United States General Accounting Office

GAO Report to the Chairman, Subcommittee

on Water and Power, Committee on

Resources, House of Representatives

March 1999 FEDERAL POWER

Implications of

Reduced Maintenance

and Repairs of Federal

Hydropower Plants

GAO/RCED-99-63

GAO United States

General Accounting Office

Washington, D.C. 20548

Resources, Community, and

Economic Development Division

B-282016 

March 30, 1999

The Honorable John T. Doolittle

Chairman, Subcommittee on Water

 and Power Committee on Resources

House of Representatives

Dear Mr. Chairman:

This report discusses the reliability of the Bureau of Reclamation’s and the

Corps of Engineers’ hydropower plants in generating electricity compared

with the reliability of nonfederal hydropower plants, reasons why the

Bureau’s and the Corps’ plants may be less reliable than nonfederal plants

and the potential implications of reduced reliability, and the actions taken

to obtain funding to better maintain and repair the Bureau’s and the Corps’

plants.

As agreed with your office, unless you publicly announce the contents of

this report earlier, we plan no further distribution of this report until 30

days from the date of this letter. At that time, we will send copies of the

report to Representative Don Young, Chairman, House Committee on

Resources; Representative George Miller, Senior Democratic Member,

House Committee on Resources; Representative Calvin Dooley, Ranking

Minority Member, House Committee on Resources, Subcommittee on

Water and Power; Senator Frank Murkowski, Chairman, Senate

Committee on Energy and Natural Resources; Senator Jeff Bingaman,

Ranking Minority Member, Senate Committee on Energy and Natural

Resources; Senator John Chafee, Chairman, Senate Committee on

Environment and Public Works; and Senator Max Baucus, Ranking

Minority Member, Senate Committee on Environment and Public Works.

We are also sending the report to Charles Borchardt, Administrator,

Southeastern Power Administration; Michael Deihl, Administrator,

Southwestern Power Administration; Major General Russell Fuhrman,

Director, Civil Works, U.S. Army Corps of Engineers; Michael Hacskaylo,

Administrator, Western Area Power Administration; Judi Johanson,

Administrator, Bonneville Power Administration; and Eluid Martinez,

Commissioner, Bureau of Reclamation. We will make copies available to

others upon request.

Page 1 GAO/RCED-99-63 Federal Power
B-282016 

If you or your staff have any questions, please call me on (202) 512-3841.

Major contributors to this report are listed in appendix VI.

Sincerely yours,

Susan D. Kladiva,

Associate Director, Energy,

 Resources, and Science Issues

Page 2 GAO/RCED-99-63 Federal Power
B-282016 

Page 3 GAO/RCED-99-63 Federal Power
Executive Summary

Purpose Because of new, more efficient technologies for generating electricity and

emerging competition in restructured electricity markets, electricity rates

have decreased by about 25 percent since 1982 and are expected to

continue to decrease.1

 Electricity provided by the federal government from

hydropower plants is generally priced less than other electricity and is

very marketable;2

 however, to retain this competitiveness as markets

continue to restructure, the federal hydropower plants3

 need to be

operated as reliably as nonfederal hydropower plants. Reliable operation

will help to ensure that the government can continue to market the

electricity it generates and recover its outstanding appropriated and other

debt of about $22 billion.4

 In addition, the Congress, GAO, and the Office of

Management and Budget have been working to help ensure that the

purchase and maintenance of all assets and infrastructure have the highest

and most efficient returns to the taxpayer and the government. The

agencies that generate most of this electricity—the Army Corps of

Engineers (the Corps), the Department of the Interior’s Bureau of

Reclamation (the Bureau)—and the federal agencies that sell it—the

Department of Energy’s four power marketing administrations (PMA)5

—need to be able to adequately maintain the federal hydropower plants

and transmission systems, in order to provide a reliable supply of

electricity.

As requested by the Chairman, Subcommittee on Water and Power, House

Committee on Resources, GAO examined (1) the reliability of the Bureau’s

and Corps’ hydropower plants in generating electricity compared with the

reliability of nonfederal hydropower plants,6

 (2) reasons why the Bureau’s

and the Corps’ plants may be less reliable than nonfederal plants and the

potential implications of reduced reliability, and (3) the actions taken to

1

The 25-percent reduction is calculated in terms of constant dollars.

2

See Federal Power: Options for Selected Power Marketing Administrations’ Role in a Changing

Electricity Industry (GAO/RCED-98-43, Mar. 6, 1998).

3

A power plant includes one or more generating units that produce electricity.

4

We use the term “appropriated debt” because the PMAs are required to set their electricity rates to

generate revenue at levels that will recover appropriations used for capital investments by the Bureau

and the Corps. However, these reimbursable appropriations are not considered to be lending by the

Department of the Treasury. Other debt includes primarily debt for irrigation facilities and other debt

for certain nonfederal nuclear power plants.

5

The four power marketing administrations are the Bonneville Power Administration (Bonneville),

Southeastern Power Administration (Southeastern), Southwestern Power Administration

(Southwestern), and Western Area Power Administrations (Western).

6

Nonfederal plants would include those owned by commercial utilities, municipal utilities, electric

cooperatives, public utility districts, or other nonfederal entities.

Page 4 GAO/RCED-99-63 Federal Power
Executive Summary

obtain funding to better maintain and repair the Bureau’s and the Corps’

plants.

Background Since about the 1930s, the Bureau and the Corps have operated about 130

hydropower plants that supply about 5 percent of the nation’s total

electricity supply. These agencies generate electricity in conjunction with

other uses of water, such as fish and wildlife enhancements, flood control,

irrigation, navigation, recreation, and water supply. The PMAs sell this

electricity primarily to wholesale customers (the “power customers”),

such as rural electric cooperatives and municipal utilities. The power

customers, in turn, sell this electricity to customers at the retail level. In

fiscal year 1997, the PMAs had revenues of over $3 billion from the sale of

electricity. A portion of these revenues is used to repay the outstanding

appropriated and other debt of about $22 billion.7

The Energy Policy Act of 1992 significantly increased competition in

wholesale electricity markets, and 18 states have acted to introduce

competition at the retail level. As a result of this competition and new,

more efficient generating technologies, prices are expected to continue to

decrease by 6 to 19 percent by 2015. In more competitive markets, utility

management measures the “reliability” of power plants to decide where

to cut costs or how to allocate scarce dollars for maintaining plants.

Within the electric utility industry, plants are “reliable” if they can function

without failure over a specific period of time or amount of usage.

Results in Brief The Bureau’s and the Corps’ hydropower plants are generally less reliable

in generating electricity than nonfederal hydropower plants. The reliability

of the Bureau’s hydropower plants has improved recently, while the Corps’

has remained relatively unchanged. Specifically, from 1993 through 1997,

the Bureau’s units were available to generate electricity an average of

about 83 percent of the time compared with about 91 percent for

nonfederal units.8

 The availability of the Bureau’s units to generate

electricity improved from about 81 percent of the time in 1993 to about

87 percent in 1997. The Corps’ units were available to generate electricity

an average of about 89 percent of the time during the period 1993 through

7

As of the end of fiscal year 1997—the latest year for which information was available—Bonneville was

responsible for repaying about $14 billion, and the other PMAs were collectively responsible for

repaying about $8 billion dollars. See Federal Electricity Activities: The Federal Government’s Net

Cost and Potential for Future Losses (GAO/AIMD-97-110 and 110A, Sept. 19, 1997).

8

The availability of power plants actually pertains to the availability of individual generating units. The

availability of power plants to generate electricity is a widely accepted measure of their reliability.

Page 5 GAO/RCED-99-63 Federal Power
Executive Summary

1997.9 However, the Bureau’s and the Corps’ units in the Pacific

Northwest—which account for over one-half of the agencies’ total

hydropower capacity and almost all of the electricity that Bonneville

markets—were available about 79 percent and 85 percent of the time,

respectively.

The Bureau’s and the Corps’ plants were less reliable because they could

not always obtain funding for maintenance and repairs when needed. GAO

found that because of uncertain funding, the agencies delay repairs and

maintenance until funds become available. GAO also found that these

delays caused frequent, extended outages and inconsistent plant

performance. The power marketing administrations’ electricity is generally

priced less than other electricity. However, as markets become more

competitive, the power marketing administrations’ customers will have

more suppliers from whom they can buy electricity. In some power

marketing systems—for example, Bonneville’s service area—existing

competition has lowered nonfederal electricity rates. As a result, during

the mid-1990s, some customers left Bonneville or bought some of their

electricity from less expensive sources. As nonfederal electricity rates

decline in competitive markets, a portion of the federal government’s

appropriated and other debt of about $22 billion may be at risk of

nonrecovery if the federal electricity does not continue to be marketable.

A factor affecting the marketability of this electricity is its reliability. In

addition, the Congress, the Office of Management and Budget, and GAO

have been working to help ensure that the purchase and maintenance of

all assets and infrastructure have the highest and most efficient returns to

the taxpayer and the government.

The Bureau, the Corps, and the power marketing administrations have

taken actions to obtain funding to maintain and repair their hydropower

plants. In general, these actions involve directly funding maintenance and

repairs from the power marketing administrations’ electricity revenues or

from funds contributed by the power customers. By enabling repairs to be

made in a timely manner, these actions have the potential to help to

improve the reliability of the power marketing administrations’ electricity

and to continue their existing rate-competitiveness.

9

The Bureau’s and the Corps units were unable to generate electricity 17 percent and 11 percent of the

time, respectively, because of breakdowns, repairs, and maintenance, compared with about 9 percent

for nonfederal units.

Page 6 GAO/RCED-99-63 Federal Power
Executive Summary

GAO’s Analysis

The Bureau’s and the

Corps’ Hydropower Plants

Are Less Reliable Than

Nonfederal Plants

The hydropower plants of the Bureau and the Corps are less reliable in

providing electricity than nonfederal hydropower plants. However, the

reliability of the Bureau’s plants improved while the Corps’ has remained

relatively unchanged. From 1993 through 1997, the Bureau’s and the

Corps’ hydropower units were available to generate electricity about

83 percent and 89 percent of the time, respectively. Nonfederal

hydropower units were available to generate electricity about 91 percent

of the time.10 The availability of the Bureau’s units to generate electricity

increased from about 81 percent in 1993 to about 87 percent in 1997. (See

fig. 1.) At the same time, from 1993 through 1997, the Bureau’s units were

in outage status11 an average of about 17 percent of the time for

breakdowns, repairs, and maintenance, compared with an average of

about 9 percent for nonfederal units. The Corps’ units were in outage

status an average of about 11 percent of the time. In addition, the Corps’

units were in forced outage status an average of about 5 percent of the

time while nonfederal and the Bureau’s units were in forced outage status

an average of about 2 percent of the time12

10Availability and outage data were obtained from the North American Electric Reliability Council—an

organization formed by the electric utility industry to promote the reliability of the electric supply

system of North America.

11“Outage status” means a generating unit was unavailable to generate electricity because of

anticipated repairs and maintenance (“scheduled outages”) or unanticipated breakdowns or

emergency repairs (“forced outages”). This differs from a utility’s deciding not to operate a unit for

reasons unrelated to its operating condition, for example, insufficient or restricted water for operating

the plant.

12As a result of comments from the Department of Defense (including the Corps), GAO revised the

report in chapter 2 to recognize the Corps’ availability factor for 1998 and a decline in the Corps’

forced outage factor for 1998. Defense suggested that GAO include the 1998 data in its figures, but

GAO did not do so because comparable data were not available for the nonfederal entities at the time

of GAO’s review.

Page 7 GAO/RCED-99-63 Federal Power
Executive Summary

Figure 1: Average Availability Factors

of the Bureau’s, the Corps’, and

Nonfederal Hydropower Generating

Units, 1993-97

Notes: The percentages are the sum of all units’ available hours divided by the sum of all units’

period hours. A unit’s period hours for a year equal 8,760 hours, or 24 hours multiplied by 365

days.

Sources: The Bureau, the Corps, and the North American Electric Reliability Council.

In addition, forced outages are strong indicators of decreased reliability

because they indicate that a utility’s units generate electricity

inconsistently. According to Corps officials, as a result of major initiatives

to rehabilitate its generating units, the agency has reduced its forced

outages from almost 6 percent in 1995 to 4.5 percent in 1997.

In the Pacific Northwest, the availability to generate electricity of the

Bureau’s and the Corps’ units was generally lower than it was for the

agencies other locations. From 1993 through 1997, the Bureau’s units in

the Pacific Northwest were only available to generate electricity about

79 percent of the time and were in outage status about 21 percent of the

time. The Corps’ units in this region were available about 85 percent of the

time and were in outage status 15 percent of the time. In contrast,

Page 8 GAO/RCED-99-63 Federal Power
Executive Summary

nonfederal units in the region were available about 90 percent of the time

and were in outage status about 10 percent of the time. The reliability of

the Bureau’s and the Corps’ hydropower plants in the Pacific Northwest is

important to the overall reliability of the Bureau and the Corps.

Funding Processes’

Impacts on the Reliability

of the Bureau’s and the

Corps’ Hydropower Plants

The federal planning and budget processes, under which the Bureau and

the Corps must operate, do not provide timely and predictable funding

needed for the maintenance and repair of hydropower plants. It can take

as long as 2 to 3 years before a repair that is identified is funded, if it is

funded at all. For example, consistent with the normal budget cycle, in

formulating a budget for fiscal year 2000, a regional office of the Bureau

began its budget process in August 1997. However, the process will not

culminate and the funding level will not be known with certainty until the

fiscal year 2000 appropriations act is signed by the President.

Delays in funding federal repairs and the uncertainty about the levels of

this funding have caused some maintenance or repairs to be postponed

until funds become available. For example, at the Bureau’s Shasta plant in

California, the need to repair the generating units was identified in 1983.

However, funding did not become available until 1995 when the customers

provided advance funding. According to a Bureau official, the repairs will

not be completed until 2003. Moreover, over time, deterioration at the

power plant worsened and, in response, the Bureau reduced the plant’s

operations.

For the most part, the PMAs’ electricity is priced below market, thus

helping to ensure that the PMAs’ can sell their electricity and helping to

secure the repayment of the government’s appropriated and other debt.

However, in more competitive markets, the PMAs’ customers will have a

choice of suppliers from which to buy electricity. In such markets, if the

reliability of federal electricity continues to be below that of other

producers, some of the competitive advantages of the PMAs’ electricity

would erode, thus decreasing its marketability. This is particularly true in

specific PMA systems where the PMAs’ electricity is already priced at about

the market rate or where competition already exists to the sale of the PMAs’

electricity. For example, in Bonneville’s service area, competitive

challenges exist to the sale of Bonneville’s electricity. Bonneville is facing

competition from low-cost suppliers of electricity that, during the

mid-1990s, caused customers to leave Bonneville and buy electricity at

rates below Bonneville’s.13

13See GAO/AIMD-97-110 and 110A.

Page 9 GAO/RCED-99-63 Federal Power
Executive Summary

Actions Taken to Promote

Faster and More Certain

Funding to Better Maintain

and Repair Federal Plants

Recognizing the delays and uncertainties that can result from the federal

planning and budget processes, the Bureau, the Corps, and the PMAs have

acted to secure funding to maintain and repair the federal hydropower

plants and related facilities. For example, recognizing the lower reliability

of the plants in the Pacific Northwest, from 1993 through 1997, the Bureau,

the Corps, and Bonneville concluded four agreements whereby

Bonneville’s electricity revenues will provide advance funding of over

$1 billion dollars for routine operations and maintenance and capital

repairs of the electricity facilities from which it markets electricity.14 The

agencies expect to be able to plan and pay for maintenance and repairs

systematically and predictably over several years and to fix unanticipated

breakdowns more rapidly. For example, under the Bureau’s and

Bonneville’s December 1996 funding agreement, the Bureau prepares an

annual operations and maintenance budget by identifying major line items

for each project for funding during the next fiscal year and also for 5 fiscal

years. Annual expenditures that are less than the targeted amount are

carried over to future years and accounted for in a “savings account,”

which can be tapped, as provided for in the agreement, to pay for

emergency repairs. Annual budgets are proposed and approved less than 1

year in advance, instead of 2 to 3 years, which is the general time frame

under the traditional appropriations process. Bonneville believes that the

increased demand for its electricity and the increased financial resources

provided by the funding agreements would improve its competitive

viability and ability to recover the full cost of the electricity system from

which it markets power.15

In addition, at such locations as the Central Valley Project in California

and the Pick-Sloan Program in Montana, North Dakota, South Dakota, and

nearby states, direct payments from the PMAs’ electricity customers have

funded the maintenance and repair of the federal power plants and related

facilities. As authorized by law, the PMAs’ customers can directly pay for

the maintenance and repair of the federal power plants and related

facilities, but these commitments must be made before the repairs begin.

For example, electricity customers have made commitments to pay for

future operations and maintenance and some selected repairs of the

federal power plants and related facilities in the Central Valley Project.

The direct funding of maintenance and repairs by electricity revenues and

customers’ financing agreements could diminish opportunities for

oversight by the Congress. However, at this time, the Bureau, the Corps,

14The agreements were concluded pursuant to the Energy Policy Act and other statutes.

15Bonneville markets electricity from the Federal Columbia River Power System.

Page 10 GAO/RCED-99-63 Federal Power
Executive Summary

and the PMAs provide such information as the history and background of

their power plants, the plants’ generating capacity and electricity

produced, annual electricity revenues and costs, and related

environmental and water quality issues to the Congress, other

decisionmakers, and the public. The means of communicating this

information include the PMAs’ annual reports; the PMAs’, the Bureau’s, and

the Corps’ Internet Websites; and letters to the appropriate congressional

committees.

Recommendations This report contains no recommendations.

Agency Comments GAO provided the Department of Energy (which represented the views of

Southeastern, Southwestern, and Western), the Department of the Interior

(including the Bureau), the Department of Defense (including the Corps),

and Bonneville with a draft of this report. The comments of Energy,

Interior, Defense, and Bonneville, and GAO’s responses to those comments,

are included in appendixes II, III, IV, and V, respectively.

The Department of Energy provided technical suggestions for the draft

report but deferred to the comments of the Bureau and the Corps on more

substantive matters. For example, Energy suggested that GAO clarify the

differences between “reliability” and “availability.” The report already

discusses that plants are viewed as reliable, within the electric utility

industry, if they can function without failure over a specific period of time

or amount of usage. The report also states that there are several ways of

measuring reliability, including the availability factor and outage factors.

Accordingly, we made no substantive changes to the report.

The Department of the Interior, including the Bureau, commented that the

report did a good job in recognizing the funding needs for operating and

maintaining electrical-generating facilities. However, according to Interior,

the report should recognize that the Bureau’s availability factors are partly

the result of the fact that the Bureau’s facilities operate to fulfill multiple

purposes and that the generation of electricity is secondary to irrigation

and other purposes. The report clearly recognizes that water is used for

multiple purposes and affects how electricity is generated. For example,

the executive summary recognizes that the Bureau and the Corps generate

electricity in conjunction with the use of water for flood control,

navigation, irrigation, and other purposes. Accordingly, no changes are

needed to the report. Also, Interior stated that the reliability of its plants

Page 11 GAO/RCED-99-63 Federal Power
Executive Summary

compares favorably with nonfederal plants, and that the forced outages

factor is a better indicator of comparative reliability than the availability

factor. GAO does not agree that the Bureau’s plants are as reliable as

nonfederal plants because, as discussed in this report, the Bureau’s plants

have lower availability factors and are in outage status more of the time

than nonfederal plants. In addition, the report already recognizes that the

forced outage factor, along with the availability factor, is viewed as one of

the most meaningful ways of measuring reliability. Accordingly, for these

points, no changes to the report are needed. Finally, GAO agrees that the

availability factor should be interpreted within the context of various

factors, some of which the Bureau listed. GAO revised chapter 1 to

recognize that assessing the performance of a hydropower plant or unit by

examining its availability factor calls for understanding additional

variables. GAO added language to reflect that the availability factor needs

to be understood in terms of such factors as the role played by the plant in

terms of the kind of demand it meets (e.g., whether it meets peak

demand), the availability of water throughout the year, and the purposes

satisfied by the dam and reservoir.

The Department of Defense, including the Corps, provided verbal

comments to clarify its position on GAO’s draft report, noting, most

significantly, that the report did not reflect changes in the performance of

the Corps’ hydropower plants that occurred in fiscal year 1998. Defense

suggested that GAO include this data in various graphs in its report. GAO

revised chapter 2 to recognize the Corps’ availability factor for 1998 and a

decline in the agency’s forced outage factor for 1998. GAO did not include

these data in graphs because comparable data were not available for the

nonfederal entities at the time of GAO’s review.

Bonneville noted that GAO “sought to conduct a fair assessment” of the

Corps’ and the Bureau’s facilities during the time of the study. Bonneville

agreed, as stated in the report, that the availability factors of the Bureau’s

and the Corps’ hydropower plants in the Pacific Northwest are lower than

in the rest of the nation. However, Bonneville suggested that GAO clarify

the report by stating that Bonneville, the Bureau, and the Corps recognized

the lower reliability of the plants in the Pacific Northwest and took action

through a series of direct-funding agreements to address the problem.

Bonneville further suggested a clarification that from 1993 through 1997,

the Bureau extensively upgraded and rehabilitated its plants, partly as a

result of the increased funding flexibility provided by the direct funding

agreements. Chapter 4 already discusses in detail the provisions of the

agreements, the $1 billion of repairs that are being funded as a result of the

Page 12 GAO/RCED-99-63 Federal Power
Executive Summary

agreements, and the expected improvements in the Bureau’s planning and

budgeting systems that result from them. GAO agrees that the suggested

revisions would enhance the reader’s understanding of the funding

agreements and revised the report to recognize that the increased funding

flexibility that resulted from the agreements enabled the Bureau to

undertake extensive repairs.

Page 13 GAO/RCED-99-63 Federal Power
Contents

Letter 1

Executive Summary 4

Chapter 1 

Background

16

Changes in Electricity Markets 17

Measuring the Reliability of Power Plants 20

Objectives, Scope, and Methodology 22

Chapter 2 

The Bureau’s and

Corps’ Hydropower

Plants Are Less

Reliable Than

Nonfederal Plants

24

The Bureau’s and Corps’ Hydropower Generating Units Are Less

Available to Generate Power

24

The Bureau’s and Corps’ Hydropower Generating Units Are in

Outage Status More of the Time Than Nonfederal Units

26

Chapter 3 

Funding Processes’

Impacts on the

Reliability of

Hydropower Plants

33

Funding for Repairs Can Take Years to Obtain and Is Uncertain 33

Funding Difficulties Lead to Delays of Maintenance That Result

in Maintenance Backlogs

35

Delayed Repairs Lead to Inconsistent Plant Performance 36

Inadequate Funding for the Maintenance and Repair of Federal

Hydropower Plants May Impact Marketability of Federal

Electricity

38

Chapter 4 

Actions Taken to

Promote Faster and

More Certain Funding

to Better Maintain and

Repair the Bureau’s

and Corps’ Plants

40

Direct Funding by Electricity Revenues May Pay for Over $1

Billion for Maintenance and Repairs

40

Initiatives for Funding by Customers Are Being Implemented 44

Appendixes Appendix I: Objectives, Scope, and Methodology 46

Appendix II: Comments From the Department of Energy 50

Page 14 GAO/RCED-99-63 Federal Power
Contents

Appendix III: Comments From the Department of the Interior 52

Appendix IV: Comments From the Department of Defense 63

Appendix V: Comments of the Bonneville Power Administration 65

Appendix VI: Major Contributors to This Report 71

Table Table I.1: Characteristics of Bureau, Corps, and Nonfederal

Hydropower Generating Units as of 1997

47

Figures Figure 1: Average Availability Factors of the Bureau’s, the Corps’,

and Nonfederal Hydropower Generating Units, 1993-97

8

Figure 1.1: Map of the Service Areas of the Power Marketing

Administrations

17

Figure 2.1: Average Availability Factors of the Bureau’s, the

Corps’, and Nonfederal Hydropower Generating Units, 1993-97

25

Figure 2.2: Total Outages factors of the Bureau’s, the Corps’, and

Nonfederal Hydropower Generating Units, 1993-97

27

Figure 2.3: Forced Outages factors of the Bureau’s, the Corps’,

and Nonfederal Hydropower Generating Units, 1993-97

28

Figure 2.4: Scheduled Outages factors of the Bureau’s, the Corps’,

and Nonfederal Hydropower Generating Units, 1993-97

29

Abbreviations

GAO General Accounting Office

MW megawatt(s)

NERC North American Electric Reliability Council

OMB Office of Management and Budget

PMA power marketing administrations

TVA Tennessee Valley Authority

Page 15 GAO/RCED-99-63 Federal Power
Chapter 1 

Background

The Army Corps of Engineers (the “Corps”) and the Department of the

Interior’s Bureau of Reclamation (the “Bureau”) operate about 130

hydropower plants at dams throughout the nation. These plants generate

electricity from the flow of water that is also used for other purposes,

including fish and wildlife enhancement, flood control, irrigation,

navigation, recreation, and water supply. Since about the 1930s, electricity

that is generated by these hydropower plants has played an important role

in electricity markets. These plants were a key element in electrifying rural

and sparsely populated areas of the nation. These plants account for over

35,000 megawatts (MW)16 of generating capacity (or about 5 percent of the

nation’s total electric supply) in 1998. The Department of Energy’s power

marketing administrations (PMA)17 generally market the electricity

generated at these plants to wholesale customers (the “power

customers”), such as rural electric cooperatives and municipal utilities,

that in turn sell the electricity to retail customers. (Fig. 1.1 shows the

service areas of the PMAs.) Revenues earned from the sale of this electricity

totaled over $3 billion in fiscal year 1997. These revenues pay for the

operation and maintenance of the government’s electricity-related assets

and repay a portion of the outstanding federal appropriated and other

debt18 of about $22 billion for the Bureau’s and the Corps’ power plants,

related PMA transmission lines, and well as certain related federal

investments for irrigation, water supply, and other facilities that are to be

repaid over time from electricity revenues.19 The revenues also pay

interest on the outstanding appropriated debt, where applicable.

16A watt is the basic unit used to measure electricity. A megawatt equals 1 million watts. A

megawatt-hour is equal to 1 megawatt of electricity applied for 1 hour. A kilowatt-hour equals 1,000

watt-hours.

17The PMAs are the Bonneville Power Administration (Bonneville), Southeastern Power

Administration (Southeastern), Southwestern Power Administration (Southwestern), and Western

Area Power Administration (Western).

18We use the term “appropriated debt” because the PMAs are required to set their electricity rates to

generate revenue at levels that will recover appropriations used for capital investments by the Bureau

and the Corps. However, these reimbursable appropriations are not considered as lending by the

Department of the Treasury. Other debt includes primarily debt for irrigation facilities and debt for

certain nonfederal nuclear power plants.

19As of the end of fiscal year 1997—the latest year for which information was available—the Bonneville

Power Administration was responsible for repaying about $14 billion, and the other PMAs were

collectively responsible for repaying about $8 billion dollars.

Page 16 GAO/RCED-99-63 Federal Power
Chapter 1 

Background

Figure 1.1: Map of the Service Areas of the Power Marketing Administrations

WA

ID

OR

CA

NV

AZ

UT

TX

NM

CO

WY

MT ND

SD

NE

KS

MN

IA

MO

AR

OK

LA

WI

IL IN

MI

OH

PA

NY

VT

NH

ME

MA

CT RI

NJ

FL

SC

MS AL GA

NC TN

KY

WV

VA

MD DE

BPA

WAPA

SWPA SEPA

BPA Bonneville Power Administration

SEPA Southeastern Power Administration

SWPA Southwestern Power Administration

WAPA Western Area Power Administration

Both Western and Southwestern market power in Kansas.

KS

Source: Developed by GAO from data provided by the Department of Energy and the PMAs.

Changes in Electricity

Markets

In traditional markets, electric utilities enjoyed relative certainty about the

amount of demand they would have to satisfy in the future. A compact

existed between utilities and state public utility commissions. Utilities

were obligated to serve all existing and future customers in their

pre-established service areas. In return, utilities were granted monopolies

within their service areas and approved rate schedules that guaranteed

Page 17 GAO/RCED-99-63 Federal Power
Chapter 1 

Background

stated earnings on their operating costs and investments. They forecasted

the load they would serve by using econometric and end-use analyses

models over future periods of time that were as long as 20 years. They

collected sufficient funds in their electric rates to pay for needed

generating capacity and to operate, maintain, and repair existing power

plants and other electricity assets. The funds collected through rates also

include profits.

However, the nation’s electricity markets are undergoing significant

changes. The Energy Policy Act of 1992 significantly increased

competition in wholesale electricity markets. In addition, competition at

the retail level is now arriving. According to the Department of Energy’s

Energy Information Administration, as of March 1999, 18 states had

acted—by legislation that had been enacted (14 states) or by regulatory

order (4 states)20 —to restructure electricity markets. Regulators in these

states expected that industrial, commercial, and, ultimately, residential

consumers would be able to choose their electricity supplier from among

several competitors, rather than being tied to one utility.

As competition increases, the rates paid by consumers for electricity have

dropped and should continue to do so. For example, according to the

Energy Information Administration, as a result of such factors as emerging

competition and new, more efficient generating technologies, retail

electricity rates decreased by about 25 percent from 1982 through 1996,

after factoring in the impact of inflation. The administration expects

electricity rates to continue to decrease in real terms by 6 percent to

19 percent by 2015.

Utilities Respond to More

Competitive Markets

In recent years, uncertainty about the pace and extent of competitiveness

in electric markets has caused utilities to be more flexible. Utilities have

relied more on purchasing electricity from other sources or acquiring new

power plants, such as smaller natural-gas-fired plants, that are less

expensive and more flexible for meeting shifting demand. They have also

cut costs by reorganizing and reducing staff, and they have consolidated or

merged with other utilities where they believed it was appropriate. For

example, after years of virtually no mergers, from October 1992 to

January 1998, investor-owned utilities had proposed over 40 mergers and

completed 17 of them, according to the Edison Electric Institute. In

20The states that enacted legislation were Arizona, California, Connecticut, Illinois, Maine,

Massachusetts, Montana, Nevada, New Hampshire, New Jersey, Oklahoma, Pennsylvania, Rhode

Island, and Virginia. Other states with regulatory orders were Maryland, Michigan, New York, and

Vermont.

Page 18 GAO/RCED-99-63 Federal Power
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Background

addition, according to utility officials, some utilities are retiring or

divesting some high-cost power plants, while others are buying those same

plants to serve a niche in their resource portfolios.

According to utility officials, in more stable electricity markets, utilities

and federal agencies maintained and repaired their hydroelectric and other

power plants according to a schedule that was predetermined by the

manufacturer’s specifications and the operating history of the plant.

Maintenance and repairs were frequently made at this predetermined time

whether or not they were needed. Because maintenance or repairs could

have been performed later or less frequently, perhaps with lower costs,

some Bureau and utility officials that we contacted characterized these

practices as over-maintenance of the hydropower plants. These practices,

according to an industry consultant, were seldom questioned partly

because of the low costs and resiliency of hydropower plants—especially

of those placed into service during the 1950s.

However, as markets become more competitive, federal agency, utility,

and electric industry officials have increasingly viewed hydropower plants

as particularly useful to utilities’ overall operations. One of hydropower’s

important traits is its flexibility in meeting different levels of demand. This

characteristic, according to utility officials, means that hydropower plants

will likely continue to play a significant role in meeting demand during

peak periods and providing ancillary services,21 without which electricity

systems cannot operate. Currently, utilities provide these services

routinely. However, according to Bureau, PMA, and utility officials,

depending upon actions taken by federal and state regulators in the near

future, a separate market may develop for ancillary services. These

services may be priced separately and may allow utilities with hydropower

to capture a market niche and earn additional revenues.

In response to new markets and perceptions about the role of hydropower

in those markets, federal agencies and some utilities have reconsidered

how they operate, maintain, and repair their hydropower plants. For

example, some utilities have implemented less-expensive, more-flexible

maintenance practices, which consider such factors as the generating size

of a utility’s hydropower plants, those plants’ roles in the utility’s

generation portfolio, and marketing and economic considerations. One

such approach, called “Reliability Centered Maintenance,” is defined as a

maintenance philosophy that attempts to make use of the most logical,

21Ancillary services are services or tariff provisions related to the generation and delivery of electricity

other than the simple generation, transmission, or distribution of electricity.

Page 19 GAO/RCED-99-63 Federal Power
Chapter 1 

Background

cost-effective mix of breakdown maintenance, preventive maintenance,

and predictive testing and proactive maintenance to attain the full life of

the equipment, reduce maintenance costs, and encourage reliable

operations. For example, according to some utilities we contacted, in

determining when to maintain or repair equipment, they are relying

increasingly on the use of monitoring equipment to detect changes in the

operating conditions of the equipment, instead of performing those actions

in a prescheduled manner, as in the past. On the basis of these

examinations, the utility may decide to repair or replace the component.

Alternatively, the utility may decide to stretch out the operation of the

component to the point of near-failure. Some components may actually be

run until they fail. However, according to Corps and utility officials, in the

cases of some smaller hydropower units, installing monitoring equipment

at a cost of $200 to $500 per unit may not make economic sense. Other

measures may also be used to monitor the operating condition of

equipment. For example, the Corps tests the lubricating oil to indicate the

condition of its generating equipment.

Also, in some cases, when deciding how and when to maintain and repair

generating units, management now considers the plant or the unit as an

individual cost center that must make a positive contribution to the

utility’s bottom line. In such an environment, plant managers will become

more aware of the production costs and will exert increased pressures to

cut costs at the plant and at the corporate levels. Plant managers may

become aware that a utility may actually shut down and sell a generating

unit if operating or repairing it does not return a required, positive

financial return.

Measuring the

Reliability of Power

Plants

As market competition intensifies, utilities will face increasing pressures

to operate as efficiently and cost-effectively as possible. Utilities’

management will need to know how well their plants are producing

electricity in order to make informed decisions about how to allocate

scarce dollars for maintaining and repairing power plants, where to cut

costs, or, in more extreme cases, which generating units22 to sell or shut

down.23 An important concept for defining power plants’ performance is

the “reliability” with which plants generate electricity. Within the electric

22A power plant is made up of one or more generating units that produce electricity.

23The Bureau, for example, has “benchmarked” the performance of its hydropower plants against

other plants in the industry, using such indicators as the availability, scheduled outage, and forced

outages factors. See Future Generations: A New Era of Power, Performance, and Progress, Bureau of

Reclamation (1996).

Page 20 GAO/RCED-99-63 Federal Power
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Background

utility industry, power plants are viewed as “reliable” if they are capable

of functioning without failure over a specific period of time or amount of

usage. The availability factor and the related outages factors are widely

accepted measures of the reliability of power plants. The time a generating

unit is “available” to generate electricity is the time it is mechanically able

to generate electricity because it is not malfunctioning unexpectedly or

because it is not being maintained or repaired. For instance, if a unit were

available to generate electricity 8,000 hours out of the 8,760 hours in a

year, then its availability factor would be 8,000 hours divided by 8,760

hours, or about 91.3 percent.

When a unit is unable to generate electricity because it is broken, being

repaired, or being maintained, it is in outage status. Outages are further

classified as “scheduled” outages if the unit is unable to generate

electricity because it is undergoing previously scheduled repairs or

maintenance. If a unit is unable to generate electricity because of an

unexpected breakdown and/or if unanticipated repairs need to be

performed, then it is in “forced outage” status. If a plant were in

scheduled outage status for 100 hours over the course of one year, then its

scheduled outage factor would be 100 hours divided by the 8,760 hours in

a year, or 1.1 percent. If a plant were in a forced outage status for 600

hours, then its forced outage factor would be 600 hours divided by the

8,760 hours in the year, or 6.8 percent of the time. For any generating unit,

the availability factor, the scheduled outage factor, and the forced outage

factor, added together, should equal 100 percent because, taken together,

they account for a plant’s entire operating status over a period of time.

Assessing the performance of a hydropower plant or unit by examining its

availability factor calls for understanding additional variables that would

affect its performance. Many officials we contacted said that the

availability factor needs to be understood in terms of such factors as the

role played by the plant in terms of the kind of demand that it meets (for

instance, whether it meets peak demand), the availability of water

throughout the year, and the purposes satisfied by the dam and reservoir.

For example, according to a utility consultant, because water is abundant

at the New York Power Authority’s Niagara Power Project, the generating

units are used primarily to satisfy nonpeak loads. Therefore, the utility

attempts to operate and maintain those units to be on line as much as

possible. To do otherwise entails a loss of generating revenues that could

be earned almost 24 hours per day. Nevertheless, officials at every utility

we contacted said that they achieved an availability of at least 90 percent,

Page 21 GAO/RCED-99-63 Federal Power
Chapter 1 

Background

and the Bureau and the Corps have formal goals of attaining that

availability level.

Objectives, Scope,

and Methodology

As requested by the Chairman, Subcommittee on Water and Power, House

Committee on Resources, we examined the (1) reliability of the Bureau’s

and Corps’ hydropower plants in generating electricity compared with the

reliability of nonfederal hydropower plants;24 (2) reasons why the

Bureau’s and the Corps’ plants may be less reliable than nonfederal plants

and the potential implications of reduced reliability; and (3) actions taken

to obtain funding to better maintain and repair the Bureau’s and the Corps’

plants.

To compare the generating reliability of the Bureau’s and the Corps’

hydropower plants with nonfederal ones, we obtained, analyzed, and

contrasted power plants’ performance data, including availability and

outages factors, from the Bureau, the Corps, and the North American

Electric Reliability Council.25 We discussed the limitations of these

performance indicators with officials from the Bureau, the Corps, the

PMAs, the Tennessee Valley Authority, investor-owned utilities, publicly

owned utilities, and other experts in the electric utility industry.

To explore why federal hydropower plants sometimes performed at lower

levels, we obtained and analyzed various reports on the subject and

discussed the topic with representatives of the Bureau, the Corps, the

PMAs, various PMA electricity customers or their associations,

investor-owned utilities, and nonfederal, publicly owned utilities.

Moreover, in addressing the implications of any reduced performance by

federal plants, we interviewed industry experts, representatives of

investor-owned and publicly owned utilities, officials of the PMAs, and the

PMAs’ electricity customers. We also examined studies about the changes

in electricity markets.

In examining steps to secure funding to better maintain and repair the

Bureau’s and the Corps’ plants, we studied the efforts of the Corps, the

Bureau, and the PMAs to pay for the maintenance and repair of federal

hydropower assets more quickly and with greater certainty. In this regard,

we contacted the Bureau, the Corps, the PMAs, and the PMAs’ power

24Nonfederal plants would include those owned by commercial utilities, municipal utilities, electric

cooperatives, public utility districts, or other nonfederal entities.

25The Council was established by the electric utility industry to promote the reliability of the electricity

supply system of North America.

Page 22 GAO/RCED-99-63 Federal Power
Chapter 1 

Background

customers at several different locations, including Denver, Colorado;

Boise, Idaho; Portland, Oregon; and Sacramento, California. At these

locations, we also examined any funding agreements concluded by these

parties and asked detailed questions about the benefits and other

implications of these agreements. Our analysis was based on the

assumption that the Bureau’s and the Corps’ hydropower plants, the

related facilities, and the PMAs would continue to exist under some form of

federal ownership. In examining other steps to secure enhanced funding,

we relied to the greatest extent possible upon previous work that we had

performed on federal electricity, especially work performed during two

prior reviews—Federal Power: Options for Selected Power Marketing

Administrations: Role in a Changing Electricity Industry (GAO/RCED-98-43,

Mar. 6, 1998) and Federal Power: Outages Reduce the Reliability of

Hydroelectric Power Plants in the Southeast (GAO/T-RCED-96-180, July 25,

1996).

Our work was performed at many different locations that included various

power plants and offices of the Bureau, the Corps, Bonneville,

Southeastern, Southwestern, and Western; investor-owned utilities; and

publicly owned utilities. We also contacted national and regional industry

trade associations.

Our work was performed from July 1998 through February 1999 in

accordance with generally accepted government auditing standards.

Appendix I contains a more complete description of our objectives, scope,

and methodology.

Page 23 GAO/RCED-99-63 Federal Power
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The Bureau’s and Corps’ Hydropower Plants

Are Less Reliable Than Nonfederal Plants

Within the electric utility industry, power plants are viewed as “reliable”

if they are capable of functioning without failure during a specific period

of time or amount of usage. From 1993 through 1997, the reliability of the

Bureau’s hydropower plants improved, while the Corps’ remained about

the same. However, the Bureau’s and the Corps’ hydropower plants are

generally less reliable in generating electricity than nonfederal plants.26

The Bureau’s and the Corps’ hydropower generating units have been in

outage status more of the time for forced and scheduled outages.

Importantly, the reliability of the Bureau’s and the Corps’ plants in the

Pacific Northwest is generally below that of Bureau and Corps plants

elsewhere and also below that of nonfederal plants in the region and

elsewhere. The Bureau’s and the Corps’ plants in the region account for

over half of these agencies’ total generating capacity and almost all of the

power marketed by the Bonneville Power Administration

(Bonneville)—the largest of the PMAs in terms of power sales.

The Bureau’s and

Corps’ Hydropower

Generating Units Are

Less Available to

Generate Power

Nationwide, both the Bureau’s and the Corps’ generating units are less

available to generate electricity than those of nonfederal utilities and

providers; however, the Bureau’s availability factor has been improving,

while the Corps’ remained about the same.27 (See fig. 2.1.) Generating

units that have malfunctioned unexpectedly or are undergoing

maintenance and repairs are not considered to be available. Generating

units that are more available to generate electricity are considered to be

more reliable. The availability factor is considered to be a key indicator of

reliability, according to the Bureau.

From 1993 through 1997, nonfederal hydropower generating units were

available to generate electricity an average of 91.3 percent of the time.

During that same period, the Bureau’s hydropower units were available an

average of 83.3 percent of the time (or 8 percent less than the average for

nonfederal units) and the Corps’ hydropower units were available an

average of 88.8 percent of the time (or 2.5 percent less than nonfederal

units). The availability factor for nonfederal units from 1993 through 1997

was relatively unchanged. The Bureau’s availability factor improved from

80.9 percent of the time in 1993 to 86.6 percent in 1997. The Bureau

believes that one reason for its lesser availability factors is that more of its

26Nonfederal plants include those of commercial utilities, municipal utilities, electric cooperatives,

public utility districts, and other nonfederal entities.

27A generating unit is available to generate power when it is mechanically able to do so. The availability

factor is not a measure of whether a plant can or cannot generate power because water cannot be

released through the turbines or is otherwise not present for purposes of generating power.

Page 24 GAO/RCED-99-63 Federal Power
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The Bureau’s and Corps’ Hydropower Plants

Are Less Reliable Than Nonfederal Plants

plants are located on pipelines, canals, and water diversion facilities in

comparison with most nonfederal plants. The Corps’ availability factor

was relatively unchanged—declining slightly from 89.6 percent in 1993 to

89.2 percent in 1997. Corps officials later provided us with data showing

an availability factor of 89.5 percent in 1998. Also, the Bureau provided us

with data showing an availability factor of 88.5 percent in 1998.

Figure 2.1: Average Availability

Factors of the Bureau’s, the Corps’,

and Nonfederal Hydropower

Generating Units, 1993-97

Notes: The percentages are the sum of all units’ available hours divided by the sum of all units’

period hours. A unit’s period hours for a year equal 24 hours multiplied by 365 days, or 8,760

hours.

Source: The Bureau, the Corps of Engineers, and the North American Electric Reliability Council.

Page 25 GAO/RCED-99-63 Federal Power
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The Bureau’s and Corps’ Hydropower Plants

Are Less Reliable Than Nonfederal Plants

The Bureau’s and

Corps’ Hydropower

Generating Units Are

in Outage Status More

of the Time Than

Nonfederal Units

If generating units are not available to generate electricity, they are said to

be in “outage” status.28 Because the Bureau’s and the Corps’ generating

units were less available to generate electricity than the rest of the

industry, they also had higher outages factors. The longer or more frequent

its outages, the less available a unit is to generate electricity. (See fig. 2.2.)

From 1993 through 1997, the hydropower units of the Bureau were in

outage status an average of 16.7 percent of the time, and the Corps’ units

were in outage status an average of 11.2 percent of the time. In contrast,

nonfederal units were in outage status an average of 8.7 percent of the

time.29

From 1993 through 1997, the Corps’ total outage factor was relatively

unchanged, whereas the Bureau’s decreased from 19.1 percent in 1993 to

13.4 percent in 1997. Nonfederal units’ total outages factors were relatively

unchanged.

28“Outage status” means that a generating unit was unavailable to generate electricity because of

anticipated repairs and maintenance (“scheduled outages”) or unanticipated breakdowns or

emergency repairs (“forced outages”). Outage status means a unit cannot operate because it is

broken, is being maintained, or is being repaired. This differs from a utility’s deciding not to operate a

unit for reasons unrelated to its operating condition—for example, insufficient or restricted water for

operating the plant.

29Except for the Corps in 1993, the total outage factor is the sum of scheduled and forced outages. To

compute a total outage factor for the Corps in 1993, we subtracted the Corps’ availability factor of

89.6 percent from 100 percent.

Page 26 GAO/RCED-99-63 Federal Power
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The Bureau’s and Corps’ Hydropower Plants

Are Less Reliable Than Nonfederal Plants

Figure 2.2: Total Outages Factors of

the Bureau’s, the Corps’, and

Nonfederal Hydropower Generating

Units, 1993-97

Note: The percentages are the sum of scheduled and forced outages factors in figures 5 and 6.

Source: The Bureau, the Corps of Engineers, and the North American Electric Reliability Council.

The Corps’ Hydropower

Generating Units Have

Higher Forced Outages,

and the Bureau’s Have

Higher Scheduled Outages

Examining the types of outages that occur indicates why generating units

were not in service. Along with the availability factor, the forced outage

factor is a key indicator of decreasing reliability because it depicts that

unexpected outages occurred, thus indicating inconsistent operations.

According to the Bureau’s 1996 benchmarking study,30 the lower the

forced outage factor, the more reliable the electricity is considered. From

1993 through 1997, the average forced outage factor for the Bureau was 2.3

percent and the Corps’ was 5.1 percent. The average forced outage factor

for nonfederal hydropower units was 2.3 percent—the same as the

Bureau’s but less than the Corps’. (See fig. 2.3.) However, it should be

noted that the Corps’ forced outage factor declined—from almost 6

percent in 1995 to 4.5 percent in 1997. According to the latest data

30A New Era of Power, Performance, and Progress: Future Generations U.S. Bureau of Reclamation

(1996).

Page 27 GAO/RCED-99-63 Federal Power
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The Bureau’s and Corps’ Hydropower Plants

Are Less Reliable Than Nonfederal Plants

provided by the Corps, the agency’s forced outage factor declined even

further to under 3.2 percent in 1998. According to a Corps official, this

improvement is the result of the agency’s $500 million effort, implemented

or identified for implementation from fiscal year 1993 through 2009, to

rehabilitate its hydropower plants.

Figure 2.3: Forced Outages Factors of

the Bureau’s, the Corps’, and

Nonfederal Hydropower Generating

Units, 1993-97

Note: The percentages are the sum of all units’ forced outage hours divided by the sum of all

units’ period hours. A unit’s period hours for a year, 8,760 hours, equals 24 hours multiplied by

365 days. The Corps did not have 1993 forced outage data.

Source: The Bureau, the Corps of Engineers, and the North American Electric Reliability Council.

Scheduled outages are, by definition, anticipated. Nevertheless, scheduled

outages factors also reflect the amount of time that a generating unit was

off-line and unable to provide a utility’s customers with electricity.

According to the Bureau’s 1996 benchmarking study, the longer a

scheduled outage, the less efficient the maintenance program. In our view,

Page 28 GAO/RCED-99-63 Federal Power
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The Bureau’s and Corps’ Hydropower Plants

Are Less Reliable Than Nonfederal Plants

a more efficient maintenance program would have placed the generating

unit into service faster, thereby enabling the utility to provide its

customers with more service and hence possibly earn more revenues.

In the case of scheduled outages, from 1993 through 1997, the Corps’

average scheduled outage factor was 6.3 percent and the Bureau’s was

14.4 percent. The average scheduled outage factor for nonfederal utilities

was 6.4 percent. However, from 1993 through 1997 the Bureau’s scheduled

outage rate showed an improvement—decreasing from 17.1 percent in

1993 to 11.3 percent in 1997—while the Corps’ and the industry’s trends in

scheduled outages factors were relatively unchanged. (See fig. 2.4.)

Figure 2.4: Scheduled Outages Factors

of the Bureau’s, the Corps’, and

Nonfederal Hydropower Generating

Units, 1993-97

Notes: The percentages are the sum of all units’ scheduled outage hours divided by the sum of all

units’ period hours. A unit’s period hours for a year, 8,760 hours, equals 24 hours multiplied by

365 days. The Corps did not have 1993 scheduled outage data.

Source: The Bureau, the Corps of Engineers, and the North American Electric Reliability Council.

Page 29 GAO/RCED-99-63 Federal Power
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The Bureau’s and Corps’ Hydropower Plants

Are Less Reliable Than Nonfederal Plants

Taking longer scheduled outages at opportune times is a management

decision that may be considered good business practice, even though such

decisions decrease a generating unit’s availability to generate electricity.

For example, the Bureau and some electric utilities extend scheduled

outages to perform additional repairs during periods when the water is not

available for generating electricity or the unit is not needed to meet

demand. Also, labor costs are minimized by avoiding the payment of

overtime wages.

However, according to some Bureau, PMA, and utility officials, these

practices may change as markets evolve. Hydropower units may need to

be available to generate electricity more of the time in order for the utility

to take advantage of new market opportunities. For example, supplying an

ancillary service, such as providing reserve capacity, may allow a utility to

earn added revenues while not actually generating electricity; however,

the unit must be in operating condition (“available”) to generate

electricity.

Reliability of the Bureau’s

and the Corps’

Hydropower Plants in the

Pacific Northwest

The reliability of the Bureau’s and the Corps’ hydropower plants in Pacific

Northwest is important to the overall reliability of the Bureau and the

Corps. The generating units of those plants account for over half of the

Bureau’s and the Corps’ total hydropower capacity. In addition, those

plants provide almost all of the generating capacity from which

Bonneville, the largest PMA, markets electricity. However, the reliability of

the Bureau’s and the Corps’ plants in the Pacific Northwest was below that

of nonfederal plants in the region.31 In addition, the reliability of the

Bureau’s and Corps’ plants in the region was also generally below that of

the Bureau’s and Corps’ plants elsewhere and below that of nonfederal

plants in other regions.32 As shown in chapter 4, Bonneville, the Bureau,

and the Corps are undertaking extensive upgrades and rehabilitations of

the federal plants. These actions occurred, in part, as a result of the

increased funding flexibility provided by the agreements under which

Bonneville would directly pay for the operation, maintenance, and repair

of these assets.

31The region includes the hydropower generating units of the regional reliability council, called the

Western Systems Coordinating Council.

32As shown in this chapter, from 1993 through 1997, nationwide, the average availability of the

Bureau’s generating units was 83.3 percent of the time, and the Corps’ was about 88.8 percent, whereas

the nonfederal units’ was 91.3 percent.

Page 30 GAO/RCED-99-63 Federal Power
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The Bureau’s and Corps’ Hydropower Plants

Are Less Reliable Than Nonfederal Plants

The availability factor of the Bureau’s units improved over time. The

availability of the Corps’ units was slightly below that of nonfederal plants,

but it declined slightly from 1993 to 1997. However, the Corps’ units had a

forced outage status over twice as high as that of nonfederal units in the

region, indicating inconsistent plant performance, while the Bureau’s units

had a scheduled outage factor that was almost three times that of

nonfederal units.

From 1993 through 1997, the Bureau’s units in the Pacific Northwest were

available to generate power an average of about 78.7 percent of the time,

and the Corps’ units were available an average of 85.4 percent of the time.

In contrast, nonfederal hydropower units in the region were available an

average of 89.7 percent of the time. The Bureau’s availability factor

improved from a level of 74 percent in 1993 to 85 percent in 1997, and the

Corps’ availability factor decreased from 87.9 percent in 1993 to

85.7 percent in 1997. In contrast, the availability factors of nonfederal units

decreased slightly from 91.8 percent in 1993 to 90.3 percent in 1997.

In the Pacific Northwest, from 1993 through 1997, the Bureau’s units were

in outage status an average of 21.3 percent of the time, and the Corps’

units were in outage status an average of 15.3 percent of the time,

compared with an average of 10.3 percent of the time for nonfederal units

in the region. The Bureau’s outage factor decreased from about 26 percent

in 1993 to 15 percent in 1997, while the Corps’ increased slightly from

12.1 percent in 1993 to 14.3 percent in 1997. The outage factor for regional

nonfederal units increased from 8.2 percent in 1993 to 9.7 percent in 1997.

The Corps’ units performed more inconsistently than nonfederal units

because from 1993 through 1997, the Corps’ units had higher forced

outages factors (an average of 6.4 percent) than the Bureau’s units (an

average of 1.9 percent) and nonfederal units (an average of 3.1 percent).

The Corps’ forced outage factor in 199433 was about 5 percent and

increased to over 7 percent in 1995 and 1996, before declining to about 5.6

in 1997. In contrast, the Bureau’s forced outage factor was lower than the

nonfederal producers’ but increased from 1.3 percent in 1993 to

1.9 percent in 1997. Nonfederal producers had a forced outage that

increased from 1.5 percent in 1993 to 3.2 percent in 1997. According to the

Corps’ Hydropower Coordinator, the higher forced outage factor for the

Corps’ units in the region pertained to the operation of fish screens and

other equipment designed to facilitate salmon migrations around the

Corps’ units. This equipment breaks or needs to be maintained, causing

33The Corps did not report a forced outage factor in 1993.

Page 31 GAO/RCED-99-63 Federal Power
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The Bureau’s and Corps’ Hydropower Plants

Are Less Reliable Than Nonfederal Plants

decreases in availability. During fiscal year 1998, at the Corps’ McNary and

Ice Harbor plants, forced outages related to fish passage equipment were

30 and 15 percent, respectively, of the total hours in which the plants

experienced forced outages.

However, from 1993 through 1997, the Bureau’s units had higher

scheduled outages factors (an average of 19.4 percent) than both the

Corps’ units (an average of 8.9 percent) and nonfederal units (an average

of 7.2 percent). The Bureau’s scheduled outages factors were far higher

than those of nonfederal parties but decreased from 24.7 percent in 1993

to 13.2 percent in 1997. The Corps’ scheduled outage factor decreased

from 9.6 percent in 1994 to 8.8 percent in 1997.34 Nonfederal parties had a

scheduled outage factor that increased from 6.7 percent in 1993 to

8.4 percent in 1994 before falling to 6.5 percent in 1997.

34The Corps did not report a scheduled outage factor in 1993.

Page 32 GAO/RCED-99-63 Federal Power
Chapter 3 

Funding Processes’ Impacts on the

Reliability of Hydropower Plants

The Bureau’s and the Corps’ plants were less reliable than nonfederal

plants partly because, under the federal planning and budget cycle, they

could not always obtain funding for maintenance and repairs when

needed. We found that funding for repairs can take years to obtain and is

uncertain. As a result, the agencies delay repairs and maintenance until

funds become available. In addition, the Anti-Deficiency Act and other

statutes require that federal agencies not enter into any contracts before

appropriations become available, unless authorized by law. Such delays

can lead to maintenance backlogs and to inconsistent, unreliable

performance. The PMAs’ electricity generally is priced less than other

electricity. However, because markets are becoming more competitive, the

PMAs’ customers will have more suppliers from which they can buy

electricity. In some power marketing systems—for example, Bonneville’s

service area—competition during the mid-1990s allowed some customers

to leave or buy some of their electricity from other sources, rather than

continuing to buy from Bonneville. Reliability is a key aspect of providing

marketable power. For example, according to Bonneville, in large

hydropower systems, the PMAs’ ability to earn electricity revenues

depends, in part, on the availability of hydropower generating units to

generate power. In more competitive markets, the reliability of the federal

electricity will have to be maintained or improved to maintain the

competitiveness of federal electricity and thus help ensure that the federal

government’s $22 billion appropriated and other debt will be repaid. In

addition, the Congress, the Office of Management and Budget (OMB), and

we have been working to help ensure that the purchase and maintenance

of all assets and infrastructure have the highest and most efficient returns

to the taxpayer and the government.

Funding for Repairs

Can Take Years to

Obtain and Is

Uncertain

The federal planning and budgeting process takes at least 2 full years and

does not guarantee that funds will be available for a specific project. This

affects the ways in which the Bureau and the Corps plan and pay for the

maintenance and repair of their hydropower plants. The federal budgeting

process is not very responsive in accommodating the maintenance and

repair of those facilities—it can take as long as 2 to 3 years before a repair

is funded, if it is funded at all. Specifically, the project and field locations

of the Bureau and the Corps identify, estimate the costs of, and develop

their budget requests, not only for hydropower, but also for their other

facilities, including dams, navigation systems, irrigation systems, and

recreational facilities. The funding needs of these various assets compete

for the funding and repair of hydropower plants may be assigned lower

priorities than other items.

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For example, officials of the Bureau’s office in Billings, Montana,

described the budget process they expected to undergo to develop a

budget for fiscal year 2000. The process began in August 1997, when the

regional office received initial budget proposals from its area offices.

During the ensuing months, the area offices; the region; the Bureau’s

Denver office; the Bureau’s Washington State office; the Office of the

Secretary of the Interior; and OMB reviewed, discussed, and revised the

proposed area offices’ and regional office’s budgets, resulting in a

consolidated budget for the Bureau and the Department of the Interior.

Certainty about expected funding levels will not be obtained until

sometime between February 1999, when OMB conveys the President’s

budget to the Congress, and the enactment and approval of the Energy and

Water Appropriations Act. The time that will elapse from August 1997,

when the area offices began their budget processes, and October 1999 (the

start of fiscal year 2000) totals 26 months.

In addition, funding for the maintenance and repair of the Bureau’s and the

Corps’ hydropower plants is uncertain. Agency officials and other policy

makers, faced with limited and scarce resources, especially in times of

limited budgets, make decisions about where and where not to spend

funds. As shown in examples below, funding is not always delivered to

maintain and repair hydropower plants, even if the need is demonstrated.

According to documentation that the Bureau provided us with, in 1983,

detailed inspections of the generating units at the Shasta, California,

hydropower plant found that generating components were deteriorating.

The Bureau advised one of its federal power customers that it would seek

funds in fiscal year 1984 for the repairs. However, OMB did not approve the

requests because the units were not “approaching a failure mode.” Later,

in 1990, the Bureau issued invitations to bid for the repairs, which, upon

receipt ranged from $9 million to $12 million. However, the project was

dropped because the Bureau had budgeted only $6 million. In 1992, after

an inspection to determine how far the deterioration had advanced, one

generating unit’s operations were reduced. The inspectors also

recommended repairing the other two units because the gains in

generating capacity that would be achieved as a result of the repairs would

enable Western to sell more electricity. To fund the repairs, the Bureau

requested funds in its fiscal year 1993 budget request; however, according

to the Bureau’s records, OMB eliminated the request. The Bureau’s Budget

Review Committee recommended that the project not be included in the

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agency’s fiscal year 1994 budget request and that the Bureau’s regional

office “make a concerted effort to find non-federal financing.”35

The Corps’ Northwestern Division in Portland, Oregon, has also

experienced difficulties in funding needed repairs. For example, at the

Corps’ hydropower plant at The Dalles, Oregon, direct funding by

Bonneville allowed the Corps to accomplish maintenance that, according

to Corps officials, in all likelihood would not have been funded because of

the funding constraints in the federal budget process. Beginning in late

1993, the Corps began preparing an evaluation report that was submitted

to headquarters to replace major plant components on 14 units36 that had

exhibited many problems over the years but were kept in service through

intensive maintenance. The Congress approved funding for the major

rehabilitation as part of the Corps’ fiscal year 1997 appropriations.

However, after 2 of the units were out of service for an extended time,

Bonneville and the Corps entered into an agreement in January 1995 for

Bonneville to pay for the rewinding of the generator at unit 9. In

February 1996, the rewinding of unit 7 was added to the agreement. In

addition, Bonneville, in March 1996, agreed to fund the replacement of the

excitation systems for The Dalles’ units 15 through 22, which were not

included in the major rehabilitation funded by appropriations.

Funding Difficulties

Lead to Delays of

Maintenance That

Result in Maintenance

Backlogs

Delayed or uncertain funding leads to delays or postponements of needed

maintenance and repairs. These delays or postponements can result in

maintenance backlogs that can worsen over time. After funding requests

are identified and screened, funding may not be made available until up to

3 years in the future. The Corps has estimated a total maintenance backlog

of about $190 million for its power plants in Bonneville’s service territory.

However, according to Bonneville and Corps officials, the extent to which

critical repair items are part of the backlog is a matter yet to be

determined. In addition, according to Bonneville and Corps officials, the

role of the approximately $190 million estimate for purposes of planning

and budgeting under Bonneville’s and the Corps’ funding agreements is

subject to debate. The Corps’ Hydropower Coordinator noted that carrying

35On August 10, 1995, Western’s power customers agreed to pay about $21.5 million to repair the units.

According to a Bureau official, this cost included not only rewinding the generators but replacing the

turbine runners. Replacing the turbine runners was not previously planned. Officials of the Sacramento

Municipal Utility District (a funding contributor) and the Bureau noted that replacing the turbine

runners allows the government to better realize the gains in capacity that result from rewinding the

generators.

36The Dalles was originally constructed with 14 units. Units 15 through 22 were added later.

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a maintenance backlog is not a bad management practice in and of itself,

as long as it can be managed through planning and budgeting techniques.

In contrast with the Corps, Bureau officials maintain that they have a

policy of not deferring maintenance and repairs they consider to be

critical, although noncritical items may be deferred. They added that the

Bureau is free to reprogram funds when needed to fund repairs and

maintenance. However, we noted that unfunded maintenance

requirements for the Bureau exist. In the Pacific Northwest, the Bureau

has been able to address these needs by securing new funding sources.

Specifically, Bonneville and the Bureau in the Pacific Northwest have

signed an agreement under which Bonneville’s power revenues will

directly pay for about $200 million of capital repairs at the Bureau’s power

plants. According to Bureau officials, some of these repairs would likely

not have been made under the existing federal planning and budgeting

processes because of limited and declining federal budgetary resources.

Therefore, it is doubtful that these maintenance needs could have been

addressed in a timely manner without a new funding mechanism.

Delayed Repairs Lead

to Inconsistent Plant

Performance

Failure to fund and perform maintenance and repairs in a timely fashion

can lead to frequent and/or extended outages. These outages force the

PMAs or their customers to purchase more expensive power than the

federal agencies provided in order to satisfy their contractual

requirements. For example, from 1990 through 1992, two or more units of

the Corps’ Carters hydropower plant, in Georgia, were out of service at the

same time for periods ranging from about 3 months to almost 1 year. A

Southeastern official estimated that its wholesale customers had

purchased replacement electricity for about $15 million more than they

would have paid for power marketed by Southeastern. In another

example, Southeastern officials estimated that customers of its

Georgia-Alabama-South Carolina system had paid 22 percent more in 1990

than in the previous year partly as a result of extended, unplanned

outages. Other factors that led to the rate increase included a drought and

increases in operation and maintenance costs at the Corps’ plants. In

addition, as previously noted in our Shasta example, the Bureau restricted

the operation of one of the plant’s generators in response to deteriorating

operating conditions.

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Utilities Attempt to Avoid

Extended Outages by

Ensuring Sufficient

Funding to Maintain and

Repair Their Power Plants

Although the average nonfederal hydropower generating unit is older (48

years) than the Bureau’s (41 years) and the Corps’ (33 years), the

nonfederal units’ availability to generate power is greater than the

Bureau’s and the Corps’. This is true because, according to utility officials,

utilities ensure that sufficient funds exist to repair and maintain their

generating units and thus promote a high level of generating availability.

According to officials from three investor-owned utilities or holding

companies37 and four publicly owned utilities with an average of about

2,458 MW of hydropower generating capacity,38 their hydropower units

were available at least 90 percent of the time—sometimes in ranges

approximating or exceeding 95 percent. Some officials said they would not

tolerate significant reductions in their generating availability because their

hydropower units play key roles in meeting demand during peak times.

Under the traditional regulatory compact between states’ public utility

commissions and utilities, the utilities have an obligation to provide all

existing and future loads in their service territories with power. According

to utility officials, to comply with these obligations, utilities implement

planning and budgeting systems that ensure that they can pay for all

necessary maintenance costs as well as critical repairs and replacements

in a timely fashion.

According to some utility officials, unlike under the federal budgeting

system, utilities typically have the financial capability to quickly obtain

funding to pay for unexpected repairs to their power plants. According to

these officials, utilities are also able to accumulate funds in reserves to

meet future contingencies, such as unexpected breakdowns and repairs of

generating units. In addition, issuing bonds but allowing work to begin

prior to the bond’s issuance is another tool that utilities use to pay for and

make repairs very quickly. For example, according to officials of the

Douglas County Public Utility District, the utility district can respond

quickly to an unexpected breakdown because (1) it has access to some

reserve funds, (2) its commissioners can approve funding via the issuance

of bonds up to 18 months after work was begun on a repair, and (3) its

budgeting process is fast and accurate. For example, the utility district in

January 1999 was completing work on the budget for the next fiscal year

that would begin in only 8 months—namely, August 1999. The budget for

the utility district’s hydropower project reflects funding requirements for

37Idaho Power, Pacific Gas and Electric, and the Southern Company.

38Chelan County Public Utility District, Washington State; Douglas County Public Utility District,

Washington State; Grant County Public Utility District, Washington State; and the New York Power

Authority.

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operations, maintenance, anticipated repairs, and debt service, on the

basis of the long-term operational and financial history for the project.

According to Bonneville, the agency is achieving a similar effect by being

able to quickly provide access to funds and establish reserve funds

through agreements whereby its funds directly pay for the operation,

maintenance, and repair of the Bureau’s and the Corps’ hydropower

plants.

Inadequate Funding

for the Maintenance

and Repair of Federal

Hydropower Plants

May Impact

Marketability of

Federal Electricity

In competitive markets, the price being charged for the electricity and the

reliability of that electricity will continue to be important factors that

consumers will consider when making purchasing decisions. On average,

the electricity sold by the PMAs has been priced less than electricity from

other sources. However, failing to adequately maintain and repair the

federal hydropower plants causes costs to increase and decreases the

reliability of the electricity. The PMAs’ rates will have to be maintained at

competitive levels, and the reliability of this power will have to be

maintained or enhanced to ensure that federal electricity remains

marketable. In addition, the Congress, OMB, and we have been working to

help ensure that the purchase and maintenance of all assets and

infrastructure have the highest and most efficient returns to the taxpayer

and the government.

Delayed and unpredictable federal funding for maintenance and repairs

have contributed to the decreased availability (and reliability) of the

federal hydropower generating units as well as to higher costs that can

cause rates to increase if those costs are included in the rates. However, in

competitive markets, increased rates decrease the marketability of federal

electricity, as nonfederal electricity rates are expected to decline.

Customers are expected to have opportunities to buy electricity from any

number of reasonably priced sources. If the PMAs’ rates are higher than

prevailing market rates, customers will be less inclined to buy power from

the PMAs. According to the Department of Energy’s Energy Information

Administration, retail rates nationwide by 2015 may be about 6 to 19

percent (after inflation) below the levels that they would have been if

competition had not begun. In certain PMA systems—for example, the

Central Valley Project, which, as of fiscal year 1997, had an appropriated

and other debt of about $267 million—the PMAs’ electricity (in this case,

supplied by Western) is already facing competition from nonfederal

generation. If the price of the PMAs’ electricity exceeds the market price,

then its marketability would be hampered.

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Any factors that can cause the PMAs’ electricity rates to increase or that

decrease reliability decrease the marketability of federal electricity. The

marketability of the federal electricity will need to be maintained, as

markets become more competitive, in order to ensure the repayment of

the federal appropriated and other debt. For example, in 1994, in

evaluating the financial status of Bonneville, we noted that:

“. . .[Bonneville’s] financial viability would also be jeopardized if the gap between

[Bonneville’s] rates and the cost of alternative energy sources continues to narrow. Such a

scenario could cause some [Bonneville] customers to meet their energy needs elsewhere,

leaving a dwindling pool of ratepayers to pay off the substantial debt accumulated from

previous years.”39

In Bonneville’s service area, during the mid-1990s, competition decreased

nonfederal electric rates, resulting in some customers leaving or buying

power from less expensive sources, rather than continuing to buy from

Bonneville.

Similarly, in the case of the Tennessee Valley Authority (TVA)—a federally

owned corporation that supplies electricity in Tennessee and six other

Southeastern states), TVA’s sales to industrial customers declined from

about 25 billion kWh in 1979 to 16 billion in 1993 after double-digit annual

rate increases.40

39Bonneville Power Administration: Borrowing Practices and Financial Condition

(GAO/AIMD-94-67BR, Apr. 19, 1994).

40Tennessee Valley Authority: Financial Problems Raise Questions About Long-term Viability

(GAO/AIMD/RCED-95-134, Aug. 17, 1995).

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Actions Taken to Promote Faster and More

Certain Funding to Better Maintain and

Repair the Bureau’s and Corps’ Plants

Various actions have been used to fund the maintenance and repair of

federal hydropower facilities. If these actions work as intended, they have

the potential to deliver dollars for maintenance and repairs faster and with

more certainty than before these actions were implemented. By enabling

repairs to be made on time, they have the potential to help improve the

reliability of the PMAs’ electricity and to continue its existing

rate-competitiveness. Hence, these actions can help to secure the

continued marketability of the PMAs’ electricity and promote the

repayment of the appropriated and other debt. However, these various

actions may reduce opportunities for congressional oversight of the

operation, maintenance, and repair of federal plants and related facilities

and reduce flexibility to make trade-offs among competing and changing

needs.

Direct Funding by

Electricity Revenues

May Pay for Over $1

Billion for

Maintenance and

Repairs

Aware of the problems involved in securing funding through federal

appropriations, the Bureau, the Corps, the PMAs, and PMA customers have

begun to take actions to secure the funding that is required to maintain

and repair the federal hydropower plants and related facilities. An

example is the Bureau’s, the Corps’, and Bonneville’s agreements in the

Pacific Northwest, concluded from 1993 to 1997 and made pursuant to the

Energy Policy Act and other statutes. According to Bureau officials, these

funding arrangements were caused by budget cuts during the 1980s. They

added that the need to perform about $200 million in electricity-related

maintenance in the near future would strain the agency’s ability for

maintenance and repairs in a steady, predictable fashion. These officials

said that, as a result of these funding shortfalls, maintenance backlogs

accumulated and the generating availability of the federal power plants in

Bonneville’s service area declined from 92 to 82 percent. In response, in

1988, the Secretary of the Interior requested that the Congress authorize

Bonneville to directly fund certain maintenance costs. Such authority was

granted in provisions of the Energy Policy Act, which authorized the

funding agreements between Bonneville, the Bureau, and the Corps.

Under these agreements, Bonneville’s electricity revenues will directly pay

for over $1 billion of routine operations and maintenance as well as capital

repairs of the Bureau’s and the Corps’ electricity assets in Bonneville’s

service territory. The agencies expect to be able to plan and pay for

maintenance and repairs in a systematic, predictable manner over several

years. The agencies expect that the resulting funding will allow them to

respond with greater flexibility and speed to the need to repair

hydropower plant equipment. According to Bonneville, the funding

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agreements will create opportunities for the increased availability of

hydropower, financial savings, and the increased revenues. In addition,

Bonneville believes that increased demand for its electricity and the

increased financial resources provided by the funding agreements will

improve its competitive viability and ability to recover the full cost of the

electricity system from which it markets power.41

The Bureau and Bonneville signed two agreements for Bonneville’s

electricity revenues to pay up front for capital repairs and improvements

as well as ordinary operations and maintenance of the Bureau’s electricity

assets in Bonneville’s service area. In January 1993, the Bureau and

Bonneville executed an agreement that provided for funding by Bonneville

of specific capital items, as provided by subsequent “subagreements.” To

date, several subagreements have been signed under which Bonneville will

pay, up front, up to about $200 million for major repairs of the Bureau’s

hydropower plants in Bonneville’s service territory. For example,

Bonneville will spend about $125 million from 1994 through 2007 for

upgrades of the turbines of 18 generating units at the Bureau’s Grand

Coulee power plant, in Washington State.

In addition, in December 1996, the Bureau and Bonneville executed an

agreement whereby Bonneville agreed to directly pay for the Bureau’s

annual operations and maintenance costs as well as selected

“extraordinary maintenance,” replacements, and additions. The parties

anticipated that funding under terms of the agreement would total about

$243 million—ranging from about $47 million to about $50 million per year

from fiscal year 1997 to fiscal 2001.

The Corps and Bonneville have also signed two agreements that allow

Bonneville’s electricity funds to directly pay for the operation,

maintenance, and repair of the Corps’ electricity assets. The first

agreement, signed in 1994, was implemented by a series of subagreements,

under which about $43 million in capital improvements and emergency

repairs are being funded by Bonneville’s electricity revenues. For example,

under one subagreement, about $29 million will be spent for reliability

improvements at 21 of the Corps’ power plants throughout Bonneville’s

service area. Bonneville is also paying for over $5 million in repairs at The

Dalles, Oregon, power plant that were requested but not approved under

the appropriations process. Other work at The Dalles is currently funded

by appropriations. In December 1997, Bonneville and the Corps signed a

second agreement under which Bonneville will directly pay for annual

41Bonneville markets power from the Federal Columbia Rivers Power System.

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operations and maintenance expenses, for Bonneville’s share of joint

project costs allocated to electricity revenues for repayment, and for some

small replacements at the Corps’ projects from which Bonneville markets

electricity. The implementation of this agreement will begin in fiscal year

1999 with an established budget of $553 million from fiscal 1999 through

fiscal 2003—about $110 million per year.

Pacific Northwest’s Funding

Initiatives Include Systematic

Planning and Budgeting

Processes

Because the implementation of the Pacific Northwest funding agreements

is still relatively new, it is too early to determine if they will result in

improvements to the availability factors of the Bureau’s and the Corps’

hydropower plants. At the same time, these efforts include a

comprehensive attempt, that in our view, establishes systematic methods

for identifying and budgeting for routine operations and maintenance, as

well as for capital repairs, rehabilitations, and replacements of the federal

hydropower plants in the region.42 For example, pursuant to the

December 1996 funding agreement, the Bureau prepares an annual

operations and maintenance budget by identifying major line items for

each project during the next fiscal year. The Bureau also prepares 5-year

budgets, on the basis of estimated budgets for each of the years that are

included. The funding totals for the 5-year period cannot be exceeded,

although any expenditures in a year that are less than the targeted amount

are carried over to future years as accounted for in a “savings account.”

The Bureau and Bonneville formed a “Joint Operating Committee” to vote

on and approve the annual and 5-year budgets as well as any modifications

to the budgets. Similarly, the December 1997 operations and maintenance

funding agreement between the Corps and Bonneville features annual and

5-year budgets that are voted upon and approved by the Joint Operating

Committee. Five-year budget totals cannot be exceeded without the

Committee’s approval, but the reallocation of funds is possible. In

addition, if “savings” occur in any year, they are shared between

Bonneville and the Corps and/or carried over to future years.

In addition, annual budgets are proposed and approved less than 1 year in

advance instead of 2 to 3 years in advance—as under the traditional

federal appropriations process. These budget practices reflect more

immediate considerations and, in the views of agency officials, are more

realistic than budgets that have to be compiled 2 to 3 years ahead of time.

42See Executive Guide: Leading Practices in Capital Decision-Making (GAO/AIMD-99-32, Dec. 1998).

That report identifies practices used by leading organizations to make capital investment decisions.

These include evaluating and ranking capital assets on the basis of established criteria and balancing

control and flexibility when funding capital projects.

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Enhanced Set-Aside Funds

Made Available

The potential advantages of the funding agreements in the Pacific

Northwest include enhancing the agencies’ ability to accumulate funds in

the “savings accounts” to pay for emergency repairs, as provided by the

agreement. According to Bureau officials, the savings can be reallocated

between projects on the basis of a telephone call between the Bureau and

Bonneville. The ability of nonfederal utilities to quickly access reserve

funds to meet emergency needs was mentioned by some nonfederal

utilities when they discussed their planning and budgeting processes with

us.

In addition to the funds in savings, a variety of funding sources can be

used to pay for maintenance and repairs, including emergency actions. For

instance, according to Bureau officials, if unexpected repairs need to be

performed, moneys to pay for them may be obtained via a subagreement

between the Bureau and Bonneville. Work on the repairs could begin prior

to Bonneville’s and the Bureau’s signing of the subagreement. According

to Corps officials, some ongoing rehabilitations of the Corps’ Bonneville

and The Dalles projects will continue to be funded with appropriations;

however, maintenance or repairs to be supported under the funding

agreements will no longer be included in the Corps’ budget requests for

appropriations. To pay for the maintenance and repair of the Bureau’s and

the Corps’ hydropower plants, Bonneville can use its cash reserves or its

bonding authority.

Pacific Northwest’s Initiatives

May Allow Agencies to Adapt

New, More Flexible

Maintenance Practices

Because the agreements provide more secure and predictable funding, the

Bureau and the Corps have begun to exercise greater flexibility in how

they maintain and repair their hydropower plants. Consistent with

evolving market competition and with the actions of nonfederal utilities,

Bureau and the Corps officials said their personnel will rely less on

traditional, prescheduled maintenance and rely more on newer, more

flexible maintenance philosophies, such as reliability-centered

maintenance. For example, according to Bureau officials at the agency’s

Pacific Northwest region, staff at the region’s electricity projects schedule

maintenance and repairs, in part, by using a database that shows when

maintenance and repairs were last performed and when a part may need

maintenance or repairs in the future. Repairs or upgrades will be

increasingly made “just-in-time” on the basis of test results. Bureau

officials characterized their maintenance philosophy as evolving to be

more responsive to Bonneville’s marketing requirements as well as to

reduce costs.

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According to these officials, because they now have funds that can be used

to pay for emergency repairs, they can take prudent risks in managing

their maintenance requirements by deferring some repairs that perhaps

can be made just in time or repairing other items that may have higher

priority. For example, according to the managers of the Grand Coulee

power plant, the new funding flexibility allowed the Bureau to reschedule

the spending of up to about $3 million on repairs at the plant.

Initiatives for Funding

by Customers Are

Being Implemented

Direct contributions from customers have been suggested and

implemented as one way to improve how the Bureau, the Corps, and the

PMAs pay for repairs. Although the use of nonfederal funds to finance

federal agencies’ operations is generally prohibited unless specifically

authorized by law, several forms of alternative financing have been

statutorily authorized by the Congress. Supporters of alternative financing,

among them officials from the Bureau, the Corps, the PMAs, and the PMAs’

electricity customers, note that alternative financing allows repairs and

improvements to be made more expeditiously and predictably than

through the federal appropriations process. They believe that alternative

financing could provide more certainty in funding repairs and help address

problems such as deferred maintenance at federal plants.

Through one type of authorized arrangement, referred to, among other

names, as “advance of funds,” nonfederal entities, such as preference

customers, pay up front for repairs and upgrades of the federal

hydropower facilities.43

Under federal statutes, such funding must be ensured before work on a

project can be started. Such funding arrangements have been proposed

and/or implemented in a variety of PMA systems, most prominently

Western’s Pick-Sloan Program in Montana, North Dakota, South Dakota,

and several neighboring states; Loveland Area Projects in Colorado and

nearby states; Hoover and Parker-Davis projects in Arizona and Nevada;

and Central Valley Project in California. For example, under an agreement

executed on November 12, 1997, by the Bureau, Western, and Western’s

power customers within the Central Valley Project, the customers agreed

to pay up front for electricity-related operations and maintenance and

certain capital improvements. These activities are specified in a funding

43According to a Corps official, the Corps’ authority to accept outside funding is much narrower than

the Bureau’s. The Corps’ authority, pursuant to 33 U.S.C. 701h, allows contributions only for flood

control work and only from states and political subdivisions. The Corps’ authority to upgrade

hydropower facilities was further limited by section 216 of the Water Resources Development Act of

1996.

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plan developed by a Governance Board that represents the Bureau,

Western, and the electricity customers. In approving spending proposals,

the Bureau and Western have veto power and two-thirds of the customers

represented on the Board must approve a proposal for it to pass. The

customers will be reimbursed for their contributions by credits on their

monthly electricity bills.

However, advance of funds agreements generally are limited in their

ability to free the funding for the maintenance and repair of federal

electricity assets from the uncertainties of the federal budget process.

They supplement rather than completely replace federal appropriations

and, therefore, may enhance the certainty of funding for repairs and

maintenance but not necessarily provide more speed in obtaining that

funding. For example, in Bonneville’s service territory, Bonneville, the

Bureau, and the Corps can budget 1 year in advance; however, under the

Central Valley Project agreement, the Governance Board approves

electricity-related operations and maintenance budgets 3 years in advance

to coincide with the federal budget and appropriation cycles for the

Bureau and Western. The dovetailing is necessary because federal

appropriations are counted upon to fund the balance of the maintenance

and repairs of the federal electricity assets.

Depending on how they are implemented, the direct funding of

maintenance and repairs by electricity revenues and agreements for

funding by customers pose the risk that opportunities for oversight by

external decisionmakers, such as the Congress, will be diminished. Also,

the lack of oversight limits Congress’s flexibility to make trade-offs among

competing needs. As the Congress and other decisionmakers examine the

need for new arrangements to fund the maintenance and repair of federal

hydropower plants, they may need to consider any reduced opportunities

for oversight, along with the potential benefits of these funding

arrangements. At this time, the Bureau, the Corps, and the PMAs provide

such information as the history and background of their power plants; the

power plants’ generating capacity and electricity produced; annual

electricity revenues, costs, and the repayment status; and related

environmental and water quality issues, to the Congress, other

decisionmakers, and to the public in general. The means of

communicating this information include the PMAs’ annual reports; the

PMAs’; the Bureau’s, and the Corps’ Internet Websites; and letters to the

appropriate congressional committees.

Page 45 GAO/RCED-99-63 Federal Power
Appendix I 

Objectives, Scope, and Methodology

As requested by the Chairman, Subcommittee on Water and Power, House

Committee on Resources, we examined (1) the reliability of the Bureau’s

and Corps’ hydropower plants in generating electricity compared with the

reliability of nonfederal hydropower plants;44 (2) reasons why the Bureau’s

and the Corps’ plants may be less reliable than nonfederal plants and the

potential implications of reduced reliability; and (3) actions taken to

obtain funding to better maintain and repair the Bureau’s and the Corps’

plants.

To compare the generating reliability of the Bureau’s and the Corps’

hydropower plants with that of nonfederal ones, we obtained, analyzed,

and contrasted power plant performance data, including availability and

outage factors, from the Bureau, the Corps, and the North American

Electric Reliability Council (NERC). NERC is a membership of

investor-owned, federal, rural electric cooperatives,

state/municipal/provincial utilities, independent power producers, and

power marketers, whose mission is to promote the reliability of the

electricity supply for North America. NERC compiles statistics on the

performance of classes of generating units, such as fossil, nuclear, and

hydro. The statistics are calculated from data that electric utilities report

voluntarily to NERC’s Generating Availability Data System. The data

reported to NERC exclude many hydropower units, which, on average, are

smaller in generating capacity than those that report to NERC. According to

the Department of Energy’s Energy Information Administration, as of

January 1998, hydropower in the United States was generated by a total of

3,493 generating units with a capacity of 91,871 megawatts (MW). As shown

in table I.1, the federal and nonfederal hydropower generating units

included in our report totaled 1,107 generating units and had a total

generating capacity of 70,005 MW, or an average generating capacity of 63.2

MW per unit. Therefore, the nonreporting units totaled 2,386, and had a

total generating capacity of 21,866 MW, or an average generating capacity

of 9.2 MW per unit. To compare the performance of federal hydropower

generating units with that of nonfederal units, we used data on

hydropower generating units from NERC’s database that excluded federal

hydropower generating units. We did not evaluate NERC’s validation of the

industry’s data, nor the specific input data used to develop the database.

We collected 1998 availability and outage data for the Bureau and the

Corps, but we did not present it in our graphs because comparative data

for the nonfederal units were not available from NERC at the time we

completed our study. We also did not evaluate the specific input data used

44Nonfederal plants include those owned by commercial utilities, municipal utilities, electric

cooperatives, public utility districts, and other entities.

Page 46 GAO/RCED-99-63 Federal Power
Appendix I 

Objectives, Scope, and Methodology

by the Corps and the Bureau to develop their databases on the

performance of federal generating units. Table I.1 depicts some of the

characteristics of the hydropower generating units included in our analysis

of the performance of the Bureau’s, the Corps, and industry’s generating

units. Data for nonfederal units is from 32 nonfederal utilities.

Table I.1: Characteristics of Bureau,

Corps, and Nonfederal Hydropower

Generating Units as of 1997

Agency

Average age of

generating

units (years)

Number of

generating

units

Nameplate

capacity of

generating

units (MW)

Average

nameplate

capacity of

generating

units (MW)

Bureau 41 188 14,515 77

Corps 33 349 20,720 59

Nonfederal 48 570 34,770 61

Note: We excluded units at two of the Bureau’s power plants from our analysis–The Boise River

Diversion because it has not operated in several years, and the Lewiston plant because it is a

small (less than 1 MW) station service power plant for the Trinity power plant.

Source: U.S. Bureau of Reclamation, U.S. Army Corps of Engineers, and NERC.

We discussed the limitations of these performance indicators with officials

from the Bureau, the Corps, the Tennessee Valley Authority,

investor-owned utilities, publicly owned utilities, and other experts in the

electric utility industry.

To explore why federal hydropower plants sometimes performed at lower

levels, we obtained and analyzed various reports on the subject, and

discussed the topic with representatives of Bonneville, the Bureau, the

Corps, various pwer maketing administration (PMA) power customers or

their associations, investor-owned utilities, and nonfederal, publicly

owned utilities. In our analysis, we included information obtained from the

Tennessee Valley Authority, a federally owned utility with high

performance indicators and significant hydropower resources.

In addressing the implications of any reduced performance by federal

plants, we interviewed industry experts, representatives of investor-owned

and publicly owned utilities, and officials of PMA power customers. We also

examined studies about the changes in electricity markets and contacted

national and regional trade associations. Moreover, we addressed

alternative ways of ensuring the enhanced funding of maintenance and

repairs of the federal hydropower plants and related facilities. In this

regard, to the extent possible, we relied upon previous work that we had

Page 47 GAO/RCED-99-63 Federal Power
Appendix I 

Objectives, Scope, and Methodology

performed on federal power, especially work performed during two prior

reviews: Federal Power: Options for Selected Power Marketing

Administrations: Role in a Changing Electricity Industry (GAO/RCED-98-43,

Mar. 6, 1998) and Federal Power: Outages Reduce the Reliability of

Hydroelectric Power Plants in the Southeast (GAO/T-RCED-96-180, July 25,

1996). Moreover, we examined the Corps’, the Bureau’s, and the PMAs’

efforts to make power revenues directly finance the maintenance and

repair of federal hydropower assets. In this regard, we contacted the

Bureau, the Corps, Bonneville, Western, and the PMAs’ power customers

and examined various agreements of arrangements to pay for the

maintenance and repair of the federal hydropower plants and related

facilities.

Our work was performed at various locations, including the offices of

federal and nonfederal parties. Regarding the Corps, these locations

include the agency’s headquarters, Washington, D.C.; the Northwestern

Division, Portland, Oregon; the Portland, Oregon, District; and the

Nashville, Tennessee, District. Because the Corps’ power operations have

been affected by the need to accommodate the migrations of salmon, we

also contacted the Walla Walla and Seattle, Washington, Districts, and the

Corps’ Bonneville (Oregon) power plant. We visited the Bureau’s offices at

the Department of the Interior in Washington, D.C.; Denver, Colorado; the

Central Valley Operations Office, Sacramento, California; the Pacific

Northwest Region, Boise, Idaho; and the Grand Coulee, Washington,

power plant. To gain a perspective on how another federal

electricity-generating entity operated its hydropower program, we

interviewed TVA officials in Chattanooga, Tennessee. Moreover, we

contacted the PMAs at locations including their Power Marketing Liaison

Office, U.S. Department of Energy, Washington, D.C.; Bonneville in

Portland, Oregon; Southeastern in Elberton, Georgia; Southwestern in

Tulsa, Oklahoma; and Western in Golden and Loveland, Colorado, and

Folsom, California.

Our scope included contacting several PMA customers or associations that

represent PMA customers, including the City of Roseville, California;

Colorado River Energy Distributors Association, Tuscon, Arizona; the

Midwest Electric Consumers Association, Denver, Colorado; the Northern

California Power Agency, Roseville, California; and the Sacramento

(California) Municipal Utility District. In addition, we contacted several

investor-owned utilities, utility holding companies, and nonfederal publicly

owned utilities (other than those previously listed) that operate significant

amounts (collectively, over 17,000 MW) of hydropower -generating

Page 48 GAO/RCED-99-63 Federal Power
Appendix I 

Objectives, Scope, and Methodology

capacity; they included the Chelan County (Washington) Public Utility

District; Idaho Power Company; Grant County (Washington) Public Utility

District; Douglas County (Washington) Public Utility District; New York

Power Authority in Niagara, New York; Pacific Gas and Electric Company,

Sacramento, California; South Carolina Electric and Gas; and the Southern

Company in Atlanta, Georgia.

Our work was performed from July 1998 through February 1999 in

accordance with generally accepted government auditing standards.

Page 49 GAO/RCED-99-63 Federal Power
Appendix II 

Comments From the Department of Energy

Page 50 GAO/RCED-99-63 Federal Power
Appendix II 

Comments From the Department of Energy

On March 6, 1999, the Department of Energy provided technical

suggestions for the draft report but deferred to the comments of the

Bureau and the Corps on more substantive matters. For example, Energy

suggested that we clarify the differences between “reliability” and

“availability.” The report already discussed that plants are viewed as

reliable, within the electric utility industry, if they can function without

failure over a specific period of time or amount of usage. The report also

demonstrates that there are several ways of measuring reliability,

including the availability factor and outage factors. Accordingly, we made

no substantive changes to the report.

Page 51 GAO/RCED-99-63 Federal Power
Appendix III 

Comments From the Department of the

Interior

Note: GAO comments

supplementing those in the

report text appear at the

end of this appendix.

See comment 1.

See comment 2.

See comment 3.

Page 52 GAO/RCED-99-63 Federal Power
Appendix III 

Comments From the Department of the

Interior

Page 53 GAO/RCED-99-63 Federal Power
Appendix III 

Comments From the Department of the

Interior

See cover letter.

See cover letter.

See cover letter.

Page 54 GAO/RCED-99-63 Federal Power
Appendix III 

Comments From the Department of the

Interior

Now the report

cover

Now on p. 4.

Now on p. 7.

Now on p. 8.

Now on p. 9.

Page 55 GAO/RCED-99-63 Federal Power
Appendix III 

Comments From the Department of the

Interior

Now on pp. 10 and 11.

Now on pp. 28 and 29.

Now on p. 30.

Now on p. 34.

Now on p. 36.

Now on p. 36.

Now on p. 35.

Now on p. 40.

Now on p. 42.

Now on p. 42.

Now on p. 44.

Page 56 GAO/RCED-99-63 Federal Power
Appendix III 

Comments From the Department of the

Interior

The following are GAO’s comments on the Department of the Interior’s

(including the Bureau of Reclamation’s) letter dated March 12, 1999.

GAO’s Comments Interior provided us with comments that were intended to clarify its

position regarding reliability measures, operation and maintenance, and

funding mechanisms.

1. In its cover letter and general comments, Interior stated that the report

does a good job in recognizing the funding needs for operating and

maintaining electrical-generating facilities. However, Interior stated the

report does not articulate in the executive summary, as it does in the body,

the initiatives undertaken by the Bureau and the Corps to identify

alternative funding sources. We believe that the executive summary

adequately addresses the issue of the initiatives undertaken by the Bureau,

the Corps, and the PMAs, particularly as they relate to efforts in the Pacific

Northwest. Therefore, we did not revise our report.

2. In its cover letter and in general comments, Interior stated that the

report does not articulate the fact that the Bureau’s facilities are operated

to fulfill multiple purposes, such as providing water for irrigation,

municipal and industrial uses, fish and wildlife enhancement, and

electricity generation. According to the Bureau, if water is frequently not

available for generating electricity, the availability factor is not a good

indicator for comparing the reliability of the Bureau’s

hydropower-generating units with other units that are not operated under

multipurpose requirements. Interior also suggested that the nonfederal

projects are freer to maximize power and revenues because they are less

affected by multiple purposes.

We disagree with the Bureau’s position that the report does not recognize

that water is used for multiple purposes and affects how electricity is

generated. For example, the executive summary recognizes that the

Bureau and the Corps generate electricity subject to the use of water for

flood control, navigation, irrigation, and other purposes. In addition, the

report recognizes, in chapter 2, that the Bureau and other utilities utilize

periods of low water and low demand to perform scheduled maintenance

and repairs. This would tend to decrease the availability factors of these

entities. The report also states that this practice may be regarded as good

business practices. We further disagree that the availability factor is not a

good basis for comparing the reliability of different projects. The

availability factor is a widely accepted measure of reliability that has

Page 57 GAO/RCED-99-63 Federal Power
Appendix III 

Comments From the Department of the

Interior

validity, as long as it is understood in terms of other factors that affect

how plants are operated. Moreover, we disagree that other utilities

necessarily operate hydropower plants that are affected less by multiple

purposes. In fact, as we have noted previously, for other utilities, the

multiple uses of the water are regulated through conditions in the utilities’

hydropower-plant-operating licenses, which are issued by the Federal

Energy Regulatory Commission.

The Bureau contends that the availability of its plants is affected by the

fact that more of the Bureau’s plants are located on pipelines, canals, and

water diversion facilities than most nonfederal plants. We recognized this

point in chapter 2.

3. In the cover letter and in its general comments, Interior stated that the

forced outages factor is a better indicator of reliability than the availability

factor for multiple purpose facilities. In addition, in its cover letter,

Interior indicated that the Bureau’s benchmarking studies indicate that its

plants compare favorably with other plants in the area of reliability.

Regarding forced outages factors, our report recognizes that there are

several indicators of reliability and the forced outages factor is one of

most meaningful. More generally, we disagree with Interior’s conclusion

that the Bureau’s plants are as reliable as those of other power providers.

As shown in chapter 2 of this report, although the Bureau’s forced outages

factors are on par with those of nonfederal utilities, the Bureau’s

availability factor is lower, and it has been improving. Moreover, the

Bureau’s scheduled outages factors are higher than nonfederal utilities.

In its general comments, Interior adds that reliability is a measure of

whether a plant can operate when it is needed, while availability is a

measure of a unit’s ability to operate within a given time period. These

factors, stated the Bureau, can be equated only when a plant is required to

operate for the full time of the period. The Bureau added that optimum

availability is unique to each plant, depending on such factors as design,

time, water supply, location, and cost. As stated in our report, reliability is

a measure of a plant’s ability to operate over a specific period or amount

of usage. We further agree that the significance of an availability factor

should be understood within the context of various factors, some of which

are mentioned by the Bureau. We revised chapter 1 to recognize that

assessing the performance of a hydropower plant or unit by examining its

availability factor calls for understanding additional variables. We added

language to reflect that the availability factor needs to be understood in

terms of such factors as the kind of demand the plant meets (e.g., whether

Page 58 GAO/RCED-99-63 Federal Power
Appendix III 

Comments From the Department of the

Interior

it meets peak demand), the availability of water throughout the year, and

the purposes satisfied by the dam and reservoir.

4. According to Interior, the report implies that the Bureau delays repairs

and maintenance, pending the availability of funds. The Bureau stated that

it performs repairs and maintenance when needed by reprioritizing funds.

We revised the report in chapter 3 to recognize the Bureau’s statement that

it reprioritizes funding. However, the example of the delayed repairs

because of delayed funding at the Bureau’s Shasta, California, project,

illustrates our point that repairs and maintenance are delayed when funds

are not forthcoming.

5. Interior stated that the Bureau has undertaken a program to improve its

performance by benchmarking its electricity operations against the rest of

the industry and is continually striving to improve, given the legal and

financial constraints encountered. Our report does not imply that these

agencies are operating in an unbusinesslike manner but shows that the

Bureau’s availability has improved in the face of financial and budgeting

constraints. We revised chapter 1 to recognize the Bureau’s benchmarking

effort.

Specific Comments 1. Interior commented that the title of the report implies that the Bureau

has reduced its operation and maintenance program. Interior stated the

Bureau has always implemented preventive and reliability-centered

maintenance and that adequate funding for these activities has been

available. Chapter 4 of the report recognizes that the Bureau, in particular

in the Pacific Northwest, will increasingly practice reliability-centered

maintenance and practiced preventive maintenance in the past. However,

the efforts of the Bureau’s field locations to engage in direct or advance

funding arrangements serves as evidence that faster and more predictable

funding is needed.

2. We added “transmission system” to the report, as requested by Interior.

3. We revised the report to indicate that the Bureau’s forced outages rate

from 1993 through 1997 was the same as the nonfederal sector’s.

4. According to Interior, our comparing plants of different size and type

may distort our conclusions about the performance of the federal and

nonfederal plants. We disagree. As shown in appendix I, the federal and

nonfederal electrical-generating units in our analysis were about same size

Page 59 GAO/RCED-99-63 Federal Power
Appendix III 

Comments From the Department of the

Interior

because our analysis of nonfederal units excluded about 2,400 smaller

ones that averaged about 9 MW of generating capacity. In addition, our

decision to include both conventional generators and pump generators in

our analysis was based on the fact that the Corps’ performance data did

not separate its conventional and pump units. The Bureau itself, in its 1996

benchmarking study, included seven pump units (about 323 MW) at its

Grand Coulee and Flatiron plants as conventional generating units.

Moreover, although the Bureau has generating units from 1 MW to 700 MW,

it used only two MW-size categories (1 to 29 MW, and 30 MW and larger) in

comparing the availability and outages factors of its plants to the industry

in its 1996 benchmarking study. In addition, our analysis of the availability

factors of the Bureau’s hydropower-generating units from 1993 through

1997 showed that among pump generators as well as the size categories

zero to 10 MW, 11 to 50 MW, 51 to 100 MW, and 101 to 200 MW, the Bureau’s

hydropower units had lower availability factors than the industry as a

whole.

5. According to Interior, although the customers funded up to $22 million

in repairs for Shasta, the rewind contract was awarded for $8.8 million,

including total costs to replace the turbines estimated at $12.2 million.

This point is expanded upon under comment 12.

6. Interior disagrees with the statement in the draft report that advance or

direct funding arrangements decrease opportunities for congressional

oversight. We revised the report to state that, although these arrangements

could diminish opportunities for oversight, the Bureau, the Corps, and the

PMAs provide such information as the history and background of their

power plants; the plants’ generating capacity and electricity produced;

annual electricity revenues and costs; and related environmental and

water availability issues to the Congress, other decisionmakers, and to the

public. The means of communicating this information include the PMAs’

annual reports; the PMAs’, the Bureau’s, and the Corps’ Internet Websites;

and letters to the Congress.

7. According to Interior, our statement that “the longer the scheduled

outage, the less efficient the maintenance program,” is out of place as it

pertains to federal plants. The statement would apply primarily to

run-of-the-river plants, according to Interior. The Department noted that

federal plants are not allowed to earn more revenues and outages do not

have an impact on revenues if water is not available for generating

electricity.

Page 60 GAO/RCED-99-63 Federal Power
Appendix III 

Comments From the Department of the

Interior

We believe our report sufficiently addresses these points. We have already

noted that performing scheduled outages during times of low water or low

demand may constitute good business practice. In addition, we have noted

the need to understand such factors as the kind of demand a plant meets

(for instance, whether it meets peak demand) and the availability of water

for generating power. Our report also states that, as markets evolve to

become more competitive, operating plants at higher availability factors

may allow the PMAs and utilities to take advantage of new opportunities to

earn revenue by selling ancillary services. In addition, we continue to

believe that, all things being equal, having plants on-line for longer periods

of time is also good business practice, as stated in the Bureau’s 1996

benchmarking report.45

8. As suggested by Interior, we revised the report to read “Western

Systems Coordinating Council.”

9. As suggested by Interior, we revised the report to reflect that three of

five units at Shasta were repaired. The other two were not.

10. In response to Interior’s comment, we revised the report to reflect that

while the Bureau defers noncritical items, it does not defer items it deems

to be critical. Interior also notes that unfunded maintenance requirements

do not necessarily indicate a deferred maintenance situation. In our view,

any maintenance requirements that are put off until the future are

deferred. However, we revised the report to state that deferred

maintenance is not problematic as long as it can be managed.

11. As requested by Interior, we added “due to limited and declining

federal budgetary sources.”

12. Interior clarified that the costs of rewinding the Shasta units decreased

from $10.5 million (low bid) in 1994 to $8.8 million in 1996. The rewind

contract was executed in 1996 to increase the rating to 142 MW per unit

versus the higher-priced rewind in 1994 to 125 MW per unit. Most

importantly, the $21.5 million commitment includes the replacement of

turbines in three units that were not included in earlier cost estimates.

Because of the new information provided regarding the nature of the

additional work at Shasta, we revised our report in chapter 3 to state that

the Bureau expanded the scope of work to be performed at the plant.

45See U.S. Bureau of Reclamation, A New Era of Power, Performance, and Progress: Future

Generations (1996).

Page 61 GAO/RCED-99-63 Federal Power
Appendix III 

Comments From the Department of the

Interior

13. As suggested by Interior, we revised the text to state that the funding

arrangements in the Pacific Northwest were necessitated by budget cuts

during the 1980s. Also, the need to fund about $200 million in maintenance

in the near term would limit the Bureau’s ability to pay for maintenance

and repairs in a steady, predictable fashion.

14. As suggested by Interior, we deleted the word “electricity” from the

reference to the Bureau’s operation and maintenance budget.

15. As suggested by Interior, we revised the text to eliminate references to

“separate” Joint Operating Committees.

16. As suggested by Interior, we changed “defer spending” to

“reschedule.”

Page 62 GAO/RCED-99-63 Federal Power
Appendix IV 

Comments From the Department of Defense

Note: GAO comments

supplementing those in the

report text appear at the

end of this appendix.

Page 63 GAO/RCED-99-63 Federal Power
Appendix IV 

Comments From the Department of Defense

On March 16, 1999, the Department of Defense (including the Army Corps

of Engineers) provided us with a letter acknowledging that the Corps’

verbal comments, discussed with us at a March 10, 1999, meeting, had

been resolved. The primary verbal comment was that we did not reflect

changes in the performance of the Corps’ hydropower plants that occurred

in fiscal year 1998. The Corps suggested that we include these data in

various graphs in our report. As discussed with Corps officials, we

addressed the changes in the Corps’ performance in the text of our report,

primarily in chapter 2. However, we declined to show changes in the

graphs because the 1998 data were not available for the nonfederal

hydropower generating units at the time we completed our review.

Page 64 GAO/RCED-99-63 Federal Power
Appendix V 

Comments of the Bonneville Power

Administration

Note: GAO comments

supplementing those in the

report text appear at the

end of this appendix.

See comment 1.

See comment 2.

Page 65 GAO/RCED-99-63 Federal Power
Appendix V 

Comments of the Bonneville Power

Administration

Now on pp. 10,

11, and 45.

See comment 3.

See comment 4.

Now on p. 10.

Page 66 GAO/RCED-99-63 Federal Power
Appendix V 

Comments of the Bonneville Power

Administration

Now on p. 8.

See comment 5.

Now on p. 9.

See comment 6.

Now on p. 33.

See comment 7.

Now on p. 38.

See comment 8.

Page 67 GAO/RCED-99-63 Federal Power
Appendix V 

Comments of the Bonneville Power

Administration

The following are GAO’s comments on the Department of Energy’s

(including the Bonneville Power Administration’s) letter dated March 11,

1999.

GAO’s Comments On March 11, 1999, Bonneville provided us with general and specific

comments regarding our draft report. Bonneville noted that in its view, we

“sought to conduct a fair assessment of the U.S. Army Corps of Engineers

(Corps) and the Bureau of Reclamation (Reclamation) facilities during the

time of the study.”

1. Bonneville understood that we were not requested to evaluate the

direct-funding agreements in the Pacific Northwest. However, Bonneville

suggested that we add language to the report to reflect that the funding

agreements between itself, the Bureau, and the Corps contain a systematic

approach to maintenance planning and investment that creates

opportunities for increased hydropower availability, financial savings, and

increased revenues. We believe that our report addresses these points.

However, we added language that Bonneville believes these enhancements

will be attained as a result of the funding agreements.

2. As noted by Bonneville, our report stated that the availability factors of

the Bureau’s and the Corps’ hydropower plants in the Pacific Northwest

are lower than in the rest of the nation. Bonneville suggested that we

clarify the report, in the executive summary, by stating that Bonneville, the

Bureau, and the Corps recognized the lower reliability of the plants in the

Pacific Northwest and took action through a series of direct-funding

agreements to address the problem. Bonneville further suggested a

clarification that during the period 1993 through 1997, the federal agencies

undertook extensive upgrades and rehabilitations of the Bureau’s plants

partly as a result of the increased funding flexibility provided by the

direct-funding agreements. We agreed that these statements would clarify

the report and incorporated them.

3. Bonneville noted that the draft report stated that funding maintenance

and repair actions through direct customer contributions or through direct

payments from the PMAs’ revenues reduced opportunities for congressional

oversight. According to Bonneville, the funding arrangement in the Pacific

Northwest was specifically supported by the Senate Appropriations

Committee in 1997. Bonneville also stated that its annual congressional

budget submission includes programmatic information on the operations

and maintenance funding that Bonneville plans to provide for the Bureau

Page 68 GAO/RCED-99-63 Federal Power
Appendix V 

Comments of the Bonneville Power

Administration

and the Corps. In response to this and other comments, we revised the

executive summary and chapter 4 to show that information is now being

made available to the Congress and others about the operation of the

federal power program. For instance, the Bureau, the Corps, and the PMAs

provide such information as the history and background of their power

plants; the plants’ generating capacity and electricity produced; annual

electricity revenues and costs; and related environmental and water

quality issues to the Congress, other decisionmakers, and to the public.

The means of communicating this information include the PMAs’ annual

reports; the PMAs’, the Bureau’s, and the Corps’ Internet Websites; and

letters to the appropriate congressional committtees.

4. We revised the executive summary as recommended by Bonneville by

adding “under the traditional appropriations process.”

5. Bonneville believed that the location of figure 1 in the executive

summary was confusing, since it discussed national availability factors but

was positioned over the discussion of availability in the Pacific Northwest.

We agree and have relocated the figure.

6. The draft’s executive summary stated that some of Bonneville’s power

customers are leaving the agency for less-expensive sources. Bonneville

stated that some customers left the power administration in an earlier

period but the situation today is significantly different, with demand for

electricity and other products exceeding the supply. Bonneville stated that

increasing demand for its electricity as well as the increased financial

resources provided by its funding agreements with the Bureau and the

Corps will improve its competitive viability and ability to recover the full

cost of the Federal Columbia River Power System. We agreed and revised

the report in the executive summary and chapter 4.

7. Bonneville suggested that the final report recognize that, for large

hydropower systems, the ability to earn electricity revenues depends on

the availability of water and of operable hydropower-generating units.

These conditions and other factors must be considered to optimize the

maintenance program for the plants from which Bonneville markets

electricity. We agreed and revised chapter 3 accordingly.

8. As suggested by Bonneville, we added language to chapter 3 to the

effect that like the Douglas County Public Utility District, Bonneville will

be able to quickly provide access to funds and establish reserved funds

through agreements whereby its funds directly pay for the operation,

Page 69 GAO/RCED-99-63 Federal Power
Appendix V 

Comments of the Bonneville Power

Administration

maintenance, and repair of the Bureau’s and the Corps’ hydropower

plants.

Page 70 GAO/RCED-99-63 Federal Power
Appendix VI 

Major Contributors to This Report

Peg Reese

Philip Amon

Ernie Hazera

Martha Vawter

(141194) Page 71 GAO/RCED-99-63 Federal Power
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