Record of Decision for the Sierra Nevada Customer Service Region 2004 Power Marketing Program

DEPARTMENT OF ENERGY

Western Area Power Administration

[DOE/EIS-0232]

Record of Decision for the Sierra Nevada Customer Service Region

2004 Power Marketing Program

AGENCY: Western Area Power Administration, DOE.

ACTION: Record of Decision.

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SUMMARY: The Department of Energy (DOE), Western Area Power

Administration (Western), has decided to develop and implement a

marketing program for marketing Federal electric power resources from

the Central Valley Project (CVP) after year 2004 that is within the

range of the actions defined in Western's preferred alternative

described in the 2004 Power Marketing Program Final Environmental

Impact Statement (final 2004 EIS). In making this decision, Western has

considered all comments received on its alternatives and the analysis

contained in the 2004 Power Marketing Program Draft and Final

Environmental Impact Statements (2004 EIS) issued for the project (DOE/

EIS-0232) in May 1996 and March 1997, respectively. The program for

marketing Federal electric power resources from the CVP is being

developed through a public process now underway pursuant to the

Administrative Procedure Act (APA). Although the marketing of Federal

power from the Washoe Project (Washoe) may change, operations of

Stampede Reservoir and generating facilities will not, so no

environmental effects are expected from marketing program changes at

this facility.

Western's 2004 EIS evaluated alternatives that cover the reasonable

range of options for marketing CVP and Washoe power. The analyses of

the environmental effects of these alternatives bracket the greatest

possible range of potential impacts which could occur. The 2004 Power

Marketing Program Draft Environmental Impact Statement (draft 2004 EIS)

analyzed four alternatives: (1) no action (continue present approach of

marketing CVP

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power), (2) maximize CVP hydropower peaking capability, (3) operate CVP

in a base-loaded mode (relatively constant power output), and (4) a

renewable case involving the purchase of 50 megawatts (MW) of power

from renewable resource generation sources. In the baseload and peaking

alternatives, the effects of various levels of power purchases from 0

to 900 MW were also analyzed for potential environmental effects.

Western's final 2004 EIS analyzed a fifth alternative identified as

Western's preferred alternative. It addressed CVP operations similar to

the maximized peaking alternative, except in Western's preferred

alternative CVP hydropower resources and Federal power customers'

resources are dispatched together in an integrated (economically

optimized) fashion, and each customer is allowed to choose the level of

firming purchases they would like Western to make to supplement the

hydropower generation.

The 2004 EIS did not identify any environmental effects associated

with Western's preferred alternative. Therefore, a monitoring program

or mitigation measures is not warranted.

DATES: Decision is effective April 11, 1997.

FOR FURTHER INFORMATION CONTACT: Mr. Jerry Toenyes, 2004 EIS Project

Manager, Sierra Nevada Region, Western Area Power Administration, 114

Parkshore Drive, Folsom, CA 95630-4710, (916) 353-4455.

SUPPLEMENTARY INFORMATION: The hydroelectric generation facilities of

the CVP are operated by the Bureau of Reclamation (Reclamation).

Reclamation manages and releases water in accordance with the various

acts authorizing specific projects and with other laws, permits, and

enabling legislation. The authority to market Federal electric power,

set rates for the power, and construct and operate transmission

facilities was transferred from the Department of the Interior (DOI) to

DOE through enactment of the Department of Energy Organization Act of

1977 (Public Law 95-91). Western is a power marketing administration

within DOE created to carry out Federal power marketing

responsibilities. Western's power marketing responsibility includes

managing the Federal power transmission system, scheduling power

production, and marketing the power produced. The Sierra Nevada Region

(SNR), with a marketing area covering most of northern and central

California and Nevada, currently markets approximately 1,480 MW of

power from the CVP in California and other sources, and available

nonfirm energy from Washoe.

All existing long-term CVP sales contracts expire on December 31,

2004. SNR has examined the environmental effects of alternative ways to

fulfill its responsibilities to market CVP and Washoe hydropower in its

2004 EIS. The 2004 EIS examined the impacts of alternatives related to

(1) The level and character of capacity, energy, and other services to

be marketed beyond 2004; and (2) establishment of eligibility and

allocation criteria for the allocations of electric power resources to

be marketed under contracts that will replace those expiring in 2004.

In implementing its proposed action, SNR desires to achieve a balanced

mix of purposes. The purposes of the proposed 2004 power marketing plan

are listed below:

To be consistent with SNR's statutory and other legal

constraints,

To provide long-term resource and contractual stability

for SNR and for customers contracting with SNR,

To provide the greatest practical value of the power

resource to SNR and to customers contracting with SNR,

To protect the human and natural environment,

To be responsive to future changes in the CVP, Washoe, and

the utility industry.

Western prepared its 2004 EIS in compliance with the National

Environmental Policy Act of 1969 (NEPA) (42 USC 4321, et seq.), the

Council on Environmental Quality regulations for implementing NEPA (40

CFR Parts 1500-1508), and the DOE regulations for compliance with NEPA

(10 CFR Part 1021) to describe the potential environmental consequences

of the range of reasonable marketing program alternatives.

Public Involvement

SNR developed a public involvement plan early in the evolution of

the 2004 EIS process. The public involvement plan was designed to guide

SNR through a collaborative and systematic decision-making process and

facilitate input from the public and interested parties and agencies.

The primary purposes of public involvement, as set out in the public

involvement plan, were to:

Inform the public,

Gather information from the public to identify public

concerns and values, and

Responsibly address stakeholder input regarding

environmental and allocation concerns and consider such input in

decision making.

Through SNR's public involvement process, an extensive effort was

made to notify all potentially interested parties about the 2004 EIS

and opportunities for involvement. Approximately 25 prescoping

stakeholder meetings (involving customers, agencies, interested groups,

and individuals) were informally held during the summer of 1993 to

provide information and to discuss issues and concerns related to the

project. An interested parties mailing list was used to keep track of

those showing an interest in the project. The list was expanded to

include any new interested parties as they were identified. The Federal

Register notice of the scoping period was published on August 10 and

13, 1993 (58 FR 42536 and 58 FR 43105). In conjunction with the notice,

a news release was sent to local newspapers, and scoping invitation

letters were mailed to those on the interested parties mailing list.

Three public scoping meetings were held in August and September 1993 to

receive written and verbal comments on environmental and marketing-

related issues. SNR held two more public meetings to facilitate

information sharing and to obtain further public comment: an Issues and

Alternatives Public Workshop on May 18, 1994, and an Alternatives

Workshop on January 18, 1995. The draft 2004 EIS was distributed to

interested parties and agencies for public review and comment. Notice

of availability of the draft 2004 EIS was published in the Federal

Register on May 24, 1996 (61 FR 26174 and 61 FR 26177). A public

hearing concerning the draft 2004 EIS was held on June 13, 1996. The

public comment period for the draft 2004 EIS closed on July 31, 1996.

Additionally, public information and involvement opportunities were

supplemented by 12 separate mailings of the project informational

bulletin, the 2004 EIS Update, designed to keep all interested groups

and individuals apprised of project details and scheduled events.

The final 2004 EIS was distributed to the public beginning in late

February 1997. The Environmental Protection Agency (EPA) notice of

availability was published on March 7, 1997 (62 FR 10559).

Description of Alternatives

In developing alternatives for the 2004 EIS, SNR focused on six key

component groups--key elements of the marketing program--that vary

across the alternatives. SNR's intent in establishing the ranges for

the variable components was to use a ``tent stakes'' approach to

constructing alternatives. Using this approach, the alternatives were

designed to cover the range of reasonable options and thus the

[[Page 22936]]

analyses of their environmental effects would bracket the range of

potential impacts. Although the final marketing plan, after completion

of the public process, may not be identical with any one of the 2004

EIS alternatives, the values for the final plan and its components will

be within the range considered and its impacts will fall within the

range of impacts assessed.

The six key component groups that are varied in the analysis of

alternatives include the following:

(1) Baseload Operations--Within the operational constraints

established by DOI, this refers to releasing water from hydroelectric

facilities to generate electricity at a relatively constant rate. This

approach would emphasize a steady water release rate from dams above

regulating reservoirs.

(2) Peaking Operations--Within the operational constraints

established by DOI, this refers to storing and releasing water from

hydroelectric facilities to generate electricity during the relatively

short period of maximum demand. This approach would emphasize periodic

water releases from dams above regulating reservoirs timed to produce

electricity when it is most needed.

(3) Power Purchases--These refer to SNR power purchases used to

supplement the Federal hydroelectric resource. Purchases were assumed

to be made from markets in California, the Pacific Northwest, and the

Desert Southwest. For purposes of modeling and analysis in the 2004

EIS, purchase levels of 0 MW, 450 MW, and 900 MW, each at capacity

factors up to 15 percent and 85 percent, are assumed. The no-action

alternative has an approximate average monthly purchase level of about

478 MW assuming average hydrologic conditions and no contractual

interchanges or exchanges.

(4) Renewable Resources--These resource types are emphasized in one

alternative and could be acquired through either selective purchases or

allocations of Federal resources to SNR's customers active in

developing renewable resources.

(5) Power Cost Analysis--This refers to analyzing cost impacts to

SNR's customers from combining the costs for purchases with SNR's

hydropower resources (aggregated), or treating these resources

individually, each with its own cost (disaggregated).

(6) Allocation to Customer Groups--This refers to assessing the

impacts of changing the quantities of power that customer groups

currently receive from the SNR. For 2004 EIS analysis purposes,

customers were divided into the following three groups, with the

customers in each group having similar load characteristics: utilities,

agriculture, and other (such as State and Federal agencies).

Nonvariable and independent components were identified which do not

vary across alternatives; therefore, the environmental effects

attributable to these components are constant under all alternatives.

Nonvariable and independent components include eligibility criteria,

first preference, preference, marketing area, delivery conditions,

transmission requirements, minimum load requirements, executed contract

requirements, alternative financing arrangements, termination

provisions, and standard provisions. Such components may be included in

the proposed 2004 power marketing plan. Because they are already

included in SNR's present activities, they represent no change from the

no-action alternative. Environmental impact analyses in the 2004 EIS

focus on those components that vary across the alternatives. Constant

effects associated with nonvariable and independent components were

included in the overall impact assessment.

Components that were analyzed in the Western's 1995 Energy Planning

and Management Program (EPAMP) EIS (Record of Decision for EPAMP EIS

was published October 12, 1995, 60 FR 53181) were not analyzed in the

2004 EIS. These components include contract length, power planning

requirements (such as integrated resource planning for customers),

withdrawal provisions, and contract adjustment provisions.

An analysis of allocations to customer groups was done to

characterize the impacts that may result from changing the quantity of

resources available to different customer groups. Such changes may

result if SNR emphasizes sales to a particular type of customer

(utility, agricultural, or other) or encourages special actions, such

as acquiring renewable resources, or customer allocations change due to

resource availability or marketing options. In the analysis, customer

allocations are both increased and decreased for each customer group.

This approach captures the range of beneficial and negative impacts

that may result from changes affecting a particular customer group.

Four alternatives structured around operations of the CVP

hydroelectric system were developed for analysis in the draft 2004 EIS.

The alternatives were refined following completion of the draft 2004

EIS and receipt of public comments. The key change from the draft 2004

EIS affecting alternative structure is the treatment of the energy

market assumed for 2005. In the draft 2004 EIS, each of the

alternatives incorporated varying levels of firm capacity purchases at

different capacity factors. In these types of contracts, Western would

be required to purchase the energy and capacity even if it were not

needed or if it were not the most economic purchase available at any

given time.

Description of Draft 2004 EIS Alternatives

The four original alternatives include the following:

The no-action alternative refers to a continuation of

SNR's present approach to marketing power, meeting 2005 loads that are

comparable to SNR's 1996 load patterns. Within operating constraints,

hydropower facilities are operated close to maximum peaking. For

modeling purposes the no-action alternative includes an average monthly

purchase of about 478 MW assuming average hydrologic conditions and no

contractual interchanges or exchanges.

Maximize hydropower peaking (the peaking alternative)

refers to operating the CVP hydropower facilities to maximize power

generation during peak load periods within operating constraints.

Federal CVP hydropower is dispatched first, before any customer

hydropower resources. Five purchase cases were considered including no

power purchases, 450 MW at 15-percent capacity factor, 450 MW at 85-

percent capacity factor, 900 MW up to a 15-percent capacity factor, and

900 MW up to an 85-percent capacity factor.

The baseload alternative refers to operating the CVP

hydropower facilities for relatively constant power output within

operating constraints. The same five purchase cases were examined as

with the peaking alternative described above.

Renewable resource acquisition (the renewables

alternative) refers to operating the CVP hydropower facilities to

maximize power generation during peak load periods within operating

constraints, and power purchases were set at 50 MW of capacity to

support the use of renewable resources. Generation was assumed to be

equally distributed among biomass, wind, solar and geothermal

facilities. A sensitivity test was run without biomass in the resource

mix for purposes of analyzing air quality and non-CVP impacts of land

use, water quality, and wastes.

Changes to Alternatives in the Final 2004 EIS

Because of utility industry restructuring presently taking shape

nationally and in California, in the final 2004 EIS the energy market

is assumed to operate with open access for both

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wholesale and retail customers. Further, power could be purchased on an

hourly basis, as needed. Because of this flexibility, when Western

makes purchases, it is unlikely that customers would make a similar

purchase to meet the same need. In addition, because both Western and

its customers would have equal access to the market, purchases would be

under similar terms and conditions. Thus, a purchase by Western would

be offset by purchases foregone by Western's customers and vice versa.

The results of these assumptions about equal access and hourly pricing

include the following:

Purchase levels described in the alternatives would be the

maximum purchased in any 1 hour by the SNR.

SNR could purchase up to the maximum capacity factor noted

but need not purchase more than it requires.

All purchases in the final 2004 EIS are assumed to be made

from power markets. The SNR's market costs would be passed on to its

customers, meaning there would be no difference between an SNR purchase

and a customer's direct market purchase. The no purchase option

represents the effects of SNR disaggregating costs associated with any

purchases. Purchase options were also analyzed on an aggregated basis.

For renewable resources, the final 2004 EIS assumed that prices

incorporating technological advancements will be available in 20

percent of the renewable resources that would be available in 2005.

This assumption was based on the Western System Coordinating Council

1995 Summary of Estimated Loads and Resources. The final 2004 EIS

analyses placed the amount of capacity from renewable resources that

could be economically supported at 50 MW.

Western's Preferred Alternative

In the final 2004 EIS, Western's preferred alternative was

described and analyzed. The preferred alternative is similar to the

maximum peaking alternative. In this alternative additional power will

be purchased if requested by customers to meet their load requirements.

This alternative was chosen to provide the greatest flexibility to meet

customer needs in making purchases and to economically optimize the

operation of Western's and its customers' power resources.

Environmentally Preferred Alternative

The maximum peaking alternative was also determined to be the

environmentally preferred alternative. This alternative was so

designated because it would provide the greatest load-carrying capacity

and best offset the need for additional powerplants. This alternative

generally results in the greatest benefits or least impacts to the

environment when impacts are quantified. Peaking with no purchases

results in the greatest environmental benefits.

Environmental Consequences

The impact analyses followed three basic steps. Historic

hydrological conditions were analyzed using the PROSIM (CVP simulation

model) model. The PROSIM outputs (in the form of monthly water flows

and available hydropower capacity and energy) were input to the PROSYM

model, a production cost simulation model of electric utility

operations. PROSYM outputs (in the form of estimated levels of electric

generation, production costs, and hourly water flows in the CVP) were

used to assess the environmental impacts.

The manner in which hydropower generating plants would be operated

is one of the fundamental differences across the alternatives. The

PROSYM analyses show that, when operated to provide electricity at peak

times (the peaking alternative), the hydropower system can offset up to

317 MW of electric generating capacity from other sources when compared

to the no-action alternative. The replacement capacity needed to offset

the difference between the baseload and no-action alternatives is 581

MW of load-carrying capacity. The amount of replacement capacity needed

to offset capacity losses from any alternative when compared to the no

action alternative is an important vector identified in the analyses

for determining the extent of possible impacts. Building new capacity

causes land-use impacts and uses physical, natural, and financial

resources needed to build the powerplant and connect it with the

interconnected transmission grid. Western is not presently planning to

build such a powerplant, but Western's actions could cause such a

powerplant to be constructed if the baseload alternative were selected.

The CVP hydropower system does not require additional facilities or

modifications to change from baseload to peaking operations or vice

versa. Thus, the lost load-carrying capacity from baseload operations

would be retrievable for CVP operations if a decision to subsequently

implement peaking operations was made. However, if the baseload

alternative is implemented and replacement capacity is built,

replacement capacity is expected to remain in place. If this occurs, a

potential shift from baseload back to peaking CVP operations would

likely result in temporary surplus capacity in the region.

Impacts resulting from CVP water releases within SNR's discretion

are limited. In comparison to the no-action alternative, the peaking

alternative results in only slightly greater pool-level fluctuation in

regulating reservoirs. Impacts are restricted to the regulating

reservoirs at Lewiston, Keswick, Lake Natoma, and Tulloch because the

regulating dams are operated to control releases downstream. The

baseload alternative would result in constant water releases from the

main dams that would avoid pool-level fluctuation and potentially

improve recreation and resident fisheries slightly in the regulating

reservoirs.

The hourly water releases from the main dams, whether operating for

peaking or baseload, affect temperature fluctuation a very minor

amount. The temperature differences are so small that, although they

can be calculated, they could not be measured in the regulating

reservoirs or the rivers downstream.

Given these findings about pool-level and temperature fluctuations,

in comparison with the no-action alternative, no alternative would

result in adverse impacts to fisheries, threatened and endangered

species, recreation, the terrestrial environment, or cultural

resources.

The more constant flows of the baseload alternative may result in

minor beneficial effects to fisheries, recreation, and cultural

resources associated with the regulating reservoirs. A reduction in

pool-level fluctuation may improve habitat for resident fish and

improve boating conditions. Stable pool elevations could also reduce

erosion at shoreline cultural resource sites, but may increase exposure

to other sources of erosion such as wave action.

Impacts to air quality, solid waste, and wastewater would be

related to the generation of electricity at powerplants apart from the

CVP. The variation across the alternatives comes from changes in

operation of combustion turbines (CTs) and combined-cycle combustion

turbines that may be located throughout northern and central

California, the Pacific Northwest, or the Desert Southwest. The most

substantial air quality impacts would come from changes in hourly

operations of other nonhydropowerplants in response to the manner in

which the CVP hydroelectric facilities are scheduled (peaking or

baseload). Generally, compared to the no-action alternative, scheduling

the hydropower system as a baseload system would result in an increase

of

[[Page 22938]]

emissions from other powerplants during the day when ambient levels are

high because thermal generation would be needed for peaking. Peaking

the hydropower system offsets daytime thermal production and reduces

daytime emissions, but increases nighttime thermal production and

emissions, when ambient levels are less. This can be important for

areas having problems meeting air quality standards during summer

afternoons when industrial, utility, and transportation emissions are

at their peak. During summer afternoons, the difference in oxides of

nitrogen emissions between the peaking and baseload alternatives would

reach over 400 pounds per hour. These emissions are equivalent to those

from a 400-MW combustion turbine plant.

Without biomass, the renewables alternative results in the most

beneficial effects on annual air emissions. Including biomass with the

other renewables sources in the renewables alternative would produce

the greatest levels of annual air emissions.

In comparison with the no-action alternative, all of the other

alternatives would result in beneficial effects on wastewater

production. As with annual air emissions, the renewables alternative

without biomass would result in the greatest benefit in reducing

wastewater production. Renewables with biomass would produce the least

benefit but would still result in a reduction in wastewater production

in comparison with the no-action alternative.

Solid waste production also would be most changed by the renewables

alternative. Biomass-fueled plants that burn municipal solid waste

produce a great deal of ash as solid waste but also reduce the quantity

of solid waste requiring disposal in a landfill. For every pound of ash

produced by biomass combustion, municipal solid waste is reduced by

about 5 pounds. When this reduction is taken into account, solid waste

would be reduced by nearly 40,000 tons with the renewables alternative.

In comparison, the other alternatives (including renewables without

biomass) are very similar to the no-action alternative.

The baseload alternative results in about 90 acres of land needed

for replacement capacity. The renewables alternative would result in

land-use impacts. Renewables, such as solar photovoltaic and wind, may

require up to about 30 times the land area per megawatt of capacity of

thermal resources such as CTs. In comparison to the no-action

alternative, the renewables alternative would require an additional 70

to 90 acres of land for powerplants.

SNR's 2004 power marketing plan would influence the overall power

costs of its customers. The alternatives were structured to determine

the maximum range of impacts to gauge socioeconomic effects in the

areas of output, employment, and labor income. When compared to the

economy of northern and central California, or of any one of four

economic regions analyzed within northern and central California, the

estimated impacts are very small. Based on results from the power

production cost analysis described in Section 4.2 of the 2004 EIS, the

associated economic impacts of the alternatives are nearly

indistinguishable in all cases and in all regions. The economic effects

of the preferred alternative and all other alternatives are not

significant; however, some indication of their positive or negative

direction is possible. Western's preferred alternative results in

economic impacts that are slightly positive in comparison to the no-

action and the peaking alternatives.

All of these socioeconomic effects reflect averaging across regions

and customer groups and do not capture the effects on individual

customers. Economic effects on SNR's customers who lose or gain

allocations may be substantial in individual cases but cannot be

determined because specific allocations have not been made. In general,

however, customers who lose allocations would be balanced by other

customers who gain equivalent allocations. Specific allocations will be

made in a separate public process under the APA.

Across the alternatives and the affected economic regions, economic

impacts are minimal, and are not disproportional across income or race

groupings of the population. In the case of agriculture customers, low-

income and minority groups make up a larger proportion of the

employment in that sector. The impacts identified do not affect

agricultural gross revenues or production levels. Thus, employment

levels are not affected, and the impacts of alternatives do not

disproportionately affect low-income or minority groups.

The effects of emphasizing the use of renewable resources (assuming

technological improvements) in the generation mix have a negative

economic impact compared to the same quantity of thermal purchases.

Improvements in technology should occur prior to 2005 that reduce the

cost of the renewable resources. The amount of renewables to be

included in the renewables alternative was determined by melding the

anticipated cost of renewables in 2004 together with the anticipated

2004 hydropower cost. The renewables share of the mix was increased

until the combined rate for SNR energy equaled the anticipated market

rate in 2004. This resulted in melding the CVP hydropower operated to

maximize peaking with 50 MW of renewable resource purchases.

Summary of Public Comments

A number of comments were provided by agencies, stakeholders, and

the public during the public review period of the draft 2004 EIS. Some

customers suggested that SNR may have underestimated the future cost of

energy generated from renewable resources and overestimated the market

price of power in post-2004 projections in the draft 2004 EIS. It was

also suggested this may have resulted in SNR's projections of

unrealistically high amounts of renewable resource power in its future

resource mix. Comments also noted a concern to reflect the most current

industry developments. Western revised these estimates in the final

2004 EIS, provided updated model assumptions and the analysis of

alternatives to more accurately represent these developments. The

resulting decision takes these factors into account.

More information was requested on how alternatives would be formed

into a cohesive power product, including purchase levels and capacity

factors that are specifically tailored to customer needs. Western will

be able to better identify these products as they are addressed within

the APA process. The final 2004 EIS focused on the environmental

impacts from the resources needed to develop products and services. The

final 2004 EIS identified the most aggressive range of actions possible

to determine the potential boundaries of environmental effects and to

establish a high degree of flexibility for Western's decisions.

Another comment requested that referenced documents, such as the

EPAMP EIS, be summarized in the final 2004 EIS. Western added

information to better describe the findings of referenced documents.

Some comments pointed out errors and differences of perception in

the descriptions of various CVP facilities and operations. These errors

and differences were corrected or explained in the final 2004 EIS.

Concerns were raised about the level of detail given to the

analysis of customer group allocations and to results for the utility

customer group. Refinements in modeling to better reflect the changing

utility industry addressed these issues.

[[Page 22939]]

Decision

Western has decided to develop and implement a marketing program

for marketing Federal electric power resources from the CVP and Washoe

that is within the range of actions defined in Western's preferred

alternative described in the 2004 EIS, to replace power contracts

expiring in the year 2004. This alternative is based on peaking the

hydropower system in an integrated (economically optimized) fashion

with Western's customer's hydropower resources. In addition, each

customer can choose the level of firming purchases it would like

Western to make on its behalf to supplement the CVP hydropower

generation. Although the marketing of Federal power from Washoe may

change, operation of the Stampede Reservoir and generation facilities

will not, so no environmental effects are expected. The modified

program for CVP power will apply to power marketing contracts

superseding those that expire December 31, 2004. Western's preferred

alternative falls within the tent stakes established in the 2004 EIS,

and is the alternative selected in the development of Western's

proposed 2004 power marketing plan.

Rationale

Western's decision considered comments received from customers and

stakeholders throughout the processes and the analyses related to the

draft and final 2004 EIS that were issued for the project (DOE/EIS-

0232) in May 1996 and March 1997, respectively. This decision is within

the scope of the alternatives discussed in the final 2004 EIS and

addresses concerns by customers and stakeholders in those documents.

The environmental effects of the environmentally preferred and the

agency preferred alternatives are nearly identical, although the

selected alternative provides economic advantages over the

environmentally preferred alternative.

A 2004 Power Marketing Plan is needed to fulfill Western's Federal

power marketing responsibilities to market Federal CVP power beyond the

year 2004.

In addition, the purpose and need for the 2004 EIS provides factors

which were used to gauge the alternatives. The purposes and their

relationship with the alternatives and other analyses are described in

the following sections and summarized in Table 1.

Legal Obligations

The first of the listed purposes was met by all of the

alternatives. This first purpose reads as follows: to be consistent

with SNR's statutory and other legal obligations. This purpose does not

favor any one alternative and is met by the decision.

Resource and Contractual Stability

The second purpose to provide long-term resource and contractual

stability for SNR and for customers contracting with SNR applies to

contract length and the quantity of resources that are allocated to

customers. Both issues were analyzed in the EPAMP EIS. The EPAMP EIS

analysis found that longer-term contracts reduced uncertainty in power

planning and were of greater value to Western's customers. All of the

alternatives could have been implemented with different contract

lengths.

The 2004 EIS analyzed impacts from extreme changes in allocations

to customer groups. The 2004 EIS analysis found that the most adverse

effects on cost and socioeconomic effects come from reducing

allocations to the utility customer group. Reducing the allocation to

the utility customer group to nothing results in adverse socioeconomic

effects.

The EPAMP EIS also analyzed reducing allocations of available

resources in order to create resource pools. These pools could be used

for allocations to new customers or to support desired policies, such

as customers who are willing to implement conservation or develop

renewable resources. The manner in which the resource pool is used was

not assessed because allocations have not yet been determined.

Table 1

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Preferred Peaking* Baseload Renewables No action

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Alternative Description............ Peaking optimized with Peaking operations Baseload operations Peaking operations Existing operations--

customer operations-- with purchase options. with purchase coupled with a 50 MW similar to peaking--

customers choose options. purchase from 478 MW average

purchases. renewables. monthly purchases.

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Legal Obligations

(4)Met by all alternatives

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Resource and Contractual Stability

(4)Analyzed in the EPAMP EIS and

the analysis of allocation to

customer groups within the 2004

EIS may be applied to all

alternatives

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Greatest Practical Value........... Lowest cost Federal Low cost but does not High costs--least Greatest costs--CVP Costs similar to

resource, available economically optimize available CVP customer capacity baseload--midlevel

load-carrying CVP resources-greatest customer load- same as peaking. CVP customer load-

customer capacity CVP customer load- carrying capacity. carrying capacity.

similar to peaking. carrying capacity.

Protect the Human and Natural Similar to peaking-- Most beneficial or Adverse effects Same as peaking for Similar to peaking

Environment. most beneficial least adverse except for least pool fluctuation-- physical effects--

socioeconomic effects. physical effects-- pool fluctuation in physical effects unfavorable

socioeconomic effects reregulating range from least to socioeconomic

depend on purchase reservoirs--some most depending on effects.

levels--no purchase adverse presence of biomass

similar to preferred socioeconomic in resource mix--

alternative. effects. Least favorable

socioeconomic effect.

Responsiveness..................... Greatest flexibility Less flexibility...... Less flexibility..... Less flexibility..... Less flexibility.

for customers.

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*Environmentally Preferred Alternative.

[[Page 22940]]

Greatest Practical Value

The third purpose was to provide the greatest practical value of

the power resource to SNR and to customers contracting with SNR. The

2004 EIS analysis found that Federal hydropower is a good value on the

power market. However, the structure and cost of supplemental purchases

can change the cost of the Federal resource and result in very small

socioeconomic effects. The baseload alternative was considered and not

selected because it represented the least-effective use of the CVP

hydropower resource in the overall energy market. The preferred

alternative was found to result in the lowest costs and most beneficial

socioeconomic effects.

Protect the Human and Natural Environment

The fourth purpose was to protect the human and natural

environment. The baseload alternative was considered but not selected

because of the adverse environmental effects of constructing and

operating necessary replacement capacity to maintain existing load-

carrying capability in the northern and central California region. In

addition, no significant positive benefits were identified to

environmental resources that would offset the negative impacts of

construction and operation of new generation capacity.

Although designated as environmentally preferred, the peaking

alternative was not selected because it does not economically optimize

integrated scheduling of Western's hydropower generation with the

generation of its customers. The preferred alternative provides nearly

identical environmental benefits as the peaking alternative, but

provides greater economic benefits, and has no major negative

environmental impacts.

The no-action alternative was not selected because it is not

consistent with customers' needs in a restructured utility industry

environment. Many of Western's customers have indicated they would like

the hydropower priced separately from purchases, and would like to make

their own purchases without incurring economic penalties. The no-action

alternative includes substantial firming purchases with the purchased

power cost melded with the hydropower cost, contrary to these

customers' preference and to price optimization in a restructured

utility environment.

The renewables alternative was not selected because it does not

economically optimize the use of CVP power resources and because the

preferred alternative allows purchases of power generated from

renewable resources. In the preferred alternative, Western can make

power purchases on behalf of customers at the customers' request, and

these purchases can be from renewable resource generation if costs are

competitive or if the customer is willing to pay the added cost. The

renewables alternative is based on costs of hydropower and purchases

being melded, while the preferred alternative is based on the

hydropower and purchased power costs being disaggregated, allowing more

freedom of choice among customers whether to take delivery of purchased

power. The latter approach is considered to be more compatible with the

developing competitive marketplace resulting from electric industry

restructuring.

Responsiveness

Regarding responsiveness to future changes in CVP, Washoe, and the

utility industry, the preferred alternative provides the greatest

flexibility to customers and keeps the Federal resources at their

highest, practical economic value while having no measurable impact on

the environment.

Mitigation Action Plan

No Mitigation Action Plan will be prepared, as the 2004 EIS did not

identify any significant environmental effects associated with

Western's selected alternative that warrant the adoption of a

monitoring program or mitigation measures.

Documents Available

For a copy of this Record of Decision or a copy of the final 2004

EIS and supporting documents, write to the 2004 EIS Project Manager at

the address listed in the For Further Information Contact Section.

Dated: April 11, 1997.

J.M. Shafer,

Administrator.

[FR Doc. 97-10859 Filed 4-25-97; 8:45 am]

BILLING CODE 6450-01-P