Power Marketing Administrations: Cost Recovery, Financing, and Comparison
to Nonfederal Utilities (Testimony, 09/19/96, GAO/T-AIMD-96-169).
GAO discussed the Southeastern, Southwestern, and Western Power
Administrations, focusing on: (1) the three power marketing
administrations' (PMA) recovery of their power-related costs; (2)
federal subsidies for financing power-related capital projects; and (3)
differences between PMA and nonfederal utilities on power production
costs. GAO noted that: (1) the three PMA do not fully recover all
power-related costs in the areas of employee health and retirement
benefits, project construction or operation, capital costs for
incomplete facilities, environmental mitigation costs, and deferred
operations and maintenance and interest expense payments; (2) the annual
unrecovered cost for these activities in fiscal year 1995 was about $83
million; (3) a federal financing subsidy of about $228 million exists
because interest expense on the Treasury debt is higher than the
interest income Treasury receives from PMA; (4) in 1994, the average PMA
revenue for wholesale electricity sales was more than 40 percent lower
than nonfederal utilities; (5) PMA production costs were generally well
below the costs for nonfederal utilities, primarily because PMA rely on
low-cost means of electricity generation and generally do not pay taxes;
and (6) increased competition and access to transmission lines and the
increasing influence of low-cost independent producers could affect PMA
costs and revenues in the future.
--------------------------- Indexing Terms -----------------------------
REPORTNUM: T-AIMD-96-169
TITLE: Power Marketing Administrations: Cost Recovery, Financing,
and Comparison to Nonfederal Utilities
DATE: 09/19/96
SUBJECT: Utility rates
Electric power transmission
Electric utilities
Federal corporations
Hydroelectric powerplants
Energy costs
Interest rates
Debt
IDENTIFIER: Civil Service Retirement System
Federal Employees Retirement System
DOE Richard B. Russell Project
Washoe Project (CA)
Pick-Sloan Missouri Basin Program
Central Valley Project (CA)
Shasta Dam (CA)
Colorado River Storage Project
Glen Canyon Dam (AZ)
DOE Harry S. Truman Project
DOE Mead-Phoenix Transmission Line Project
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Cover
================================================================ COVER
Before the Subcommittee on Water and Power Resources, Committee on
Resources, House of Representatives
For Release on Delivery
Expected at
2 p.m.
Thursday
September 19, 1996
POWER MARKETING ADMINISTRATIONS -
COST RECOVERY, FINANCING, AND
COMPARISON TO NONFEDERAL UTILITIES
Statement of Linda M. Calbom
Director, Civil Audits
Accounting and Information Management Division
GAO/T-AIMD-96-169
GAO/AIMD-96-169T
(913745)
Abbreviations
=============================================================== ABBREV
CSRS - Civil Service Retirement System
DOE - Department of Energy
FERS - Federal Employees Retirement System
IOU - investor-owned utilities
IPP - independent nonutility power producers
kWh - kilowatthour
NERC - North American Electric Reliability Council
O&M - operations and maintenance
OMB - Office of Management and Budget
OPM - Office of Personnel Management
PMA - power marketing administration
POG - publicly owned generating utilities
============================================================ Chapter 0
Mr. Chairman and Members of the Subcommittee:
Today, we are presenting testimony on a report\1 we prepared in
response to a request from you and the Ranking Minority Member of the
full committee. We were asked to answer specific questions about
three power marketing administrations (PMA)--Southeastern,
Southwestern, and Western. You asked us to determine (1) whether all
power-related costs incurred through September 30, 1995, had been
recovered through the PMAs' electricity rates, (2) if the financing
for power-related capital projects is subsidized by the federal
government and, if so, to what extent, and (3) how PMAs differ from
nonfederal utilities and 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.
As members of this Subcommittee know, most of the hydropower
facilities involved were originally designed for other purposes in
addition to producing electricity. I would like to begin my
testimony by providing a brief background on the history and purpose
of the power marketing administrations as well as information about
their operations. I will then discuss our findings on each of the
questions.
--------------------
\1 Power Marketing Administrations: Cost Recovery, Financing, and
Comparison to Nonfederal Utilities (GAO/AIMD-96-145, September 19,
1996).
BACKGROUND ON THE THREE PMAS
---------------------------------------------------------- Chapter 0:1
The three PMAs we studied (Southeastern, Southwestern, and Western)
market primarily wholesale power in 30 states\2 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 or the Department of the Interior's
Bureau of Reclamation, commonly referred to as "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.
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. The Department of Energy's
(DOE) 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\3 ) be
recovered, with interest, over periods that can last 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.
Because PMAs and operating agencies generally receive financing from
appropriations, Department of the Treasury checks are issued for
their disbursements. Operating agencies allocate power-related costs
to the PMAs for recovery. PMAs set rates to recover power-related
costs, bill customers, and the resultant revenue is returned to
Treasury. The chart in attachment I demonstrates the flow of
appropriated funds, costs to be recovered, and how repayment is made
to Treasury from the revenues collected from power customers. It
also outlines the costs that have not been recovered through this
process, as well as the financing subsidy, that are discussed in
detail in this testimony.
--------------------
\2 The wholesale power market for all five of the PMAs, including
Bonneville and Alaska, encompasses 34 states.
\3 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 Treasury.
RATES DO NOT RECOVER ALL
POWER-RELATED COSTS
---------------------------------------------------------- Chapter 0:2
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, we 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. We
identified five main power-related costs that meet these criteria
that have not yet been fully recovered through electricity rates.\4
First, the three PMAs do not recover the full cost of power-related
postretirement health benefits and Civil Service Retirement System
(CSRS) pensions for current PMA and operating agency employees.\5
For fiscal year 1995, we estimate that these unrecovered costs were
about $16 million for these three PMAs. 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, we estimate that
the cumulative unrecovered costs associated with postretirement
health benefits and CSRS pension benefits were about $436 million for
these three PMAs.
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 nonoperational 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 power-related 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, we believe that the Washoe
Project is unlikely to generate sufficient revenue to repay all O&M
and interest expenses.
Third, as we reported in May 1996,\6 at the Pick-Sloan Missouri Basin
Program (Pick-Sloan), about $454 million of capital costs for
hydropower facilities and water storage reservoirs has 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 but 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 we
also reported in May 1996, changing the terms of repayment to cover
any of the $454 million investment would require congressional
action. In addition, 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.
In the aggregate, we estimate that the annual unrecovered costs for
the three PMAs was about $83 million for fiscal year 1995 for the
five main power-related activities identified above. As of September
30, 1995, the cumulative unrecovered power costs could be as much as
$1.8 billion. Table 1 provides a summary of our estimates of these
unrecovered costs.
Table 1
Estimated Total Unrecovered Annual and
Cumulative Power-related Costs as of and
for the Year Ending September 30, 1995
(Dollars in millions)
Description Annual -1995 Cumulative
---------------------------------------- ------------- -------------
Pension and postretirement health $16.4 $436.0
benefits
Russell Project (pumping units)
Capitalized interest for fiscal year 25.6
1995 488.0
Construction-work-in-progress balance\a
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 13.6\c 454.0\d
Pick-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 capitalized
interest.
\b Reflects the cumulative appropriated debt that might not be
recovered. Annual deferred payments for O&M and interest expenses
are included in the "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 the 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 fully recover costs in the
future is questionable.
Source: GAO estimates based on information provided by the PMAs,
operating agencies, and OPM.
--------------------
\4 We 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.
\5 We did not examine unrecovered costs for retired employees because
relevant actuarial information was not available from the Office of
Personnel Management (OPM).
\6 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 0:3
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 appropriated debt due in a given
fiscal year. Such debt must be paid first, regardless of interest
rate.) Second, prior to 1983,\7 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. As shown in
figure 1, 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 compared to 9.1 percent for
Treasury's outstanding bond portfolio as of September 30, 1995.
Figure 1: Average Interest
Rates Paid by the PMAs on
Appropriated Debt Compared to
Rates Paid by Treasury on Its
Outstanding Bond
Portfolio--Fiscal Years 1952 to
1995
(See figure in printed
edition.)
Note 1: Western was created in 1977. Pre-1977 interest rates are
for appropriated debt transferred from the Bureau of Reclamation to
Western in 1977. Sufficient data were not available to identify the
weighted average interest rates in fiscal years 1952 to 1985 for
projects in Western's service area. Western officials indicated that
on a consolidated basis for all projects, 3 percent represents a
reasonable weighted average interest rate on Western's appropriated
debt for those years.
Note 2: Percentages shown at right represent percentages for 1995.
Sources: Data on PMAs developed by GAO from data provided by PMAs;
Treasury interest rates determined based on Treasury summary
information related to the public debt of the United States.
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. As shown in
table 2, we estimate that the PMA financing subsidy for fiscal year
1995 was about $228 million.\8
Table 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 irrigation assistance to be paid by Western; includes
deferred payments.
Sources: PMA audited financial statements and other data, and
Treasury summary information related to the public debt of the United
States.
Over the next several decades, as the pre-1983 appropriated debt is
repaid, the PMAs' financing subsidy should decrease. However, as
shown in figure 1, 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, the nature of Treasury's borrowing
practices contributes 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 for fiscal year
1995.
--------------------
\7 In 1983, DOE 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 and 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.
\8 See GAO/AIMD-96-145 for a detailed discussion of our methodology
for calculating the financing subsidy.
FEDERAL SUBSIDIES AND INHERENT
ADVANTAGES OF PMAS RESULT IN
LOW COST POWER
---------------------------------------------------------- Chapter 0:4
PMAs market low cost wholesale electricity. We believe that average
revenue per kilowatthour (kWh) is a strong indicator of the relative
power production costs and overall competitive position of the PMAs
compared to other utilities.\9 As shown in figure 2, in 1994 the
PMAs' average revenue per kWh for wholesale sales was more than 40
percent lower than investor-owned utilities (IOUs) and publicly owned
generating utilities (POGs) in the primary North American Electric
Reliability Council\10 (NERC) regions in which the PMAs operate.
Figure 2: Average Revenue Per
Kilowatthour of Wholesale Power
Sold, 1994
(See figure in printed
edition.)
Note: SERC - Southeastern Electric Reliability Council; SPP -
Southwest Power Pool; WSCC - Western Systems Coordinating Council.
Source: Developed by GAO based on information from the PMAs' 1994
annual reports, Energy Information Administration, and American
Public Power Association.
In 1994, the national wholesale average revenue per kWh was 3.5 cents
for IOUs and 3.9 cents for POGs. This compares to 1.49 cents for
Southwestern; 1.82 cents for Western; and 1.98 cents for
Southeastern. To take into account the variability of PMA
hydropower, we also compared the PMAs' average revenue per kWh 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 that 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\11 to the applicable NERC regions for 1994 is
presented in our report issued today. 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.
Some of the difference in average revenue per kWh between the three
PMAs and nonfederal utilities is attributable to the PMAs'
unrecovered power-related costs and federally subsidized debt
financing discussed earlier. PMAs also have other inherent
advantages that contribute to their low-cost power. First, PMAs rely
almost exclusively upon hydropower produced by projects built
primarily 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.
To illustrate, during 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. Second, 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 totalling an estimated $124
million. Also, 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.
In aggregate, we estimate that the unrecovered power-related costs
and financing subsidy total about $300 million for fiscal year 1995.
Over the last 30 years, we estimate that these costs have been in the
billions. It is important to emphasize that the PMAs are generally
following applicable laws and regulations regarding recovery of these
power-related costs and financing of capital projects.
--------------------
\9 The average revenue per kilowatthour for wholesale sales (sales
for resale) is referred to in this testimony 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 publicly owned generating utilities (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 investor-owned utilities (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. 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.
\10 The North American Electric Reliability Council (NERC) 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.
\11 Southeastern has 4 systems, Southwestern has 3 systems, and
Western has 10 systems.
-------------------------------------------------------- Chapter 0:4.1
Mr. Chairman, this concludes my testimony. I would be happy to
respond to any questions that you or Members of the Subcommittee may
have.
(See figure in printed edition.)Attachment
*** End of document. ***