[Federal Register Volume 61, Number 73 (Monday, April 15, 1996)]
[Notices]
[Pages 16480-16483]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-9243]



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DEPARTMENT OF ENERGY
Western Area Power Administration


Western Area Power Administration's Concept for Purchase of Non- 
Hydropower Renewable Resources, and Solicitation of Interest

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of policy consideration and request for comment.

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SUMMARY: Western Area Power Administration (Western) is considering 
adoption of a policy whereby Western would purchase a portion of its 
expected purchase power requirements, on a project-by-project basis and 
in a competitive manner, from non-hydropower renewable resource 
producers. Within this portion of purchase power requirement set-aside 
for non-hydropower renewable resource, Western is also considering a 50 
percent reservation for solar resources. Western has developed the 
concept contained in this notice for public consideration and comment. 
Western also solicits interest from power customers who want Western to 
facilitate the delivery of non-hydropower renewable resources on their 
behalf and at their cost. In addition, Western solicits public comment 
on alternative concepts that may also provide marketing opportunities 
for non-hydropower renewable resource producers. Western seeks as well, 
information from renewable resource developers that helps in 
understanding these resource options. After considering public comment 
on the concept described in this notice, and after considering 
alternative concepts and opportunities offered by the public, Western 
will adopt a final non-hydropower renewable resource purchase policy 
and program for each of its projects. If the policy adopted provides 
for one or more projects to acquire a portion of their purchase power 
requirements from non-hydropower renewable resources, those projects 
will then begin separate processes to acquire such resources.

DATES: Western seeks comments on the purchase concept outlined in this 
notice and input on alternative marketing concepts and opportunities. 
To be considered, comments and other input in response to this notice 
needs to be received by May 15, 1996.
    At this time, Western does not plan to hold a public meeting. 
However, a summary of comments received, and Western's response to 
those comments, will be provided in a subsequent Federal Register 
notice, and to parties indicating they wish to continue receiving 
information about this process.

FURTHER INFORMATION: To receive information on this concept and 
solicitation, and/or to make requests to receive subsequent mailings on 
this process, contact: Mr. Michael S. Cowan, Chief Program Office, 
Western Area Power Administration, P.O. Box 3402, Golden, CO 80401-
0098, (303) 275-1630.

Background

    Western is conducting this process in support of the Department of 
Energy's program to develop renewable energy technologies as cost-
competitive sources of electricity. The competitive forces brought on 
by electric utility deregulation have reduced immediate market 
opportunities for renewable resources, such as wind, solar, and 
biomass. However, over time, competition is expected to create new 
opportunities for renewable energy sales, as technology improves and 
end-use customers are offered greater freedom to choose their sources 
of power. This is a critical period in which electricity markets are 
being shaped and future energy options are being defined, and it is 
important that renewable energy is one of the choices that the new 
market will offer.
    With its significant transmission resources, customer base, and 
interconnections with electric utilities throughout the West, Western 
is in a position to facilitate market opportunities for non-hydropower 
renewable resources. This public process was initiated to determine 
Western's appropriate role as such a facilitator, and to guide 
Western's decision as a potential buyer of non-hydropower renewables.
    In 1995, Western developed a set of Integrated Resource Planning 
(IRP) principles for its own resource acquisition and transmission 
planning activities. These principles were developed through a public 
process and were published in the Federal Register, ``Final Principles 
of Integrated Resource Planning for Use in Resource Acquisition and 
Transmission Planning,'' 60 FR 30533 (June 9, 1995). In adopting these 
principles, Western committed to considering a full range of supply- 
and demand-side resource options (including renewable resources) that 
would be evaluated on a project-by-project basis using criteria 
developed in a public process.
    Western's purchase power requirements are determined on a project-
by-project basis. This is done because each project has differing 
purchase power requirements, the projects are marketed separately, and 
the cost of purchase power is recovered through firm power rates 
charged to each project's customers.
    Western commonly makes power purchases for the purpose of 
``firming'' the hydropower that it is charged with marketing. Although 
Western does not have unlimited authority to purchase non-Federal 
power, the courts interpreting the Reclamation statutes have held that 
Western has inherent authority to purchase non-Federal power to 
maximize the sale of federally produced power at firm power rates. 
Western has been given statutory authority to market a higher level of 
firm power than the Central Valley Project generators can regularly 
produce, by purchasing up to 400 MW of additional power.
    Western is currently involved in two public processes to determine 
the need for purchase power and the criteria to be applied in making 
purchase power decisions. These include the Replacement Resources 
Process, pursuant to the Grand Canyon Protection Act of 1992 (Public 
Law 102-575) and the Central Valley Project 2004 Power Marketing 
Program. These processes are being conducted consistent with the 
principles of IRP adopted by Western. Public responses to the concept 
presented in this notice and specific to these projects will be 
considered in these ongoing public processes.
    The facilities, marketing programs, nature of purchase power 
requirements, and estimated financial impacts from purchasing non-
hydropower renewables for each of Western's projects are summarized in 
the following text and table. The nature of purchase power requirement 
is described as either firm or non-firm energy, and either annual, 
seasonal, or monthly. Firm energy is energy with capacity. Conversely, 
non-firm energy is energy only. The term of any purchase power contract 
would vary, but in no case will the term extend beyond the expiration 
of the project's current long-term firm power sales contracts, as 
amended.
    The estimated financial and rate impacts provided are calculated by 
applying the assumptions of a 5 percent of annual purchase power 
requirement

[[Page 16481]]

set-aside for non-hydropower renewable resources and a 55 mill per kWh 
cost for non-hydropower renewable resources. This 55 mill per kWh cost 
was assumed because it is considered achievable by many renewable 
resources. The 5 percent level of set-aside was assumed because it 
seemed to define a significant marketing opportunity for non-hydropower 
renewable resources, while keeping potential rate impacts to a minimum.
    The estimated financial and rate impacts are examples only. Actual 
financial and rate impacts will depend on the final policy adopted 
regarding set aside percentages, purchase cost limitations, and actual 
cost of such purchases.

Salt Lake City Area/Integrated Projects (SLCA/IP)

    For marketing and rate-making purposes, the Colorado River Storage 
Project (CRSP) and the Collbran and Rio Grande projects were combined 
into the SLCA/IP on October 1, 1987 and are marketed under the Post-
1989 General Power Marketing and Allocation Criteria, developed in 1986 
and modified by a 1989 court order.
    The CRSP is the largest component of the SLCA/IP and consists of 
four major storage units: Glen Canyon, on the Colorado River in 
Arizona; Flaming Gorge on the Green River in Utah; Navajo on the San 
Juan River in northwestern New Mexico; and the Wayne N. Aspinall Unit 
(formerly Curecanti) on the Gunnison River in west-central Colorado.
    Six Federal powerplants are associated with the CRSP. Maximum 
operating capacity of CRSP's 17 generating units is 1,802 MW. The CRSP 
Customer Service Center markets the 4,700 million kWh generated each 
year, in Colorado, Utah, New Mexico and Arizona. Portions of Nevada and 
Wyoming are also served by CRSP power.
    The CRSP expected annual purchase power requirement is 200 million 
kWh of non-firm energy. Due to daily fluctuation release constraints at 
Glen Canyon and Flaming Gorge powerplants, and contractual monthly load 
patterns, the CRSP purchase power requirement is spread throughout most 
months of both winter and summer seasons. The purchase requirement is 
also confined to the day time, or on-peak periods. Alternative non-firm 
energy costs are presently 10.25 mills per kWh. The nature of the CRSP 
purchase power requirement is seasonal non-firm energy. The term for 
CRSP purchase contracts would not extend beyond the termination date of 
Western's existing long-term firm power sales contracts (September 30, 
2004).
    Assuming a 200 million kWh non-firm energy purchase requirement 
each year, a five percent purchase power requirement set-aside for non-
hydropower renewable resources, alternative non-firm energy cost of 
10.25 mills per kWh, and non-hydropower renewable resource cost at 55 
mills per kWh, the additional cost to CRSP ratepayers would be $448 
thousand annually. These additional costs would translate into a 0.07 
mill per kWh rate increase--or a 0.4 percent rate increase.

Parker-Davis Project

    The Parker-Davis Project is comprised of Parker and Davis Dams, on 
the Colorado River below Hoover Dam, powerplants at each of these dams, 
and the associated transmission system. Western's share of the combined 
installed capacity of these powerplants is 338 MW.
    Power generated from the Parker-Davis Project is marketed to 
customers in Nevada, Arizona, and California. From Parker-Davis 
hydropower generation, Western's Desert Southwest Regional Office 
markets 183,774 kW of capacity in the winter season and 244,271 kW of 
capacity in the summer season. Total marketable energy is 313 million 
kWh in the winter season and 837.5 million kWh in the summer season.
    In the event Parker-Davis generation is not sufficient to meet firm 
contractual obligations, Western must purchase power from other 
resources. The Parker-Davis Project purchase power requirement is about 
70 million kWh annually. This requirement varies by season. During the 
spring (February through April) there is usually surplus generation--
with some deficiencies in late spring. During the summer season, 
surplus generation usually exists, with only periodic purchase power 
requirements when rains are heavy. During the late summer to early fall 
period, there are some small purchase power requirements. The fall 
months of October and November are usually surplus in generation. 
Generation deficiencies generally occur during December with 
fluctuations of deficiency and surplus during January. The nature of 
the Parker-Davis purchase power requirement is seasonal non-firm 
energy. The term for Parker-Davis purchase power contracts would not 
extend beyond the termination date of Western's existing long-term firm 
power sales contracts (September 30, 2008).
    Assuming a 70 million kWh firm energy purchase requirement each 
year, a 5 percent purchase power requirement set-aside for non-
hydropower renewable resources, alternative seasonal non-firm energy 
cost of 20 mills per kWh, and non-hydropower renewable resource cost at 
55 mills per kWh, the additional cost to Parker-Davis ratepayers would 
be $123 thousand annually. These additional costs would translate into 
a 0.11 mill per kWh rate increase--or a 1.7 percent rate increase.

Loveland Area Projects (LAP)

    The Pick-Sloan Missouri Basin Program-Western Division(Western 
Division) and the Fryingpan-Arkansas Project (Fry-Ark) were 
operationally and contractually integrated by the Post-1989 marketing 
criteria into the LAP for marketing and rate setting purposes. This 
program is administered by Western's Rocky Mountain Region (RMR). The 
RMR markets this power in Colorado, Wyoming, Kansas, and western 
Nebraska. The RMR markets power, including project use power, to 40 
customers.
    Western Division generating resources include Bureau of Reclamation 
Missouri River Basin powerplants: Yellowtail, Boysen, Pilot Butte, 
Glendo, Kortes and Fremont Canyon. The powerplants of Reclamation's 
Colorado-Big Thompson, Kendrick, Shoshone and North Platte projects 
have also been integrated with the Western Division for marketing and 
operation.
    Fry-Ark has six dams, five reservoirs; and two generating units at 
the powerplant at Mt. Elbert.
    The marketing criteria published in the Federal Register, 51 FR 
4012 (January 31, 1986), provide for marketing 2,088 million kWh of 
long-term firm energy with 716.5 MW of capacity annually. Firm power 
contracts provide for Western to furnish a specific amount of energy 
with capacity each month for the term of the contract. LAP firm energy 
is marketed based on available generation rather than customer load 
factors.
    The marketing criteria and electric service contracts provide for 
re-evaluation of the marketable energy with capacity in 1999, if 
necessary, with 5 years notice. The RMR completed a resource study in 
July 1995. The results of the resource study were published in the 
Federal Register, 51 FR 4012 (December 20, 1995). The study shows that 
the RMR annual purchase power requirement is 66 million kWh. The nature 
of the LAP purchase power requirement is monthly non-firm energy, 
primarily during the winter season. The term for LAP purchase power 
contracts would not extend beyond the termination date of existing

[[Page 16482]]

long-term firm power contracts (September 30, 2024).
    Assuming a 66 million kWh non-firm energy purchase requirement each 
year, a 5 percent purchase power requirement set-aside for non-
hydropower renewable resources, alternative non-firm energy cost of 16 
mills per kWh, and non-hydropower renewable resource cost at 55 mills 
per kWh, the additional cost to LAP ratepayers would be $129 thousand 
annually. These additional costs would translate into a 0.04 mill per 
kWh rate increase--or a 0.2 percent rate increase.

Pick-Sloan Missouri Basin Program--Eastern Division (Pick-Sloan Eastern 
Division)

    Western's Upper Great Plains Regional Office, in Billings, Montana, 
markets power for the Pick-Sloan Eastern Division, which serves 
customers across more than 378,000 square miles in the northern Rocky 
Mountain and central plains states. Seven dams and powerplants on the 
Missouri River produce hydropower for the Pick-Sloan Eastern Division. 
They are: Canyon Ferry in western Montana; Garrison at Riverdale, N.D.; 
Oahe at Pierre, S.D.; Big Bend at Fort Thompson, S.D.; Fort Randall and 
Gavins Point in southern South Dakota. Yellowtail Dam on the Bighorn 
River in south central Montana produces power for both the Pick-Sloan 
Eastern and Western divisions. Including one-half of Yellowtail, Pick-
Sloan Eastern Division powerplants generate in excess of 10,000 million 
kWh in a normal year.
    The Pick-Sloan Eastern Division expects to purchase about 130 
million kWh of non-firm energy annually. These requirements are 
restricted to the Winter season. The prevailing rate for non-firm 
energy in the Upper Great Plains Region is 14 mills per kWh. The nature 
of the Pick-Sloan Eastern Division purchase power requirement is 
seasonal non-firm energy. The term for Pick-Sloan Eastern Division 
purchase power contracts would not extend beyond the termination date 
of existing long-term firm power contracts (September 30, 2020).
    Assuming a 130 million kWh non-firm energy purchase requirement 
each year, a 5 percent purchase power requirement set-aside for non-
hydropower renewable resources, alternative non-firm energy cost of 14 
mills per kWh, and non-hydropower renewable resource cost at 55 mills 
per kWh, the additional cost to Pick-Sloan Eastern Division ratepayers 
would be $267 thousand annually. These additional costs would translate 
into a 0.05 mills per kWh rate increase--or a 0.3 percent rate 
increase.

Central Valley Project (CVP)

    The Central Valley Project in California has 12 dams that create 
reservoirs with a total storage capacity of 10.6 million acre-feet. The 
generating units associated with these dams have an installed capacity 
of 2,022 MW and a net average annual generation of about 5,200 million 
kWh.
    After providing the power needed to deliver CVP water (project use 
requirements including station service), CVP power is marketed to 
preference and non-preference customers. The annual firm CVP power 
sales typically exceed 6,000 million kWh. The sum of project use and 
preference customer contractual obligations currently requires the 
Sierra Nevada Region (SNR) of Western to purchase power to meet CVP 
power obligations.
    Firm purchases of 310 to 340 MW are currently being purchased under 
long-term contracts. The capacity factors of these resources range from 
40 to 100 percent. There are no seasonal purchases, except in very dry 
years. In months where purchases exceed needs, energy is sold and/or 
banked under contract with Pacific Gas and Electric Company to be used 
during months when purchases are less than needs. Typically May through 
August are surplus months and November through February are deficit 
months. The nature of the CVP purchase power requirement is annual firm 
energy. The term for CVP purchase power contracts would not extend 
beyond the termination date of existing long-term firm power contracts 
(September 30, 2004). The CVP purchase power needs beyond 2004 are 
being determined in a separate public process.
    Assuming 310 MW at 40 percent load factor purchase power 
requirement each year, a 5 percent purchase power requirement set-aside 
for non-hydropower renewable resources, alternative firm energy cost of 
23 mills per kWh, and non-hydropower renewable resource cost of 55 
mills per kWh, the additional cost to CVP ratepayers would be $1.738 
million annually. These additional costs would translate into a 0.29 
mill per kWh rate increase, or a 1.3 percent rate increase.

                      Tabular Summary of Estimated Impacts From Concept for Western Purchase of Non-Hydropower Renewable Resources                      
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                                     Purchase    5 percent     Nature of                                            Percent     Equivalent     Term of  
           Project name               reqmnt     set-aside     purchase     Alt. cost    Add. cost   Rate impact  rate (mills/ MW increase     present  
                                      (GWH)        (GWH)        reqmnt                  (mills/kWh)    ($1,000)       kWh)         \1\        contracts 
-------------------------------------------------------------------------------------------------------------------------------------------------\2\----
CRSP.............................          200         10.0  Seasonal non-       10.25          448         0.07          0.4          3.8          2004
                                                              firm                                                                                      
Parker-Davis.....................           70          3.5  Seasonal non-       20.00          123         0.11          1.7          1.3          2008
                                                              firm                                                                                      
LAP..............................           66          3.3  Monthly non-        16.00          129         0.04          0.2          1.3          2024
                                                              firm                                                                                      
P-S Eastern......................          130          6.5  Seasonal non-       14.00          267         0.05          0.3          2.5          2020
                                                              firm                                                                                      
CVP..............................        1,086         54.3  Annual firm         23.00        1,738         0.29          1.3         20.5          2004
                                  ----------------------------------------------------------------------------------------------------------------------
      Total......................        1,552         77.6                                   2,705                                   29.4              
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\1\ Equivalent MW is calculated by applying a 30 percent capacity factor to the 5 percent set-aside energy amount.                                      
\2\ Term of sales contracts.                                                                                                                            

Concept

    Western is considering committing a portion of its purchase power 
requirements, on a project-by-project basis, for competitive 
solicitation from non-hydropower renewable resource power producers. 
The primary criterion used to determine the portion of purchase 
commitment would be that the

[[Page 16483]]

additional cost associated with purchase of such resources have little 
or no discernable rate impact to Western's power customers. Another 
criterion is that the cost of the non-hydropower renewable resource be 
less than an established upper limit, or cost cap. The contract term 
for purchase of these renewable resources would also vary by project, 
but in no case would the term extend beyond the termination date of 
Western's long-term firm power sales contracts for the project.
    Within this concept, Western is also considering a 50 percent 
reservation of the non-hydropower renewable set-aside for solar 
resources--with the remaining 50 percent of set-aside open to other 
non-hydropower renewable resources, such as wind and biomass. This 
reservation for solar resources is being considered to help diversify 
the mix of non-hydropower resources purchased and to support the 
Department of Energy's goal of commercializing a variety of renewable 
resource technologies.
    Other terms, requirements, and criteria such as: dispatchability, 
point of delivery, dependability, resource diversity, environmental 
impact, etc. would be developed in the project-specific application of 
this concept. Resource acquisitions made through application of this 
concept will be made on a project-by-project, cost-competitive basis 
within the set-aside for non-hydropower renewable resources 
established, with criteria and requirements satisfied, and in a manner 
consistent with Western's principles of IRP.

Solicitation

    Western also solicits expressions of interest from its long-term 
firm power customers who may want Western to facilitate the purchase 
and delivery of non-hydropower renewable resources on their behalf and 
at their cost. These purchases would be in addition to Western's own 
purchases. Western also solicits input on alternative concepts, within 
Western's power marketing framework, administrative capability, and 
purchase power authority, that may also provide marketing opportunities 
for non-hydropower renewable resource producers.
    In addition, Western solicits information from renewable resource 
developers that can help increase Western's understanding of non-
hydropower renewable resource opportunities.

Public Process

    The public process to determine Western's policy for purchase of 
non-hydropower renewables on a project-by-project basis begins with the 
publication of this notice.
    Western requests public comments on the concept outlined in this 
notice. On the non-hydropower renewable resource purchase concept, 
Western requests whether or not the respondent supports Western 
adopting such a concept. With an indication of support, Western 
requests additional project-specific comments on (a) the magnitude or 
percentage of a potential purchase power requirement set-aside, (b) 
whether it's appropriate to have a 50 percent reservation for solar 
resources within the set-aside, and if so, whether the reservation 
amount for solar should be increased or reduced, (c) the acceptable 
rate impact, (d) a recommended cost cap in mills per kWh for non-
hydropower resources, (e) a recommended contract term for purchase, and 
(f) any other related matter.
    Western also requests input from the public on alternative methods 
whereby Western may be able to facilitate market opportunities for non-
hydropower renewable resources.
    Comments on this concept, responses to solicitation of interest, 
suggested alternative concepts, and information on market opportunities 
for renewable resources, are being sought during a 30-day comment 
period. Following this comment period, the final non-hydropower 
renewable resource purchase policy for each Western project will be 
published in the Federal Register. This public process ends with 
publication of the final policy in the Federal Register. The policy 
will be effective 30 days after publication. If the policy adopted 
provides for one or more projects to acquire a portion of their 
purchase power requirements from non-hydropower renewable resources, 
those projects will then begin separate processes to acquire such 
resources. Each of these acquisition processes will be consistent with 
Western's principles of IRP, and will build upon criteria established 
in the policy adopted.

Environmental Evaluation

    Western is seeking comment on the non-hydropower renewable resource 
purchase concept presented in this notice through a public process. 
Western is committed to initiating an appropriate public process under 
NEPA and its implementing regulations for this proposed policy on a 
project- specific basis at the earliest possible time.

Determination Under Executive Order 12866

    DOE has determined this is not a significant regulatory action 
because it does not meet the criteria of Executive Order 12866, 58 FR 
51735. Western has an exemption from centralized regulatory review 
under Executive Order 12866; accordingly, no clearance of this notice 
by the Office of Management and Budget is required.

    Issued at Golden, Colorado, April 3, 1996.
J. M. Shafer,
Administrator.
[FR Doc. 96-9243 Filed 4-12-96; 8:45 am]
BILLING CODE 6450-01-P