Parker-Davis ProjectNotice of Rate Order No. WAPA-68

DEPARTMENT OF ENERGY

Western Area Power Administration

Parker-Davis Project--Notice of Rate Order No. WAPA-68

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Rate Order--Parker-Davis Project Firm Electric

Service Rate and Firm and Non-Firm Transmission Rate Adjustments.

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

SUMMARY: Notice is given of the confirmation and approval by the Deputy

Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-68

and Rate Schedules PD-F5, PD-FT5, PD-NFT5, and PD-FCT5 placing

decreased firm power rates for capacity and energy and decreased firm

and non-firm transmission rates from the Parker-Davis Project (P-DP) of

the Western Area Power Administration (Western) into effect on an

interim basis. The interim rates, called the provisional rates, will

remain in effect on an interim basis until the Federal Energy

Regulatory Commission (FERC) confirms, approves, and places them into

effect on a final basis, or until they are replaced by other rates.

Western is requesting approval to place into effect a rate decrease

in the firm power rates for capacity and energy and a rate decrease for

firm and nonfirm transmission service from the P-DP. Four major changes

are affecting the rates for the P-DP system

The first change is in the costs apportionment study. This change

was suggested by the P-DP customers and was a collaborative effort

between all of Western's P-DP customers, Western and the Bureau of

Reclamation (Reclamation). The new costs apportionment study more

accurately allocates the P-DP's total power related costs and revenue

between generation and transmission. In the previous

[[Page 53779]]

ratesetting study for Step Two rates, the apportionment percentages

between generation and transmission were approximately 26 percent and

74 percent, respectively. Based upon a reallocation of these costs, the

appointment percentages between generation and transmission are

approximately 16 percent and 84 percent, respectively.

The second change concerns the ratesetting methodology. This change

has also been made in response to questions and concerns voiced by

Western's P-DP customers. Previously, rates were set using the

traditional pinch-point methodology, where 50 years of data was

analyzed and rates were based on the year in which the revenue

requirement was the highest. Under the proposed methodology, revenue

requirements are determined for the next five years. In addition, a

compound interest amortization schedule is prepared for all

investments, including replacements, thus ensuring project repayment.

By October 1 of each year, new rates for the following five year period

will be determined and implemented.

The third change concerns the determination of interest offsets. An

interest offset is a credit that is made toward interest expense.

Western has decided to handle interest offsets consistently with the

other Federal power marketing administrations. The main difference

between the new method and the old method is that the old method

calculated interest offsets on only the principal that was repaid in

the current year. The new method calculates interest offsets on both

principal and interest for the current year.

The final change is in the area of cost containment. Western and

its customers have participated in many collaborative, or partnership,

efforts since the last P-DP rate process. Western has significantly

increased its customer's input into its engineering and future

construction program, its maintenance activities, and in its financial

planning and budget planning activities. This collaborative effort has

resulted in a significant decrease in both future operation and

maintenance expenses and capital expenses.

A comparison of existing and provisional rates follows:

Comparison of Existing and Provisional Power and Transmission Rates

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

Step 2 of the existing rates

October 1, 1995, through January Proposed rates October 1, 1995\1\ Percent

31, 1999 change

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

Composite Rate\2\ (mills/kWh) 12.01............................ 6.33............................. -47.29

Firm Capacity Charge ($/kW/ $2.63............................ $1.92............................ -27.00

month) PD-F5.

Firm Energy Charge (mills/ 6.01............................. 1.95............................. -67.55

kWh) PD-F5.

Firm Transmission Service ($/ $12.55........................... $11.51........................... -8.29

kW/year) PD-FT5.

Nonfirm Transmission Service 2.39............................. 2.19............................. -8.37

(mills/kWh) PD-NFT5.

Transmission Service for SLCA/ $6.27 per kW-Season.............. $5.76 per kW-Season.............. -8.13

IP PD-FCT5.

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

\1\A new rate will be determined each year on September 1, based upon the proposed new ratesetting methodology.

These rates represent FY 1996 only.

\2\The Composite Rate is the total of the Firm Capacity Charge, the Firm Energy Charge and the Firm Transmission

Service, all expressed on a mills/kWh basis.

DATES: Rate Schedules PD-F5, PD-FT5, PD-FCT5, and PD-NFT5 will be

placed into effect on an interim basis on the first day of the first

full billing period beginning on or after October 1, 1995, and will be

in effect until FERC confirms, approves, and places the rate schedules

into effect on a final basis for a five year period, or until the rate

schedules are superseded.

FOR FURTHER INFORMATION CONTACT:

Mr. J. Tyler Carlson, Area Manager, Phoenix Area Office, Western Area

Power Administration, P.O Box 6457, Phoenix, AZ 85005-6457, (602) 352-

2453

Ms. Deborah M. Linke, Acting Director, Division of Power Marketing,

Western Area Power Administration, P.O Box 3402, Golden CO 80401-0098,

(303) 275-1610

Mr. Joel K. Bladow, Assistant Administrator for Washington Liaison,

Western Area Power Administration, Room 8G-027, Forrestal Building,

1000 Independence Avenue, SW., Washington, DC 20585-0001, (202) 586-

5581

SUPPLEMENTARY INFORMATION: 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 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 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.

Most of the comments received at the public meetings and in

correspondence dealt with purchase power costs, comparability issues

with the recently announced FERC notice of proposed rulemaking

concerning open access non-discriminatory transmission service, the new

rate methodology and Reclamation's working capital improvement process.

Rate Order No. WAPA-68, confirming, approving, and placing the

proposed P-DP rate adjustments into effect on an interim basis, is

issued, and the new Rate Schedules PD-F5, PD-FT5, PD-FCT5, and PD-NFT5

will be submitted promptly to FERC for confirmation and approval on a

final basis.

[[Page 53780]]

Issued in Washington, DC, September 29, 1995.

Charles B. Curtis,

Deputy Secretary.

Department of Energy--Deputy Secretary

In the matter of: Western Area Power Administration, Rate

Adjustment for Parker-Davis Project. Rate Order No. WAPA-68.

Order Confirming, Approving, and Placing the Parker-Davis Project Firm

Power Service Rate, Firm Transmission Service Rate, Nonfirm

Transmission Service Rate and Transmission Service for the Salt Lake

City Area/Integrated Projects Into Effect on an Interim Basis

October 1, 1995.

These power 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 of Energy (Secretary).

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 (FERC). 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:

$/kW/month: Monthly charge for capacity (usage--$ per kilowatt per

month).

Costs 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.

EA: Environmental assessment.

EIS: Environmental impact statement.

FERC: Federal Energy Regulatory Commission.

FY: Fiscal year.

Interior: U.S. Department of the Interior.

kW: Kilowatt.

KW/month: The greater of (1) the highest 30-minute demand measured

during the month, not to exceed the contract obligation, or (2) the

contract rate of delivery.

kWh: Kilowatthour.

mills/kWh: Mills per kilowatthour.

MW: Megawatt.

NEPA: National Environmental Policy Act of 1969.

NOPR: Notice of Proposed Rulemaking.

O&M: Operation and maintenance.

P-DP: Parker-Davis Project.

pinch-point The FY in which the level of the rate is set as dictated by

a revenue requirement in some future year to meet relatively large

annual costs or to repay investments which come due.

PAO: Western's Phoenix Area Office.

PMA: Power marketing administration.

Proposed Rate: A rate revision 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.

Reclamation: Bureau of Reclamation, U.S. Department of the Interior.

Replacements: A unit of property constructed or acquired as a

substitute for an existing unit of property for the purpose of

maintaining the power features of a project or the joint features

properly allocated to power.

SLCA/IP: Salt Lake City Area/Integrated Projects.

Western: Western Area Power Administration, U.S. Department of Energy.

Effective Date

The new rates and rate methodology will become effective on an

interim basis on the first day of the first full billing period

beginning on or after October 1, 1995, and will be in effect pending

FERC's approval of them or substitute rates on a final basis for a five

year 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 the development of the firm power rate, firm transmission

rate, and nonfirm transmission rate. The provisional firm power rate,

firm transmission rate, and nonfirm transmission rate will cause more

than a 1 percent change in total P-DP power revenues; therefore, it is

a major rate adjustment as defined at 10 CFR Secs. 903.2(e) and

903.2(f)(1). The distinction between a minor and a major rate

adjustment is used only to determine the public procedures for the rate

adjustment.

The following summarizes the steps Western took to ensure

involvement of interested parties in the rate process:

1. Discussion of the proposed rate adjustment was initiated on

February 16, 1995, when a letter announcing an informal customer

meeting was mailed to all firm power customers, firm and nonfirm

transmission customers, and other interested parties. The informal

customer meeting was held on February 22, 1995, in Phoenix, Arizona. At

this informal meeting, Western and Reclamation Representatives

explained the need for the rate adjustments and answered questions for

those attending.

2. A Federal Register notice was published on March 21, 1995 (60 FR

14935), 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.

3. On March 29, 1995, letters were mailed from PAO 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

March 1995. The Rate Brochure also included a copy of the Federal

Register notice of March 21, 1995.

4. At the public information forum on April 5, 1995, Western and

Reclamation representatives explained the need for the rate adjustments

in greater detail and answered additional questions.

5. The public comment forum was held on May 15, 1995, to give the

customers and interested parties an opportunity to comment for the

record. Five persons, representing customers and customer groups, made

oral comments.

6. On June 22, 1995, a letter was mailed to all P-DP customers and

interested parties with copies of an updated PRS and rate design

spreadsheets.

[[Page 53781]]

7. A Federal Register notice was published on July 6, 1995 (60 FR

35199), extending the consultation and comment period until July 12,

1995.

8. Eight comment letters were received during the 114-day

consultation and comment period which ended July 12, 1995. 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). 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).

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, 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 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 the state of Arizona. Reservoir

operation is limited to minor storage fluctuations. The dam provides a

head of approximately 75 feet for 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. MWD is

entitled, under current contract, to one-half of the net energy

generated by Parker Powerplant at any given time.

Davis Dam, which created Lake Mohave, provides regulation, both

hourly and seasonally, of water releases from lake Mead (through Hoover

Dam and Powerplant) to 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.

All facilities of the P-DP were operated and maintained by

Reclamation until the formation of the DOE pursuant to the DOE

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 DOE. The responsibility for operation and

maintenance of the dams and powerplants remains with Reclamation.

Power Repayment Studies

PRS's are prepared each fiscal year to determine if power revenues

will be sufficient to pay, 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 existing and provisional rates follows:

Comparison of Existing and Provisional Power and Transmission Rates

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

Step 2 of the existing rates

October 1, 1995, through January Proposed rates October 1, 1995\1\ Percent

31, 1999 change

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

Composite Rate\2\ (mills/kWh) 12.01............................ 6.33............................. -47.29

Firm Capacity Charge ($/kW/ $2.63............................ $1.92............................ -27.00

month) PD-F5.

Firm Energy Charge (mills/ 6.01............................. 1.95............................. -67.55

kWh) PD-F5.

Firm Transmission Service ($/ $12.55........................... $11.51........................... -8.29

kW/year) PD-FT5.

Nonfirm Transmission Service 2.39............................. 2.19............................. -8.37

(mills/kWh) PD-NFT5.

Transmission Service for SLCA/ $6.27 per kW/season.............. $5.76 per kW/season.............. -8.13

IP PD-FCT5.

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

\1\A new rate will be determined each year on September 1, based upon the proposed new ratesetting methodology.

These rates represent FY 1996 only.

\2\The Composite Rate is the total of the Firm Capacity Charge, the Firm Energy Charge and the Firm Transmission

Service, all expressed on a mills/kWh basis.

Certification of Rate

Western's Administrator has certified that the P-DP firm power

rate, firm transmission rate, nonfirm transmission rate, and the

transmission service for SLCA/IP rate, placed into effect on an interim

basis herein are the lowest possible consistent with sound business

principles. The rates have been developed in accordance with

administrative policies and applicable laws.

Discussion

Western is requesting approval to place into effect a rate decrease

in the

[[Page 53782]]

firm power rates for capacity and energy and a rate decrease for firm

and nonfirm transmission service from the P-DP of the Western Area

Power Administration on an interim basis. Four major changes are

affecting the rates for the Parker-Davis system.

The first change is in the costs apportionment study. This change

was suggested by the P-DP customers and was a collaborative effort

between all of Western's P-DP customers, Western and Reclamation. Since

the last rate adjustment process, Western has worked with the customers

to develop a revised costs apportionment study which can be described

in four steps.

1. All costs, including Western's O&M expenses, Reclamation

expenses, purchase power costs, multi-project costs associated with

Mead Service Center, interest expenses, and principal payments were

allocated to either generation or transmission. Each component was

allocated based on whether it was directly related to generation or

transmission. If a component was related to both, a customer allocation

factor based on the number of customers was used to separate costs

between generation and transmission.

2. All revenues, including nonfirm transmission, nonfirm energy,

fuel replacement, spinning reserves, facility use charges, and multi-

project revenues associated with SCADA and the Phoenix Service Center

were allocated to either generation or transmission. Each component was

allocated based on whether it was directly related to generation or

transmission. If a component was related to both, a customer allocation

factor was used to separate other sources of revenues between

generation and transmission.

3. Project use costs for both generation and transmission were

compared to the anticipated revenue of $1.2 million. The difference

between the project use costs and the anticipated revenues was

allocated to the generation and transmission customers. This allocation

was based on the ratio of project use generation costs to project use

transmission costs.

4. Final percentages of costs associated with generation and costs

associated with transmission were derived.

The new costs apportionment study more accurately allocates the P-

DP's total power related costs and revenue between generation and

transmission. In the previous ratesetting study for Step Two rates, the

apportionment percentages between generation and transmission were

approximately 26 percent and 74 percent, respectively. Based upon a

reallocation of these costs, the new apportionment percentages between

generation and transmission are approximately 16 percent and 84

percent, respectively.

The second change concerns the ratesetting methodology. This change

has also been made in response to questions and concerns voiced by

Western's P-DP customers. Previously, rates were set using the

traditional pinch-point methodology, where 50 years of data was

analyzed and rates were based on the year in which the revenue

requirement was the highest. Under the proposed methodology, revenue

requirements are determined for the next five years. In addition, a

compound interest amortization schedule is prepared for all

investments, including replacements, thus ensuring project repayment.

By October 1 of each year, new rates for the following five year period

will be determined and implemented.

Under the previous pinch-point methodology, 50 years of data were

analyzed and the rate was based on the year in which the highest

revenue requirement was encountered. This methodology used a priority

of repayment which first applied annual revenues to operation and

maintenance expenses, purchased power expenses, interest, and then to

required annual principal payments. Any excess annual revenue was then

applied toward principal owed to the Federal Treasury. Under the new

repayment methodology, Western first determines an amortization

schedule of all existing and future investments. This includes both a

principal component and an interest component. Western then adds this

annual amortization amount to operation and maintenance expenses,

purchase power expenses, and other annual expenses to determine the

total annual revenue requirements over the next five years. An average

revenue requirement and an average rate are than calculated for the

five year period. Revenues collected that are in excess of the annual

revenue requirement are carried forward to the next year and are

utilized to cover revenue shortfalls in future years. This new

methodology, while relying on a five year rate setting period instead

of 50 years, provides for guaranteed payment of all costs within the

five year rate setting window and establishes a guaranteed methodology

concerning repayment of principal, thus ensuring total repayment of the

project within its prescribed time period.

RA 6120.2 states that revenues remaining after paying for annual

expenses shall be used to repay the Federal investment. Under the new

ratesetting methodology, repayment of the Federal investment will

become a component of the total annual expenses and will be made on an

annual basis through a compound interest amortization payment. Any

excess revenues remaining after the payment of total annual expenses

will be carried forward to the following operating year to be applied

toward annual expenses.

The third change concerns the determination of interest offsets. An

interest offset is a credit that is made toward interest expense.

Western has decided to handle interest offsets consistent with the

other Federal power marketing agencies. The main difference between the

new method and the old method is that the old method calculated

interest offsets on only the principal that was repaid in the current

year. The new method calculates interest offsets on both principal and

interest for the current year.

The final change is in the area of cost containment. Western and

its customers have participated in many collaborative, or partnership,

efforts since the last P-DP rate process. Western has significantly

increased its customer's input into its engineering and future

construction program, its maintenance activities, and in its financial

planning and budget planning activities. This collaborative effort has

resulted in a significant decrease in both future operation and

maintenance expenses and capital expenses.

Since the last P-DP rate process was concluded, Western and the

customers have worked quite closely in a partnership process to

implement a coordinated 10-year engineering and construction plan

process. This process annually generates a 10-Year Engineering and

Construction plan, which is issued in October of each year. This

process is also integrated with Western's rates and budgeting processes

to (1) provide certainty to the customers that all of Western's

processes are operating from the same financial base and (2) provide

the customers with the maximum input possible into the financial

decisions that are reflected in the rates paid by the customers. This

process has resulted in considerable changes both in the way Western

does business and in the amount of future expenditures Western will be

committing on behalf of its customers.

Power Sales Revenue Requirements

A comparison of the power sales revenue requirements estimated for

1996 and the existing 1996 power sales revenue requirements are noted

in the table below.

[[Page 53783]]

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

Estimated 1996 revenue

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

Existing Proposed

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

Power Sales Revenue Requirements.... \1\$42,011,732 \2\$28,521,763

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

\1\From the Parker-Davis Project Rate Design Worksheet for WAPA-55, Step

2.

\2\From the Parker-Davis Project Rate Design Worksheet for WAPA-68.

The rate decrease satisfies the cost-recovery criteria set forth in

DOE Order RA 6120.2.

Statement of Revenue and Related Expenses

The following table provides a summary of revenue and expense data

through the 5-year Provisional Rates approval period.

Parker-Davis Project Comparison of 5-Year Rate Period Revenues and

Expenses

[In thousands of dollars]

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

Current

Provisional step 2

ratesetting proposed

(FY 1996) rate (FY Difference

PRS 1996- 1995) PRS

2000 1996-2000

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

Total Revenues\1\................ 180,212 210,401 30,189

Revenue Distribution:

O&M.......................... 114,874 123,095 8,221

Purchased Power.............. 4,500 1,400 -3,100

Other........................ 1,017 2,891 1,874

Interest..................... 56,452 66,130 9,678

Investment Repayment......... 3,014 13,113 10,099

Capitalized Expenses......... 355 3,772 3,417

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

Total...................... 180,212 210,401 30,189

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

\1\Total Revenues includes revenues from all sources. Total Revenues for

the Provisional ratesetting PRS also includes excess revenues from the

previous year.

Basis for Rate Development

The rates were designed using a cost apportionment study. The study

was based upon the separation of costs between generation and

transmission. As a result of the study, 84 percent of the P-DP costs

are to be recovered from the firm transmission customers, while the

remaining 16 percent of the costs are to be recovered from firm power

customers. The rate design consists of five steps.

1. Required revenue is derived in the proposed PRS for the period

1996 through 2000.

2. The percentages from the Costs Apportionment Study for

generation and transmission are applied to the total revenue

requirements in step one above. This determines the required revenue

for generation and the required revenue for the transmission system.

3. The firm transmission rate is developed by dividing the required

revenue for transmission by the total transmission sales. Total

transmission sales includes firm transmission service and firm electric

service.

4. The transmission rate is applied to the sales for firm

transmission service to determine transmission revenues.

5. The demand and energy components of the power rate are then

calculated. The demand component is calculated by (i) first multiplying

the firm transmission rate by the maximum firm electric service kW

sales, (ii) adding 50 percent of the required revenue for generation

and then (iii) dividing this total revenue requirement by the average

firm electric service kW sales.

The energy component is determined by dividing 50 percent of the

generation revenue requirements by the total firm electric service kWh

sales.

The composite rate is determined by adding the revenue requirements

associated with demand and the revenue requirements associated with

energy and dividing by the total firm electric kWh sales.

The SLCA/IP rate is determined by dividing the firm transmission

service rate in half, to determine the seasonal rate.

Comments

During the 114-day comment period. Western received eight written

comments either requesting additional information or commenting on the

rate adjustment. In addition, five persons provided oral comments

during the May 15, 1995, public comment forum. All comments were

reviewed and considered in the preparation of this rate order.

Written comments were received from the following sources:

Arizona Public Service Company (Arizona)

Salt River Project (Arizona)

Maricopa Water District (Arizona)

Ak-Chin Indian Community (Arizona)

Irrigation & Electrical Districts Association of Arizona (Arizona)

Tonopah Irrigation District (Arizona)

Overton Power District No. 5, Valley Electric Association, Inc.

(Nevada)

Arizona Power Authority--R.W. Beck (Arizona)

Representatives of the following organizations made oral comments:

Overton Power District No. 5, Valley Electric Association, Inc.

(Nevada)

Arizona Power Authority (Arizona) (two commenters)

Salt River Project (Arizona)

Irrigation & Electric District Association of Arizona (Arizona)

Most of the comments received at the public meetings and in

correspondence dealt with purchase power costs, comparability issues

with the recently announced FERC notice of proposed rulemaking

concerning open access non-discriminatory transmission service, new

rate methodology, and Reclamation's working capital improvement

process.

[[Page 53784]]

Issue: Some customers expressed concern about purchase power costs

that have been incurred in the past, especially in unusual flood years,

such as occurred in 1993. Western was forced into a position of buying

power to replace lost generation when the customers did not need

replacement power. How do we handle this hydrologic condition so it

doesn't happen again?

Response: Western shares the customers' concern that this

hydrologic condition could occur again. In the near future, Western

will set up a working group to examine how to keep purchase powers

costs from occurring under these particular conditions. Western looks

forward to working with its customers on this issue.

Issue: Customers would like Western to determine what would be

required of Western should FERC finalize its notice of proposed

rulemaking (NOPR) on the comparability issue.

Response: Presently, Western has several working groups set up to

determine what would be required of Western should the FERC NOPR become

final. This is a Western-wide issue. Once the requirements on

comparability are determined and Western determines how it will

voluntarily adhere to such requirements, such information will be made

available to all customers and interested parties.

Issue: Customers would like Reclamation to continue to commit to

enter into a 10-year planning process related to costs and expenditures

of the Parker-Davis Project.

Response: Reclamation has verbally committed to continue to work

with the customers on a 10-year planning process related to its

operations and maintenance expenses.

Issue: The customers support the compound interest amortization

process and commend Western for implementation of this item in the PRS.

Response: Western acknowledges the customer's support and looks

forward to working with customers on other process improvement issues.

Issue: One transmission customer requested that the 11.5 percent

increase for the firm transmission rate be phased in using a two-step

process.

Response: Western received only one comment pertaining to phasing

in the firm transmission rate. While the provisional firm transmission

rate of $11.51/kW-yr is 10.67 percent higher than the existing Step 1

rate of $10.40/kW-yr, it is 8.29 percent lower than the existing Step 2

rate previously proposed to go into effect October 1, 1995. Western

believes that a phase in of the rate will not be necessary.

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 that this action is categorically excluded from

the preparation of an environmental assessment or an environmental

impact statement.

Executive Order 12866

DOE has determined that 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 Office of Management and Budget is required.

Availability of Information

Information regarding this rate adjustment, including PRSs,

comments, letters, memorandums, and other supporting material made by

or kept by Western for the purpose of developing the power rates, is

available for public review in the Phoenix Area Office, Western Area

Power Administration, Office of the Assistant Area Manager for Power

Marketing, 615 South 43rd Avenue, Phoenix, Arizona 85009; Western Area

Power Administration, Division of Power Marketing, 1627 Cole Boulevard,

Golden, Colorado 80401; and Western Area Power Administration, Office

of the Assistant Administrator for Washington Liaison, Room 8G-027,

Forrestal Building, 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.

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 October 1, 1995, Rate Schedules PD-F4, PD-FT4, PD-

FCT5, and PD-NFT5 for the P-DP. The rate schedule shall remain in

effect on an interim basis, pending the Federal Energy Regulatory

Commission confirmation and approval of it or a substitute rate on a

final basis, through September 30, 2000.

Issued in Washington, DC, September 29, 1995.

Charles B. Curtis,

Deputy Secretary.

Department of Energy--Western Area Power Administration; Parker-Davis

Project

Schedule of Rates for Wholesale Firm Power Service

[Rate Schedule PD-F5 Supersedes Schedule PD-F4]

Effective: The first day of the first full billing period beginning

on or after October 1, 1995, and remaining in effect through September

30, 2000, or until superseded, whichever occurs first.

Available: In the marketing area serviced by the Parker-Davis

Project (P-DP).

Applicable: To the 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 Rate: October 1, 1995:

Demand Charge: $1.92 per kilowatt of billing demand.

Energy Charge: 1.95 mills per kilowatthour of use.

Billing Demand: The billing demand will be the greater of (1) the

highest 30-minute integrated demand measured during the month up to,

but not in excess of, the delivery obligation under the power sales

contract, or (2) the contract rate of delivery.

October 1, 1996, through September 20, 2000:

By October 1 of each year, a new rate for the following 5-year

period will be determined and implemented as described in the rate

design section of the rate order WAPA-68.

Billing for Unauthorized Overruns: For each billing period in which

there is a contract violation involving an unauthorized overrun of the

contractual firm capacity and/or energy obligations, such overruns

shall be billed at 10 times the above rate.

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: None. The customer will normally be required to

maintain a power factor at all points of measurement between 95-percent

lagging and 95-percent leading.

[[Page 53785]]

Department of Energy--Western Area Power Administration; Parker-Davis

Project

[Rate Schedule PD-FT5 (Supersedes Schedule PD-FT4)]

Schedule of Rate for Firm Transmission Service

Effective: The first day of the first full billing period beginning

October 1, 1995, and remaining in effect through September 30, 2000, or

until superseded, whichever occurs first.

Available: Within the marketing area served by the Parker-Davis

Project (P-DP).

Applicable: To 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: October 1, 1995:

Transmission Service Charge: $11.51 per kilowatt per year for each

kilowatt at the point of delivery, established by contract, payable

monthly at the rate of $0.96 per kilowatt.

October 1, 1996, through September 30, 2000:

By October 1 of each year, a new rate for the following 5-year

period will be determined and implemented as discussed in the rate

design section of the rate order WAPA-68.

For Reactive Power: None. There shall be no entitlement to transfer

of reactive kilovolt-amperes at delivery points, except when such

transfer 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 power and/or energy obligations, such overrun shall be

billed at 10 time the above rate.

Department of Energy--Western Area Power Administration; Parker-Davis

Project

[Rate Schedule PD-FCT5 (Supersedes Schedule PD-FCT4)]

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 October 1, 1995, and remaining in effect through September

30, 2000, or until superseded, whichever occurs first.

Available: Within the marketing area served by the Parker-Davis

Project (P-DP) transmission facilities.

Applicable: To 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: October 1, 1995:

Transmission Service Charge: $5.76 per kilowatt per season for each

kilowatt at the point of deliver, established by contract.

October 1, 1996, through September 30, 2000:

By October 1 of each year, a new rate for the following 5-year

period will be determined and implemented as discussed in the rate

design section of the rate order WAPA-68.

For Reactive Power: None. There shall be no entitlement to transfer

of reactive kilovolt-amperes 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 power and/or energy obligations, such overrun shall be

billed at 10 times that above rate.

Department of Energy--Western Area Power Administration; Parker-Davis

Project

[Rate Schedule PD-NFT5 (Supersedes Schedule PD-NFT4]

Schedule of Rate for Nonfirm Transmission Service

Effective: The first day of the first full billing period beginning

on or after October 1, 1995, and remaining in effect through September

30, 2000, or until superseded, whichever occurs first.

Available: Within the marketing area serviced by the Parker-Davis

Project (P-DP) transmission facilities.

Applicable: To 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: October 1, 1995:

Nonfirm Transmission Service Charge: 2.19 mills per kilowatthour of

scheduled or delivered kilowatthours at point of delivery, established

by contract, payable monthly.

October 1, 1996, through September 30, 2000:

By October 1 of each year, a new rate for the following 5-year

period will be determined and implemented as discussed in the rate

design section of the rate order WAPA-68.

For Reactive Power: None. There shall be no entitlement to transfer

of reactive kilovolt-amperes 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. 95-25686 Filed 10-16-95; 8:45 am]

BILLING CODE 6450-01-M