Central Valley Project Notice of Rate Order No. WAPA-72

DEPARTMENT OF ENERGY

Western Area Power Administration

Central Valley Project Notice of Rate Order No. WAPA-72

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of Rate Order--Central Valley Project commercial firm

power rate adjustment.

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

Secretary of the Department of Energy (DOE) of Rate Order No. WAPA-72

and Rate Schedule CV-F8 placing provisional commercial firm power rates

for capacity and energy from the Central Valley Project (CVP) of the

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

basis. 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.

The commercial firm power rates will provide sufficient revenue to

pay all annual costs including interest expense, plus repayment of

required investment within the allowable time period. These rates

consist of a capacity rate, energy base rate, and energy tier rate. The

energy tier rate is applied to energy at a 70 percent and higher load

factor, and is based on the average CVP Northwest energy rate. The load

factor is computed based on the lesser of the customer's (1) maximum

demand for the month, or if a scheduled customer, the maximum scheduled

demand for the month; or (2) the customer's Contract Rate of Delivery

(CRD) for commercial firm power.

A comparison of existing and provisional rates follows:

Comparison of Existing and Provisional Rates

[Commercial Firm Power Rate Schedule]

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

Effective period Existing Provisional Percent Change

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

Composite Rate (mills/kWh):

10/01/95 to 09/30/96..................................... 31.55 23.35 (26)

10/01/96 to 09/30/97..................................... 31.55 25.00 (21)

10/01/97 to 04/30/98..................................... 34.37 26.50 (23)

Capacity Rate ($/kW/month):

10/01/95 to 09/30/96..................................... 6.57 4.03 (39)

10/01/96 to 09/30/97..................................... 6.57 4.32 (34)

10/01/97 to 04/30/98..................................... 7.16 4.58 (36)

Energy Base Rate (mills/kWh):

10/01/95 to 09/30/96..................................... 17.73 14.83 (16)

10/01/96 to 09/30/97..................................... 17.73 15.93 (10)

10/01/97 to 04/30/98..................................... 19.33 16.93 (12)

Energy Tier Rate (mills/kWh):

10/01/95 to 09/30/96..................................... 34.70 25.90 (25)

10/01/96 to 09/30/97..................................... 34.70 26.27 (24)

10/01/97 to 04/30/98..................................... 37.46 26.48 (29)

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

[[Page 52672]]

DATES: Rate Schedule CV-F8 will be placed into effect on an interim

basis on October 1, 1995 and will be in effect until FERC confirms,

approves, and places the rate schedule in effect on a final basis for a

2\1/2\-year period, or until the rate schedule is superseded.

FOR FURTHER INFORMATION CONTACT:

Mr. James C. Feider, Area Manager, Sacramento Area Office, Western Area

Power Administration, 114 Parkshore Drive, Folsom, CA 95630, Telephone

(916) 353-4418

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

Power Marketing Liaison Office, Room 8G-027, Forrestal Building, 1000

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

586-5581

SUPPLEMENTARY INFORMATION: 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 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 are located at 10 CFR Part 903.

These power rates were developed pursuant to section 302(a) of the

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

involved, were transferred to and vested in the Secretary of Energy.

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 these commercial firm power rates. A

summary of the steps Western took to ensure involvement of interested

parties in the rate process follows:

1. The proposed rate adjustment was initiated on June 9, 1995, when

a letter announcing an informal customer meeting was mailed to all

commercial firm power customers and interested parties. The meeting was

held on June 26, 1995, in Sacramento, California. At this informal

meeting, Western explained the rationale for the rate decrease and rate

design methodology, and answered questions.

2. A Federal Register notice was published on July 10, 1995 (60 FR

35556), officially announcing the commercial firm power 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 July 17, 1995, letters were mailed from Western's Sacramento

Area Office to all commercial firm power customers and interested

parties transmitting the Federal Register notice of July 10, 1995.

4. On July 19, 1995, a rate brochure was mailed to all commercial

firm power customers and interested parties.

5. At the public information forum held on the morning of July 26,

1995, Western explained the rationale for the rate decrease and rate

design methodology in greater detail, and answered questions.

6. The comment forum was held on the afternoon of July 26, 1995, to

give the public an opportunity to comment for the record. Two customer

representatives made oral comments.

7. Eight comment letters were received during the consultation and

comment period. The consultation and comment period ended August 11,

1995. All formally submitted comments have been considered in the

preparation of this rate order.

Rate Order No. WAPA-72, confirming, approving, and placing the

proposed CVP commercial firm power rates into effect on an interim

basis, is issued, and the new Rate Schedule CV-F8 will be submitted

promptly to FERC for confirmation and approval on a final basis.

Issued in Washington, D.C., September 19, 1995.

Charles B. Curtis,

Deputy Secretary.

Order Confirming, Approving, and Placing the Central Valley Project

Commercial Firm Power Service Rates into Effect on an Interim Basis

September 19, 1995.

These power rates were developed 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 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 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; (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 are located at 10 CFR Part 903.

Acronyms and Definitions

As used in this rate order, the following acronyms and definitions

apply:

Composite rate:

Energy rate that recovers capacity and energy revenue requirements.

Contract 2948A:

Pacific Gas and Electric Company's contract with Western for the

sale, interchange and transmission of power; Contract No. 14-06-200-

2948A, as amended.

Corps:

United States Army Corps of Engineers.

CRD:

Contract rate of delivery. The maximum amount of capacity that

Western is contractually obligated to provide to a customer.

CVP:

Central Valley Project.

DOE:

Department of Energy.

DOE Order RA6120.2:

An order dealing with power marketing administration financial

reporting.

Energy base rate:

Energy rate applied to energy sales below a 70 percent monthly load

factor.

Energy component:

The component of this rate which sets forth the charges for energy.

It is expressed in mills/kWh and applied to each kWh made available to

each customer.

Energy tier rate:

Energy rate applied to energy sales at a 70 percent and higher

monthly

[[Page 52673]]

load factor.

FERC:

Federal Energy Regulatory Commission.

FY:

Fiscal year.

Intertie:

Pacific Northwest-Pacific Southwest Intertie.

kW:

Kilowatt (1000 watts).

kW/month:

Kilowatt per month.

kWh:

Kilowatthour.

Load factor:

The ratio of total energy delivered compared to the maximum energy

available during a specified period of time.

mills/kWh:

Mills per kilowatthour.

MW:

Megawatt (1000 kW).

NEPA:

National Energy Policy Act of 1969 (42 U.S.C. 4321 et seq.).

Northwest:

Northwest United States.

O&M:

Operation and maintenance.

PG&E:

Pacific Gas and Electric Company.

Power factor:

The ratio of real (kW) to apparent power (kVA) at any given point

and time in an electrical circuit. Generally it is expressed as a

percentage ratio.

PRS:

Power repayment study.

Provisional rates:

A rate which has been confirmed, approved, and placed in effect on

an interim basis by the Deputy Secretary.

RAC:

Revenue adjustment clause.

Rate brochure:

A document prepared for public distribution explaining the

rationale and background of the rate proposal contained in this rate

order dated July 1995.

Reclamation:

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

Revenue requirement:

The revenues required to recover O&M expenses, purchase power and

transmission service expenses, interest, deferred expenses, and Federal

investments.

Secretary:

Secretary of Energy.

Western:

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

Effective Date

The new rates 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 2\1/2\-year period ending

April 30, 1998, 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 these commercial firm power rates. The

following summarizes the steps Western took to ensure involvement of

interested parties in the rate process:

1. The proposed rate adjustment was initiated on June 9, 1995, when

a letter announcing an informal customer meeting was mailed to all

commercial firm power customers and interested parties. The meeting was

held on June 26, 1995, in Sacramento, California. At this informal

meeting, Western explained the rationale for the rate decrease and rate

design methodology, and answered questions.

2. A Federal Register notice was published on July 10, 1995 (60 FR

35556), officially announcing the commercial firm power 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 July 17, 1995, letters were mailed from Western's Sacramento

Area Office to all commercial firm power customers and interested

parties transmitting the Federal Register notice of July 10, 1995.

4. On July 19, 1995, a rate brochure was mailed to all customers

and interested parties.

5. At the public information forum held on the morning of July 26,

1995, Western explained the rationale for the rate decrease and the

rate design methodology in greater detail and answered questions.

6. The comment forum was held on the afternoon of July 26, 1995, to

give the public an opportunity to comment for the record. Two customer

representatives made oral comments.

7. Eight comment letters were received during the consultation and

comment period. The consultation and comment period ended August 11,

1995. All formally submitted comments have been considered in the

preparation of this rate order.

Project History

The CVP in the Central Valley Basin of California has twelve dams

that create reservoirs with a total capacity of 10.66 million acre-feet

of water. The CVP contains 615 miles of canals, five pumping plants,

and eleven powerplants.

The Emergency Relief Appropriations Act of 1935 initially

authorized the CVP to be constructed by Reclamation. In 1944, Congress

authorized the American River Division to be constructed by the Corps.

In 1949, the Division was reauthorized for integration into the CVP.

The Trinity River Division was authorized by Congress in 1955. The San

Luis Unit was authorized by Congress in 1960. In 1965, Congress

authorized construction of the Auburn-Folsom South Unit as an addition

to the CVP. Congress authorized the San Felipe Division in 1967, and

the Allen Camp Unit in 1976. In 1964, Congress authorized the Intertie,

of which the CVP has the right to use 400 MW of transmission capacity

to import power from the Pacific Northwest.

PG&E and Western operate under Contract 2948A, executed in 1967,

which provides for the sale, interchange, and transmission of capacity

and energy between Western and PG&E. Contract 2948A also includes

provisions for the integration of power generated from the CVP

facilities with the 400 MW of entitlement on the Intertie. The contract

also provides that PG&E will support a maximum simultaneous demand of

1,152 MW for the CVP preference customers through calendar year 2004.

If the CVP power facilities cannot meet obligations to the preference

customers, Contract 2948A provides Western the right to purchase

capacity and energy from PG&E to meet those requirements. Any energy in

excess of Western's obligations to preference customers can be sold to

PG&E through a banking provision in the contract. The energy made

available under this banking arrangement allows Western to supplement

CVP generation to meet preference customer load.

Power generated from the CVP system is first dedicated to meeting

the project pumping facilities' power requirements. The remaining power

generated at the power facilities is allocated to various preference

customers in California.

Each preference customer's CRD is composed of firm long-term power

allocations, and may include short-term withdrawable allocations that

are currently allocated, but unused by another customer. For this rate

adjustment it is assumed that all customer withdrawable CRDs can be

withdrawn in the event the load level of 1,152 MW is exceeded.

Western's preference customer load level is limited under Contract

2948A to

[[Page 52674]]

a maximum simultaneous demand, excluding project loads, of 1,152 MW.

The maximum simultaneous demand is the sum of each preference

customer's demand for CVP power at a coincidental moment, adjusted to

the load center at the Tracy Switchyard. Notwithstanding the

simultaneous demand limit, Western has contractual obligations to serve

approximately 1,478 MW of firm CRD to its preference customers. This

level of CRD can be served because of the diversity in customers' loads

and load management arrangements Western has with certain customers.

Power Repayment Study

PRSs 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 RA6120.2, 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.

Existing and Provisional Rates

A comparison of the existing and provisional rates follows:

Comparison of Existing and Provisional Rates

[Commercial Firm Power Rate Schedule]

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

Effective period Existing Provisional Percent change

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

Composite Rate (mills/kWh)

10/01/95 to 09/30/96..................................... 31.55 23.35 (26)

10/01/96 to 09/30/97..................................... 31.55 25.00 (21)

10/01/97 to 04/30/98..................................... 34.37 26.50 (23)

Capacity Rate ($/kW/month):

10/01/95 to 09/30/96..................................... 6.57 4.03 (39)

10/01/96 to 09/30/97..................................... 6.57 4.32 (34)

10/01/97 to 04/30/98..................................... 7.16 4.58 (36)

Energy Base Rate (mills/kWh):

10/01/95 to 09/30/96..................................... 17.73 14.83 (16)

10/01/96 to 09/30/97..................................... 17.73 15.93 (10)

10/01/97 to 04/30/98..................................... 19.33 16.93 (12)

Energy Tier Rate (mills/kWh):

10/01/95 to 09/30/96..................................... 34.70 25.90 (25)

10/01/96 to 09/30/97..................................... 34.70 26.27 (24)

10/01/97 to 04/30/98..................................... 37.46 26.48 (29)

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Certification of Rate

Western's Administrator has certified that the CVP commercial firm

power rates placed into effect on an interim basis herein are the

lowest possible rates consistent with sound business principles. The

rates have been developed in accordance with administrative policies

and applicable laws.

Discussion

The CVP provisional rates for commercial firm power change the CVP

rate design and lower the rates currently in effect under Amended Rate

Schedule CV-F7.

The CVP provisional composite rates reflect a 21 percent to 26

percent decrease from the current composite rates established in

Amended Rate Schedule CV-F7. The recent decrease in customer CVP power

purchases and the corresponding decrease in purchase power expenses are

the major factors in the reduced rates.

The existing rate design collects 40 percent of the revenue

requirement from capacity sales and 60 percent from energy sales.

Effective October 1, 1995, the rate design will change to collect 35

percent of the revenue requirement from capacity sales and 65 percent

from energy sales, to reflect the greater portion of Western's costs

associated with energy. A reduction in capacity purchase costs also

result from Western's Sacramento Area Office entering into an

arrangement with PG&E that will reduce the cost of capacity supplied by

PG&E, from the current rate of approximately $17.00/kW/month to $5.875/

kW/month beginning in June 1996.

The capacity rate percentage decreases are larger than the energy

base rate decreases for two reasons: (1) The change in rate design from

a 40 percent capacity/60 percent energy split to a 35 percent capacity/

65 percent energy split, and (2) the forecasted energy tier sales were

reduced disproportionately to the overall reduced forecast of customer

energy sales. Therefore, the energy tier revenues are smaller, leaving

more revenue to be recovered through the energy base rate.

The energy tier rate is based on the average CVP Northwest energy

rate in both the existing and the provisional rates. The energy tier

rate decreases between 24 percent to 29 percent from the existing rates

in Amended Rate Schedule CV-F7. The decrease is due to the reduction in

current market prices for energy from the Northwest from the level

projected in the PRS supporting the current CVP commercial firm power

rates.

The provisional composite rates increase approximately 7 percent in

FY 1997 and 6 percent in FY 1998 as a result of increases in purchase

power rates from Northwest suppliers and a 3 percent escalation factor

in Western's O&M expenses.

The existing and proposed revenue requirements for the Central

Valley Project are as follows:

[[Page 52675]]

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

Estimated 1996 revenue

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

Existing Proposed

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

Revenue requirements:............... $247,898,000 $193,618,000

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

The provisional rates provide sufficient revenues to satisfy the

cost recovery criteria set forth in DOE Order RA6120.2.

Statement of Revenue and Related Expenses

The following table provides a summary of revenue and expense data

through the 2\1/2\-year proposed rate approval period.

Central Valley Project--Comparison of Cost Evaluation Rate Period

Revenues and Expenses

[$1,000]

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

Provisional

ratesetting Current rate Difference

PRS 1996-98 PRS 1996-98

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

Revenue Distribution:

O&M................. 105,521 113,066 (7,545)

Purchase Power...... 407,804 704,129 (296,325)

Transmission........ 45,098 46,191 (1,093)

Interest............ 29,933 26,902 3,031

Investment Repayment 21,598 25,077 (3,479)

Total Revenues.... 609,954 915,365 (305,411)

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

Basis for Rate Development

The CVP rate adjustment is needed to reflect reduced purchase power

expenses that have occurred due to a decrease in customers' CVP power

purchases. A major contributing factor in the rate decrease is reduced

purchase power costs from PG&E. A rate decrease of 21 percent to 26

percent from the existing rate schedule occurs during the FY 1996 to FY

1998 period.

The provisional rates consist of a capacity rate, energy base rate,

and energy tier rate. The energy tier rate will be applied in the same

manner as it is in the current rate schedule, to any energy purchased

at a 70 percent and higher monthly load factor. The energy tier rate is

based on the average CVP Northwest energy rate.

The revenue recovery split between capacity and energy has changed

from that in the existing rate schedule. Currently, the split is 40

percent capacity/60 percent energy. Under the provisional rates the

split is 35 percent capacity/65 percent energy. This change reflects a

greater portion of Western's costs associated with energy, and a

decrease in capacity purchase costs.

The RAC, the Power Factor Adjustment Clause, the Low Voltage Loss

Adjustment, and other provisions which are part of the commercial firm

power rate schedule are not being modified at this time, and will

remain as specified in the Amended Rate Schedule CV-F7.

Comments

During the public comment period, Western received eight written

comments on the rate adjustment. In addition, two customer

representatives commented during the July 26, 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:

Broadview Water District (California)

Calaveras Public Power Agency (California)

National Aeronautics and Space Administration--Ames Research Center

(California)

Northern California Power Agency (California)

City of Palo Alto (California)

City of Santa Clara (California)

Trinity Public Utilities District (California)

Tuolumne Public Power Agency (California)

Representatives of the following organizations made oral comments:

City of Palo Alto (California)

Sacramento Municipal Utility District (California)

The comments received at the public meetings and in correspondence

dealt with the commercial firm power rate design, specifically, the

capacity/energy split for revenue recovery. All comments supported

Western's efforts to reduce the rates and have the provisional rates in

effect by October 1, 1995. Discussion of comments will address the

capacity/energy split, and Western will address several comments with

one response. The comments and responses, paraphrased for brevity, are

discussed below. Direct quotes from comment letters are used for

clarification where necessary.

Commercial Firm Power Rate Design (Capacity/Energy Split)

The following comments relate to the change in CVP rate design from

recovering 40 percent of the revenue requirement from capacity sales

and 60 percent from energy sales, to 35 percent from capacity and 65

percent from energy. Several comments supported the change in the

capacity/energy split.

Comments: One customer commented that they opposed the change from

a 40 percent capacity/60 percent energy split to a 30 percent capacity/

70 percent energy split due to an inappropriate allocation of costs to

energy, and for the reason that an unfair cost responsibility would be

placed on the high load factor customers. However, this same customer

sent a subsequent letter concurring with Western's proposal to change

the 40 percent capacity/60 percent energy split to the 35 percent

capacity/65 percent energy split used to develop the provisional rates.

Other customers argued against keeping the 40 percent capacity/60

percent energy split for the reason that the 40 percent capacity/60

percent energy split is inequitable to the low load factor customers,

and recommended that Western should change its capacity/energy ratio to

be more in line with rate structures of other utility operations

[[Page 52676]]

providing comparable services and serving the same area as Western.

Other comments received recommended Western consider changing the

capacity/energy split to at least a 30 percent capacity/70 percent

energy split.

Response: Western initially proposed to continue the existing 40

percent capacity/60 percent energy revenue requirement split. Western

then developed two studies analyzing the appropriate revenue

requirement split for capacity and energy. In the first study the

associated costs of each CVP resource were allocated to capacity or

energy. This study indicated that approximately 45 percent of the total

resource cost could be allocated to capacity and 55 percent allocated

to energy. An initial study analyzing a fixed/variable cost approach

indicated that approximately 30 percent of Western's costs could be

fixed and allocated to capacity and approximately 70 percent could be

variable and allocated to energy. Further refinement of this fixed/

variable cost study resulted in 35 percent allocated to capacity and 65

percent to energy. Based on these studies, the future reduction in the

capacity purchase rate from PG&E, current market conditions, and

comments from the CVP preference customers, Western concluded that a 35

percent allocation to capacity and 65 percent allocation to energy was

a reasonable split. By shifting a larger percentage of the costs from

capacity to energy, Western believes that the provisional rates will

more closely reflect the cost of providing capacity and energy to its

customers. The rate design reflects Western's cost of capacity and

energy to provide power to all CVP customers, not an individual

customer's consumption of capacity or energy. The impact on individual

customers will vary depending on that customer's usage of capacity or

energy from the CVP. It is Western's position that Western has an

obligation to meet all its contractual commitments and that the

capacity/energy revenue split coupled with the energy tier rate

recognizes Western's overall cost of power.

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 the 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 or

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

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

Power Administration, Office of the Assistant Area Manager for Power

Marketing, 114 Parkshore Drive, Folsom, California 95630, and the Power

Marketing Liaison Office, Office of the Assistant Administrator for

Washington Liaison, Room 8G-027, Forrestal Building, 1000 Independence

Avenue SW., Washington, DC 20585.

Submission to the 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 Schedule CV-F8 for the Central

Valley Project. The rate schedule shall remain in effect on an interim

basis, pending confirmation and approval on a final basis by the

Federal Energy Regulatory Commission, through April 30, 1998, or until

superseded.

Issued in Washington, D.C., September 19, 1995.

Charles B. Curtis,

Deputy Secretary.

Schedule of Rates for Commercial Firm Power Service

Effective: October 1, 1995.

Available: Within the marketing area served by the Sacramento Area

Office.

Applicable: To the commercial firm power customers for general

power service supplied through one meter, at one point of delivery,

unless otherwise provided by contract.

Character: Alternating current, 60 hertz, three-phase, delivered

and metered at the voltages and points established by contract.

Monthly Rates

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

Period Capacity Energy

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

10/01/95-09/30/96...... $4.03/kW/month......... Base: 14.83 mills/kWh.

Tier: 25.90 mills/kWh.

10/01/96-09/30/97...... 4.32/kW/month.......... Base: 15.93 mills/kWh.

Tier: 26.27 mills/kWh.

10/01/97-04/30/98...... 4.58/kW/month.......... Base: 16.93 mills/kWh.

Tier: 26.48 mills/kWh.

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

Billing

Demand: The rates listed above for capacity shall be the charge per

kW of billing demand. The billing demand is the highest 30-minute

integrated demand measured or scheduled during the month up to, but not

in excess of, the delivery obligation under the power sales contract.

Energy: The rates listed above for energy shall be a charge per kWh

for all energy use up to, but not in excess of, the maximum kWh

obligation of the United States during the month as established under

the power sales contract.

The energy base rate shall be applied to all energy sales below a

70 percent monthly load factor. The energy tier rate shall be applied

to all energy sales at a 70 percent and higher monthly load factor. The

monthly load factor shall be calculated based on the lesser of the

customer's (1) maximum demand for the month or, if a scheduled

customer, the maximum scheduled demand for the month; or (2) the CRD.

Only power offered under this Rate Schedule CV-F8 will be used in the

calculation of the load factor.

Adjustments

Billing for Unauthorized Overruns

For each billing period in which there is a contract violation

involving an unauthorized overrun of the contractual obligation for

capacity and/or energy, such overrun shall be billed at 10 times the

applicable rates above. The energy base rate will be used as the

overrun rate for energy.

For Revenue Adjustment

The following methodology shall be used for the revenue adjustment

clause (RAC) calculation:

1. If the actual net revenue is greater than the projected net

revenue for the RAC calculation period, a revenue credit will be

allocated during the RAC

[[Page 52677]]

adjustment period. The credit will equal the difference between the

actual net revenue and projected net revenue, represented by the

following formula:

ANR > PNR ; C = ANR - PNR

Where:

ANR = Actual Net Revenue

PNR = Projected Net Revenue

C = Credit

2. If actual net revenue is less than the projected net revenue for

the RAC calculation period, a revenue surcharge will be allocated

during the RAC adjustment period.

2.1 If the actual net revenue is negative, the surcharge will be

equal to the minimum investment payment plus the annual deficit,

represented by the following formula:

ANR 0 ; S = MIP - ANR (if ANR > MIP, S = 0)

Where:

ANR = Actual Net Revenue

PNR = Projected Net Revenue

MIP = Minimum Investment Payment

S = Surcharge

Provided, that if the actual net revenue is greater than the minimum

investment payment, the surcharge will be equal to zero.

3. The maximum RAC credit allocation will equal $20 million plus

the amount of the Pacific Gas and Electric Company refund credit

applied to Western power bills for the fiscal year. The maximum

allocation for a RAC surcharge shall not exceed $20 million.

4. The RAC credit or surcharge shall be allocated to each CVP

commercial firm power customer based on the proportion of the

customer's billed obligation to Western for CVP commercial firm

capacity and energy to the total billed obligation for all CVP

commercial firm power customers for CVP commercial firm capacity and

energy for the RAC calculation period.

5. For purposes of the RAC calculation, the following terms are

defined:

5.1 Actual Net Revenue--The Recorded Net Revenue.

5.2 Annual Deficit--The amount the recorded annual expenses,

including interest, exceeding recorded annual revenues.

5.3 Minimum Investment Payment--The lesser of 1 percent of the

recorded unpaid investment balance at the end of the prior FY that the

RAC is being calculated, or the projected net revenue.

5.4 Projected Net Revenue--The annual net revenue available for

investment repayment projected in the PRS for the rate case during the

FY that the RAC is being calculated (see Table 1).

5.5 RAC Adjustment Period--The period January 1 through September

30, following the RAC calculation period when credits or surcharges

will be applied to the power bills.

5.6 RAC Calculation Period--The last recorded FY (October 1

through September 30).

5.7 Recorded Net Revenue--The annual net revenue available for

repayment recorded in the PRS for the FY that the RAC is being

calculated.

6. Subject to modification by a superseding rate schedule, the

final RAC will be allocated to the customers during the period January

1, 1999, to September 30, 1999.

Table 1.--Projected net revenue Available for Investment Repayment for

Revenue Adjustment Clause

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

Projected Net

Period Revenue `

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

October 1, 1995-September 30, 1996.................... $11,783,544

October 1, 1996-September 30, 1997.................... 4,506,910

October 1, 1997-September 30, 1998.................... 5,307,779

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

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 be required to maintain a power factor at all

points of measurement between 95-percent lagging and 95-percent

leading. The low power factor charge (LPFC) will be calculated by

multiplying the customer's maximum monthly demand by the kVar/kW rate

for the customer's mean power factor as provided in the following Table

2:

Table 2.--kVar/kW Rate Table

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

Power factor Rate

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

0.94...................................................... $0.09

0.93...................................................... 0.17

0.92...................................................... 0.24

0.91...................................................... 0.32

0.90...................................................... 0.39

0.89...................................................... 0.46

0.88...................................................... 0.53

0.87...................................................... 0.60

0.86...................................................... 0.66

0.85...................................................... 0.73

0.84...................................................... 0.79

0.83...................................................... 0.86

0.82...................................................... 0.92

0.81...................................................... 0.99

0.80...................................................... 1.05

0.79...................................................... 1.12

0.78...................................................... 1.18

0.77...................................................... 1.25

0.76...................................................... 1.32

0.75 & below.............................................. 1.38

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

A LPFC will be assessed when a customer's power factor is less than

95 percent.

(a) A charge of $2.50 per kVar will be assessed for every kVar

required to raise a customer's power factor to 95 percent. The

calculated power factor used to determine if a charge will be assessed

is the arithmetic mean of a customer's measured monthly average power

factor and their measured onpeak power factor, rounded to the nearest

whole percent with 0.5 percent or greater rounded to the next higher

percent.

(b) The mean power factor will be calculated at each customer's

point of delivery. If a customer has multiple points of delivery, the

power factor will be determined from totalized information from the

points of delivery.

(c) No credit will be given for customers operating between 95

percent and 100 percent.

(d) Customers that have a monthly peak demand less than or equal to

50 kW will not be subject to the LPFC.

(e) The Contracting Officer may waive the LPFC for good cause in

whole or in part.

[FR Doc. 95-25043 Filed 10-6-95; 8:45 am]

BILLING CODE 6450-01-P