[Federal Register Volume 60, Number 195 (Tuesday, October 10, 1995)]
[Notices]
[Pages 52671-52677]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-25043]



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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.

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

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) 
----------------------------------------------------------------------------------------------------------------

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 < PNR and < O ; S = MIP + AD
Where:
ANR = Actual Net Revenue
PNR = Projected Net Revenue
MIP = Minimum Investment Payment
AD = Annual Deficit
S = Surcharge

    2.2  If the actual net revenue is positive, the surcharge will 
equal the minimum investment payment less the actual net revenue, 
represented by the following formula:

ANR < PNR and > 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