Power Marketing Administrations: Cost Recovery, Financing, and Comparison
to Nonfederal Utilities (Chapter Report, 09/19/96, GAO/AIMD-96-145).

In recent years, Congress has weighed the pros and cons of privatizing
the federal power marketing administrations (PMA), which transmit and
sell electric power generated at federal hydropower facilities. This
report provides information on three of these PMAs--the Southeastern
Power Administration, the Southwestern Power Administration, and the
Western Area Power Administration. GAO answers the following three
questions: Have all power-related costs incurred through September 1995
been recovered through the PMA's electricity rates? Is the financing for
power-related capital projects subsidized by the federal government and,
if so, to what extent? How do PMAs differ from nonfederal utilities and
what is the impact of these differences on power production costs? GAO
summarized this report in testimony before Congress; see: Power
Marketing Administrations: Cost Recovery, Financing, and Comparison to
Nonfederal Utilities, by Linda M. Calbom, Director of Civil Audits,
before the Subcommittee on Water and Power Resources, House Committee on
Resources. GAO/T-AIMD-96-169, Sept. 19 (15 pages).

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

 REPORTNUM:  AIMD-96-145
     TITLE:  Power Marketing Administrations: Cost Recovery, Financing, 
             and Comparison to Nonfederal Utilities
      DATE:  09/19/96
   SUBJECT:  Utility rates
             Energy marketing
             Electric utilities
             Electric power transmission
             Public utilities
             Construction costs
             Interest rates
             Retirement benefits
             Tax exempt status
             Hydroelectric energy
IDENTIFIER:  Federal Employees Retirement System
             Civil Service Retirement System
             Reclamation Fund
             Bureau of Reclamation Pick-Sloan Missouri Basin Program
             DOE Richard B. Russell Project
             DOE Harry S. Truman Project
             DOE Mead-Phoenix Transmission Line Project
             Fort Peck Project (MT)
             Colorado River Storage Project
             Glen Canyon Dam (AZ)
             Central Valley Project (CA)
             Shasta Dam (CA)
             Central Arizona Project (AZ)
             
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Cover
================================================================ COVER

Report to Congressional Requesters

September 1996

POWER MARKETING ADMINISTRATIONS -
COST RECOVERY, FINANCING, AND
COMPARISON TO NONFEDERAL UTILITIES

GAO/AIMD-96-145

Power Marketing Administrations

(913745)


Abbreviations
=============================================================== ABBREV

  AEAN - aggregate entry age normal
  APPA - American Public Power Association
  CSRS - Civil Service Retirement System
  CVP - Central Valley Project
  CWIP - construction-work-in-progress
  DOE - Department of Energy
  EEI - Edison Electric Institute
  EIA - Energy Information Administration
  F&WS - U.S.  Fish and Wildlife Service
  FASAB - Federal Accounting Standards Advisory Board
  FASB - Financial Accounting Standards Board
  FERC - Federal Energy Regulatory Commission
  FERS - Federal Employee Retirement System
  FTE - full-time equivalent
  GASB - Governmental Accounting Standards Board
  IOU - investor-owned utility
  IPP - independent power producer
  KPMG - KPMG Peat Marwick LLP
  kWh - kilowatthour
  NERC - North American Electric Reliability Council
  NRC - Nuclear Regulatory Commission
  O&M - operating and maintenance
  OMB - Office of Management and Budget
  OPM - Office of Personnel Management
  PMA - Power Marketing Administration
  POG - publicly owned generating utility
  PURPA - Public Utilities Regulatory Policies Act of 1978
  SEPA - Southeastern Power Administration
  SFAS - Statement of Financial Accounting Standards
  SFFAS - Statement of Federal Financial Accounting Standards
  SWPA - Southwestern Power Administration
  UDC - ultimate development concept
  WAPA - Western Area Power Administration

Letter
=============================================================== LETTER


B-271161

September 19, 1996

The Honorable John T.  Doolittle
Chairman, Subcommittee on Water
 and Power Resources
Committee on Resources
House of Representatives

The Honorable George Miller
Ranking Minority Member
Committee on Resources
House of Representatives

As requested, this report presents the results of our review of three
power marketing administrations' (PMAs) cost recovery practices,
financing, and comparison to nonfederal utilities. 

We are sending copies of the report to appropriate House and Senate
committees, interested Members of the Congress, the PMAs, the
Secretary of Energy, the Secretary of the Interior, the Secretary of
Defense, the Office of Management and Budget, and other interested
parties.  Copies will also be made available to others upon request. 

I may be reached at (202) 512-8341 if you have any questions about
this report.  Major contributors to this report are listed in
appendix VII. 

Linda M.  Calbom
Director, Civil Audits


EXECUTIVE SUMMARY
============================================================ Chapter 0


   PURPOSE
---------------------------------------------------------- Chapter 0:1

In recent years, the Congress has focused increasing attention on the
pros and cons of privatizing the federal power marketing
administrations (PMAs), which transmit and sell electric power
generated mainly at federal hydropower facilities.  Most of these
facilities were originally designed for other purposes in addition to
producing electricity.  The Chairman, Subcommittee on Water and Power
Resources, House Committee on Resources, and the Committee's Ranking
Minority Member asked GAO to provide information about three of these
PMAs--the Southeastern Power Administration, the Southwestern Power
Administration, and the Western Area Power Administration.  As
requested, GAO's review addressed three main questions: 

  -- Have all power-related costs incurred through September 30,
     1995, been recovered through the PMAs' electricity rates? 

  -- Is the financing for power-related capital projects subsidized
     by the federal government and, if so, to what extent? 

  -- How do PMAs differ from nonfederal utilities and what is the
     impact of these differences on power production costs? 

We were not asked to and did not address whether any changes in PMA
cost recovery practices or financing should be made. 


   BACKGROUND
---------------------------------------------------------- Chapter 0:2

The three PMAs, part of the Department of Energy (DOE), market
primarily wholesale power in 30 states produced at large,
multiple-purpose water projects.  Collectively, in fiscal year 1995,
they had revenues of almost $1 billion.  Most of the power they sell
is produced at 102 hydroelectric dams built and run primarily by the
U.S.  Army Corps of Engineers and the Department of the Interior's
Bureau of Reclamation (operating agencies).  The operating agencies
constructed these facilities as part of a larger effort in developing
multipurpose water projects that have functions other than power
generation, including flood control, irrigation, navigation, and
recreation.  To transmit this power, Southwestern and Western have
their own transmission facilities, while Southeastern relies on the
transmission services of other utilities. 

The three PMAs receive annual appropriations to cover operating and
maintenance (O&M) expenses and, if applicable, the capital investment
in transmission assets.  Federal law calls for PMAs to set power
rates at levels that will repay these appropriations as well as the
power-related O&M and capital appropriations expended by the
operating agencies generating the power.  DOE's implementing order
specifies that unless otherwise prescribed by law, appropriations
used for O&M expenses be recovered in the same year the expenses are
incurred, but that appropriations used for capital investments (which
we refer to as appropriated debt\1 ) be recovered, with interest,
over periods of up to 50 years.  At the end of fiscal year 1995, the
three PMAs had about $5.4 billion of appropriated debt outstanding. 
In addition, Western is required to recover about $1.5 billion of
capital costs related to assistance on completed irrigation
facilities (which we refer to as irrigation debt), without interest,
with repayment periods of up to 60 years. 


--------------------
\1 GAO calls this appropriated debt because PMAs are required to
repay appropriations used for capital investments, with interest. 
However, these reimbursable appropriations are not technically
considered lending by the Treasury. 


   RESULTS IN BRIEF
---------------------------------------------------------- Chapter 0:3

GAO identified five main power-related costs that have not been fully
recovered by one or more of the PMAs through rates:  (1) pensions and
postretirement health benefits for current employees, (2)
construction costs for some power-generating and transmission
projects, (3) construction and O&M costs that have been allocated to
irrigation facilities at the Pick-Sloan Program that are incomplete
and infeasible, (4) costs of mitigating the environmental impact of
certain water projects, and (5) certain O&M and interest expense
payments due from Western.  In some cases, PMAs are not required to
recover these costs because of specific legal provisions, while in
others, the DOE implementing order either excludes the costs or is
not specific and has been interpreted by the PMAs to exclude the
costs.  GAO estimated that these unrecovered costs amounted to
approximately $83 million for fiscal year 1995 and cumulatively could
be as much as $1.8 billion as of September 30, 1995. 

GAO also determined that financing of power-related capital projects
is subsidized by the federal government and estimates that the
financing subsidies were about $200 million in fiscal year 1995.  GAO
estimates that the cumulative financing subsidy over the last 30
years has been several billion dollars.  Financing subsidies result
from DOE policies that require PMAs to pay off high interest
appropriated debt first while retaining low-interest debt.  Also,
prior to 1983, the interest rates imposed at the time the funds for
capital projects were appropriated were generally below U.S. 
Department of Treasury rates.  Financing subsidies exist because
Treasury's cost of funds is greater than the interest rates on PMA
appropriated debt.  For example, the fiscal year 1995 weighted
average interest rate for the Southwestern Power Administration's
$686 million of outstanding appropriated debt was 2.9 percent
compared to Treasury's September 30, 1995, weighted average interest
rate on its bond portfolio of 9.1 percent.  Treasury's cost of funds
is relatively high because of its inability to refinance or prepay
its debt. 

The types of unrecovered costs described above are typically included
in power production costs and electricity rates established by
nonfederal utilities.  In addition, nonfederal utilities, on average,
generally pay higher interest rates on debt than do PMAs.  PMAs have
other inherent advantages over nonfederal utilities.  One such
advantage is that nearly all of the power marketed by these three
PMAs is hydropower primarily generated from projects built 30 to 60
years ago.  This hydropower is a low cost energy source compared to
coal and nuclear fuels, which are the primary energy sources used by
other utilities.  Another advantage is that PMAs, as federal
agencies, do not, for the most part, pay taxes.  The unrecovered
costs, financing subsidies, and inherent cost advantages have
resulted in the PMAs' being a low cost marketer of wholesale electric
power.  In 1994, the PMAs average revenue per kilowatthour (kWh) for
wholesale sales was approximately 40 percent less than the average
for nonfederal utilities. 

PMAs also have disadvantages compared to nonfederal utilities.  For
example, Western is required to recover certain nonpower costs
through rates, such as the Hoover Dam Visitor Center and irrigation
assistance totaling $1.5 billion.  Increased competition in wholesale
electricity markets is projected to lower rates, which will magnify
the importance of the PMAs' marketing low cost power because
customers are able to buy electricity from suppliers that have the
most advantageous rates. 

In aggregate, we estimate that the unrecovered power-related costs
and financing subsidy total about $300 million for fiscal year 1995
and billions of dollars over the last 30 years.  It is important to
note that the PMAs are generally following applicable laws and
regulations regarding recovery of power-related costs discussed in
this report and financing of capital projects. 


   GAO'S ANALYSIS
---------------------------------------------------------- Chapter 0:4


      RATES DO NOT RECOVER ALL
      POWER-RELATED COSTS
-------------------------------------------------------- Chapter 0:4.1

The Reclamation Project Act of 1939 and the Flood Control Act of 1944
generally require that the PMAs recover through power rates the costs
of producing and marketing federal hydropower.  However, these acts
do not define which costs are required to be recovered.  In addition,
DOE's implementing Order RA 6120.2, which was issued in 1979 and last
revised in 1983, excludes certain costs associated with
nonoperational facilities and is not specific about recovery of
others.  Where the order is not specific, PMAs have interpreted it to
exclude certain costs from rates.  To define the full cost of power
production and marketing, GAO referred to Office of Management and
Budget (OMB) Circular A-25, "User Charges," industry practice, and
federal accounting standards.  These criteria indicate that the full
cost of producing and marketing federal hydropower would include all
direct and indirect costs incurred by the PMAs, operating agencies,
and other agencies involved in power-related activities.  GAO
identified five main power-related costs that meet these criteria
that have not yet been fully recovered through electricity rates.\2

First, the three PMAs do not recover the full cost of power-related
postretirement health benefits and Civil Service Retirement System
(CSRS) pension benefits for current PMA and operating agency
employees.  For fiscal year 1995, GAO estimates that these
unrecovered costs were about $16 million.  The annual funding
shortfall associated with CSRS pension benefits will be eliminated
over time as CSRS employees leave the government and are replaced by
employees covered by the Federal Employees Retirement System (FERS),
for which pension benefits are fully funded.  The annual funding
shortfall associated with postretirement health benefits, however,
will not be eliminated as a result of this transition, since it is an
entirely separate benefit program.  As of September 30, 1995, GAO
estimates that the cumulative unrecovered costs associated with
postretirement health benefits and CSRS pension benefits were about
$436 million. 

Second, all three PMAs had incurred costs and/or had costs allocated
to them for projects that were completed or under construction for
which full costs were not being recovered.  In some cases, this was
because the power-generating projects had never operated as designed. 
In accordance with DOE guidance, PMAs set rates that exclude the
costs of non-operational parts of power projects, including
capitalized interest.  For example, at the Russell Project, partially
on line since 1985, litigation over excessive fish kills has kept
four of the eight turbines from becoming operational.  As a result,
about one-half of the project's construction costs have been excluded
from Southeastern's rates.  It is unclear whether these costs,
totalling $488 million as of September 30, 1995, will be recovered if
the project never operates to the capacity designed.  In other cases,
the tenuous financial condition of completed projects also raises
questions about whether related power costs will be recovered.  For
example, Western is currently selling electricity from the Washoe
Project for less than 20 percent of what it costs to produce. 
According to Western, this situation is the result of relatively high
construction costs and drought conditions.  According to Western's
1995 annual report:  "Based on current conditions, it is unlikely the
project will be able to generate sufficient revenues to repay the
Federal investment." For the same reasons, GAO believes that the
Washoe Project is unlikely to generate sufficient revenue to repay
all O&M and interest expenses. 

Third, as GAO reported in May 1996,\3 at the Pick-Sloan Missouri
Basin Program (Pick-Sloan), about $454 million of capital costs for
hydropower facilities and water storage reservoirs have been
allocated to authorized irrigation facilities that are infeasible and
therefore not expected to be completed.  Western is currently selling
electricity to its power customers that would have been used by the
irrigators had the irrigation facilities been completed.  As long as
the $454 million is allocated to incomplete irrigation facilities,
recovery by Western will not be required.  If the facilities were
completed and the capital costs were determined to be beyond the
irrigators' ability to repay, then Western would be required to
recover most of these irrigation costs without interest.  If these
costs had been allocated based on the actual use of the hydropower
facilities and water storage reservoirs, they would have been
allocated primarily to power production and recovered, with interest,
through electricity rate charges within 50 years of completion. 
Under the current repayment criteria, it is unlikely that Western
will be required to recover the principal or any interest on these
capital costs.  In addition, since 1987, $13.7 million ($15.3 million
in constant 1995 dollars) of power-related O&M expenses incurred by
the Army Corps of Engineers at Pick-Sloan have been allocated to
incomplete irrigation facilities and thus are not being recovered
through power rates. 

The methodology that resulted in allocating power-related capital and
O&M costs to the incomplete irrigation facilities was developed
decades ago in anticipation of the completion of all planned
irrigation facilities.  This methodology is still being used and will
continue to increase these unrecovered power costs.  However, as GAO
also reported in May 1996, changing the terms of repayment to recover
any of the $454 million investment would require congressional
action.  Additionally, any changes between the program's power and
irrigation purposes may also necessitate reviewing other aspects of
the agreements--specifically, the agreements involving areas that
accepted permanent flooding from dams in anticipation of the
construction of irrigation facilities that are now not likely to be
constructed. 

Fourth, the Central Valley Project's Shasta Dam and the Colorado
River Storage Project's Glen Canyon Dam have incurred power-related
environmental mitigation costs that are legislatively excluded from
Western's rates.  For the Shasta Dam, these costs totaled $9.7
million in 1995 and $5.4 million in 1994.  For the Glen Canyon Dam,
they totaled $13.9 million and $12.5 million for the same 2 years. 
The total cumulative legislatively excluded environmental costs for
the two projects were $134.3 million ($152.5 million in constant 1995
dollars) as of September 30, 1995. 

Fifth, as of September 30, 1995, Western had unrecovered O&M and
interest expense payments relating to nine of its 15 projects.  These
"deferred payments" are to be repaid to Treasury, with interest. 
According to Western, these deferred payments are primarily due to
drought conditions which reduced streamflow and hence the ability to
generate electricity in the late 1980s and early 1990s.  The balance
of Western's deferred payments decreased from about $250 million as
of September 30, 1994, to about $196 million as of September 30,
1995.  Western officials have told us they expect to recover the
majority of these costs over time. 


--------------------
\2 GAO did not assess the reasonableness of the methodologies used by
the operating agencies to allocate costs to power users and therefore
could not determine whether these allocations result in recovery of
all applicable operating agency power costs. 

\3 Federal Power:  Recovery of Federal Investment in Hydropower
Facilities in the Pick-Sloan Program (GAO/T-RCED-96-142, May 2,
1996). 


      FAVORABLE TERMS RESULT IN
      SUBSIDIZED FINANCING
-------------------------------------------------------- Chapter 0:4.2

Power-related capital projects are financed, primarily, with
appropriated funds.  Federal legislation and DOE policy enable PMAs
to implement flexible financing terms that allow the accumulation of
large amounts of appropriated debt at low interest rates.  PMAs have
low interest rates on appropriated debt for two primary reasons. 
First, DOE's policy generally requires PMAs to pay off outstanding
debt with the highest interest rate first, regardless of maturity
dates.  (This does not apply to any debt due in a given fiscal year. 
Such debt must be paid first, regardless of interest rate.) Second,
prior to 1983, capital projects were generally financed at interest
rates lower than the then prevailing comparable Treasury interest
rates.  Because repayment terms on below market interest rate
appropriated debt are up to 50 years, some of this debt could remain
outstanding for several more decades. 

A financing subsidy exists because the interest expense incurred by
Treasury on its debt is higher than the interest income Treasury
receives from the PMAs for their appropriated debt.  This financing
subsidy is a result of the flexible repayment terms allowed the PMAs
by federal law and DOE regulations and the below market interest
rates incurred on appropriated debt prior to 1983.  For fiscal year
1995, the average interest rates on appropriated debt were 2.9
percent for Southwestern, 4.4 percent for Southeastern, and 5.5
percent for Western.  The average interest rate on Treasury's
outstanding bond portfolio as of September 30, 1995, was 9.1 percent. 
GAO estimates that the financing subsidy for the three PMAs was about
$200 million in fiscal year 1995.  Over the next several decades, as
the pre-1983 appropriated debt is paid off, the PMAs' financing
subsidy should decrease.  However, the PMAs' ability to repay high
interest debt first has been a factor and likely will continue to
contribute to PMA average interest rates being below the effective
Treasury average interest rate.  In addition, Treasury's borrowing
practices contribute to the magnitude of the financing subsidy. 
Treasury's inability to refinance or prepay outstanding debt in times
of falling or low interest rates is part of the reason for its
relatively high 9.1 percent average cost of funds in fiscal year
1995. 


      FEDERAL SUBSIDIES AND
      INHERENT ADVANTAGES OF PMAS
      RESULT IN LOW COST POWER
-------------------------------------------------------- Chapter 0:4.3

PMAs market low cost wholesale electricity.  The PMAs' average
revenue per kWh for wholesale sales was substantially lower in 1994
than averages for other utilities.  In 1994, the national wholesale
average revenue per kWh was 3.5 cents for investor-owned utilities
(IOUs) and 3.9 cents for publicly owned generating utilities (POGs). 
This compares to 1.49 cents for Southwestern; 1.82 cents for Western;
and 1.98 cents for Southeastern.  GAO believes that average revenue
per kWh is a strong indicator of the relative power production costs
and overall competitive position of the PMAs compared to other
utilities.  Except for several rate-setting systems at Western, and
one at Southeastern, the PMAs' power production costs appear to be
stable and well below the costs for nonfederal utilities in their
respective areas of the country. 

In addition to unrecovered costs and subsidized financing, other
inherent advantages contribute to the PMAs marketing low cost power. 
One key advantage is PMA access to and almost exclusive reliance on
hydropower primarily produced by projects built 30 to 60 years ago, a
low cost means of generating electricity.  Unlike the PMAs and
operating agencies, IOUs build new capacity to meet future customer
needs and must rely on more expensive sources of electricity, such as
coal and nuclear energy.  In 1995, about 55 percent of the
electricity generated in the United States by IOUs and POGs was
fueled by coal, and another 25 percent by nuclear energy.  PMAs, as
federal agencies, generally do not pay taxes, whereas other utilities
pay federal and state income taxes, property taxes, and other taxes,
or payments in lieu of taxes.  In 1994, IOUs paid an average of about
14 percent of revenues for taxes, and POGs paid an average of 5.8
percent of revenues to state and local governments in lieu of taxes. 

PMAs also have certain disadvantages compared to nonfederal
utilities.  For example, Western is required to recover through rates
the cost of the Hoover Dam Visitor Center totaling an estimated $124
million.  Additionally, Western is required to recover approximately
$1.5 billion related to construction costs on completed irrigation
facilities.  Reclamation law provides for Western to repay certain
portions of capital costs allocated to irrigation purposes which are
determined to be beyond the ability of the irrigators to repay. 
Recent developments are projected to decrease average wholesale
electricity rates, which could impact the competitiveness of certain
of the PMAs' higher cost rate-setting systems.  Competition in the
wholesale electricity market is increasing due to legislation such as
the Energy Policy Act of 1992, which encouraged additional wholesale
suppliers to enter the market and provided greater access to other
utilities' transmission lines.  Another factor that could impact the
PMAs is the increasing influence of low cost independent (nonutility)
power producers (IPPs).  Construction of increasingly efficient
natural gas-fired combustion turbines by IPPs is driving the market
price of wholesale electricity down. 


   AGENCY COMMENTS
---------------------------------------------------------- Chapter 0:5

The Department of Energy's Power Marketing Liaison Office provided
written comments to GAO that reflect the views of Southeastern,
Southwestern, and Western.  These written comments and GAO's
responses are discussed below and in chapters 2, 3, and 4, and
appendix II. 

In commenting on a draft of this report, the PMAs stated that they
are following the law and congressional intent in their current
repayment and accounting practices.  They stated that congressional
action would be needed to change PMA repayment and cost recovery
practices.  With regard to cost recovery, the PMAs agree that by law
there are some power-related costs that are not fully recovered
through rates.  However, they believe that a distinction needs to be
made between unrecovered (could be recovered in the future) versus
unrecoverable (will never be recovered) costs and disagree with
certain findings about unrecovered costs as discussed in the agency
comments section of chapter 2.  During its review, GAO noted that the
PMAs were generally following applicable laws and regulations
regarding cost recovery and financing of capital projects.  However,
determining whether the Congress should change PMA repayment and cost
recovery practices was beyond the scope of GAO's review.  GAO was
requested to determine whether all power-related costs incurred as of
September 30, 1995, had been recovered.  The determination of whether
unrecovered costs through this point in time will be recovered in the
future, or whether all power-related costs should be recovered, was
beyond the scope of this review. 

The PMAs agree that certain unpaid investments are charged an
interest expense that is less than Treasury's cost of borrowing at
the time the investment was made.  However, they believe GAO's
methodology for calculating the financing subsidy is flawed and that
it should not include the PMAs' flexible repayment terms as part of
the calculation of the financing subsidy.  GAO disagrees.  As stated
in chapter 3, GAO believes that there is a financing subsidy on the
PMAs' appropriated debt because interest rates the PMAs pay do not
fully recover the federal government's cost of funds.  GAO believes
that its methodology in calculating this financing subsidy reflects a
reasonable approximation of the net cost of power-related financing
to the federal government.  This net cost includes both the interest
differential at the time of the borrowing and the PMAs' flexible
repayment terms for their appropriated debt. 

The PMAs noted that they are not truly comparable to other utilities
because of their unique characteristics and different mission.  The
PMAs agree that they are low cost producers of electricity but
disagree with GAO's use of average revenue per kWh to make
comparisons with other utilities.  The PMAs stated that using average
revenue per kWh to make such comparisons may mislead the report's
readers about the magnitude and causes of the difference in cost
between PMAs and other utilities.  As stated in chapter 4, GAO
believes that average revenue per kWh is a strong indicator of the
PMAs' relative power production cost and competitiveness.  GAO also
believes that PMA customers are primarily concerned with production
costs and resultant electricity rates.  Given falling electricity
rates and increasing competition, if the PMAs do not market low cost
power, then they may not be able to recover all power-related costs. 
Therefore, GAO believes that its comparison of the differences in
power production costs between PMAs and other utilities and the
reasons for the differences are essential. 

GAO discussed this report's contents with U.S.  Army Corps of
Engineers officials, including the Hydropower Coordinator and audit
liaison representatives.  They generally concurred with the contents
of this report and provided oral comments, which GAO has incorporated
into the final report, as appropriate.  The U.S.  Bureau of
Reclamation, Department of the Interior, provided unofficial
comments, which we incorporated into the final report, as
appropriate.  Official written comments were not received from the
Bureau in time for publication of this report. 


INTRODUCTION
============================================================ Chapter 1

Federal power marketing administrations (PMAs) are part of the
Department of Energy (DOE).  The five PMAs sell electric power within
34 states--to all states except those in the Northeast and upper
Midwest.  They sold about 3 percent of the nation's electric power
output in 1994.  Almost all of it is hydroelectric power generated by
multiple-purpose dams built and operated by other federal agencies. 
The Chairman, Subcommittee on Water and Power Resources, House
Committee on Resources, and the Ranking Minority Member, House
Committee on Resources, asked us to review several issues relating to
three of these PMAs-- Southeastern, Southwestern, and Western.  The
primary focus of our review was to determine whether all
power-related costs incurred through September 30, 1995, have been
recovered through the PMAs' electricity rates; whether the financing
for power-related capital projects is subsidized by the federal
government and, if so, to what extent; and how PMAs differ from
nonfederal utilities and the impact of these differences on power
production costs.  In addition, we were asked to provide information
on Federal Energy Regulatory Commission (FERC) oversight of the PMAs. 


   PMAS MARKET POWER GENERATED BY
   OTHER AGENCIES
---------------------------------------------------------- Chapter 1:1

Nationwide, there are five PMAs--the three on which this report is
focused, plus the Alaska Power Administration and the Bonneville
Power Administration.\1 Established between 1937 and 1977,\2 PMAs
sell electricity primarily on a wholesale basis with the legislated
goal of encouraging widespread use of power at the lowest possible
cost to consumers consistent with sound business principles.  By law,
they are required to give priority in the sale of federal power to
public power entities, such as public utility districts,
municipalities, and customer-owned cooperatives.  These customers are
referred to as "preference customers." PMAs helped make electricity
available for the first time to many consumers who lived in rural
areas. 

PMAs generally control and operate power transmission facilities, but
do not control or operate the facilities that actually generate
electric power.\3 These power generating facilities are controlled by
other federal agencies--most often by the Department of the
Interior's Bureau of Reclamation (Bureau) or the Department of the
Army Corps of Engineers (Corps).  The dams at which the power
generating facilities are located also serve a variety of nonpower
purposes, including flood control, irrigation, navigation, and
recreation.  The project must be operated in a way that balances all
of these uses--and, in many instances, power is not the primary use. 
Responsibility for operating the facilities to serve all of these
multiple functions rests with the Corps and the Bureau, which are
called the "operating agencies."


--------------------
\1 See Bonneville Power Administration:  Borrowing Practices and
Financial Condition (GAO/AIMD-94-67BR, April 19, 1994). 

\2 In 1977, the DOE Organization Act established the Western Area
Power Administration and transferred power marketing responsibilities
and transmission assets previously managed by the Bureau of
Reclamation to Western.  The act also transferred the other four PMAs
from the Department of the Interior to DOE. 

\3 The Alaska Power Administration, which controls and operates two
projects, is the one exception.  Alaska's two projects are not
multipurpose; they are operated to serve power needs only. 
Legislation has been enacted to sell the Alaska Power Administration
to nonfederal entities. 


   POWER-RELATED APPROPRIATIONS TO
   PMAS AND TO OPERATING AGENCIES
   MUST BE RECOVERED THROUGH RATES
---------------------------------------------------------- Chapter 1:2

Unlike most other federal agencies, PMAs are required by law to
recover through rates funds appropriated for power-related costs. 
Funding for the three PMAs is generally through the annual
appropriations process.\4 The PMAs receive annual appropriations and
make both capital expenditures, such as for PMA-controlled
transmission facilities, and operating and maintenance (O&M)
expenditures.  PMAs generally pay for these expenditures by
requesting Treasury to cut checks on their respective appropriation
accounts.  The operating agencies also receive appropriations.  The
operating agencies allocate the portions of those appropriations that
are used to fund power-related capital and O&M expenses to the PMAs
for recovery from power rates. 

The allocated portion includes all capital costs and O&M expenses
that are solely related to the generation of power.  In addition, a
portion of the operating agency's "joint costs" are allocated to the
PMAs.  These are capital costs and O&M expenses related not only to
power production but to the dam's other purposes.  The operating
agencies allocate the amount of joint costs that are power-related by
applying a percentage established for each multiple-purpose project. 

PMAs recover these appropriations through revenues generated from
power sales.  The Reclamation Project Act of 1939 and the Flood
Control Act of 1944 require PMAs to set power rates at levels that
are forecasted as adequate to recover costs.  The Reclamation Project
Act of 1939 requires that rates for electric power be adequate to
recover the power-related share of construction costs, to include
interest charged at a rate of not less than 3 percent.  The act also
requires recovery of annual O&M costs and "other fixed charges as the
Secretary deems proper." The Flood Control Act of 1944 requires that
rates for electric power be adequate to recover the cost of
"producing and transmitting such electric energy." Power-related
capital costs are to be recovered "over a reasonable period of
years."

These legislative provisions have been implemented by the Department
of Energy in DOE Order RA 6120.2 (September 20, 1979, as revised on
October 1, 1983).  This order specifies that the total revenues of
any project administered by a PMA must be sufficient to recover O&M
costs in the year incurred, to recover federal investment in
generation and transmission facilities within a 50-year period, and
to recover capital costs allocated to completed Bureau of Reclamation
irrigation facilities that are beyond the capability of irrigators to
repay (also called "irrigation assistance").  Under the order,
capital investments have a longer recovery period than O&M costs. 
PMAs are generally required to recover, without interest,
appropriations used to fund O&M costs in the same year that the
expenses are incurred.  In contrast, the PMAs are required to recover
appropriations that fund capital investments (which we refer to as
appropriated debt\5 ), with interest, over a specified repayment
period.  The recovery period is generally 50 years for assets used to
generate power and 35 to 45 years for assets used to transmit power. 

The order specifies that the adequacy of power revenues be tested by
the preparation of an annual study, known as a "power system
repayment study," which is submitted by the PMAs for approval to the
Secretary of Energy.  This study forecasts power-related capital and
O&M costs that the PMAs will be required to recover in the future. 
It also forecasts revenues expected to be forthcoming under current
rates.  If the study projects that revenues will not be adequate to
recover power system costs over the remainder of the repayment
period, rates may be increased or other cost recovery actions may be
taken. 

During the year, PMAs generate revenues based on the rates they have
established in accordance with the power repayment studies.  The
three PMAs bill customers for power sales.  Southeastern's and
Southwestern's customers generally make payments directly to a U.S. 
Department of Treasury "lock box" at a bank.  The bank processes the
account payments and transfers the cash to Treasury's General Fund,
where it is categorized as miscellaneous receipts.  To finance their
operations, Southeastern and Southwestern request Treasury to cut
checks on their respective appropriations accounts. 

Western and its customers deposit collections directly to Treasury's
"lock box" or federal reserve bank and then the receipts are posted
to various Treasury accounts.  Western either seeks annual
appropriations from these accounts to finance its operations, or for
certain accounts has the legal authority to spend funds without
further appropriations.  Those Treasury accounts include the
Reclamation Fund; Colorado River Dam Fund; Boulder Canyon Project
Fund; Falcon and Amistad Operating and Maintenance Fund; Central
Valley Project Restoration Fund; Lower Colorado River Basin
Development Fund; Upper Colorado River Basin Fund; and Colorado River
Basins Power Marketing Fund.  In this report, we refer to the
recovery from revenues of power-related operating and maintenance
appropriations and capital construction costs as a "repayment" or
"payment" to Treasury, even though in most cases the PMAs do not
write a check or otherwise transfer funds to Treasury. 

Ideally, over the course of a year, collections received by Treasury
will offset, or "repay," amounts appropriated to the PMAs and
operating agencies for O&M expenses, as well as an amortized amount
of capital construction costs.  The PMAs, pursuant to the DOE Order,
monitor expenses and revenues to ensure that power rates are
sufficient to generate revenue to recover expenses.  The DOE Order
prescribes the sequence in which PMAs are to offset expenses with
revenues as follows:  (1) operations and maintenance, (2) purchased
and exchanged power, (3) transmission services, and (4) interest. 
The remaining revenues are to be applied to the balance due on any
payments of annual expenses that have been deferred (these are called
"deferred payments," which the Order requires be repaid with
interest) and then toward the repayment of capital investments.  The
Order also covers other subjects, including priority of capital cost
repayment, interest rate calculation, and other PMA ratemaking and
accounting criteria. 


--------------------
\4 The Fort Peck Project, Colorado River Storage Project, and Central
Arizona Project have been legislatively authorized to use revolving
funds to finance some types of expenditures.  In addition, some
projects use nonfederal (third-party) financing as a supplemental
funding source, as discussed in chapter 4. 

\5 We call this appropriated debt because PMAs are required to repay
appropriations used for capital investments, with interest.  However,
these reimbursable appropriations are not technically considered
lending by the Treasury


   ROLE OF SOUTHEASTERN,
   SOUTHWESTERN, AND WESTERN AREA
   POWER ADMINISTRATIONS
---------------------------------------------------------- Chapter 1:3

Collectively, Southeastern, Southwestern, and Western Area Power
Administrations market power in 30 states.  (See figure 1.1.) In
fiscal year 1995, they had total power sales of almost $1 billion. 
The power they sell is produced at 102 power plants built and run
primarily by the Corps of Engineers or the Bureau of Reclamation. 

   Figure 1.1:  Service Areas for
   Southeastern, Southwestern, and
   Western

   (See figure in printed
   edition.)

   Source:  Developed by GAO from
   data provided by the PMAs.

   (See figure in printed
   edition.)

The three PMAs differ substantially in size and revenue.  (See table
1.1.) Western is the largest, accounting for more than four times the
revenue of either Southeastern or Southwestern.  Southwestern and
Western have their own transmission facilities, while Southeastern
relies entirely on the transmission services of other utilities. 



                               Table 1.1
                
                    Characteristics of Southeastern,
                       Southwestern, and Western

                                                                Fiscal
                                                                  year
                                                  Miles of        1995
                                   Number of                  revenues
                        Megawatt       power  transmission         (in
PMA                     capacity      plants         lines   millions)
--------------------  ----------  ----------  ------------  ----------
Southeastern               3,093          23             0        $159
Southwestern               2,051          24         1,380         114
Western                   10,581          55        16,760         713
----------------------------------------------------------------------
Source:  Derived by GAO from the PMAs' audited financial statements
and other PMA data for fiscal year 1995. 

Collectively, the three PMAs are responsible for repaying about $5.4
billion of appropriated debt.  (See table 1.2.) For 1995, the
weighted average interest rate on this outstanding debt was 4.9
percent.  (See chapter 3 for a more detailed discussion of
appropriated debt balances and weighted average interest rates.)



                               Table 1.2
                
                 Appropriated Debt and Weighted Average
                             Interest Rates

                                                              Weighted
                                          Appropriated         average
                                                  debt   interest rate
                                           as of 9/30/             for
                                                    95     fiscal year
PMA                                      (in millions)            1995
--------------------------------------  --------------  --------------
Southeastern                                    $1,491            4.4%
Southwestern                                       686           2.9 %
Western                                        3,184\a           5.5 %
======================================================================
Total                                           $5,361            4.9%
----------------------------------------------------------------------
\a Excludes $1.5 billion of irrigation debt stemming from capital
costs related to completed irrigation facilities, for which no
interest is charged.  These irrigation costs are discussed in chapter
3.  Includes Western's deferred payments. 

Source:  The PMAs' audited financial statements for fiscal year 1995
or material developed by GAO from other data provided by the PMAs. 

Additional specific information about each PMA follows. 

Southeastern.  The Southeastern Power Administration was created in
1950 to market federal power on a wholesale basis.  The 23
hydroelectric power plants from which Southeastern markets power are
all operated by the Corps.  About half of the plants (with more than
60 percent of the generating capacity) have been added since 1960. 
In 1995, Southeastern marketed power to 296 customers.  In all, it
sold about 6.8 billion kilowatthours (kWh)\6 of energy.  The
percentage of cost allocated to power by the Corps averages about 69
percent and ranges by facility from about 45 percent to about 81
percent.  Because it has no transmission lines of its own, it has no
transmission-related investment costs to recover. 

Southwestern.  The Southwestern Power Administration was created in
1943.  The 24 hydroelectric power plants from which Southwestern
markets wholesale\7 federal power are all operated by the Corps. 
Slightly less than two-thirds of the plants (and 56 percent of the
capacity) have been added since 1960.  In 1995, Southwestern marketed
power to 95 customers, selling about 7.7 billion kWh of energy.  The
percentage of cost allocated to power by the Corps averages about 35
percent and ranges by facility from about 21 percent to about 68
percent.  Southwestern's investment in transmission facilities as of
September 30, 1995, was about $126 million. 

Western.  The Western Area Power Administration was created in 1977. 
The establishing legislation transferred power marketing
responsibilities and transmission assets previously managed by the
Bureau of Reclamation to Western.  Western markets power, on a
wholesale\8 basis, from 55 hydroelectric power plants.  The Bureau
operates 45 plants, the Corps operates 6, and the remaining 4 are
operated by three other organizations.\9 Western also markets the
federal government's share of electricity generated by the coal-fired
Navajo Generating Station in Arizona.  In 1995, Western marketed
power to 546 customers, selling about 32.8 billion kilowatthours of
energy.  The percentage of cost allocated to power by the operating
agencies for three large projects that Western is responsible for
averaged about 50 percent.  These three projects accounted for about
83 percent of Western's 1995 revenues.  The individual cost
allocations for the three projects were 21 percent, 46 percent, and
84 percent.\10 Western's investment in transmission facilities as of
September 30, 1995, was about $2.1 billion. 


--------------------
\6 A kilowatthour is 1,000 watt hours.  A watt hour is equal to 1
watt of power applied for 1 hour. 

\7 A small percentage of Southwestern sales are to end users. 

\8 A small percentage of Western sales are to end users. 

\9 Two plants are operated by the Department of State's International
Boundary and Water Commission.  The Provo Water User's Association
and the California Department of Water Resources each operate one
plant. 

\10 Extensive calculations would be required to determine the
percentage of cost allocated to power for all projects.  As such, we
limited our analysis to the three largest projects. 


   OVERSIGHT OF PMAS
---------------------------------------------------------- Chapter 1:4

Each PMA is led by an administrator, who is appointed by the
Secretary of Energy.  The administrator is authorized to make
decisions regarding PMA operations, subject to the supervision and
direction of the Secretary.  DOE oversight includes approving PMA
budgets as part of DOE's annual federal budget process, establishing
each PMA's personnel limit, and giving interim approval to rate
adjustments that the PMA recommends.  The PMA financial officers
typically participate in the determination of rates.\11 The final
approval of PMA rates is the responsibility of FERC.  Appendix VI
discusses FERC oversight in detail. 

The Department of Energy's Office of Inspector General has
programmatic oversight responsibility for the PMAs, as well as
oversight of the PMAs' financial accountability.\12

DOE Order RA 6120.2 calls for the PMAs to prepare annual reports
containing audited financial statements.  The Inspector General
retains Independent Public Accountants to perform annual audits of
these financial statements. 


--------------------
\11 Senior financial managers at Southeastern and Southwestern are
involved in rate-setting.  However, Western's Chief Financial Officer
is not involved. 

\12 In addition, the Department of the Interior's Office of the
Inspector General has oversight responsibility pertaining to the
Bureau of Reclamation, and the Department of Defense's Inspector
General has oversight responsibility pertaining to the Corps of
Engineers. 


   LEGISLATIVE CHANGES RESULT IN
   COMPETITIVE WHOLESALE
   ELECTRICITY MARKET
---------------------------------------------------------- Chapter 1:5

Increasing competition in the wholesale electricity market could have
a major impact on the PMAs.  Historically, investor-owned utilities
(IOUs) and other electricity providers have operated as regulated
monopolies.  IOUs typically are required to provide electric service
to all customers within their power service areas in exchange for
exclusive service territories.  To serve customers, utilities incur
costs for building new generating plants and operating the power
system.  Through electricity rate charges, IOUs generally recover all
costs incurred plus a regulated rate of return. 

Several key laws have resulted in an increasingly competitive
electricity market.  The Public Utilities Regulatory Policies Act of
1978 (PURPA) facilitated the creation of small (less than 80
megawatts of capacity) electricity generators that were exempt from
many federal and state regulations.  Called "nonutility generators"
or "independent power producers" (IPPs),\13 these entities typically
use new technologies, such as cogenerating plants\14 or natural
gas-fired generation units, to generate power.  The National
Independent Energy Producers\15 estimated that, at the end of 1995,
IPPs accounted for about 8 percent of the total generating capacity
in the United States. 

IPPs pose a direct competitive threat to PMAs, IOUs, and other
utilities, in part because they can build generation facilities near
large industrial or municipal customers and sell power to these
customers for a lower rate than the established utility.  In
addition, recent technological advances have significantly increased
the efficiency of natural gas-fired generation units.  The growth and
increased efficiency of IPPs have placed downward pressure on
wholesale electricity rates. 

The Energy Policy Act of 1992 promoted increased competition in the
electricity market.  The act encouraged additional wholesale
suppliers to enter the market and opened the transmission of
electricity by allowing wholesale electricity customers, such as
municipal distributors, to purchase electricity from any supplier,
even if that power must be transmitted over lines owned by another
utility--referred to as wheeling of power.  Fees are paid to the
transmitting utility for use of its system.  Under the act's
provisions, FERC can compel a utility to transmit electricity
generated by another utility into its service area for resale.  More
recently, FERC has issued a final rule implementing this provision of
the act.  DOE has directed the PMAs to comply with the intent of the
act and FERC's rule.  According to Western and Southwestern, they
have always operated with a policy of open access to their
transmission systems on a first-come, first-served capacity available
basis.  As a result of the increased competition, FERC expects
wholesale and retail electricity rates to drop.  Increased
competition may impact the PMAs' status as a low cost supplier. 


--------------------
\13 IPPs, which are firms that produce electric power to be sold at
wholesale rates, are not considered utilities because they do not
produce power for a service area and do not engage in transmitting or
distributing power. 

\14 The cogeneration of power involves the use of steam, waste heat,
or resultant energy from a commercial or industrial plant or process. 

\15 The National Independent Energy Producers is a trade association
representing many nonutility generators of electricity and IPPs. 


   OBJECTIVES, SCOPE, AND
   METHODOLOGY
---------------------------------------------------------- Chapter 1:6

The objectives of this report were to determine (1) whether all
power-related costs incurred through September 30, 1995, have been
recovered through the PMAs' electricity rates (chapter 2), (2)
whether the financing for power-related capital projects is
subsidized by the federal government and, if so, to what extent
(chapter 3), and (3) how PMAs differ from nonfederal utilities and
the impact of these differences on power production costs (chapter
4).  Additional information on our objectives, scope, and methodology
is in appendix I.  This appendix includes detailed explanations of
the calculations of various estimates used in the report, as well as
a list of the various organizations and groups we contacted. 

When appropriate, we used audited numbers from the PMAs' 1995, 1994,
and earlier annual reports.  We conducted our review from January
1996 through September 1996 in accordance with generally accepted
government auditing standards.  We requested written comments on a
draft of this report from the three PMAs, the Department of Energy,
and the operating agencies.  Only the PMAs provided written comments
in time for publication in this report.  These comments are evaluated
and reprinted in appendix II. 


RATES DO NOT RECOVER ALL
POWER-RELATED COSTS
============================================================ Chapter 2

Some costs related to producing and marketing federal hydropower are
not being recovered through power rates by the three PMAs.  We
identified five main power-related activities for which costs are not
fully recovered.  First, the three PMAs do not recover the full costs
to the federal government of providing Civil Service Retirement
System (CSRS) pensions and postretirement health benefits for current
PMA employees and operating agency employees engaged in producing and
marketing the power sold by the PMAs.  Second, there are construction
projects for which the three PMAs might not recover costs from power
customers.  Third, power-related construction and O&M expenses
assigned to incomplete irrigation facilities at Pick-Sloan will
likely not be recovered.  Fourth, certain costs for environmental
mitigation have been legislatively precluded from cost recovery. 
Finally, Western had unrecovered O&M and interest expenses as of
September 30, 1995, related to certain projects.  Taking into
consideration all these categories of unrecovered costs we
identified, we estimated that the amount of unrecovered costs for
fiscal year 1995 was about $83 million.  We estimated that the
cumulative amount of these unrecovered costs, as of September 30,
1995, could be as much as $1.8 billion.  It is important to note that
the PMAs are generally following applicable laws and regulations
regarding cost recovery. 


   RECOVERY OF SOME COSTS HAS NOT
   BEEN REQUIRED
---------------------------------------------------------- Chapter 2:1

The Reclamation Project Act of 1939 and the Flood Control Act of
1944, as discussed in chapter 1, generally require the recovery
through power rates of the costs of producing and marketing federal
hydropower.  However, these acts do not specify which costs are to be
recovered.  The Reclamation Project Act refers to the recovery of
"annual operation and maintenance" costs and "other fixed charges as
the Secretary deems proper." The Flood Control Act refers to the
recovery of the costs associated with producing and transmitting
electricity from federal power projects.  Neither act defines its
terminology. 

Recovery of power-related costs has been implemented by the Secretary
of Energy through DOE Order RA 6120.2.\1 The DOE order states that
all costs of operating and maintaining the power system, as well as
the costs of transmission, should be included in rates.  The order
does not define operating and maintenance costs.  Given the
flexibility this lack of specific guidance provides, the PMAs have
interpreted it to exclude certain costs from rates. 

To define the full costs associated with producing and marketing
federal hydropower, we referred to Office of Management and Budget
(OMB) Circular A-25, "User Fees," which provides guidance for federal
agencies to use in setting fees to recover the full costs of
providing goods and services.\2 DOE Order RA 6120.2 does not adopt
this guidance or otherwise refer to OMB Circular A-25.  Nevertheless,
the circular does offer a definition of full costs that is useful in
identifying power-related costs that the PMAs do not now recover
through power rates.  OMB Circular A-25 defines full costs as all
direct and indirect costs of providing the goods or service.  This
definition is consistent with that contained in federal accounting
standards recommended by the Federal Accounting Standards Advisory
Board (FASAB) and adopted by GAO, OMB, and Treasury.\3 The FASAB
standards define the full cost of an entity's output as ".  .  .  the
sum of (1) the costs of resources consumed by the segment that
directly or indirectly contribute to the output, and (2) the costs of
identifiable supporting services provided by other responsibility
segments within the reporting entity, and by other reporting
entities." Applying the definitions of "full cost" used in OMB
Circular A-25 and federal accounting standards indicates that the
full cost of the electricity sold by the PMAs would include all
direct and indirect costs incurred by the operating agencies to
produce the power, the PMAs to market and transmit the power, and any
other agencies to support the operating agencies and PMAs. 

Investor-owned and publicly-owned utilities generally must recover
the full cost of producing power through rates.  A discussion of
relevant private industry accounting and cost recovery practices is
in chapter 4. 

It is important to note that we did not assess the reasonableness of
the methodologies used in developing the operating agency cost
allocation formulas that are established for each project.  To more
fully assess whether PMA electricity rates include all power-related
costs would require an analysis of the reasonableness of these
allocations.  If the allocation formulas were not reasonable, it
could result in a substantial over- or under-allocation of costs by
the operating agencies to the PMAs. 


--------------------
\1 Although the office that wrote the order has been abolished and
the order has not been updated since October 1983, the three PMAs
still consider it to be DOE's most authoritative guidance on PMA
financial reporting and rate-setting. 

\2 OMB Circular A-25's purpose is to implement a law commonly known
as the User Fee Statute.  However, its guidance may be used by
agencies in setting fees authorized by other laws to the extent it
does not conflict with the requirements of those laws. 

\3 FASAB Statement of Federal Financial Accounting Standards (SFFAS)
no.  4, Managerial Cost Accounting Concepts and Standards for the
Federal Government, June 1995. 


   PENSION AND POSTRETIREMENT
   HEALTH BENEFITS ARE NOT FULLY
   RECOVERED
---------------------------------------------------------- Chapter 2:2

The three PMAs do not recover the full costs to the federal
government of providing postretirement health benefits and CSRS
pensions for current PMA employees and operating agency employees
engaged in producing and marketing the power sold by the PMAs.  The
employee and the employing agency both contribute annually toward the
costs of the future CSRS pension benefits.  Since the employee and
agency contributions toward CSRS pensions are less than the full cost
of providing the pension benefits, the federal government must, in
effect, make up the funding shortfall.  In addition, neither the
agency nor the employee pays the federal government's portion of
postretirement health benefits, which will eventually be paid by the
general fund of the Treasury.  For 1995 alone, these unrecovered
costs for the three PMAs were an estimated $16.4 million.\4 The
cumulative unrecovered CSRS pension and postretirement health benefit
costs for the three PMAs totaled an estimated $436 million as of
September 30, 1995.  According to Office of Personnel Management
(OPM) officials, pensions for employees covered by the Federal
Employees Retirement System (FERS) are fully funded each year and
cumulatively, so there are no relevant unrecovered costs.  See
appendix I for a discussion of our methodology for computing
unrecovered pension and postretirement benefit costs. 

As with all other federal agencies, the full cost of CSRS pension
benefits is not paid by the PMAs or the operating agencies.  As
required, CSRS employees and the agency each pay a fixed
percentage--7 percent--of the employee's salary to offset future
pension costs.  However, this combined contribution does not cover
the full cost of the employee's future pension benefits, which
amounted to more than 25 percent of salary as of September 30, 1995. 
Thus, the annual funding shortfall is more than 11 percent of every
CSRS employee's salary.\5 The annual funding shortfall associated
with pension benefits will be eliminated over time as CSRS employees
leave the government and are replaced with FERS employees, provided
that FERS pension benefits remain fully funded annually. 

The full cost of the federal government's portion of postretirement
health benefits (for both CSRS and FERS employees) is likewise not
paid by federal agencies, including the PMAs and operating agencies,
during the period of the beneficiaries' employment.  OPM estimates
that almost $2,000 per employee would need to have been contributed
in fiscal year 1995 to cover each employee's postretirement health
benefit costs earned.  However, no fund has been established to
accumulate assets to pay for these future benefits, which will
eventually be paid for by the federal government.  In contrast to the
situation regarding CSRS pensions, the annual funding shortfall
associated with postretirement health benefits will not be eliminated
as CSRS employees are replaced by FERS employees, since it is an
entirely separate benefit program. 

OMB Circular A-25 specifically includes all funded or unfunded
retirement costs not covered by employee contributions in its
definition of full cost.  In addition, beginning in fiscal year 1997,
Statement of Federal Financial Accounting Standards (SFFAS) no.  5\6

requires federal agencies to record the full cost of pension and
postretirement health benefits in annual financial statements. 
Private sector accounting standards have required similar reporting
for pensions\7 beginning in 1987 and postretirement health and other
benefits\8 beginning in 1993.  IOUs have adopted SFAS no.  87 and
SFAS no.  106 for accounting purposes and in most instances for
rate-setting. 


--------------------
\4 Our analyses covered pension and postretirement health benefits
for current employees only; the costs associated with retirees were
not considered because the actuarial information needed to do so was
not readily available from OPM. 

\5 Public Law 99-335, the statute which established FERS, requires
that when the budget authority in the retirement fund for CSRS is
exhausted, automatic annual appropriations will be made to amortize
the shortfall over 30 years.  For more detail on the funding status
of FERS and CSRS, see Public Pensions:  Summary of Federal Pension
Plan Data (GAO/AIMD-96-6, February 16, 1996). 

\6 Statement of Federal Financial Accounting Standards (SFFAS) no. 
5, Accounting for Liabilities of the Federal Government. 

\7 Statement of Financial Accounting Standards (SFAS) no.  87,
Employers' Accounting for Pensions. 

\8 Statement of Financial Accounting Standards (SFAS) no.  106,
Employers' Accounting for Post-retirement Benefits Other Than
Pensions. 


      ANNUAL AND CUMULATIVE
      UNRECOVERED COSTS
-------------------------------------------------------- Chapter 2:2.1

Based on our analysis of the estimated number of full-time equivalent
(FTE) positions involved in producing and marketing the power sold by
the three PMAs, and information provided by OPM, we estimated that
the fiscal year 1995 unrecovered pension and postretirement health
benefits totaled about $10.3 million and $6.1 million,
respectively.\9

For pensions, about $7.3 million of the unrecovered costs (70
percent) related to personnel involved in producing and marketing the
power sold by Western, while about $1.7 million (16 percent) and $1.4
million (14 percent) related to Southeastern and Southwestern,
respectively.  For postretirement health benefits, about $4.2 million
of the unrecovered costs (69 percent) related to Western, while about
$1.1 million (18 percent) and $786,000 (13 percent) related to
Southeastern and Southwestern, respectively.  These are the amounts
that would have been necessary to fully recover CSRS pensions and
postretirement health benefits earned in fiscal year 1995 for current
employees of the three PMAs and operating agency employees involved
in power production and marketing.  These costs, which are not
recovered by the PMAs through power rates, are shown in figure 2.1. 
More detailed information regarding these unrecovered costs can be
found in appendix III. 

Based on our analysis of estimated FTEs associated with producing and
marketing power and information provided by OPM, we estimated that
the cumulative unrecovered costs for pension and postretirement
health benefits as of September 30, 1995, are $355 million and $81
million, respectively.  For pensions, about $250 million of the
cumulative unrecovered costs (70 percent) related to personnel
involved in producing and marketing the power sold by Western, while
about $57 million (16 percent) and $48 million (14 percent) related
to Southeastern and Southwestern, respectively.  For postretirement
health benefits, about $56 million of the cumulative unrecovered
costs (69 percent) related to Western, while about $14 million (18
percent) and $10 million (13 percent) related to Southeastern and
Southwestern, respectively.  The cumulative unrecovered costs for
current employees are depicted in figure 2.2.  More detailed
information regarding the cumulative unrecovered costs can be found
in appendix III. 

   Figure 2.1:  Estimated 1995
   Unrecovered Pension and
   Postretirement Health Benefits

   (See figure in printed
   edition.)

Source:  GAO estimates based on information provided by the PMAs,
operating agencies, and OPM. 

   Figure 2.2:  Estimated
   Cumulative Unrecovered Pension
   and Postretirement Health
   Benefits as of September 30,
   1995

   (See figure in printed
   edition.)

Note:  Total column may not add due to rounding. 

Source:  GAO estimates based on information provided by the PMAs,
operating agencies, and OPM. 


--------------------
\9 The individual amounts attributable to the PMAs may not add to
totals due to rounding. 


   SOME PROJECT CONSTRUCTION AND
   INTEREST COSTS ARE NOT BEING
   RECOVERED
---------------------------------------------------------- Chapter 2:3

There are construction costs that the three PMAs might not recover
from power customers.  In two cases, the Richard B.  Russell and
Harry S.  Truman Projects, costs are not currently being recovered
because the power-generating projects have not operated as designed. 
In two other cases, the Washoe and Mead-Phoenix Projects, the tenuous
financial condition of the projects raises questions about whether
power costs will be recovered.  In another case, power-related costs
associated with a Western abandoned transmission line incurred before
1969 have not been included in rates and there is a chance that these
costs may never be recovered from power customers. 


      RUSSELL PROJECT
-------------------------------------------------------- Chapter 2:3.1

To date, about one-half of the cost of constructing the Richard B. 
Russell Project,\10

which is located on the Savannah River between Georgia and South
Carolina, has been excluded from Southeastern's rates to power
customers because the project has never operated as designed.  In
addition, interest associated with the pumping units is not paid to
Treasury each year.\11 Instead, interest--$25.6 million for fiscal
year 1995--is capitalized and added to the
construction-work-in-progress (CWIP) balance annually.  If the
project never operates as designed, it is uncertain whether the
federal government will be able to fully recover these construction
and capitalized interest costs. 

Positioned between two existing dams, the Russell Project was built
virtually exclusively for the generation of hydropower.  Ninety-nine
percent of the original construction costs and 93 percent of annual
O&M expenses associated with the Russell Project are tentatively
allocated to power.  The project, which enjoyed broad support from
electric utilities in North Carolina, South Carolina, and Georgia
because of its potential to generate low cost power, was authorized
by the Flood Control Act of 1966 and construction began in 1976. 

The Russell Project has four operational conventional generating
units that provide 300,000 kilowatts of capacity, and four
nonoperational pumping units 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 those units went into
the customers' rate base.  However, because of litigation over
excessive fish kills, the four pumping units, which were completed in
1992, have never been allowed to operate commercially.  As a result,
the costs associated with them have been left in a CWIP account,
where interest has been accruing, and have not been included in
rates.  Southeastern's financial statements show about $488 million
in CWIP as of September 30, 1995, all of which is for construction
costs and capitalized interest related to the Russell Project.  Of
the $488 million related to Russell, an estimated $338 million was
for construction costs and $150 million for capitalized interest. 

Southeastern continues to classify as CWIP the $488 million of costs
related to Russell's pumping units, even though construction on those
units was completed in 1992 and associated litigation and
environmental testing have been ongoing since May 1988.  According to
its fiscal year 1995 financial statements, Southeastern follows SFAS
no.  71, Accounting for the Effects of Certain Types of Regulation. 
In situations similar to Russell's, if the costs were deemed
allowable by the regulator, private entities following SFAS no.  71
would transfer the amount from CWIP to a regulatory asset account and
begin recovering costs.  Under DOE Order RA 6120.2 guidance, however,
Southeastern may not be required to recover the costs of Russell's
pumping units through rates as long as the units are nonoperational. 
Southeastern officials believe that the litigation over the pumping
units will be resolved in Southeastern's favor, the pumping units
will be allowed to operate commercially, and the costs associated
with them will be recovered through rates.  However, if the four
pumping units are never allowed to operate commercially, it is
unclear whether the costs associated with them--about $488 million as
of September 30, 1995--will be recovered through power rates. 


--------------------
\10 The Richard B.  Russell Project was originally named the Trotters
Shoals Dam. 

\11 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.  Then, the water can be
used to produce power during periods of high demand for electricity. 


      TRUMAN PROJECT
-------------------------------------------------------- Chapter 2:3.2

A similar situation exists at the Harry S.  Truman Dam and Reservoir,
which is located in the Osage River in Missouri.\12 Designed
originally for flood control, hydropower and recreation were later
added as authorized project purposes.  Construction of the Truman
Project began in October 1964, and it was placed in service (for
flood control and recreation) in November 1979.  The in-service dates
for hydropower generating units range from January 1980 to September
1982.  Total power-related construction costs were about $158 million
as of the end of fiscal year 1995. 

The Truman Project has six generating units, also designed to operate
as pumping units, which provide 160,000 kilowatts of capacity. 
However, because of excessive fish kills by the pumping units, the
Truman project has never been operated at its 160,000 kilowatt
capacity.  Instead, only 53,300 kilowatts have been declared to be in
commercial operation, and use of the pump-back facilities has never
been commercially implemented.  As a result, the Corps determined
that it would be inappropriate to recover through Southwestern's
power rates the costs associated with the units that have not been
used commercially.  The Corps prepared an interim cost allocation for
this project that accounted for the fact that the project was not
fully operational.  Southwestern petitioned FERC to have the cost of
the nonproducing portion of the assets deferred from inclusion in
power rates until it becomes fully operational.  FERC concurred as
part of its approval of Southwestern's 1989 power rates.  As a result
of FERC's decision, Southwestern has deferred the inclusion of the
estimated amount of the costs associated with the nonoperational
units in Southwestern's reimbursable share of the project's costs. 
Thus, $31 million, which consists of capital construction costs and
capitalized interest, has been deferred from recovery through power
rates, reducing the total to be repaid from $158 million to $127
million.\13 This deferral is accomplished through an adjustment to
Southwestern's appropriated debt each year.  According to
Southwestern officials, the $31 million adjustment is not a permanent
elimination of these costs from Southwestern's appropriated debt;
these costs will be included in rates if the Harry S.  Truman
facility operates as designed. 

Through 1994 the Corps calculated the interest expense associated
with hydroelectric projects related to Southwestern.  Interest
expense was based on the entire power-related construction costs of
these projects.  Southwestern was therefore paying interest on the
$31 million Truman deferral. 

Beginning in fiscal year 1995, Southwestern and the other PMAs began
calculating the power-related interest expense on the operating
agency projects.  In 1995, Southwestern's calculation of interest
expense for the Truman project excluded interest associated with the
$31 million Truman deferral.  About $930,000 in interest associated
with the Truman deferral was therefore not paid and was excluded from
Southwestern's rates.  Southwestern officials have acknowledged the
error and said that the 1995 underpayment of interest will be
corrected in fiscal year 1996. 


--------------------
\12 The Harry S.  Truman Project was originally named the Kaysinger
Bluff Dam and Reservoir.  Public Law 92-267 changed the name of the
project to the Harry S.  Truman Dam and Reservoir on May 26, 1970. 

\13 According to Southwestern officials, the deferral does not affect
O&M costs, since all power-related O&M expenses are paid annually. 


      WASHOE PROJECT
-------------------------------------------------------- Chapter 2:3.3

The Washoe Project (Stampede Dam) is not generating sufficient
revenue to cover annual power-related O&M expenses and interest and
repay the federal investment.  The 3,650 kilowatt power plant for the
Stampede Dam was completed in 1987, and power sales began in 1988. 
Since the project began producing power, it has only generated
sufficient revenue to cover a portion of its annual O&M expenses and
has been unable to make any annual interest payments.  In addition,
the project has not generated enough revenue to repay any of the
project's appropriated debt.  Since 1988, the project has deferred
about $3.9 million in O&M and interest expense payments.  As of
September 30, 1995, the outstanding unpaid federal investment in the
project was $8.9 million. 

According to Western, the project has not been able to recover the
costs of producing power because the project:  (1) has construction
costs that are high in relation to other utilities, (2) has not been
able to find customers to purchase the power at a rate that would
recover the full cost of producing the power, (3) began producing
power in the first year of a 7-year drought, and (4) prior to 1992,
lacked the transmission service to wheel power to customers
interested in buying the power.  Western officials project that a
permanent rate increase of almost 500 percent would be necessary to
recover the annual costs.  In January 1996, Western projected that it
would have to sell its Washoe power at a rate of at least 11 cents
per kilowatthour (kWh) to cover annual O&M expenses (excluding
depreciation), interest charges, and debt repayments; however, in
fiscal year 1995, the project was selling power at about 2 cents per
kilowatthour.  According to Western's fiscal year 1995 annual report: 
"Based on current conditions, it is unlikely the project will be able
to generate sufficient revenues to repay the Federal investment." For
the same reasons, we believe that the Washoe Project is unlikely to
generate sufficient revenue to repay all O&M and interest expenses. 

During fiscal year 1994, Western negotiated a contract to sell some
Washoe power to the U.S.  Fish and Wildlife Service (F&WS).  The
project's authorizing legislation specifies that the cost of
facilities for the development of the fish and wildlife resources of
the project area, including the O&M costs, shall be nonreimbursable. 
Western classified the cost of power sold to F&WS as nonreimbursable,
thereby reducing the amount of construction and O&M costs that must
be repaid to Treasury by the Washoe Project.  Western believes the
project can become more financially viable by reclassifying a portion
of the project's costs as nonreimbursable.  However, we believe this
action just shifts the responsibility for recovering the project's
costs from the ratepayers to the federal government, and does not
reduce the actual costs of producing the power.  Therefore, we
believe this action does not significantly improve the prospects of
the project being able to generate sufficient revenue to cover all
power-related capital costs or O&M and interest expenses. 


      WESTERN'S MEAD-PHOENIX
      TRANSMISSION LINE
-------------------------------------------------------- Chapter 2:3.4

Another project with questionable financial viability is the
Mead-Phoenix Transmission Line,\14 a recent addition to the Pacific
Northwest-Pacific Southwest Intertie Project intended to increase
power transmission capability between the Pacific Northwest and
Pacific Southwest.  This transmission project was a joint venture
between Western and 13 other participants and began operation in
April 1996.  Western's share of the total project's costs is about 34
percent.  According to Western officials, Western's portion of the
cost of the project, including capitalized interest, is expected to
be about $94.1 million.  Western officials said that, in 1990 and
1993, prospective customers of the Mead-Phoenix Line indicated that
their demand for power from the line significantly exceeded Western's
proposed share of capacity.  However, anticipated demand for power
from the line later dropped precipitously, and it is unclear whether
Western will be able to successfully market its entire transmission
capacity.  A Western official told us that during its first few
months of operation in 1996, the project has not generated sufficient
revenues to cover all O&M and interest expenses.  However, Western is
confident that sufficient revenues will be raised to recover annual
O&M and interest expenses. 

In recent testimony before the Subcommittee on Water and Power
Resources, House Committee on Resources,\15 Western's Administrator
said that it is aggressively marketing the remainder of the line's
capacity.  The Administrator indicated that if the project does not
achieve the level of sales assumed in developing the transmission
charges, Western will initiate a new rate process to ensure the
recovery of project costs.  If Western is unable to find customers
for all of its capacity, it is uncertain whether market forces will
allow it to increase its rates enough to generate sufficient revenue
to recover annual O&M and interest expenses or appropriated debt. 


--------------------
\14 The Mead-Phoenix Transmission Line is a recent addition to the
Intertie Project.  Upon completion, the Mead-Phoenix Line, in
conjunction with the Mead-Adelanto Line, will provide additional
power transmission capability between central Arizona, southern
Nevada, and southern California.  The Mead-Phoenix Line consists of
256 miles of 500-kV transmission line that runs from Phoenix,
Arizona, through Mead Substation near Boulder City, Nevada, and on to
Marketplace switching station, also in southern Nevada.  Our
discussion of financial viability relates only to Western's portion
of the Mead-Phoenix addition. 

\15 Western Area Power Administration (WAPA) Construction and
Maintenance Activities and Bureau of Reclamation Power Facilities
Management:  Hearing Before the Subcommittee on Water and Power
Resources, House Committee on Resources, 104th Cong., 2nd Sess. 
(March 19, 1996). 


      WESTERN'S ABANDONED
      TRANSMISSION LINE
-------------------------------------------------------- Chapter 2:3.5

Another example of an unrecovered power-related cost is an abandoned
transmission line that has incurred costs of about $14.5 million,
which Western has not included in power rates.  According to the
Bureau, the transmission line, which was planned to be the direct
current portion of the Pacific Northwest-Pacific Southwest Intertie
Project, was abandoned because of sporadic funding.  Because the
project has not provided any benefits to project customers, the
ratepayers recently requested that Western seek authority through the
budget cycle to have about $11.1 million of the cost of the abandoned
transmission line declared nonreimbursable.  If Western was granted
such authority, the power customers would not be required to recover
these costs through rates.  However, Western recently asserted that
it (1) does not plan to request authority to declare any of the costs
of this project as nonreimbursable and (2) plans to include the costs
of the abandoned transmission line in its power repayment study for
recovery. 

In addition to not repaying the construction costs, Western has not
paid the federal government any interest on this investment since
construction began on the project in 1965.  In fiscal year 1995, if
Western had paid interest at the rate that applied when construction
began--3 percent--it would have paid about $435,000 in interest on
the $14.5 million.  We estimate that if Western had begun repaying
the annual interest expense on the project costs when construction
was discontinued in 1969, it would have paid the federal government
about $6.4 million in annual interest payments over the 26-year
period from 1969 to 1996.  The potential unrecovered costs as of the
end of fiscal year 1995 are about $20.9 million. 

Because the cost of the abandoned transmission line has not been
included in rates since construction was discontinued over 26 years
ago, we believe doubt exists about whether these costs will ever be
included in rates.  However, if these costs are ever taken into
rates, it is not clear whether interest will be recovered from the
time construction was discontinued in 1969 through when the costs are
included in rates.  It is also unclear whether the 50-year repayment
period will begin in 1969 or when the costs are actually included in
the power repayment study.  In addition, Western did not disclose
which rate-setting system would absorb these costs.  Western
officials were unable to clarify these issues.  The cost to the
federal government of Western's decision to delay resolution of cost
recovery for the abandoned transmission line will depend on how it
decides to address these issues. 


   COSTS ASSIGNED TO INCOMPLETE
   IRRIGATION FACILITIES WILL
   LIKELY NOT BE RECOVERED
---------------------------------------------------------- Chapter 2:4

As of September 30, 1994, about $454 million of the federal
investment in the capital costs for hydropower facilities and water
storage reservoirs of the Pick-Sloan Missouri Basin Program
(Pick-Sloan) had been allocated to authorized irrigation facilities
that are incomplete and infeasible.  Western is currently selling
electricity to its power customers that would have been used by the
irrigators had the irrigation facilities been completed.  If these
costs had been allocated based on the actual use of the hydropower
facilities and water storage reservoirs, the costs would have been
allocated primarily to power and repaid through electricity rate
charges within 50 years, with interest. 

If all of the irrigation facilities were to be completed as
originally planned, the above capital costs would be repaid without
interest primarily by power customers.\16 However, since all but one
of these irrigation facilities are not expected to be completed, the
capital costs assigned to these facilities will not be repaid unless
Congress approves a change in the cost allocation methodology used to
distribute costs to the various program purposes, or deauthorizes the
incomplete irrigation facilities.  However, any changes between the
program's power and irrigation purposes may also necessitate
reviewing other aspects of the agreements--specifically, the
agreements involving areas that accepted permanent flooding from dams
in anticipation of the construction of irrigation projects that are
now not likely to be constructed. 

In addition, interest is not being paid on the $454 million.  Using
the 3 percent interest rate in effect for power projects when
construction began, we estimate that lost interest payments to
Treasury amounted to about $13.6 million for fiscal year 1995. 

The federal investment in the Pick-Sloan Program will continue to
increase because of renovations and replacements.  The capital costs
assigned to the incomplete irrigation facilities will also continue
to increase because of the cost allocation methodology, which is
based on original agreements reached decades ago that anticipated
that all irrigation facilities would be completed as planned.  For
example, in our May 1996 testimony,\17 we noted that the capital
costs assigned to irrigation facilities increased about $37 million
between fiscal year 1987 and fiscal year 1994, an average annual
increase of nearly $5 million.  Therefore, unless Congress approves a
change in the cost allocation methodology used to assign capital
costs to the various program purposes, ongoing power-related capital
costs will continue to be assigned to the incomplete irrigation
facilities and will likely not be recovered through rates. 

Annual O&M expenses that otherwise would have been allocated to power
and repaid from electricity rates have also been allocated to the
incomplete irrigation facilities.  Since 1987, Western has adjusted
the Corps' allocated annual O&M expenses because the two agencies
interpret specific legislation\18 differently.  As of September 30,
1995, about $13.7 million ($15.3 million in constant 1995 dollars) of
the Corps' power-related O&M expenses had been allocated to
incomplete irrigation facilities.  The annual adjustments have ranged
from a low of $1.1 million in fiscal year 1987 to a high of $2.1
million in fiscal year 1995.  If these expenses had been allocated to
power, they would have been included in Western's annual O&M expenses
and recovered through electricity rates.\19


--------------------
\16 Reclamation law determines how the costs of constructing
reclamation projects are allocated and how repayment responsibilities
are assigned among the projects' beneficiaries.  Collectively, the
federal reclamation statutes that are generally applicable to all
projects and the statutes authorizing individual projects are
referred to as reclamation law.  In implementing reclamation law, the
Bureau is guided by its implementing regulations, administrative
decisions of the Secretary of the Interior, and applicable court
cases.  Reclamation law provides for Western to use its power
revenues to repay Treasury a certain 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 (irrigation assistance). 

\17 Federal Power:  Recovery of Federal Investment in Hydropower
Facilities in the Pick-Sloan Program (GAO/T-RCED-96-142, May 2,
1996). 

\18 The McGovern Amendment to the 1977 Department of Energy
Organization Act precludes any changes to the cost allocation
methodology used by the Pick-Sloan Program without prior
congressional approval.  The Corps changed from the "ultimate
development concept" (UDC) to the "current use" costs allocation
methodology to allocate its annual O&M expenses to the various dam
purposes.  Since this change occurred after the passage of the
McGovern Amendment and did not receive congressional approval,
Western concluded that the Corps should have continued to use the
ultimate development concept method to allocate O&M expenses. 
Western has adjusted the Corps' annual O&M expenses to reflect the
ultimate development concept methodology that was used prior to 1987
and has presented the adjusted costs in its financial statements. 

\19 In 1990, the Pick-Sloan Program did not generate sufficient
revenues to repay its O&M expenses.  The O&M expenses for this year
were recorded as interest bearing debt and repaid in fiscal year
1995. 


   CERTAIN ENVIRONMENTAL
   MITIGATION COSTS ARE
   LEGISLATIVELY EXEMPT FROM
   RECOVERY
---------------------------------------------------------- Chapter 2:5

The Central Valley Project's Shasta Dam and the Colorado River
Storage Project's Glen Canyon Dam have incurred power-related
environmental mitigation costs that are legislatively excluded from
Western's power rates.  For the Shasta Dam, these costs totaled $9.7
million and $5.4 million in 1995 and 1994, respectively.  For the
Glen Canyon Dam, these costs totaled $13.9 million and $12.5 million
in 1995 and 1994, respectively.  The total cumulative unrecovered
environmental costs for the two projects was about $134.3 million
($152.5 million in constant 1995 dollars) as of the end of fiscal
year 1995. 

Certain environmental costs incurred at the Shasta Dam were exempted
from recovery by the 1991 Energy and Water Development Appropriations
Act.  The act included a provision stating that any increase in
purchased power cost incurred by Western after January 1, 1986, that
resulted from bypass releases for temperature control purposes
related to preservation of fisheries in the Sacramento River, not be
allocated to power.  According to Western, the bypass releases at
Shasta will cease when construction of a Temperature Control Device
is completed.  Western expects this device to be in service by
December 1996. 

Similarly, certain costs of mitigating the environmental impact of
fluctuating river flows at the Glen Canyon Dam were exempted from
recovery by the Grand Canyon Protection Act of 1992.  The purpose of
the act was to "protect .  .  .  and improve the values for which
Grand Canyon National Park and Glen Canyon National Recreation Area
were established." The act states that certain costs of environmental
impact studies related to Glen Canyon Dam are not to be paid for by
power customers.  The act includes a provision that the above costs
could become the responsibility of the power customers under certain
circumstances.  According to Western, sufficient data does not exist
to determine whether the overall provisions of the act would result
in a future obligation by the power customers.  Western plans to
reflect any future obligations related to these costs in the period
in which such obligations become evident. 


   CERTAIN OPERATING AND
   MAINTENANCE AND INTEREST
   EXPENSES ARE NOT YET RECOVERED
   BY WESTERN
---------------------------------------------------------- Chapter 2:6

Since fiscal year 1975, Western has deferred O&M and/or interest
payments on 12 projects that are supposed to be repaid annually. 
Under DOE Order RA 6120.2, deferred O&M and interest payments are to
be repaid the following year, with interest, at DOE policy rates,\20

before repayment of appropriated debt.  In effect, the federal
government extends an interest bearing loan to the PMAs in the amount
of the deferred payments.  The balance of Western's deferred payments
outstanding at the end of fiscal year 1995 was about $196 million. 
This balance decreased from about $250 million at the end of fiscal
year 1994 as Western repaid about $54 million in fiscal year 1995.\21
The bulk of the balance outstanding--almost $131 million--was
associated with the Pick-Sloan Program.  The remaining balance was
associated with eight other projects.  According to Western, the
deferred payments have occurred primarily because of extended drought
conditions.  As a result of the deferred payments, many of the
projects' firm power rates have been raised by Western.  For example,
Western stated that the composite firm power rate at the Pick-Sloan
Program has increased approximately 75 percent since the start of
drought conditions in 1988.  Western attributes about half of the
increase to the drought and the increased interest expense associated
with the deferred payments and the failure to repay outstanding
appropriated debt.  Although Southeastern and Southwestern have
deferred O&M and interest expense payments, both had repaid the
amounts, with interest, prior to September 30, 1995. 

Because of the PMAs' reliance on hydropower to generate electricity,
the PMAs' annual revenue is unpredictable and varies from year to
year.  As a result, the DOE order that specifies the terms PMAs must
follow to repay their federal investment was designed with the
variable revenue characteristics of hydroelectric systems in mind. 
The DOE order allows the PMAs to vary the repayment of their federal
investments and miss interest and/or O&M expense payments in years
when revenue is not sufficient to cover these costs.  However, the
DOE regulations require the PMAs to record deferred annual payments
as liabilities\22 on their financial statements and to repay these
deferred payments plus interest in future years before any principal
payments are made on the outstanding federal investment. 

The amount and frequency of deferred payments over the last 20 years
have varied among the three PMAs.  Since fiscal year 1975, Western
has deferred either an annual O&M and/or interest expense payment in
one or more years for 12 of the 15 projects.  As of September 30,
1995, 9 of the 15 projects still had about $196 million in
outstanding debt related to deferred payments.  Western plans to
recover the majority of these costs over time.  More detailed
information about Western's deferred payments over the last 20 years
can be found in chapter 3 and appendix IV, and a discussion of FERC's
role in rate-setting can be found in appendix VI. 

According to Southeastern officials, severe drought conditions in the
1980s created poor water conditions and, as a result, insufficient
revenue to cover annual interest and O&M payments.  Southeastern had
also deferred payments in other years due to poor water conditions. 
Southwestern deferred interest payments in 1977 and O&M and interest
payments in 1981.  According to Southwestern officials, the payments
were deferred primarily because of poor water conditions.  Both
Southeastern and Southwestern had repaid all their deferred payments
as of the end of fiscal year 1995. 


--------------------
\20 For a description of DOE policy rates, see chapter 3. 

\21 The $54 million is a net amount.  Some projects paid all current
year expenses and also reduced their balances of outstanding deferred
payments, while other projects deferred current year payments
totaling about $765,000 in fiscal year 1995. 

\22 Western does not record a liability to recognize deferred
payments.  Instead, deferred payments are reflected as a reduction in
Accumulated Net Revenues on Western's Statements of Assets, Federal
Investment, and Liabilities (Balance Sheet).  Western's external
auditor has determined that this treatment of deferred payments by
Western satisfies the DOE regulation that requires a liability to be
recognized for deferred payments.  For rate-setting purposes, the
deferred payments are treated as debt. 


   SUMMARY OF UNRECOVERED
   POWER-RELATED COSTS
---------------------------------------------------------- Chapter 2:7

We estimate that, for the five main power-related activities
identified in this chapter, the annual unrecovered costs for the
three PMAs is about $83 million for fiscal year 1995.  In addition,
as of September 30, 1995, we estimate that total cumulative
unrecovered power costs could be as much as $1.8 billion.  Our
analysis of unrecovered power-related costs is shown in table 2.2. 



                               Table 2.2
                
                 Estimated Total Unrecovered Annual and
                Cumulative Power-related Costs as of and
                 for the Year Ending September 30, 1995

                         (Dollars in millions)

                                                  Annual -
Description                                           1995  Cumulative
----------------------------------------------  ----------  ----------
Pension and postretirement health benefits           $16.4      $436.0
Russell Project (pumping units)
 Capitalized interest for fiscal year 1995            25.6
 CWIP balance\a                                                  488.0
Truman Project                                         0.9        31.0
Washoe Project\b                                       ---         8.9
Abandoned Transmission Line
 Capital construction costs                                       14.5
 Unrecovered interest                                  0.4         6.4
Irrigation-related capital costs at Pick-           13.6\c     454.0\d
 Sloan
Deferred payments at Western                           0.8       195.7
Irrigation-related O&M at Pick-Sloan                   2.1      15.3\e
Environmental costs                                   23.6     152.5\e
======================================================================
Total                                                $83.4  $1,802.3\f
----------------------------------------------------------------------
\a Includes cumulative unrecovered principal and interest costs. 

\b Reflects the cumulative appropriated debt that might not be
recovered.  Annual deferred payments for O&M and interest expenses
are included in "Deferred payments at Western" line item. 

\c This amount represents unrecovered interest and was calculated
based on the $454 million. 

\d The $454 million is as of September 30, 1994, because fiscal year
1995 data were not available. 

\e These amounts are converted to constant 1995 dollars to be
comparable to the other cumulative dollars that are already reported
in fiscal year 1995 dollars. 

\f Amounts for Mead-Phoenix Transmission Line are not included in
this estimate because it did not become operational until fiscal year
1996.  However, the project's ability to recover costs in the future
is questionable. 

Source:  GAO estimates based on information provided by the PMAs,
operating agencies, and OPM. 


   AGENCY COMMENTS AND OUR
   EVALUATION
---------------------------------------------------------- Chapter 2:8

In commenting on a draft of this report, the PMAs stated that they
agree that there are some power-related costs that were not fully
recovered through rates.  However, they asserted that the objective
of our review was to specifically identify costs that were
"unrecoverable," which they defined as those that have not been and
will never be repaid to Treasury under current law and/or policy, as
opposed to "unrecovered," which they defined as those not repaid at a
point in time but that will be in the future.  While we recognize
there is a distinction between the two concepts, we believe that
"unrecoverable" costs are essentially a subset of "unrecovered"
costs.  Moreover, we disagree with the PMAs' assertion about the
objective of our review.  The objective, based on our agreements with
congressional requester staff, was to determine whether all
power-related costs incurred through September 30, 1995, had been
recovered through electricity rates.  Our objective was not to
distinguish between "unrecovered" and "unrecoverable" costs.  We have
clarified the discussion of our objective in the executive summary
and other relevant sections of the final report. 

In addition, the PMAs disagreed with certain of our characterizations
of unrecovered costs in the five main categories discussed in this
chapter.  These points, and our responses, are discussed below and in
appendix II. 


      CIVIL SERVICE PENSION AND
      POSTRETIREMENT HEALTH
      BENEFITS
-------------------------------------------------------- Chapter 2:8.1

The PMAs agreed that the full costs of these benefits are not
included in PMA power rates.  They suggested that we more fully
reflect the content of this chapter in our executive summary by
noting therein that the cost underrecovery associated with CSRS
pensions should go away over time as CSRS employees retire and the
federal workforce is comprised of employees covered by FERS, which is
fully funded annually.  In response, we added an explanatory
statement to the executive summary.  However, we also note in our
executive summary that the unrecovered costs associated with
postretirement health benefits will not be eliminated after the shift
from CSRS to FERS. 

In addition, the PMAs believe that they cannot deposit power revenues
into the Civil Service Retirement and Disability Fund (Fund) to pay
for unfunded retirement benefits, because doing so would violate
federal appropriations law by augmenting the annual appropriation
made to the Fund.  Our objective was not to address whether the PMAs
should or should not recover these costs; our objective was to
determine whether these costs were unrecovered.  Consequently, we did
not address whether it would be appropriate for the PMAs to deposit
power revenues directly into the Fund to pay for these costs.  We
agree that should the Congress decide that the PMAs should deposit
directly into the Fund an amount to cover these costs, the Congress
should enact legislation permitting a transfer of that amount into
the Fund.  Alternatively, the augmentation issue could be avoided by
depositing amounts recovered, like many other PMA ratepayer
collections, into the General Fund of the Treasury where the revenue
would be available to the Congress to appropriate into the Fund to
cover the full cost to the government of CSRS pensions.  Recovery of
postretirement health benefits could be handled the same way. 

The PMAs also believe that our reference to OMB Circular A-25 in this
chapter was improper, because the PMAs do not recover costs in
accordance with the Circular.  We agree that the PMAs do not follow
Circular A-25, and we note in this chapter that recovery of
power-related costs has been implemented through DOE Order RA 6120.2,
which does not adopt the guidance in Circular A-25 or otherwise refer
to it.  We do not state that the PMAs are required to follow Circular
A-25; instead, we use the Circular as criteria for defining all the
costs associated with producing and marketing federal hydropower. 
Developing such a definition of full costs was necessary before
assessing whether the PMAs were recovering all power-related costs
through rates, which was one of the objectives of our review. 


      CONSTRUCTION COSTS FOR
      NONOPERATIONAL PROJECTS
-------------------------------------------------------- Chapter 2:8.2

The PMAs believe that we inappropriately characterized the costs
associated with nonoperational projects, specifically Russell and
Truman.  They assert that we characterized those costs as not only
unrecovered but also likely never to be recovered.  That assertion is
not accurate.  Regarding the Russell Project, in our draft report we
state that, if the nonoperational pumping units are never allowed to
operate commercially, the costs associated with their construction
will likely not be recovered.  We do not state that it is likely that
the units will not be allowed to operate commercially.  We only point
out the fact that the units have been in CWIP for 20 years and
litigation has been ongoing since 1988.  We believe these facts
demonstrate that the ultimate operation of the Russell pumping units
is not a certainty.  Moreover, we specifically reiterate Southeastern
management's belief that the pumping units will be allowed to operate
commercially and that these costs will be recovered in the future. 
However, in response to the PMAs' concerns, we revised the final
report to state that it is unclear whether these costs will be
recovered if the project never operates to the capacity designed. 

Regarding the Truman Project, we state that, with FERC's concurrence,
certain costs associated with nonoperational pumping units have been
deferred from power rates.  We do not state that it is likely that
the costs will never be recovered.  We merely demonstrate that the
ultimate operation of these pumping units is not a certainty. 
Moreover, we specifically state Southwestern management's belief that
the costs will be recovered if the facilities become operational. 

The PMAs state that we should incorporate into the report the
similarity of Southeastern's handling of the Russell Project's cost
recovery to similar situations for other utilities governed by FERC
and state public utility commissions.  As discussed in chapter 4, we
agree that FERC and state public utility commissions disallow certain
costs and that shareholders of IOUs, not ratepayers, bear these
costs.  However, we do not believe that Southeastern's handling of
the Russell Project is similar to that of other utilities.  Compared
to other utilities, the relative dollar amount and the length of time
for the deferral of Russell costs from Southeastern's rates are
unique.  Note that construction of the Russell Project began in 1976
and the pumping units are still recorded as CWIP today.  Thus,
Southeastern has not recovered any costs for the nonoperational
units.  In contrast, IOUs attempt to recover costs immediately, even
in situations where the ultimate success of the project is still
uncertain. 

The PMAs state that an abandoned transmission line for Western's
Pacific Northwest-Southwest Intertie Project cannot be declared
nonreimbursable or unrecoverable because Western does not have direct
legislative authority to do so.  As a result, the PMAs assert that
Western will include the costs of the abandoned transmission line in
rates.  This position is contrary to that provided to us during our
review.  Previously we had not seen any indication that Western
planned to include these costs in rates, and all indications were
that the costs would be declared nonreimbursable.  As stated in this
chapter, transmission line construction was discontinued in 1969 and
the costs were still included in Western's financial statements at
September 30, 1995.  The costs associated with the abandoned line
have not been recovered, and no interest has been paid to the
Treasury.  We estimate that at September 30, 1995, the total
unrecovered costs for this abandoned transmission line are about
$20.9 million. 


      PROJECTS WITH QUESTIONABLE
      ABILITY TO RECOVER COSTS
-------------------------------------------------------- Chapter 2:8.3

The PMAs believe that our description of the economic viability of
two projects, Washoe and Mead-Phoenix, needs to be clarified. 
Specifically, the PMAs state that they are reluctant to conclude that
projects that are uneconomic today will remain so forever.  We agree
that project conditions can change over time and that projects
experiencing financial problems today, such as Mead-Phoenix, may not
face financial problems forever.  In addition, we believe that given
the increased competition in the wholesale electricity market and
wholesale electricity rates that are expected to fall, some projects
that are viable today may not be economic in the future.  Regarding
Washoe, we concur with Western's assessment in its 1995 annual report
that "Based on current conditions it is unlikely the project will be
able to generate sufficient revenues to repay the Federal
investment." In addition, we correctly state that the project has
been unable to recover all of its O&M and interest expenses and had
outstanding deferred payments of $3.9 million as of September 30,
1995.  Regarding Mead-Phoenix, we state that a Western official does
not expect the project, in its first few months of operation, to
generate sufficient revenue to recover all O&M and interest expenses. 
We believe this fact supports our statement that the project has
"questionable financial viability."


      SUBALLOCATED PICK-SLOAN
      POWER COSTS
-------------------------------------------------------- Chapter 2:8.4

The PMAs generally agreed with this section of the chapter, but
suggested that we add two points.  First, they suggested that more
emphasis be placed on the fact that the methodology for cost
allocations cannot be changed without congressional approval.  We
concur with this suggestion and have revised our report accordingly. 

Second, the PMAs suggested that our report include a statement from
our May 1996 testimony that noted that the Pick-Sloan Program
incorporates agreements reached decades ago and that any changes to
power and irrigation purposes may necessitate reviewing other aspects
of the agreements.  We have incorporated this statement into our
executive summary and chapter 2. 


FAVORABLE TERMS RESULT IN
SUBSIDIZED FINANCING
============================================================ Chapter 3

The three PMAs receive favorable terms in repaying the appropriated
debt that finances capital projects.  In addition, the interest rates
on outstanding appropriated debt are lower than the cost to the
federal government of providing this financing.  As a result, a
financing subsidy exists because the interest income earned by
Treasury on the appropriated debt is less than Treasury's related
interest expense.  We estimate that the financing subsidy for the
three PMAs for fiscal year 1995 was about $228 million. 
Cumulatively, this subsidy amounts to several billion dollars.  It is
important to note that the PMAs were generally following applicable
laws and regulations regarding the financing of capital projects. 


   PMAS' FINANCING COSTS ARE LOWER
   THAN THE GOVERNMENT'S COST OF
   PROVIDING THE FINANCING
---------------------------------------------------------- Chapter 3:1

The PMAs have accumulated substantial amounts of appropriated debt at
low interest rates.  This situation has resulted primarily because
the PMAs repay high interest rate debt first and because PMA
appropriated debt incurred prior to 1983 was generally at below
market interest rates. 


      PMAS HAVE SUBSTANTIAL DEBT
-------------------------------------------------------- Chapter 3:1.1

Historically, a large portion of capital construction projects have
been financed with appropriated debt.  The three PMAs are responsible
for repaying the appropriated debt, which amounted to about $5.4
billion as of September 30, 1995.  In addition, as of September 30,
1995, Western was responsible for repaying about $1.5 billion of
irrigation-related construction costs (which we refer to as
irrigation debt), which is discussed later in this chapter.  While
the total appropriated debt for the three PMAs has risen over the
last 5 years, it has not risen for all of the PMAs.  As shown in
table 3.1, the appropriated debt balances for Southwestern have
declined over the last 5 years.  Southeastern's appropriated debt has
remained relatively constant.  In contrast, Western's appropriated
debt has increased by $377 million for the same 5-year period. 
Western's increase is due primarily to capital spending for new or
replacement projects and deferred payments for several projects that
resulted in very little or no principal on debt being repaid. 



                               Table 3.1
                
                  PMAs' Total Appropriated Debt as of
                    September 30, 1991 Through 1995

                         (Dollars in millions)


PMA                               1991    1992    1993    1994    1995
------------------------------  ------  ------  ------  ------  ------
Southeastern                    $1,425  $1,442  $1,443  $1,467  $1,491
Southwestern                       769     750     721     712     686
Western\\a\                      2,807   2,911   3,017   3,145   3,184
======================================================================
Total                           $5,001  $5,103                  $5,361
                                                $5,181  $5,324
----------------------------------------------------------------------
\a Excludes Western's irrigation debt; includes deferred payments. 

Source:  Derived by GAO from PMA audited financial statements and
other data provided by the PMAs. 


      PMAS HAVE FLEXIBLE REPAYMENT
      TERMS
-------------------------------------------------------- Chapter 3:1.2

Because the power marketed by PMAs is generated at hydroelectric
dams, the amount of power available for them to sell is greatly
dependent on weather conditions.  During years in which precipitation
is high, reservoir levels are sufficient to generate large quantities
of electricity.  In drought years, however, reservoir levels are
reduced and there is less electricity generated and available for
sale by the PMAs. 

The Flood Control Act of 1944 provides that appropriated debt must be
repaid within "a reasonable period of years," but it does not specify
that any principal on outstanding debt be repaid in any particular
year.  The Department of Energy's (DOE) interpretation of this law,
Order RA 6120.2, specifies that, unless otherwise prescribed by law,
each federal dollar spent on a capital project is to be repaid with
interest within 50 years.  Shorter repayment periods are used for
replacements and transmission facilities.  DOE's Order RA 6120.2 also
requires that PMAs, to the extent possible, repay the highest
interest bearing appropriated debt first.\1

Appropriated debt carries a fixed interest rate with no ability of
Treasury to call\2 the debt.  Although PMAs are generally required to
pay off highest interest debt first, they cannot refinance the debt. 
Thus, Treasury bears the risk of increases in interest rates and
PMAs, to some degree, bear the risk of decreases in interest rates. 
Western, for example, has some appropriated debt that is at interest
rates above the current Treasury 30-year bond rate.  However, because
Western cannot refinance this debt and does not have sufficient cash
flow to pay it off, it must pay the above-market interest rates. 


--------------------
\1 Appropriated debt due in a given fiscal year must be paid first,
regardless of interest rate. 

\2 Call refers to the ability of the lender to require the borrower
to pay back the debt before its maturity date. 


      INTEREST RATES BEFORE 1983
      WERE LOWER THAN TREASURY'S
-------------------------------------------------------- Chapter 3:1.3

From the inception of the PMAs until 1983, the interest rates paid by
PMAs on appropriated debt were either established administratively or
by specific legislation authorizing and funding the dam construction. 
The interest rates specified in legislation were generally 2.5
percent to 3.125 percent.  Treasury borrowing rates were based on
market conditions. 

As shown in figure 3.1, when appropriated debt was incurred in the
1950s, the average Treasury interest rate and statutory rates were
about the same; however, beginning in the 1960s, the difference
between the interest rates paid on the PMAs' outstanding appropriated
debt and the average interest rate Treasury paid on its outstanding
bond portfolio in the same years started to grow.  Because repayment
terms on appropriated debt are up to 50 years, this pre-1983 below
market interest debt could remain outstanding for several more
decades. 

   Figure 3.1:  Average Interest
   Rates Paid by the PMAs on
   Appropriated Debt Compared to
   Rates Paid by Treasury on
   Outstanding Bond
   Portfolio--Fiscal Years 1952 to
   1995

   (See figure in printed
   edition.)

Note:  Western was created in 1977.  Interest rates shown before 1977
are for appropriated debt transferred from the Bureau to Western in
1977.  Percentages shown at right represent percentages for 1995. 

Sources:  Data on PMAs developed by GAO from data provided by PMAs;
Treasury interest rates:  Department of Treasury, summary information
related to the public debt of the United States. 

By 1985, the average interest rate on Treasury's outstanding bonds
had increased to about 11.02 percent, while the average interest rate
on the PMAs' outstanding appropriated debt was between 2.8 and 3.1
percent. 

Figure 3.1 also shows the large difference between PMAs in average
interest rates on outstanding appropriated debt and the impact of the
higher interest rates required after 1983.  As of September 30, 1995,
Southwestern's average interest rate on appropriated debt was 2.9
percent, compared to 4.4 percent for Southeastern and 5.5 percent for
Western.  Southwestern has had strong water years, and its cash flow
has allowed repayment of most new appropriated debt, while the low
interest debt remains unpaid.  According to Southwestern, part of the
reason for the strong cash flow is the inclusion in rates of a
provision for future capital replacements, which causes rates to be
10 percent higher than necessary to cover current expenses.  As of
September 30, 1995, only about $45 million of Southwestern's
outstanding appropriated debt of $686 million was financed at
interest rates above 3.125 percent. 

The weighted-average interest rate paid by Southeastern rose from
about 2.7 percent in the early 1980s to about 4.4 percent as of
September 30, 1995.  The increase in average interest rates reflects
Southeastern's inability, due to drought conditions and resulting low
revenues, to pay off all the appropriated debt associated with more
recent, higher interest rate additions to the power system.  In
addition, the 6.125 percent interest rate associated with the Russell
Project contributed to Southeastern's average interest rate increase. 
Western's average interest rate has risen due to increased market
interest appropriated debt resulting from post-1983 construction
projects.  In addition, according to Western, drought conditions have
been the primary reason O&M and interest expenses have been deferred. 
As a result, Western's cash flow has not been sufficient to pay off
higher interest appropriated debt. 


      CAPITAL FINANCING IS
      FEDERALLY SUBSIDIZED
-------------------------------------------------------- Chapter 3:1.4

The historically low interest rates and flexible repayment terms for
PMAs result in a financing subsidy because the interest rates paid by
the PMAs do not fully recover the federal government's cost of funds. 
(See figure 3.1.) To estimate the financing subsidy, we compared
Treasury's average interest rate on bonds outstanding, which was
about 9.1 percent for fiscal year 1995, to the interest rates on the
PMAs' debt as of the end of fiscal year 1995.  In this analysis, we
used the average interest rate on all Treasury bonds outstanding. 
The Treasury Bond portfolio includes components with various terms up
to 30 years.\3 Since Treasury does not match its borrowing with
individual program financing, the average interest rate on Treasury's
entire bond portfolio best reflects its cost of funds.  See appendix
I for a discussion of our methodology for calculating this financing
subsidy. 

As shown in table 3.2, the estimated financing subsidy using
Treasury's average interest rate on bonds outstanding for fiscal year
1995 was about $228 million. 



                               Table 3.2
                
                 Estimated PMA Financing Subsidy, 1995

                        Outstandin
                                 g
                        appropriat    Weighted    Treasury   Financing
                           ed debt     average     average     subsidy
                          (dollars    interest    interest    (dollars
                                in      rate\a      rate\b          in
PMA                      millions)   (percent)   (percent)   millions)
----------------------  ----------  ----------  ----------  ----------
Southeastern                $1,491         4.4         9.1         $70
Southwestern                   686         2.9         9.1          43
Western\c                    3,184         5.5         9.1         115
======================================================================
Totals                      $5,361         4.9         9.1        $228
----------------------------------------------------------------------
\a We calculated the weighted average interest rate for the PMAs by
dividing interest costs by average appropriated debt outstanding for
1995. 

\b The 9.1 percent interest rate is the average interest rate paid on
Treasury's outstanding bond portfolio at the end of fiscal year 1995. 

\c Excludes Western's irrigation debt; includes deferred payments. 

Sources:  PMA audited financial statements and other data, and
Department of Treasury summary information related to the public debt
of the United States. 

The above estimate shows that Treasury is currently paying a higher
interest rate on its outstanding debt than PMAs are paying on their
outstanding appropriated debt.  Over the next several decades, as the
pre-1983 appropriated debt is repaid, the PMAs' financing subsidy
should decrease.  However, as shown in figure 3.1, despite new
borrowing at market rates, the PMAs' ability to repay high interest
debt first has been a factor and likely will continue to contribute
to PMA average interest rates being below the effective Treasury
average interest rate.  In addition, Treasury's inflexible borrowing
practices contribute to the magnitude of the financing subsidy. 
Treasury's general inability to refinance or prepay the federal
government's outstanding debt in times of falling or low interest
rates is part of the reason for its relatively high 9.1 percent
average cost of funds for fiscal year 1995. 

We estimate that, cumulatively, the financing subsidy for the three
PMAs is several billion dollars.  This estimate is based on the
spread between Treasury and PMA interest rates shown in figure 3.1,
which, to varying degrees, has existed for over 30 years. 


--------------------
\3 Had we used the average interest rate on bonds with 15 or more
years to maturity, which was 8.73 percent as of September 30, 1995,
our estimate of the financing subsidy would have been approximately
the same.  Note that this long-term rate is consistent with the
current Treasury rate set out in DOE Order RA 6120.2. 


      INTEREST RATES ON NEW
      FINANCING AFTER 1983 TRACK
      WITH TREASURY'S RATES
-------------------------------------------------------- Chapter 3:1.5

In 1983, the Department of Energy increased the interest rates at
which new projects or replacements to old projects would be financed
by modifying its Order RA 6120.2.  This modification required that,
in the absence of specific legislation to the contrary, new projects,
additions, and equipment replacements made after September 30, 1983,
be financed at interest rates equal to the average yield during the
preceding fiscal year on interest-bearing marketable securities of
the United States, which, at the time the computation is made, have
terms of 15 years or more remaining to maturity.  As shown in figure
3.2, our review showed that, after 1983, new capital projects or
replacements that were debt-financed had interest rates that track
closely with Treasury rates. 

   Figure 3.2:  Interest Rates
   Paid by PMAs on New Financing
   Compared to Treasury 30-Year
   Rates for Bonds Issued From
   1983 Through 1995

   (See figure in printed
   edition.)

Sources:  Department of Treasury officials and documents provided by
PMAs. 

The new interest rates did not apply to projects that were already
under construction.  For example, the Russell project, on which
construction started in 1975, continued to capitalize interest at the
rate applicable in 1975, 6.125 percent.  Projects continue to carry
the interest rate in effect at the time the projects are started,
regardless of when the borrowing occurred.  As a result, Treasury's
cost of funds could either be greater or less than the project rate
depending on whether interest rates are falling or rising.  In 1985,
the year the first electric generating unit became commercially
available at the Russell project, the interest cost borne by Treasury
was nearly 10.8 percent, significantly higher than the rate of the
interest associated with Russell. 

Since the rates the PMAs pay for new appropriated debt are based on
the average of Treasury issues in the prior year, during times of
falling interest rates, PMAs will usually pay interest on new
appropriated debt at rates above current Treasury rates.  Conversely,
during times of rising interest rates, PMAs will pay interest on new
appropriated debt at rates below current Treasury rates. 

As shown in figure 3.1, despite new borrowing at market rates, it is
the PMAs' ability to repay high interest debt first that has kept and
likely will continue to keep their average interest rates below those
of Treasury.  However, over time, as the pre-1983 appropriated debt
is repaid, the PMAs' financing subsidy should eventually decrease. 


      WESTERN CARRIES HIGH LEVELS
      OF NONINTEREST BEARING
      IRRIGATION-RELATED DEBT
-------------------------------------------------------- Chapter 3:1.6

In addition to appropriated debt, Western is responsible for repaying
certain irrigation-related construction costs on completed irrigation
facilities (which we refer to as irrigation debt).  As previously
noted, reclamation law provides for irrigation assistance to be
recovered primarily by power revenues.  Although irrigation debt is
scheduled to be recovered with power revenues, Western does not view
irrigation debt as a PMA cost.  Therefore, when Western repays these
amounts, neither the costs, nor the related revenues, are reflected
in Western's financial statements.\4

As of September 30, 1995, according to Western, it had approximately
$1.5 billion of outstanding irrigation debt,\5 which is to be repaid
without interest.  The repayment period for the irrigation debt could
be up to 60 years after completion of construction--up to a 10-year
development period plus a 50-year repayment period.  Because DOE's
repayment policies require PMAs to repay their highest interest rate
debt first (unless lower interest-bearing debt is at the end of its
repayment period, in which case it would be paid first), the
irrigation debt, at zero percent interest, will generally not be
repaid until the end of its repayment period.  As of September 30,
1995, according to Western, about $32 million of the total $1.5
billion of irrigation debt had been recovered through electricity
rates.  To the extent irrigation debt is repaid through electricity
rates, power users are subsidizing irrigators. 

In addition to the long period allowed for repayment of irrigation
debt, completed irrigation facilities were under construction for
periods ranging from 1 to 27 years, with an average construction
period of about 8 years.  Therefore, the irrigation debt may not be
repaid, on average, until approximately 68 years after the initial
costs were incurred.  Using the average interest rate on Treasury
bonds outstanding for 1995 of 9.1 percent, we estimate that in 1995
the cost to Treasury of Western's $1.5 billion of irrigation debt was
$137 million. 

This irrigation debt continues to increase at the Pick-Sloan and
other projects due to capital improvements allocated to completed
irrigation facilities that are to be repaid by Western.  To
illustrate the future cost to the federal government of new
irrigation debt, we calculated the present value of this new debt,
assuming it would be repaid at zero percent interest at the end of
the average 68 years that the debt would most likely be outstanding. 
By applying a discount rate of 7 percent, which approximates
Treasury's current 30-year bond rate, we estimate that the present
value of each dollar that will be repaid 68 years from today is less
than one penny. 


--------------------
\4 The irrigation debt is not recorded on Western's financial
statements.  Irrigation debt is discussed in Western's financial
statements in the footnote called "Commitments and Contingencies."

\5 See chapter 2 for a discussion of power-related costs that have
been allocated to incomplete irrigation facilities. 


   AGENCY COMMENTS AND OUR
   EVALUATION
---------------------------------------------------------- Chapter 3:2

In commenting on a draft of this report, the PMAs stated that they
agree that certain unpaid investments (appropriated debt) are charged
an interest expense that is less than the Treasury's cost of
borrowing at the time the investment was made.  However, the PMAs
expressed great concern with our methodology for measuring the
magnitude of Treasury's unrecovered financing costs and, as a result,
do not concur with our estimate of the magnitude of this cost.  The
PMAs believe our approach is invalid and is equivalent to assuming
that the PMAs refinance their appropriated debt on an annual basis. 
The PMAs believe that a more accurate methodology for determining the
magnitude of the unrecovered financing cost would be to compare each
investment's fixed interest rate against Treasury's cost of borrowing
in the year the investment was placed in service.  Thus, they propose
calculating the 1995 financing difference by comparing the Treasury's
cost of funds in the year of the PMA investment to the actual PMA
interest rate on that investment. 

As stated in this chapter, we believe that there is a financing
subsidy on the PMAs' appropriated debt because the interest rates the
PMAs pay do not fully recover the federal government's cost of funds. 
We characterize this situation as a financing subsidy because there
is a net cost to the federal government of providing the PMAs with
appropriated debt.  We do not believe the methodology proposed by the
PMAs captures the full amount of this subsidy because it does not
consider the impact of the PMAs' flexible repayment terms or, as
discussed below, the impact of Treasury's borrowing practices.  As
discussed in appendix I, the methodology described by the PMAs would
be a more accurate means to calculate the portion of the subsidy
related to the below market financing.  However, the records were not
available at Western to make the type of specific calculation the
PMAs proposed. 

We calculated the 1995 estimated financing subsidy by taking the
difference between the PMAs' weighted average interest rate for 1995
and the Treasury's average interest rate on its entire bond
portfolio.  Since Treasury borrows for the needs of the entire
federal government using short-term and long-term financing, and does
not match specific borrowings with the PMAs' appropriated debt
financing, the average interest rate on Treasury's entire bond
portfolio best reflects its cost of funds.  We believe our approach
reasonably captures both the impact of the below market financing
provided the PMAs prior to 1983 and the flexible repayment terms
currently afforded the PMAs under DOE policies.  To help ensure that
our methodology was reasonable, we spoke to representatives of OMB,
Treasury, and the Congressional Budget Office. 

The PMAs disagree with our assertion that the Treasury's additional
cost is caused, in part, by the DOE policy of allowing the PMAs to
pay off the highest interest rate debt first.  The PMAs believe that
as long as the interest rate assigned to each PMA borrowing reflects
the Treasury's cost of borrowing at the time, then Treasury is kept
whole and no additional cost is incurred.  We disagree.  Treasury is
not "kept whole" because Treasury's borrowing practices are
inflexible in that it is generally unable to refinance or prepay
outstanding debt in times of falling interest rates.  This
inflexibility is part of the reason for Treasury's relatively high
9.1 percent average cost of funds.  Because of the PMAs' flexibility,
and the Treasury's inflexibility, there are, and likely always will
be, differences in the cost of funds.  In summary, we continue to
believe that the PMAs' ability to pay off the highest interest rate
appropriated debt first, and at any time they desire within the
repayment terms of up to 50 years, results in a financing subsidy. 


FEDERAL SUBSIDIES AND INHERENT
ADVANTAGES OF PMAS RESULT IN
LOW-COST POWER
============================================================ Chapter 4

PMAs market low cost wholesale electricity.  PMAs' average revenue
per kilowatthour (kWh) for wholesale sales\1 has historically been
substantially lower than average revenue per kWh for nonfederal
utilities.  Some of the difference in average revenue per kWh is
attributable to the PMAs' unrecovered power-related costs (see
chapter 2) and federally subsidized debt financing.  (See chapter 3.)
Inherent advantages PMAs have compared to other utilities contribute
to lower power production costs and lower average revenue per kWh. 
One such advantage is that PMAs market primarily low-cost hydropower
while other utilities generally must rely on more expensive coal and
nuclear plants to generate electricity.  Another advantage is that
PMAs, as federal agencies, do not, for the most part, pay taxes. 
PMAs are required to recover several nonpower costs, which is a
disadvantage compared to other utilities.  Competition in the
wholesale electricity market could impact the PMAs' position as
marketers of low cost electricity. 


--------------------
\1 The average revenue per kilowatthour for wholesale sales (sales
for resale) is referred to in this report as average revenue per kWh. 
This average is calculated by dividing total revenue from the sale of
wholesale electricity by the total wholesale kilowatthours sold. 
Because PMAs and POGs generally recover costs through rates with no
profit, average revenue per kWh should be reflective of PMAs' and
POGs' full power production costs.  For IOUs, average revenue per kWh
should represent cost plus the regulated rate of return.  Given that
a large portion of IOU rate of return (net income), 80 percent, is
used to pay common stock dividends, which is a financing cost,
average revenue per kWh also approximates power production cost for
IOUs.  The Energy Information Administration cautions that average
revenue per unit of energy sold should not be used as a substitute
for the price of power.  The price that any one utility charges
another for wholesale energy comprises numerous transaction-specific
factors including 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.  These fees are influenced by factors such
as time of delivery, quantity of energy, and reliability of supply. 


   PMAS' AVERAGE REVENUE PER KWH
   HAS BEEN SUBSTANTIALLY LOWER
   THAN NONFEDERAL UTILITIES
---------------------------------------------------------- Chapter 4:1

As shown in figure 4.1, in 1994 the PMAs' average revenue per kWh was
more than 40 percent lower than IOUs and publicly owned generating
utilities (POGs) in the primary North American Electric Reliability
Council\2 (NERC) regions in which the PMAs operate. 

   Figure 4.1:  Average Revenue
   Per kWh of Wholesale Power
   Sold, 1994

   (See figure in printed
   edition.)

Note:  SEPA/SERC - Southeastern/Southeastern Electric Reliability
Council; SWPA/SPP -
Southwestern/Southwest Power Pool; WAPA/WSCC - Western/Western
Systems Coordinating Council. 

Source:  Developed by GAO based on data from the PMAs' 1994 annual
reports, Energy Information Administration (EIA), and American Public
Power Association (APPA). 

According to the Energy Information Administration, in 1994 the
nationwide average revenue per kWh was 3.5 cents for IOUs and 3.9
cents for POGs.  The PMAs' average revenue per kWh in 1994, by
rate-setting system, ranged from a low of 0.66 cents per kWh for
Southwestern's Robert D.  Willis system to a high of 3.09 cents per
kWh for Southeastern's Georgia-Alabama-South Carolina system.  We
also reviewed each PMA's average revenue per kWh compared to national
averages for IOUs and POGs from 1990 through 1993.  During that
period, the PMAs' average revenue per kWh was consistently at least
40 percent less than those of IOUs and POGs.  A detailed comparison
of PMA, POG, and IOU average revenue per kWh for 1990 through 1994
and a comparison of each PMA's average revenue per kWh by
rate-setting system to IOUs and POGs in the applicable NERC regions
for 1994 is provided in appendix V.  We have provided these
comparisons by rate-setting system because each PMA system and
corresponding NERC region has different average revenue per kWh. 
These average revenues per kWh may vary considerably by rate-setting
system due to customer mix, contractual arrangements, and regional
environmental factors such as streamflow\3 and wildlife. 

In 1994, Southwestern's average revenue per kWh was the lowest of the
three PMAs.  The PMAs' average revenue per kWh, which is generally
reflective of power production costs, differs for a number of
reasons, such as average interest rates, streamflow, and the
operating efficiency of the hydroelectric plants.  As discussed in
chapter 3, Southwestern has significantly lower average interest
rates than the other PMAs.  In addition, Southwestern had above
average streamflow in 1994 and other recent years.  Western, in
contrast, has had deferred payments in the 1990s primarily due to
drought conditions.  A potential reason for higher average revenue
per kWh for Southeastern is the operating condition of hydroelectric
plants that generate the power that it markets.  We recently reported
that the Corps' hydroelectric plants in the Southeast have
experienced lengthy outages resulting in declines in reliability and
availability of power.\4 We did not review the hydroelectric plants
that generate the power marketed by Southwestern and Western to
determine if similar operating problems exist. 

According to the American Public Power Association (APPA), POGs'
average revenue per kWh were higher than IOUs' average revenue per
kWh for several reasons.  First, POGs sell a higher percentage of
wholesale power under firm power contracts, which command higher
prices than nonfirm sales.  Second, the timing of many POGs'
construction of coal and nuclear generating facilities, in the late
1970s and early 1980s, coincided with new environmental regulations
with which previously built facilities were not required to comply. 
This is in contrast to many IOUs that built coal plants before the
1970s.  Also, POGs often do not have enough of their own generating
capacity to meet customer needs and thus purchase power from IOUs. 

There are some limitations to our comparison of average revenue per
kWh.  The most recent industry data we could obtain was 1994.  Since
that time, competition has increased and may have reduced the average
revenue per kWh.  In addition, we did not include independent power
producers (IPPs) in our comparison because similar information was
not readily available.  IPPs supply a small percentage of the total
market (8 percent) with electricity; however, IPPs are providing a
large portion of the new capacity\5 with low cost, natural gas-fired
turbines, which is driving wholesale electric rates down.  IPPs could
pose a significant competitive threat to the PMAs.  Despite these
limitations, we believe that our comparison of the average revenue
per kWh is a strong indicator of the relative power production cost
and overall competitive position of the PMAs compared to other
utilities. 


--------------------
\2 The North American Electric Reliability Council was formed by the
electric utility industry to promote the reliability and adequacy of
the bulk power supply in the electric utility systems of North
America.  NERC consists of nine regional reliability councils and
encompasses essentially all the power systems of the contiguous
United States, as well as parts of Canada and Mexico. 

\3 Streamflow is the quantity of water passing a given point in a
stream or river during a given period, usually expressed in cubic
feet per second.  Streamflow is primarily dependent on regional
weather conditions. 

\4 See Federal Power:  Outages Reduce the Reliability of
Hydroelectric Power Plants in the Southeast (GAO/T-RCED-96-180, July
25, 1996). 

\5 Capacity is the amount of electric power that can be delivered by
a generating unit at one time. 


   SEVERAL SYSTEMS FACE
   COMPETITIVE PRESSURE
---------------------------------------------------------- Chapter 4:2

Most of the PMAs' 17 different rate-setting systems appear to be in a
strong competitive position compared to POGs and IOUs in their areas. 
However, several systems have high or increasing production costs. 
Increasing competition in the utility industry may limit their
ability to raise rates.  One of these systems, the Washoe Project, is
not viable under existing operating conditions.  Western is selling
electricity from this project for 1.9 cents per kWh that is costing
11 cents per kWh to produce.  Other projects, such as Pick-Sloan,
face mounting pressure to continue to increase rates.  Pick-Sloan had
outstanding deferred payments of $131 million as of September 30,
1995.  To recover deferred payments and potentially recover
irrigation debt, Pick-Sloan faces upward rate pressure.  Competition
could make it difficult for this project to recover its substantial
irrigation debt.  Although low cost now, potential rate increases at
Pick-Sloan could affect its future competitive position. 

Another project, the Central Valley Project (CVP), has started to
feel the effects of competition and has acted to improve its
position.  Much of the CVP power that Western sells is purchased from
nonfederal sources at prices established in long-term contracts.  CVP
"passes through" the costs of purchasing this power to its customers;
no profit is made.  In fiscal year 1995, CVP purchased less power for
its customers than in fiscal year 1994 for a variety of reasons. 
According to CVP officials, one of the reasons for this was that its
customers were able to obtain needed power from other sources at a
lower price than the price CVP had established in its contracts.  CVP
officials told us that they expect this trend to continue and have
begun to terminate the contracts they hold to purchase power--a
process which they expect to continue over the next several years. 

The rates that CVP charges for firm power are composite; that is,
they incorporate the cost of both CVP-purchased and CVP-generated
power.  CVP's average revenue per kWh is the highest when compared to
other projects where Western markets power.  One reason for this is
the inclusion in rates of the relatively expensive CVP-purchased
power.  Since CVP's repayment study projects the purchase of less and
less power in coming years, the consequence could be lower rates. 

Except for the Georgia-Alabama-South Carolina system, it appears that
Southeastern's rate-setting systems are in a relatively strong
competitive position.  As discussed in chapter 2, if the inactive
portion of the Russell Project is brought on line, according to
Southeastern officials, it would likely cause an increase in rates
for the Georgia-Alabama-South Carolina system because of the $488
million invested in this portion of the project.  As shown in
appendix V, the average revenue per kWh at this system--3.09 cents
per kWh--is the highest for all three PMAs. 

Southwestern is in a very strong competitive position in all of its
rate-setting systems.  As shown in appendix V, there are substantial
differences in the average revenue per kWh of Southwestern's
rate-setting systems and the average revenue per kWh of the IOUs and
POGs in the NERC regions in which Southwestern markets power. 

As discussed earlier, the impact of competition in the wholesale
electricity market, and the increasing impact of low cost IPP
electricity, could affect the PMAs' competitive position. 


   FEDERAL SUBSIDIES AND INHERENT
   ADVANTAGES CONTRIBUTE TO
   LOW-COST POWER
---------------------------------------------------------- Chapter 4:3

PMAs sell primarily wholesale power generated at federal water
projects.  The Flood Control Act of 1944 calls for the PMAs to
encourage the most widespread use of electricity at the lowest
possible rates to consumers.  The PMAs do not sell power for profit. 
IOUs generally provide a defined service area with power and build
new generating capacity to meet future customer needs.  Both
wholesale and retail electricity is sold by IOUs.  The objective of
IOUs is to produce a return for their shareholders.  POGs are similar
to PMAs in that they are owned and/or operated by governmental
entities--federal, state, or local.  They are nonprofit entities
established to serve their communities and nearby consumers at cost. 
POGs sell both wholesale and retail electricity. 

Key operating and financial differences exist between PMAs and other
utilities.  Many of these differences, including the PMAs' reliance
on hydropower, other utilities' need to pay various taxes, accounting
and rate-setting practices, and financing, result in advantages to
the PMAs and contribute to the substantial difference in power
production costs.  In this section, we compare key operating and
financial factors of PMAs to IOUs and POGs.  We selected two IOUs and
two POGs from each of the PMAs' service areas.  In order to be
selected, each utility had to generate at least some
hydroelectricity.  We contacted APPA and the Edison Electric
Institute (EEI) to corroborate our findings from the individual
utilities.  For a description of the methodology for our comparison,
see appendix I. 


      GENERATION OF ELECTRICITY
-------------------------------------------------------- Chapter 4:3.1

PMAs rely almost entirely on hydroelectric power while other
utilities are primarily dependent on coal and nuclear generating
plants.  Table 4.1 shows the large contrast in percent of power
coming from various generating sources used by the PMAs and other
utilities. 



                               Table 4.1
                
                     Net Generation, PMAs and Other
                            Utilities, 1995

                          (Figures in percent)

                                        Nuclea
                                  Coal       r     Gas   Hydro   Other
------------------------------  ------  ------  ------  ------  ------
PMAs                                 8       0       0      92       0
Other utilities                     55      25      12       6       2
----------------------------------------------------------------------
Source:  Energy Information Administration. 

According to APPA, POGs on average generated 26 percent\6 of their
electricity from hydroelectric plants in 1994.  EEI reported that
IOUs generated an average of 4 percent of electricity from
hydroelectric plants between 1990 and 1994.  The hydroelectric plants
that generate the power marketed by the PMAs have several key cost
advantages over coal and nuclear plants that contribute to lower
power production costs, including relatively low capital construction
costs and no fuel costs. 

To show the relatively low capital cost of these hydroelectric
plants, we compared the investment in utility plant per megawatt of
capacity for these plants to those of other utilities.  As shown in
figure 4.2, Southeastern, Southwestern, and Western have
substantially less invested in power plants than other utilities,
which contributes to their lower power production costs.  Note that
Southeastern's investment in utility plant per megawatt is
substantially higher than the other PMAs.  This is because the
Russell project, which is discussed in chapter 2, has incurred
construction costs of $488 million with no corresponding generating
capacity. 

   Figure 4.2:  Investment in
   Utility Plant per Megawatt of
   Generating Capacity

   (See figure in printed
   edition.)

Source:  GAO analysis of financial data in PMAs' 1994 annual reports
and EIA data. 

Compared to other utilities, the lower investment in PMA-related
hydroelectric plants is partly the result of construction of these
plants 30 to 60 years ago, at lower costs compared to more recent
construction.  Unlike the PMAs and operating agencies, IOUs build new
capacity to meet the future needs of customers.  The higher
construction costs for the other utilities shown in figure 4.2
reflects more recent construction of coal and nuclear plants.  Many
IOU and POG nuclear plants that were completed and are operating had
significant capital construction costs, which is at least partly due
to stringent Nuclear Regulatory Commission (NRC) regulations. 
Utilities with coal plants must comply with the Clean Air Act, which
requires significant investments in pollution control equipment for
many plants.  The PMAs' relatively low investment in utility plant
results in a large cost advantage.  Our analysis excluded nuclear
plants that are mothballed\7 and thus provide no capacity while
resulting in significant capital costs.  Inclusion of these
"regulatory assets" would have increased the POG and IOU investment. 
Appendix I describes the methodology used for computing the ratios in
figure 4.2. 

Another major reason that hydroelectric plants result in lower power
production costs is the cost of fuel.  This is particularly important
when comparing hydro plants to coal plants.  The cost of coal is a
major operating expense for most other utilities.  Nuclear fuel is
also a significant cost, although not nearly as large a factor as
coal.  In 1994, POGs' fuel costs represented 15 percent of operating
revenues, while IOUs' fuel costs represented 17 percent of operating
revenue.  The PMAs, on the other hand, have the benefit of marketing
power from hydroelectric plants, which do not have an associated fuel
cost.\8

The PMAs do have certain costs of operations resulting from
hydroelectric production that differ from coal and nuclear
generation.  According to Southwestern, the Corps is subject to
federal regulations, such as the Endangered Species Act and the
National Environmental Policy Act.  Southwestern, through the Corps'
operations, estimates that it lost about $1.3 million in revenues
over the past 5 years through water spilled\9 and operations changed
to improve water quality for downstream recreational fisheries. 
Southwestern also estimates that it has spent nearly $500,000 on
equipment, studies, and services in an effort to find solutions to
the water quality/sport fisheries problem.  Southeastern and Western
face similar issues related to the Corps and Bureau operations of
their respective hydroelectric facilities.  It is important to note
here that capital and O&M costs relating to nonpower uses of federal
dams, including flood control, navigation, and recreation, are
allocated to those other purposes and not included in PMA electricity
rates.  As discussed in chapter 1, on average, the cost allocations
to power are 69 percent, 35 percent, and 50 percent for projects
related to Southeastern, Southwestern, and Western, respectively. 

POGs and IOUs face similar regulations in running hydroelectric dams. 
The utilities we contacted reported to us that they need to comply
with numerous laws including the Federal Power Act, Federal Water
Pollution Control Act, Clean Water Act, and the Endangered Species
Act.  In addition, these utilities are subject to regulations of
government agencies such as FERC, the Forest Service, and other state
and local governmental agencies.  The operations of hydropower
projects at the utilities we contacted are greatly affected by these
laws and regulations.  In fact, several utilities reported to us that
the laws and regulations make certain new hydroelectric projects
economically infeasible.  As with Southwestern, one of the POGs
reported that it is required to spill water, which results in over $1
million per year in lost revenues.  Some of the utilities reported
that they recover a portion of O&M costs for recreational services
and facilities; however, for the most part, the capital and O&M costs
incurred in complying with laws and regulations are recovered through
electricity rate charges. 


--------------------
\6 This average does not include any adjustments for joint ownership
of plants.  Credit for all generation from a plant is given to the
operator of the plant. 

\7 Mothballed nuclear plants can be either incomplete or completed
plants that have had construction terminated or have been shut down
either temporarily or permanently.  Under generally accepted
accounting principles, these costs are either written off or, if
deemed allowable by the applicable regulator, are classified as
"regulatory assets" and included in rates through amortization. 

\8 As noted in table 4.1, a relatively small amount of electricity
marketed by Western is produced from coal. 

\9 A water spill occurs when an operating agency allows water to pass
through the dam without producing electricity.  Water may be spilled
because a reservoir is too full or because extra water is needed for
navigation, recreation, or irrigation flows.  Water may be spilled to
maintain water quality.  Water temperature and dissolved oxygen
levels may be controlled through water spillage. 


      INCOME AND OTHER TAXES
-------------------------------------------------------- Chapter 4:3.2

PMAs, as federal entities, are generally not subject to taxes, which
gives them a substantial power production cost advantage over POGs
and IOUs.  POGs, as publicly owned utilities, typically do not pay
income taxes because they are a unit of state or local government. 
However, many POGs do make payments in lieu of taxes to local
governments.  IOUs are subject to several forms of taxation.  Such
taxes include all the general taxation rules in the federal tax laws
as well as a variety of state and local taxes, such as income tax,
gross receipts tax, franchise tax, and property tax. 

With the exception of the Boulder Canyon Project, the PMAs generally
do not make payments in lieu of taxes to state or local governments. 
The Boulder Canyon Project Adjustment Act of 1940 requires annual
payments to the states of Arizona and Nevada.  In 1995, the project
paid $600,000, or 1.2 percent of operating revenues to these states. 

According to EEI, in 1994, IOUs, on average, paid taxes totaling
about 14 percent of operating revenue.  This average varies
significantly by state and utility due to differing state and local
government taxation laws and various levels of IOU profitability. 
The IOUs we contacted pay taxes ranging from 11 percent to 20 percent
of operating revenue.  Examples of taxes paid by the IOUs we
contacted are federal and state income tax, real and personal
property tax, corporate franchise tax, invested capital tax, and
municipal license tax. 

POGs are exempt from paying federal or state income taxes.  However,
most POGs we contacted make a contribution to one or more local
governmental entities, generally in lieu of property taxes.  APPA
conducted a survey\10 and found that 77 percent of the respondents
made contributions to local governmental entities; 74 percent of
those contributions were payments in lieu of taxes.  POGs also
contribute free or reduced cost electrical service, the use of
employees, and other services such as the use of vehicles, equipment,
and materials to local governments.  A study\11 of 670 public
distribution utilities showed that the median net payments and
contributions as a percent of electric operating revenue were 5.8
percent.  The range of net payments as a percentage of operating
revenue for the POGs we contacted varied from 0 to 17 percent. 


--------------------
\10 1994 Survey of Local Publicly-Owned Electric Utilities Tax
Payments and Contributions to State and Local Government, American
Public Power Association. 

\11 1994 Payments and Contributions by Public Power Distribution
Systems to State and Local Government, American Public Power
Association, March 1996. 


      ACCOUNTING AND RATE-SETTING
      PRACTICES
-------------------------------------------------------- Chapter 4:3.3

PMAs are agencies of the Department of Energy and thus are required
to follow standards recommended by the Federal Accounting Standards
Advisory Board (FASAB) and approved by GAO, OMB, and Treasury. 
Certain FASAB standards directly address accounting requirements for
the PMAs.  For example, as discussed in chapter 2, SFFAS no.  5
prescribes accounting principles the PMAs will be required to follow
for recording the full cost of pension and postretirement health
benefits.  Because FASAB standards and other relevant federal
guidelines do not specifically address regulated entities, the PMAs
are allowed to follow the provisions of Statement of Financial
Accounting Standards no.  71, Accounting for the Effects of Certain
Types of Regulation (SFAS 71).\12

The provisions of SFAS no.  71 require, among other things, that the
financial statements of a utility reflect the economic effects of
rate regulation and provide for a relevant matching of revenues and
expenses.  Regulatory actions can provide reasonable assurance of the
existence of an asset, reduce or eliminate the value of an asset, or
impose a liability on the regulated enterprise.  For example, if a
regulator determined that the costs of a nonproducing power plant
were allowable, then the costs of the plant would be carried as a
"regulatory asset" and reflected in rates.  In contrast, if the costs
were determined to be unallowable, the asset would be written off
with no corresponding rate charge. 

IOUs are subject to the pronouncements of FASB and thus prepare
financial statements in accordance with SFAS 71.\13 POGs are subject
to the pronouncements of the Governmental Accounting Standards Board
(GASB).  GASB Statement 20, Accounting and Financial Reporting for
Proprietary Funds and Other Governmental Entities That Use
Proprietary Fund Accounting, states that if GASB has not addressed an
issue, then an entity may follow FASB guidance.  POGs generally
prepare financial statements in accordance with SFAS 71 since GASB
has not addressed regulatory accounting for governmental entities. 

IOUs typically use the accrual basis\14 (as modified by SFAS 71) to
determine costs to be recovered through electricity rates, using
depreciation to recover capital costs.  Depreciation as a basis for
recovery of capital costs provides a consistent, systematic method on
which to base rates by recognizing the cost of the asset equally over
its useful life.  PMAs and POGs generally use a cash basis or debt
service method of setting rates.  Under this method, capital costs
are recovered through rates as payments for the asset are made.  For
example, if a capital asset is debt financed, the cost would be
included in rates when principal on the debt is repaid or scheduled
to be repaid.  Repayment terms between PMAs and POGs differ.  POGs
generally repay principal on debt in fixed annual or semiannual
installments, whereas most PMA debt has flexible repayment terms and
as such is not required to be repaid until the final year. 

Rate recovery terms for the various types of utilities vary. 
Depreciable lives of hydroelectric assets for the IOUs we contacted
range from 22 years to 96 years, with most asset types exceeding 40
years.  POGs' tax-exempt bonds are generally repaid over 18 to 40
years.  PMAs have 50 years to repay federal appropriations for hydro
assets.  Therefore, even though the PMAs have flexible repayment
terms, in some cases, their costs may ultimately be recovered sooner
than the IOUs overall. 

The financial statements of the PMAs and POGs are presented on an
accrual basis in accordance with SFAS 71.  The financial reporting
difference created by setting rates on a cash basis and reporting on
the accrual basis is recognized in the Federal Investment (Equity)
section of the PMA financial statements as accumulated net
revenues.\15 POGs generally eliminate a mismatch of income between
cash basis rate-setting and accrual basis financial statements by
recording an asset (liability) on the balance sheet with an
offsetting credit (debit) to the income statement. 

There are differences among IOUs, POGs, and PMAs regarding the types
of expenses included in power production costs and resultant rates. 
The types of expenses included in wholesale and retail rates are
subject to approval by utility commissions and may be determined by
legislation as well as accounting practices.  We found that IOUs
typically include all expenses in retail rates unless disallowed by a
utility commission.  If the utility commission deems that certain
expenses do not benefit ratepayers, they will prohibit such expenses
from being included in retail rates.  For example, one state utility
commission decided that advertising expenses, membership dues,
lobbying fees, and nonutility operation expenses do not benefit
ratepayers and therefore were not allowed to be recovered through
retail rates.  However, these costs are often recovered fully through
wholesale rates because FERC generally allows such costs.  An example
of costs that FERC may disallow from wholesale rates is a portion of
CWIP if FERC determines that the IOU has requested an unreasonable
amount to be included in rates.  Most POGs we contacted include all
of their expenses in rates.  PMAs' rates, on the other hand, do not
include some costs, as discussed in chapter 2.  However, PMAs are
required to recover certain nonpower costs.  For example, Western is
required to recover the Hoover Dam Visitor Center costs, which are
estimated at about $124 million.  In addition, Western is required to
repay about $1.5 billion of capital costs related to assistance on
completed irrigation facilities (irrigation debt). 

According to FERC, often an IOU will determine within the first 3
years of construction that a project is not viable and halt
construction so as to minimize expenses which will not provide
benefit to ratepayers.  Normally if an IOU halts construction on a
project, it will pass these costs through to the ratepayers.  A
customer may challenge the inclusion of such costs in rates with the
appropriate utility commission.  The commission may then conduct a
prudency test which serves as the basis for allowing such costs in
rates.  The purpose of the prudency test is to determine whether it
was prudent to build the project at the time construction began.  If
so, then the cost of the abandoned project would be fully included in
the rate base.  Even if the project does not meet the prudency test,
according to FERC, the ratepayers would still be responsible for some
portion of the costs and shareholders would be responsible for the
remainder of the costs.  PMAs are not subject to FERC's prudency
test. 

PMAs, because of DOE Order RA 6120.2, do not include project costs in
rates until put into commercial service.  The Russell Project,
although not yet operational but determined viable according to
Southeastern, was in construction for 16 years and has been awaiting
commercial operation for the last 4 years.  As such, costs related to
the Russell Project totaling $488 million, including accumulated
interest, are still in CWIP and excluded from rates.  Compared to
other utilities, the relative magnitude and length of time for
Southeastern's deferral of Russell from its rates is unique. 

IOUs' and POGs' basic rate-setting methods also differ from PMAs. 
IOUs and POGs generally use a revenue requirements study.  For IOUs,
the revenue requirement is the amount of money the utility requires
to cover its annual expenses while earning a reasonable rate of
return for its investors.  POGs follow similar methods but do not
require a rate of return since they are publicly owned, although some
may include an allowance to provide equity capital for the system. 
Power repayment studies are prepared annually by the PMAs to
determine the adequacy of current rates and determine new rates.  The
power repayment study tests the adequacy of rates; it entails a
5-year cost evaluation period and recovery of costs within their
legally permitted repayment periods.  The study also forecasts
power-related capital and O&M costs that the PMA will be required to
repay in the future and projects future revenues based on current
rates.  If the study shows that revenues generated under current
rates will be inadequate to cover expenses, new rates may be
designed.  Most of the unrecovered costs identified in chapter 2 are
not included in the study and, therefore, are not included in the
determination of rates. 


--------------------
\12 Private sector entities and the PMAs, where applicable, follow
the generally accepted accounting principles of the Financial
Accounting Standards Board (FASB). 

\13 Utilities are also subject to the provisions of Statement of
Financial Accounting Standards no.  101, Regulated Enterprises -
Accounting for the Discontinuation of Application of FASB Statement
No.  71.  Deregulation, a change in the method of regulation, or a
change in the competitive environment for an entity's regulated
services or products, can cause SFAS no.  101 to be applied.  If any
of these events occur, the entity would be required to write off
related regulatory assets and liabilities.  In addition, the entity
would be required to determine any impairment to other assets,
including plant, and write down the assets, if impaired, to their
face value.  Given the increasing competition in the electricity
market, certain enterprises may cease to meet the criteria for
application of SFAS no.  71. 

\14 Pronouncements of FASB generally require accrual accounting,
which recognizes revenues in the period when earned and expenses in
the period when incurred, regardless of when payments are received or
made. 

\15 Accumulated net revenues represent differences between the timing
of recognition of expenses and the related revenues, with the primary
cause related to the difference between the recognition of capital
costs based on depreciation expense for financial reporting purposes
and the actual flow of cash for rate-setting purposes.  Because
revenue from rate-setting on a cash basis has exceeded depreciation
for financial reporting purposes, the PMAs' accumulated net revenue
balance represents deferred revenue. 


      FINANCING OF CAPITAL
      PROJECTS
-------------------------------------------------------- Chapter 4:3.4

The methods and costs of capital financing vary greatly among the
PMAs, POGs, and IOUs.  Federal power-related capital projects rely
primarily on debt financing from Treasury.  This financing is
dependent on the appropriations process, discussed in chapter 1. 
POGs rely primarily on debt financing from the capital market for
capital projects.  In addition to debt financing, IOUs are able to
use equity financing. 

PMAs have substantial balances of appropriated debt that have been
used to finance the construction of hydroelectric and transmission
facilities.  As discussed in chapter 3, because of several factors,
PMA interest rates on appropriated debt have been subsidized by the
federal government.  POGs and IOUs also issue debt to finance capital
projects.  POGs and IOUs typically go to the financial markets to
issue various short-term and long-term debt instruments.  POGs
generally issue bonds that are exempt from federal and state income
taxes.  This results in POGs getting favorable interest rates on
their debt.  IOUs issue long-term debt and some short-term
instruments, such as commercial paper.  IOU interest rates are based
on market forces and typically vary based on the bond ratings of the
particular IOU.  Unlike PMAs, IOUs and POGs have the flexibility to
refinance debt in times of falling interest rates.  However, as
discussed previously, PMAs have the ability to repay higher interest
rate debt first, thereby allowing them to effectively manage their
debt costs. 

According to EIA, the average interest rate for 1994 for all POGs was
5.6 percent.  For IOUs, it was 7.3 percent.  The average interest
rates of the POGs and IOUs we contacted for 1995 were in the same
range as for the entire industry in 1994.  For the POGs, the low was
5.1 percent and the high was 6.1 percent.  The IOUs' range was 6.5
percent to 7.9 percent.  In 1995, the PMAs' average interest rates
ranged from 2.9 percent for Southwestern to 5.5 percent for Western. 

The Bureau has obtained financing for several capital projects from
Western's customers, which we will refer to as "third-party
financing." The Bureau has the authority to accept contributions from
Western's customers to defray the costs of capital construction.  As
of September 30, 1995, outstanding third-party financing, or customer
advances, amounted to about $154 million for the Hoover Dam capital
improvement (uprating) program (Boulder Canyon Power System) and
about $25 million for the Buffalo Bill project (Pick-Sloan Missouri
Basin Power System).  The interest rates for the Hoover Dam uprating
program range from 5.5 percent to 8.2 percent, and the interest rate
for the Buffalo Bill project is 11.07 percent. 

Under third-party financing arrangements, Western customers provide
funding (primarily from the issuance of bonds) to the Bureau to use
for the capital project.  The customers pay the debt service cost,
and Western records the proceeds as a liability and records interest
expense.  Western then bills the customers for the production costs
of electricity, including the debt service on the third-party
financing, and credits the customers for the debt service costs. 
Essentially, this arrangement results in customers directly paying
for capital improvements rather than paying for them indirectly
through rates.  Unlike the Russell Project, which was financed with
appropriated debt, third-party financing shifts many of the risks of
construction projects to the customers, who are responsible for the
bonds, rather than the federal government. 

In addition to debt financing, federal power-related capital projects
are financed using a method similar to revenue financing.  Revenue
financing is paying for capital projects with net cash generated from
operations.  Revenue financing for the PMAs occurs when power
revenues exceed O&M expenses and the resulting net revenue is used to
pay off appropriated debt on new projects or replacements in the
first year of the repayment period.  In effect, the capital
appropriation is repaid in the year that it was made with revenue
from current power customers.  Southwestern, for example, has been
able to keep its average interest rate at 2.9 percent by revenue
financing its new projects that would have been financed at DOE
policy rates.  POGs and IOUs also use revenue financing for capital
projects.  To the extent a utility is able to finance capital
projects from net cash flow rather than debt it will reduce future
interest expense.  In addition to revenue and debt financing, IOUs
have access to equity financing.  IOUs are able to issue common and
preferred stock and typically pay a large portion of earnings out in
common dividends.  In 1994 the IOU payout ratio\16 was 80 percent. 
Dividends represent a financing cost for IOUs. 

As discussed in chapter 1, PMAs' appropriated debt generally has
terms of 50 years for generating projects and 35 to 45 years for
transmission investments.  Most of the PMA debt follows a "balloon
payment methodology," in which principal is due at the end of the
repayment period with no required annual amortization.  This differs
from the IOUs we contacted, who reported maximum maturities on debt
of 30 to 40 years.  IOUs reported that they generally pay principal
off in balloon payments at maturity, either through cash flow from
operations or refinancing.  POGs reported maximum maturities of 18 to
40 years; however, the POGs generally repay principal in fixed
amounts each year.  As discussed in the rate-setting section,
inclusion of capital costs in rates for PMAs and other utilities
varies from the cash (debt service) to the accrual basis. 

We noted several other differences in financing, including control of
capital expenditures and placement costs.  The PMAs and operating
agencies face the constraints of federal budget pressures in
obtaining capital financing.  According to the Corps, the focus on
the federal deficit has put pressure on PMA and operating agency
budgets and has resulted in less funding for PMAs and operating
agencies for hydropower capital programs.  POGs and IOUs have more
direct control over capital budgets.  However, POGs and IOUs are thus
subject to the scrutiny of the market, such as the bond rating
system, which affects the appeal of the bonds to the investing
public.  IOU financing is also subject to the scrutiny of regulators. 

The PMAs, as federal agencies who are appropriated capital funds, do
not pay any placement costs\17 or transaction fees.  In contrast,
POGs and IOUs must pay placement costs.  The POGs and IOUs we
contacted reported placement costs from .09 percent of the face value
of the debt offering up to 1.5 percent.  In addition, IOUs reported
placement costs on common and preferred equity offerings of about 3
percent. 

When compared to IOUs, PMAs and POGs are generally more highly
leveraged.  Figure 4.3 shows that the PMAs and POGs rely heavily on
debt financing for capital projects. 

   Figure 4.3:  PMAs' Leverage
   Compared to Other Utilities

   (See figure in printed
   edition.)

Source:  GAO analysis of financial data in PMAs' 1994 audited
financial statements and EIA data. 

The PMAs' and POGs' ratios of long-term debt as a percentage of total
assets are much higher than IOUs because PMAs and POGs finance most
of their capital expenditures with debt rather than equity or
revenue.  IOUs may utilize a combination of debt, equity, and revenue
financing which results in lower leverage.  However, IOUs' also pay
dividends to stockholders which are, in essence, a financing cost. 
This cost is not a factor in the calculation of interest on long-term
debt to operating revenue in figure 4.3.  If IOUs' common dividends
were included in this calculation, then an average of 15 percent of
IOUs' operating revenue would be paid for financing costs.  There is
an expected correlation between long-term debt to total assets and
interest on long-term debt to operating revenue for each of the
entities.  Those utilities that utilize debt to a greater extent to
finance capital expenditures have greater interest expense relative
to operating revenue. 

The PMA ratio of interest on long-term debt to operating revenue
would be much higher if interest rates were not subsidized by the
federal government, as discussed in chapter 3.  The ratio shown for
Southeastern is higher than the other PMAs because of the Russell
Project, which is incurring capitalized interest but generating no
revenue.  Southwestern's ratio is only 18 percent because of its low
average interest rate of 2.9 percent. 


--------------------
\16 The payout ratio is calculated by dividing common stock dividends
by net income and thus represents the percentage of net income that
was paid out in common stock dividends. 

\17 Placement costs include brokers fees, attorney fees, accounting
fees, and other costs of public debt or equity offerings. 


   AGENCY COMMENTS AND OUR
   EVALUATION
---------------------------------------------------------- Chapter 4:4

In commenting on a draft of this report, the PMAs stated that they
are not truly comparable to other utilities because they have unique
characteristics that make certain comparisons against other utilities
of limited value.  The PMAs stated, for example, that unlike
"traditional utilities," they do not have a responsibility to meet
load growth in their regions or the authority to acquire new firm
power resources.  The PMAs stated that it is inappropriate to compare
their hydropower costs to coal and nuclear generation of other
utilities. 

We agree with the PMAs that they are different from other utilities
in the ways discussed in this chapter, including cost of production,
types of generating facilities, payment of taxes, accounting and
rate-setting, and financing.  We also discuss in this chapter the
different missions and responsibilities of PMAs, IOUs, and POGs.  We
believe that power customers are primarily concerned with production
costs and resultant electricity rates, not whether the supplier is an
IOU, POG, or PMA or whether the supplier is using coal, nuclear, or
hydroelectric generation.  Given increasing competition and
electricity rates that are expected to fall, if the PMAs do not
remain low-cost suppliers, then they may not be able to recover all
power-related costs.  Therefore, our discussion of the differences in
power production costs between PMAs, IOUs, and POGs and the reasons
for these differences is essential. 

The PMAs agreed with our statement in this chapter that PMAs are
low-cost suppliers of electricity.  However, the PMAs are concerned
that our use of average revenue per kilowatthour (kWh) is overly
simplistic and may mislead readers about the magnitude and causes of
differences in costs between PMAs and other utilities.  The PMAs do
not believe average revenue per kWh takes into account differences in
types of electricity sold that result in different prices.  They
believe a more accurate measure would be to compare similar products
being offered by different utilities. 

The PMAs appear to be concurring with the results of our analysis but
disagreeing with the methodology that led to those results.  We
continue to believe that the average revenue per kWh is a strong
indicator of the relative power production costs of the PMAs as
compared to IOUs and POGs.  For PMAs and POGs, over time, average
revenue per kWh should equal cost because each operates as a
nonprofit organization that recovers costs through revenues.  For
IOUs, average revenue per kWh should represent cost plus the
regulated rate of return.  Given that a large portion of IOU rate of
return (net income), 80 percent, is used to pay common stock
dividends, which is a financing cost, average revenue per kWh also
approximates power production costs for IOUs. 

We acknowledge in appendix I that we did not perform a detailed
electricity rate comparison of PMAs to nonfederal utilities.  We also
state in this chapter that the price that any one utility charges
another for wholesale energy comprises numerous factors.  We believe
that the PMAs' alternative methodology of comparing similar products
being offered would provide a reasonable rate or price comparison. 
However, as the PMAs note in their comments, this analysis would be
difficult, and the PMAs themselves have not done it.  Also, the PMAs'
proposed analysis would not necessarily result in a better indicator
of relative production costs because different types of power may be
sold above or below total production cost.  Average revenue per kWh,
on the other hand, better captures total production costs. 

The PMAs also stated that a related problem with using average
revenue per kWh as a measure of the PMAs' competitiveness is the
variability in output of PMA hydropower projects.  The PMAs believe
our use of average revenue per kWh to indicate competitiveness could
result in wide variations in a PMA's competitive position from year
to year.  In order to address this factor, we reviewed the PMAs'
average revenue per kWh for 1990 through 1994.  For each of these
years, the PMAs' average revenue per kWh was consistently at least 40
percent less than those of IOUs and POGs.  We believe that this
5-year comparison is a strong indicator of the PMAs' current
competitiveness. 

The PMAs also expressed concern that the report gives greater focus
to advantages enjoyed by the PMAs without giving equal attention to
other costs that the PMAs' customers must repay that would not
normally be charged to nonfederal utility customers.  The PMAs stated
that we report that irrigation assistance is a large subsidy paid by
Western's customers and suggested that we also note other examples,
such as future replacement costs, the Hoover Dam Visitor Center,
payments in lieu of taxes, and billions of irrigation investments
that are not even in service. 

We believe that our report provides an appropriate discussion of the
relative advantages and disadvantages the PMAs have compared to
nonfederal utilities.  However, we believe the advantages outweigh
the disadvantages.  The PMAs' use of hydropower plants built 30 to 60
years ago, tax-exempt status, unrecovered costs discussed in chapter
2, and the financing subsidy discussed in chapter 3, in aggregate,
provide the PMAs with a substantial cost advantage compared to
nonfederal utilities.  We believe this large difference is reflected
in the average revenue per kWh comparisons shown in this chapter and
appendix V. 

We agree that the PMAs have disadvantages compared to nonfederal
utilities, and we have more fully reflected those in this chapter. 
For example, we added the Hoover Dam Visitor Center as a nonpower
cost that Western must recover through rates.  However, we do not
agree with the PMAs' statement that our draft report said that
irrigation assistance is a large subsidy paid by Western's customers. 
Our draft report stated that "as of September 30, 1995, according to
Western, about $32 million of the total $1.5 billion of total
irrigation debt has been recovered through electricity rates." To the
extent that Western actually repays this irrigation debt, the power
users are subsidizing irrigators.  The billions of future irrigation
investments that are not even in service are not costs that have been
incurred, and it is questionable whether they ever will be incurred. 
To the extent that these planned future costs are included in
Western's power repayment studies and impact current rates, the
actual application of any relevant power revenue would be to other
appropriated debt.  We believe that until these future irrigation
costs are incurred and repaid, or funds are set aside for their
future repayment, they do not represent a disadvantage to Western. 

The PMAs stated that Southwestern's inclusion of future replacement
costs in its current repayment study results in its rates being 10 to
15 percent greater than they would otherwise be.  We do not agree
with this statement.  The actual application of the revenues
generated by inclusion of these costs in current rates has been to
current year capital appropriations or other appropriated debt.  As a
result, Southwestern has been able to pay off most of its recent,
higher interest debt and currently has a weighted average interest
rate of 2.9 percent compared to 4.4 percent for Southeastern and 5.5
percent for Western.  In addition, as discussed in chapter 3,
Southwestern has reduced its balance of appropriated debt from $769
million at September 30, 1991, to $686 million at September 30, 1995. 
Thus, we believe that Southwestern has managed its appropriated debt
using sound business principles and has minimized its interest
expense that must be recovered through rates. 

Another disadvantage cited by the PMAs relates to tentative project
cost allocations.  The PMAs stated that the tentative cost
allocations may very well be higher, as in the case of the Clarence
Cannon Project, than the final allocated costs.  According to
Southwestern's 1995 annual report, there are four projects that still
have tentative allocations.  Southwestern states in this report that
"[T]he amount of adjustments that may be necessary when final
allocations are approved for these projects is not presently
determinable."

Because final allocations can either increase or decrease the
percentage of costs allocated to power, the net effect of changes to
allocations will not be known until all are finalized.  Therefore, we
do not believe that these tentative allocations represent a
disadvantage to the PMAs. 


OBJECTIVES, SCOPE, AND METHODOLOGY
=========================================================== Appendix I

The Chairman, Subcommittee on Water and Power Resources, House
Committee on Resources, and the Ranking Minority Member, House
Committee on Resources, asked us to review several issues relating to
Southeastern, Southwestern, and Western.  The primary focus of our
review was to determine whether all power-related costs incurred
through September 30, 1995, have been recovered through the PMAs'
electricity rates (chapter 2 and appendixes III and IV); whether the
financing for power-related capital projects is subsidized by the
federal government and, if so, to what extent (chapter 3); and how
these PMAs differ from nonfederal utilities and the impact of these
differences on power production costs (chapter 4 and appendix V).  In
addition, we were asked to provide information on FERC oversight of
the PMAs (appendix VI).  The following sections detail the
methodologies used in our analyses. 


   ASSESSING WHETHER PMA RATES
   RECOVER ALL POWER-RELATED COSTS
--------------------------------------------------------- Appendix I:1

To assess whether PMA rates recover all power-related costs, we
reviewed appropriate legislation affecting the three PMAs, including
the Flood Control Act of 1944, Reclamation Project Act of 1939, and
applicable federal guidance.  The acts discuss cost recovery in
general, but do not specifically define the costs that must be
recovered.  The Secretary of Energy has set PMA cost recovery and
accounting policy in DOE Order RA 6120.2, which we reviewed in
detail.  To define the full costs associated with producing and
marketing federal hydropower, we reviewed Office of Management and
Budget (OMB) Circular A-25, which provides guidance for use in
setting fees to recover the full costs of providing goods and
services.  The circular defines full cost as all direct and indirect
costs of providing goods and services and is consistent with guidance
of full cost reporting contained in SFFAS No.  4.  These criteria
indicate that the full cost of the electricity sold by the PMAs is
the sum of all direct and indirect costs incurred by the operating
agencies to produce the power, the costs incurred by the PMAs to
market and transmit the power, and the costs incurred by any other
agencies to support the operating agencies and PMAs. 

To get an understanding of the PMAs' financing and the types of costs
incurred, we reviewed the 1995 and 1994 annual reports of
Southeastern, Southwestern, and Western.  The financial statements
included in the annual reports were audited by KPMG Peat Marwick LLP
(KPMG), an independent public accounting firm.  KPMG was hired by the
DOE Inspector General to perform the audits of the PMAs.  The KPMG
audits of the PMAs are conducted in accordance with private sector
and government auditing standards.  On the basis of its audits, KPMG
issues opinions on the fairness of the PMA financial statements and
the adequacy of PMA internal controls and compliance with laws and
regulations.  KPMG issued unqualified opinions for 1995 and 1994 for
Southeastern, Southwestern, and Western financial statements,
indicating that they are fairly stated in all material respects. 
While it was not within the scope of our work to assess the overall
quality of the auditors' work, we reviewed selected 1995 and 1994
KPMG audit workpapers to obtain background information.  We met with
KPMG and DOE Inspector General staff to discuss the financial audits. 
Throughout our report, where appropriate, we used audited numbers
from the PMAs' 1995, 1994, and earlier annual reports. 

We interviewed numerous officials at the PMAs and the operating
agencies in the finance and rate-setting functions.  We provided
questions to each of the respective groups relating to cost recovery
and other matters addressed in our report.  We analyzed data provided
to us by the PMAs and operating agencies to determine which costs are
and are not fully recovered through rate charges.  We did not assess
the reasonableness of the methodologies used in developing the
operating agency cost allocation formulas that are established for
each project.  In addition, the unrecovered costs identified in this
report focus on the material items we found in reviewing the data
sources described in this appendix.  There could be additional
unrecovered costs that did not come to our attention during this
review. 


   ASSESSING THE RECOVERY OF
   PENSION AND POSTRETIREMENT
   HEALTH BENEFITS
--------------------------------------------------------- Appendix I:2

To assess whether pension and postretirement health benefits were
fully recovered by the PMAs through rate charges, we consulted with
representatives from the Office of Personnel Management, Office of
Actuaries.  We also reviewed KPMG's 1995 and 1994 reports on
compliance with laws and regulations.  We determined that certain
Civil Service Retirement System (CSRS) pension and all
post-retirement health benefits for current employees were not being
recovered. 

To calculate these unrecovered costs, we reviewed SFFAS No.  5, which
requires all federal agencies, including PMAs, to record the full
cost of pension and postretirement benefits in financial statements
beginning in fiscal year 1997.  SFFAS No.  5 prescribes that the
aggregate entry age normal (AEAN) actuarial cost method be used to
calculate pension expenses and accrued actuarial liabilities for
pension benefits.  Under the AEAN method, which is based on dynamic
economic assumptions, including future salary increases, the
actuarial present value of projected benefits is allocated on a level
basis over the earnings or the service of the group between entry age
and assumed exit ages and should be applied to pensions on the basis
of a level percentage of earnings.  The portion of this actuarial
present value allocated to a valuation year is called the "normal
cost." We consulted with OPM's actuaries to obtain an understanding
of how to apply the AEAN method to estimate the amount by which
employer and employee contributions toward future CSRS pension
benefits fall short of the normal cost of those benefits. 

We determined the applicable normal cost, under the AEAN method, of
CSRS pensions for fiscal year 1995 and the cumulative unrecovered
cost (unfunded liability) as of September 30, 1995.  For CSRS
employees, OPM reported that, in 1995, 25.14 percent of gross
salaries was the full (normal) cost to the federal government of
benefits earned that year by employees and that federal agencies
contributed 7 percent and employees contributed 7 percent to OPM for
CSRS, leaving a funding deficiency of 11.14 percent of each CSRS
employee's annual salary.  This 11.14 percent funding deficiency is
applicable to the PMAs.  To calculate the difference between the full
(normal) cost for CSRS pensions and the amount employees and the
federal agencies contributed, we did the following: 

  -- estimated the number of PMA and operating agency employees
     involved in producing and marketing power for each of the three
     PMAs, based on information provided by the PMAs and operating
     agencies;

  -- estimated the number of those employees covered by the CSRS,
     based on governmentwide information provided by OPM on the
     percentage of employees covered by CSRS;

  -- multiplied that number by the average salary\1 to estimate total
     CSRS payroll expense; and

  -- multiplied the resulting number by 11.14 percent, which,
     according to OPM actuaries, represents the difference between
     the normal cost of future CSRS pensions and combined employer
     and employee contributions. 

The result is an estimate of the additional amount the agencies would
have had to contribute to fully fund CSRS pension benefits earned in
fiscal year 1995. 

To determine the cumulative unrecovered costs, under the AEAN method,
for future CSRS pensions, we estimated the total accrued actuarial
liability, which is equal to the present value of the total expected
future benefit obligation less the present value of the future entry
age normal cost contributions.  To estimate the total cumulative
unrecovered costs, we multiplied the accrued actuarial liability to
payroll ratio (5.916), which was provided by OPM, by the estimated
gross CSRS payroll associated with power production and marketing for
the PMAs and operating agencies. 

To estimate the funded portion of the accrued actuarial liability, we
multiplied the asset to payroll ratio (2.085), also provided by OPM,
times the estimated gross CSRS payroll associated with power
production and marketing for the PMAs and operating agencies.  We
subtracted the funded portion from the total accrued actuarial
liability to obtain an estimate of the cumulative unrecovered costs
as of the end of fiscal year 1995. 

In addition to pensions, federal employees are eligible to receive
postretirement health coverage, for which a portion of the premium is
paid by the federal government.  While employed, neither federal
employees nor their employing agencies contribute funds to pay for
the federal government's portion of postretirement health benefits. 
The PMAs do not recover this cost from ratepayers.  To calculate the
amount of the unrecovered power-related costs for fiscal year 1995,
we again used the AEAN method, which is prescribed by FASAB for
estimating postretirement health benefits costs.  We estimated the
number of PMA and operating agency employees involved in producing
and marketing power for each of the three PMAs.  We multiplied this
number for each of the PMAs by the 82 percent governmentwide health
benefits plan participation rate, which we then multiplied by $1,973
(OPM's estimate of the annual normal cost for postretirement health
benefits per participating employee).  The result of this calculation
approximates the normal cost of postretirement health benefits for
fiscal year 1995 and the amount the agencies would have had to
contribute to fully fund postretirement health benefits earned that
year.  To determine the cumulative unrecovered costs for
postretirement health benefits, under the AEAN method, we multiplied
the number of power-related personnel times the 82 percent
participation rate and then times $26,336 (OPM's estimate of the
cumulative unrecovered cost per employee as of the end of fiscal year
1995). 

It is important to note that our calculations of annual unrecovered
pension and postretirement health benefits do not include any
provision for retirees of the three PMAs or the operating agencies
because the relevant actuarial information needed to do so was not
available from OPM. 


--------------------
\1 We obtained actual salary information for the PMAs.  For the
operating agencies, we used governmentwide average salary information
for CSRS employees, which we obtained from OPM. 


   ASSESSING THE RECOVERY OF OTHER
   COSTS
--------------------------------------------------------- Appendix I:3

Information on recovery of costs relating to the Russell Project,
Truman Project, Washoe Project, Mead-Phoenix Project, and Western's
Abandoned Transmission Line was obtained by analyzing the PMAs'
annual reports and other information provided by the PMAs and
operating agencies.  For the Russell Project, we reviewed records of
congressional hearings on the project back to its initial approval in
the 1960s. 

To identify the portion of power-related capital costs allocated to
incomplete and infeasible irrigation facilities at Pick-Sloan, we
used (1) cost reports and estimates of the power requirements for
irrigation facilities prepared by the Bureau of Reclamation, (2) cost
allocation percentages prepared by the Bureau of Reclamation and
Corps of Engineers, and (3) reconciliations prepared by Western of
Western's Power Repayment Studies and the Bureau's Statement of
Project Construction Cost and Repayment as of September 30, 1994. 

To identify the portion of the Corps' power-related O&M expenses that
Western has allocated to incomplete irrigation facilities for
financial reporting and cost recovery purposes, we reviewed the
annual calculations made by Western to allocate the Corps' annual O&M
expenses based on the planned rather than the actual use of the
irrigation facilities. 

We used cost reports and financial statements from the PMAs and
operating agencies to review environmental costs.  We determined that
some environmental costs have been legislatively excluded from
recovery in rates.  We also found that some environmental costs are
included in rates, but could not determine whether all such costs are
included.  To obtain the data necessary to make this determination
would have required audit work which was beyond the scope of the
assignment. 


   DETERMINING WHETHER PMA
   FINANCING IS FEDERALLY
   SUBSIDIZED
--------------------------------------------------------- Appendix I:4

For the purposes of this report, we defined the financing subsidy as
the difference between Treasury's borrowing cost and the interest
paid by the three PMAs to Treasury.  Treasury's borrowing cost is
particularly relevant because the federal government has had debt
outstanding since before 1940--before the oldest PMA appropriated
debt still outstanding--and has had a deficit every year since 1969. 
Thus, the federal government has had to issue debt to extend
financing to the PMAs.  There are three main aspects of the subsidy
to the PMAs, although not all PMA debt has each of these elements. 
One is the difference between the PMA borrowing rate and the closest
match of Treasury borrowing in terms of maturity at the time of the
appropriation.  The second is the PMAs' ability to repay the highest
interest-bearing appropriated debt first.  The third is that
Treasury's borrowing practices are inflexible in that it is generally
unable to refinance or prepay outstanding debt in times of falling
interest rates.  Another factor is that PMA appropriated debt has
maturities of up to 50 years, which is beyond the maximum maturity of
Treasury bonds.  Thus, if PMAs do not pay off appropriated debt
within 30 years, Treasury would have to refinance its corresponding
debt. 

Because the data are not available to calculate the total subsidies
for each loan in a way that fully accounts for all of the aspects of
the subsidy, we developed an alternative method to estimate the 1995
financing subsidy.  Specifically, we multiplied the amount of PMA
appropriated debt outstanding by the average interest rate Treasury
was paying on its portfolio of bonds outstanding at the end of fiscal
year 1995.  We then multiplied the amount of appropriated debt
outstanding by the average interest rate paid by the PMAs.  Finally,
we subtracted the estimated interest paid by the PMAs at their
average interest rates from the estimated interest paid by Treasury
on the same amount of debt. 

Since Treasury does not match its borrowing with the PMAs'
appropriated debt financing, the average interest rate on Treasury's
entire bond portfolio best reflects its cost of funds.  The bond
portfolio average interest rate includes bonds with varying
maturities up to 30 years.  Treasury's bond portfolio average
interest rate of 9.1 percent was obtained from the Monthly Statement
of the Public Debt of the United States as of September 30, 1995. 
This document is published by the Bureau of Public Debt, Department
of Treasury. 

To illustrate the historical spread between the PMAs' cost of funds
on appropriated debt and Treasury's bond portfolio, we compared the
average interest rate Treasury was paying on its bond portfolio
outstanding at the end of fiscal years 1952 to 1995 to the average
interest rates paid by PMAs on their appropriated debt balances in
the same years.  We obtained data on levels of appropriated debt and
weighted average interest rates associated with that debt from the
PMAs.  In some years adjustments to historical financial records had
occurred, causing significant fluctuations in calculated interest
rates; in these instances, we averaged the calculated interest rates
over the period of fluctuation.  Sufficient data were not available
to identify the weighted average interest rates in fiscal years 1952
to 1985 for projects now serving Western.  During this period,
interest rates ranged from 0 percent on some minor projects in the
early 1950s to 12.375 percent in fiscal year 1985.  Western believes
that on a consolidated basis for all projects, 3 percent represents a
reasonable weighted average interest rate on appropriated debt for
fiscal years 1952 through 1985.  To identify the average interest
rates paid by Western for fiscal years 1986 through 1995, we divided
Western's annual interest on federal investment by the average
outstanding appropriated debt during the year.  Because of various
adjustments to the annual interest expense, Western's interest
expense and resultant average interest rates fluctuated significantly
during this period.  To show the trend line for Western's interest
rates for fiscal years 1986 through 1995, we estimated the trend by
plotting interest rates using the above calculations and using the
5.5 percent average for 1995 as the end point. 

To compare Treasury's cost of funds to the new DOE policy rate for
the years 1983 through 1995, we compared Treasury's yield rate on
30-year bonds issued each year to the average interest rates the PMAs
were generally required to pay on new financing received from
Treasury.  We analyzed this time period because DOE's policy changed
in 1983 to bring the cost of financing new PMA appropriated debt in
line with Treasury market interest rates. 

Our calculation of the financing subsidy does not include the impact
of other forms of subsidy such as the difference between Treasury
debt being compounded semiannually versus PMA debt being compounded
annually.  Our estimate of the subsidy also does not consider the
impact that the risk of hydropower projects might have had on the
PMAs' interest rates if they had been financed in the private market
rather than through Treasury. 

We calculated the total outstanding PMA appropriated debt as of
September 30, 1995, using audited financial statements and power
repayment studies.  Western's appropriated debt included its deferred
payments.  We also calculated the PMAs' weighted average interest
rates using data from the PMAs' audited financial statements and
other data we received from the PMAs.  We obtained the concurrence of
PMA representatives as to the accuracy of our calculations of overall
PMA debt as well as the weighted average interest rate calculations. 

To help ensure that our methodology was reasonable, we spoke to
representatives of OMB, Treasury, and the Congressional Budget
Office.  We also reviewed a report by the Energy Information
Administration (EIA), an agency of the federal DOE, entitled Energy
Subsidies:  Direct and Indirect Interventions in Energy Markets
(SR/EMEU-92-02, November 1992).  This report calculates an interest
subsidy for the PMAs. 


   COMPARING PMAS TO NONFEDERAL
   UTILITIES
--------------------------------------------------------- Appendix I:5

We assessed how PMAs' average revenue per kWh, operations, tax
status, accounting, rate-setting, and financing compared to the
electric utility industry and focused our efforts on reasons why PMA
power production costs were substantially lower than those of POGs
and IOUs.  We determined that IOUs and POGs were the appropriate
"industry group" to compare to PMAs because they generate and
transmit electricity and sell some power at wholesale.  We did not
include non-generating publicly owned utilities or rural electric
cooperatives because these utilities generally buy electricity
wholesale from a generating utility and sell the electricity retail. 
They ordinarily have no generating assets and thus are not comparable
from an operating or financial perspective.  Although we believe IPPs
pose a competitive threat to PMAs, we excluded them from our
comparison because IPP revenue per kWh and other relevant information
was not readily available for 1994. 

We compared the average revenue per kWh for Southeastern,
Southwestern, and Western to the average revenue per kWh of
nonfederal utilities.  To do so, we divided the revenue from the sale
of wholesale electricity by the total wholesale kilowatthours sold. 
We did our comparison on sales for resale (wholesale sales) because
the three PMAs are almost exclusively wholesale electricity
suppliers.  A minor portion of Western's and Southwestern's sales are
to end users--federal and state agencies.  These sales are included
in the calculation of average wholesale rates but have no impact on
the average revenue per kWh.  We did not perform a detailed
electricity rate comparison of PMAs and nonfederal utilities. 
However, we believe that our comparison of average revenue per kWh is
a strong indicator of the PMAs' relative power production cost and
overall competitiveness compared to other utilities.  We performed
the computations for each of the PMAs using 1994 annual reports
because this corresponded to the industry-wide data we had available
for the POGs and IOUs.  We obtained average revenue per kWh
information by NERC region for POGs and IOUs from the American Public
Power Association (APPA) and EIA, respectively. 

To assess the similarities and differences between PMAs, IOUs, and
POGs, we contacted two IOUs and two POGs in each of the PMA service
areas.  All 12 utilities that we contacted had some hydroelectric
generating facilities.  We gathered data from these utilities on
their operations, accounting and rate-setting practices, financing,
and rate oversight.  We gathered similar data from the PMAs.  To
corroborate the information obtained from individual IOUs and POGs,
we gathered similar information from and met with the Edison Electric
Institute (EEI) and APPA to discuss these comparisons and the other
components of our report. 

To illustrate the key differences between PMAs, POGs, and IOUs, we
prepared several ratios for fiscal year 1994.  Information for POGs
and IOUs was obtained from the EIA.  These ratios were computed as
follows. 

  -- Net generation of power represents the percentage of each fuel
     source used to produce electricity.  "Other utilities"
     encompasses both IOUs and POGs.  Data were provided by EIA on
     total net generation by fuel source. 

  -- Investment in utility plant per megawatt of generating capacity
     was calculated by dividing gross utility plant and CWIP by total
     megawatts of installed capacity.  We did not include regulatory
     assets in our calculation.  A downward adjustment was made to
     Southwestern's available generating capacity because the Truman
     plant is operating with significantly reduced capacity due to
     environmental problems.  In addition, the generating capacity
     relating to Russell's inactive units was not included in
     Southeastern's calculation.  This ratio illustrates the relative
     cost of construction for generation and transmission plants. 

  -- Fuel costs as a percentage of revenue were calculated by
     dividing total fuel cost by operating revenue.  Data were
     provided by EIA. 

  -- Leverage ratios were calculated by dividing long-term debt by
     total net assets and interest on long-term debt by operating
     revenue.  Long-term debt for the POGs includes bonds and
     advances from municipalities and others.  The IOUs' long-term
     debt includes bonds, other long-term debt, and advances from
     associated companies.  Adjustments were made to long-term debt
     to account for unamortized premiums and discounts.  The current
     portion of long-term debt was excluded from our calculation of
     long-term debt for the POGs and IOUs.  No adjustment has been
     made for the current portion of the PMAs' long-term debt because
     there is no debt repayment requirement until the final year of
     the repayment period.  For Western, long-term debt includes debt
     related to third-party financing arrangements. 

  -- Interest on long-term debt to operating revenue was calculated
     by dividing total gross interest expense by operating revenue. 
     Gross interest expense includes capitalized interest.  For
     Western, interest expense includes third-party financing
     interest. 

To determine the characteristics of FERC oversight and to identify
similarities and differences between the rate approval and oversight
process for PMAs and IOUs, we interviewed FERC representatives in
various divisions of the Office of Electric Power Regulation.  We
asked for descriptions of the processes that each type of entity must
submit to in order for a rate change to take place.  We also
discussed the basis for approving or disapproving rate changes
requested by each type of utility. 


   ORGANIZATIONS AND GROUPS
   CONTACTED
--------------------------------------------------------- Appendix I:6


      FEDERAL ENTITIES
------------------------------------------------------- Appendix I:6.1

Department of Energy
Energy Information Administration
Federal Energy Regulatory Commission
Department of Treasury
Department of the Interior
Bureau of Reclamation
U.S.  Army Corps of Engineers
Office of Management and Budget
Congressional Budget Office
Office of Personnel Management


      BOND RATING AGENCIES AND
      FINANCIAL ANALYSTS
------------------------------------------------------- Appendix I:6.2

Fitch Investors Service, Inc., New York, NY


      INDEPENDENT PUBLIC
      ACCOUNTING FIRM
------------------------------------------------------- Appendix I:6.3

KPMG Peat Marwick L.L.P. 


      ELECTRIC UTILITIES OR
      HOLDING COMPANIES
------------------------------------------------------- Appendix I:6.4

Southern Company, Atlanta, GA
Duke Power Company, Charlotte, NC
Crisp County Power Commission, Cordele, GA
South Carolina Public Service Authority (Santee Cooper), Moncks
Corner, SC
Empire District Electric Company, Joplin, MO
Union Electric Company, St.  Louis, MO
City of North Little Rock Electric Department, North Little Rock, AR
Grand River Dam Authority, Vinita, OK
Pacific Gas and Electric Company, San Francisco, CA
Montana Power Company, Butte, MT
Salt River Project, Tempe, AZ
California Department of Water Resources, Sacramento, CA


      TRADE OR INTEREST GROUP
      ASSOCIATIONS
------------------------------------------------------- Appendix I:6.5

American Public Power Association, Washington, DC
Edison Electric Institute, Washington, DC
National Independent Energy Producers, Washington, DC




(See figure in printed edition.)Appendix II
COMMENTS FROM THE THREE POWER
MARKETING ADMINISTRATIONS
=========================================================== Appendix I



(See figure in printed edition.)



(See figure in printed edition.)



(See figure in printed edition.)



(See figure in printed edition.)



(See figure in printed edition.)



(See figure in printed edition.)



(See figure in printed edition.)


The following are GAO's comments on the PMAs' letter dated September
4, 1996. 


   GAO COMMENTS
--------------------------------------------------------- Appendix I:7

1.  We have more clearly noted in our report that the PMAs are
generally following applicable laws and regulations regarding cost
recovery and financing of capital projects.  However, determining
whether the PMAs' practices are in accordance with law, or whether
the Congress should make policy changes for repayment and cost
recovery practices, was beyond the scope of this review. 

2.  We agree with the PMAs' comment and have modified the report
where appropriate. 

3.  We have revised the executive summary in several places in
response to the views of the PMAs that it provided insufficient
balance.  These revisions provide clarification of views expressed in
the body of the report. 

4.  Our report identifies environmental costs that have been
legislatively excluded from recovery.  In addition, we determined
that there are environmental costs that do get included in rates;
however, we do not conclude that all power-related environmental
costs, other than those legislatively precluded, are recovered
through power rates.  To have the data necessary to make this
determination would have required audit work which was beyond the
scope of the assignment. 

5.  We have revised our report to reflect that Western officials plan
to recover a majority of deferred payments over time.  Reviewing
Western's future plans to recover deferred payments was beyond the
scope of our review. 


ESTIMATED UNRECOVERED PENSION AND
POSTRETIREMENT HEALTH BENEFIT
COSTS
========================================================= Appendix III

The following two tables show GAO's estimates of the three PMAs'
annual funding shortfalls and cumulative unrecovered costs associated
with Civil Service Retirement System (CSRS) pension and
postretirement health benefits.  As discussed in chapter 2, the
estimates include only current employees of the PMAs and operating
agencies; they do not include retirees.  The tables show the amounts
for the PMAs, the operating agencies, and totals. 



                                   Table III.1
                     
                            Estimated 1995 Pension and
                     Postretirement Health Benefit Costs Not
                          Recovered from Power Customers

                              (Dollars in thousands)


                   Operating           Operating             Operating
             PMA      agency     PMA      agency       PMA    agencies     Total
--------  ------  ----------  ------  ----------  --------  ----------  --------
Pension     $109      $1,560    $665        $733    $4,374      $2,883   $10,324
 amount     (1%)       (15%)    (6%)        (7%)     (42%)       (28%)  (100%)\a
 (Percen
 t of
 total)
Health        61       1,005     314         472     2,293       1,919     6,064
 amount     (1%)       (17%)    (5%)        (8%)     (38%)       (32%)  (100%)\a
 (Percen
 t of
 total)
================================================================================
Total       $170      $2,565    $979      $1,205    $6,667      $4,802  $16,388\
--------------------------------------------------------------------------------
\a Percentages may not total 100 due to rounding. 

Source:  GAO estimates based on information provided by the PMAs,
operating agencies, and OPM. 



                                   Table III.2
                     
                      Estimated Total Cumulative Unrecovered
                       Costs for Pension and Postretirement
                     Health Benefits as of September 30, 1995

                              (Dollars in thousands)


                Operating             Operating              Operating
          PMA      agency       PMA      agency        PMA    agencies     Total
-----  ------  ----------  --------  ----------  ---------  ----------  --------
Pensi             $53,635   $22,884     $25,220   $150,405     $99,152  $355,052
 on    $3,755       (15%)      (6%)        (7%)      (42%)       (28%)  (100%)\a
 amou    (1%)
 nt
 (Per
 cent
 of
 tota
 l)
Healt     821      13,411     4,190       6,306     30,601      25,612    80,940
 h       (1%)       (17%)      (5%)        (8%)      (38%)       (32%)  (100%)\a
 amou
 nt
 (Per
 cent
 of
 tota
 l)
================================================================================
Total  $4,576     $67,046   $27,074     $31,526   $181,006    $124,764  $435,992
--------------------------------------------------------------------------------
\a Percentages may not total 100 due to rounding. 

Source:  GAO estimates based on information provided by the PMAs,
operating agencies, and OPM. 


WESTERN AREA POWER ADMINISTRATION
DEFERRED PAYMENTS
========================================================== Appendix IV

The following schedule provides detailed information about Western's
deferred operating and maintenance (O&M) expense and interest expense
payments by project since fiscal year 1975.  Specifically, the
schedule shows the year the payments were deferred, the type of
payment deferred, the interest rates applicable to the deferred
payment debt, the amount of the deferred payments, and the
outstanding balance of the deferred payment debt as of September 30,
1995. 



                                    Table IV.1
                     
                      Western's Deferred Payments for Fiscal
                             Years 1976 Through 1995

Name         Year      Type of
of        payment      expense                        Amount of    Amount unpaid
projec        was      payment       Interest  deferred payment    as of 9/30/95
t        deferred      deferred      rate (%)      (in dollars)     (in dollars)
------  ---------  --  ------------  --------  ----------------  ---------------
Pick-        1989      Interest         9.250        $8,040,310               $0
 Sloan
             1990                       8.875        13,672,497                0
                        O&M
             1990      Interest         8.875        37,844,690       15,713,456
             1991      Interest         8.750        29,264,073                0
             1992      Interest         8.500        49,750,956       49,750,956
             1993      Interest         7.875        65,534,048       65,534,048
================================================================================
Total                                                               $130,998,460
 Pick-
 Sloan
Frying       1983      O&M              3.046        $1,935,826         $840,653
 pan-
 Arkan
 sas
             1983      Interest         3.046            29,483           29,483
             1984      O&M             10.403           272,992                0
             1984      Interest        10.403         3,798,264                0
             1985      O&M             10.898           885,464                0
             1985      Interest        10.898         6,456,958                0
             1986      Interest        11.070         3,754,785                0
             1987      Interest        10.693         2,457,817                0
             1989      Interest        10.250         2,750,821                0
             1990      Interest        10.075         2,281,432                0
             1991      Interest         9.920         1,202,967                0
================================================================================
Total                                                                   $870,136
 Fryin
 gpan-
 Arkan
 sas
Centra       1976      Interest         6.625        $3,192,493               $0
 l
 Valle
 y
             1976      O&M              6.625        22,477,513                0
             1977      Interest         7.000         5,401,178                0
             1977      O&M              7.000        27,940,904                0
             1978      Interest         7.000         7,361,506                0
             1978      O&M              7.000        15,160,032                0
             1979      Interest         7.500         9,476,885                0
             1979      O&M              7.500        16,657,212                0
             1980      Interest         8.000        11,730,666                0
             1980      O&M              8.000        19,231,204                0
             1981      Interest         8.500        18,532,437                0
             1981      O&M              8.500        37,147,233                0
             1982      Interest         9.000        17,615,141                0
             1983      Interest         9.500         5,078,253                0
             1989      Interest         9.250         8,288,907                0
================================================================================
Total                                                                         $0
 Centr
 al
 Valle
 y
Washoe       1988      O&M              8.500           $99,412          $99,412
             1988      Interest         8.500           242,539          242,539
             1989      O&M              9.250            38,724           38,724
             1989      Interest         9.250           271,372          271,372
             1990      O&M              8.875            23,144           23,144
             1990      Interest         8.875           300,083          300,083
             1991      O&M              8.750           128,853          128,853
             1991      Interest         8.750           337,614          337,614
             1992      O&M              8.500           151,974          151,974
             1992      Interest         8.500           380,589          380,589
             1993      O&M              7.875           127,789          127,789
             1993      Interest         7.875           425,090          425,090
             1994      O&M              7.125           142,242          142,242
             1994      Interest         7.125           468,701          468,701
             1995      O&M              7.250           192,816          192,816
             1995      Interest         7.250           543,082          543,082
================================================================================
Total                                                                 $3,874,024
 Washoe
Collbr       1977      Interest         7.000          $189,794               $0
 an
             1978      Interest         7.000           160,869                0
             1979      Interest         7.500           104,865                0
             1980      Interest         8.000            53,960                0
             1981      Interest         8.500           117,213                0
             1982      Interest         9.000           172,439                0
             1984      Interest         9.500           304,125                0
             1991      Interest         8.500           342,426                0
             1991      O&M              8.500           346,929                0
================================================================================
Total                                                                         $0
 Collb
 ran
       1989                      10.250       $10,775,262               $0
 Color                  O&M
 ado
 River
 Stora
 ge
 Proje
 ct
             1989      Interest        10.250         6,848,151                0
             1990      Interest        10.080         6,197,373                0
             1991      O&M              9.920        11,005,806                0
             1991      Interest         9.920        19,864,455                0
             1992      Interest         9.740        21,366,372                0
             1994      Interest         9.230        53,847,105       43,795,000
================================================================================
Total                                                                $43,795,000
 Color
 ado
 River
 Stora
 ge
 Proje
 ct
Provo        1991      Interest         8.750              $487               $0
 River
             1991      O&M              8.750            11,141                0
             1995      Interest         9.230            29,343           29,343
================================================================================
Total                                                                    $29,343
 Provo
 River
Rio          1976      Interest         6.630          $244,589               $0
 Grande
             1977      Interest         7.000           430,785                0
             1978      Interest         7.000           368,231                0
             1979      Interest         7.500           165,937                0
             1990      Interest         8.880           107,316                0
             1990      O&M              8.880           163,242                0
================================================================================
Total                                                                         $0
 Rio
 Grand
 e
Seedsk       1985      Interest        10.900            $1,716               $0
 adee
             1986      Interest        11.070            21,573                0
             1986      O&M             11.070           204,727                0
             1987      Interest        10.690           134,282                0
             1987      O&M             10.690           334,514                0
             1988      Interest        10.370           189,840                0
             1988      O&M             10.370           309,517                0
             1989      O&M             10.250           204,262                0
             1989      Interest        10.250           241,628                0
             1990      Interest        10.080           392,813          287,920
             1991      Interest         9.920           208,209          208,209
             1992      Interest         9.740           271,820          271,820
             1993      Interest         9.500           745,275          745,275
================================================================================
Total                                                                 $1,513,224
 Seeds
 kadee
Boulde       1988      Interest         8.500        $2,586,667       $2,586,667
 r
 Canyo
 n
             1989      Interest         9.250         2,329,541          101,807
             1990      Interest         8.875         2,545,023        2,545,023
             1991      Interest         8.500         2,770,895        2,770,895
================================================================================
Total                                                                 $8,004,392
 Bould
 er
 Canyo
 n
Parker       1992      Interest         7.875        $2,667,784       $2,667,784
 -
 Davis
             1993      O&M              7.875         1,836,554          769,893
================================================================================
Total                                                                 $3,437,677
 Parke
 r-
 Davis
Intert       1976      Interest         6.625        $1,796,982               $0
 ie
             1977      Interest         7.000         1,306,475                0
             1978      Interest         7.000           885,308                0
             1979      Interest         7.500           743,102                0
             1980      Interest         8.000           385,024                0
             1981      Interest         8.500           532,401                0
             1982      Interest         9.000         1,077,947                0
             1983      Interest         9.500           457,867                0
             1992      Interest         7.875         2,742,335        2,742,335
             1993      Interest         7.875           393,503          393,503
             1994      Interest         7.125            44,773           44,773
================================================================================
Total                                                                 $3,180,611
 Inter
 tie
================================================================================
Overal                                                              $195,702,867
 l
 Total
--------------------------------------------------------------------------------
Source:  Data in this table was provided by Western and was not
verified by GAO.  The unpaid balance of $195,702,867 as of September
30, 1995, reconciles to the audited financial statements. 


COMPARISON OF AVERAGE REVENUE PER
KWH SOLD BETWEEN PMAS AND OTHER
UTILITIES
=========================================================== Appendix V

This appendix shows a comparison of average revenue per kWh between
PMAs, IOUs, and POGs.  The 5-year comparison in table V.1 shows that
the difference between the PMAs' and other utilities' average revenue
per kWh has been consistently greater than 40 percent for 5
consecutive years. 



                               Table V.1
                
                 Trend Analysis of Average Revenue per
                   kWh of Wholesale Power Sold--1990
                              Through 1994

                          (Cents/kilowatthour)

                                  1990    1991    1992    1993    1994
------------------------------  ------  ------  ------  ------  ------
Western                           1.50    1.67    1.75    1.81    1.82
Southwestern                      1.27    1.59    1.37    1.23    1.49
Southeastern                      1.58    1.86    2.12    1.89    1.98
IOUs                              4.17    3.58    3.57    3.40    3.50
POGs                              3.78    3.78    3.90    3.80    3.90
----------------------------------------------------------------------
Source:  PMA Annual Reports and Financial Statistics of Major U.S. 
Investor-Owned Electric Utilities, Energy Information Administration,
DOE. 

Figures V.2 through V.9 in this appendix also show a comparison of
average revenue per kWh for each of the PMAs' 17 rate-setting systems
to the relevant North American Electric Reliability Council (NERC)
region.  This detailed comparison is particularly relevant because
PMA rates are set at a rate-setting system level.  Some rate-setting
systems market power in more than one NERC region and thus are shown
in more than one graphic.  Figure V.1 shows the nine NERC regions. 

   Figure V.1:  North American
   Electric Reliability Council
   Region Map for the United
   States

   (See figure in printed
   edition.)

Source:  North American Electric Reliability Council. 

The remaining figures in this appendix show the 1994 average revenue
per kWh for each of the three PMAs' rate-setting systems compared to
the average revenue per kWh for IOUs and POGs for 1994 for each of
the NERC regions in which the PMA rate-setting systems market power. 

   Figure V.2:  Comparison of
   Average Revenue per kWh by
   Southeastern Rate-setting
   System for the SERC Region

   (See figure in printed
   edition.)

Source:  Developed by GAO from Southeastern's 1994 annual report,
EIA, and APPA. 

   Figure V.3:  Comparison of
   Average Revenue per kWh by
   Southwestern Rate-setting
   System for the SPP Region

   (See figure in printed
   edition.)

Source:  Developed by GAO from Southwestern's 1994 annual report,
EIA, and APPA. 

   Figure V.4:  Comparison of
   Average Revenue per kWh by
   Southwestern Rate-setting
   System for the ERCOT Region

   (See figure in printed
   edition.)

Source:  Developed by GAO from Southwestern's 1994 annual report,
EIA, and APPA. 

   Figure V.5:  Comparison of
   Average Revenue per kWh by
   Southwestern Rate-setting
   System for the MAIN Region

   (See figure in printed
   edition.)

Source:  Developed by GAO from Southwestern's 1994 annual report,
EIA, and APPA. 

   Figure V.6:  Comparison of
   Average Revenue per kWh by
   Western Rate-setting System for
   the WSCC Region

   (See figure in printed
   edition.)

Source:  Developed by GAO from Western's 1994 annual report, EIA, and
APPA. 

   Figure V.7:  Comparison of
   Average Revenue per kWh by
   Western Rate-setting System for
   the SPP Region

   (See figure in printed
   edition.)

Source:  Developed by GAO from Western's 1994 annual report, EIA, and
APPA. 

   Figure V.8:  Comparison of
   Average Revenue per kWh by
   Western Rate-setting System for
   the MAPP Region

   (See figure in printed
   edition.)

Source:  Developed by GAO from Western's 1994 annual report, EIA, and
APPA. 

   Figure V.9:  Comparison of
   Average Revenue per kWh by
   Western Rate-setting System for
   the ERCOT Region

   (See figure in printed
   edition.)

Source:  Developed by GAO from Western's 1994 annual report, EIA, and
APPA. 


WHOLESALE RATE
OVERSIGHT/REGULATION
========================================================== Appendix VI

The Federal Energy Regulatory Commission (FERC) oversees wholesale
electric rates and service standards as well as the transmission of
electricity in interstate commerce.  FERC's jurisdiction of utilities
does not extend to federal or municipal utilities.  The Secretary of
Energy, however, delegated to FERC the authority to approve the PMAs'
rates. 

FERC's involvement in IOUs' activities is broad.  Any changes in
contracts, rates, or services must be approved by FERC.  IOUs must
get approval from FERC for increasing rates in the event of increased
costs, adding new construction to the rate base, mergers, and
acquisitions.  FERC's criteria for reviewing IOUs' rates is that they
be just and reasonable and not unduly discriminatory or preferential. 
Factors that FERC considers in reviewing rates are competition and
equal access.  This is to provide assurance that the IOU does not
exercise a monopoly in the sale or transmission of electricity and to
determine their control over power resources in that area. 

The Secretary of Energy has the authority to approve the PMAs' rates
but delegated to the Deputy Secretary of Energy the responsibility to
approve rates on an interim basis.  Once the Deputy Secretary of
Energy approves the rates, they go into effect on an interim basis
and a rate application is submitted to FERC for final approval of the
rates.  Interim rates are in effect for an average of 4 months. 

FERC's review process for the PMAs is restricted to the scope granted
it by the Secretary of Energy.  The review is limited to assessing: 

(1) whether the rates are the lowest possible to customers consistent
with sound business principles,

(2) whether the revenue levels generated by the rates are sufficient
to recover the costs of producing and transmitting electric energy,
and

(3) the assumptions and projections used in developing the rate
components. 

FERC may only affirm, remand, or disapprove the PMAs' rates.  If FERC
affirms rates, they are approved to be put into effect on a final
basis.  For a remanding of rates, the interim rate remains in effect,
and the PMA must provide clarification to FERC on a designated issue. 
If the clarification provided by the PMA results in rates being
affirmed, the interim rate goes into effect on a final basis.  If
FERC disapproves rates, it means FERC has found the submitted rate to
be wrong.  The interim rate remains in effect, but the PMA must
submit a new rate application.  The new rate application should
compensate for any overcollection or undercollection as a result of
the interim rate. 

Limiting the review process further, FERC may reject the rate
determinations only if it finds them to be (1) arbitrary, capricious,
or in violation of the law, (2) violative of DOE regulations, or (3)
violative of agreements between the PMA Administrator and the
applicable power generating agency.  FERC is prohibited from
reviewing policy judgments and interpretations of laws and
regulations made by the generating agencies. 

There are indications that the rate review process by FERC for the
PMAs has not been fully effective in ensuring that adequate revenue
from power sales is earned to repay appropriations.  For example,
Western's Washoe Project had deferred payments related to interest
and O&M expense of $3.9 million as of September 30, 1995. 


MAJOR CONTRIBUTORS TO THIS REPORT
========================================================= Appendix VII

ACCOUNTING AND INFORMATION
MANAGEMENT DIVISION, WASHINGTON,
D.C. 

Gregory D.  Kutz, Assistant Director
Donald R.  Neff, Senior Audit Manager
Robert E.  Martin, Senior Audit Manager
Caryn A.  Catignani, Auditor
Patricia B.  Petersen, Auditor

OFFICE OF THE GENERAL COUNSEL,
WASHINGTON, D.C. 

Thomas H.  Armstrong, Assistant General Counsel
Amy M.  Shimamura, Senior Attorney

ATLANTA FIELD OFFICE

Carolyn L.  McClary, Auditor

DENVER FIELD OFFICE

Lori C.  Hendrickson, Accountant

SEATTLE FIELD OFFICE

Laurence L.  Feltz, Senior Evaluator
David W.  Bogdon, Senior Evaluator


*** End of document. ***