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

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

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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

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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

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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