[Federal Register Volume 62, Number 38 (Wednesday, February 26, 1997)]
[Notices]
[Pages 8710-8721]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 97-4695]


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


DEPARTMENT OF ENERGY

Proposed 2004 Power Marketing Plan

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of proposed plan.

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

SUMMARY: The Western Area Power Administration's (Western) Sierra 
Nevada Customer Service Region (Sierra Nevada Region) has developed a 
Proposed 2004 Power Marketing Plan (Proposed Plan). The Proposed Plan 
provides for marketing power from Central Valley Project (CVP) and 
Washoe Project powerplants after the year 2004. Western currently 
markets about 1,580 megawatts (MW) of CVP power under long-term 
contracts to 80 preference customers in northern and central 
California. Western also markets 3.65 MW of Washoe Project power. On 
December 31, 2004, all of Western's long-term CVP power sales contracts 
will expire, along with Contract 14-06-200-2948A (Contract 2948A) with 
the Pacific Gas and Electric Company (PG&E) for the sale, interchange 
and transmission of electric capacity and energy. Western has developed 
the Proposed Plan to define the products and services to be offered, 
and the eligibility and allocation criteria that will lead to 
allocations of CVP and Washoe Project power beyond the year 2004. This 
Federal Register notice initiates the Administrative Procedure Act 
process that gives the public an opportunity to participate in 
administrative rulemaking for marketing of this power by Western after 
the year 2004, and requests public comment.

DATES: On April 8, 1997, beginning at 10 a.m., Western will hold a 
public information forum on the Proposed Plan. At the information 
forum, Western representatives will present the Proposed Plan and 
respond to questions from the public. On April 24, 1997, beginning at 1 
p.m., Western will hold a public comment forum to receive oral and 
written comments on the Proposed Plan. Each forum will be held at the 
Sierra Nevada Regional Office, 114 Parkshore Drive, Folsom, California. 
Oral or written comments may be presented at the public comment forum. 
A transcript of oral comments made at this forum will be available from 
the court reporter. Written comments on the Proposed Plan will be 
accepted from the date of publication of this Federal Register notice 
through May 27, 1997.

ADDRESSES: Written comments may be hand-delivered, mailed, or faxed to 
the address provided below. Comments must be received by 5 p.m. PDT or 
postmarked on May 27, 1997 to assure consideration. Inquiries and 
written comments regarding the Proposed Plan should be directed to: 
James C. Feider, Regional Manager, Western Area Power Administration, 
Sierra Nevada Region, 114 Parkshore Drive, Folsom, CA 95630-4710, (916) 
353-4418, (916) 985-1931 FAX.
    All documentation developed or retained by Western for the purpose 
of developing the Proposed Plan will be available for inspection and 
copying at the address below.

FOR FURTHER INFORMATION CONTACT: Zola M. Jackson, Power Marketing 
Manager, Western Area Power Administration, Sierra Nevada Region, 114 
Parkshore Drive, Folsom, CA 95630-4710, (916) 353-4421.
    After all public comments have been considered, Western will 
publish a Final 2004 Power Marketing Plan (Final Plan) in the Federal 
Register.

[[Page 8711]]

SUPPLEMENTARY INFORMATION:

Authorities

    The Sierra Nevada Region developed this Proposed Plan in accordance 
with its power marketing authorities in the Federal Reclamation laws, 
the Act of June 17, 1902 (32 Stat. 388), the Act of August 4, 1939 (53 
Stat. 1187); the Act of April 8, 1935 (49 Stat. 115), the Act of June 
22, 1936 (49 Stat. 1622), the Act of August 26, 1937 (50 Stat. 844), 
the Act of October 17, 1940 (54 Stat. 1198), the Act of December 22, 
1944 (58 Stat. 887), Act of October 14, 1949 (63 Stat. 852), the Act of 
September 26, 1950 (64 Stat. 1036), the Act of August 12, 1955 (69 
Stat. 719), the Act of August 1, 1956 (70 Stat. 775), the Act of June 
3, 1960 (74 Stat. 156), the Act of October 23, 1962 (76 Stat. 1173), 
the Act of September 2, 1965 (79 Stat. 615), the Act of August 4, 1977 
(91 Stat. 565), and the Act of July 16, 1984, including all acts 
amendatory and/or supplementary to the above listed.

Development of the Proposed Plan

    Western is developing the Proposed Plan to define: (1) the products 
and services to be offered, and (2) the criteria for allocating power 
resources to be marketed under contracts that will replace those 
expiring on December 31, 2004.
    Development of the Proposed Plan was initiated with a series of 
three informal public information meetings held on November 17, 1995, 
March 7, 1996, and May 13, 1996. These meetings began informal 
discussions to identify pertinent issues and possible marketing 
options, including products and services and eligibility and allocation 
criteria, to be included in the Proposed Plan. During the informal 
process, Western evaluated several options for marketing power after 
termination of existing contracts. Western's proposal provides each 
customer a right to customize its power allocation from Western. This 
will provide a customer the flexibility to optimize the use of Western 
power.
    Western is also proposing to offer a resource extension to existing 
customers and to offer a portion of the resource to new customers. 
Western believes its Proposed Plan provides a balance between existing 
and new customers, while meeting its contractual obligations that 
continue beyond 2004.
    As explained in the DATES section of this notice, Western will hold 
public information and comment forums on the Proposed Plan. After 
consideration of all public comments, Western will publish notice of 
the Final Plan in the Federal Register. With that notice, Western will 
also announce its decisions regarding power resource extensions to 
existing customers and call for applications for new allocations. The 
deadline for receipt of applications will be set forth in the call for 
applications. Western will then consider the applications, determine 
which applications meet the requirements of the Final Plan, and 
exercise its discretion provided by law in allocating the power to 
eligible applicants. Proposed and final allocations will subsequently 
be published in the Federal Register.
    To implement the Proposed Plan, the level of power resources to be 
marketed must be determined. Determining levels of power resources to 
be marketed and subsequently entering into contracts for the delivery 
of related products and services could be a major Federal action with 
potentially significant impacts on the human environment. Therefore, an 
Environmental Impact Statement (EIS) process was initiated on the 2004 
Power Marketing Program with a Federal Register notice published at 58 
FR 42536 and 43105, on August 10 and 13, 1993, respectively, in 
compliance with the National Environmental Policy Act of 1969 (NEPA) 
(42 U.S.C. 4321, et seq.), as amended, and associated implementing 
regulations. Following several public meetings, a draft EIS was 
prepared. The draft EIS described the environmental consequences of a 
range of reasonable marketing plan alternatives and identified no 
significant impacts. A Federal Register notice was published on May 24, 
1996 (61 FR 26174) announcing that the draft EIS was available for 
public review and comment. Also, Western held a public hearing on June 
13, 1996 to receive formal comments on the draft EIS, with a July 31, 
1996 deadline for receipt of written comments. A final EIS is expected 
to be completed by March 1997, and a Record of Decision is tentatively 
scheduled to be published in April 1997. The Final Plan will 
incorporate decisions made as a result of the findings of the final 
EIS.
    The schedule for the Proposed Plan was developed to recognize 
Western's responsibility to its customers to provide: (1) necessary 
planning time (approximately 5 years after final contract commitments) 
for customers to acquire new power resources should their allocation of 
CVP power change; (2) sufficient time for Western's Sierra Nevada 
Region or its customers to negotiate contracts for control area 
services, third-party transmission, and supplemental power supplies; 
and (3) time to meet with each customer to design a product/service 
package prior to the customer making a final commitment.
    The Proposed Plan also incorporates the intent of the Final Rule 
for the Energy Planning and Management Program (EPAMP) (10 CFR part 
905), published by Western on October 20, 1995 at 60 FR 54151. The 
EPAMP Final Rule became effective on November 20, 1995. EPAMP 
implements Section 114 of the Energy Policy Act of 1992, and requires 
Western's customers to prepare Integrated Resource Plans (IRP). The 
Power Marketing Initiative (PMI) of EPAMP provides a framework for 
extending a major portion of the power available at the time current 
contracts expire to existing customers, and for establishing project-
specific resource pools. During the public process for EPAMP, it was 
determined that application of the PMI to the CVP would be evaluated 
during the 2004 Power Marketing Plan public process.

Background

    The CVP is a large water and power system, initially authorized by 
Congress in 1935, which covers approximately one-third of the State of 
California. Legislatively defined purposes set the priorities for the 
CVP as: (1) river regulation; (2) improvement of navigation; (3) flood 
control; (4) irrigation; (5) domestic uses; and (6) power. In addition, 
the CVP Improvement Act of 1992 added fish and wildlife habitat as a 
priority to the list of CVP purposes.
    The CVP power facilities include 11 powerplants with a maximum 
operating capability of about 2,044 MW, and an estimated average annual 
generation of 4.6 million megawatthours (MWh). The U.S. Department of 
the Interior, Bureau of Reclamation (Reclamation) operates the water 
control and delivery system and all of the powerplants with the 
exception of the San Luis Unit, which is operated by the State of 
California for Reclamation. Western markets and transmits the power 
available from the CVP.
    Western owns the 94 circuit-mile Malin-Round Mountain 500-kilovolt 
(kV) transmission line (an integral section of the Pacific Northwest-
Pacific Southwest Intertie (Pacific Intertie)), 803 circuit miles of 
230-kV transmission line, 7 circuit miles of 115-kV transmission line 
and 44 miles of 69-kV and below transmission line. Western also has 
part ownership in the 342-mile California-Oregon Transmission Project 
(COTP). Some of Western's existing customers have no direct access to 
Western's transmission lines and receive service over transmission 
lines owned by other utilities.

[[Page 8712]]

    Western has historically combined output from CVP hydroelectric 
facilities with supplemental power from a number of other power 
resources. This has enabled Western to enhance the CVP power resources 
and to market an amount of firm power to its customers that would not 
be available solely from CVP facilities in all years. A portion of this 
supplemental power has been transmitted over the COTP and Pacific 
Intertie.
    The Washoe Project was authorized by Congress in 1956 and is a 
separate project from the CVP. The Washoe Project, located in west-
central Nevada and east-central California, was designed to regulate 
runoff from the Truckee and Carson rivers and to enhance irrigation; 
water drainage; municipal, industrial, and fisheries uses; and provide 
flood protection; fish and wildlife habitat; and recreation. The Washoe 
Project includes Prosser Creek Dam and reservoir; Stampede Dam, 
reservoir, and powerplant; Marble Creek Dam; and Pyramid Lake Fishway. 
The Stampede Powerplant, located in Sierra County, California, was 
completed in 1987, and has a maximum operating capability of 3.65 MW 
with an estimated annual generation of 10,000 MWh. Sierra Pacific Power 
Company (SPPC) owns and operates the only transmission system available 
for distribution of power generated at the Stampede Powerplant.

History of Central Valley Project Power Allocations

    Power was first generated in the CVP at the Shasta Powerplant in 
1944. Formal allocations of 450 MW of CVP power were first made in 
1952. In 1964, with the addition of the Trinity River Division 
facilities, allocations to preference customers were increased to 925 
MW. In 1967, under terms of Contract 2948A, power imports over the 
Pacific Intertie (Northwest imports) were incorporated along with 
provisions for load level increases up to 985 MW in 1975 and up to 
1,050 MW in 1980.
    Later in 1980, the load level was increased by 102 MW to 1,152 MW. 
This increase in allocations was accomplished under the 1981 Power 
Marketing Plan (47 FR 4139) dated January 28, 1982. New customers 
received 26 MW of nonwithdrawable power and 42 MW of withdrawable power 
for a total of 68 MW, with 4 MW of withdrawable power left unallocated. 
Also, diversity power allocations of 30 MW were made to those customers 
who could shed load during Sierra Nevada Region's system simultaneous 
peak.
    During the same time period, SMUD challenged Western's right to 
meld the costs of Northwest imports into CVP power rates charged to 
SMUD. In a 1983 settlement, it was agreed that SMUD would pay the 
melded CVP power rates; SMUD's electric service contract, due to expire 
in 1994, would be extended to 2004; and SMUD would have the right to 
purchase 100 MW of peaking capacity through 2004. Further, SMUD would 
have the right to purchase a portion of the power to be marketed from 
2005 to 2014.
    Under the 1994 Power Marketing Plan (57 FR 45782 and 58 FR 34579) 
dated October 5, 1992 and June 28, 1993, respectively, existing 
customers with contracts expiring in 1994 were allocated 501 MW, and 
approximately 8 MW was allocated to new customers.
    In addition to the power marketed in the 1994 Power Marketing Plan, 
total power under existing contracts includes approximately 910 MW of 
long-term firm power, 100 MW of peaking capacity, and 60 MW of 
withdrawable power, for a total of about 1,580 MW. See Appendix A of 
this notice for Existing Customers' CRD Amounts.
    On November 30, 1993, the National Defense Authorization Act (NDA 
Act) was signed into law. This act provides that, for a 10-year period, 
the CVP electric power allocations to military installations in the 
State of California which have been closed or approved for closure 
shall be reserved for sale through long-term contracts to preference 
entities which agree to use such power to promote economic development 
at the military installations closed or approved for closure. On 
December 1, 1994, Western published the final NDA Act procedures 
developed to fulfill the requirements of section 2929 of the NDA Act 
(59 FR 61604). To date, about 42 MW of long-term firm power and about 9 
MW of withdrawable power under contract to military installations being 
closed has been converted to NDA Act power.

History of Washoe Project (Stampede Powerplant) Allocations

    Pursuant to Final Allocation of Stampede Powerplant Power (50 FR 
43456) dated October 25, 1985, Western allocated all the energy 
generated at Stampede Powerplant in excess of that needed to serve 
project use (Lahontan Fish Hatchery and Marble Bluff Fish Facility) to 
Truckee-Donner Public Utility District. Because Truckee-Donner was 
unable to obtain transmission service, it was unable to enter into a 
contract with Western to receive Stampede energy. In 1988, Western 
rescinded the allocation of Stampede energy to Truckee-Donner and 
marketed Stampede energy to SPPC under short-term agreements.
    In 1990, Western began conducting a bidding process for the sale of 
Stampede energy, giving priority to preference entities. Since no 
preference entity met the bidding criteria, SPPC continued to purchase 
Stampede energy under short-term agreements.
    In April 1994, Western executed agreements with SPPC and the Fish 
and Wildlife Service (F&WS) which established a mechanism to provide 
project use service to the F&WS facilities. These agreements also 
provide Western the option to market and transmit all energy, in excess 
of that which is required to provide project use service, outside of 
SPPC's control area.

Regulatory Procedure Requirements

Regulatory Flexibility Analysis

    Pursuant to the Regulatory Flexibility Act of 1980 (5 U.S.C. 601, 
et seq.), each agency, when required to publish a proposed rule, is 
further required to prepare and make available for public comment an 
initial regulatory flexibility analysis to describe the impact of the 
proposed rule on small entities. Western has determined that (1) this 
rulemaking relates to services offered by Western and therefore is not 
a rule within the purview of the Act, and (2) an allocation of power 
from Western would not cause an adverse economic impact to such 
entities. The requirements of this Act can be waived if the head of the 
agency certifies that the rule will not, if promulgated, have a 
significant economic impact on a substantial number of small entities. 
By his execution of this Federal Register notice, Western's 
Administrator certifies that no significant economic impact on a 
substantial number of small entities will occur.

Environmental Compliance

    In compliance with NEPA (42 U.S.C. 4321, et seq.), Council on 
Environmental Quality NEPA implementing regulations (40 CFR parts 1500-
1508), and DOE NEPA implementing regulations (10 CFR part 1021), 
Western completed an environmental impact statement on EPAMP. The 
Record of Decision was published in the Federal Register on October 12, 
1995 (60 FR 53181). Additionally, as described in the Supplementary 
Information Section of this notice, Western and the Environmental 
Protection Agency announced the availability of Western's draft EIS on 
the 2004 Power Marketing Program in Federal Register notices published 
on May 24, 1996 (61 FR

[[Page 8713]]

26174 and 26178, respectively). The draft EIS described the 
environmental consequences of a range of reasonable marketing plan 
alternatives and identified no significant impacts. The Proposed Plan 
falls within the range of alternatives considered. This NEPA review 
will assure all environmental effects related to Western's Proposed 
Plan have been identified and analyzed.
    CVP and Washoe electrical capacity and energy to be marketed is 
influenced by available reservoir storage and water releases controlled 
by Reclamation within the CVP in California. Pursuant to Title 34 of 
Public Law 102-575, the CVP Improvement Act of 1992, Reclamation is 
preparing a Programmatic Environmental Impact Statement (PEIS) 
addressing improvements to fish and wildlife habitat stipulated in 
Public Law 102-575, and potential changes in CVP operations and water 
allocations to meet those obligations. The draft PEIS may result in 
modifications to CVP facilities and operations that would affect the 
timing and quantity of electric power generated by the CVP. Such 
changes may, in turn, affect electric power products and services to be 
marketed by Western. This Proposed Plan is designed to accommodate 
these changes. Western is a cooperating agency in Reclamation's PEIS.

Review Under the Paperwork Reduction Act

    In accordance with the Paperwork Reduction Act of 1980, 44 U.S.C. 
3501-3520, Western has received approval from the Office of Management 
and Budget (OMB) for the collection of customer information in this 
rule, under control number 1910-1200.

Determination Under Executive Order 12866

    DOE has determined that the Proposed Plan is not a significant 
regulatory action because it does not meet the criteria of Executive 
Order 12866 (58 FR 51735). Western has an exemption from centralized 
regulatory review under Executive Order 12866; accordingly, no 
clearance of this notice by OMB is required.

Proposed 2004 Power Marketing Plan

    This Proposed Plan addresses: (1) the power to be marketed after 
2004; (2) the terms and conditions under which the power will be 
marketed; and (3) the criteria to determine who will receive an 
allocation.
    Within broad statutory guidelines and operational constraints of 
the CVP, Western has wide discretion as to whom and on what terms it 
will contract for the sale of Federal power as long as preference is 
accorded to statutorily defined public bodies. Power must be sold in 
such a manner as will encourage the most widespread use at the lowest 
possible rates consistent with sound business principles.

I. Acronyms and Definitions

    As used herein, the following acronyms and terms, whether singular 
or plural, shall have the following meanings:
    Administrator: The Administrator of Western Area Power 
Administration.
    Allocation: An offer to an entity to purchase power from Western.
    Allocation Criteria: Conditions applied to all applicants seeking 
an allocation.
    Allottee: A preference entity receiving an allocation or power 
resource extension.
    Ancillary Services: Those services necessary to support the 
transfer of electricity while maintaining reliable operation of the 
transmission provider's transmission system in accordance with good 
utility practice. Ancillary services are generally described in Federal 
Energy Regulatory Commission Order No. 888, Docket Nos. RM95-8-000 and 
RM94-7-001, issued April 24, 1996.
    Base Resource: CVP and Washoe Project power output and existing 
power purchase contracts extending beyond 2004 determined by Western to 
be available for marketing, exclusive of project use and First 
Preference entitlements.
    Capacity: The electrical capability of a generator, transformer, 
transmission circuit or other equipment.
    Central Valley Project (CVP): A multipurpose Federal water 
development project extending from the Cascade Range in northern 
California to the plains along the Kern River south of the City of 
Bakersfield.
    Contract Principles: Provisions made part of the electric service 
contracts which include the General Power Contract Provisions.
    Contract Rate of Delivery (CRD): The maximum amount of capacity 
made available to a preference customer for a period specified under a 
contract.
    Curtailable Power: Power which may be curtailed on a real-time 
scheduling basis at Western's sole discretion under certain conditions.
    Custom Product: A combination of products and services, excluding 
provisions for load growth, made available by Western per customer 
request, utilizing the customer's Base Resource and supplemental 
purchases made by Western at customer expense.
    Customer: An entity with a contract and receiving electric service 
from Western's Sierra Nevada Region.
    Diversity Power: Power made available because of the diversity of 
customers' peak demands at the time of Sierra Nevada Region's peak 
demand.
    Eligibility Criteria: Conditions that must be met to qualify for an 
allocation.
    Energy: Measured in terms of the work it is capable of doing over a 
period of time; electric energy is usually measured in megawatthours.
    Energy Planning and Management Program (EPAMP): Western-wide 
program developed to encourage customer energy planning (60 FR 54151, 
dated October 20, 1995).
    Existing Customer: A preference customer with a contract to 
purchase firm power, offered under a previous allocation process or 
marketing plan, that extends through December 31, 2004.
    Extension CRD: Existing customer's CRD exclusive of Diversity and 
Curtailable Power, peaking/excess capacity, and NDA Act Power not used 
for military loads.
    Final Plan: Western's Final 2004 Power Marketing Plan.
    Firm: A type of product and/or service that is available to a 
customer at the times it is required.
    First Preference Customer/Entity: A preference customer and/or a 
preference entity (an entity qualified to use, but not using preference 
power) within a county of origin (Trinity, Calaveras and Tuolumne) as 
specified under the Trinity River Division Act (69 Stat. 719) and the 
New Melones Act of the Flood Control Act of 1962 (76 Stat. 1180).
    General Power Contract Provisions (GPCP): Standard terms and 
conditions which are included in electric service contracts.
    Integrated Resource Plan (IRP): A process and framework within 
which the costs and benefits of both demand and supply-side resources 
are evaluated to develop the least total cost mix of utility resource 
options.
    Kilowatt (kW): The electrical unit of capacity that equals one 
thousand watts.
    Load Factor: The ratio of the average load in kW supplied during a 
designated period to the peak or maximum load in kW occurring in that 
period.
    Long-Term: A designation for a contractual period of time greater 
than 5 years.
    Marketing Area: The area which generally encompasses northern and 
central California extending from the Cascade Range to the Tehachapi 
Mountains and west-central Nevada.
    Megawatt (MW): The unit by which the rate of production of 
electricity is

[[Page 8714]]

often measured; one megawatt equals one million watts.
    NDA Act: Section 2929 of the National Defense Authorization Act, 
Public Law 103-160, 107 Stat. 1547, 1935 (1993), which provides that, 
for a 10-year period, the CVP electric power allocations to military 
installations in the State of California which have been closed or 
approved for closure shall be reserved for sale through long-term 
contracts to preference entities which agree to use such power to 
promote economic development at the military installations closed or 
approved for closure.
    NDA Act Power: Power allocated in accordance with the NDA Act 
Procedures (59 FR 61604, dated December 1, 1994), which provide for NDA 
Act power allocations.
    Peaking: The operation of electric powerplants for brief periods 
when demand for electricity is greatest.
    Power: Capacity and energy.
    Power Marketing Initiative (PMI): A component of Western's EPAMP 
providing criteria regarding certain Western power marketing programs.
    Preference: The requirements of Reclamation law which provide that 
preference in the sale of Federal power shall be given to 
municipalities and other public corporations or agencies and also to 
cooperatives and other nonprofit organizations financed in whole or in 
part by loans made pursuant to the Rural Electrification Act of 1936 
(Reclamation Project Act of 1939, section 9(c), 43 U.S.C. 485h(c)).
    Project Use: Power as defined by Reclamation law and/or used to 
operate CVP and Washoe Project facilities.
    Proposed Plan: Western's Proposed 2004 Power Marketing Plan.
    Reclamation law: Refers to a series of Federal laws with a lineage 
dating back to the turn of the century. Viewed as a whole, these laws 
create the framework under which Western markets power.
    Sierra Nevada Region: The Sierra Nevada Customer Service Region of 
Western Area Power Administration.
    Unbundled: Electric service that is separated into its components 
and offered for sale with separate rates for each component.
    Washoe Project: A Federal water project located in the Lahontan 
Basin in west-central Nevada and east-central California.
    Western: Western Area Power Administration, United States 
Department of Energy, a Federal power marketing administration 
responsible for marketing the surplus generation from Federal 
hydroelectric multipurpose projects pursuant to Reclamation law and the 
DOE Organization Act (91 Stat. 565, 42 U.S.C. 7101, et seq.).
    Withdrawable: Power that may be withdrawn under certain conditions.

II. Marketable Power Resource

    The primary purpose of the CVP and Washoe Project is water control 
and delivery. The water control system consists of storage reservoirs 
that provide daily, seasonal, and annual flow regulation, and smaller 
regulating reservoirs for diverting water and smoothing upstream dam 
and powerplant releases. Power generated from these resources depends 
on hydrology and water operation requirements. Some of the power 
generated is used for project use to operate pumping and fishery 
facilities. Currently, project use power is metered at 181 locations in 
northern and central California and Nevada.
    Expected CVP generation (energy and capacity) for 2005 and beyond 
will vary annually, monthly, and daily, based on hydrology and other 
constraints that govern CVP operations. CVP generation is available at 
generator bus and must be adjusted for project use, maintenance, 
reserves, transformation losses, and certain ancillary services before 
a Base Resource is available for marketing. Transmission losses will be 
pursuant to the terms of a transmission service agreement. The power 
resources will also be adjusted for First Preference customers as 
described in this Proposed Plan.
    The following Table provides estimates of CVP power resources and 
adjustments before any power resources are available to customers 
beyond 2004:

                             Table A.--Estimated CVP Power Resources and Adjustments                            
----------------------------------------------------------------------------------------------------------------
         Power resources/adjustment                                       Range/value                           
----------------------------------------------------------------------------------------------------------------
Annual energy generation....................  2,400,000-8,600,000 MWh.                                          
Monthly energy generation...................  100,000-1,100,000 MWh.                                            
Monthly capacity............................  1,100-1,900 MW.                                                   
Annual project use..........................  670,000-1,670,000 MWh.                                            
Monthly project use.........................  10,000-180,000 MWh.                                               
Monthly project use (on peak)...............  30-230 MW.                                                        
Monthly maintenance.........................  0-300 MW.                                                         
Reserves....................................  5% of monthly capacity.                                           
CVP transmission and transformation losses    1.8% (as of 1995).                                                
 from the generator bus to a 230-kV load bus.                                                                   
----------------------------------------------------------------------------------------------------------------

    All of the power resource adjustments and variables mentioned above 
will influence the amount of Base Resource available to customers. 
During some critically dry months, purchases may be required to meet 
project use and only a minimal amount of Base Resource will be 
available during such months. The useability of the Base Resource for 
meeting customers'' loads will be directly related to a customer's 
ability to integrate this power resource into their power resource mix.
    Western proposes to include any power available from existing power 
purchase contracts with terms extending beyond 2004 in the Base 
Resource. Currently, Western has a contract with Portland General 
Electric Company for 65 MW at a 40 percent minimum load factor that has 
a final termination date of October 15, 2015.
    Western also proposes to market part of the 3.65 MW available from 
the Washoe Project with the CVP power resource on an annual basis. 
Energy from the Washoe Project, which is estimated to be about 10,000 
MWh annually, is currently being provided to F&WS Lahontan National 
Fish Hatchery and Marble Bluff Fish Facility. These F&WS facilities are 
project use loads of the Washoe Project and have first call on the 
power resources from the Washoe Project. All costs associated with 
providing F&WS project use service are, by law, nonreimbursable, and 
are not included in the Washoe Project energy rates. Energy in excess 
of the F&WS needs will be sold under the Final Plan.
    Western will continue to make every effort to provide the Washoe 
Project power resource to F&WS. F&WS is currently using approximately 
50

[[Page 8715]]

percent of Washoe Project generation, and the same percentage of costs 
is considered nonreimbursable. Western expects that F&WS loads will 
increase, reducing the amount of power resource to be integrated with 
the CVP as well as the cost to be repaid from power revenues.

III. Products and Services

    Western proposes to market its Base Resource alone or in 
combination with the option to purchase a Custom Product. The Custom 
Product will be in addition to the optional purchase described in 
Section IV.A.2. All costs incurred by Western in providing additional 
services to customers will be paid by those customers. The degree to 
which Western continues to purchase power will depend on customer 
requirements and Federal authorities. All products will be subject to 
operational requirements and constraints of the CVP, transmission 
availability, and purchase limitations.
    Each allottee will be allocated a portion of the Base Resource. 
Following execution of a contract pursuant to the Final Plan, Western 
will work with each individual allottee to determine the best use of 
the Base Resource for that allottee. All allottees will be required to 
commit to the Base Resource no later than December 31, 1999.
    Upon request, Western will develop a Custom Product for any 
allottee. A Custom Product may include use of the Base Resource as firm 
power, ancillary services, reserves, etc., or may include Western 
purchasing additional resources, including firming energy, to provide 
some of these services. Final commitments to a Custom Product must be 
made by December 31, 2001, for a period of no less than five (5) years 
of service. Thereafter, the Custom Product will be offered for periods 
of one (1) year or more.
    Any unused power resource available will be marketed under terms 
and conditions and for periods of time determined by Western. Products 
and services from unused power resources may be made available on a 
monthly, weekly, daily, hourly, or nonfirm basis.
    Western may offer unused First Preference power, subject to 
withdrawal on a pro-rata basis, upon six (6) months written notice.
    Western proposes to establish and to manage an exchange program to 
allow all customers to fully and efficiently use their power 
allocation. Any power allocated by Western to a customer that cannot be 
used on a real-time basis due to that customer's load profile must 
first be offered under this program to other customers or Western. 
Western will not be obligated to exchange or to purchase any surplus 
power from the customers on its own behalf. If the surplus power is not 
exchanged with other customers or purchased by Western under this 
program, it may be offered to others, giving priority to preference 
entities.

IV. Proposed Resource Extension and Resource Pool Allocation

    On December 31, 2004, Western's long-term CVP power sales contracts 
for 1,580,230 kilowatts (kW) will expire. This Proposed Plan addresses 
the eligibility for and allocation of CVP and Washoe Project power 
after these contracts expire. When allocating power under the Final 
Plan, Western proposes to apply the principles of the Power Marketing 
Initiative (PMI) of the Energy Planning and Management Program. In 
accordance with the PMI, Western proposes to set aside a portion of its 
available power resource for new allocations. Based on Western's 
evaluation of potential new loads, Western proposes to initially 
provide 96 percent of its available power resource to existing 
customers and to establish a resource pool for new allocations with the 
remaining 4 percent. An additional incremental resource pool of up to 2 
percent is proposed for 2014. When calculating the 96 percent resource 
extension for existing customers, only CRD classified as Extension CRD 
will be considered. Also, no extensions will be greater than an 
existing customer's load. Extension CRD amounts are set forth in 
Appendix A. Contractual extensions to First Preference customers are 
subject to specific legislation and are addressed in Section VI.

A. Extension for Existing Customers

    Western proposes that existing customers will have a right to 
purchase a percentage of the Base Resource based on the ratio of each 
existing customer's Extension CRD to the total of all existing 
customers'' Extension CRD under the terms of this Section. However, for 
the period from 2005 through 2014, Western is proposing that SMUD will 
have a right to purchase 360/1,152 of the Base Resource, as referenced 
in the settlement agreement with SMUD, Contract DE-MS65-83WP59070, 
dated April 15, 1983. All other existing customers will have a right to 
purchase the remaining amount of the Base Resource, after it is 
adjusted to accommodate SMUD's rights and the resource pool. After 
2014, SMUD's right to purchase the Base Resource will be adjusted to 
reflect the ratio of SMUD's Extension CRD (currently 361 MW) to the 
total of all existing customers'' Extension CRD. SMUD's rights will 
also be adjusted by 4 percent and up to an additional 2 percent to 
accommodate the resource pool.
    Due to the diversity among existing customers' loads, including 
SMUD, existing customers' total Extension CRD exceeds the 1,152 MW 
referenced in the SMUD settlement agreement. Western's proposal will 
result in SMUD receiving a proportionately greater share of the Base 
Resource than other existing customers if the total Extension CRD 
remains at a level greater than 1,152 MW. Therefore, Western is also 
proposing that through 2014, all existing customers, excluding SMUD, be 
given the option to have Western purchase an additional increment of 
power, on a pass-through-cost basis, equal to the amount of power 
unavailable to them as a result of application of the 360/1,152 ratio. 
Existing customers must commit to the optional purchase for an annual 
or greater period.
    After 2014, each existing customer, including SMUD and those 
customers that receive a new allocation under the Final Plan, will have 
a right to purchase a pro-rata amount of the Base Resource, adjusted 
for the incremental resource pool, based on their long-term purchase 
right to the Base Resource.
    Western proposes the following extension formulas to determine 
existing customers' purchase right to the Base Resource. Application of 
these formulas will also determine each existing customer's right to 
the optional purchase. Examples of the formulas are provided in 
Appendix B. This calculation may be further adjusted for First 
Preference customers.
    1. For the period 2005 through 2014, existing customers purchase 
right to an extension resource will be calculated as follows:

[[Page 8716]]

[GRAPHIC] [TIFF OMITTED] TN26FE97.001


Where:

A = Lesser of individual existing customer's Extension CRD as of 
December 31, 2001; or 104 percent of their maximum demand during CY 
1997 through 2000. Western reserves the right to adjust the value of 
``A'' when it is determined that the maximum demand is not reflective 
of an existing customer's load.
B = The sum of all values for ``A''.
BR = Base Resource available.
ABR = Adjusted Base Resource
[GRAPHIC] [TIFF OMITTED] TN26FE97.002

RP% = Resource pool percentage.

    2. Existing customer's (excluding SMUD) right to the optional 
purchase will be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TN26FE97.003

Where:

TOP = Total Optional Purchase
[GRAPHIC] [TIFF OMITTED] TN26FE97.004

A = Lesser of individual existing customer's Extension CRD as of 
December 31, 2001; or 104 percent of their maximum demand during CY 
1997 through 2000. Western reserves the right to adjust the value of 
``A'' when it is determined that the maximum demand is not reflective 
of an existing customer's load.
B = The sum of all values for ``A''.
BR = Base Resource available.
RP% = Resource pool percentage.
C = The sum of all existing customers', including SMUD, Extension CRD.

    Western and SMUD have been negotiating an agreement whereby SMUD 
would waive its rights to the 360/1,152 ratio in return for additional 
services through 2004. If such an agreement is reached, these formulas 
will be appropriately adjusted.
    3. For the period 2015 through 2024, the rights of all existing 
customers, including SMUD and customers receiving a new allocation from 
the initial resource pool under the Final Plan, will have a right to a 
resource extension equal to their pro-rata share of the Base Resource. 
To determine a customer's pro-rata share, each customer's percentage 
will first be adjusted based on the change in SMUD's percentage 
described earlier in this Section. All customers' percentages, 
including SMUD, will then be adjusted to accommodate the incremental 
resource pool as determined by Western, up to 2 percent.

B. Resource Pool Allocations:

    Western proposes to establish a resource pool by reserving a 
portion of the power available after 2004 for allocation to eligible 
new and existing customers. Western will apply the following to 
determine resource pool allocations.
    1. Resource Pool Amount: The resource pool will initially consist 
of up to 4 percent of the power resources available after 2004. This 
power will be subject to the terms and conditions specified in an 
electric service contract. An incremental resource pool is also 
proposed in the year 2014. The proposed incremental resource pool will 
consist of up to 2 percent of the power resources available after 2014, 
plus a portion of the resource that becomes available from adjusting 
SMUD's percentage. That portion will be equal to what SMUD would have 
been required to contribute to the initial resource pool. SMUD will 
also be subject to the 2 percent resource pool adjustment. Allocations 
for the incremental resource pool will be determined through a separate 
public process at a later date.
    Western will, at its discretion, allocate a percentage of the 
initial resource pool to individual applicants that meet the 
eligibility criteria. This allocation percentage will be multiplied by 
the resource pool percentage to determine the applicant's percentage of 
the power resource. Allocations from the resource pool are separate 
from the resource extension.
    2. General Eligibility Criteria: The following general eligibility 
criteria will be applied to all applicants seeking an allocation under 
the Final Plan.
    a. Applicants must meet the preference requirement under section 
9(c) of the Reclamation Project Act of 1939 (43 U.S.C. 485h(c)), as 
amended and supplemented.
    b. Applicants must be located within Sierra Nevada Region's 
Marketing Area. (Map of Marketing Area available upon request.)

[[Page 8717]]

    c. Applicants that require power for their own use must be ready, 
willing, and able to receive and use Federal power.
    d. Applicants that provide retail electric service must meet the 
requirements of Section IV.B.2.c above, and must require the power for 
electric service to their customers, not for resale to others.
    e. Applicants must submit an application in response to the notice 
calling for applications issued by Western in the Federal Register in 
conjunction with the Final Plan. That notice will include the deadline 
for receipt of those applications.
    f. Native American applicants must be a Native American tribe as 
defined in the Indian Self Determination Act of 1975 (25 U.S.C. 450b, 
as amended).
    g. Applicants must have a load of 1 MW or greater. Western will 
normally not allocate amounts less than 1 MW; however, smaller 
allocations may be considered, provided Western can aggregate the 
applicant's load with other loads to schedule and deliver an aggregated 
1 MW.
    3. General Allocation Criteria: The following general allocation 
criteria will be applied to all applicants seeking an allocation under 
the Final Plan.
    a. Allocations will be made in amounts as determined solely by 
Western in exercise of its discretion under Reclamation law.
    b. Allocations under the Final Plan will be available to new 
qualified applicants and to existing customers whose Extension CRD set 
forth in Appendix A is not more than 15 percent of their peak load in 
CY 1996 and not more than 10 MW.
    c. The maximum amount of capacity used to determine a resource pool 
allocation will be the applicant's peak demand during CY 1996 or the 
amount requested, whichever is less, rounded up to the nearest 100 kW.
    d. An allottee will have the right to buy power from Western only 
upon the execution of an electric service contract between Western and 
the allottee, and satisfaction of all conditions in that contract.
    e. A customer receiving power from the initial resource pool will 
be subject to the incremental resource pool adjustment in 2014.

V. General Criteria and Contract Principles

    Western proposes to apply the following criteria and contract 
principles to all new and/or existing customers' contracts, except that 
certain criteria may not apply to First Preference customers' 
contracts, under the Final Plan:
    A. Electric service contracts shall be executed within six (6) 
months of a contract offer, unless otherwise agreed to in writing by 
Western.
    B. Percentages shall be subject to adjustment in the future as 
provided for in the Final Plan and the electric service contract.
    C. All power supplied by Western will be delivered pursuant to a 
scheduling arrangement.
    D. All power will be provided on a take-or-pay basis. A commitment 
must be made to take-or-pay for the service as of the date set forth in 
the contract. All costs associated with the products and services 
provided, including ancillary services and optional purchases, will be 
passed on to the customer(s) using the product or service.
    E. Western will offer a contract amendment to existing customers 
and a new contract to new allottees to implement the Final Plan. 
Contract amendments and contracts shall require commitments to the Base 
Resource by the customer on or before December 31, 1999, and the 
optional purchase, as well as the Custom Product, on or before December 
31, 2001. This will allow for power resources and products to be 
developed prior to final commitment by the customer.
    F. Withdrawable power marketed under the Final Plan will be subject 
to withdrawal on a pro-rata basis upon six (6) months written notice, 
as determined by Western.
    G. Upon request, Western shall assist each allottee and existing 
customer in obtaining third-party transmission arrangements for 
delivery of power allocated under the Final Plan; nonetheless, each 
entity is ultimately responsible for obtaining its own delivery 
arrangements beyond the CVP transmission system.
    H. Contracts entered into under the Final Plan shall provide for 
Western to furnish electric service effective January 1, 2005 through 
December 31, 2024.
    I. Specific products and services may be provided for periods of 
time as agreed to in the electric service contract.
    J. Contracts entered into as a result of the Final Plan shall 
incorporate Western's standard provisions for power sales contracts, 
IRP, and GPCP.
    K. Contracts will include a clause that allows Western to reduce or 
rescind a customer's power from Western upon six (6) months notice if 
Western determines that the customer is not using this power to serve 
its own loads, except as otherwise specified in Section III.
    L. Any power not under contract may be allocated by the 
Administrator at any time, at the Administrator's sole discretion, or 
sold as deemed appropriate by Western.
    M. Contracts will include a clause providing for Western to adjust 
the customers' percentage of the resource for the incremental resource 
pool.

VI. First Preference Entitlement and Allocation

    The Trinity River Division Act (69 Stat. 719) and the New Melones 
Act of the Flood Control Act of 1962 (76 Stat. 1180) specified that 
contracts for the sale and delivery of the additional electric energy 
available from the CVP power system as a result of the construction of 
the plants authorized by these acts and their integration into the CVP 
system shall be made in accordance with preferences expressed in 
Federal Reclamation laws. These acts also provided that a first 
preference of 25 percent of the additional energy shall be given, under 
Reclamation law, to preference customers in the counties of origin 
(Trinity and Tuolumne and Calaveras) for use in those counties who are 
ready, able and willing to enter into contracts for the energy.
    In order to meet the requirements of these acts, Western published 
the Final Withdrawal Procedures at 51 FR 7702 on March 5, 1986. The 
Final Plan will supersede the Final Withdrawal Procedures.
    Western proposes to calculate and allocate the Maximum Entitlements 
of First Preference Customers (MEFPC), which is the maximum amount of 
energy available to First Preference customers/entities, in accordance 
with the following:
    A. The MEFPC will be calculated separately for the New Melones 
Project, Calaveras and Tuolumne counties, and the Trinity River 
Division, Trinity County, (First Preference Projects), to determine the 
25 percent of the additional energy made available to the CVP as a 
result of the construction of each of these projects. Since the acts do 
not specify the basis for calculating the 25 percent of additional 
energy, Western proposes that a previous 20-year average historical 
generation or actual years of data available, whichever time period is 
less, be used to determine the MEFPC. Based on the most current 
information available, this calculation would result in an estimated 
MEFPC of 95,766 MWh available to the CVP as a result of construction of 
the New Melones Project and an estimated MEFPC of 288,285 MWh available 
to the CVP as a result of construction of the Trinity River Division. 
The MEFPC will be

[[Page 8718]]

recalculated every five (5) years, with the initial recalculation 
pertaining to this Proposed Plan being completed by December 31, 2002.
    B. Upon recalculation, if the MEFPC from a First Preference Project 
is 10 percent above or below the currently effective MEFPC from that 
First Preference Project, the MEFPC will be adjusted to reflect that 
increase or decrease. Western will notify the affected First Preference 
customer(s) at least six (6) months prior to an adjustment being made 
to the MEFPC. Upon request, and at its discretion, Western may make 
purchases necessary to compensate for any power loss experienced by a 
First Preference customer due to recalculation of the MEFPC. The costs 
for all purchases made on behalf of a First Preference customer(s) will 
be passed on to that First Preference customer(s).
    C. An allocation made to a First Preference customer under the 
Final Plan will be based on the power requirements of that First 
Preference customer. The sum of allocations, including losses, shall 
not exceed the MEFPC from each First Preference Project, or a county of 
origin's share of the MEFPC, except as allowed under Section VI.G 
below.
    D. Following execution of a contract amendment or contract pursuant 
to the Final Plan, Western will work with each First Preference 
customer/entity to identify its power requirements and the best use of 
the First Preference entitlement for that First Preference customer. 
Each First Preference customer/entity may elect one of the options set 
forth below.
    1. Full Requirements: Power requirements (capacity and energy), 
adjusted for project use and transformation and transmission losses 
from the generation bus to the First Preference customer delivery 
point, will be at the Base Resource rates. Western will provide the 
First Preference customer full requirements up to its right to the 
MEFPC. Adjustment for transmission losses shall include losses for CVP 
transmission and third-party transmission. The contract between the 
First Preference customer and Western will include the appropriate 
losses and the load factor to be used to calculate the First Preference 
customer's maximum capacity and energy.
    2. Percentage: A portion of the MEFPC will be converted to a 
percentage of the Base Resource. This option will be served on a take-
or-pay basis. Each First Preference customer selecting this percentage 
allocation option will also be subject to the following:
    a. A commitment to this option must be made no later than December 
31, 2001. If a commitment is not made by December 31, 2001, the full 
requirements option will be deemed chosen.
    b. This option will be applied in a manner similar to that of the 
other customers receiving a power allocation from the CVP.
    c. The percentage allocation made to each First Preference customer 
under the Final Plan will be applied to the power resource which has 
been adjusted for project use and transformation and transmission 
losses from the generation bus to the First Preference customer 
delivery point, rounded up to the nearest 100 kW. Adjustment for 
transmission losses shall include losses for CVP transmission and 
third-party transmission.
    d. The percentage calculation will be based on a First Preference 
customer's load profile for the most recent 12 months preceding the 
percentage calculation.
    e. A First Preference customer may request an increase in its 
percentage allocation by notifying Western in writing at least seven 
(7) months in advance of the month in which the increase is to become 
effective (increases in percentages are effective the first day of a 
month).
    E. A First Preference entity may exercise its rights to use a 
portion of the MEFPC by providing written notice to Western at least 
eighteen (18) months prior to the anniversary date of the First 
Preference Project located in its county. Anniversary date means the 
successive fifth year anniversary of the date the Secretary of the 
Interior declared the availability of power from the powerplants in the 
counties of origin. New applications for services to begin on January 
1, 2005 under this Proposed Plan must be received eighteen (18) months 
prior to January 1, 2002 (i.e., July 1, 2000) for Trinity County and 
eighteen months prior to April 5, 2002 (i.e., October 5, 2000) for 
Calaveras and Tuolumne counties. Other anniversary years applicable to 
this Proposed Plan are 2007, 2012, 2017, and 2022.
    F. If the request(s) of First Preference customers/entities for 
power, including adjustments for project use and losses, becomes 
greater than the MEFPC from that county's First Preference Project, 
then Western will allocate the remaining MEFPC to the First Preference 
customer(s)/entity(ies) first making a request for a power allocation.
    G. Power allocated to First Preference customers/entities in 
Tuolumne and Calaveras counties will be subject to the following 
additional conditions:
    1. Tuolumne and Calaveras counties shall each be entitled to one-
half of the New Melones Project MEFPC.
    2. If First Preference customers in either Tuolumne County or 
Calaveras County are not using their county's full one-half share, and 
a First Preference customer/entity in the other county requests power 
in an amount exceeding that county's one-half share, then Western will 
allocate the unused power, on a withdrawable basis, to the requesting 
First Preference customer/entity. Such power may be withdrawn for use 
by a First Preference customer/entity in the county not using its full 
one-half share upon six (6) months written notice from Western.
    H. Trinity County is currently the sole recipient of the Trinity 
River Division's First Preference rights.
    I. For planning purposes, First Preference customers may be 
required to provide forecasts and other information required by Western 
as set forth in the electric service contract.
    J. The general criteria and contract principles set forth in 
Sections V.A, C, and F through J of this Proposed Plan will apply to 
First Preference customers.

VII. Transmission Service

    The Federal Energy Regulatory Commission (FERC) issued two closely 
related final rules. The first rule, Order No. 888, issued April 24, 
1996 (Docket Nos. RM95-8-000 and RM94-7-001), requires public utilities 
owning, controlling, or operating transmission lines to file 
nondiscriminatory open access tariffs that offer others the same 
transmission service they provide themselves. The second rule, Order 
No. 889, issued April 24, 1996 (Docket No. RM95-9-000), requires public 
utilities to implement standards of conduct and an Open Access Same-
time Information System (OASIS) to share information about available 
transmission capacity. Western has agreed to follow the spirit and 
intent of FERC Orders 888 and 889. Therefore, Western proposes to 
provide transmission services separately from power services. Sierra 
Nevada Region's transmission capability will be offered as a separate 
unbundled service to all preference customers receiving power pursuant 
to the Final Plan. Each customer will have an option to purchase 
transmission sufficient to deliver the maximum amount of power it 
receives under the Final Plan. Surplus transmission will be available 
to all

[[Page 8719]]

preference customers, as well as to other entities.

    Issued in Washington, DC on February 19, 1997.
Joel K. Bladow,
Assistant Administrator.

              Appendix A.--Existing Customers' CRD Amounts              
------------------------------------------------------------------------
                                                           Extension CRD
                                          CRD \1\ (as of   1 2 (CRD less
           Existing customers              proposed plan  excluded types
                                            publication    of power) 3 4
                                            date) (kW)         (kW)     
------------------------------------------------------------------------
Air Force--Beale........................          21,575          21,575
Air Force--McClellan....................          12,000          12,000
Air Force--Onizuka......................           1,500           1,500
Air Force--Travis.......................          12,651          12,651
Air Force--Travis / David Grant Medical                                 
 Center.................................           4,000           4,000
Air Force--Travis Wherry Housing........           1,400           1,400
Alameda, City of........................          21,145          21,145
Arvin-Edison Water Storage District.....          30,000          30,000
Avenal, City of.........................             622             622
Banta-Carbona Irrigation District.......           3,700           3,700
Bay Area Rapid Transit District.........           4,000           4,000
Biggs, City of..........................           4,200           4,200
Broadview Water District................             500             500
Byron-Bethany Irrigation District.......           2,200           2,200
Calaveras Public Power Agency...........           7,000  ..............
California State University, Sacramento--                               
 Nimbus.................................              40              40
Castle Joint Powers Authority...........           3,000  ..............
Cawelo Water District...................             500             500
Corrections--California State Prison-                                   
 Sacramento.............................           2,300           2,300
Corrections--Deuel Vocational Institute.           1,700           1,700
Corrections--Northern California Youth                                  
 Center.................................           1,700           1,700
Corrections--Sierra Conservation Center.           3,000  ..............
Corrections--Vacaville Medical Facility.           1,800           1,800
Defense Logistics Agency--Sharpe                                        
 Facility...............................           4,000           4,000
Defense Logistics Agency--Tracy Facility           3,800           3,800
Delano-Earlimart Irrigation District....             987             987
East Bay Municipal Utility District.....           1,965           1,965
East Contra Costa Irrigation District...           2,000           2,000
East Contra Costa Irrigation District,                                  
 P.P. #3................................             500             500
Energy--Lawrence Berkeley National                                      
 Laboratory.............................          11,000          11,000
Energy--Lawrence Livermore National                                     
 Laboratory.............................          16,711          16,711
Energy--Site 300........................           2,500           2,500
Energy--Stanford Linear Accelerator                                     
 Center.................................          47,403          38,403
Glenn-Colusa Irrigation District........           3,343           3,343
Gridley, City of........................           9,400           9,400
Healdsburg, City of.....................           3,241           3,241
James Irrigation District...............             987             987
Kern-Tulare Water District..............             987             987
Lassen Municipal Utility District.......           3,000           3,000
Lindsay-Strathmore Irrigation District..             987             987
Lodi, City of...........................          13,236          13,236
Lompoc, City of.........................           5,197           5,197
Lower Tule River Irrigation District....           1,965           1,965
Modesto Irrigation District.............          10,805          10,805
NASA--Ames Research Center..............          80,000          80,000
NASA--Moffett Federal Airfield..........           5,009  ..............
Navy--Concord Weapons Station...........           2,398           2,398
Navy--Dixon Radio Station...............             915             915
Navy--Lemoore Air Station...............          18,000          18,000
Navy--Mare Island Shipyard..............           6,000           6,000
Navy--Oakland Army Base.................           2,275           2,275
Navy--Oakland Supply Center.............           7,000           7,000
Navy--Stockton Communications Station...           3,700           3,700
Navy--Treasure Island Station...........           4,000           4,000
Palo Alto, City of......................         175,000         175,000
Parks & Recreation, California                                          
 Department of--Folsom..................             100             100
Parks Reserve Forces Training Area......             500             500
Patterson Water District................           2,000           2,000
Plumas-Sierra Rural Electric Cooperative          25,000          25,000
Provident Irrigation District...........             750             750
Rag Gulch Water District................             500             500
Reclamation District 2035...............           1,600           1,600

[[Page 8720]]

                                                                        
Redding, City of........................         116,000         116,000
Roseville, City of......................          69,000          69,000
Sacramento Municipal Utility District\5\         361,000         361,000
Sacramento Municipal Utility District...         100,000  ..............
San Juan Water District.................           1,000           1,000
San Luis Water District-Fittje..........           3,250           3,250
San Luis Water District-Kaljian.........           3,400           3,400
Santa Clara, City of....................         216,532         136,532
Santa Clara Valley Water District.......             987             987
Shasta Lake, City of....................          11,450          11,450
Sonoma County Water Agency..............           1,500           1,500
Terra Bella Irrigation District.........             987             987
Trinity County Public Utilities District          17,000  ..............
Tuolumne Public Power Agency............           7,000  ..............
Turlock Irrigation District.............           3,941           3,941
Ukiah, City of..........................           8,773           8,773
University of California, Davis.........          14,682          14,682
West Side Irrigation District...........           2,000           2,000
West Stanislaus Irrigation District.....           5,200           5,200
Westlands Water District, Assumed Point                                 
 of Delivery............................           6,684           6,684
Westlands Water District, Pumping Plant                                 
 #7-1...................................           3,200           3,200
Westlands Water District, Pumping Plant                                 
 #6-1...................................           1,850           1,850
Temporarily unallocated NDA Act power...           5,500           5,500
                                         -------------------------------
                                               1,580,230       1,349,221
------------------------------------------------------------------------
Notes:                                                                  
\1\ CRD temporarily laid off and reallocated to other existing customers
  is reflected in this Appendix A, under both CRD and Extension CRD, as 
  being returned to the existing customer who received the original     
  allocation.                                                           
\2\ The Extension CRD will be reduced if an existing customer is not    
  using its full CRD (based on the peak demand experienced during CY    
  1997 through 2000).                                                   
\3\ Exclusions are Diversity and Curtailable Power, peaking/excess      
  capacity, First Preference entitlements, and NDA Act power not used   
  for military loads.                                                   
\4\ May be adjusted for conversion from project use power to preference 
  power due to Federal facility transfers to existing project use       
  customers.                                                            
\5\ Sacramento Municipal Utility District's Extension CRD will be       
  360,000 kW if the 360/1,152 ratio is used for resource extension      
  purposes.                                                             

Appendix B--Examples of Existing Customers' Resource Extension Proposal 
2005 Through 2014
    Assumptions:
     An existing customer with an Extension CRD of 100 MW.
     Base Resource after 2004 is 1000 MW.
     Sum of all existing customers' Extension CRD is 1,349 MW.
     Initial resource pool is 4%.
     Incremental resource pool is 2%.
     All amounts are rounded.
    1. For the period 2005 through 2014, an existing customer's 
percentage right to a resource extension will be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TN26FE97.005

Where:
A=Lessor of individual existing customer's (excluding SMUD) Extension 
CRD as of December 31, 2001; or 104 percent of their maximum demand 
during CY 1997 through 2000. Western reserves the right to adjust the 
value of ``A'' when it is determined that the maximum demand is not 
reflective of an existing customer's load.
B=The sum of all values for ``A''.
BR=Base Resource available.
ABR=Adjusted Base Resource
[GRAPHIC] [TIFF OMITTED] TN26FE97.006


[[Page 8721]]


RP%=Resource pool percentage.
Calculation:
SMUD's purchase rights=
    (360/1,152) x BR
    (360/1,152) x 1,000
    0.3125 x 1,000
    312.5 MW
Existing 100 MW customer's purchase rights=
    (A/B) x ABR
    (100/988) x ABR
    0.101 x 660
    67 MW
ABR=
    {BR-[(360/1,152) x BR]} x (100%-RP%)
    {1,000-[(360/1,152) x 1,000]} x (100%-4%)
    [1,000-(0.3125 x 1,000)] x 96%
    (1,000-312.5) x 96%
    687.5 x 96%
    660 MW
    2. Existing customer's (excluding SMUD) rights to the optional 
purchase will be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TN26FE97.007

Where:

A = Lessor of individual existing customer's Extension CRD as of 
December 31, 2001; or 104 percent of their maximum demand during CY 
1997 through 2000. Western reserves the right to adjust the value of 
``A'' when it is determined that the maximum demand is not reflective 
of an existing customer's load.
B = The sum of all values for ``A''.
C = The sum of all existing customers', including SMUD, Extension CRD.
BR = Base Resource available.
RP% = Resource pool percentage.
TOP = Total optional purchase
[GRAPHIC] [TIFF OMITTED] TN26FE97.008

Calculation:
Individual existing 100 MW customer's optional purchase=
    (A/B  x  TOP
    (100/988)  x  TOP
    0.101  x  43.1
    4.4 MW
TOP=
    {[(360/1,152)-(361/1,349)]  x  BR}  x  (100%-RP%0)
    {[(360/1,152)-(361/1,349)]  x  1,000}  x  (100%-4%)
    [(.3125-0.2676)  x  1,000]  x  96%
    (0.0449  x  1,000)  x  96%
    44.9  x  96%
    43%
[FR Doc. 97-4695 Filed 2-25-97; 8:45 am]
BILLING CODE 6450-01-P