Power Marketing Administrations: Their Ratesetting Practices Compared
With Those of Nonfederal Utilities (Letter Report, 03/30/2000,
GAO/AIMD-00-114).

Pursuant to a congressional request, GAO reviewed the Department of
Energy's (DOE) power marketing administrations (PMA), focusing on: (1)
how the PMAs set their rates to recover costs; (2) how the PMAs'
ratesetting practices compare to those of investor-owned and publicly
owned utilities; and (3) the impact of the PMAs' ability to defer
repayment of portions of their debt on their future competitiveness.

GAO noted that: (1) the PMAs determine the adequacy of rates by
performing annual reviews of their projected costs and revenues, using
processes and assumptions that are to identify and factor into rates
costs that are legally recoverable, while keeping rates as low as
possible; (2) Southwestern, Southeastern, and most Western Area Power
Administrations projects make this determination through power repayment
studies (PRS); (3) Bonneville uses a revenue requirement study; (4)
these studies analyze historical data and project estimated future costs
and revenues as a key part of ratesetting; (5) regulatory oversight and
the processes and assumptions that guide cost recovery vary among PMAs,
investor-owned utilities (IOU) and publicly owned generating (POG)
utilities; (6) in addition, rates are affected by responsibilities to
investors and taxing authorities and whether the entity operates in a
cost-based or market-based environment; (7) all the entities GAO
reviewed had some kind of public process that took place when changes in
rates were under consideration; (8) however, PMAs differed significantly
from IOUs and POGs in two areas; (9) first, they have the flexibility to
defer repayment of appropriated debt until the year due, which is
typically longer than other utilities are able to defer repayment of
their debts; (10) unlike IOUs and POGs, PMAs do not have to generate a
return for owners and generally do not pay taxes; (11) 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; (12) 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; (13) these high financing costs may become more significant in
an increasingly competitive electricity industry; (14) while the high
financing costs will pose challenges for these three PMAs, 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; (15) key among the PMAs'
advantages is that they market low-cost hydropower, much of it generated
from facilities built decades ago at low cost; (16) in addition, in
contrast to IOUs and POGs, PMAs are generally not required to pay taxes
or generate a return for owners; and (17) because of these inherent cost
advantages, the PMAs overall are well positioned competitively.

--------------------------- Indexing Terms -----------------------------

 REPORTNUM:  AIMD-00-114
     TITLE:  Power Marketing Administrations: Their Ratesetting
	     Practices Compared With Those of Nonfederal Utilities
      DATE:  03/30/2000
   SUBJECT:  Electric utilities
	     Utility rates
	     Cost analysis
	     Energy marketing
	     Hydroelectric energy
	     Prices and pricing
	     Electric power generation
	     Competition
	     Cost control
	     Loan repayments

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GAO/AIMD-00-114

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

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

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

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

Accounting and Information
Management Division

B-283123

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 investor-owned
and publicly owned utilities, and

3. the impact of the PMAs' ability to defer repayment of portions of their
debt on their future competitiveness.

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.

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.

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, 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.

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.

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.

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.

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.

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

ï¿½ bonds issued to the Treasury to finance capital programs, such as
transmission system development, conservation, and fish and wildlife
enhancement;

ï¿½ debt service on nonfederal bonds primarily for the construction of Energy
Northwest (formerly the Washington Public Power Supply System) nuclear
plants;17 and

ï¿½ 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).

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:

ï¿½ Historical hydrological data and projected river operations will be used
to project future water conditions.

ï¿½ Appropriated debt related to the original construction of assets used to
generate power will generally be repaid within 50 years.19

ï¿½ Appropriated debt related to assets used to transmit power will generally
be repaid within 35 to 45 years.

ï¿½ 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.

ï¿½ 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

ï¿½ 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.

ï¿½ Where possible, to mitigate interest costs, the highest interest rate debt
will be paid first.

ï¿½ 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.

In addition to the above, Bonneville makes the following key assumptions:

ï¿½ U.S. Treasury bonds will be systematically repaid based on the term of the
debt.

ï¿½ Revenue requirements will be set at the higher of forecasted accrued
expenses (including depreciation expense) or cash requirements.

ï¿½ 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.

ï¿½ 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.

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.

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.

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.

When they are considering a rate adjustment, the three PMAs are required to
publish notices in the Federal Register to notify customers, the general
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.

Figure 3: The Three PMAs' Rate Development Process
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
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.

Figure 4: Bonneville's Rate Development Process
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.

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.

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
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:

ï¿½ 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.

ï¿½ 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.

ï¿½ 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.

ï¿½ 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.

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 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

ï¿½ 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

ï¿½ 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.

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 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.

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.

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.

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

                 Bonneville          Southeasternc,h     Southwesternc   Westernc,d

            Appropriated Treasury   CumberlandGA-AL-SC   Integratede    CVPf SLCA-IP
              Debtb,c     Bondsg
 Total
 percentage
 repaid     17           28         64        27         43             63.2 60.2
 before year
 due
 Percentage
 repaid at
 least 10
 years      9            24         36        25         19             62.7 59.7
 before year
 due

aThis 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).

bBonneville'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.

cThis 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-in-progress) because
those assets do not have repayment due dates.

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

eSouthwestern'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.

fAlthough 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.

gBonneville 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).

hThe 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.

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.

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.

Table 2: Percentages of the PMAs' High Interest and Low Interest Debt Repaid
as of Fiscal Year 1998a

             Bonneville             Southeasternb         Southwesternb,  Westernb,e
                                                          d

             Appropriated Treasury  Cumberland GA-AL-SC   Integrated      CVP SLCA-IP
             Debtb        Bonds
 Percentage
 of high
 interestc   13           81        100        100        99              93  52
 debt
 repaid
 Percentage
 of low
 interestc   66           33        62         21         25              53  69
 debt
 repaid

aThis 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).

bThis 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.

cFor 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.

dSouthwestern's data are for fiscal year 1997.

eThe 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

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.
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
Salt Lake City Area Integrated Projects carry interest rates ranging from
7 percent to 11 percent.

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.

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.

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.

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.

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.

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.

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.

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
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.

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.

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.

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

Objectives, Scope, and Methodology

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.

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.

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.

ï¿½ 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.

ï¿½ Geographic location: We selected entities from across the United States to
ensure that our analyses considered ratesetting practices that may vary in
different regions.

ï¿½ Status of electric industry restructuring: We selected at least one IOU
and one POG from nonrestructured states and all the others from restructured
states.

ï¿½ Location in relation to PMA service territories: We selected at least one
IOU and/or one POG from each PMA's service territory.

ï¿½ 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.

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

ï¿½ the percentage of the PMAs' debt repaid before due as of September 30,
1998,48 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;

ï¿½ the repayment of debt by interest rate as of September 30, 1998,49 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;

ï¿½ 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;

ï¿½ the average operating expenses by generation type (fossil, gas, hydro, and
nuclear) to confirm that hydroelectric generation of power is relatively
inexpensive;

ï¿½ 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;

ï¿½ 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

ï¿½ 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.

Department of Energy
Energy Information Administration
Federal Energy Regulatory Commission

PricewaterhouseCoopers, LLP
Deloitte & Touche, LLP

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

California Public Utilities Commission, San Francisco, California
Idaho Public Utilities Commission, Boise, Idaho
Virginia State Corporation Commission, Richmond, Virginia

American Public Power Association, Washington, D.C.
Edison Electric Institute, Washington, D.C.
National Association of Regulatory Utility Commissioners, Washington, D.C.

Comments From Southeastern, Southwestern, and Western Area Power
Administrations

Comments From the Bonneville Power Administration

The following are GAO's comments on the Bonneville Power Administration's
letter dated March 23, 2000.

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
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.

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
reports50 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.51

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.

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").52 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 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
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)

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

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
  

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.

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.

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.

10. As 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.

11. Previous 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.

12. DOE 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.

13. Revenue 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.

14. The 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.

15. In 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.

16. Reclamation 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.

17. Bonneville 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.

18. Bonneville's estimated range of funding is $438 million to $721 million
annually for fiscal years 2002 through 2006.

19. There are exceptions, such as Bonneville's Yakima-Chandler Project with
a legislated repayment period of 66 years.

20. However, 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.

21. Southeastern'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.

22. According 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.

23. Debt 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.

24. Rather 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.

25. These 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.

26. When 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.

27. Parties 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.

28. The purpose of an initial brief is to identify separately each legal,
factual, and policy issue to be resolved by the Administrator.

29. The 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.

30. For purposes of this discussion, we define an IOU as a for-profit
utility that generates, transmits, and distributes power.

31. For 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.

32. Depreciation 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.

33. Some 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.

34. In a restructured environment, the market sets the price for generation
and only the distribution portion of an IOU's rates remains regulated.

35. The 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-service-based power.

36. Depending 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.

37. Default 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.

38. We 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.

39. Federal Electricity Activities: Appendixes to The Federal Government's
Net Cost and Potential for Future Losses (GAO/AIMD-97-110A , September 19,
1997).

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

41. The 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.

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

43. The 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.

44. However, Bonneville has repaid a significant portion of its U.S.
Treasury bonds before due.

45. The 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.

46. Federal Electricity Activities: Appendixes to The Federal Government's
Net Cost and Potential for Future Losses (GAO/AIMD-97-110A, September 19,
1997).

47. EIA 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.

48. Southwestern's data are for fiscal year 1997.

49. Southwestern's data are for fiscal year 1997.

50. 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).

51. 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.

52. Merriam-Webster's Collegiate Dictionary , tenth edition. Springfield,
Massachusetts: Merriam-Webster, 1993.
*** End of document. ***