Parker-Davis Project Rate Adjustment; Notice of Rate Order No. WAPA-75

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places it into effect on a final basis or until superseded.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schedule is superseded.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:

[[Page 63151]]

Comparison of Existing Rates and Proposed Rate Methodology Rates

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

Existing Rate Proposed Rate

(FY 1995) (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. Sec. 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. Sec. 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. Sec. 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 long-term 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.

Sec. 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. Sec. 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. Sec. 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.

[[Page 63152]]

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

[[Page 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

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

Provisional

Existing Rate Rate (FY 1998) Percent Change

(FY 1995) \1\ (%)

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

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

[[Page 63154]]

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 Provisional

Rate PRS Rate PRS Difference

1996-2000 1998-2002

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

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

[[Page 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 in-depth

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

[[Page 63156]]

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

Parker-Davis.

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 Parker-Davis 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, three-phase, 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.

[[Page 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, three-phase, 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, three-phase, 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, three-phase, 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 kilowatt-year 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