[Federal Register Volume 62, Number 81 (Monday, April 28, 1997)]
[Notices]
[Pages 22934-22940]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 97-10859]


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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

[[Page 22935]]

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

[[Page 22937]]

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      
--------------------------------------------------------------------------------------------------------------------------------------------------------
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.  
--------------------------------------------------------------------------------------------------------------------------------------------------------
Legal Obligations                                                                                                                                       
(4)Met by all alternatives                                                                                                                              
--------------------------------------------------------------------------------------------------------------------------------------------------------
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                                                                                                                                           
--------------------------------------------------------------------------------------------------------------------------------------------------------
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.                                                                                                    
--------------------------------------------------------------------------------------------------------------------------------------------------------
*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