[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
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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
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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