GAO

United States General Accounting Office

Report to the Chairman, Subcommittee 

on Water and Power, Committee on 

Resources, House of Representatives

March 2000 POWER MARKETING 

ADMINISTRATIONS

Their Ratesetting 

Practices Compared 

With Those of 

Nonfederal Utilities

GAO/AIMD-00-114

Page 1 GAO/AIMD-00-114 Power Marketing Administrations

Contents

Letter 3

Appendixes Appendix I: Objectives, Scope, and Methodology 44

Appendix II: Comments From Southeastern, Southwestern, 

and Western Area Power Administrations 48

Appendix III: Comments From the Bonneville Power Administration 50

Tables Table 1: Percentages of the PMAs’ Debt Repaid Before Due as of 

Fiscal Year-End 1998 (in Total and at Least 10 Years Before Due) 28

Table 2: Percentages of the PMAs’ High Interest and Low Interest 

Debt Repaid as of Fiscal Year 1998 31

Figures Figure 1: Percentages of Retail and Wholesale Power Sales for PMAs, 

POGs, and IOUs for 1998, in Megawatthours (mWh) and Dollars 7

Figure 2: Illustrative Pinch-Point Year for a PMA Ratesetting System 16

Figure 3: The Three PMAs’ Rate Development Process 18

Figure 4: Bonneville’s Rate Development Process 21

Figure 5: Financing Costs as a Percentage of Operating Revenues 

for the PMAs, IOUs, and POGs for Fiscal Year 1998 32

Figure 6: Average 1998 Operating Expenses by Generation Type 

for Plants Operated by IOUs 35

Figure 7: Percentage of Power Generated by Hydroelectric Plants 

for PMAs, IOUs, and POGs for Fiscal Year 1998 36

Figure 8: Investment in Utility Plant per Megawatt of 

Generating Capacity, 1998 37

Figure 9: Average Revenue per Kilowatthour for Wholesale Sales 

for 1998 for PMAs, POGs, and IOUs 39
Contents

Page 2 GAO/AIMD-00-114 Power Marketing Administrations

Abbreviations

CVP Central Valley Project

CWIP construction-work-in-progress

DOE Department of Energy

EIA Energy Information Administration

EPAct Energy Policy Act of 1992

FERC Federal Energy Regulatory Commission

GA-AL-SC Georgia-Alabama-South Carolina

IOU investor-owned utility

mWh megawatthour

O&M operating and maintenance

PMA power marketing administration

POG publicly owned generating utility

PRS power repayment study

PUC public utility commission

RRS revenue requirement study

SCLA-IP Salt Lake City Area Integrated Projects
Page 3 GAO/AIMD-00-114 Power Marketing Administrations

United States General Accounting Office

Washington, D.C. 20548

Accounting and Information

Management Division

B-283123 Letr

March 30, 2000

The Honorable John T. Doolittle

Chairman, Subcommittee on Water and Power

Committee on Resources

House of Representatives

Dear Mr. Chairman:

This report responds to your request that we review the ratesetting 

practices of the Department of Energy’s (DOE) power marketing 

administrations (PMA) and compare them with those of other utilities. As a 

follow-on to our previous work, which discussed the PMAs’ ability to defer 

recovering through rates some of the federal government’s investment in 

power facilities, you asked that we examine the PMAs’ ratesetting practices 

and assess their impact on the PMAs’ future competitiveness. Specifically, 

you asked us to determine

1. how the PMAs set their rates to recover costs, 

2. how the PMAs’ ratesetting practices compare to those of investorowned and publicly owned utilities, and

3. the impact of the PMAs’ ability to defer repayment of portions of their 

debt on their future competitiveness. 
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We evaluated the assumptions and processes the PMAs use in setting their 

rates and recovering their costs by collecting key data and analyzing 

methodologies at the four PMAs,1

 DOE, and the Federal Energy Regulatory 

Commission (FERC) as well as three investor-owned utilities (IOU) and 

four publicly owned generating utilities (POG).2

 We also compared the 

PMAs’ financial data to IOU and POG financial data obtained from the 

Energy Information Administration (EIA).3

 We conducted our review from 

June 1999 through March 2000 in accordance with generally accepted 

government auditing standards. Additional information on our objectives, 

scope, and methodology is contained in appendix I. 

Results in Brief The PMAs determine the adequacy of rates by performing annual reviews 

of their projected costs and revenues,4

 using processes and assumptions 

that are to identify and factor into rates costs that are legally recoverable, 

while keeping rates as low as possible. Southwestern, Southeastern, and 

most Western projects make this determination through power repayment 

studies (PRS); Bonneville uses a revenue requirement study (RRS). These 

studies analyze historical data and project estimated future costs and 

revenues as a key part of ratesetting. The primary goal of the review is to 

determine whether existing rates will generate sufficient revenue to 

recover identified costs over the period under review. The PMAs are to take 

action to remedy the situation when the projections indicate that this cost 

recovery goal is not being met. Any consideration of a rate change prompts 

a public process during which customers and the general public are able to 

provide input before the change is finalized and approved by FERC. 

1

The four PMAs are Bonneville Power Administration (Bonneville), Southeastern Power 

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

Western Area Power Administration (Western). Because of differences in legislative 

authority and ratesetting practices, in this report we sometimes discuss Bonneville 

separately and refer to the other PMAs as “the three PMAs.”

2

See appendix I for a further discussion of our selection criteria for IOUs and POGs.

3

EIA is a statistical and analytical agency in the Department of Energy. 

4

The three PMAs’ rates are based on cash flow projections of the revenue required to 

recover costs. Bonneville’s revenue requirements are set at the higher of forecasted accrued 

expenses (including depreciation expense) or cash requirements. Revenue generated in any 

given year is used to repay annual expenditures of the year, such as operating and 

maintenance costs, interest costs, and the cost of power purchased from other utilities for 

resale. Any revenue remaining after payment of such annual expenditures is allocated to 

repay appropriated debt.
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Although there are similarities between the PMAs’ ratesetting practices and 

those of IOUs and POGs, there are some key differences. Regulatory 

oversight and the processes and assumptions that guide cost recovery vary 

among PMAs, IOUs, and POGs. In addition, rates are affected by 

responsibilities to investors and/or taxing authorities and whether the 

entity operates in a cost-based or market-based environment. All the 

entities we reviewed had some kind of public process that took place when 

changes in rates were under consideration. However, PMAs differed 

significantly from IOUs and POGs in two areas. First, they have the 

flexibility to defer repayment of appropriated debt5

 until the year due, 

which is typically longer than other utilities are able to defer repayment of 

their debts.6

 Second, unlike IOUs and POGs, PMAs do not have to generate 

a return for owners7

 and generally do not pay taxes.

While PMAs have the flexibility to defer repayment of appropriated debt 

until the year due, in practice they have repaid significant portions before 

due and generally retire high interest rate debt first. Nevertheless, the 

financing costs as a percentage of operating revenues of three of the 

PMAs—Bonneville, Southeastern, and Western—are high relative to IOUs 

and POGs. Bonneville’s financing costs are relatively high because of its 

large interest-bearing debt of about $13.8 billion, of which $4.2 billion 

relates to nonoperational and canceled nuclear facilities. Southeastern’s 

and Western’s financing costs are relatively high because of capital 

expenditures made in recent years, some at relatively high interest rates, 

much of which has not yet been repaid. These high financing costs may 

become more significant in an increasingly competitive electricity industry. 

While the high financing costs will pose challenges for these three PMAs, 

5

We call this appropriated debt because PMAs are required to set rates to repay 

appropriations used for capital investments with interest. However, these reimbursable 

appropriations are not technically considered lending by Treasury. The PMAs in some cases 

receive financing through means other than appropriations. For example, Bonneville issues 

bonds to the U.S. Treasury and Western receives nonfederal (third party) financing at 

certain projects.

6

Due dates for appropriated debt vary. In general, appropriated debt related to (1) original 

construction of assets used to generate power must be paid within 50 years, (2) assets used 

to transmit power must be paid within 35 to 45 years, and (3) replacements of assets that 

generate or transmit power must be paid within 50 years or their useful service lives, 

whichever is less.

7

IOUs are typically expected to generate a return for shareholders, and some POGs transfer 

funds from accumulated net revenues to other government units to fund other government 

activities.
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all of the PMAs have important cost advantages that enhance their 

competitive positions as industry restructuring proceeds and other utilities 

attempt to cut costs and become more efficient. Key among the PMAs’ 

advantages is that they market low-cost hydropower, much of it generated 

from facilities built decades ago at low cost. In addition, in contrast to IOUs 

and POGs, PMAs are generally not required to pay taxes or generate a 

return for owners. Because of these inherent cost advantages, the PMAs 

overall are well positioned competitively.

Background The PMAs were established between 1937 and 1977 to sell and transmit 

electricity generated primarily from federal hydropower facilities. The 

facilities were constructed as part of a larger effort to develop 

multipurpose water projects that have functions in addition to power 

generation, such as navigation, flood control, irrigation, water supply, and 

recreation. Most of these facilities were constructed, and continue to be 

owned and operated, by the Department of the Interior’s Bureau of 

Reclamation and the U.S. Army Corps of Engineers. As required by law, the 

PMAs give preference in the sale of power to public power customers such 

as irrigation districts, municipally owned utilities, customer-owned 

cooperatives, and, in some cases, state governments and the federal 

government.

The electricity industry encompasses both wholesale and retail markets. 

Wholesale power sales are sales by one entity to another for resale to 

ultimate consumers. Retail power sales are sales to residential, 

commercial, industrial, and other end-use consumers. According to EIA, 

about one half of all electricity generated in the United States is traded in 

the wholesale market before being sold to the ultimate consumer. 

The PMAs sell power primarily in the wholesale power market. In contrast, 

IOUs and POGs sell mostly retail power. Figure 1 shows the percentages of 

retail and wholesale power sales for the PMAs, POGs, and IOUs for 1998.
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Figure 1: Percentages of Retail and Wholesale Power Sales for PMAs, POGs, and 

IOUs for 1998, in Megawatthours (mWh) and Dollars

Source: Developed by GAO based on data from the PMAs’ annual reports and composite national data 

on IOUs and POGs from EIA.

81%

19%

84%

16%

37%

63%

25%

75%

25%

75%

13%

87%

0%

20%

40%

60%

80%

100%

PMAs

(mWh)

PMAs ($) POGs

(mWh)

POGs ($) IOUs

(mWh)

IOUs ($)

Wholesale Sales Retail Sales

Percentage
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The PMAs operate in an electricity industry that is changing from a highly 

regulated environment, in which cost is the main factor in determining 

rates, to one that increasingly relies on competitive markets to set prices. 

The implementation of the Energy Policy Act of 1992 (EPAct) and 

initiatives to promote retail competition in a growing number of states are 

creating greater competition in the industry. EPAct authorized FERC8

 to 

order public utilities to provide transmission, or “wheeling,”9

 services to 

promote competitive wholesale power sales. Before the passage of EPAct, 

FERC could not require utilities to provide wheeling services to promote 

wholesale power sales. 

Pursuant to its authority under the EPAct, in 1996 FERC issued Order 888, 

which required utilities to offer wheeling services to other utilities or 

electricity providers at the same price and availability that they give 

themselves. This promotes competition by allowing generators to make 

sales for resale (e.g., wholesale sales) to noncontiguous utilities. Order 888 

also allows recovery from customers of prudently incurred stranded costs10

by utilities transitioning into a competitive marketplace. Recovery of 

wholesale stranded costs is regulated by FERC. Recovery of retail stranded 

costs is regulated at the state level, and implementation varies by state. 

In addition, legislatures and public utility commissions in most states are 

considering, or have approved, initiatives that will promote competition in 

the market for retail power sales. As of February 1, 2000, 24 states had 

enacted legislation or regulatory orders promoting retail access to 

competitive markets; the remaining states and the District of Columbia 

were either actively pursuing restructuring or investigating restructuring 

options.

8

FERC is an independent agency within the Department of Energy with broad regulatory 

authority over the interstate transmission and sale of wholesale electricity, natural gas, and 

oil.

9

Wheeling is the transmission of power over lines owned by another utility.

10As defined by FERC, a stranded cost is any legitimate, prudent, and verifiable cost 

incurred by a public or transmitting utility that is no longer economically viable in a 

competitive environment. 
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PMA Ratesetting 

Practices

The PMAs’ ratesetting practices (i.e., the processes and assumptions used 

in ratesetting) are expected to identify and factor into rates all costs that 

are legally recoverable from power customers while keeping rates as low 

as possible.11 The PMAs receive their authority to set cost-based rates from 

the Reclamation Project Act of 1939 and the Flood Control Act of 1944. In 

addition, the primary statute governing Bonneville’s ratesetting process is 

the Northwest Power Act. DOE’s ratesetting practices for the PMAs have 

been established by the Secretary of Energy in Order RA 6120.2.12 Each 

PMA performs an annual analysis to identify revenue requirements13 for, in 

general, a 50-year period.14 In doing so, each PMA costs to be recovered and 

levels those costs over the ratesetting period so as to keep rates low and 

stable. Rates are then set to recover costs.

11Previous GAO reports (Power Marketing Administrations: Cost Recovery, Financing, and 

Comparison to Nonfederal Utilities (GAO/AIMD-96-145, September 19, 1996); Federal 

Electricity Activities: The Federal Government’s Net Cost and Potential for Future Losses, 

volumes 1 and 2 (GAO/AIMD-97-110 and 110A, September 19, 1997); and Power Marketing 

Administrations: Repayment of Power Costs Needs Closer Monitoring (GAO/AIMD-98-164, 

June 30, 1998)) have demonstrated that the PMAs are not recovering all costs of generating, 

transmitting, and marketing power.

12DOE Order RA 6120.2 on “Power Marketing Administration Financial Reporting” 

establishes requirements for a broad range of financial issues, including setting rates, 

recovering costs, preparing repayment studies, establishing and maintaining the accounting 

systems, and financial reporting.

13Revenue requirements are the revenues that must be generated to repay costs and debt 

and irrigation payments due in the applicable time period. In addition, Bonneville includes 

in its revenue requirements an annual reserve amount to mitigate the risk of not achieving 

repayment obligations.

14The period covered by the PRSs is longer than 50 years for some projects. For example, the 

PRSs cover 60 years for the Salt Lake City Area—Integrated Projects and 100 years for the 

Pick-Sloan project. It can also be shorter than 50 years if the appropriated debt related to 

assets used to generate and transmit power is paid off earlier. As discussed later, there can 

be a difference between the repayment period and the ratesetting period.
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Identifying Revenue 

Requirements

PMAs are required to establish power rates sufficient to pay annual 

expenditures, such as operating and maintenance costs, interest costs, and 

the cost of power purchased from other utilities for resale. Rates must also 

be sufficient to repay debt, including the appropriations that financed 

completed generation and transmission facilities.15 In addition, rates must 

be sufficient to repay certain nonpower costs the Congress has assigned to 

power users to repay. Bonneville’s and Western’s rates are set to collect 

additional revenue to repay the federal appropriations that financed certain 

irrigation facilities.16 In addition, Bonneville is required to provide power to 

specified residential and small farm consumers of IOUs.

In addition to the above, Bonneville’s rates must cover the costs of

• bonds issued to the Treasury to finance capital programs, such as 

transmission system development, conservation, and fish and wildlife 

enhancement;

• debt service on nonfederal bonds primarily for the construction of 

Energy Northwest (formerly the Washington Public Power Supply 

System) nuclear plants;17 and 

15In a limited number of cases, the capital costs of some completed projects are not included 

in rates. For example, as discussed later, certain construction costs and capitalized interest 

at the Richard B. Russell Project are not included in Southeastern’s rates. Other costs that 

are sometimes not recovered from rates include certain environmental mitigation costs that 

have been legislatively exempted from recovery. 

16Reclamation law provides for Bonneville and Western to use their power revenues to repay 

a portion of the capital costs allocated to completed irrigation facilities that are determined 

by the Secretary of the Interior to be beyond the ability of the irrigators to repay. As of 

September 30, 1998, approximately $863 million in irrigation costs had been allocated for 

repayment through power revenues at Bonneville and $3,139 million at Western. Of those 

amounts, $25 million (3 percent) had been repaid at Bonneville and $35 million (1 percent) 

repaid at Western.

17Bonneville used its contracting authority to acquire all or part of the generating capability 

of nuclear power projects in Energy Northwest. Under these contracts, Bonneville agreed to 

pay all or part of the annual projects’ budgets, including debt service, whether or not the 

projects are completed. Two of the nuclear plants are nonoperational and therefore do not 

generate revenues. As of September 30, 1998, Bonneville had $6.9 billion outstanding in 

nonfederal project debt. 
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• measures to protect fish and wildlife populations and to mitigate 

damage to Pacific Northwest fish stocks affected by the construction 

and operation of the Federal Columbia River Power System.18

DOE Order RA 6120.2 requires that the PMAs annually determine the 

adequacy of power rates by calculating how much revenue is needed each 

year to meet annual expenditures and debt repayment requirements over 

the ratesetting period. The three PMAs make this determination through 

power repayment studies (PRS). Bonneville uses a revenue requirement 

study (RRS), which is similar to a PRS. Bonneville considers several risks 

in developing its revenue requirements. Among the risks considered are 

weather-related uncertainties associated with the reliance on hydropower 

generation, market prices for power, general economic conditions, the 

performance of its generation assets, and expenditures Bonneville must 

make to protect, mitigate, and enhance fish and wildlife populations. 

Bonneville’s target is to set rates that will result in a 97.5 percent 

probability that payments to the Treasury will be made on time and in full 

for each year of the rate period (or 88 percent over a 5-year period). Once 

Bonneville establishes its revenue requirements, it allocates costs to 

classes of service and designs rates.

PMAs prepare these studies on either a project basis or a system basis, 

consistent with how they sell power and set rates. For example, 

Southeastern sells power within four separate power systems; each 

includes one or more Corps projects for which rates are set. Bonneville’s 

RRS includes all of its power projects. However, Bonneville is required by 

26 FERC 61,096 to separately develop transmission rates.

A PMA’s PRS or RRS determines its annual revenue requirements by 

analyzing historical financial information and projected estimates of future 

revenues, expenditures, and capital costs throughout the period covered by 

the study. Historical financial information is gathered from the accounting 

records. In addition, historical, and projected generation, hydrological and 

other data are provided by project operators (i.e., the Bureau and the 

Corps). 

18Bonneville’s estimated range of funding is $438 million to $721 million annually for fiscal 

years 2002 through 2006.
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When preparing a PRS or RRS, the PMAs make several assumptions about 

the future in establishing revenue requirements and setting rates. Key 

assumptions include the following:

• Historical hydrological data and projected river operations will be used 

to project future water conditions.

• Appropriated debt related to the original construction of assets used to 

generate power will generally be repaid within 50 years.19

• Appropriated debt related to assets used to transmit power will 

generally be repaid within 35 to 45 years.

• Appropriated debt related to replacements of assets used in generating 

and transmitting power will be repaid within the lesser of 50 years or 

their estimated useful service lives.

• The PRS/RRS will include a “cost evaluation period,” which usually is 

the first 5 years of the PRS/RRS.20 During the cost evaluation period, 

future estimates of costs and revenues, which are based on forecasted 

budget data, may be modified to reflect changing conditions, such as 

additions to the power systems or inflation. Operating and maintenance 

(O&M) cost estimates are escalated by an inflation factor over the 5-year 

period, and the estimate for the fifth year is then carried through to the 

end of the ratesetting period without further escalation.21

• Interest rates in effect for each project will be those specified in the 

individual project authorizing legislation, or in DOE Order RA 6120.2 for 

all future year investments.

• Where possible, to mitigate interest costs, the highest interest rate debt 

will be paid first.

• The PMAs will take a credit against interest costs to recognize the 

savings to the government for payments the PMAs make to the Treasury 

throughout the year for obligations that are not due until the end of the 

year.

19There are exceptions, such as Bonneville’s Yakima-Chandler Project with a legislated 

repayment period of 66 years. 

20However, the length of the cost evaluation period is discretionary and is not always 

5 years. For example, in its fiscal year 2002 Initial Power Rate Proposal, Bonneville uses an 

8-year cost evaluation period (fiscal years 1999 through 2006). The cost evaluation period 

extends from the last year historical information is available (fiscal year 1998) through the 

proposed 5 year rate test period (fiscal years 2002-2006), which is the period rates are 

expected to remain in effect. 

21Southeastern’s cost estimates are escalated by an inflation factor to the mid-point of the 

evaluation period. These estimates are then carried through to the end of the rate review 

period with no further escalation.
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In addition to the above, Bonneville makes the following key assumptions:

• U.S. Treasury bonds will be systematically repaid based on the term of 

the debt.

• Revenue requirements will be set at the higher of forecasted accrued 

expenses (including depreciation expense) or cash requirements.

• Rates will be developed so as to create an 88 percent probability that 

cash flows will be sufficient to enable Bonneville to make Treasury 

payments on time and in full over a 5-year period. Bonneville analyzes 

operating (e.g., hydro generation) and nonoperating risks (e.g., fish and 

wildlife expenses) and risk mitigation measures in assessing whether 

the 88 percent probability is met.

• Financial reserves will be maintained to mitigate risk. For example, 

Bonneville includes as a component of its revenue requirement, 

amounts to mitigate risks associated with several factors, including 

funding of fish and wildlife initiatives, water conditions, and economic 

conditions. 

As mentioned previously, under DOE Order RA 6120.2, the PMAs are 

required to set rates sufficient to recover costs. The PMAs generally use 

PRSs and RRSs as a basis for setting rates and keeping rates as low and 

stable as possible, even though revenue requirements vary from year to 

year. For example, a ratesetting system may have 43 years of comparatively 

stable revenue requirements, but a large increment of appropriated debt 

becomes due in year 44 of the ratesetting period. The PMAs attempt to level 

payments over the entire ratesetting period.
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Unless otherwise prescribed by project enacting legislation or DOE 

regulation, the PMAs are generally allowed to defer the repayment of 

appropriated debt until it is due, generally 50 years for original 

construction of projects and additions to projects, 35 to 45 years for 

transmission assets, and the lesser of 50 years or the estimated service lives 

for replacements. These provisions give the PMAs some flexibility, within 

the parameters of DOE Order RA 6120.2, in determining when to repay 

appropriated debt.22 In practice, after paying annual costs that are required 

to be paid in any given year, the PMAs then generally use any remaining 

revenues to repay highest interest rate debt.23 The PMAs have flexibility in 

selecting which increment of debt to repay among those bearing the same 

interest rate. 

Although all the PMAs use allowable repayment periods as noted above, 

there are some differences in their interpretations of DOE Order 6120.2 

regarding the ratesetting period. For example, Southwestern considers the 

ratesetting period to be 50 years. Southeastern considers the ratesetting 

period to be 50 years from the date of the last increment of appropriated 

debt that would require a rate adjustment; therefore, if no additional 

significant appropriated debt is incurred, the ratesetting period decreases 

each year. Some Western projects consider the ratesetting period to be the 

period up to the pinch-point year, discussed below, or when the last 

increment of appropriated debt is repaid, whichever is later. 

22According to DOE Order RA 6120.2, the order of precedence for repayment each year is 

annual expenditures (O&M, purchased and exchange power, and transmission service), 

interest costs, unpaid or deferred annual expenditures, if any, and any debt due in that year. 

Remaining revenues are available for repayment of appropriated debt. In addition, Public 

Law No. 89-448 authorized the payment of irrigation costs from remaining revenues. Costs 

incurred in any year in which revenues fail to recover annual expenditures are deferred to 

the following year and accrued on the balance sheet as a liability. Deferred costs are repaid 

with interest.

23Debt that is due in a given year—including low interest debt and irrigation debt that carries 

no interest—is a higher priority for repayment than higher interest rate debt.
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The PMAs’ rates are generally set based on the projected cumulative 

revenue requirements through a time frame ending with what is referred to 

as the “pinch-point” year.24 The pinch-point year is the year within the 

period covered by the PRS in which the annual revenue requirements are 

projected to be the highest. Rates are set to ensure that the cumulative 

revenue for the first year of the study through the end of the pinch-point 

year is at least equal to the cumulative revenue requirements for the same 

period. The pinch-point year occurs when a significant required payment is 

due for annual expenditures and/or a capital repayment obligation.25 Figure 

2 illustrates that cumulative revenue and cumulative revenue requirements 

must be equal by the pinch-point year.

24Rather than “pinch-point,” Bonneville uses the term “critical year.” The “critical year” is the 

year where Bonneville’s levelization of debt service is at the point where each obligation is 

scheduled for repayment by no later than its due date.

25These expenditures that must be made in the pinch-point year arise because (1) annual 

expenditures are generally required to be paid in the year incurred, although certain 

expenditures can be deferred in years when revenues are insufficient to cover them, (2) the 

repayment of some debt cannot be further deferred because they are at their due dates, 

(3) the amount of revenue the PMAs can generate each year is limited and therefore the 

PMAs cannot wait until the years that the debt is due to repay it, and (4) some lower interest 

debt cannot be paid earlier because cash available to repay debt will be used to repay higher 

interest rate debt first under DOE Order RA 6120.2’s repayment precedence. Only significant 

changes in these factors, such as large additions or replacements that would affect revenue 

requirements, would move the pinch-point year.
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Figure 2: Illustrative Pinch-Point Year for a PMA Ratesetting System

Source: Developed from information provided by the PMAs, particularly the Western Area Power 

Administration.

In this example, cumulative revenue meets cumulative revenue 

requirements in year 44 of the ratesetting period, the pinch-point year. 

Under DOE Order RA 6120.2, the PMAs are to take action if the current rate 

will not generate sufficient cumulative revenue to equal cumulative 

revenue requirements by the pinch-point year. Such action may include 

cutting costs and/or adjusting rates. As illustrated by figure 2, cumulative 

revenues exceed cumulative revenue requirements prior to the pinch-point 

year. During this ratesetting period, early repayments of appropriated debt 

due in the pinch-point year facilitate meeting total cumulative revenue 

requirements by lowering the amount due in the pinch-point year. This 

allows a single rate to generate sufficient revenue to recover cumulative 

costs by the pinch-point year. Beyond the pinch-point year, the cumulative 

revenues exceed the cumulative revenue requirements and rates would be 

recalculated. 

PMAs Use Open Public 

Process in Developing Rates

When they are considering a rate adjustment, the three PMAs are required 

to publish notices in the Federal Register to notify customers, the general 

$0

$500,000,000

$1,000,000,000

$1,500,000,000

$2,000,000,000

$2,500,000,000

$3,000,000,000

$3,500,000,000

$4,000,000,000

00 05 10 15 20 25 30 35 40 45 50

Ratesetting years

Irrigation payments

due

Appropriated debt

payments due

Cumulative interest

payments

Cumulative

expenditures

Cumulative

revenue

Pinch-point requirements

Cumulative revenue

Revenue

requirements
B-283123

Page 17 GAO/AIMD-00-114 Power Marketing Administrations

public, and other interested parties. The three PMAs then have 90 days 

from the date of the Federal Register notice to conduct public information 

and public comment forums, which are transcribed formal events in which 

the three PMAs explain the procedures used to establish and support the 

rate adjustments and provide citizens the opportunity to voice their 

opinions and suggestions. All comments are considered during the rate 

development process. If this public participation process leads to 

significant changes in the proposed rate adjustment, a modified proposal 

may be published in the Federal Register and the public again offered an 

opportunity to comment on the modifications. 

The three PMAs prepare a final rate proposal for each ratesetting system 

and forward the information to the Secretary of Energy or his designee, 

requesting the Secretary to confirm, approve, and place the rate into effect 

on an interim basis. Once this approval takes place and the interim rate is 

placed into effect, the Secretary submits the rate proposal to FERC for final 

approval. After reviewing the rate proposal, FERC is authorized to take one 

of three actions, but does not have authority to change the rate. FERC may 

(1) confirm, approve, and place the rate into effect on a final basis, (2) send 

it back to the PMA for further study, or (3) disapprove it, in which case the 

rate that existed prior to the interim rate goes back into effect. Upon 

rendering its decision, FERC publishes a notice in the Federal Register. 

The rate development process for the three PMAs is depicted in figure 3.
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Page 18 GAO/AIMD-00-114 Power Marketing Administrations

Figure 3: The Three PMAs’ Rate Development Process

At the beginning of each fiscal

year, each PMA updates PRSs

to verify that rates are adequate

to meet repayment criteria

PMAs publish the proposed rates

in the Federal Register

PMAs hold formal public

information and comment

forums to explain proposed rate

change

PMAs review comments and

make adjustments, as deemed

appropriate

PMAs submit rates to the

Secretary of Energy or his

designee for approval on an

interim basis

Secretary of Energy or his

designee reviews and approves

the rates on an interim basis

(new rates become effective)

FERC allows intervention

before approving the rates on a

final basis or remands the

rates to the PMAs

Each PMA reports the status of

repayment for all of its projects to

the Secretary of Energy

or his designee

(existing rates remain in effect)

PMAs prepare a Revised Power

Repayment Study to support

rate approval requests

Are rates

sufficient to

recover all

costs?

YES

PMAs notify customers and

public of new rate proposal

NO

Development Process

Identifying Revenue

Requirements

Public Rate

Rate Implementation
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Page 19 GAO/AIMD-00-114 Power Marketing Administrations

Like the three PMAs, Bonneville prepares its revenue requirement 

analysis26 under DOE Order RA 6120.2 guidance and files a notice of the 

initial rate proposal in the Federal Register. Bonneville’s ratesetting process 

is specified in the Northwest Power Act which, among other things, 

requires Bonneville to hold rate case proceedings in determining the final 

rate proposal. 

Bonneville holds field hearings throughout the region to obtain public input 

and questions from all interested participants (e.g., consumers). The 

hearings are recorded and transcribed and become a part of the official 

record. In addition to field hearings, Bonneville holds formal hearings, 

which are semijudicial rate case proceedings. Both types of hearings are 

presided over by a hearing officer. However, only parties to the rate case27

may take part in the formal hearings. Such parties file direct cases 

(testimony) including responding to Bonneville’s initial rate proposal. 

Bonneville and the parties file rebuttal testimony to the parties’ direct cases 

and have the opportunity to ask clarifying questions about one another’s 

testimony and submit written data requests in order to prepare their 

responses. In addition, both Bonneville and parties to the rate case have an 

opportunity to cross-examine one another’s witnesses on all relevant 

issues. 

At the close of the formal hearings, the parties prepare initial briefs 

summarizing their issues to date.28 Bonneville’s Administrator reviews the 

official record and prepares a draft Record of Decision. Parties to the rate 

case may respond to the draft Record of Decision by filing “Briefs on 

Exceptions,” by a specified date (usually within a month).29 The 

administrator reviews the entire record and issues a final Record of 

Decision. Unlike the three PMAs, Bonneville is not required to submit its 

26When considering a rate adjustment, Bonneville’s planned expenses and capital 

investments for the rate period are made subject to public review and comment before a 

rate proposal is initiated.

27Parties to the rate case are those individuals or groups designated by the hearing officer as 

parties. Interested individuals or groups must submit a “petition to intervene” for 

consideration to become parties. 

28The purpose of an initial brief is to identify separately each legal, factual, and policy issue 

to be resolved by the Administrator.

29The purpose of the briefs on exceptions is to (1) raise any alleged legal, policy, or 

evidentiary errors in the draft Record of Decision and (2) provide additional support for 

tentative decisions contained in the draft Record of Decision.
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rate proposal to the Secretary of Energy. The proposed rates are submitted 

directly to FERC for approval. FERC’s approval process for Bonneville is 

the same as for the other three PMAs. The rate development process for 

Bonneville is depicted in figure 4.
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Page 21 GAO/AIMD-00-114 Power Marketing Administrations

Figure 4: Bonneville’s Rate Development Process

Bonneville holds a

prehearing conference

Bonneville holds

field hearings 1/

Parties file testimony including

responding to Bonneville's initial

proposal

Bonneville and parties file rebuttal

testimony to parties' direct testimony

Notice of initial proposal published in the Federal Register

(official start of the rate case)

Bonneville and parties

cross-examine one

another's witnesses

Parties file initial briefs summarizing

the issues to date

Bonneville's Administrator reviews

the official record and prepares

draft Record of Decision 3/

Parties review draft Record of

Decision

Parties prepare "Briefs on

Exceptions"

Bonneville's Administrator reviews

the entire record and issues a final

Record of Decision

Bonneville files rates with FERC for

approval

Discovery: Parties

have the

opportunity to ask

clarifying questions

about Bonneville's

and one another's

testimony and

submit written data

requests in order to

prepare their

responding

testimony.

1/ The rate case is open to the public; comments become part of the official record.

2/ Some of the field hearings are held concurrently with the formal hearings. Only "parties" to the rate

case may take part in the formal hearings. The hearing officer determines "parties" to the rate case.

3/ Official record includes testimony, exhibits, hearing transcriptions, letters

and other documents filed during the rate case.

Public Comment

and Interaction

Rate Approval Phase

Formal

Hearings

2/
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Ratesetting Practices 

of the PMAs, IOUs, and 

POGs Differ

Like PMAs, IOUs30 and POGs gather data and prepare studies to determine 

the revenue requirements necessary to recover their costs, obtain input 

from interested parties at public forums, and present rate proposals to the 

appropriate oversight body. However, the processes and assumptions used 

by IOUs and POGs differ from those of the PMAs in several respects. Key 

differences relate to 

1. cost recovery and the process for setting rates, including oversight 

procedures,

2. whether rates are cost-based or market-based, and

3. the responsibilities to owners or taxing authorities.

Cost Recovery Practices 

and Ratesetting Processes

In general, PMAs recover their costs through wholesale rates while IOUs 

and POGs recover costs through a combination of retail and wholesale 

rates. In both regulated and restructured states, the market generally sets 

IOUs’ and POGs’ wholesale generation rates. In a regulated environment, 

IOUs generally recover their fixed costs through their retail rates. As a 

result, excess power sold in wholesale markets generates a profit to the 

extent that prices set by the wholesale market exceed IOUs’ marginal 

costs. As states restructure, IOUs will likely begin to recover more fixed 

costs through their wholesale rates because competitive pressures on retail 

rates will likely reduce the amount of fixed costs that IOUs can recover 

through retail sales. In general, POGs are owned and operated by the 

municipalities they serve and report to an elected or appointed local 

oversight body, such as a city council or utility governing board. In 

addition, in 12 states POGs are also subject to regulation by a state 

regulatory authority. As a result, POGs’ ratesetting practices vary. 

30For purposes of this discussion, we define an IOU as a for-profit utility that generates, 

transmits, and distributes power.
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As noted earlier, the PMAs’ PRSs/RRSs include information on historical 

costs from project inception and projected costs and revenues over the 

ratesetting period, generally 50 years. When setting rates, the PMAs factor 

projected inflation into their analyses during the first 5 years of the PRS, 

which is called the cost evaluation period. In contrast, in setting their retail 

rates IOUs use a much shorter period—a 1-year historical period—and 

generally project costs only from 0 to 2 years forward. Among the POGs, 

the number of historical years used in setting rates generally ranges from 

1 to 3 years while the number of years used to project revenue 

requirements typically ranges from 3 to 5 years.31 All of the POGs we 

contacted considered the impact of inflation and/or trends on their 

projections of future revenue requirements.

IOUs systematically recover their capital costs through rates by using 

annual depreciation or amortization,32 either on a straight-line basis over 

the life of the asset or on an accelerated basis.33 IOUs also pay financing 

costs, including interest on loans and bond interest, on a systematic annual 

basis. They typically repay debt financing obtained by issuing bonds or 

taking out loans in accordance with the terms of the bond and loan 

agreements. 

POGs use depreciation and amortization expense to recognize capital costs 

for financial reporting purposes, but generally recover capital costs based 

on the debt service requirements included in their annual budgets. They 

31For the POGs we contacted, the number of historical years used in setting rates ranged 

from 1 to 10 years, while the number of years used to project revenue requirements ranged 

from 3 to 25 years. However, POGs generally use revenue requirement projections beyond 

5 years to make decisions about future expansion or to identify when they believe future 

rate adjustments or new bond issuances may be needed, rather than for immediate 

ratesetting purposes.

32Depreciation is the allocation of the expense associated with property, plant and 

equipment to each period benefited by the asset. Amortization is the allocation of expenses 

associated with intangible and other assets, such as abandoned plant, to each period 

benefited. Straight-line depreciation and amortization are calculated by dividing the cost of 

the asset less estimated salvage value, if any, by its estimated useful life or allowable period 

of time.

33Some IOUs are preparing for the move toward market-based rates by accelerating 

depreciation while their retail rates still remain protected. For example, some states that 

have restructured have frozen retail rates until a future set date. IOUs can use this 

opportunity to accelerate depreciation to recover as much of their investment as possible; 

then, when they make the transition to full market-based rates, they can stretch out 

recovery of their remaining capital costs to make their rates more competitive.
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repay financing costs and principal in the same manner as IOUs. The 

financing period for capital assets and the period for recovering the cost of 

capital projects used by the POGs we contacted ranged up to 35 years. In 

contrast to IOUs and POGs, the PMAs have flexibility to repay their 

appropriated debt any time up to the year due, which is generally the 50th 

year for generation assets.

IOUs’ Ratesetting Process To set rates in a regulated environment,34 IOUs identify the costs that must 

be recovered through rates, such as those related to O&M, transmission, 

purchased power, debt related to capital assets, interest on financed debt 

and/or bonds, and taxes. In identifying these costs, IOUs adjust for known 

events, such as salary increases and property tax increases. In addition, 

IOUs determine the total cost of assets that must be recovered through 

rates and are allowed to set rates to generate a regulated rate of return for 

investors on the value of these assets. 

To determine expected revenues, IOUs take the total sales for all classes of 

customers for the prior year; in some cases, they recalculate these 

revenues to adjust them to a normalized weather year. They then make 

adjustments for known future events, such as a major new factory that 

would require a significant amount of power in the coming year. In general, 

IOUs use 1 year of historical data and project from 0 to 2 years into the 

future. They compile the data into a rate case, with proposed rates by class 

of customer (e.g., industrial, commercial, or residential) and submit the 

case to their state regulatory commission. Like the PMAs’ rate proposals, 

the IOUs’ rate proposals undergo a public process whereby interested 

parties can testify and introduce exhibits to support their positions. IOUs 

negotiate with their state commissions over the proposed rates, and the 

state commissions actually set the rates.

POGs’ Ratesetting Process POGs also prepare cost studies and evaluate their revenue requirements to 

identify the need for rate changes, give public notice of proposed rate 

changes, obtain input from interested parties at public forums, and present 

rate proposals to the appropriate oversight body for approval. However, we 

found significant differences among the POGs regarding the cost 

evaluation period used to identify revenue requirements and set rates, as 

illustrated by the following:

34In a restructured environment, the market sets the price for generation and only the 

distribution portion of an IOU’s rates remains regulated.
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• One POG sets its rates based on projected demand for power and 

expected costs for the following year only. Although it prepares 

long-term cost projections internally, these projections are used 

primarily to make decisions about future expansion and to identify 

opportunities to purchase power, and not for setting rates.

• A second POG analyzes costs over 5 to 10 years to set rates. Estimates of 

future power needs are generally projected 10 years, while cost of 

service analyses used to project future revenue requirements and set 

rates are generally projected over 5 years. 

• A third POG projects its revenue requirements over 25-years and uses 

the 3-to-5 year projections to set rates. These projections are based on 

actual historical costs over the last 5 years and projected changes in the 

budget. The revenue requirement projections for years 6 through 25 are 

used primarily to identify the need for future rate adjustments or the 

issuance of new bonds. The projected costs for this period are based on 

various trend and regression analyses using historical data, the forecast 

data for years 1 through 5, and projected capital projects. 

• The fourth POG does not follow a specific or formal process to set rates. 

The staff of its electric division makes recommendations to the city 

council to ensure that rates for the following year generate sufficient 

revenue to cover actual budgeted expenses plus a required payment in 

lieu of taxes to the city’s general fund. Costs are generally not projected 

beyond the 1-year period.

POGs propose their own retail rates, which are generally reviewed and 

approved by the POGs’ boards of commissioners or other local elected or 

appointed oversight body, such as a city council. In 12 states, the POGs are 

also subject to regulation by a state regulatory authority. Because POGs 

generally are not required to report to a specific regulatory body, we did not 

identify a consistent oversight and rate approval methodology applicable to 

them. For two of the POGs we contacted, the rates are set by the utility and 

approved by the city councils. For the other two POGs we contacted, the 

boards of directors approve all rate changes without the need for city 

council approval.

Cost-Based Versus MarketBased Ratesetting

As the electricity industry continues to move toward market-based rates, 

utilities are expected to find ways to become more efficient. In a regulated 

environment, IOUs’ retail rates are based on the costs their state 

commissions allow in their rate bases, but in a competitive environment 

the IOUs’ will have an incentive to reduce costs to enhance the 

competitiveness of their rates. The PMAs are also taking steps to reduce 
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Page 26 GAO/AIMD-00-114 Power Marketing Administrations

costs and prepare themselves for a competitive market situation, but they 

continue to set rates based on costs, as required by current law. Meanwhile, 

many of the larger POGs are increasingly abandoning their traditional fully 

allocated cost methods for designing rates and are focusing more on 

market conditions. 

As noted, in a restructured environment the market generally sets the price 

for the generated commodity (power),35, 36 FERC regulates transmission, 

and the state commissions set the rates for distribution (retail sales) for 

IOUs and some POGs. Local governing bodies generally set the rates for 

retail sales for most POGs. In most states this is the final approval process; 

however, in some states final approval is given by the state regulatory 

agency. Restructuring legislation varies from state to state and therefore 

differences exist among IOUs’ ratesetting practices. However, several 

elements are similar among states that have restructured, and in general

• IOUs will continue to file rate cases for distribution services with their 

state commissions and where applicable, an IOU that provides default 

service37 (from a cost-of-service perspective only) will also file a rate 

case with its state commission, and 

• some states have frozen rates until a set future date, which should allow 

utilities an opportunity to recover potential stranded costs while rates 

are still protected.

Responsibilities to Investors 

and Taxing Authorities

IOUs are expected to generate a return for owners and pay income and 

other taxes. These costs are included in the IOUs’ rate cases. POGs, as 

publicly owned utilities, typically do not pay income taxes because they are 

units of state or local governments. However, many POGs do make 

payments in lieu of taxes to local governments. In addition, in some cases 

POGs generate a return for owners in that the excess revenues they 

35The market may not always set the price for power in a restructured state. For example, 

Oregon’s restructuring legislation allows residential and small commercial customers who 

do not want to purchase power at market the option to continue to receive cost-of-servicebased power.

36Depending on state restructuring legislation, some utilities are setting up marketing 

divisions to sell power. For example, one utility we spoke with sells power by phone on a 

short-term contract basis.

37Default service is the requirement for a provider to provide service for customers who do 

not choose an electricity supplier. State public utility commissions regulate default service.
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generate are transferred from the POGs’ accounts and used to fund other 

government activities. The PMAs do not have to generate a return for 

owners and generally do not pay taxes. The impact of these differences is 

discussed further in the next section.

Overall the PMAs Are 

Well Positioned 

Competitively

The PMAs are allowed to defer repayment of appropriated debt until due,38

but in practice have been repaying significant portions before they are due 

and generally focusing on retiring high interest rate debt first. Nevertheless, 

the financing costs of three of the PMAs—Bonneville, Southeastern, and 

Western—are high relative to other utilities. While the high financing costs 

will pose challenges for these three PMAs, the PMAs overall have 

important cost advantages that enhance their competitive positions.

PMAs’ Debt Repayment 

Practices

Under DOE Order RA 6120.2, the PMAs are not required to systematically 

(i.e., on a normal amortizing basis) recover from power customers the 

federal appropriations that finance the capital assets of projects at which 

the PMAs market power. Unlike traditional financing situations, such as 

home mortgages and bank loans, annual repayments of the PMAs’ 

appropriated debt do not have to be made to the Treasury. Instead, the 

PMAs are required to recover the appropriated debt from power customers 

within a specified repayment period. The required recovery period is 

generally 50 years for assets used to generate power, 35 to 45 years for 

assets used to transmit power, and the lesser of 50 years or their estimated 

useful service lives for replacements.

While the PMAs have the ability to defer the repayment of the appropriated 

debt, in practice they have been repaying significant portions before the 

year in which they are due. Table 1 shows our analysis of the portions of 

the PMAs’ debt that have been repaid before the year in which the debts are 

due. It shows the total percentages of debt repaid before the year in which 

the PMAs’ debts are due and the percentages repaid at least 10 years before 

the year the debts are due for certain ratesetting systems.

38We are referring here to the PMAs’ ability to put off into the future the repayment of certain 

low interest appropriated debt, while repaying high interest debt. We are not referring to the 

PMAs’ ability to defer payment of annual operating and other expenses in years when 

revenues are insufficient to pay those costs.
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Table 1: Percentages of the PMAs’ Debt Repaid Before Due as of Fiscal Year-End 1998 (in Total and at Least 10 Years Before 

Due)a

a

This analysis covered all Bonneville power projects (100% of 1998 power sales); Southeastern’s 

Cumberland and Georgia-Alabama-South Carolina (GA-AL-SC) systems (89% of 1998 power sales); 

Southwestern’s Integrated System (91% of 1998 generating capacity); and Western’s Central Valley 

Project (CVP) and the Colorado River Storage Project of the Salt Lake City Area Integrated Projects 

(SCLA-IP) (47% of 1998 power sales).

b

Bonneville’s outstanding balance of appropriated debt was restructured as of October 1, 1996. The 

restructuring resulted in a reduction in the principal amount outstanding from about $6.9 billion to 

about $4.3 billion and an increase in the associated interest rate of about 3.6 percentage points. We do 

not consider the $2.6 billion principal reduction resulting from the restructuring to be a repayment. 

c

This analysis is of the repayment of appropriated debt related to assets already placed in service. It 

does not cover appropriated debt for assets not yet placed in service (e.g., construction-work-inprogress) because those assets do not have repayment due dates.

d

The data needed to calculate these percentages for the Pick-Sloan project were not available.

e

Southwestern’s data is for fiscal year 1997. The actual percentage of appropriated debt for 

Southwestern’s Integrated System that was repaid at least 10 years before the year due is higher. But, 

because of the way the repayment data are categorized in the PRS, in many cases we were unable to 

determine the exact year of the repayment.

f

Although the repayment data for Western’s CVP indicates the exact year of repayment of appropriated 

debt repaid in full as of September 30, 1998, it does not indicate the repayment year for appropriated 

debt that has been partially repaid. Therefore, repayment percentages are based on the status of 

repayment as of September 30, 1998.

g

Bonneville has less flexibility in repaying bonds than in repaying appropriated debt. Although some of 

the debt is callable, the bonds are generally repaid based on the term of the debt (i.e., repaid on the 

maturity date). 

h

The actual percentages for Southeastern’s two systems are likely higher. But, because the repayment 

data did not specify the exact year of repayment, in many cases we were unable to determine whether 

the payment was made before due or at least 10 years before due.

Source: Developed by GAO based on information contained in the three PMAs’ power repayment 

studies and Bonneville’s Revenue Requirement Study. 

The relatively low percent of debt repaid by Bonneville relates to its 

investments in nuclear facilities. As of September 30, 1998, Bonneville had 

about $13.8 billion in debt. Of the $13.8 billion, approximately $4.2 billion 

relates to nonoperational and canceled nuclear projects, and an additional 

$2.5 billion relates to one operating nuclear plant of Energy Northwest. 

Bonneville Southeasternc,h Southwesternc Westernc,d

Appropriated

 Debtb,c

Treasury

Bondsg Cumberland GA-AL-SC Integratede CVPf SLCA-IP

Total percentage repaid 

before year due

17 28 64 27 43 63.2 60.2

Percentage repaid at 

least 10 years before 

year due

9 24 36 25 19 62.7 59.7
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In addition, as we reported previously,39 Bonneville has faced significant 

competitive pressure in recent years. In particular, low natural gas prices 

and improved technology for gas-fired generation facilities combined to put 

downward pressure on electricity rates in Bonneville’s region. Also, excess 

generating capacity in the region resulted in additional downward pressure 

on prices in wholesale markets. Thus, Bonneville has had little pricing 

flexibility in recent years, which has limited its ability to set rates high 

enough to repay debt at a faster rate. 

The relatively low percentage of appropriated debt repaid for 

Southeastern’s Georgia-Alabama-South Carolina System is related 

primarily to the relatively recent construction of the Richard B. Russell 

Project.40 The Russell Project has four operational conventional generating 

units that provide 300,000 kilowatts of capacity and four nonoperational 

pumping units41 intended to provide another 300,000 kilowatts of capacity. 

The last of the four conventional units came on-line in 1986, and the costs 

associated with the units are included in the customers’ rates. 

The four pumping units were completed in 1992. However, because of 

litigation over their environmental impacts, the four pumping units have 

never been allowed to operate commercially. As a result, Southeastern has 

not included the costs of the four pumping units in the customers’ rates and 

has not begun repaying the appropriations. 

Because the costs of the conventional units have been in the rate base a 

relatively short time, Southeastern has repaid little of the federal 

appropriations. As of September 30, 1998, Southeastern had repaid 

$31 million (nearly all of which was related to additions to the project) of 

the $366 million in costs associated with the operational conventional units 

and none of the $603 million in costs associated with the nonoperational 

pumping units.

39Federal Electricity Activities: Appendixes to The Federal Government’s Net Cost and 

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

40The Richard B. Russell Project was originally named the Trotters Shoals Dam.

41The pumping units are designed to allow water, after it has passed through generating 

units, to be pumped back into the reservoir during periods of low demand for electricity. 

The water can then be used to produce power during periods of high demand for electricity.
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The fact that the three PMAs have been repaying large portions of the debt 

before it is due does not mean that they have repaid as much or more than 

they would have if required to repay their debt systematically on a normal 

amortizing basis. For high-interest debt, the three PMAs have generally 

repaid more than they would have on a normal amortizing basis. For 

low-interest debt, the three PMAs have generally repaid less than they 

would have on a normal amortizing basis. This is because, in accordance 

with provisions in DOE Order RA 6120.2, the three PMAs have generally 

been repaying the highest interest debt first and deferring repayment of 

lower interest rate debt.42, 43 By doing so, the three PMAs effectively reduce 

their future interest costs.

In contrast, although Bonneville has repaid some of its higher interest rate 

appropriated debt before it is due, Bonneville’s percentage of higher 

interest rate appropriated debt repaid is relatively low.44 This is primarily 

related to its large interest payments on nuclear facilities and the 

approaching maturity of lower interest rate appropriated debt and Treasury 

bonds. Table 2 shows the percentages of high interest and low interest rate 

debt the PMAs have repaid.

42However, appropriated debt due in a given fiscal year must be paid.

43The PMAs’ ability to defer repayment of appropriated debt for a longer period than IOUs 

and POGs and to repay highest interest rate appropriated debt first offsets their general 

inability to refinance appropriated debt, which could be a disadvantage in times of declining 

interest rates. As discussed previously, however, Bonneville’s appropriated debt was in fact 

restructured as of October 1, 1996. 

44However, Bonneville has repaid a significant portion of its U.S. Treasury bonds before due.
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Table 2: Percentages of the PMAs’ High Interest and Low Interest Debt Repaid as of Fiscal Year 1998a

a

This analysis covered all Bonneville power projects (100% of 1998 power sales); Southeastern’s 

Cumberland and Georgia-Alabama-South Carolina (GA-AL-SC) systems (89% of 1998 power sales); 

Southwestern’s Integrated System (91% of 1998 generating capacity); and Western’s Central Valley 

Project (CVP) and the Colorado River Storage Project of the Salt Lake City Area Integrated Projects 

(SCLA-IP) (47% of 1998 power sales).

b

This analysis is of the repayment of appropriated debt related to assets already placed in service. It 

does not cover appropriated debt for assets not yet placed in service because repayment of those 

appropriations has not begun.

c

For each ratesetting system, we calculated a simple average interest rate and considered everything 

above the average to be high and everything below the average to be low.

d

Southwestern’s data are for fiscal year 1997.

e

The data needed to calculate the percentages for the Pick-Sloan Project were not available.

Source: Developed by GAO based on information contained in the three PMAs’ Power Repayment 

Studies and Bonneville’s Revenue Requirement Study.

The financing costs of three of the PMAs—Bonneville, Southeastern, and 

Western—are relatively high compared to those of IOUs and POGs. Their 

relatively high financing costs mean that Bonneville, Southeastern, and 

Western have less flexibility to respond to competitive pressures in an 

increasingly competitive market environment. Moreover, while interest 

costs are fixed, IOUs have some flexibility in deciding whether to pay 

dividends to shareholders. Financial flexibility is an important 

consideration in an increasingly competitive electricity industry. Direct 

comparisons of financing costs are somewhat difficult because the 

financing structures of the entities differ. IOUs’ financing consists of both 

equity and debt, while the PMAs’ and POGs’ financing consists mostly of 

debt.45

Bonneville Southeasternb Southwesternb,d Westernb,e

Appropriated

Debtb

Treasury

Bonds Cumberland GA-AL-SC Integrated CVP SLCA-IP

Percentage of high 

interestc debt repaid

13 81 100 100 99 93 52

Percentage of low 

interestc debt repaid

66 33 62 21 25 53 69

45The three PMAs’ financing generally consists of appropriations that must be repaid to the 

federal government, with interest. In addition to federal appropriations, Bonneville’s 

financing includes U.S. Treasury bonds and nonfederal debt (i.e., debt held by the public, 

primarily related to nuclear projects). POGs’ financing generally consists of debt capital, 

which is obtained primarily by issuing electric revenue bonds.
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To determine the entities’ relative financing costs, we compared the PMAs’ 

and POGs’ percentage of interest costs to operating revenues to the IOUs’ 

percentages of interest and dividend (both common and preferred) costs to 

operating revenues. The results of our analyses are shown in figure 5.

Figure 5: Financing Costs as a Percentage of Operating Revenues for the PMAs, 

IOUs, and POGs for Fiscal Year 1998

Source: Developed by GAO based on data from the PMAs’ annual reports and composite national data 

on IOUs and POGs from EIA.

Like the percentage of appropriated debt repaid, the relatively high 

financing costs at Bonneville are related to its nuclear investments and the 

interest it must pay on its outstanding interest-bearing debt. Two of the 

nuclear plants Bonneville invested in were terminated and therefore do not 

generate revenues to offset the interest costs of the associated debt. As of 

September 30, 1998, Bonneville had outstanding debt of about $13.8 billion. 

36.4%

40.6%

16.6%

24.0%

15.2%

7.1%

15.8%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

Bonneville

Southeastern

Southwestern

Western

POGs

IOUs w/Pref Div

IOUs w/All Div

Percent
B-283123

Page 33 GAO/AIMD-00-114 Power Marketing Administrations

Of that amount, unpaid federal appropriations totaled about $4.4 billion, 

bonds owed to the U.S. Treasury totaled about $2.5 billion, and debt related 

to nonfederal projects totaled about $6.9 billion.

The high financing costs at Southeastern are related to interest costs on the 

federal appropriations that financed the construction of the Russell 

Project. Little of the appropriations related to this project have been 

repaid—only $31 million as of September 30, 1998—and the balance 

continues to incur an interest cost each year. Although Southeastern pays 

interest annually ($20.8 million in fiscal year 1998) on the outstanding 

federal appropriations related to the operational conventional units, it does 

not pay interest annually on the federal appropriations related to the 

nonoperational pumping units. Instead, Southeastern has been capitalizing 

interest annually by adding it to a construction-work-in-progress (CWIP) 

account; for fiscal year 1998, the capitalized interest amounted to 

$34.7 million. Thus, the amount to be recovered if the pumping units 

become operational continues to grow. 

As we reported previously,46 if the nonoperational Russell units are allowed 

to operate commercially and the costs go into rates, rates would have to be 

raised to recover the construction and accumulated interest costs reflected 

in the CWIP balance and to pay interest annually on this amount. Such an 

increase in interest expense would increase Southeastern’s financing costs 

significantly. For example, if Southeastern were to have paid the 

capitalized interest of $34.7 million in fiscal year 1998, its financing costs 

would have been about 60 percent of operating revenues. Southeastern 

officials expect that the Russell units becoming fully operational would 

necessitate a substantial rate increase for the Georgia-Alabama-South 

Carolina System. As we reported previously, the longer the eventual 

operation of the pumping units is delayed, the greater the costs that will 

have to be recovered through rates and the greater the potential impact on 

rates. This situation would pose a challenge to Southeastern in a 

competitive electricity market because at some point the price of the 

power generated at the Russell Project may not be competitive.

The relatively high financing costs at Western are related to relatively 

recent construction projects that carry higher interest rates. For example, 

about 60 percent of the debt outstanding as of September 30, 1998, for the 

46Federal Electricity Activities: Appendixes to The Federal Government’s Net Cost and 

Potential for Future Losses (GAO/AIMD-97-110A, September 19, 1997).
B-283123

Page 34 GAO/AIMD-00-114 Power Marketing Administrations

Salt Lake City Area Integrated Projects carry interest rates ranging from 

7 percent to 11 percent. 

Cost Advantages Enhance 

PMAs’ Competitive 

Positions

In addition to examining the PMAs’ ratesetting practices and how they 

affect their repayment of debt and financing costs, other factors are critical 

to any assessment of the PMAs’ competitive positions. The PMAs have 

some important cost advantages that enhance their competitive position, 

including primarily marketing low-cost hydroelectric power, marketing 

power from facilities that in many cases were built decades ago at 

relatively low cost, and not having to generate a return for owners or pay 

taxes. 

One of the PMAs’ most significant competitive advantages is that they 

market primarily low-cost hydroelectric power. Largely because there is no 

fuel cost associated with hydroelectric power, its costs are substantially 

lower than for other sources of generation. Figure 6 shows 1998 average 

data on operating expenses, including fuel costs, for fossil fuel, gas, and 

hydroelectric and nuclear generation plants operated by IOUs.
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Page 35 GAO/AIMD-00-114 Power Marketing Administrations

Figure 6: Average 1998 Operating Expenses by Generation Type for Plants Operated 

by IOUs

Source: Developed by GAO based on data from EIA.

Marketing primarily low-cost hydroelectric power gives the PMAs’ a 

significant overall competitive advantage compared to IOUs and POGs, 

which generate far less of their power from hydroelectric plants. Figure 7 

shows the percentages of power generated by hydroelectric plants for the 

PMAs, IOUs, and POGs for fiscal year 1998. 

20.6

30.5

5.8

21.6

0

5

10

15

20

25

30

35

Fossil Gas Hydro Nuclear

Mills per kWh
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Page 36 GAO/AIMD-00-114 Power Marketing Administrations

Figure 7: Percentage of Power Generated by Hydroelectric Plants for PMAs, IOUs, 

and POGs for Fiscal Year 1998

Source: Developed by GAO based on data from the PMAs’ annual reports and composite national data 

on IOUs and POGs from EIA.

Another competitive advantage for the PMAs is that they market power 

from facilities that were, in many cases, built decades ago at relatively low 

construction costs. To show the relatively low capital cost of the PMAs’ 

hydroelectric plants, we compared the PMAs’ investment in utility plant per 

megawatt of generating capacity. Figure 8 shows that the PMAs have 

invested less in utility plant per megawatt of generating capacity than IOUs 

and POGs.

82.0%

100% 100%

91.7%

27.5%

3.1%

0

20

40

60

80

100

Bonneville

Southeastern

Southwestern

Western

POGs

IOUs

Percent
B-283123

Page 37 GAO/AIMD-00-114 Power Marketing Administrations

Figure 8: Investment in Utility Plant per Megawatt of Generating Capacity, 1998

Source: Developed by GAO based on data from the PMAs’ annual reports and composite national data 

on IOUs and POGs from EIA.

In addition, as discussed previously, the PMAs do not have to generate a 

return for owners or pay taxes. In contrast, according to EIA, in 1998 IOUs 

paid dividends to investors totaling about 8.3 percent of operating 

revenues. Also according to EIA, in 1998 IOUs paid taxes totaling about 

13 percent of operating revenues. POGs, as publicly owned utilities, 

typically do not pay income taxes because they are units of state or local 

governments. However, many POGs make payments in lieu of taxes to local 

governments. According to EIA, in 1998 POGs made tax and tax equivalent 

payments totaling about 2.6 percent of operating revenues. In addition, 

according to industry sources, some POGs transfer additional funds from 

their accumulated net revenues accounts to fund other government 

activities, thereby essentially generating a return for owners. Not having to 

include a return to owners and tax payments in their rates is a competitive 

advantage for the PMAs. 

817

693

539 504

1,068

1,144

0

200

400

600

800

1,000

1,200

Bonne ville

Southeastern

Southw estern

Western

POGs

IOUs

Dollars in thousands
B-283123

Page 38 GAO/AIMD-00-114 Power Marketing Administrations

Although the PMAs enjoy significant cost advantages, they face some 

disadvantages relative to IOUs and POGs. For example, due to their 

reliance on hydropower, the PMAs face weather-related uncertainties to a 

greater extent than IOUs and POGs. Because the amount of rainfall 

determines how much power many of the projects marketed by the PMAs 

can generate, in low water years they may have to purchase power at 

higher rates to fulfill contracts. In addition, because of the multipurpose 

nature of federal water projects, operating restrictions may limit the 

amount of power the PMAs can market. IOUs and POGs that use 

hydropower also face weather-related uncertainties and operating 

restrictions, but given the PMAs reliance on hydropower, these factors may 

have a proportionately larger adverse impact on them. Also, the previously 

mentioned congressionally-assigned irrigation costs that Bonneville and 

Western must recover through power rates are obligations that IOUs and 

POGs do not have.

On balance, the PMAs’ cost advantages outweigh their disadvantages. As a 

result of these cost advantages, the PMAs’ power production costs—as 

reflected in calculations of average revenues per kWh—are lower than 

those of the IOUs and POGs. Because PMAs generally recover costs 

through rates with no profit, average revenues per kWh should reflect their 

full power production costs. For IOUs and POGs, average revenues per 

kWh should represent costs plus the return generated for owners.47 As 

shown in figure 9, the PMAs’ average revenues per kWh were considerably 

below those of IOUs and POGs in 1998.

47EIA cautions that average revenues per kWh per unit of energy sold should not be used as 

a substitute for the price of power. The price that any one entity charges another for 

wholesale energy comprises numerous transaction-specific factors such as the fee charged 

for reserving a portion of capacity, the fee for the energy actually delivered, and the fee for 

the use of the facilities. The fees are influenced by factors such as time of delivery, quantity 

of energy, and reliability of supply. However, despite its limitations, we believe that average 

revenues per kWh is a good indicator of relative power production costs since, over time, 

utilities must recover all costs to remain in business. In addition, analysts and bond rating 

agencies commonly use the measure in assessing the competitiveness of power rates, and 

EIA uses it to approximate costs.
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Page 39 GAO/AIMD-00-114 Power Marketing Administrations

Figure 9: Average Revenue per Kilowatthour for Wholesale Sales for 1998 for PMAs, 

POGs, and IOUs

Source: Developed by GAO based on data from the PMAs’ annual reports and composite national data 

on IOUs and POGs from EIA.

Therefore, despite the PMAs’ higher financing costs, the PMAs remain 

well-positioned because of their inherent advantages.

Agency Comments and 

Our Evaluation

We received separate written comments from the Department of Energy’s 

Power Marketing Liaison Office, representing the three PMAs, and from the 

Bonneville Power Administration. The three PMAs’ comment letter is 

reproduced in appendix II. Bonneville’s comment letter, and the enclosure 

accompanying it, is reproduced in appendix III. The three PMAs’ comments 

are discussed below. Bonneville’s comments are discussed below and in 

appendix III. The three PMAs and Bonneville also provided technical 

comments, which we incorporated as appropriate.

The Three PMAs In commenting on a draft of this report, the three PMAs stated that the 

report is a generally fair representation of PMA ratesetting practices. They 

2.637

1.931

1.463

1.713

3.46

3.147

0.00

1.00

2.00

3.00

4.00

Bonneville

Southeastern

Southwestern

Western

POGs

IOUs

Cents per kWh
B-283123

Page 40 GAO/AIMD-00-114 Power Marketing Administrations

did, however, request that the report segment discussing PMA cost 

advantages also include a more detailed discussion of certain cost 

disadvantages faced by the PMAs to offer an additional perspective on their 

competitive positions. Specifically, the three PMAs suggested that the 

report include discussion of the PMAs’ (1) inability to refinance, 

(2) reliance on hydropower, which is subject to weather-related 

uncertainty, (3) operating restrictions affecting the amount of power 

available for the PMAs to market, (4) requirement to repay certain costs 

related to irrigation facilities, and (5) inability to diversify into other lines 

of business. 

We have added some discussion of the first three issues into the report. 

Regarding the PMAs’ inability to refinance, however, it is important to note 

that this disadvantage is offset by the flexible repayment terms associated 

with this debt. As we note in our report, the PMAs have the ability to defer 

repayment of appropriated debt for a longer period than IOUs and POGs 

and are able to repay highest interest rate debt first while deferring 

repayment of low interest debt.

Regarding the requirement to repay certain irrigation costs, our report 

clearly states that Bonneville and Western are required to set rates at levels 

sufficient to repay certain nonpower costs, such as irrigation, that the 

Congress has assigned to power users to repay. However, based on the 

comment of the three PMAs, we have noted in our report that this is an 

obligation that IOUs and POGs do not have. 

Regarding the last item, the PMAs are limited in their choice of services to 

offer to those that fall within their congressional mandate. We have no 

basis for agreeing that diversification could accelerate return of the 

taxpayers’ investment. Inherent in this assertion is the presumption that 

the PMAs would be able to generate excess revenues by diversifying. We 

have not evaluated whether this is a reasonable assumption. 

Bonneville Power 

Administration

The Department of Energy’s Bonneville Power Administration stated that it 

had significant concerns with our message. Specifically, Bonneville stated 

that we (1) misconstrue the role of repayment studies in its revenue 

requirements and rates, (2) inadequately address its risk mitigation 

activities, (3) mischaracterize its debt obligations and debt management 

practices, (4) do not consider the “public benefits” that it must provide, and 

(5) fail to mention the many rate directives found in Section 7 of the 

Northwest Power Act. 
Page 41 GAO/AIMD-00-114 Power Marketing Administrations

In our view, the comments provided by Bonneville were largely of an 

elaborative and technical nature. We have incorporated some of the 

information provided to give additional context to the report. However, the 

changes incorporated as a result of Bonneville’s comments did not alter our 

overall assessment of its ratesetting and debt repayment practices and we 

disagree that our report misconstrues these practices. Given the detailed 

nature of Bonneville’s comments, our detailed evaluation of those 

comments is included in appendix III. 

As agreed with your office, unless you publicly announce its contents 

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

date. At that time, we will send copies to Representative Calvin Dooley, 

Ranking Minority Member, House Subcommittee on Water and Power, 

Committee on Resources; Representative Joe Barton, Chairman, and 

Representative Rick Boucher, Ranking Minority Member, House 

Subcommittee on Energy and Power, Committee on Commerce; Senator 

Gordon Smith, Chairman, and Senator Byron Dorgan, Ranking Minority 

Member, Senate Subcommittee on Water and Power, Committee on Energy 

and Natural Resources. We are also sending copies of this report to the 

Honorable Bill Richardson, Secretary of Energy; the Honorable Jacob J. 

Lew, Director, Office of Management and Budget; Judith A. Johansen, 

Administrator and Chief Executive Officer, Bonneville Power 

Administration; Charles A. Borchardt, Administrator, Southeastern Power 

Administration; Michael A. Deihl, Administrator, Southwestern Power 

Administration; Michael S. Hacskaylo, Administrator, Western Area Power 

Administration; and other interested parties. Copies will also be made 

available to others upon request.
B-283123

Page 42 GAO/AIMD-00-114 Power Marketing Administrations

If you or your staff have any questions concerning this report, please 

contact me at (202) 512-9508 or Robert Martin, Assistant Director, at 

(202) 512-4063. Major contributors to this report were Mary Merrill, 

Donald R. Neff, and Patricia B. Petersen.

Sincerely yours,

Linda M. Calbom

Director, Resources, Community, and

Economic Development Accounting

and Financial Management Issues
Page 43 GAO/AIMD-00-114 Power Marketing Administrations
Page 44 GAO/AIMD-00-114 Power Marketing Administrations

Appendix I

Objectives, Scope, and Methodology ApApenednxidexiIs

We were asked to determine (1) how the PMAs set their rates to recover 

costs, (2) how the PMAs’ ratesetting practices compare to those of 

investor-owned utilities (IOU) and publicly owned generating (POG) 

utilities, and (3) the impact of the PMAs’ ability to defer repayment of 

portions of their debt on their future competitiveness. In determining how 

the PMAs set their rates to recover costs, we were also asked to examine 

the assumptions the PMAs use in setting their rates and the processes the 

PMAs use to set rates to recover costs.

Determining How the 

PMAs Set Their Rates 

to Recover Costs

Before setting rates, the PMAs perform power repayment studies (PRS) or, 

in the case of Bonneville Power Administration, revenue requirement 

studies (RRS) to identify costs to be recovered and revenue requirements. 

As a result, to achieve this objective we focused on the PMAs’ PRSs and 

RRSs. We did not examine in detail every analysis performed by the PMAs 

that is incorporated into these studies and the PMAs’ revenue 

requirements, or verify the results of those analyses. To identify and 

examine the assumptions the PMAs use in setting their rates and to 

determine how the PMAs set their rates to recover costs, we 

(1) interviewed representatives from the four PMAs, (2) contacted the 

PMAs’ external auditors, (3) examined published documentation on the 

PMAs’ ratesetting processes, (4) requested and analyzed written responses 

related to specific questions about the ratesetting methodologies, including 

assumptions, used by the PMAs, and (5) analyzed at least one PRS from 

each of the three PMAs and Bonneville’s RRS for its current power rate 

case. We analyzed the PRSs/RRSs for one or more ratesetting systems from 

each of the four PMAs that would encompass at least 75 percent of total 

revenues or 75 percent of total generating capacity for each PMA. Where 

possible, we traced data in the PRSs and RRS to the audited financial 

statements of each PMA.

Determining How the 

PMAs’ Ratesetting 

Processes and 

Assumptions Compare 

to Those of IOUs and 

POGs

To determine how the PMAs’ ratesetting processes and assumptions 

compare to those of IOUs and POGs, we interviewed officials of four POGs 

and three IOUs and reviewed documentation they provided. We also 

discussed the ratesetting practices of (1) the IOUs we selected with the 

public utility commissions (PUC) that regulate them and with 

representatives from the Edison Electric Institute and (2) POGs with 

representatives from the American Public Power Association. We selected 

the IOUs and POGs based on the following criteria.
Appendix I

Objectives, Scope, and Methodology

Page 45 GAO/AIMD-00-114 Power Marketing Administrations

• Size: We selected relatively large entities to (1) give us as much coverage 

as possible, (2) increase the likelihood that we examined entities whose 

scope of operations were similar to the PMAs, and (3) increase the 

likelihood that the entities would have a ratesetting process comparable 

in scope to that of the PMAs.

• Geographic location: We selected entities from across the United States 

to ensure that our analyses considered ratesetting practices that may 

vary in different regions.

• Status of electric industry restructuring: We selected at least one IOU 

and one POG from nonrestructured states and all the others from 

restructured states.

• Location in relation to PMA service territories: We selected at least one 

IOU and/or one POG from each PMA’s service territory.

• Generation from hydro sources: Given the other criteria above, we 

selected two IOUs and two POGs that either generated or purchased 

power directly from utilities that generated a portion of their power 

from hydro sources. 

We limited our selection of publicly owned utilities to generating utilities 

because, in general, they are larger and therefore more likely to have a 

more formal ratesetting process than nongenerators. 

We also (1) interviewed representatives from the four PMAs and from each 

of the selected IOUs, POGs, and PUCs, (2) examined documentation 

obtained from the PUCs, (3) interviewed an official from the Federal 

Energy Regulatory Commission (FERC), and (4) interviewed 

representatives from industry groups representing IOUs, POGs, and PUCs 

(Edison Electric Institute, American Public Power Association, and 

National Association of Regulatory Utility Commissioners, respectively). 

Based on the data we collected, we compared the PMA ratesetting process 

and assumptions to those of IOUs and POGs.

Assessing the PMAs’ 

Competitive Positions

To assess the PMAs’ future competitiveness, we performed financial 

analyses based on information in the PRSs and RRS and the PMAs’ audited 

financial statements and compared the results to equivalent information for 

IOUs and POGs that was obtained from the Energy Information 

Administration within the Department of Energy. Specifically, we analyzed
Appendix I

Objectives, Scope, and Methodology

Page 46 GAO/AIMD-00-114 Power Marketing Administrations

• the percentage of the PMAs’ debt repaid before due as of September 30, 

1998,1

 for selected ratesetting systems at each of the PMAs to determine 

whether the PMAs have been repaying significant portions of their debt 

before the year in which they are due;

• the repayment of debt by interest rate as of September 30, 1998,2

 for 

selected ratesetting systems at each of the PMAs to determine (1) the 

extent to which the PMAs had repaid their higher interest rate debt first, 

in accordance with provisions contained in Department of Energy Order 

RA 6120.2 and (2) the impact this repayment methodology could have on 

the PMAs’ ability to compete in a restructured environment; 

• the relative financing costs of the PMAs compared to POGs and IOUs to 

determine whether the PMAs will have the same financial flexibility to 

respond to competitive pressures as POGs and IOUs;

• the average operating expenses by generation type (fossil, gas, hydro, 

and nuclear) to confirm that hydroelectric generation of power is 

relatively inexpensive;

• the PMAs’, IOUs’, and POGs’ percentage of generation by fuel type as of 

the end of fiscal year 1998 to determine which entities are positioned to 

benefit the most from inexpensive sources of generation;

• the investment in utility plant per megawatt of generating capacity to 

illustrate the relatively low capital cost of the hydroelectric plants that 

generate the power the PMAs market; and

• the average revenue per kilowatthour for each PMA compared to IOUs 

and POGs as of the end of fiscal year 1998 to determine the PMAs’ cost 

of power relative to other utilities.

Organizations and 

Groups Contacted

Federal Entities Department of Energy

Energy Information Administration

Federal Energy Regulatory Commission

1

Southwestern’s data are for fiscal year 1997.

2

Southwestern’s data are for fiscal year 1997.
Appendix I

Objectives, Scope, and Methodology

Page 47 GAO/AIMD-00-114 Power Marketing Administrations

Independent Public 

Accounting Firms

PricewaterhouseCoopers, LLP

Deloitte & Touche, LLP

Electric Utilities City of Idaho Falls, Idaho Falls, Idaho

Idaho Power, Boise, Idaho

JEA, Jacksonville, Florida

Oklahoma Municipal Power Authority, Edmond, Oklahoma

PG&E, San Francisco, California

San Antonio City Public Service Board, San Antonio, Texas

Virginia Power, Richmond, Virginia

Public Utility Commissions California Public Utilities Commission, San Francisco, California

Idaho Public Utilities Commission, Boise, Idaho

Virginia State Corporation Commission, Richmond, Virginia

Trade or Interest Group 

Associations

American Public Power Association, Washington, D.C.

Edison Electric Institute, Washington, D.C.

National Association of Regulatory Utility Commissioners, Washington, 

D.C. 
Page 48 GAO/AIMD-00-114 Power Marketing Administrations

Appendix II

Comments From Southeastern, Southwestern, 

and Western Area Power Administrations ApendxiI

Now on pp. 26-38.
Appendix II

Comments From Southeastern, 

Southwestern, and Western Area Power 

Administrations

Page 49 GAO/AIMD-00-114 Power Marketing Administrations
Page 50 GAO/AIMD-00-114 Power Marketing Administrations

Appendix III

Comments From the Bonneville Power 

Administration ApendxiI

See comment 1.

See comment 1.

Note: GAO’s comments 

supplementing those in the 

report text appear at the 

end of this appendix.
Appendix III

Comments From the Bonneville Power 

Administration

Page 51 GAO/AIMD-00-114 Power Marketing Administrations

See comment 1.
Appendix III

Comments From the Bonneville Power 

Administration

Page 52 GAO/AIMD-00-114 Power Marketing Administrations

See comment 2.

See comment 2.

See comment 3.

See comment 4.

See comment 5.

See comment 6.

See comment 6.

See comment 4.
Appendix III

Comments From the Bonneville Power 

Administration

Page 53 GAO/AIMD-00-114 Power Marketing Administrations

See comment 3.

See comment 7.

See comment 7.

See comment 7.

See comment 7.

See comment 8.
Appendix III

Comments From the Bonneville Power 

Administration

Page 54 GAO/AIMD-00-114 Power Marketing Administrations

See comment 9.

See comment 10.

See comment 11.

See comment 11.

See comment 12.

See comment 13.

See comment 14.
Appendix III

Comments From the Bonneville Power 

Administration

Page 55 GAO/AIMD-00-114 Power Marketing Administrations

See comment 10 and 

footnote to comment 10.

See comment 10.

See comment 15.

See comment 16.

See comment 17.

See comment 17.

See comment 17.
Appendix III

Comments From the Bonneville Power 

Administration

Page 56 GAO/AIMD-00-114 Power Marketing Administrations

See comment 17.

See comment 18.

See comment 18.

See comment 18.

See comment 18.

See comment 18.

See comment 18.
Appendix III

Comments From the Bonneville Power 

Administration

Page 57 GAO/AIMD-00-114 Power Marketing Administrations

See comment 18.

See comment 19.

See comment 20.

See comment 20.

See comment 18.
Appendix III

Comments From the Bonneville Power 

Administration

Page 58 GAO/AIMD-00-114 Power Marketing Administrations

The following are GAO’s comments on the Bonneville Power 

Administration’s letter dated March 23, 2000.

GAO Comments 1. Discussed in the “Agency Comments and Our Evaluation” section of the 

report. 

2. We disagree that our report misconstrues the role of repayment studies 

in Bonneville’s revenue requirements and rates. In our report, we focus 

on Bonneville’s revenue requirements studies (RRS), which encompass 

the debt service analyses contained in its repayment studies. In 

addition, we state that three of the PMAs use power repayment studies 

(PRS) to identify revenue requirements and demonstrate cost recovery 

as a key part of ratesetting, while Bonneville uses RRSs for similar 

purposes.

3. We recognize that, for Bonneville, repayment studies are prepared 

separately for generation debt and transmission debt for each year of a 

cost evaluation period. However, in response to Bonneville’s comments 

and technical comments provided by the three PMAs, we clarified in 

our report that we focused on the PRSs and RRSs, which encompass 

the full range and amount of costs to be recovered. We also clarified 

that there are key differences between (1) repayment studies and 

revenue requirements and (2) cost evaluation periods and repayment 

periods. 

4. We added language to acknowledge that Bonneville’s revenue 

requirements are set at the higher of forecasted accrued expenses 

(including depreciation expense) or cash requirements.

5. Our report acknowledges the complexity of preparing the studies that 

form the basis for ratesetting. However, it was not our intent to 

describe every facet of the process for Bonneville or the other entities 

we reviewed. However, to the extent policy issues resulted in costs to 

be recovered through power rates and therefore become a part of 

revenue requirements, we discussed the cost in our report. For 

example, our report states that the costs of protecting fish and wildlife 

and mitigating damage to fish affected by the construction and 

operation of the Federal Columbia River Power System are a 

consideration in the revenue requirements analysis that underlie 

Bonneville’s rates. We also state that the estimated range of funding for 
Appendix III

Comments From the Bonneville Power 

Administration

Page 59 GAO/AIMD-00-114 Power Marketing Administrations

these activities is $438 to $721 million annually for fiscal years 2002 

through 2006.

6. We agree that rates are designed after developing revenue requirements 

and have added clarifying comments to that effect. Our report 

discusses the similarities and differences between the IOUs and the 

PMAs fairly extensively. The report states that the IOUs’ rate proposals 

undergo a public process similar to the PMAs’ process and describe the 

types of costs (e.g., depreciation, interest, and operating expenses) the 

IOUs recover through rates. Further, we discuss that IOUs use a 

historical test period, adjusted for known and measurable changes. 

However, contrary to the comment, the historical test period used by 

the IOUs we contacted is much shorter than the period used by 

Bonneville and the other PMAs and is therefore a difference rather than 

a similarity. 

7. In our report we state that, in setting rates, Bonneville considers 

operating risks, such as weather-related uncertainties associated with 

the reliance on hydropower generation, and nonoperating risks such as 

fish and wildlife protection and mitigation expenditures. We also 

discuss Bonneville’s objective of setting rates that will result in an 

88 percent probability that Treasury payments will be made on time and 

in full over a 5-year period. However, as a result of Bonneville’s 

comments we expanded our discussion of Bonneville’s risk mitigation 

considerations and targets. We expanded our discussion of the types of 

risks that Bonneville considers in developing its revenue requirements. 

We also added a discussion of Bonneville’s target of setting rates that 

will result in a 97.5 percent probability that payments to the Treasury 

will be made on time and in full for each year of the rate period 

(88 percent over a 5-year period). The other issues raised in this 

comment provide a level of detail that is not required to accomplish the 

objectives of our review.

8. We recognize that Bonneville does not simply assume that average 

water conditions will prevail in the future when setting rates. We 

revised our report to say that historical hydrological data and projected 

river operations are used to project future water conditions. 
Appendix III

Comments From the Bonneville Power 

Administration

Page 60 GAO/AIMD-00-114 Power Marketing Administrations

9. We do not agree with Bonneville’s statement that its risk management 

strategies have enabled Bonneville to recover all costs on time and in 

full for 16 consecutive years. As we state in the current report, previous 

GAO reports1

 have demonstrated that the PMAs—including 

Bonneville—are not recovering all of the federal government’s costs of 

generating, transmitting, and marketing power. In those reports, GAO 

estimated that the unrecovered costs incurred by the federal 

government related to Bonneville’s operations totaled about 

$2,085 million for fiscal years 1992 through 1996.

10. This information provided by Bonneville provides a level of detail that 

is not required to accomplish the objectives of our review.2

11. We disagree with Bonneville’s statement that our report 

mischaracterizes its debt obligations and debt management practices. 

In our report we clearly state that Bonneville’s rates must cover the 

repayment of appropriations and bonds issued to the Treasury and debt 

service on nonfederal bonds primarily for the construction of Energy 

Northwest (formerly the Washington Public Power Supply System) 

nuclear plants. Further, we state that Bonneville had an outstanding 

debt of about $13.8 billion as of September 30, 1998, of which 

$4.4 billion related to unpaid federal appropriations, $2.5 billion related 

to bonds owed to the U.S. Treasury, and $6.9 billion related to its 

nonfederal project (e.g., nuclear projects) debt. Moreover, regarding 

debt management, in our report we state that in setting rates the PMAs 

assume that they will, where possible, mitigate interest costs by paying 

the highest interest rate debt first. This is consistent with Bonneville’s 

statement that its debt management objective is to minimize its total 

debt service costs. Examining the effect of the 1996 Bonneville 

Appropriations Refinancing Act was beyond the scope of our review.

1

Power Marketing Administrations: Cost Recovery, Financing, and Comparison to 

Nonfederal Utilities (GAO/AIMD-96-145, September 19, 1996); Federal Electricity Activities: 

The Federal Government’s Net Cost and Potential for Future Losses, volumes 1 and 2 

(GAO/AIMD-97-110 and 110A, September 19, 1997); and Power Marketing Administrations: 

Repayment of Power Costs Needs Closer Monitoring (GAO/AIMD-98-164, June 30, 1998).

2

Bonneville subsequently informed us that the statement in its comment letter that it has 

deferred an interest payment only once in its history is incorrect. According to Bonneville, it 

deferred interest payments in four separate years during the 1980s, with the last deferral 

occurring in fiscal year 1983.
Appendix III

Comments From the Bonneville Power 

Administration

Page 61 GAO/AIMD-00-114 Power Marketing Administrations

12. Our report makes it clear that the components of “financing costs” are 

(1) interest costs for the entities financed through debt only and 

(2) interest and dividends (common and preferred) for the entities 

financed through a combination of debt and equity. We analyzed and 

reported these financing costs as a percentage of operating revenues 

for the PMAs, IOUs, and POGs as an indicator of financial flexibility, 

which is an important consideration in an increasingly competitive 

electricity industry.

13. As stated in the explanation provided with table 1, the table illustrates 

the percentages of debt (1) repaid before the year in which the debts 

are due and (2) repaid at least 10 years before the year the debts are 

due. As explained in our discussion with Bonneville officials on 

March 16, we calculated the percentages repaid based on the total 

appropriated debt incurred over time that financed the PMAs. At that 

time, the Bonneville officials explained that their 68 percent figure was 

calculated based only on early repayments as a percentage of the 

amount of appropriated debt Bonneville had actually repaid to date, not 

on total appropriated debt incurred. The Bonneville officials agreed 

that our 17 percent figure was accurate as presented. While Bonneville 

did provide us with data from 1991 to 1998, that data were not 

sufficiently detailed for us to perform a complete analysis.

14. While we recognize that the term “deferred payments” can be used to 

describe missed interest and operations and maintenance expenses, 

our report uses the common dictionary definition of deferral (i.e., to 

“put off or delay”).3

 We believe we are correct in characterizing the 

PMAs’ ability to repay highest interest rate debt first and low interest 

rate debt later as deferring the repayment of low interest appropriated 

debt. However, we did add some language to the report clarifying that 

we are referring to the repayment of appropriated debt and that the 

deferral is until the years due and not beyond. We do not believe that 

our report suggests that the PMAs systematically make balloon 

payments by waiting until the year due to repay appropriated debt. In 

our report, we state that while the PMAs have the ability to defer the 

repayment of appropriated debt, they have repaid significant portions 

before the years in which they are due. In addition, table 1 shows that 

the PMAs have repaid significant portions of their appropriated debt 

3

Merriam-Webster’s Collegiate Dictionary, tenth edition. Springfield, Massachusetts: 

Merriam-Webster, 1993.
Appendix III

Comments From the Bonneville Power 

Administration

Page 62 GAO/AIMD-00-114 Power Marketing Administrations

before it is due, although Bonneville has repaid a lesser percentage 

before due than have the other three PMAs.

15. We state in our report that Bonneville’s rates must cover debt service 

on $6.9 billion in nonfederal bonds used primarily to construct Energy 

Northwest nuclear plants. We added language to our report that two of 

these nuclear plants are nonoperational and therefore do not generate 

revenues to offset the interest costs of the associated debt.

16. We do not believe it necessary to include in our report the table 

Bonneville provided that compares its appropriations to IOU capital. As 

discussed above, we adequately and accurately characterized 

Bonneville’s debt obligations and debt management practices.

17. We disagree with Bonneville’s statement that we did not consider the 

impact on its competitive position of its expenditures on “public 

benefits” initiatives. We considered the impact that expenditures 

related to the primary benefit cited by Bonneville—environmental 

mitigation and enhancement activities—have on Bonneville’s rates and 

costs, which are directly related to its competitive position. In our 

report we state that the costs of protecting fish and wildlife and 

mitigating damage to fish affected by the construction and operation of 

the Federal Columbia River Power System are a consideration in the 

revenue requirements analysis that underlie Bonneville’s rates. In 

addition, we state that the estimated range of funding for these 

activities is from $438 to $721 million annually for fiscal years 2002 

through 2006. To the extent that these expenditures go toward 

mitigating environmental harm not caused by the production of power, 

they provide public benefits. However, to the extent that these 

expenditures are undertaken to mitigate environmental harm caused by 

producing power, the costs are analogous to the environmental 

mitigation costs incurred by any other utility. We did not assess 

whether Bonneville’s expenditures to mitigate environmental harm 

caused by producing power are greater or lesser than the 

environmental mitigation expenditures of other utilities.

In addition, we disagree with Bonneville’s statement that we do not 

consider the irrigation costs that Bonneville must recover through 

rates. Our report clearly states that two of the PMAs—Bonneville and 

Western—are required to set rates at levels sufficient to repay certain 

nonpower costs, such as irrigation, that the Congress has assigned to 

power users to repay. Further, our report states that as of 
Appendix III

Comments From the Bonneville Power 

Administration

Page 63 GAO/AIMD-00-114 Power Marketing Administrations

September 30, 1998, approximately $863 million in irrigation costs had 

been allocated for repayment through power revenues at Bonneville 

and that $25 million (3 percent) of that amount had been repaid. We 

have also added a statement to the report acknowledging Bonneville’s 

requirement to provide power to residential and small farm consumers 

of investor-owned utilities.

Any disadvantages cited by Bonneville in its letter are overshadowed by 

the cost advantages we describe in our report. Our report shows that 

Bonneville’s investment in utility plant per megawatt of generating 

capacity and average revenues per kilowatthour for wholesale sales are 

relatively low compared to IOUs and POGs.

18. We disagree. The objectives of our review did not include providing 

detailed information on every legislative requirement followed by 

Bonneville or the other three PMAs. We did not delineate all the 

requirements contained in the Northwest Power Act or the other acts 

we cited, such as the Reclamation Project Act of 1939 and the Flood 

Control Act of 1944. Our report acknowledges that Bonneville’s 

ratesetting process is unlike that of the other three PMAs.We have 

added language to clarify that the primary statute governing 

Bonneville’s ratesetting procedures is the Northwest Power Act. In 

addition, we discuss Bonneville’s rate development process separately 

and provide a separate flowchart that depicts Bonneville’s process 

under the Northwest Power Act. To achieve our reporting objectives, 

we appropriately focused on the three PMAs’ power repayment studies 

and Bonneville’s revenue requirement study, which identify the PMAs’ 

costs to be recovered through rates and revenue requirements. The 

legislative requirements affecting Bonneville’s revenue requirements 

are reflected in its revenue requirement studies.

19. We developed the flowchart depicting Bonneville’s ratesetting process 

based on discussions with Bonneville officials. We have incorporated 

into this final report Bonneville’s subsequent minor edits and 

clarifications. 

20. Our report discusses the Energy Policy Act of 1992 and FERC’s role in 

ratesetting sufficiently to achieve the objectives of our review.

(913864) Letr
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