoenix,

Arizona 85009; and Office of the

Assistant Administrator for Power

Marketing Liaison, Room 8G–027, 1000

Independence Avenue SW.,

Washington, DC 20585.

Submission to Federal Energy

Regulatory Commission

The rate herein confirmed, approved,

and placed into effect on an interim

basis, together with supporting

documents, will be submitted to FERC

for confirmation and approval on a final

basis. Western is developing open

access tariffs consistent with FERC

Order No. 888 and intends to publish

short-term rates by November 1997, and

submit long-term rates to the FERC by

April 1, 1998.

Order

In view of the foregoing and pursuant

to the authority delegated to me by the

Secretary of Energy, I confirm and

approve on an interim basis, effective

November 1, 1997, Rate Schedules PD–

F6, PD–FT6, PD–FCT6, and PD–NFT6

for the Parker-Davis Project. The rate

schedule shall remain in effect on an

interim basis, pending Federal Energy

Regulatory Commission confirmation

and approval of it or a substitute rate on

a final basis, through September 30,

2002.

Dated: November 18, 1997.

Elizabeth A. Moler,

Deputy Secretary.

[Rate Schedule PD–F6; (Supersedes Schedule

PD–F5)]

Schedule of Rates for Wholesale Firm

Power Service

Effective: The first day of the first full

billing period beginning on or after

November 1, 1997, and remaining in

effect through September 30, 2002, or

until superseded, whichever occurs

first.

Available: In the marketing area

serviced by the Parker-Davis Project (P–

DP).

Applicable: To the existing wholesale

power customers for firm power service

supplied through one meter at one point

of delivery, unless otherwise provided

by contract.

Character and Conditions of Service:

Alternating current at 60 hertz, threephase, delivered and metered at the

voltages and points established by

contract.

Monthly Charge: Energy Charge. Each

Contractor shall be billed monthly an

energy charge. This charge is equal to

the Contractor’s monthly energy

entitlement multiplied by the Energy

Rate (rounded to the penny). The Energy

Rate shall be equal to 50 percent of the

Annual Revenue Requirement Allocated

to Generation divided by the sum of the

Annual Energy entitlement to the P–DP

Priority Use Power Contractors and the

Annual Energy entitlement to the P–DP

Firm Electric Service Contractors,

rounded to two decimal places.

Capacity Charge: Each Contractor

shall be billed monthly a capacity

charge. This charge is equal to the

Contractor’s Seasonal Billing Contract

Rate of Delivery (CROD) multiplied by

the Capacity Rate, rounded to the

penny. The Capacity Rate shall be equal

to 50 percent of the Annual Revenue

Requirement Allocated to Generation

divided by the sum of the Average

Monthly Billing CROD for the P–DP

Priority Use Power Contractors and P–

DP Firm Electric Service Contractors

that is then divided by 12, rounded to

the penny.

Transmission Charge. Each Contractor

shall be billed monthly a transmission

charge equal to the Contractor’s

Seasonal Billing Contract Rate of

Delivery (CROD) multiplied by the rate

calculated in accordance with PD–FT6,

rounded to the penny.

Billing of Excess Energy: For each

billing period in which there is excess

energy available, offered, and delivered

to the Contractor, such excess energy

purchases shall be billed at the Energy

Rate.
Federal Register / Vol. 62, No. 228 / Wednesday, November 26, 1997 / Notices 63157

Billing for Unauthorized Overruns:

For each billing period in which there

is a contract violation involving an

unauthorized overrun of the CROD,

energy, and/or transmission obligations,

such overruns shall be billed at 10 times

(1) the Energy Rate for energy overruns,

(2) the Capacity Rate for CROD

overruns, and (3) the P–DP Firm

Transmission Rate, then in effect as it

may be amended, for transmission

overruns.

For Transformer Losses: If delivery is

made at transmission voltage but

metered on the low-voltage side of the

substation, the meter readings will be

increased to compensate for transformer

losses as provided for in the contract.

For Power Factor: The customer will

normally be required to maintain a

power factor at all points of

measurement between 95-percent

lagging and 95-percent leading.

[Rate Schedule PD–FT6; (Supersedes

Schedule PD–FT5)]

Schedule of Rate for Firm Transmission

Service

Effective: The first day of the first full

billing period beginning November 1,

1997, and remaining in effect through

September 30, 2002, or until

superseded, whichever occurs first.

Available: Within the marketing area

served by the Parker-Davis Project (P–

DP).

Applicable: To existing firm

transmission service customers where

capacity and energy are supplied to the

P–DP system at points of

interconnection with other systems and

transmitted and delivered, less losses, to

points of delivery on the P–DP system

specified in the service contract.

Character and Conditions of Service:

Alternating current at 60 hertz, threephase, delivered and metered at the

voltages and points established by

contract.

Monthly Rate: Transmission Service

Charge: Each Contractor shall be billed

a dollar per kilowatt per year rate for

each kilowatt at the point of delivery,

established by contract, payable

monthly at a dollar per kilowatt per

month rate. The yearly rate is equal to

the Annual Revenue Requirement

Allocated to Transmission divided by

the Average Monthly Billing Contract

Rate of Delivery, rounded to the penny.

The monthly billing rate is equal to the

dollar per kilowatt per year rate divided

by 12, rounded to the penny.

Adjustments: For Reactive Power.

There shall be no entitlement to transfer

of reactive kilovoltamperes at delivery

points, except when such transfers may

be mutually agreed upon by contractor

and contracting officer or their

authorized representatives.

For Losses. Capacity and energy losses

incurred in connection with the

transmission and delivery of power and

energy under this rate schedule shall be

supplied by the customer in accordance

with the service contract.

Billing for Unauthorized Overruns.

For each billing period in which there

is a contract violation involving an

unauthorized overrun of the contractual

firm transmission obligations, such

overrun shall be billed at 10 times the

above rates.

[Rate Schedule PD–FCT6; (Supersedes

Schedule PD–FCT5)]

Schedule of Rate for Firm Transmission

Service of Salt Lake City Area

Integrated Projects Power

Effective: The first day of the first full

billing period beginning on or after

November 1, 1997, and remaining in

effect through September 30, 2002, or

until superseded, whichever occurs

first.

Available: Within the marketing area

served by the Parker-Davis Project (P–

DP) transmission facilities.

Applicable: To existing Salt Lake City

Area Integrated Projects (SLCA/IP)

southern division customers where

SLCA/IP capacity and energy are

supplied to the P–DP system by the

Colorado River Storage Project (CRSP) at

points of interconnection with the CRSP

system and for transmission and

delivery on a unidirectional basis, less

losses, to southern division customers at

points of delivery on the P–DP system

specified in the service contract.

Character and Conditions of Service:

Alternating current at 60 hertz, threephase, delivered and metered at the

voltages and points of delivery

established by contract.

Monthly Rate: Transmission Service

Charge: Each Contractor shall be billed

a dollar per kilowatt per seasonal rate

for each kilowatt at the point of

delivery, established by contract,

payable monthly at a dollar per kilowatt

per month rate. The seasonal rate is

equal to the P–DP Firm Transmission

Rate then in effect as it may be amended

divided by 2, rounded to the penny. The

monthly billing rate is equal to the

dollar per kilowatt per season rate

divided by six, rounded to the penny.

Adjustments: For Reactive Power.

There shall be no entitlement to transfer

of reactive kilovoltamperes at delivery

points, except when such transfers may

be mutually agreed upon by contractor

and contracting officer or their

authorized representatives.

For Losses. Capacity and energy

losses incurred in connection with the

transmission and delivery of power and

energy under this rate schedule shall be

supplied by the customer in accordance

with the service contract.

Billing for Unauthorized Overruns.

For each billing period in which there

is a contract violation involving an

unauthorized overrun of the contractual

firm transmission obligations, such

overrun shall be billed at 10 times the

above rates.

[Rate Schedule PD–NFT6; (Supersedes

Schedule PD–NFT5)]

Schedule of Rate for Nonfirm

Transmission Service

Effective: The first day of the first full

billing period beginning on or after

November 1, 1997, and remaining in

effect through September 30, 2002, or

until superseded, whichever occurs

first.

Available: Within the marketing area

serviced by the Parker-Davis Project (P–

DP) transmission facilities.

Applicable: To existing nonfirm

transmission service customers where

capacity and energy are supplied to the

P–DP system at points of

interconnection with other systems,

transmitted subject to the availability of

the transmission capacity, and delivered

on a unidirectional basis, less losses, to

points of delivery on the P–DP system

specified in the service contract.

Character and Conditions of Service:

Alternating current at 60 hertz, threephase, delivered and metered at the

voltages and points of delivery

established by contract.

Monthly Rate: Nonfirm Transmission

Service Charge: Each Contractor shall be

billed monthly a mills per kilowatthour

rate of scheduled or delivered

kilowatthours at point of delivery,

established by contract, payable

monthly. This rate is equal to P–DP

Firm Transmission dollar per kilowattyear rate then in effect as it may be

amended divided by (8,760 multiplied

by 0.60) multiplied by 1,000, rounded to

two decimal places.

Adjustments: For Reactive Power.

There shall be no entitlement to transfer

of reactive kilovoltamperes at delivery

points, except when such transfers may

be mutually agreed upon by contractor

and contracting officer or their

authorized representatives.

For Losses. Capacity and energy

losses incurred in connection with the

transmission and delivery of power and

energy under this rate schedule shall be

supplied by the customer in accordance

with the service contract.

[FR Doc. 97–31074 Filed 11–25–97; 8:45 am]

BILLING CODE 6450–01–P