oversight

Federal Energy Regulatory Commission: Charges for Hydropower Projects' Use of Federal Lands Need to Be Reassessed

Published by the Government Accountability Office on 2003-05-20.

Below is a raw (and likely hideous) rendition of the original report. (PDF)

             United States General Accounting Office

GAO          Report to Congressional Requesters




May 2003
             FEDERAL ENERGY
             REGULATORY
             COMMISSION
             Charges for
             Hydropower Projects’
             Use of Federal Lands
             Need to Be
             Reassessed




GAO-03-383
             a
                                                 May 2003


                                                 FEDERAL ENERGY REGULATORY
                                                 COMMISSION

Highlights of GAO-03-383, a report to            Charges for Hydropower Projects’ Use of
Congressional Requesters
                                                 Federal Lands Need to Be Reassessed



Hydropower projects generate                     Since 1987, FERC’s charges for hydropower projects on federal lands have
power valued at billions of dollars.             been based on a linear rights-of-way fee schedule that was originally used
For projects located on federal                  to determine the annual fees other agencies charged for the rights to locate,
lands, FERC is required to assess                among other things, powerlines, pipelines, and communication lines on
“reasonable annual charges” to use               federal lands—uses that are generally less valuable than hydropower. FERC
these lands. FERC agrees that fair
market value is the most
                                                 chose this system primarily because it was simple and predictable and
reasonable basis for assessing                   would not subject the commission to appeals from the electricity industry.
these charges. This report                       However, this system has no relationship to the economic benefit of the
examines FERC’s annual charge                    federal lands used to produce hydropower. In addition, in implementing
system and the extent to which it                this system, FERC does not ensure that (1) the charges it collects achieve
reflects the federal lands’                      the hydropower annual charge program objectives, (2) it has accurate
contributions to hydropower. GAO                 information on the amount of federal lands licensees use, or (3) its billing
described and assessed FERC’s                    system collects all charges due the federal government for the use of
annual charge system, estimated                  its lands.
the fair market value for the use of
federal lands, and discussed the                 The annual charges FERC currently collects from hydropower projects for
implications of higher charges on
consumers and project owners.
                                                 the use of federal lands are significantly less than the annual fair market
                                                 value of these lands. For this report, GAO defined this value as the value of
                                                 the annual economic contribution that the use of federal lands makes to the
                                                 production of hydropower. According to GAO’s analysis, FERC is receiving
FERC should reconsider its current               less than 2 percent of the annual fair market value for the use of these lands.
system and develop new strategies                In performing its analysis, GAO examined multiple electricity market
and options for assessing annual                 scenarios, including three that estimated the value of federal lands using
charges that are proportionate with              actual industry data from three recent years. Under these scenarios, the fair
the economic benefits conveyed to                market value for the use of federal lands by GAO’s sample of hydropower
hydropower licensees.                            projects is at least $157 million annually and, under some market conditions,
                                                 hundreds of millions of dollars more. In comparison, FERC collected about
While FERC is developing this
                                                 $2.7 million in annual charges from these projects in 2002.
strategy, it should better manage
its current system by verifying
the amount of federal lands                      GAO reached these conclusions on the basis of its analysis of a stratified
hydropower projects use and                      random sample of 24 projects that use federal lands. This sample was drawn
resolving discrepancies among its                from 56 projects that collectively account for about 90 percent of the
multiple billing and land databases.             hydropower produced on federal lands. Although this sample of 24 projects
                                                 was not representative of all hydropower projects on federal lands, these
In its comments, FERC disagreed                  projects produced about 60 percent of all electricity generated by FERC-
with our valuation of federal lands              licensed hydropower projects that use federal land and represent about 35
but agreed with our                              percent of all federal lands used for hydropower production.
recommendations to resolve
discrepancies among its databases.
                                                 If FERC decides to collect annual charges that more closely reflect the fair
The National Hydropower
Association also disagreed with our              market value for the use of federal lands, the implications of such a decision
valuation of federal lands.                      for consumers and hydropower project owners would depend on (1) how
                                                 much of the fair market value FERC chooses to recover and how it decides
www.gao.gov/cgi-bin/getrpt?GAO-03-383.
                                                 to implement these higher charges and (2) whether the affected electricity
To view the full report, including the scope     market is still fully regulated or has been restructured.
and methodology, click on the link above.
For more information, contact Barry T. Hill at
(202) 512-3841.
Contents



Letter                                                                                                   1
                             Results in Brief                                                            4
                             Background                                                                  8
                             FERC’s System for Determining Annual Charges Is Based on Values
                               for Rights-of-Way, Not Hydropower                                        13
                             Many Federal Lands in Our Sample Are Significantly More Valuable
                               Than FERC’s Current Charges Suggest                                      16
                             Effect of Higher Annual Charges on Consumers and Project Owners
                               Will Depend on FERC’s Implementation and the Regulatory
                               Environment                                                              28
                             FERC’s Future Ability to Increase Annual Charges Could Be Limited
                               by Electricity Market Restructuring                                      31
                             Conclusion                                                                 34
                             Recommendations for Executive Action                                       34
                             Agency and Industry Comments                                               35
                             Scope and Methodology                                                      37


Appendixes
              Appendix I:    Estimating the Fair Market Value of Federal Land
                             Used to Produce Hydropower                                                 40
             Appendix II:    Net Benefits Analysis for Each of the 24 Projects in
                             Our Sample                                                                 66
             Appendix III:   Comments from the Federal Energy Regulatory
                             Commission                                                                 90
             Appendix IV:    Comments from the National Hydropower Association                          98
              Appendix V:    Comments from the Department of the Interior                              150
             Appendix VI:    GAO Contact and Staff Acknowledgments                                     154



Tables                       Table 1: Hydropower Projects Included in Our Sample                        12
                             Table 2: The Estimated Annual Value for the Use of Federal Lands
                                      for Each of the 24 Projects in Our Sample for 1998, 1999,
                                      and 2000; and FERC Annual Charges for 2002                        20
                             Table 3: Results of Our Sensitivity Analyses of Each of the
                                      24 Projects in Our Sample—1999, 1999 with a Change in
                                      Price, and 1999 with a Change in Quantity                         23




                             Page i                               GAO-03-383 FERC Charges for Federal Lands
          Contents




          Table 4: The Estimated Annual Value for the Use of Federal Lands
                    for Each of the 24 Projects in Our Sample for 2003, and
                    FERC Annual Charges for 2002                                     25
          Table 5: Numeric Example of Summary Net Benefits
                    Calculations                                                     51
          Table 6: Profiles of Our Sample of 24 Hydropower Projects                  53
          Table 7: Prices Used to Value Hydropower for Our Sample of
                    24 Projects                                                      59
          Table 8: Bath County, FERC License No. 2716                                66
          Table 9: Big Creek 1&2, FERC License No. 2175                              67
          Table 10: Bliss, FERC License No. 1975                                     68
          Table 11: Boundary, FERC License No. 2144                                  69
          Table 12: California Aqueduct, FERC License No. 2426                       70
          Table 13: Coosa River, FERC License No. 2146                               71
          Table 14: Don Pedro, FERC License No. 2299                                 72
          Table 15: Feather River, FERC License No. 2100                             73
          Table 16: Haas-Kings River, FERC License No. 1988                          74
          Table 17: Hells Canyon, FERC License No. 1971                              75
          Table 18: Kerckhoff 1&2, FERC License No. 96                               76
          Table 19: Kerr, FERC License No. 5                                         77
          Table 20: North Fork, FERC License No. 2195                                78
          Table 21: North Umpqua, FERC License No. 1927                              79
          Table 22: Noxon Rapids, FERC License No. 2075                              80
          Table 23: Pit River, FERC License No. 233                                  81
          Table 24: Priest Rapids, FERC License No. 2114                             82
          Table 25: Rock Island, FERC License No. 943                                83
          Table 26: Rocky Reach, FERC License No. 2145                               84
          Table 27: Skagit River, FERC License No. 553                               85
          Table 28: Swift, FERC License No. 2111                                     86
          Table 29: Thompson Falls, FERC License No. 1869                            87
          Table 30: Upper American River Project, FERC License No. 2101              88
          Table 31: Upper North Fork Feather River, FERC License
                    No. 2105                                                         89


Figures   Figure 1: Locations of the 56 Largest FERC-Licensed Projects
                    That Use Federal Lands for Hydropower Production                  9
          Figure 2: The Estimated Annual Value for the Use of Federal Lands
                    Compared with FERC’s Annual Charges                              18
          Figure 3: Illustration of the Cost to Produce Hydropower Before
                    and After a Sale That Occurs as Part of Restructuring            33
          Figure 4: The Net Benefits Methodology                                     47




          Page ii                              GAO-03-383 FERC Charges for Federal Lands
Contents




Abbreviations

BCPS         Bath County Pumped Storage
BLM          Bureau of Land Management
CAPX         California Power Exchange
CCCT         combined-cycle combustion turbine
EIA          Energy Information Administration
FERC         Federal Energy Regulatory Commission
GAO          General Accounting Office
ID           irrigation district
IOU          investor-owned utility
IPP          independent power producer
kwh          kilowatt-hour
Muni         municipality
NBV          net book value
NHA          National Hydropower Association
O&M          operations and maintenance
PJM-WH       Pennsylvania, New Jersey, Maryland-Western Hub
PUD          Public Utility District
RCLPD        replacement cost less physical depreciation
SERC         Southeastern Electric Reliability Council
WECC         Western Electricity Coordinating Council



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Page iii                                      GAO-03-383 FERC Charges for Federal Lands
A
United States General Accounting Office
Washington, D.C. 20548



                                    May 20, 2003                                                                                  Leter




                                    The Honorable David L. Hobson
                                    Chairman
                                    The Honorable Peter J. Visclosky
                                    Ranking Minority Member
                                    Subcommittee on Energy and Water Development
                                    Committee on Appropriations
                                    House of Representatives

                                    The Honorable Charles H. Taylor
                                    Chairman, Subcommittee on Interior
                                    Committee on Appropriations
                                    House of Representatives

                                    The Federal Energy Regulatory Commission (FERC)—an independent
                                    fivemember commission appointed by the President and confirmed by
                                    the Senate—issues licenses to construct and operate many nonfederally
                                    owned hydropower projects, including 173 located on federal lands. These
                                    173 projects generate electricity worth billions of dollars annually.1

                                    The Federal Power Act requires FERC to establish and collect reasonable
                                    annual charges for the use of these federal lands. In doing so, FERC
                                    must take into account the effect of these charges on consumer rates
                                    and hydropower development. The act does not prescribe what value
                                    represents a reasonable annual charge; however, one criterion generally
                                    used for valuing land in both the public and private sectors is the land’s fair
                                    market value. In implementing the annual charge requirement, FERC stated
                                    that using the fair market value of the land is the most reasonable method
                                    for compensating the government for the use of its lands. Fair market value
                                    is generally defined as the price agreed to by a willing buyer and a willing
                                    seller, where both parties have reasonable knowledge of the relevant facts.
                                    Since federal lands are not generally sold, our estimate of fair market value
                                    in this report refers to the value of the annual economic contribution
                                    federal lands make to the production of hydropower.



                                    1
                                      For this report, we focused on the 173 projects that use 25 acres or more of federal land
                                    to produce hydropower. An additional 109 projects use fewer than 25 acres of federal
                                    land to produce hydropower. Also, we did not include projects that only use federal lands
                                    for the transmission of power. Finally, we did not include Indian reservations in our
                                    definition of federal lands.




                                    Page 1                                         GAO-03-383 FERC Charges for Federal Lands
The federal lands used to generate hydropower have considerable
value because of the advantages hydropower has over other sources
of electricity and because of the scarcity of lands that can be used
to generate hydropower. Compared with other sources of electricity
generation, hydropower is inexpensive to produce, its production can
be increased quickly in periods of peak demand, and it produces no
air pollution or radioactive wastes. There are also some disadvantages
to hydropower, such as the fact that (1) the amount of power produced is
limited to the amount of water available and (2) future regulatory actions
established through the relicensing of hydropower projects could,
among other things, limit the future quantity—or increase the cost—of
hydropower produced at some projects. While hydropower has some
advantages over other sources of electricity generation, lands that are
suitable for producing large amounts of hydropower are scarce. These
lands have unique characteristics, such as steep canyons, flowing rivers,
and/or the capability of storing large volumes of water. The more
hydropower the land is capable of producing, the greater the value of
the land.

The U.S. electricity industry is currently undergoing substantial
restructuring—from an industry that has historically been highly
regulated by federal and state governments to one that operates in a
more competitive environment. For example, FERC has historically
approved wholesale electricity prices—the prices charged when utilities
buy and sell power from other utilities within the same region of the
country—and state regulators have approved retail electricity prices, such
as those charged to residential and industrial consumers, principally on
the basis of production costs. However, some states have recently
restructured their retail electricity markets by allowing competition in
the generation segment of the industry. In some cases, regulated utilities
were required to sell many or all of their power plants in order to foster
competition. In restructured markets, prices are determined by supply
and demand. As a matter of policy, FERC encourages the movement
toward greater competition in wholesale energy markets. While some
states have plans to move in this direction, others do not.

As requested, this report addresses FERC’s system for developing
reasonable annual charges for the use of federal lands and the extent to
which this system reflects the contribution these lands make to the
generation of electricity. Specifically, we (1) describe the system FERC
currently uses for determining reasonable annual charges for the use of
federal lands by hydropower projects and assess FERC’s management of



Page 2                                GAO-03-383 FERC Charges for Federal Lands
that system; (2) estimate the fair market value for the use of these federal
lands and compare that value with the annual charges FERC currently
collects for the use of these lands; (3) discuss the implications for
consumers and hydropower project owners of having FERC collect annual
charges that more closely reflect the fair market value of the land; and
(4) discuss the implications of FERC’s not acting to collect charges that
more closely reflect fair market value until after restructuring of electricity
markets occurs.

To determine the fair market value of federal lands used by hydropower
projects, we examined a stratified random sample of 24 FERC-licensed
hydropower projects from a group of 56 projects. These 56 projects
collectively account for about 90 percent of the hydropower produced on
federal lands. Although our sample of 24 projects was not representative
of all hydropower projects on federal lands, these projects produced
about 60 percent of all the electricity generated by the FERC-licensed
hydropower projects that used federal land and represent about 35 percent
of all federal lands used to produce hydropower. We estimated the annual
value of the federal lands in our sample of projects using a technique
known as a “net benefits analysis.” A net benefits analysis estimates the
difference between the value of the power produced and the cost to
produce it. This difference is an estimate of the land’s annual fair market
value. We used the net benefits approach because there is no active market
for renting lands for hydropower that would provide comparable values
for these lands. With the exception of federal lands and lands within Indian
reservations, FERC generally requires licensees to either own the land
within their project boundaries or secure the land through an easement
in perpetuity.

We applied our net benefits methodology to our sample of projects under
six different scenarios. First, we conducted a net benefits analysis on the
basis of actual industry data for 3 recent years—1998, 1999, and 2000. In
general, to conduct these three analyses, we estimated the value of the
power by multiplying data on the average wholesale price of electricity
by the amount of electricity actually generated. To estimate the cost of
producing that power, we estimated project capital costs, including a rate
of return on the investment, and added this estimate to data on actual
operating costs for the same period. Second, to demonstrate how our
analysis can be affected by changes in the price and quantity of power
produced in any given year, we performed two sensitivity analyses on our
1999 results—one for changes in price and one for changes in quantity.
Finally, because the wholesale price of electricity was extremely volatile at



Page 3                                  GAO-03-383 FERC Charges for Federal Lands
                   times during the 3-year period—1998, 1999, and 2000—we estimated what
                   the fair market value of these lands might be in 2003 using (1) average
                   annual generation data for 1995 through 2000 and operating cost data for
                   1998 through 2000, (2) estimates of capital costs for 2003, and (3) estimates
                   of the long-term value of electricity. For comparison purposes, we adjusted
                   all values to 2002 constant dollars. We discussed our approach and the
                   results of our analysis with FERC, representatives of the hydropower
                   projects we sampled, industry associations, state governments, consumer
                   advocate groups, and several other federal agencies. Some of these
                   representatives expressed concerns about using this method, preferring
                   instead FERC’s current method because of its simplicity and relatively low
                   charges. We discuss additional details on our use of the net benefits
                   analysis in appendix I.



Results in Brief   Although FERC has acknowledged that using fair market value is the most
                   reasonable method for compensating the federal government for the use of
                   its land, since 1987, FERC has used a “linear rights-of-way” fee schedule
                   to determine annual charges for federal land used by hydropower projects.
                   This system—designed by the U.S. Department of Agriculture’s Forest
                   Service and the Department of the Interior’s Bureau of Land Management—
                   was originally used to determine the annual fees the two agencies should
                   charge for the rights to locate, among other things, power lines, pipelines,
                   and communications lines on federal land. The agencies base their specific
                   fees on the number of acres used. In implementing the linear rights-of-way
                   system, FERC acknowledged that hydropower project uses are more
                   valuable than rights-of-way. As a result, to capture these higher values,
                   FERC doubled the per-acre fees in the rights-of-way schedule and
                   multiplied that amount by the number of acres that were identified as being
                   federally owned within the hydropower project’s designated boundary.
                   FERC then collected these amounts as annual charges for the use of
                   federal lands by hydropower projects. FERC stated that the purpose of the
                   1987 annual charge system was to “establish a fair market rate” for the use
                   of federal lands. However, this system has no relationship to the economic
                   benefit of the federal lands used to produce hydropower. In addition,
                   according to FERC’s former Director of Hydropower, FERC chose this fee
                   system primarily because it was a simple and predictable method to use
                   and would not subject the commission to numerous court challenges from
                   the electricity industry.




                   Page 4                                 GAO-03-383 FERC Charges for Federal Lands
Since issuing its regulations in 1987, FERC has not performed the oversight
needed to ensure that (1) the charges it is collecting meet the hydropower
annual charge program objectives, (2) it has accurate information on the
amount of federal lands used by licensees, or (3) its billing system collects
all charges that are due the federal government for the use of its lands.
Specifically, FERC has not performed any research or analysis to assess
whether its fee schedule results in annual charges that are proportionate to
the benefits conferred. In addition, FERC allows licensees to self-report the
amount of federal acreage their projects use but does not verify any of this
information. Since FERC determines its annual charges on a per-acre basis,
having accurate and verified information on the amount of federal lands
licensees use is critical to collecting all monies that are due the
government. Finally, FERC has three separate databases it uses to
determine annual charges—two for determining the amount or type of
federal land used by a hydropower project and one for determining the
billing amount. These databases sometimes contain conflicting
information, which lead to billing errors and, in some cases, result in
FERC’s not collecting all the annual charges due the federal government.

The annual charges FERC currently collects for the use of federal lands
are significantly less than the value of the annual economic contribution
that these lands make to the production of hydropower, according to our
analysis of the 24 hydropower projects. That is, FERC is receiving less than
2 percent of the fair market value for the use of these lands. In total, the
estimated fair market value of the federal lands used by our sample of
24 hydropower projects is at least $157 million annually and, under some
market conditions, the value of these lands is worth hundreds of millions
of dollars more. In comparison, FERC collected about $2.7 million in
annual charges from these projects in 2002.

If FERC decides to collect annual charges that more closely reflect the
fair market value for the use of federal lands, the implications of such a
decision for consumers and hydropower project owners would depend on
(1) how much of the fair market value FERC chooses to recover and how
it decides to implement these higher charges and (2) whether the affected
electricity market is still fully regulated or has been restructured. First,
FERC must balance any increases in charges with the Federal Power Act’s
requirement to seek to avoid unreasonable increases in consumer rates
and the act’s goal of encouraging the development of hydropower. FERC
may therefore decide to collect only a portion of the fair market value of
the land as an annual charge. No matter how much more FERC decides
to charge, the impact of higher charges will depend in part on how FERC



Page 5                                 GAO-03-383 FERC Charges for Federal Lands
introduces them. FERC has options to mitigate the negative effects of
increasing annual charges, such as phasing in higher charges over several
years or tailoring the implementation to accommodate changes in the
regulatory structure of the industry. Second, in a regulated market, any
increases in FERC’s annual charges would most likely be passed on directly
to consumers through higher electricity rates. This impact would be most
evident for some utilities and their customers in locations such as Idaho,
Oregon, and Washington State, which rely heavily on FERC-licensed
hydropower projects to generate their electricity. Consumers who buy
power from these utilities have historically enjoyed some of the lowest
electricity rates in the country. Consequently, any increase in annual
charges to better reflect the fair market value of the federal land would
most likely increase rates to a level that would be closer to the national
average. In contrast, in a restructured environment, where electricity
rates are based on wholesale market prices, increased annual charges are
much more likely to affect the profitability of the electric utility and its
shareholders rather than consumers. In this restructured, competitive
environment, the utility may not be able to pass on any FERC increases in
annual charges to consumers. For this reason, consumers are less likely to
be affected.

If FERC decides not to collect annual charges that better reflect the fair
market value for the use of federal lands until after restructuring occurs,
it may (1) limit its opportunity to increase charges and (2) put taxpayers
at risk of losing a potential future stream of revenue. Specifically, in
restructured markets some utilities have been required to sell their
generation facilities, such as hydropower plants, in order to increase
competition. The price at which these plants sell includes the net benefits
resulting from the use of the federal land on which the project is located.
Once these plants are sold, the federal government may have limited ability
to capture these benefits because the new owner paid a price that included
the capitalized value of the land.2 Any further increase in costs, such as
increased annual charges, could make the cost of the project exceed the
value of the power produced. For example, Maine, Montana, and New York
have already restructured their wholesale electricity markets. In these
states, as projects were sold, the state or the previous owner captured all
of the projects’ expected net benefits. In Montana, where projects that



2
  The capitalized value of the land is the present value of the expected annual net benefits
over the future lifetime of the project.




Page 6                                          GAO-03-383 FERC Charges for Federal Lands
included federal land were sold, the federal government did not receive any
benefits from the sale even though the federal government owned some or
most of the land on which these projects were built. Furthermore, if FERC
continues to maintain annual charges at their current low level, this benefit
to some consumers will be at the expense of many other taxpayers, who
may have to make up this lost revenue through their taxes. As FERC has
observed in connection with annual charges assessed for the use of
government dams, an “overly low annual charge payment…ultimately
places higher costs on other consumer members of the public who must
make up the difference through their taxes.”3

In light of the new information we are providing on the value of the
contribution that federal lands make to the production of hydropower and
FERC’s policy to make all energy markets more competitive, we are
recommending that FERC develop new strategies and options for assessing
annual charges for the use of federal lands by hydropower projects that are
proportionate with the benefits conveyed to the licensees. As FERC
develops this strategy, we also recommend that it improve the management
of its current annual charge system.

We provided FERC, the Department of the Interior, the Forest Service,
and the National Hydropower Association (NHA)—a hydropower
industry group—with a draft of this report for their review and comment.
The Forest Service declined to comment. The Department of the Interior
agreed with the report and provided some technical clarifications
and observations. FERC generally agreed with our findings and
recommendations on the conflicting information in the databases it uses
to manage its annual charge system, but generally did not believe that
our method of assessing the value of federal lands used by hydropower
projects would be appropriate. FERC also raised concerns about using a
net benefits approach as a mechanism to collect annual charges. While we
recommend that FERC reassess its current annual charge system and
look for ways to better account for the value of federal lands, we do not
specifically recommend that FERC deploy our approach to value the land
as a mechanism for collecting annual charges. NHA disagreed with our
report and raised a number of concerns about increased annual charges.
For example, NHA commented that increased annual charges will increase
electricity rates to consumers, which could adversely affect the economy
of some states that benefit from low-priced hydropower. Our report


3
    See 48 Fed. Reg. 15134, 15136 (1983).




Page 7                                      GAO-03-383 FERC Charges for Federal Lands
             discusses this and notes that the impacts from increasing annual charges
             largely depend on (1) how much of the land’s value FERC decides to collect
             and how it implements any higher charges and (2) whether the affected
             electricity market is still fully regulated or has been restructured.



Background   Hydropower projects include dams, reservoirs, stream diversion
             structures, powerhouses containing turbines driven by falling water, and
             transmission lines. Lands capable of producing hydropower generally have
             unique characteristics, such as flowing water, steep canyons, and/or the
             ability to store large volumes of water for later release through the turbines
             that generate electricity. Nationwide, hydropower projects generate about
             10 percent of all electricity produced in the United States. Federally
             owned and operated hydropower projects produce approximately half
             of this electricity. Nearly all the remaining half is produced by about
             1,000 nonfederal hydropower projects that are licensed by FERC,
             about 173 of which use at least some federal lands to produce their
             hydropower.4 Of these 173 projects, 56 projects account for about
             90 percent of the hydropower produced on federal lands. From these
             56 projects, we selected a random sample of 24 hydropower projects which
             are the focus of this report. As figure 1 shows, most of the projects that use
             federal lands are located in the western United States due, in part, to the
             suitable topography found in many western states.




             4
               For this report, we focused on the 173 projects that use 25 acres or more of federal land to
             produce hydropower.




             Page 8                                          GAO-03-383 FERC Charges for Federal Lands
Figure 1: Locations of the 56 Largest FERC-Licensed Projects That Use Federal
Lands for Hydropower Production




    24 hydropower projects in our sample
    Other projects that use federal lands

Sources: FERC and GAO.



Section 10(e) of the Federal Power Act requires FERC to collect
“reasonable annual charges” to compensate the federal government for the
use of its lands.5 FERC must balance the amount of these annual charges
with the authorizing act’s requirement to seek to avoid unreasonable
increases in consumer rates and the act’s goal of encouraging the
development of hydropower. The act does not require FERC to collect the
fair market value of the federal land used by FERC-licensed hydropower
projects. However, fair market value is a common criterion used by both
the public and private sectors to value lands throughout the country, and, in
implementing the act, FERC stated that fair market value was the most
reasonable method of compensating the federal government for the use of
its lands. FERC further stated, “[r]easonable annual charges are those that




5
  Our review did not focus on FERC’s administration of its responsibilities under
section 10(e) of the Federal Power Act to establish annual charges for hydropower
projects occupying lands within Indian reservations.




Page 9                                       GAO-03-383 FERC Charges for Federal Lands
are proportionate to the value of the benefit conferred. Therefore, a fair
market value approach is consistent with the dictates of the act.”6 The act
also prescribes how revenues from annual charges are to be distributed:
50 percent go to the Reclamation Fund—a fund that pays for reclamation
projects, primarily in the western United States; 37.5 percent go back to the
states where the projects are located; and 12.5 percent is deposited in the
Treasury’s general fund. In addition, the act fully or partially exempts
hydropower projects owned by states or municipalities from paying annual
charges if the power is sold to the public without profit or used for
municipal purposes.

The value of any land is determined by using one of three approaches—the
comparable sales approach, the income approach, or the cost approach.
The comparable sales approach, which looks at transaction data for
comparable lands, cannot be used for hydropower projects because
(1) transaction data based on sales are not appropriate since these data
are largely based on nonhydropower uses and (2) data based on renting
or leasing nonfederal lands for hydropower uses are not available. FERC
requires licensees, as a condition of obtaining a FERC license, to own the
lands or obtain an easement in perpetuity from another landowner in order
to ensure a steady supply of hydropower. Federal lands and some Native
American lands are not subject to this requirement; however, licensees
must pay annual charges for using these lands. When there are few or no
transaction data available for comparable sales, the income approach can
be used, provided that reliable and sufficient data are available. The income
approach determines the value of a property or a business by considering
its income-producing potential. The cost approach estimates the value of a
property by adding (1) the current cost of reconstructing or replacing
existing improvements, less physical depreciation and (2) the estimated
value of the land. While the cost approach is generally considered less
reliable than the comparable sales or income approaches, some cost
approach techniques can be used to develop information needed by the
other two approaches. For our analysis, we used a variant of the income
approach—called a net benefits approach—to determine the value of
federal lands used by a sample of hydropower projects. However, instead
of using actual income from the hydropower projects—as a traditional
income approach would do—our net benefits analysis relied on the market
prices of the hydropower produced by these projects. We used market
prices because they reflect the value of power more accurately than


6
    See 52 Fed. Reg. 18201, 18205 (1987).




Page 10                                     GAO-03-383 FERC Charges for Federal Lands
electricity prices that are set through state regulatory processes. (For more
information on this approach, see app. I.)

The methodology for conducting a net benefits analysis is consistent with
standard economic theory and is based on long-established principles in
economics for valuing an asset that has unique characteristics. Specifically,
with a net benefits analysis, the value of the land is the benefit that remains
after subtracting all nonland costs of production, including returns on
the owner’s investment, from the value of the power produced. This
methodology for valuing land has been accepted and used by FERC and
the electricity industry as a basis for annual charges in certain instances
in the past. For example, FERC has approved annual charges for Native
American lands occupied by hydropower projects in which the net benefits
method was a basis for the annual charge. In addition, FERC used a similar
methodology for a period of time to determine annual charges when
private operators attached powerhouses to federal government dams to
produce hydropower.

We performed our analysis on a random sample of 24 FERC-licensed
hydropower projects that use federal lands. The value of each project
varies considerably from year to year, depending on the prevailing price of
electricity, the amount of water available, and restrictions that may be put
on the project’s use. In addition, each project differs from the others
according to the topography of the land and the primary purpose of the
project. For example, some projects are “run-of-the–river” projects,
meaning that they depend on stream flow to operate, while others have
large reservoirs to store water for later use. Projects with large storage
reservoirs can operate to maximize revenues by generating power during
periods of high demand when wholesale prices are high. Run-of-the-river
projects cannot do this, since they depend on stream flow to generate
power. Finally, other projects have primary purposes other than
hydropower generation, such as flood control, irrigation, and municipal
and industrial water supply. These other uses greatly affect the net benefits
of the project over the years. We did not attempt to estimate the value of
the federal lands used for purposes other than hydropower. Table 1
presents the name, location, and owner of each of the 24 projects included
in our sample.




Page 11                                 GAO-03-383 FERC Charges for Federal Lands
Table 1: Hydropower Projects Included in Our Sample

Project (FERC license no.)                                 Location        Owner
Bath County (2716)                                         Virginia        Dominion Virginia Power & Allegheny Power
Big Creek 1 & 2 (2175)                                     California      Southern California Edison
Bliss (1975)                                               Idaho           Idaho Power
Boundary (2144)                                            Washington      City of Seattle
California Aqueduct (2426)                                 California      California and Los Angeles Departments of Water
Coosa River (2146)                                         Alabama         Alabama Power
Don Pedro (2299)                                           California      Turlock and Modesto Irrigation Districts
Feather River (2100)                                       California      California Department of Water Resources
Haas-Kings River (1988)                                    California      Pacific Gas and Electric
Hells Canyon (1971)                                        Idaho/Oregon    Idaho Power
Kerckhoff 1 & 2 (96)                                       California      Pacific Gas and Electric
Kerr (5)                                                   Montana         Pennsylvania Power and Light Montana
North Fork (2195)                                          Oregon          Portland General Electric
North Umpqua (1927)                                        Oregon          Pacificorp
Noxon Rapids (2075)                                        Idaho/Montana   Avista Corporation
Pit River (233)                                            California      Pacific Gas and Electric
Priest Rapids (2114)                                       Washington      Grant County Public Utility District
Rock Island (943)                                          Washington      Chelan County Public Utility District
Rocky Reach (2145)                                         Washington      Chelan County Public Utility District
Skagit River (553)                                         Washington      City of Seattle
Swift (2111)                                               Washington      Pacificorp
Thompson Falls (1869)                                      Montana         Pennsylvania Power and Light Montana
Upper American River Project (2101)                        California      Sacramento Municipal Utility District
Upper North Fork Feather River (2105)                      California      Pacific Gas and Electric
Sources: FERC and the Energy Information Administration.




                                                            Page 12                     GAO-03-383 FERC Charges for Federal Lands
FERC’s System for            While FERC has recognized that using the fair market value of land is a
                             reasonable approach for determining annual fees, it currently uses a fee
Determining                  system designed for linear rights-of-way uses to determine annual charges
Annual Charges               for hydropower projects using federal lands. The linear rights-of-way fee
                             system was designed by the U.S. Forest Service and the Bureau of Land
Is Based on Values           Management (BLM) to collect fees for federal lands used for power lines,
for Rights-of-Way,           pipelines, and communications lines. However, this system has no
Not Hydropower               relationship to the economic benefit of the federal lands used to produce
                             hydropower. In addition, according to FERC’s former Director of
                             Hydropower, FERC chose to use this system because it was simple,
                             predictable, and would not subject the commission to numerous court
                             challenges from the electricity industry. This official also stated that FERC
                             did not have the specialized staff needed to develop its own system.
                             However, FERC has not diligently managed this fee system to ensure that
                             (1) the charges it currently collects meet the hydropower annual charge
                             program objectives, (2) it has accurate information on the amount of
                             federal lands used by licensees, or (3) its billing system collects all charges
                             that are due the federal government for the use of its lands.



FERC Currently Uses a        The Federal Water Power Act was passed in 1920—which became the
Modified Rights-of-Way Fee   Federal Power Act in 1935—and since 1938 FERC has used a number of
                             methods for determining annual charges for the use of federal lands by
Schedule for Determining     hydropower projects including appraisals and national average land
Annual Charges for           values. In the 1960s, FERC calculated annual charges based on a national
Hydropower Projects          average land value. This method resulted in annual land use charges of
                             $10.31 per acre in 1979. In 1981, the Department of Energy’s Office of the
                             Inspector General reported that this method resulted in “unreasonably
                             low and inequitable” annual charges because (1) FERC based the charges
                             on out-dated land value information and (2) FERC was using land
                             values based on a nationwide average, which led to undervaluing many
                             hydropower lands.7 In response, in 1987, FERC amended its regulations
                             under the Federal Power Act to, among other things, revise its
                             methodology for assessing federal land use charges. Specifically,
                             FERC implemented a modified version of the Forest Service/BLM
                             rights-of-way fee schedule for determining reasonable annual charges for
                             hydropower projects.


                             7
                               See Department of Energy, Assessment of Charges Under The Hydropower Licensing
                             Program, DOE/IG-0178 (Dec. 22, 1981).




                             Page 13                                   GAO-03-383 FERC Charges for Federal Lands
The Forest Service/BLM fee schedule charges annual per-acre fees on the
basis of regional land values and the number of acres used. Recognizing
that federal lands used for rights-of-way are generally less valuable than
those used for hydropower project purposes, FERC modified the schedule
by doubling the fees and then multiplying that amount by the number of
acres that were identified as being federally owned within project
boundaries. The commission reasoned that fees for rights-of-way uses
on federal lands should be lower than fees charged for hydropower uses
because land used for rights-of-way remain available for other multiple
uses—such as mining, grazing, and cutting timber—while lands used for
hydropower are not available for these types of uses. However, FERC
officials said that they have not conducted any detailed research or analysis
to determine whether doubling the fees in the rights-of-way schedule
resulted in a reasonable annual charge for the use of federal lands for
hydropower production.

The Forest Service and BLM developed their fee schedule system by
collecting market data on land values throughout the nation. Using these
data, the agencies produced a system in 1986 that based annual fees on the
number of acres used, the location of the land, and the type of right-of-way
requested. However, in 1996, we reported that these values did not consider
several factors critical to establishing land values that reflect fair market
value. Specifically, they did not reflect what the land was being used for,
the “highest and best” use of the land, or the values of any urban uses.8
Forest Service officials acknowledged that the fees were too low and said
that the data collected to generate the land values used in the fee schedule
system represent the low end of the market. According to these officials,
the agency’s fee system may be collecting as little as 10 percent of the fair
market value of the federal lands used for rights-of-way purposes. While
the Forest Service agreed with the findings and recommendations of our
1996 report, to date, the agency has yet to revise its rights-of-way fee
schedule system—largely because it has not placed a high priority on
completing this task.

According to a former FERC director of hydropower, FERC adopted the
Forest Service/BLM fee schedule system to determine annual charges for
using federal lands primarily because it was simple and predictable, and
would not subject the Commission to numerous appeals from industry.


8
  See U.S. General Accounting Office, U.S. Forest Service: Fee System for Rights-of-Way
Program Needs Revision (GAO/RCED-96-84, Apr. 22, 1996).




Page 14                                       GAO-03-383 FERC Charges for Federal Lands
                          Adopting the rights-of-way fee system accomplished these goals because it
                          is billed on a per-acre basis, its fees are annually updated based on the
                          Consumer Price Index, and the fees are low enough to make court
                          challenges from the electricity industry unlikely. In addition, in 1987 when
                          FERC was selecting a new fee system, it did not have the staff, such as
                          appraisers and economists, needed to determine the value of the federal
                          lands used for hydropower production and to design an original fee system.
                          As a result, adopting the Forest Service/BLM fee schedule provided an
                          opportunity to increase overall fees without having to develop a new
                          schedule based on hydropower land values.



FERC Has Not Diligently   Since issuing the regulations in 1987, FERC has not performed the
Managed Its Current       oversight needed to ensure that (1) the charges it collects meet the
                          hydropower annual charge program objectives, (2) it has accurate
Fee System
                          information on the amount of federal lands used by licensees, or (3) its
                          billing system collects all charges due the federal government for the use
                          of its lands. Federal internal control standards require agencies to measure
                          and monitor program performance to be reasonably sure that the program
                          is meeting its objectives.9 However, FERC has neither measured nor
                          monitored its current fee system to determine if the charges it currently
                          collects meet program objectives. Specifically, in the 15 years since FERC
                          implemented the current fee system, it has never assigned staff—such as
                          economists and appraisers—to determine if the system is collecting
                          reasonable annual charges. Consequently, FERC cannot demonstrate
                          whether its current annual charges for the use of federal lands are
                          reasonable or need adjustment. During the course of our review, FERC’s
                          executive director agreed that an assessment of the current system would
                          be appropriate.

                          Federal internal control standards also require agencies to establish and
                          implement policies and procedures to reasonably ensure that valid and
                          reliable data are obtained on the operations of the programs they manage.
                          However, FERC allows licensees to self-report the total federal acreage
                          that they use to produce hydropower and makes no attempt to verify this
                          information. As a result, FERC does not know if it is receiving valid and
                          reliable information from the hydropower licensees.



                          9
                            See U.S. General Accounting Office, Standards for Internal Control in the Federal
                          Government (1999).




                          Page 15                                       GAO-03-383 FERC Charges for Federal Lands
                     Finally, FERC is hampered in its effort to analyze the licensees’ information
                     because its databases contain differing and, at times, directly conflicting
                     information about hydropower projects on federal lands. FERC uses at
                     least three separate databases to determine annual charges for the use of
                     federal lands by hydropower projects. One database contains information
                     on the types of federal lands on which the hydropower projects are located,
                     another contains data on the number of acres of federal land the
                     hydropower projects use, and the third database contains information on
                     the billing amounts. Our analysis of these databases showed that some
                     projects were not billed when they should have been while others were
                     sent bills when they should not have been. For example, according to
                     FERC, project owners are not to begin receiving bills for the use of federal
                     lands until they have begun construction of the hydropower project.
                     However, we found several instances in which FERC’s databases indicate
                     that the agency sent bills for annual charges to applicants for hydropower
                     project licenses, including to some applicants whose projects were never
                     built. In addition, we found that FERC had not billed a very large project in
                     Idaho for the use of federal lands for 2 years, resulting in a total loss in
                     annual charges of about $30,000 for 1999 and 2000. We made numerous
                     attempts to reconcile the inconsistent data in FERC’s multiple databases.
                     However, most of these attempts resulted in still more contradictions
                     concerning what information was correct. Consequently, while we have
                     identified several problems with FERC’s billing system, we could not
                     determine the extent of FERC’s billing problems.



Many Federal Lands   FERC’s annual charges are significantly less than the value of the
                     annual economic contribution that federal lands make to the production
in Our Sample Are    of hydropower. We estimate that the annual fair market value for the use of
Significantly More   the federal lands used by the 24 hydropower projects in our sample was at
                     least $157 million. However, under FERC’s modified linear rights-of-way
Valuable Than        fee schedule, these 24 projects paid about $2.7 million in annual charges to
FERC’s Current       the federal government in 2002. Because electricity markets are volatile,
Charges Suggest      we performed a net benefits analysis under six different market conditions,
                     with each analysis yielding a similar result: FERC is currently collecting
                     annual charges that are less than 2 percent of the annual contribution that
                     these lands make to the production of hydropower. This result holds true
                     even though the value of federal lands at individual projects varied
                     considerably from year to year.




                     Page 16                                GAO-03-383 FERC Charges for Federal Lands
Federal Lands Used by      Since wholesale electricity markets are volatile—for example, prices are
Hydropower Projects Have   very high in some years and very low in others—we estimated the fair
                           market value of federal lands used by our sample of 24 hydropower
Significant Value          projects using six different scenarios:

                           • examining historical industry data for 1998, 1999, and 2000, on the cost
                             and value of power generated by our sample of projects;

                           • performing both price and quantity sensitivity analyses on the results of
                             our 1999 analysis, the most moderate of these years; and

                           • developing an estimate of what the value of these federal lands might be
                             in 2003.

                           Figure 2 shows the results of our analysis of the six different scenarios and
                           compares those values with FERC’s annual charges for 2002.




                           Page 17                                GAO-03-383 FERC Charges for Federal Lands
                             Figure 2: The Estimated Annual Value for the Use of Federal Lands Compared
                             with FERC’s Annual Charges

                             1,800     Dollars in millions

                             1,700

                             1,600

                             1,500


                               600

                               500

                               400

                               300

                               200

                               100

                                 0

                                       1998      1999             1999                  1999   2000          2003
                                                                                                         estimate
                                       Calendar years
                                                                                       ity
                                                                                 itiv
                                                               tyvi



                                                                                   s
                                                                           sis sen
                                                        sis siti
                                                     aly en



                                                                        aly ty
                                                   an ice s



                                                                      an anti
                                                                       Qu
                                                    Pr




                                               2002 FERC annual charges ($2.7 million)

                             Source: GAO.


                             Note: All data are in 2002 dollars. Also, we did not perform this analysis for 2001 or 2002.




Fair Market Value Based on   According to the historical industry data we examined for 1998, 1999,
Actual Data for 1998,1999,   and 2000, the supply and demand for power varied substantially, and
                             the wholesale price of electricity varied accordingly. These data
and 2000
                             included one year (1998) of relatively low prices and one year (2000)
                             of extraordinarily high prices. These changes in the wholesale price of
                             electricity resulted in widely differing values for the federal lands used to
                             produce hydropower. Specifically, the estimated value of federal lands for
                             our sample projects was $157 million in 1998, $280 million in 1999, and
                             $1.7 billion in 2000.




                             Page 18                                                              GAO-03-383 FERC Charges for Federal Lands
The estimated value for the use of federal lands during these 3 years
varied primarily in response to changes in the average wholesale price
of electricity. For example, an abundant supply of rain in portions of the
western United States in 1998 produced a supply of hydropower in those
states that was well above historical averages. The elevated supply of
electricity contributed to the relatively low wholesale electricity prices
for that year. Prices in 1999 were still somewhat low in the West. In 2000,
the wholesale price of electricity was extremely high. Causes for the high
prices included fast-growing demand, slow-growing supply, and unusually
dry and warm weather in the region, which led to the decreased availability
of electricity in California and other western states. California state
officials and others also claimed that wholesale suppliers of electricity
were exercising market power10 to raise prices above competitive levels.
Table 2 shows the results of our analysis for 1998, 1999, and 2000 and
compares these results with FERC’s annual charges for 2002. Each of these
estimates represents the value for the use of the land based on the price
of electricity, including the potential exercise of market power, and other
market conditions that existed during that year. In the longer term, the fair
market value for the use of the land in a competitive market cannot be
consistently based on electricity prices that are higher than the cost of
alternative means of producing electricity. As a result, the unusually high
values during 2000 could not be sustained. Such high prices would provide
a strong incentive for investors to build new electricity generating plants
that would drive down the price of electricity to the cost of that alternative
source thereby limiting the fair market value for the use of the land.




10
  In this context, market power refers to the ability of individual sellers of electricity
to charge prices above competitive levels. For more information on the electricity
market in California, see U.S. General Accounting Office, Restructured Electricity
Markets: California Market Design Enabled Exercise of Market Power, GAO-02-828,
(June 21, 2002).




Page 19                                          GAO-03-383 FERC Charges for Federal Lands
Table 2: The Estimated Annual Value for the Use of Federal Lands for Each of the 24 Projects in Our Sample for 1998, 1999, and
2000; and FERC Annual Charges for 2002

Dollars in thousands
                                                                                                                                          2002 FERC
                              1998 value                         1999 value                            2000 value                             annual
Project name               of federal lands                   of federal lands                      of federal lands                         charges
Hells Canyon                          $111,336                               $145,857                              $602,751                       $371
Boundary                                 26,606                                 67,362                              297,597                          34
Priest Rapids                            11,665                                 24,129                                92,322                         49
Big Creek 1 & 2                           4,865                                   6,184                               96,303                        154
Bliss                                     1,972                                   3,399                               25,470                         16
Rocky Reach                                   775                                 1,819                                7,408                           3
Rock Island                                   139                                   596                                3,082                           1
Kerr                                          102                                   339                                2,563                           2
Coosa River                                     1                 ($34)                                ($86)                                           7
Thompson Falls              ($246)                                                  349                                5,772                           4
Swift                        (338)                                                  318                                3,369                         19
North Fork                    (408)                                                 832                                7,530                           7
Noxon Rapids                  (715)                                                 410                                7,872                         22
Upper North
Fork Feather
River                         (867)                               (517)                                                6,236                         85
Pit River                   (1,380)                                               2,535                               54,400                         49
Kerckhoff 1 & 2             (3,371)                             (4,515)                                               43,344                         25
Don Pedro                   (5,332)                             (6,587)                                                6,905                        249
Feather River               (6,119)                             (6,132)                                               34,847                           9
North Umpqua               (13,922)                             (4,731)                                               84,937                        108
Bath County                (14,682)                                             10,228               (1,294)                                         48
Haas-Kings
River                      (19,006)                            (22,205)                                               69,049                        202
Skagit River               (22,991)                                             15,290                              165,137                         917
California
Aqueduct                   (27,025)                            (22,210)                                                1,793                         17
Upper American
River                      (39,178)                            (34,344)                                               68,687                        286
Total of positive values              $157,460                               $279,648                           $1,687,376                      $2,685
Source: GAO.

                                              Note: All data are in 2002 dollars. Also, as discussed in the text below, the totals in this table do not
                                              include projects with negative values. More detailed results of our net benefits analysis for each project
                                              in our sample are included in app. II. Finally, FERC annual charges are based on the number of federal
                                              acres within the designated boundary of a hydropower project.




                                              Page 20                                               GAO-03-383 FERC Charges for Federal Lands
Some of the values in table 2 were negative, and we did not include those
values in the totals. The negative values are the result of our methodology
and assumptions and imply that, during the specific years with such values,
the return on investment was less than the industry average of 7.22 percent
that we assigned as part of each project’s costs.11 Negative values do not
mean that the land is valueless or that annual charges should be negative.
Rather, the fact that individual owners and investors choose to continue to
operate these facilities demonstrates that the land has value. For the
projects that had negative values, the return during those years was not
equivalent to what would have been earned in other investment options
with similar risk. With one exception, the projects with negative net
benefits actually had a positive estimated return on investment that
ranged from 6.8 percent to 0.1 percent.12 That is, for all but one of the
projects with negative net benefits, the value of power exceeded all the
costs of producing the power and still provided some positive return on
investment. If these low rates of return were to be sustained, the owners
of these projects would cease operations, and the land for hydropower
purposes would be worth zero in the worst case.

For most of the projects in our sample, the negative net benefits also
occurred because of very low electricity prices and/or overestimated
capital costs. While the cost to operate a hydropower project generally
remains stable, low electricity prices can dramatically reduce revenues
and thereby reduce or eliminate any net benefit for that year. For some of
our sample projects, a negative net benefit estimate may also mean that
the project was built for other purposes, such as irrigation. As such, the
capital costs of the project include the costs associated with both
irrigation and hydropower production. For these projects, other purposes
are emphasized over the production of hydropower. For example, the Don
Pedro Project in California is part of an irrigation project that favors storing
water for later consumption over releasing water to generate power. As a
result, the revenue potential from hydropower operations is not maximized
and the project has a minimal or negative net benefit.




11
     For greater detail on how we determined costs for this analysis, see app. I.
12
     For our estimate of the return on investment for each project, see app. II.




Page 21                                            GAO-03-383 FERC Charges for Federal Lands
Fair Market Value of Federal   We used our analysis of 1999 industry data to perform our sensitivity
Lands Sensitivity Analysis     analyses because that year was the most moderate of the 3 recent years of
                               actual historical data that we reviewed. The sensitivity analyses illustrates
Based on Our Analysis of       the effect that uncertainty in two key variables—price and quantity—has
1999 Data                      on our estimates of the value of federal lands. In performing these analyses,
                               we developed benchmarks for the (1) price and (2) quantity of power
                               produced. Specifically, our price benchmark is based on estimates of the
                               long-term value of power and our quantity benchmark is based on
                               historical averages. We then calculated the change in the hydropower
                               projects’ net benefits in 1999 when (1) wholesale prices for electricity were
                               increased to the benchmark, but everything else stayed the same and
                               (2) the quantity of power produced by the projects was decreased to the
                               benchmark, but everything else remained the same.

                               Our analysis indicated that the value of federal lands is sensitive to
                               changes in both the price of electricity and the amount of power generated.
                               For example, had average prices in 1999 been about 8 percent higher,
                               equivalent to the estimated cost of electricity from the lowest cost
                               alternative source, net benefits would have risen from $280 million to
                               $351 million. (We used the cost of electricity from a combined-cycle
                               combustion turbine generator as our benchmark for the estimated
                               long-term value of power because it is generally the lowest cost alternative
                               to most hydropower generation.)13 On the other hand, if hydropower
                               generation in 1999 had been about 10 percent lower, at about the average
                               level of generation over the past two decades in California, net benefits
                               would have been about $218 million. (We used this two-decade average as
                               our benchmark for the quantity of electricity.) Table 3 shows the results of
                               our sensitivity analyses in relationship to the results of our 1999 analysis.




                               13
                                 Over the long-term, a combined-cycle combustion turbine (CCCT) technology, that
                               primarily utilizes natural gas as a fuel, is generally considered the lowest cost alternative for
                               electric power from a hydropower project that runs most of the time. Significant changes
                               in the relative prices of fossil fuels could make another technology more economic. For
                               example, if gas prices are expected to rise significantly, a coal-fired power plant technology
                               may supplant CCCT as the lowest-cost alternative. However, this would make hydropower
                               relatively more valuable.




                               Page 22                                          GAO-03-383 FERC Charges for Federal Lands
Table 3: Results of Our Sensitivity Analyses of Each of the 24 Projects in Our Sample—1999, 1999 with a Change in Price, and
1999 with a Change in Quantity

Dollars in thousands
                                                                                1999 value                                 1999 value
                                       1999 value                           of federal lands—                      of federal lands—quantity
Project name                        of federal lands                         price sensitivity                             sensitivity
Hells Canyon                                        $145,857                                   $176,837                                    $121,831
Boundary                                               67,362                                     82,356                                      55,733
Priest Rapids                                          24,129                                     28,554                                      20,697
Skagit River                                           15,290                                     26,123                                       6,888
Bath County                                            10,228                                     10,228                                       3,029
Big Creek 1 & 2                                         6,184                                      9,744                                       3,423
Bliss                                                   3,399                                      4,764                                       2,341
Pit River                                               2,535                                      4,689                                          865
Rocky Reach                                             1,819                                      2,182                                       1,538
North Fork                                                832                                       1,291                                         477
Rock Island                                               596                                         752                                         476
Noxon Rapids                                              410                                         874                                          50
Thompson Falls                                            349                                         630                                         131
Kerr                                                      339                                         447                                         254
Swift                                                     318                                         586                                         111
Coosa River                             ($34)                                     ($40)                                       ($46)
Upper North Fork Feather
River                                   (517)                                     (263)                                       (713)
Kerckhoff 1 & 2                       (4,515)                                   (3,087)                                     (5,622)
North Umpqua                          (4,731)                                                         899                   (9,098)
Feather River                         (6,132)                                   (3,558)                                     (8,128)
Don Pedro                             (6,587)                                   (5,316)                                     (7,573)
Haas-Kings River                     (22,205)                                  (20,154)                                   (23,796)
California Aqueduct                  (22,210)                                  (20,602)                                   (23,457)
Upper American River                 (34,344)                                  (27,659)                                   (39,529)
Total of positive values                            $279,648                                   $350,956                                    $217,844
Source: GAO.

                                          Note: All data are in 2002 dollars. Details on how we conducted our sensitivity analyses of 1999 data
                                          are included in app. I. Also, as previously discussed, the totals in this table do not include projects with
                                          negative values.




                                          Page 23                                                GAO-03-383 FERC Charges for Federal Lands
Estimated Fair Market Value   We developed an estimate for 2003 by (1) using our benchmark
of Federal Lands in 2003      estimate of the value of power, (2) using recent averages for the quantity
                              of power produced, (3) using recent averages for operating costs, and
                              (4) developing an estimate of capital costs for 2003. This estimate is
                              about $386 million, and it reflects what the value for the use of federal
                              lands would be using more typical values for the price and quantity of the
                              power produced. However, this estimate is subject to the uncertainties
                              that exist in electricity markets, including weather, changes in electricity
                              demand or supply, the costs of alternative fuels such as natural gas, and
                              future regulatory constraints, among other factors. Table 4 shows the
                              results of this analysis and FERC’s annual charges for 2002. Overall, the
                              table shows that FERC’s annual charges for the use of federal lands are
                              significantly below the fair market value of these lands.




                              Page 24                                GAO-03-383 FERC Charges for Federal Lands
Table 4: The Estimated Annual Value for the Use of Federal Lands for Each of the 24 Projects in Our Sample for 2003, and
FERC Annual Charges for 2002

Dollars in thousands

                                                                                    2003 value                                        2002 FERC
Project name                                                                     of federal lands                                 annual charges
Hells Canyon                                                                                    $194,221                                        $371
Boundary                                                                                           85,120                                          34
Priest Rapids                                                                                      28,206                                          49
Big Creek 1 & 2                                                                                    20,730                                        154
Skagit River                                                                                       20,497                                        917
Bath County                                                                                        12,067                                          48
Bliss                                                                                                5,733                                         16
Pit River                                                                                            5,064                                         49
Kerckhoff 1 & 2                                                                                      3,973                                         25
North Umpqua                                                                                         2,305                                       108
Rocky Reach                                                                                          2,013                                          3
Noxon Rapids                                                                                         1,382                                         22
North Fork                                                                                           1,269                                          7
Rock Island                                                                                            732                                          1
Thompson Falls                                                                                         687                                          4
Swift                                                                                                  572                                         19
Kerr                                                                                                   556                                          2
Feather River                                                                                          229                                          9
Upper North Fork Feather River                                                                         207                                         85
Coosa River                                                                                               2                                         7
Don Pedro                                                           ($5,635)                                                                     249
Haas-Kings River                                                      (6,815)                                                                    202
Upper American River                                                (15,175)                                                                     286
California Aqueduct                                                 (20,029)                                                                       17
Total of positive values                                                                        $385,563                                      $2,685
                                           Source: GAO.

                                           Note: All data are in 2002 dollars. Also, as previously discussed, the totals in this table do not include
                                           projects with negative values.




                                           Page 25                                               GAO-03-383 FERC Charges for Federal Lands
Most of the Lands Used by   Our analyses for 1998, 1999, 2000, and 2003 found that the lands in our
Individual Projects in      sample are worth significantly more than FERC currently charges for most
                            years and for most projects. However, for each project, the value of the
Our Sample Are Worth        federal land can change dramatically with a significant change in supply
Significantly More Than     and demand for electricity. For example, as discussed earlier, in some years
FERC Currently Charges      when electricity prices are low, the value of power is so low that a project
                            produces a negative net benefit.

                            In general, for the years we examined, we found the following differences
                            among the projects in our sample:

                            • In 1998, prices were so low that the value of the power produced by
                              15 of the 24 projects was less than the cost to produce the power—
                              including a 7.2 percent rate of return—resulting in a negative net
                              benefit. The lands associated with the remaining nine projects were
                              estimated to be worth $157 million.

                            • In 1999, electricity prices were somewhat higher than in 1998 but still
                              low from a historical perspective. As a result, the lands associated with
                              15 of the 24 projects were estimated to be worth $280 million, while the
                              remaining 9 projects had negative net benefits.

                            • In 2000, the electricity crisis in the West drove prices to extraordinarily
                              high levels. As a result, 22 projects had lands estimated to be worth
                              about $1.7 billion, and only two projects in our sample had a negative
                              net benefit.

                            • For 2003, we estimated that the federal lands in 19 of the 24 projects
                              would be worth about $386 million and that the federal lands within the
                              remaining projects would be worth little, if anything, for hydropower
                              uses above what they currently pay in annual charges.14

                            For 2003, of the 19 projects whose federal lands are worth significantly
                            more than current annual charges suggest, five projects are on federal
                            lands worth exceptionally more. We estimate the lands in these five
                            projects to be worth about $349 million annually, or about 90 percent of the
                            value of all of the lands in our sample of 24 projects. FERC currently

                            14
                              Three of these five projects were built for purposes other than hydropower, such as
                            irrigation, one had high capital costs, and one had less than 1 percent of its project on
                            federal lands.




                            Page 26                                         GAO-03-383 FERC Charges for Federal Lands
                              collects annual charges totaling about $1.5 million from these five projects,
                              but our analysis estimates that the land in each project is worth from
                              $20 million to $193 million more than what FERC currently charges.
                              These five projects are

                              • Hells Canyon (Idaho Power) in Idaho,

                              • Boundary (City of Seattle),

                              • Skagit River (City of Seattle),

                              • Priest Rapids (Grant County Public Utility District) in Washington State,
                                and

                              • Big Creek 1 & 2 (Southern California Edison) in California.

                              These projects are among those that (1) generated the largest volume of
                              electricity, (2) had the lowest level of capital costs, and/or (3) used the
                              highest percentage of federal lands. However, three of these projects are
                              owned by municipalities (Boundary, Skagit River, and Priest Rapids).
                              Section 10(e) of the Federal Power Act exempts licensees for state and
                              municipal power projects from paying annual charges to the extent project
                              power is sold to the public without profit or for state or municipal
                              purposes. Each of these three projects received a partial exemption in the
                              recent past that reduced their annual charges by about 9 percent for
                              Boundary and Skagit River, and about 35 percent for Priest Rapids.



Limitations of Our Analysis   Our estimates of the fair market value of federal lands used to produce
                              hydropower are subject to a number of uncertainties that can affect
                              the price or quantity of hydropower produced. Changes in the weather,
                              regulatory constraints, or the cost of fuels can dramatically affect
                              electricity markets. Weather and rainfall patterns can affect the
                              supply, price, and demand for electricity. For example, a hot, dry spring
                              season will increase the demand for power and, at the same time, reduce
                              the availability of hydropower. In addition, future regulatory actions
                              established through the relicensing of hydropower projects could, among
                              other things, limit the future quantity—or increase the cost—of
                              hydropower produced at some projects. Furthermore, electricity
                              markets are influenced by the cost of fuels, such as coal and natural gas,
                              used to generate electricity at non-hydropower-generating plants. These
                              uncertainties are best illustrated by the dramatic changes in the fair market



                              Page 27                                GAO-03-383 FERC Charges for Federal Lands
                         value of the lands between 1998 and 2000. Finally, our analysis is also
                         limited by the lack of available historical data on wholesale electricity
                         prices because active markets have been in operation for only a few years.
                         We cannot quantify the impact of these uncertainties on our overall
                         estimates. However, it remains clear that, no matter how volatile the
                         market, the federal lands used by our sample of projects to produce
                         hydropower are worth significantly more than FERC’s current annual
                         charges indicate.



Effect of Higher         If FERC decides to collect annual charges that more closely reflect the
                         fair market value for the use of the land, the effects on consumers and
Annual Charges on        project owners will depend on (1) how FERC chooses to implement these
Consumers and            higher charges and (2) whether the electricity industry in the state where
                         the project is located has been restructured.
Project Owners Will
Depend on FERC’s
Implementation
and the Regulatory
Environment

Impacts Will Depend on   When considering the actions it could take to revise its annual charge
FERC’s Implementation    system, FERC must balance any increases in charges with the Federal
                         Power Act’s requirement to seek to avoid unreasonable increases in
                         consumer rates, and the act’s goal of encouraging the development of
                         hydropower. FERC may therefore decide to collect only a portion of the
                         fair market value of the land as an annual charge. Clearly, if FERC
                         decides to continue charging a small portion of the fair market value
                         of federal lands, then the impact on hydropower project owners and
                         consumers will be minimal. However, if FERC decides to collect a
                         much higher percentage of the fair market value of federal lands as an
                         annual charge, then project owners and/or consumers could be
                         significantly affected.

                         If FERC increases annual charges to 100 percent of the fair market value
                         for the use of the land, then the electricity rates of some utilities could
                         experience significant increases. These utilities would include those that
                         rely heavily on FERC-licensed hydropower, such as those in states like




                         Page 28                                GAO-03-383 FERC Charges for Federal Lands
Idaho, Oregon, and Washington. For example, one Idaho Power project in
our sample—Hell’s Canyon—uses federal lands that we estimated would be
worth about $146 million in 1999. If 100 percent of the estimated value of
these federal lands became FERC’s basis for its annual charges, then the
total cost to operate all of Idaho Power would increase by about
25 percent, from about $580 million to about $726 million.15 Because Idaho
Power operates under state regulation, this cost increase for the Hell’s
Canyon project would probably be passed on to Idaho Power’s customers
through higher rates. We did not include in our sample all of the
hydropower projects that Idaho Power owns and that use federal lands.
Therefore, Idaho Power’s costs could increase even more than the increase
for the Hell’s Canyon project if FERC decides to increase annual charges to
100 percent of fair market value for these other projects. However, the
Hell’s Canyon hydropower project alone accounts for about 70 percent of
all of Idaho Power’s hydropower generating capacity. Consequently, the
additional costs for the other projects are not likely to be as sizable.

Large increases in electricity rates can, in the short term, harm the
economies of the areas the utility serves. Consumers would pay not only
more for their household electricity, but they would also tend to pay more
for other goods and services, as local businesses pass on increased
electricity costs to consumers. In addition, according to officials from the
Idaho Public Utility Commission, increases in electricity rates of 20 percent
or more could reduce or eliminate the incentive for businesses to relocate
to or remain in Idaho and would therefore affect the unemployment rate.

Such economic impacts are likely to be less pronounced in states where
utilities do not depend as much on FERC-licensed hydropower for a
significant percentage of their generation. Also, impacts will likely be less
in the case of hydropower projects that use a smaller percentage of federal
land. For example, the Chelan County Public Utility District (PUD) in
Washington State pays FERC about $3,200 in annual charges for its use of
federal lands for its Rocky Reach and Rock Island hydropower projects.
These lands account for about 1 percent of the acreage in each of the
projects. We estimated that these lands could be worth about $2.7 million
for 2003. While this value could result in a large increase in charges, it is


15
  According to Idaho Power’s annual report (SEC Form 10-K405) for the fiscal year
ending Dec 31, 2001, the cost of operating Idaho Power for 1999 was about $546 million.
Once adjusted to 2002 dollars—which we did for comparison purposes—the $546 million
becomes $580 million.




Page 29                                      GAO-03-383 FERC Charges for Federal Lands
                         only about 2 percent of our total annual estimated cost—about $150 million
                         in 2003—to operate these two projects (including capital costs). Thus, this
                         increase is not likely to significantly affect the project owner or
                         its customers.

                         FERC has options to mitigate the effects on consumers of annual charges
                         that better reflect the fair market value of the federal lands:

                         • FERC could collect only a portion of the fair market value of the land as
                           annual charges.

                         • FERC could phase in the charges over several years to allow
                           project operators and consumers to better prepare for and adjust to the
                           higher rates.

                         • FERC could also delay implementing any higher annual charges until
                           electricity markets become more competitive through restructuring. In
                           restructured markets, to remain competitive, project owners may not be
                           able to pass on higher annual charges to consumers.16 However, FERC
                           would need to prepare to implement higher charges while states are
                           moving toward restructuring their electricity markets. If FERC is not
                           prepared to act, as discussed below, its opportunities to increase annual
                           charges at a later date would be limited.



Effect of Higher Costs   The regulatory environment largely determines whether consumers or
Will Depend on Market    project owners pay increased charges for the fair market value of federal
                         lands used for hydropower. Some of the states that could be affected by
Environment
                         increases in annual charges currently have electricity industries that are
                         highly regulated—that is, the price to consumers is based on the cost of
                         production. For example, consumers in Idaho and Washington State—
                         which now regulate their utilities—would see the greatest impact because
                         some of their electric utility companies rely heavily on FERC-licensed
                         hydropower projects for their electricity. Customers who use these utilities
                         have enjoyed some of the lowest electricity rates in the country.




                         16
                           In restructured markets, hydropower owners will be free to sell the electricity they
                         generate at market prices, rather than at regulated rates. However, they will not be able to
                         sell electricity above the market price.




                         Page 30                                        GAO-03-383 FERC Charges for Federal Lands
                         In a regulated electricity market, increases in annual charges are most
                         likely going to be passed on to consumers. However, in a restructured
                         environment, where electricity rates are based on wholesale market prices,
                         increased annual charges are much more likely to affect the profitability of
                         the electric utility and its shareholders than consumers. Specifically, in a
                         restructured environment with competition, the utility may not be able to
                         pass on increases in annual charges and still keep its customers. For this
                         reason, consumers would less likely be affected. Among the states most
                         likely to be affected by any significant changes in annual charges, Montana
                         has already made the transition to market-based pricing of electricity. As a
                         result, in Montana, the owners of hydropower projects—rather than the
                         customers of these projects—are likely to pay most of any increase in
                         annual charges.



FERC’s Future Ability    If FERC decides not to act to collect annual charges that better reflect the
                         fair market value for the use of federal lands by hydropower projects until
to Increase Annual       after restructuring occurs, it may limit its opportunity to increase charges,
Charges Could Be         thereby putting the taxpayers at risk of losing a potential future stream of
                         revenue. Specifically, FERC’s ability to raise annual charges may be limited
Limited by Electricity   after states restructure the generation segment of their electricity market
Market Restructuring     because new purchasers of existing hydropower projects on federal land
                         will likely have paid a price that included the capitalized value of the land.

                         Some states have moved toward restructuring the generation segment of
                         their electricity markets. This shift changes the way that the benefits
                         associated with hydropower are distributed between the ratepayers and
                         the project owners. In a regulated environment, where rates are based on
                         the cost of service, ratepayers receive the benefits in the form of low
                         electricity rates. These rates are associated with the low cost of
                         hydropower production, including the low annual charges assessed to
                         those who use federal lands to produce power. However, in restructuring
                         this industry to create more competition, some states have allowed or
                         required utilities to sell their power plants, including hydropower plants
                         that are located partially or entirely on federal land. The sale price for these




                         Page 31                                 GAO-03-383 FERC Charges for Federal Lands
projects may include the net benefits that are attributable to the
contribution the federal lands make to the production of power. When
these projects are sold, either the state and/or the seller have captured
these net benefits.17 The state and/or the seller are able to capture these net
benefits because FERC had not set annual charges at a level that better
reflects the fair market value of the federal land. If FERC had done so, the
project’s price would have been reduced to reflect the higher operating
costs associated with annual charges that more closely reflect fair market
value. Once these projects are sold, the federal government may be
reluctant to raise annual charges because the new owner probably paid a
price that included the capitalized value of the federal land. Any further
cost increases, such as higher annual charges, could make power
production costs exceed the current market price of electricity. As a result,
the new project operator would likely either operate at a loss or lose its
customers to competition. In such situations, FERC may be reluctant to
raise annual charges to better represent the fair market value of the
federal land.

Some states, including Maine, Montana, and New York, have already
restructured the generation segment of their electricity industries in ways
that resulted in the utilities’ selling off their hydropower projects. In these
states, both the state and/or the seller captured the net benefits resulting
from the sale of the projects. In Maine and Montana, the projects were
auctioned, and the winning bids were well above the amounts that the
regulators deemed sufficient to reimburse the selling utility for the value
of its fixed assets, including the land owned by the utility. However, in
Montana, where some of the hydropower projects’ land is federally owned,
the sale price was likely higher than it would have been if annual charges
had more closely reflected fair market value. In fact, the new owners of
these assets told us that their bid would have been lower if they had
expected higher annual charges for the federal land. If FERC had
implemented higher charges, more revenues would have accrued to the
federal government and less to the state of Montana.




17
  As states regulate electricity markets, they also act on behalf of state ratepayers in
approving the final restructuring arrangements. In some cases, the restructuring
arrangements will then result in states’ capturing some or all of the net benefit of projects
that are sold as part of a restructuring effort.




Page 32                                         GAO-03-383 FERC Charges for Federal Lands
Figure 3 graphically depicts how the sale of a hydropower project—sold as
part of a state’s effort to restructure its electricity market—causes the
capitalized value of the land’s net benefit to become a component of the
project’s selling price and thus the buyer’s capital costs. However, this
higher selling price would be at the expense of taxpayers who are at risk of
losing a potential future stream of revenue. As FERC has observed in
connection with annual charges assessed for the use of government dams,
an “overly low annual charge payment…ultimately places higher costs on
other consumer members of the public who must make up the difference
through their taxes.”18



Figure 3: Illustration of the Cost to Produce Hydropower Before and After a Sale
That Occurs as Part of Restructuring

Value of power                                                     Price to consumers
                                                                   Net benefit

                                  Net benefit


         Price to consumers                                            Capitalized value
                                                                       of the land
                                                                   +
                Value of plant                                         Value of plant
               and equipment                                           and equipment
          +                                                        +
                 Depreciation                                          Depreciation

                 Capital costs    Capital costs    Capital costs       Capital costs




                                 Operations and   Operations and
                                  maintenance      maintenance
                                     costs            costs
                                    Before           After
                                 deregulation     deregulation
Source: GAO.




18
     48 Fed. Reg. 15134, 15136 (1983).




Page 33                                           GAO-03-383 FERC Charges for Federal Lands
Conclusion            Under the Federal Power Act, FERC is required to collect reasonable
                      annual charges to compensate the federal government for the use of its
                      lands. FERC must balance the amount of these annual charges with the
                      authorizing act’s requirement to seek to avoid unreasonable increases in
                      consumer rates and the act’s goal of encouraging the development of
                      hydropower. However, by tying the annual charges to an out-of-date
                      rights-of-way fee system, FERC is collecting less than 2 percent of our
                      estimate of the fair market value for the use of federal lands by our
                      sample of hydropower projects. FERC has not conducted any research and
                      analysis to determine whether its current annual charges are reasonable.
                      Thus, FERC has no assurance that its current system strikes a balance
                      between those who benefit from the federal lands—consumers and
                      hydropower project owners—and the taxpayers who own the lands. Even
                      if FERC could ensure that it was assessing reasonable annual charges,
                      administrative problems with the current system—self-reported data and
                      conflicting information in the databases—would hamper FERC’s ability to
                      collect all moneys due.

                      In addition, as states restructure their electricity markets, inaction on the
                      part of FERC to reassess what constitutes a reasonable annual charge
                      could limit the agency’s ability to increase charges in the future as states
                      distribute the net benefits of hydropower projects that are sold during the
                      restructuring process. In the end, if FERC does not act, taxpayers who do
                      not benefit from low hydropower electricity rates may lose the opportunity
                      to benefit from a potential future stream of revenue.



Recommendations for   We recommend that FERC reassess its system of annual land use charges
                      in light of the (1) information we are providing concerning the estimated
Executive Action      value of the contribution that federal lands make to the production of
                      hydropower, (2) trend toward the restructuring of the nation’s electricity
                      markets, and (3) flaws in its present system. Specifically, FERC should
                      develop new strategies and options for assessing annual charges that are
                      proportionate with the benefits conveyed to hydropower licensees. In
                      conducting this reassessment, FERC should (1) determine methods for
                      assessing or estimating the fair market value of federal lands used for
                      hydropower purposes and (2) determine methods for assessing annual
                      charges, taking into account the federal land’s fair market value as well as
                      the competing goals of encouraging hydropower development and avoiding
                      unreasonable increases in electricity rates to consumers.




                      Page 34                                GAO-03-383 FERC Charges for Federal Lands
                      In the interim, while FERC is developing this strategy, we further
                      recommend that FERC improve its internal control systems in the
                      following ways:

                      • improve the management of its current system for assessing annual
                        charges through periodically verifying self-reported data on the amount
                        of federal lands licensed hydropower projects use, and

                      • resolve discrepancies among its multiple billing and land databases in
                        order to ensure that each project is properly billed for the annual land
                        use charges it owes the federal government.



Agency and Industry   We provided FERC, the Department of the Interior, the Forest Service, and
                      the National Hydropower Association—a hydropower industry group—
Comments              with a draft of this report for their review and comment. The Forest Service
                      declined to comment on the report. Interior agreed with the report and
                      provided some technical clarifications and observations. (See app. V for
                      Interior’s comments and our response.)

                      FERC generally agreed with our findings and recommendations on the
                      conflicting information in the databases it uses to manage its annual charge
                      system, but it generally disagreed with our assessment of the value of
                      federal lands used by hydropower projects. FERC questioned the validity
                      of our analysis of the value of federal lands because our analysis resulted in
                      values that were significantly higher than current annual charges. However,
                      it is difficult for FERC to make meaningful comparisons on the basis of
                      current annual charges because, as we discuss, FERC’s annual charge
                      system is based on a fee schedule that was not designed for hydropower
                      uses and moreover does not accurately assess fair market value for its
                      originally intended purpose. Furthermore, FERC has not performed any
                      analysis of the value of these federal lands in over 15 years, and therefore
                      cannot ensure that the charges it collects meet the objectives of its annual
                      charge program. FERC also raised concerns about (1) using a net benefits
                      approach as a mechanism to collect annual charges and (2) linking
                      annual charges to electricity markets, which have recently been volatile.
                      Concerning our use of the net benefits approach, our report recommends
                      that FERC reassess its current annual charge system and look for ways to
                      better account for the value of federal lands. We used the net benefits
                      approach as a method to illustrate the contributions that these lands
                      make to the production of hydropower. We do not specifically recommend
                      that FERC deploy our approach to value the land as a mechanism for



                      Page 35                                 GAO-03-383 FERC Charges for Federal Lands
determining annual charges. Concerning the linking of annual charges to
electricity markets, our report recognizes the volatility that has recently
occurred in these markets. If FERC decides to reassess and revise its
annual charge system, it does not have to use an annual charge system that
fluctuates with electricity markets. FERC can decide to use a system
based on long-term expectations, which would tend to mitigate short-term
volatility. In the past, FERC has approved annual charges for tribal lands
that (1) were based on a long-term analysis of the value for the use of the
land and (2) were a fixed amount so that licensees could plan and budget
for them. (See app III. for FERC’s comments and our response.)

NHA disagreed with the report. It raised several concerns about having
FERC use a net benefits approach to levy annual charges. However, we
do not specifically recommend this use. Instead, we used the net benefits
approach as a tool to value the federal lands used by a sample of
FERC-licensed hydropower projects. In so doing, we found that FERC
is collecting only a very small percentage of the federal lands’ value in
its current annual charge system, and recommend that FERC reassess its
current annual charge system without recommending a specific approach.
NHA also commented that increased annual charges will increase
electricity rates to consumers, which could adversely affect the economy
of some states that benefit from low-priced hydropower. We recognized
this possibility. As our report discusses, the impacts from increased annual
charges largely depend on (1) how much of the land’s value FERC decides
to collect as an annual charge and how it implements any higher charges
and (2) whether the affected electricity market is still fully regulated or has
been restructured.

NHA also commented that potential annual charges for the use of federal
land should be reduced to recognize the public benefits provided by
hydropower projects, such as recreation, flood control, irrigation, and fish
and wildlife enhancement. However, FERC has twice rejected this
argument, saying, in essence, that under the Federal Power Act, public
benefits are provided as a condition of receiving the license and that the
licensee deserves no compensation for merely complying with the law.
(See app. IV for NHA’s comments and our response.)




Page 36                                 GAO-03-383 FERC Charges for Federal Lands
Scope and     To determine FERC’s current system for assessing annual charges, we
              reviewed relevant laws, regulations, and FERC rulings. In addition, we
Methodology   interviewed officials from FERC, federal land management agencies, and
              industry associations concerning the history and application of the current
              annual charge system. We also reviewed pertinent documents from these
              sources, as well as past reports from GAO and the Department of Energy’s
              Office of the Inspector General. To assess FERC’s management of its
              current system we obtained records from multiple FERC databases for
              various years. These records included information on billing, the type of
              federal land associated with each hydropower project (e.g., Forest Service,
              BLM), and the number of federal acres associated with each project in our
              sample. We assessed the reliability of FERC’s data by analyzing and
              crosschecking the information that was provided. In addition, we
              interviewed FERC officials and requested a variety of documents in an
              attempt to clarify discrepancies found in the data.

              To estimate the values of the federal lands that utility companies use
              to generate hydropower, we performed a net benefits analysis using
              project-specific data for a sample of 24 hydropower projects that use
              federal lands. We developed this sample by obtaining information on the
              amount of hydropower generated by each FERC-licensed project that
              uses federal lands. We then determined that the 56 projects with the
              greatest generation produced about 90 percent of the power generated
              by FERC-licensed projects on federal lands. From these 56 projects, we
              selected 24 using a stratified random sampling method. The projects were
              grouped into four strata based on the size of the project as determined by
              the amount of generation produced. The first stratum included the largest
              projects, the second stratum had the next largest group, and so forth. We
              weighted the sample toward the largest generators by sampling 9 of the
              10 projects in the first stratum. We grouped the remaining projects among
              the other three strata according to size. Five projects were randomly
              selected from each of the other strata. (For greater detail on our
              methodology see app. I.) We discussed the merits and limitations of this
              approach with officials from FERC, hydropower project owners, and
              several industry associations, including the National Hydropower
              Association and the Western Utilities Group.




              Page 37                               GAO-03-383 FERC Charges for Federal Lands
To determine what effect an increase in annual charges might have on
utilities and their customers, we met with utility representatives with
projects in our sample to share the results of our analysis and discuss the
implications of having FERC increase annual charges to the values that
our analysis suggests. In addition, we spoke with state regulators in
California, Idaho and Montana; FERC officials; hydropower project
owners; and industry associations to obtain their views concerning
potential impacts associated with an increase in annual charges. Finally,
we met with representatives from a taxpayer advocacy group to discuss
any implications of FERC’s inaction on general taxpayers who do not
receive any benefits associated with hydropower projects on federal lands.

To identify the potential implications of FERC’s not addressing its current
annual charge system in a timely manner, we relied on generally accepted
economic principles of regulated and restructured markets to identify the
possible consequences of FERC’s inaction. In addition, we looked at
available data for a recent sale of hydropower projects in Montana that
included federal lands. On the basis of generally accepted economic
principles and the data from that sale, we developed a probable scenario
concerning the distribution of the net benefits when a hydropower project
is sold as part of the restructuring of a state’s electricity market.

We conducted our work from August 2000 through February 2003 in
accordance with generally accepted government auditing standards.


We are sending copies of this report to the Commissioners of the Federal
Energy Regulatory Commission; the Secretaries of Agriculture and of the
Interior; the Director, Office of Management and Budget, and other
interested parties. We will also make copies available to others upon
request. In addition, the report will be available at no charge on the GAO
Web site http://www.gao.gov.




Page 38                               GAO-03-383 FERC Charges for Federal Lands
If you or your staff have any questions about this report, please call me on
202-512-3841. Key contributors to this report are listed in appendix VI.




Barry T. Hill
Director, Natural Resources
 and Environment




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Appendix I

Estimating the Fair Market Value of Federal                                                                               Appendx
                                                                                                                                ies




Land Used to Produce Hydropower                                                                                            Append
                                                                                                                                x
                                                                                                                                Ii




                           We were asked to estimate the fair market value of federal lands that are
                           used by hydropower projects that the Federal Energy Regulatory
                           Commission (FERC) licenses. This appendix describes how we estimated
                           the fair market value of such lands. The appendix contains four sections.
                           The first describes our rationale for choosing the net benefits methodology.
                           The second describes the methodology. The third describes the decisions
                           that we made in implementing the methodology, including choices on our
                           sample of dams and the scenarios that we estimated. Finally, the fourth
                           section describes the data required to estimate those scenarios.



GAO’s Rationale for        This section provides a rationale for choosing the net benefits methodology
                           to estimate fair market value and describes our methodology in detail. Our
Choosing the Net           net benefits methodology estimates the value of the land by calculating the
Benefits Methodology       difference between the value of the hydropower that is generated and the
                           full nonland cost of producing it. In the absence of comparable market
to Estimate Fair           sales, the net benefits methodology provides an alternative for estimating
Market Value               fair market value that is consistent with economic principles and
                           appraisal practices.



The Principle of the Net   Our net benefits approach follows from the long-established economic
Benefits Approach          principle that allocates to fixed factors of production such as land the
                           residual value that remains after subtracting the compensation for all other
                           factors of production at their fair market value. Economic principles and
                           the real estate appraisal literature advocate market sales as the most
                           reliable measure of real estate values. In some cases, there may be no
                           market sales. One such case would be real estate with special
                           characteristics that limit the usefulness of market sales for appraising its
                           value. In cases like this, economists and appraisers advocate alternative
                           approaches to valuing real property. Economists have used net benefits
                           analysis, and appraisers have used similar analyses that are generally
                           referred to as “income capitalization analysis.”1 In the case of land values,
                           the real estate appraisal literature includes a particular variant of income




                           1
                            See The Appraisal of Real Estate, 12th ed. (Chicago: Appraisal Institute, 2001), especially
                           pp. 25 to 26 and ch. V. Even when market sales are available, a complete appraisal requires
                           the use of all available information as well as market sales.




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Appendix I
Estimating the Fair Market Value of Federal
Land Used to Produce Hydropower




capitalization analysis that is referred to as the “land residual technique,”
with origins and wide support in economics.2 The land residual technique is
particularly similar to our net benefits methodology.

Our net benefits methodology, like the land residual technique, starts with
the value of the goods that are produced and then subtracts the costs of all
nonland factors of production. The residual net benefits are the estimated
value of the land.

Land that is used for hydropower generation fits the description of real
estate with special characteristics that limit the usefulness of market sales
for appraising its value. Land that is a mile upstream or downstream from a
suitable location may be far less valuable because of the absence of a
special feature, such as a canyon. Hence, land transactions in the general
vicinity of a hydropower project are not likely to shed light on the value of
the project’s land.

Electric utility companies have purchased land for use in hydropower
generation, but their purchases were made largely under a regulatory
system that does not reveal the value of the purchased land in the
hydropower generation use. The Federal Power Act gives utilities the right
of eminent domain which allows them to condemn private property
necessary for the construction, maintenance, or operation of the project;
and this ability to condemn property can have a distorting effect on the
economics of utilities’ land transactions. Utility representatives told us that
the prices they paid for land acquisitions for hydropower projects reflected
the market value of the land in the previous use, such as ranching or
logging. The value of the land in such uses is likely to be very different from
its value in the intended use—hydropower generation. In some states, in
recent years, lands used for hydropower generation have also changed
hands in cases where utilities divested their hydropower projects in
competitive bidding auctions. However, in these cases, the prospective
buyers typically bid on packages of electricity generation assets. We had no
way of isolating the value of the land from the overall value of the package


2
  This technique goes back to David Ricardo’s notion that “land rent is a residual, equal to
the excess of revenues from the sale of goods produced on the land over remunerations to
non-land factors used in production.” Cited in Norman G. Miller, Steven T. Jones, and
Stephen E. Roulac, “In Defense of the Land Residual Theory and the Absence of a Business
Value Component for Retail Property,” The Journal of Real Estate Research 10:2 (1995):
203–15. This article gives a brief review of other economists who advanced this theory into
the 1990s.




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Estimating the Fair Market Value of Federal
Land Used to Produce Hydropower




of assets, especially in the absence of a large number of transactions. Even
if the value of land for hydropower generation could be estimated from
such transactions in some cases, it may be of little use for other cases. The
value of land used for hydropower generation in one project may be quite
different from the value of land in another project.

All land that is used to produce hydropower has unique features that
make the land scarce and valuable, and these features provide a rationale
for compensating its owners for its use. The production of hydropower
requires land with certain characteristics, capital investments on that
land, and a staff to manage and operate the project. The net benefits
methodology recognizes that the return on capital investments is a
payment to the owners of the capital, including compensation for the risk
the owners incurred in their investment. Similarly, the salaries and other
operating costs paid to management and employees at each hydropower
facility represent the market valuation of their contribution to the
production of hydropower. The remaining input required to produce
hydropower is land. The fair market value of that input can be estimated by
using the net benefits methodology.

In adapting this methodology, we estimated the value of the site using
wholesale electricity market prices of the power that the projects in our
sample produced rather than the regulated rates that utilities actually
charged. The values we estimated differ from the contribution of the
hydropower to the actual revenues from the sale of the hydropower in
our sample. Utilities sell power to their ratepayers at regulated rates that
reflect the costs of generation and delivery to customers. Our analysis is
concerned with the generation segment only of the electric power industry,
not the delivery segment (transmission and distribution). It is possible to
estimate the portion of an electric utility’s revenues that corresponds to
generation only. However, given traditional utility regulation, that estimate
would correspond to the portion of our equation that covers the costs of
generation, which include a return on the capital investment. Because of
regulation, the cost of electric power differs from its market value.
Wholesale market prices are a more accurate reflection of the economic
value of power.

In addition, FERC has approved settlements involving Native American
lands occupied by hydropower projects in which the net benefits method
figured prominently in the calculation of the annual charge. Specifically,
the Confederated Tribes of Warm Springs Reservation in Oregon receives
about $11 million annually for their lands in the Pelton-Round Butte project



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                          Appendix I
                          Estimating the Fair Market Value of Federal
                          Land Used to Produce Hydropower




                          as the result of a FERC-approved settlement that was based in part on a net
                          benefits calculation. Moreover, the Bureau of Indian Affairs has advocated,
                          as standard practice, the use of the net benefits methodology as a starting
                          point in negotiations between tribes and owners of hydropower projects.

                          Outside of the United States, economists in Canada and Norway have
                          employed methodologies similar to our net benefits methodology in order
                          to estimate the resource value of hydropower. Economists in these two
                          countries that rely heavily on hydropower have estimated “hydro-electric
                          rents” by deducting nonland costs from the value of hydropower.3
                          Moreover, the government of Norway uses a net benefits model for
                          assessing charges on hydropower. The Norwegian methodology calculates
                          the present value of a hydropower facility’s revenues net of all capital and
                          operations and maintenance costs over the entire lifetime of the facility.
                          This is another variant of the land residual or net benefits methodology.4



Industry Input in         Early in our review, we met with many representatives of electric
Developing Our Approach   utilities, state utility regulators, and other stakeholders to obtain their
                          views on our methodology for estimating the value of federal land used for
                          hydropower generation. These stakeholders included representatives of
                          most of the private and public entities that own the projects in our
                          sample. Representatives of the owners of projects in our sample, with few
                          exceptions, generally expressed reservations about using net benefits as a
                          method for estimating the value of land used for hydropower generation.
                          Furthermore, even those who said that net benefits was conceptually a
                          valid method for estimating land values, still had concerns about using this
                          method as a basis for setting FERC charges. In addition, industry
                          representative expressed reservations about estimation difficulties and


                          3
                            See, for example, Richard C. Zuker and Glenn P. Jenkins, Blue Gold: Hydro-Electric Rents
                          in Canada, a study prepared for the Economic Council of Canada (Ottawa: Canadian
                          Government Publishing Centre, 1984), Eirik S. Amundsen, Christian Andersen, and Jan
                          Gaute Saunnarnes, “Rent Taxes on Norwegian Hydropower Generation,” The Energy
                          Journal 13:1 (1992), and David Gillen and Jean-Francois Wen, Waterpower Program
                          Financial Review, report submitted to Ontario Ministry of Natural Resources, Province of
                          Ontario, (April 1997.)
                          4
                            The implementation of the Norwegian methodology differs from ours in that it capitalizes
                          net benefits over the entire lifetime of the project; our approach relies on annualized net
                          benefits calculations. The capitalization approach assumes adequate knowledge of
                          hydropower values and costs in the future. We refrained from such an approach because we
                          wished to avoid forecasting values and costs well into the future.




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Estimating the Fair Market Value of Federal
Land Used to Produce Hydropower




uncertainties and difficulties in implementing a system of charges based on
the estimates of net benefits. They also expressed serious concerns about
the impacts of higher FERC charges based on our estimates of net benefits.
They cited potentially serious impacts on ratepayers and, in some cases,
local economies, depending on how FERC would implement a system of
higher charges based on net benefits estimates. On the other hand, state
regulators to whom we described our methodology generally agreed with
its conceptual validity, but some of them also expressed concern about
impacts on ratepayers and on local economies. Industry representatives
and regulators generally agreed that higher charges would have more
impacts on the shareholders of companies in case of restructuring that
allows hydropower to be sold at market rates.

In contrast, from discussions with representatives of several projects in our
sample, it appeared that their preference for FERC’s current method of
determining land charges was a result of its simplicity and relatively
low charges.

One of the main substantive arguments that utilities used against our
net benefits approach is that the value of land used for generating
hydropower can be inferred from market transactions in lands in the
general vicinity of the projects. According to this argument, the value of
land in a hydropower project that is surrounded by grazing land, for
example, is likely to be similar to the value of neighboring grazing plots.
However, FERC has observed that the annual charge for federal lands
should be proportionate to the value of the benefit conferred, and the
benefit that the project owner receives from the land is the ability to
operate a hydropower project, not to graze livestock.5 Federal appeals
courts have similarly concluded that annual charges must be proportional




5
  Some project owners have argued that land within a project boundary that does not
contribute anything to hydropower generation should not be valued for hydropower
purposes. However, the project owner could not have obtained its license without gaining
access to all the land within the project boundary; thus, it is inaccurate to argue that there is
no relationship between the federal land within the boundary and the hydropower project.
Moreover, FERC established the project boundaries as containing those lands.




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Estimating the Fair Market Value of Federal
Land Used to Produce Hydropower




to the benefit conferred.”6 The fallacy of the argument for valuation based
on adjacent lands may be illustrated by the example of grazing lands. The
value of a rancher’s land may not change significantly if it were moved a
mile in any direction. Land that is used for hydropower generation,
however, cannot easily be substituted with other land, even if it is nearby.

In some hydropower project sales in recent years, the right to the use of the
land was bundled with the physical assets. Often, generation assets sold as
packages that included hydropower generation projects as well as other
generation plants that rely on fossil fuels such as coal. Because of the
bundling of the land and physical assets, the sale does not reveal the
market value for these lands. Even if the market value for hydropower
project land could be gathered from such transactions, little could be said
about the value of other lands used to generate hydropower because of
inherent differences in the characteristics of different lands and in the
value of electricity generated in different regions. As we explain later, wide
differences in the topographic characteristics of project lands greatly affect
the value of each project. Therefore, the value of project land is likely to
differ widely from one project to another.

While we rejected the argument for using adjacent land values to estimate
the value of lands used for hydropower generation, we accepted a number
of specific suggestions that various stakeholders, including representatives
of electric utilities, made regarding our methodology. For example, we
modified our methodology to include utilities’ administrative and general
costs and their tax expenses.




6
 East Columbia Basin Irrigation District v. FERC, 946 F.2d 1550, 1560 (9th Cir. 1991).
Licensees also argue that if land is to be valued on the basis of its contribution to
hydropower production, each acre should be assessed differently, so that acres included in
the project solely for environmental purposes, for example, are assessed at a lower rate.
In response, we note that FERC’s current system of land charge also assesses the same
charge for each acre within the project boundary, regardless of the individual acre’s
contribution to hydropower production. In any event, the licensees can obtain no economic
benefit from the project unless it obtains access to all the lands within the project boundary.
However, FERC is authorized to approve licensee requests to alter project boundaries. Such
requests could increase in the event that significant increases in annual charges,
undifferentiated by acre, were to be implemented.




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                   Appendix I
                   Estimating the Fair Market Value of Federal
                   Land Used to Produce Hydropower




A Description of   We used a net benefits methodology to estimate the fair market value of
                   federal lands used to generate electricity at a sample of 24 FERC-licensed
Our Methodology    hydropower projects. For this report, “fair market value” refers to annual
                   estimates of net benefits rather than a one-time sale of the permanent right
                   to use the federal land.7 Our estimate of the net benefits for a given project
                   during a given year is the difference between the estimates of the market
                   value of power that the project generates and the full cost of all nonland
                   factors used for hydropower generation for that year. We defined the full
                   cost of nonland factors as the sum of the year’s (1) annualized capital cost;
                   (2) operations and maintenance costs; including a share of corporate
                   overhead; and (3) a share of the owner’s direct tax expenses allocated to
                   the project. All factors of production contribute to the value of power that a
                   hydropower project generates, and full costs, as we define them, cover the
                   compensation that all factors—except land—earn on their contributions.
                   Our net benefit methodology allocates to project lands the difference
                   between the value of hydropower production at the project and the full
                   production costs as we defined them. The federal government’s share of
                   net benefits is based on the federal share of the total land area within the
                   FERC boundaries of a given project.

                   Our net benefits methodology follows four basic steps:

                   • To estimate the value of hydropower that a project generates, we
                     multiplied the quantity of hydropower generated by the wholesale price
                     for power in its market area. As discussed earlier, our estimates of the
                     value of power generally differ from the revenues that the project
                     owners earn from the sale of the hydropower that they generate,
                     because utilities’ revenues are still predominantly based on costs rather
                     than on market prices.

                   • For each project, we summed its annualized capital cost; operations
                     and maintenance costs, including a share of corporate overhead costs;
                     and a share of the owner’s tax expenses allocated to the project.



                   7
                     To create a value that is comparable to current annual FERC charges, we focused on the
                   annual value of the lands in a hydropower project. This is different from the capitalized
                   value of the project’s land. The capitalized value is the present value of annual net benefits
                   over the future lifetime of the project. An appraiser would consider the capitalized value of
                   the land in connection with an outright sale of the land, for example, as opposed to annual
                   charges for the use of the land.




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• We subtracted the sum of costs from the value of hydropower. The
  resulting differential represents an estimate of the annualized fair
  market value of project lands.

• We multiplied the estimated annualized fair market value of project
  lands by the federal government’s share of total project lands to obtain
  the federal government’s share of this estimate.

Figure 4 illustrates how the net benefits methodology estimates the value
of the land by deducting from the value of hydroelectric power three
major cost components: capital costs, operations and maintenance costs,
and taxes.



Figure 4: The Net Benefits Methodology




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                       Appendix I
                       Estimating the Fair Market Value of Federal
                       Land Used to Produce Hydropower




Technical Details of   While the previous overview of the methodology provides a summary of the
Our Methodology        steps taken, we represent the methodology by several equations that allow
                       it to be implemented, using data on a sample of dams. The methodology
                       estimates the fair market value of the federal land for a given project during
                       a given year. The model can be summarized as follows in equations 1 and 2:

                       FNB (i,t) = s ( i ) × NB (i,t)                                                     (1)
                       NB (i,t) = p (i,t) × Q (i,t) – C (i,t)                                             (2)
                       where
                       FNB (i,t)    = Federal net benefits for project i, in year t;
                       s(i)         = percentage of land that is federal land for project i;
                       NB (i,t)     = net benefits for project i, in year t;
                       p (i,t)      = price we used to value the hydropower generated for
                                      project i, in year t;
                       Q (i,t)      = amount of electric power generated and sold by project i, in
                                      year t; and
                       C (i,t)      = cost of all nonland inputs for project i, in year t.

                       Project land is all the land within the project boundary, excluding lands
                       used for transmission rights of way.

                       On the cost side, we included operations and maintenance costs, a share of
                       the owner’s tax expenses assigned to the project, and annualized capital
                       cost in equation 3:

                       C (i,t) = O&M (i,t) + T (i,t) + K (i,t)                                            (3)
                       where
                       O&M (i,t) = project’s direct operations and maintenance costs, plus an
                                   adjustment intended to assign a portion of the owner’s
                                   overhead costs to the project;
                       T (i,t)      = share of taxes the project owner paid, which we assigned to
                                      the project; and
                       K (i,t)      = annualized capital costs of the project.




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Estimating the Fair Market Value of Federal
Land Used to Produce Hydropower




In addition, annualized capital costs are defined by equation 4:

K (i,t) = D ( i ) + r × RCLPD (i,t)                                                 (4)

where

D(i)           = annual depreciation factor for project i;
r              = real discount rate to convert a capital cost to annual
                 payments; and
RCLPD (i,t) = replacement cost less physical depreciation. We used this
              estimate as a proxy for the value of the project’s capital
              investment net of accumulated depreciation. RCLPD for
              project i, declines by an amount equal to D ( i ) each year.

In other words,

RCLPD (i,t) = RCLPD ( i,t – 1 ) – D ( i )                                           (5)

We assumed that the depreciation factor, D ( i ) , stays constant for the
period of analysis, 1998 through 2003. Capital additions, replacement of
major equipment, or major maintenance over a longer period would result
in the annual depreciation factor’s changing over time. We chose this
method of annualizing capital costs because it is widely used in utility
industries. A utility is allowed to set electricity rates that will recover its
full estimated costs, including depreciation and a return on the net value of
its capital investment—the value remaining after accumulated depreciation
has been subtracted.8




8
 A standard definition of revenue requirements is
R = C + D + ( r × B ),
where
R = total quantity of revenues to be provided,
C = total operating costs of the firm,
D = depreciation allowance,
r = allowed rate of return on the firm’s undepreciated assets, and
B = net value of the firm’s undepreciated assets, or the rate base.

See Giles Burgess Jr., The Economics of Regulation and Antitrust (New York:
HarperCollins College Publishers, 1995), p. 66.




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Estimating the Fair Market Value of Federal
Land Used to Produce Hydropower




Table 5 illustrates our methodology further with a numeric example for a
hypothetical Project X.

• We start by calculating the value of power—the project’s generation
  amount multiplied by the wholesale electric power price. In our
  example, we multiply 5 billion kilowatt-hours that the plant produces in
  2003 by a price of $0.04/kwh (or $40/megawatt-hour). The result is
  $200 million.

   • Next we calculate nonland costs of $130 million by adding capital
     costs, operations and maintenance costs, and corporate taxes.

   • Capital costs consist of (1) an annual depreciation allowance of
     $25 million, and return on investment of $75 million (replacement
     cost less physical depreciation of $1 billion multiplied by the after-
     tax, regulated real rate of return of 7.5 percent; we chose 7.5 percent
     instead of 7.22 percent for simplicity for this example);

   • taxes are a prorated share of corporate taxes and equal $10 million;
     and

   • operations and maintenance costs, including a share of the project
     owner’s overhead costs, are $20 million.

The sum of costs is $130 million. The net benefit is therefore $200 million
minus $130 million, which is $70 million. For this hypothetical example,
this $70 million is our estimate of the annualized value of project lands for
2003. To obtain the federal government’s share, we multiply this amount by
the federal government’s share of project lands, 10 percent in this
hypothetical example, to obtain $7 million as our estimate of the fair
market value of the federal land for 2003.




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                            Appendix I
                            Estimating the Fair Market Value of Federal
                            Land Used to Produce Hydropower




                            Table 5: Numeric Example of Summary Net Benefits Calculations

                            Project X                                                                    Year 2003
                              Generation (kwh)                                                       5,000,000,000
                              Price in $/kwh                                                                  0.04
                            Value of power                                                            $200,000,000
                              Replacement cost less physical depreciation                           $1,000,000,000
                              Rate of return on investment                                                    7.5%
                            Subtotal (return on investment)                                            $75,000,000
                              1 year’s depreciation                                                    $25,000,000
                              Taxes—a prorated share of corporate taxes                                $10,000,000
                              O&M, including a share of corporate overhead                             $20,000,000
                            Total costs                                                               $130,000,000
                            Net benefit                                                                $70,000,000
                              Federal lands’ share of project lands                                           10%
                            Net benefit of federal lands                                                $7,000,000
                            Source: GAO.

                            Notes: Hypothetical example.
                            kwh = kilowatt-hour




Implementing the Net        This section of the appendix describes the decisions that we made to
                            implement the net benefits methodology for estimating fair market value. It
Benefits Methodology        includes information on our sample of 24 dams, the six scenarios that we
                            estimated, and the different types of data that are required to determine fair
                            market value.



Information on Our Sample   We selected for analysis a random sample of 24 of the 56 largest
of 24 Hydropower Dams       FERC-licensed projects that occupy federal land. Twenty-two of the
                            24 projects in our sample were in western states, while the 2 others were in
                            Alabama and Virginia. The 24 projects ranged from about 75 megawatts to
                            2,100 megawatts of generating capacity and accounted for about 60 percent




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Estimating the Fair Market Value of Federal
Land Used to Produce Hydropower




of the generation for all FERC-licensed hydropower projects on federal
land.9 In addition, our sample accounted for about 35 percent of the federal
lands used by FERC-licensed projects to generate hydropower.10 Figure 1 in
the report illustrates the geographic distribution of the projects in
our sample.

Some of the projects in our sample are owned by private entities while
others are owned by states, municipal utility districts, or other public
entities. Two of the projects in our sample were built primarily for
transporting water from northern California to various locations, and one
was built with irrigation, flood protection, and hydropower generation as
primary purposes.

The sample of dams includes the wide variety of characteristics that
determine the value and costs of any particular dam. The value of
hydropower generated at each dam and its production costs depend on
many factors, including physical characteristics and how the dam is used
for power generation and other purposes. For example, some dams, known
as “run-of-the-river dams,” run almost continuously, while others store
water in impoundments and, as a result, use that water at a later time to
produce more electricity during peak demand periods, when the electricity
is more highly valued. Since the value is determined by the market price at
the time the electricity is produced, the two types of dams have different
values, even if they generate the same amount of hydropower.11 Our sample
also includes dams with widely varying construction costs that depend on
the shape of the land around the dam and other topographic conditions.
Table 6 provides profiles of the dams in our sample.




9
  The electricity generation capacity of a power plant is measured in kilowatts, or
megawatts. One kilowatt is 1,000 watts, and a megawatt is 1 million watts. A watt is an
electrical unit of power, or rate of energy transfer.
10
     These figures exclude land used for transmitting electric power.
11
     Wholesale electric power prices vary from one hour of the day to the next.




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                                                                    Appendix I
                                                                    Estimating the Fair Market Value of Federal
                                                                    Land Used to Produce Hydropower




Table 6: Profiles of Our Sample of 24 Hydropower Projects

Dollars in millions
FERC project
number                           Project name                                       State                Ownership typea                       Capacity in megawatts
5                                Kerr                                               Montana              IPP                                                            196
96                               Kerckhoff 1& 2                                     California           IOU                                                            178
233                              Pit River                                          California           IOU                                                            368
553                              Skagit River                                       Washington           Muni                                                           688
943                              Rock Island                                        Washington           PUD                                                            627
1869                             Thompson Falls                                     Montana              IPP                                                             90
1927                             North Umpqua                                       Oregon               IOU                                                            186
1971                             Hells Canyon                                       Idaho–Oregon          IOU                                                          1,167
1975                             Bliss                                              Idaho                IOU                                                             75
1988                             Haas-Kings River                                   California           IOU                                                            189
2075                             Noxon Rapids                                       Idaho–Montana        IOU                                                            466
2100                             Feather River                                      California           State                                                          762
2101                             Upper American River                               California           Muni                                                           740
2105                             Upper North Fork Feather River                     California            IOU                                                           348
2111                             Swift 1                                            Washington           IOU                                                            240
2114                             Priest Rapids                                      Washington           PUD                                                           1,856
2144                             Boundary                                           Washington           Muni                                                          1,060
2145                             Rocky Reach                                        Washington           PUD                                                           1,280
2146                             Coosa River                                        Alabama               IOU                                                           688
2175                             Big Creek 1&2                                      California            IOU                                                           152
2195                             North Fork River                                   Oregon               IOU                                                             92
2299                             Don Pedro                                          California           ID                                                             167
2426                             California Aqueduct                                California            State                                                        1,679
2716                             Bath County                                        Virginia             IOU                                                           2,100
Source: GAO’s analysis of data from the Energy Information Administration (EIA), FERC, and Scientech.
                                                                    a
                                                                    ID = irrigation district; IOU = investor-owned utility; IPP = independent power producer; muni =
                                                                    municipality; PUD = a public utility district.




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                          Appendix I
                          Estimating the Fair Market Value of Federal
                          Land Used to Produce Hydropower




We Estimated the Fair     We produced estimates of fair market value for each of 3 recent years, 1998
Market Value of Federal   through 2000, and the current year, 2003. We also conducted sensitivity
                          analysis for 1999 estimates by constructing hypothetical examples to test
Land for Six Scenarios    the impact of a higher price in one case and lower hydropower generation
                          by each project in the second case. We chose to estimate land values for
                          4 years because factors that determine net benefits can vary considerably
                          from year to year, depending on wholesale electricity prices, water
                          availability, and restrictions on water use, among other things.

                          In order to estimate the net benefits for 2003, we assumed that the
                          hydropower produced by our sample of plants would be at the average
                          quantity generated over 5 recent years, 1995 through 2000, and that the
                          price of wholesale electricity would be equal to the average cost of
                          production from a newly built, least-cost alternative generation plant.
                          Currently, the least-cost alternative is a combined-cycle, dual-fuel,
                          combustion turbine power plant operating primarily on natural gas. Some
                          industry analysts consider this average cost a good current indicator of the
                          average tendency of wholesale prices in the long term. While the data on
                          prices and production for 1998-2000 provide an estimate of the value of the
                          federal lands during these years, these estimates depended on the market
                          conditions that prevailed at the time. In the longer term, the fair market
                          value for the use of the lands would be limited by the cost of the least-cost
                          alternative source of electricity, as in the 2003 calculation, rather than
                          sustained higher prices that may occur during a given year, such as 2000.
                          Such higher prices would induce investors to build new generating capacity
                          and thereby drive the long-run price of electricity to the cost of that
                          alternative.

                          In order to determine the influence of quantity and price variations
                          independently of each other, we also conducted a sensitivity analysis for
                          1999 by constructing a “lower quantity” case and a “higher price” case.12
                          The lower quantity sensitivity case for 1999 included 10 percent less
                          generation than the actual figure for each project in our sample. We chose
                          this 10 percent reduction to reflect the fact that annual hydropower
                          generation in California from 1983 through 2001 averaged about 10 percent
                          less than its level in 1999. We also constructed a higher price scenario for
                          1999 in which we assumed that the price was equal to $40 per megawatt-


                          12
                            Sensitivity analysis refers to artificially changing the value of a given variable in a model to
                          gauge the effect of change on model results.




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                          Estimating the Fair Market Value of Federal
                          Land Used to Produce Hydropower




                          hour, which is about 8 percent higher than the price that we originally used
                          for 1999. We selected $40 because it represents the long-run marginal cost
                          per megawatt-hour from a newly built, least-cost alternative source of
                          power generation. (This assumption is similar to our price assumption
                          for 2003.)



Data to Implement         To estimate the fair market value of federal land, we needed data on several
                          key variables. This section describes the price and quantity data we used to
the Net Benefits          estimate the value of the hydropower produced at each of the 24 facilities.
Methodology               In addition, this section describes the three key elements of cost data that
                          we used, including (1) annualized capital costs, (2) operations and
                          maintenance costs, and (3) taxes.13 Finally, it describes the data we used
                          for determining the federal share of project lands.



Price and Quantity Data   We used prices of electric power in wholesale markets to value the
                          hydropower that our sample of 24 projects generated. Wholesale electric
                          power markets have developed in response to the restructuring of the
                          electricity industry across the United States. These market prices differ in
                          two ways from the regulated rates that electric power consumers have
                          traditionally paid. First, regulated rates are set through an administrative
                          process, are intended to reflect the utility’s average cost of production, and
                          include returns on the net value of capital investments, subject to approval
                          by state regulators. Wholesale market prices largely reflect market forces
                          on both the supply and demand sides of the market. Second, regulated
                          rates reflect the costs of a bundle of services, including generation,
                          transmission, and distribution. Wholesale electricity prices do not reflect
                          the value of the delivery service, which is provided separately and is still
                          subject to traditional cost-based regulation.

                          We used prices from the California Power Exchange (CAPX) for all
                          projects in the Western Electricity Coordinating Council (WECC) during
                          1998 through 2000. These include all projects in our sample except the
                          Coosa River in Alabama and the Bath County in Virginia. Specifically, we
                          used an average of the hourly wholesale market prices for all hydropower
                          projects that sold into CAPX, weighted by each individual unit’s hourly


                          13
                            We adjusted all dollar values in our analysis to 2002 constant dollars, using the gross
                          domestic product (GDP) implicit price deflator.




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generation. We obtained the confidential hourly generation data from
FERC. We used the resulting annual weighted average price for the projects
in Idaho, Montana, Oregon, and Washington State, as well as California,
because of the integrated nature of WECC. Large quantities of electric
power are traded across the WECC region during the course of the year,
despite occasional transmission constraints within the region at different
times. While transmission constraints prevent trades across subregions at
times, resulting in different prices for different locations, annual averages
tend to converge because of trading activity when transmission capacity is
sufficient. We consulted with a number of experts on this matter and they
agreed that it is reasonable to use the annual average of hourly prices in
California as a proxy for the annual average price for the entire
WECC region.

The operations of CAPX were relevant to our analysis because CAPX
hourly prices were publicly available prices for directly valuing much of the
hydropower generated by the projects in our sample over the period of our
analysis. CAPX was also important to our analysis because California is a
large and important part of the WECC region, which has been a fairly well
integrated market region for electric power. WECC comprises 14 western
states, the Canadian provinces of Alberta and British Columbia, and
portions of northern Mexico. Twenty-two of the hydropower projects in our
sample are in WECC.

For the Coosa River project in Alabama, we used the simple average of
Southeastern Electric Reliability Council (SERC) hourly prices for
1998-2000.14 We used the simple average because hourly generation data
were not available.

The Bath County Pumped Storage (BCPS) project is a special case because
it is a pumped-storage project.15 It is co-owned by Dominion Virginia Power
and Allegheny Power, and is located within PJM’s–Western Hub (PJM-WH).
PJM is the centralized wholesale electricity market for an area that
encompasses Maryland, New Jersey, Pennsylvania, and portions of Virginia
and West Virginia; PJM-WH is one of the zones within PJM. Dominion
Virginia Power, which is co-owner of BCPS with Allegheny Power, uses

14
   These are prices for SERC, excluding Florida. We obtained them from the Tennessee
Valley Authority, but they originate from Power Markets Weekly.
15
  The California Aqueduct project also includes a pumped-storage facility, but we did not
treat the project as a whole as a pumped storage facility.




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PJM-WH prices to value the power that it sells from BCPS for internal
accounting purposes, and the Allegheny Power System is an active
participant in PJM-WH.

Dominion Virginia Power provided us with hourly data on the hydroelectric
power that it sold from its share of BCPS hydropower generation for 1998
and 1999. We used these hourly generation data and hourly PJM-WH prices
to value all BCPS power sold from BCPS in 1998 and 1999. Specifically, for
each of these 2 years, we calculated a price on the basis of average of all
hourly prices from PJM-WH, weighted by Dominion Virginia Power’s sales
from this project. These weighted average values can be thought of as
average hourly revenue per megawatt-hour for the respective years, had all
Dominion Virginia Power’s share been sold at PJM-WH prices. Dominion
Virginia Power did not provide hourly generation data for 2000, but we
used the 1998 and 1999 hourly generation and price data and the hourly
PJM-WH price data for 2000 to extrapolate a weighted average price for
BCPS for 2000.16

For 2003, we assumed that prices for all projects except BCPS would be
equal to the cost per megawatt-hour from the least cost, newly-built
alternative source of power generation. In the electricity industry, this
average is also known as the “levelized” cost of the least-cost, long-run
alternative. It includes all cost components, including capital costs and a
return on investment. The reasoning behind this assumption is that
investors will not invest in new power generation capacity if they cannot
reasonably expect future prices that will allow recovery of all costs,
including a risk-adjusted return on their invested capital. We assumed that




16
  A pumped water project pumps water from a lower reservoir to an upper reservoir at
times when demand for electricity is low. During periods of high demand, the water is
released back to generate electricity. For 1998 and 1999, we calculated a weighted average
value per megawatt-hour for Dominion Virginia Power sales from BCPS at $34.03 and
$51.98, respectively. These values are 1.57 and 1.86 times higher than the simple averages of
hourly PJM-WH prices for these years. We used the lower of these two ratios, 1.57, as an
escalation factor for the 2000 simple average of hourly PJM-WH prices to value BCPS
generation for that year.




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hydropower, on average, should be valued at least as highly as base load
power, so we used levelized cost estimates for base load plants.17
Specifically, we used Global Insight (formerly DRI-WEFA Inc.) levelized
cost estimates for power that is generated by a combined-cycle, dual-fuel
combustion turbine. Global Insight’s estimates are for different regions of
the United States, so we used the estimates for the western and
southeastern states—$42 per megawatt-hour.18 For the special case of
BCPS for 2003, we used the levelized cost estimate of about $41 per
megawatt-hour (in 2002 dollars) but extrapolated a price based on the 1998
and 1999 data.

For all the projects in our sample, we escalated wholesale prices by 7 or
12 percent to reflect the value of ancillary services. Ancillary services
include services related to the provision of electricity other than simple
generation, transmission, or distribution.19 The provision of “balancing
energy supply” is an example of an ancillary service. This is energy that is
not scheduled in advance but is required to meet energy imbalances in real
time to maintain the reliability of the electric system. Because markets for
electricity ancillary services in the United States are generally not well
developed, we tried to account for their value by escalating the wholesale
market price by a fixed percent. Hydropower projects are recognized as
very important sources of ancillary services. We used a 7 percent price
escalation factor for all our sample projects except for the Bath County
project pumped storage project in Virginia (BCPS.) We chose 7 percent as a
conservative number after consulting with a number of experts and
reviewing how other studies accounted for the value of ancillary services.
For BCPS, we used a 12 percent price escalation factor that the project
owner agreed was a reasonable number. Table 7 provides some detail on
the wholesale market prices we used in our analysis.




17
  Base load generating plants are designed for nearly continuous operation at or near
full capacity to provide all or part of the base load. Base load is the minimum level of
demand for electric power in a given system over a period of time.
18
     Global Insight World Energy Service, U.S. Outlook, released January 2002.
19
 Ancillary services are required to maintain system reliability and meet the electric system’s
operating criteria. They include spinning, nonspinning, replacement reserves, regulation,
voltage control, and instantaneous start capability.




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                                                                  Estimating the Fair Market Value of Federal
                                                                  Land Used to Produce Hydropower




Table 7: Prices Used to Value Hydropower for Our Sample of 24 Projects

                                                                                             Project by location
                          California and the Northwesta                                   Coosa River, Alabama                                 Bath County Pumped Storageb
Year                          Pricec       Basis                                        Pricec       Basis                                          Pricec      Basis
1998                         $27.40        Hydro-specific                              $40.01        Simple average of                             $36.86       Average of hourly real-
                                           average of hourly                                         hourly prices for the                                      time prices for PJM–
                                           prices from CAPX,                                         Southeast Reliability                                      Western Hub,
                                           weighted by hourly                                        Council region,                                            weighted by project
                                           generationd                                               excluding Florida                                          hourly generation
1999                           35.43       Hydro-specific                                42.14       Simple average of                               55.16      Average of hourly real-
                                           average of hourly                                         hourly prices for the                                      time prices for PJM–
                                           prices from CAPX,                                         Southeast Reliability                                      Western Hub,
                                           weighted by hourly                                        Council region,                                            weighted by project
                                           generationd                                               excluding Florida                                          hourly generation
2000                         124.54        Hydro-specific                                34.60       Simple average of                               44.34      Extrapolated from
                                           average of hourly                                         hourly prices for                                          simple average of
                                           prices from CAPX,                                         Southeast Reliability                                      hourly PJM–Western
                                           weighted by hourly                                        Council region,                                            Hub prices, adjusted
                                           generationd                                               excluding Florida                                          to reflect peak values
2003                           41.21       Levelized cost of                             41.21       Levelized cost of                               64.68      Extrapolated from
                                           electricity from a                                        electricity from a                                         levelized cost of
                                           combined-cycle dual                                       combined-cycle dual                                        electricity from a
                                           fuel plant for the                                        fuel plant for                                             combined-cycle dual
                                           Western region                                            Southeast Reliability                                      fuel plant for the
                                                                                                     Council                                                    Southeast Reliability
                                                                                                                                                                Council
1999 higher                    40.00       Approximate levelized                         40.00       Approximate levelized                           55.16      Average of hourly real-
price                                      costs from least-cost                                     costs from least-cost                                      time prices for PJM–
sensitivity                                base-load plant                                           base-load plant                                            Western Hub,
                                                                                                                                                                weighted by project
                                                                                                                                                                hourly generation
1999 lower                     35.43       Hydro-specific                                42.14       Simple average of                               55.16      Average of hourly real-
hydropower                                 average of hourly                                         hourly prices for the                                      time prices for PJM–
generation                                 prices from CAPX,                                         Southeast Reliability                                      Western Hub,
sensitivity                                weighted by hourly                                        Council region,                                            weighted by project
                                           generationd                                               excluding Florida                                          hourly generation
Sources: California Power Exchange and California Independent System Operator, Dominion Generation, the Federal Energy Regulatory Commission, Global Insight, and PJM Interconnection.

                                                                  Note: For the Coosa River project, we used data from the Tennessee Valley Authority, based on Power
                                                                  Markets Weekly.
                                                                  a
                                                                      Projects in the Northwest include Idaho, Montana, Oregon, and Washington State.
                                                                  b
                                                                      Pumped-storage facilities have high pumping costs that we accounted for separately.
                                                                  c
                                                                   Prices per megawatt-hour, in 2002 constant dollars. One megawatt-hour is equal to
                                                                  1,000 kilowatt-hours. Prices exclude the value of ancillary services.
                                                                  d
                                                                      CAPX = California Power Exchange.




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                    Estimating the Fair Market Value of Federal
                    Land Used to Produce Hydropower




                    As we mentioned above, we constructed two sensitivity cases for 1999, one
                    assuming lower hydropower generation and the other assuming a higher
                    price. For the lower-generation case, we used the same price as our 1999
                    “base case.” For the 1999 higher-price case, we assumed a price of $40 per
                    megawatt-hour for all projects except BCPS. As with the 2003 prices
                    assumption, we selected this price because it is approximately equal to the
                    cost of power from the least-cost, new alternative generation source.

                    The hydropower generation data for 1998 through 2000 came from several
                    sources. For the investor-owned utilities, we used data from the project
                    owners’ annual FERC form 1. For publicly owned projects—those owned
                    by state agencies, municipalities, public utility districts, or irrigation
                    districts—we used Energy Information Administration (EIA) form 412,
                    which the utilities are required to submit to EIA. For 2003, we used for each
                    project the average net generation for 1995–2000. To compute these
                    averages, we obtained the 1995-2000 data from RDI databases, a service of
                    Platts Global Energy. Our 5-year average included a mix of relatively high
                    and low hydropower generation years in the western U.S.



Capital Cost Data   We hired Scientech, an expert power plant engineering and consulting firm,
                    to provide us with capital cost estimates because FERC’S and EIA’s data on
                    capital costs do not account for the effect of inflation over long periods of
                    time. FERC’s and EIA’s data forms contain capital cost figures that consist
                    of original investment costs plus the cost of additions and less the cost of
                    retirements in current dollar values. For example, if a turbine is replaced
                    because of its age, the retired turbine’s original cost is subtracted and the
                    cost of the new one is added. The forms show only the cumulative capital
                    cost figures; they do not detail retirements and additions and their dates.
                    For example, 1990 capital expenditures may be added to 1940 capital cost
                    expenditures, with no adjustment for inflation, rendering the figure
                    unusable for our purposes. Representatives of hydropower project owners
                    told us that they could not provide us with detailed, project-by-project data
                    on major retirements and additions and their dates, especially for projects
                    that date back many decades. The California Public Utility Commission
                    regulators also said that searching their records for such data would be
                    extremely difficult, even if complete data existed.




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Given these data constraints, we decided to assign to each project annual
capital costs based on the standard formula of compensating utilities for
their costs, and on a current estimate of the project owners’ net capital
investments (net of accumulated depreciation). The standard formula for
compensating utilities for their capital costs is based an annual
depreciation factor and the “net book value of their investments in
equation 5:”20

ACC = D + ( r × B )                                                                     (6)

where

ACC           = annualized capital component of a utility’s revenue
                requirement,
D             = annual capital depreciation allowance,
r             = regulated rate of return on the firm’s net assets, and
B             = net book value of the firm’s assets, also known as the “rate
                base.” (See footnote 8.)

Data on the net book value of the projects are not available. Hence, we
decided to rely instead on an expert consultant’s estimates of replacement
cost less physical depreciation (RCLPD). RCLPD is an estimate of the
value, in today’s dollars, of the owner’s net investment. Because of
inflation, RCLPD is likely to be systematically higher than net book value
(B in the above formula,) and it is therefore higher than the amount that
would adequately compensate project owners for such costs. Since capital
costs are a major component of total costs in our analysis, our reliance
on RCLPD effectively means that our estimates of capital cost are
systematically high, and our estimates of net benefits are conservative.

A team of Scientech engineers and analysts used extensive data sources
and their hydropower engineering expertise to estimate RCLPD for each of
the individual projects in our sample. Scientech started with estimates of
replacement costs, which are the total capital investment that would be
needed today to reproduce a given project on the unimproved site.
Scientech estimated separately for each project in our sample the costs of


20
  Net book value is defined as original cost less accumulated depreciation—all in the dollar
values of the years in which the original costs were incurred.




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(1) reservoirs, dams, and waterways, (2) power plant structures, (3) power
plant equipment, and (4) roads and bridges. Next, Scientech made
assumptions about the useful life span of these components of hydropower
projects in order to estimate physical depreciation factors for them. Given
knowledge of development dates, and Scientech’s own estimates of
replacement costs and depreciation factors, Scientech estimated RCLPD
for each project. It also added, for each project, an estimate of the cost of
licensing that these projects had incurred in the past.

Scientech estimated RCLPD in 2002 dollar values by first estimating
replacement costs (new) for each category and then making assumptions
regarding their useful life span and their age to estimate their physical
depreciation. It also added, for each project, an estimate of the cost of
licensing that these projects had incurred in the past. Finally, Scientech
estimated an annual depreciation factor, D(i), for each project as a
composite of the depreciation factors in each category.

Moreover, we assumed that all the capital costs of a project are allocated to
the hydropower function. This is certainly not the case for at least
three projects in our sample. The California Aqueduct and the Feather
River projects in California were built primarily to convey water over
hundreds of miles from northern California to various locations, making
their development costs far higher per megawatt of electric generation
capacity than most other projects in our sample. The Don Pedro project
was built with irrigation and flood protection as major purposes, in
addition to electricity. Since we had no reliable way of allocating the capital
costs of these projects among their major purposes, we allocated all the
capital cost to hydropower generation. However, this potential
overstatement of capital costs could lead to an understatement of the value
of these projects.

In order to provide an annual estimate of the return on the value of capital,
we used a real discount rate of 7.22 percent—a weighted average cost of
capital for investor-owned electric utilities, averaged over the 5 years
1998 through 2002—from Global Insight. We used the investor-owned
utilities’ rate for all projects, although public utilities’ cost of borrowing is
lower. We used a real, after-tax discount rate, based on Global Insight’s




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                    financial data for investor-owned electric utilities. This rate is consistent
                    with guidance from the Office of Management and Budget.21 We used a real
                    rate because our analyses relies on costs (including capital costs) and
                    benefits in constant dollar values.



Operations and      For the operations and maintenance data, we relied on data provided by
Maintenance Costs   project owners on their FERC form 1 and EIA form 412. We used project-
                    specific costs and added an amount that reflected the owners’ general and
                    administrative costs, or overhead costs. To accomplish this, we used data
                    from FERC form 1 for each of the investor-owned projects in our sample.
                    We obtained from these forms the overall corporate (1) electric operations
                    and maintenance expenses and (2) administrative and general costs. We
                    then calculated what percentage the corporate wide administrative and
                    general costs were of the total corporate operations and maintenance
                    costs. We multiplied this percentage by the project-specific operations and
                    maintenance costs. The resulting amounts were added to the operations
                    and maintenance costs for the investor-owned projects. Because we did not
                    have adequate information on the publicly owned projects in our sample,
                    we used an annual average percentage, on the basis of data for the investor-
                    owned utilities, and applied it to the publicly owned projects in the sample.

                    BCPS’ operations and maintenance costs posed a special challenge. As we
                    mentioned above, pumped-storage projects pump water up into a reservoir
                    during off-peak hours, when the electricity prices are relatively low, and
                    then generate electricity with the stored water during peak-demand hours.




                    21
                      According to OMB Circular A-94, “Guidelines and Discount Rates for Benefit-Cost
                    Analysis of Federal Programs,” the real (constant dollar) rate of 7 percent “approximates
                    the marginal pretax rate of return on an average investment in the private sector in recent
                    years.” Investor-owned electric utilities, however, belong to the corporate segment of the
                    private sector. According to the Office of Management and Budget, the private, real pretax
                    rate of return on an average investment in the corporate private sector over the period 1991
                    through 2001 has been about 10 percent, making an after-tax rate of about 7 percent a
                    reasonable estimate for the corporate sector. The level of financial risk in the regulated
                    electric utility industry has generally been lower, so historical rates of return were probably
                    also lower than the average for the corporate sector. However, unregulated energy
                    companies that operate in today’s restructured electricity markets face higher risk levels
                    than their regulated counterparts did in the past.




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        FERC form 1 did not include the costs of pumping water that a
        pumped-storage facility incurs as part of its normal operations. However,
        Dominion Energy provided us with hourly data on its use of electric power
        for pumping, as well as power generation, for 1998 and 1999. We used the
        hourly pumping data and PJM-WH prices to estimate BCPS’ pumping costs
        for those 2 years. We multiplied the hourly amounts of power it used for
        pumping by the PJM-WH hourly prices and summed the products. We also
        relied on its 1998 and 1999 data to extrapolate this project’s pumping costs
        for 2000 and 2003.22



Taxes   Taxes are paid at the corporate level—not by individual hydropower
        projects. However, to fully account for the total costs for each project, we
        assigned a portion of the project owners’ taxes to their projects in our
        sample. To accomplish this, we obtained the total corporate taxes and total
        generation in kilowatt-hours from the FERC form 1. We then divided the
        taxes by the total generation to obtain a “tax per kilowatt-hour.” We then
        multiplied this rate by the amount of generation at a given project for each
        year to produce each project’s share of the total taxes. This amount was
        then added to the total costs for that project. Publicly owned generators of
        electric power are exempt from federal income taxes, but many of them
        pay significant amounts of taxes and “tax equivalents.” We used a similar
        method, using data from EIA form 412s, to assign a portion of the tax
        burden of the public entity that owned a project in our sample to the
        individual project itself. For example, if Utility A paid $10 million in taxes
        in 1998 and its Project Y generated 10 percent of A’s total generation, we
        used 10 percent of $10 million, that is, $1 million, as our tax estimate.

        Our estimate for the projects’ year 2003 taxes is an average of their 1998
        and 1999 taxes, adjusted for inflation. We excluded 2000 from our tax
        calculations because it was a very unusual year for utilities’ finances in the
        western United States, where most of our sample projects were located.


        22
          The manager of BCPS told us that the relationship between the amount of electricity used
        for pumping water and the amount of hydropower it generates is stable over time: 1.25
        kilowatt-hours of pumping are needed for each kilowatt-hour of power generated, on
        average. We also calculated the average cost of pumping per kilowatt-hour for 1998 and
        1999, using hourly amounts of electricity used for pumping and hourly PJM-WH prices. For
        those 2 years, we calculated a ratio of this weighted average cost of pumping to the simple
        annual average of hourly PJM-WH prices. We used these relationships and BCPS’ 2000 and
        2003 hydropower generation figures to extrapolate the project’s 2000 and 2003
        pumping costs.




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                               Estimating the Fair Market Value of Federal
                               Land Used to Produce Hydropower




Data on the Federal Share of   To determine the percentage of a project’s lands that are federal, we
Project Lands                  obtained the amount of federal acreage associated with each project from
                               FERC documents. Because FERC did not have data on the total acreage of
                               each project (including federal and nonfederal lands), we generally
                               obtained the total project acreage from the each of the owners of projects
                               in our sample. (Two project owners chose not to share this information
                               with us, so we used estimates the Forest Service provided—one of the
                               agencies that manages the federal lands on which these projects are
                               located.) From this information, we determined the percentage of federal
                               land associated with each project by dividing the number of federal acres
                               by the number of total project acres. We did not include transmission line
                               acreage in our analysis because we were interested only in the primary
                               project acres.




                               Page 65                                       GAO-03-383 FERC Charges for Federal Lands
Appendix II

Net Benefits Analysis for Each of the
24 Projects in Our Sample                                                                                                                   Appendx
                                                                                                                                                  Ii




                                                    This appendix provides details on our estimates of the net benefit of
                                                    federal lands for each project. These details include the value of the
                                                    power produced and the costs to produce it. Sources for the data used
                                                    in this analysis are discussed in appendix I. For some years, our analysis
                                                    estimates that the net benefit for several projects are negative values. As
                                                    discussed in our report, a negative net benefit estimate does not mean that
                                                    the value of the land is negative or, in most cases, that the project is losing
                                                    money. Instead, a negative net benefit estimate indicates that, for that
                                                    year, the project operated below the industry average rate of return on
                                                    investment (7.22 percent) that we assigned as part of each project’s costs.
                                                    To show how the rate of return on investment can vary from year to year,
                                                    the tables below provide our estimates of the rate of return on investment
                                                    for each of the projects in our sample. (In the following tables, some totals
                                                    do not add because of rounding).



Table 8: Bath County, FERC License No. 2716

Dollars in 2002 dollars
                                                               1998                        1999                   2000                  2003
   Generation (kwh)                                  3,750,777,000             4,161,461,000             4,519,820,000         4,144,019,333
  Price                                                    $0.0413                   $0.0618                    $0.0497              $0.0724
Value of power                                       $154,855,911              $257,083,891               $224,478,155          $300,181,342
   RCLPD                                            $1,174,300,000           $1,159,900,000             $1,145,500,000        $1,102,300,000
  Rate of return on investment                                7.22%                    7.22%                     7.22%                 7.22%
Subtotal (return on investment)                       $84,784,460                $83,744,780               $82,705,100           $79,586,060
  1-year’s depreciation                               $14,400,000                $14,400,000               $14,400,000           $14,400,000
Total capital costs                                   $99,184,460                $98,144,780               $97,105,100           $93,986,060
   Taxes                                              $22,996,196                $25,514,120               $31,061,285           $24,255,158
  Operations and maintenance                          $85,111,699                $96,897,363              $100,931,663          $138,844,651
Total costs                                          $207,292,355              $220,556,262               $229,098,047          $257,085,868
Net benefit                                          ($52,436,444)               $36,527,629               ($4,619,893)          $43,095,474
  Percentage of project
  on federal lands                                             28%                         28%                     28%                  28%
Net benefit of federal lands                         ($14,682,204)               $10,227,736               ($1,293,570)          $12,066,733


Estimated return on investment                                2.75%                   10.37%                     6.82%               11.13%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owners: Virginia Dominion Power & Allegheny Power.
                                                    FERC annual charges (2002): $48,061.




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Table 9: Big Creek 1&2, FERC License No. 2175

Dollars in 2002 dollars
                                                               1998                      1999                2000                   2003
   Generation (kwh)                                 1,016,587,421                728,211,389          770,657,000            943,396,000
  Price                                                    $0.0293                    $0.0379             $0.1333                $0.0441
Value of power                                        $29,800,271                $27,607,706        $102,698,124             $41,596,288
   RCLPD                                              $61,600,000                $54,850,000          $48,100,000            $27,850,000
  Rate of return on investment                                7.22%                     7.22%              7.22%                   7.22%
Subtotal (return on investment)                        $4,447,520                  $3,960,170          $3,472,820             $2,010,770
  1-year’s depreciation                                $6,750,000                  $6,750,000          $6,750,000             $6,750,000
Total capital costs                                   $11,197,520                $10,710,170          $10,222,820             $8,760,770
   Taxes                                               $8,422,837                  $5,990,369        ($8,346,210)             $7,206,603
  Operations and maintenance                           $5,315,070                  $4,722,987          $4,518,040             $4,898,434
Total costs                                           $24,935,427                $21,423,526           $6,394,649            $20,865,807
   Net benefit                                         $4,864,844                  $6,184,180         $96,303,474            $20,730,481
  Percentage of project on
  federal lands                                               100%                       100%               100%                   100%
Net benefit of federal lands                           $4,864,844                  $6,184,180         $96,303,474            $20,730,481


Estimated return on investment                             15.12%                      18.49%            207.44%                 81.66%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Southern California Edison.
                                                    FERC annual charges (2002): $153,780.




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Table 10: Bliss, FERC License No. 1975

Dollars in 2002 dollars
                                                               1998                        1999                2000                   2003
   Generation (kwh)                                   491,650,000                465,406,000            405,601,000            463,943,000
  Price                                                    $0.0293                  $0.0379                 $0.1333                $0.0441
Value of power                                        $14,412,242                $17,644,316            $54,050,585            $20,456,210
   RCLPD                                              $93,720,000                $91,540,000            $89,360,000            $82,820,000
  Rate of return on investment                                7.22%                   7.22%                  7.22%                   7.22%
Subtotal (return on investment)                        $6,766,584                 $6,609,188             $6,451,792             $5,979,604
  1-year’s depreciation                                $2,180,000                 $2,180,000             $2,180,000             $2,180,000
Total capital costs                                    $8,946,584                 $8,789,188             $8,631,792             $8,159,604
   Taxes                                                 $984,341                 $1,591,870             $1,406,085             $1,288,105
  Operations and maintenance                           $1,194,352                 $1,597,704             $1,562,505             $1,454,008
Total costs                                           $11,125,278                $11,978,762            $11,600,382            $10,901,717
Net benefit                                            $3,286,964                 $5,665,555            $42,450,203             $9,554,493
  Percentage of project on
  federal lands                                                60%                         60%                 60%                    60%
Net benefit of federal lands                           $1,972,178                 $3,399,333            $25,470,122             $5,732,696


Estimated return on investment                             10.73%                    13.41%                 54.72%                 18.76%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Idaho Power.
                                                    FERC annual charges (2002): $16,327.




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Table 11: Boundary, FERC License No. 2144

Dollars in 2002 dollars
                                                               1998                        1999                 2000                   2003
   Generation (kwh)                                 3,827,283,720                4,445,309,880         3,786,081,000          4,353,333,000
  Price                                                    $0.0293                      $0.0379              $0.1333                $0.0441
Value of power                                       $112,193,100                $168,529,100          $504,534,981            $191,947,487
   RCLPD                                             $438,460,000                $427,670,000          $416,880,000            $384,510,000
  Rate of return on investment                                7.22%                       7.22%               7.22%                   7.22%
Subtotal (return on investment)                       $31,656,812                    $30,877,774         $30,098,736            $27,761,622
  1-year’s depreciation                               $10,790,000                    $10,790,000         $10,790,000            $10,790,000
Total capital costs                                   $42,446,812                    $41,667,774         $40,888,736            $38,551,622
   Taxes                                              $23,023,259                    $21,573,230         $25,252,386            $22,298,245
  Operations and maintenance                            $8,164,029                    $7,662,020          $7,093,877             $7,735,371
Total costs                                           $73,634,100                    $70,903,024         $73,235,000            $68,585,237
Net benefit                                           $38,559,000                    $97,626,076       $431,299,981            $123,362,250
  Percentage of project
  on federal lands                                             69%                          69%                 69%                    69%
Net benefit of federal lands                          $26,605,710                    $67,361,992       $297,596,987             $85,119,952


Estimated return on investment                              16.01%                       30.05%             110.68%                 39.30%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: City of Seattle.
                                                    FERC annual charges (2002): $33,538.




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Table 12: California Aqueduct, FERC License No. 2426

Dollars in 2002 dollars
                                                               1998                        1999                     2000                2003
   Generation (kwh)                                  1,665,149,000             2,055,889,000             1,745,986,000         1,953,370,000
  Price                                                    $0.0293                   $0.0379                     $0.1333             $0.0441
Value of power                                        $48,812,223                $77,942,175              $232,670,937           $86,128,137
   RCLPD                                            $2,392,100,000           $2,365,500,000             $2,338,900,000        $2,259,100,000
  Rate of return on investment                                7.22%                    7.22%                       7.22%               7.22%
Subtotal (return on investment)                      $172,709,620              $170,789,100               $168,868,580          $163,107,020
  1-year’s depreciation                               $26,600,000                $26,600,000                  $26,600,000        $26,600,000
Total capital costs                                  $199,309,620              $197,389,100               $195,468,580          $189,707,020
   Taxes                                                         $0                          $0                       $0                  $0
  Operations and maintenance                          $18,410,988                $19,362,864                  $25,995,071        $21,599,815
Total costs                                          $217,720,608              $216,751,964               $221,463,651          $211,306,835
Net benefit                                         ($168,908,385)            ($138,809,788)                  $11,207,286     ($125,178,698)
  Percentage of project
  on federal lands                                             16%                         16%                       16%                16%
Net benefit of federal lands                         ($27,025,342)             ($22,209,566)                   $1,793,166      ($20,028,592)


Estimated return on investment                                0.16%                    1.35%                       7.70%               1.68%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: California Department of Water Resources.
                                                    FERC annual charges (2002): $17,463.




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Table 13: Coosa River, FERC License No. 2146

Dollars in 2002 dollars
                                                               1998                       1999                2000                   2003
   Generation (kwh)                                 2,350,723,000             1,631,966,000          1,028,390,000          2,037,752,000
  Price                                                    $0.0428                   $0.0451               $0.0370                $0.0441
Value of power                                       $100,631,464               $73,579,712            $38,074,641            $89,848,715
   RCLPD                                             $705,520,000              $680,040,000          $654,560,000            $578,120,000
  Rate of return on investment                                7.22%                    7.22%                7.22%                   7.22%
Subtotal (return on investment)                       $50,938,544               $49,098,888            $47,259,232            $41,740,264
  1-year’s depreciation                               $25,480,000               $25,480,000            $25,480,000            $25,480,000
Total capital costs                                   $76,418,544               $74,578,888            $72,739,232            $67,220,264
   Taxes                                              $14,869,270               $10,322,842             $7,054,801            $12,596,056
  Operations and maintenance                           $9,016,934                  $8,538,031           $9,007,943             $8,903,706
Total costs                                          $100,304,748               $93,439,762            $88,801,975            $88,720,026
Net benefit                                              $326,716             ($19,860,049)          ($50,727,334)             $1,128,688
  Percentage of project
  on federal lands                                             0.2%                       0.2%               0.2%                    0.2%
Net benefit of federal lands                                   $555                 ($33,762)            ($86,236)                 $1,919


Estimated return on investment                                7.27%                    4.30%                -0.53%                  7.42%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Alabama Power.
                                                    FERC annual charges (2002): $6,933.




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Table 14: Don Pedro, FERC License No. 2299

Dollars in 2002 dollars
                                                               1998                        1999                       2000                  2003
   Generation (kwh)                                 1,053,287,020                  702,548,000                  477,697,000          636,108,000
  Price                                                    $0.0293                      $0.0379                    $0.1333               $0.0441
Value of power                                        $30,876,085                  $26,634,765                  $63,658,133          $28,047,322
   RCLPD                                             $505,640,000                $499,830,000                  $494,020,000         $476,590,000
  Rate of return on investment                                7.22%                       7.22%                      7.22%                 7.22%
Subtotal (return on investment)                       $36,507,208                  $36,087,726                  $35,668,244          $34,409,798
  1-year’s depreciation                                 $5,810,000                  $5,810,000                   $5,810,000           $5,810,000
Total capital costs                                   $42,317,208                  $41,897,726                  $41,478,244          $40,219,798
   Taxes                                                          $0                          $0                        $0                    $0
  Operations and maintenance                            $2,968,359                  $2,539,956                   $3,516,604           $3,055,939
Total costs                                           $45,285,567                  $44,437,682                  $44,994,848          $43,275,737
Net benefit                                          ($14,409,482)               ($17,802,918)                  $18,663,284        ($15,228,415)
  Percentage of project
  on federal lands                                             37%                          37%                        37%                  37%
Net benefit of federal lands                          ($5,331,508)                ($6,587,080)                   $6,905,415          ($5,634,514)


Estimated return on investment                                4.37%                       3.66%                     11.00%                 4.02%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owners: Turlock and Modesto Irrigation Districts.
                                                    FERC annual charges (2002): $249,313.




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Table 15: Feather River, FERC License No. 2100

Dollars in 2002 dollars
                                                               1998                       1999                      2000                2003
   Generation (kwh)                                  3,847,301,000             2,925,184,000             2,524,105,000         3,189,787,000
  Price                                                    $0.0293                   $0.0379                     $0.1333             $0.0441
Value of power                                       $112,779,887              $110,898,596               $336,363,450          $140,644,329
   RCLPD                                            $1,586,540,000           $1,567,080,000             $1,547,620,000        $1,489,240,000
  Rate of return on investment                                7.22%                    7.22%                       7.22%               7.22%
Subtotal (return on investment)                      $114,548,188              $113,143,176               $111,738,164          $107,523,128
  1-year’s depreciation                               $19,460,000                $19,460,000                  $19,460,000        $19,460,000
Total capital costs                                  $134,008,188              $132,603,176               $131,198,164          $126,983,128
   Taxes                                                         $0                         $0                        $0                  $0
  Operations and maintenance                          $12,768,334                $12,360,892                  $11,570,904        $12,388,113
Total costs                                          $146,776,522              $144,964,068               $142,769,068          $139,371,241
Net benefit                                          ($33,996,635)             ($34,065,471)              $193,594,382            $1,273,088
  Percentage of project
  on federal lands                                             18%                        18%                        18%                18%
Net benefit of federal lands                          ($6,119,394)               ($6,131,785)                 $34,846,989           $229,156


Estimated return on investment                                5.08%                    5.05%                      19.73%               7.31%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: California Department of Water Resources.
                                                    FERC annual charges (2002): $9,158.




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Table 16: Haas-Kings River, FERC License No. 1988

Dollars in 2002 dollars
                                                               1998                       1999                   2000                   2003
   Generation (kwh)                                 1,000,289,000                 493,756,000             743,326,000            860,409,000
  Price                                                    $0.0293                     $0.0379                $0.1333                $0.0441
Value of power                                        $29,322,499                 $18,719,112             $99,055,981            $37,937,219
   RCLPD                                             $407,080,000                $400,260,000           $393,440,000            $372,980,000
  Rate of return on investment                                7.22%                      7.22%                 7.22%                   7.22%
Subtotal (return on investment)                       $29,391,176                 $28,898,772             $28,406,368            $26,929,156
  1-year’s depreciation                                 $6,820,000                  $6,820,000             $6,820,000             $6,820,000
Total capital costs                                   $36,211,176                 $35,718,772             $35,226,368            $33,749,156
   Taxes                                              $12,264,819                  $5,391,264           ($20,449,656)             $8,828,041
  Operations and maintenance                            $3,207,088                  $3,732,820             $3,044,591             $3,377,873
Total costs                                           $51,683,083                 $44,842,856             $17,821,303            $45,955,071
Net benefit                                          ($22,360,584)              ($26,123,744)             $81,234,679            ($8,017,852)
  Percentage of project
  on federal lands                                             85%                            85%                85%                    85%
Net benefit of federal lands                         ($19,006,496)              ($22,205,182)             $69,049,477            ($6,815,174)


Estimated return on investment                                1.73%                      0.69%                27.87%                   5.07%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Pacific Gas and Electric.
                                                    FERC annual charges (2002): $202,378.




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Table 17: Hells Canyon, FERC License No. 1971

Dollars in 2002 dollars
                                                               1998                      1999                 2000                   2003
   Generation (kwh)                                 7,482,604,000                7,041,547,000       5,768,411,000          6,998,260,000
  Price                                                    $0.0293                    $0.0379              $0.1333                $0.0441
Value of power                                       $219,345,258                $266,956,772        $768,701,233            $308,567,808
   RCLPD                                             $703,460,000                $679,470,000        $655,480,000            $583,510,000
  Rate of return on investment                                7.22%                     7.22%               7.22%                   7.22%
Subtotal (return on investment)                       $50,789,812                 $49,057,734          $47,325,656            $42,129,422
  1-year’s depreciation                               $23,990,000                 $23,990,000          $23,990,000            $23,990,000
Total capital costs                                   $74,779,812                 $73,047,734          $71,315,656            $66,119,422
   Taxes                                              $14,981,058                 $24,084,830          $19,997,178            $19,532,944
  Operations and maintenance                           $5,877,905                  $7,760,440           $7,664,822             $7,114,735
Total costs                                           $95,638,775                $104,893,003          $98,977,656            $92,767,101
Net benefit                                          $123,706,483                $162,063,769        $669,723,577            $215,800,707
  Percentage of project
  on federal lands                                             90%                       90%                  90%                    90%
Net benefit of federal lands                         $111,335,835                $145,857,392        $602,751,219            $194,220,636


Estimated return on investment                             24.81%                      31.07%             109.39%                 44.20%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Idaho Power.
                                                    FERC annual charges (2002): $371,075.




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Table 18: Kerckhoff 1&2, FERC License No. 96

Dollars in 2002 dollars
                                                               1998                        1999                  2000                   2003
   Generation (kwh)                                   811,487,000                 442,526,000             519,900,000            685,309,000
  Price                                                    $0.0293                     $0.0379                $0.1333                $0.0441
Value of power                                        $23,787,952                 $16,776,898             $69,282,125            $30,216,696
   RCLPD                                             $132,900,000                $126,700,000           $120,500,000            $101,900,000
  Rate of return on investment                                7.22%                      7.22%                 7.22%                   7.22%
Subtotal (return on investment)                         $9,595,380                 $9,147,740              $8,700,100             $7,357,180
  1-year’s depreciation                                 $6,200,000                  $6,200,000             $6,200,000             $6,200,000
Total capital costs                                   $15,795,380                 $15,347,740             $14,900,100            $13,557,180
   Taxes                                                $9,949,865                 $4,831,890           ($14,302,979)             $7,390,878
  Operations and maintenance                            $3,150,251                  $3,437,569             $3,012,817             $3,249,366
Total costs                                           $28,895,497                 $23,617,198              $3,609,938            $24,197,424
Net benefit                                           ($5,107,544)                ($6,840,301)            $65,672,187             $6,019,272
  Percentage of project
  on federal lands                                             66%                            66%                66%                    66%
Net benefit of federal lands                          ($3,370,979)                ($4,514,599)            $43,343,643             $3,972,720


Estimated return on investment                                3.38%                      1.82%                61.72%                 13.13%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Pacific Gas and Electric.
                                                    FERC annual charges (2002): $25,476.




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Table 19: Kerr, FERC License No. 5

Dollars in 2002 dollars
                                                               1998                       1999                       2000                        2003
   Generation (kwh)                                 1,013,017,230               1,112,198,118              1,124,722,000               1,164,570,000
  Price                                                    $0.0293                     $0.0379                    $0.1333                     $0.0441
Value of power                                        $29,695,615                 $42,165,283               $149,880,996                 $51,348,308
   RCLPD                                             $162,760,000               $158,745,000                $154,730,000               $142,685,000
  Rate of return on investment                                7.22%                     7.22%                       7.22%                      7.22%
Subtotal (return on investment)                       $11,751,272                 $11,461,389                $11,171,506                 $10,301,857
  1-year’s depreciation                                 $4,015,000                 $4,015,000                  $4,015,000                 $4,015,000
Total capital costs                                   $15,766,272                 $15,476,389                $15,186,506                 $14,316,857
   Taxes                                                $7,033,669                 $7,740,389                  $4,968,029                 $7,387,029
  Operations and maintenance                            $1,806,949                 $2,021,255                  $1,592,134                 $1,824,738
Total costs                                           $24,606,889                 $25,238,033                $21,746,669                 $23,528,624
Net benefit                                             $5,088,725                $16,927,250               $128,134,327                 $27,819,685
  Percentage of project
  on federal lands                                              2%                          2%                         2%                          2%
Net benefit of federal lands                              $101,775                   $338,545                  $2,562,687                   $556,394


Estimated return on investment                              10.35%                     17.88%                      90.03%                     26.72%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: PP&L Montana.
                                                    FERC annual charges (2002): $1,823.
                                                    For this project, operations and maintenance costs were adjusted to exclude payments made for the
                                                    use of Native American lands.




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Table 20: North Fork, FERC License No. 2195

Dollars in 2002 dollars
                                                               1998                       1999                2000                   2003
   Generation (kwh)                                   507,690,000                 586,514,000          466,426,000            535,966,000
  Price                                                    $0.0293                     $0.0379             $0.1333                $0.0441
Value of power                                        $14,882,439                 $22,235,722          $62,156,154            $23,631,853
   RCLPD                                             $100,280,000                 $96,460,000          $92,640,000            $81,180,000
  Rate of return on investment                                7.22%                      7.22%              7.22%                   7.22%
Subtotal (return on investment)                         $7,240,216                 $6,964,412           $6,688,608             $5,861,196
  1-year’s depreciation                                 $3,820,000                 $3,820,000           $3,820,000             $3,820,000
Total capital costs                                   $11,060,216                 $10,784,412          $10,508,608             $9,681,196
   Taxes                                                $2,561,569                 $2,728,153           $1,940,147             $2,644,861
  Operations and maintenance                            $3,813,505                 $3,521,370           $2,643,929             $3,374,338
Total costs                                           $17,435,290                 $17,033,935          $15,092,684            $15,700,395
Net benefit                                           ($2,552,852)                 $5,201,787          $47,063,470             $7,931,459
  Percentage of project
  on federal lands                                             16%                         16%                16%                    16%
Net benefit of federal lands                            ($408,456)                   $832,286           $7,530,155             $1,269,033


Estimated return on investment                                4.67%                    12.61%              58.02%                 16.99%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Portland General Electric.
                                                    FERC annual charges (2002): $7,087.




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Table 21: North Umpqua, FERC License No. 1927

Dollars in 2002 dollars
                                                               1998                     1999                 2000                   2003
   Generation (kwh)                                 1,068,238,000               1,151,767,000         992,251,000          1,067,051,000
  Price                                                    $0.0293                   $0.0379              $0.1333                $0.0441
Value of power                                        $31,314,358                $43,665,405        $132,227,847             $47,048,493
   RCLPD                                             $449,780,000               $441,260,000        $432,740,000            $407,180,000
  Rate of return on investment                                7.22%                    7.22%               7.22%                   7.22%
Subtotal (return on investment)                       $32,474,116                $31,858,972          $31,243,828            $29,398,396
  1-year’s depreciation                                 $8,520,000                $8,520,000           $8,520,000             $8,520,000
Total capital costs                                   $40,994,116                $40,378,972          $39,763,828            $37,918,396
   Taxes                                                $2,665,609                $3,531,653           $2,919,663             $3,098,631
  Operations and maintenance                            $1,577,117                $4,486,202           $4,607,187             $3,726,428
Total costs                                           $45,236,841                $48,396,827          $47,290,678            $44,743,455
Net benefit                                          ($13,922,483)               ($4,731,423)         $84,937,169             $2,305,039
  Percentage of project
  on federal lands                                            100%                     100%                 100%                   100%
Net benefit of federal lands                         ($13,922,483)               ($4,731,423)         $84,937,169             $2,305,039


Estimated return on investment                                4.12%                    6.15%              26.85%                   7.79%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Pacificorp.
                                                    FERC annual charges (2002): $107,525.




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Table 22: Noxon Rapids, FERC License No. 2075

Dollars in 2002 dollars
                                                               1998                        1999                2000                   2003
   Generation (kwh)                                 1,688,285,000             1,896,663,000           1,635,238,000          1,996,970,000
  Price                                                    $0.0293                  $0.0379                 $0.1333                $0.0441
Value of power                                        $49,490,433               $71,905,653           $217,912,605             $88,050,552
   RCLPD                                             $624,740,000              $613,080,000           $601,420,000            $566,440,000
  Rate of return on investment                                7.22%                   7.22%                  7.22%                   7.22%
Subtotal (return on investment)                       $45,106,228               $44,264,376             $43,422,524            $40,896,968
  1-year’s depreciation                               $11,660,000               $11,660,000             $11,660,000            $11,660,000
Total capital costs                                   $56,766,228               $55,924,376             $55,082,524            $52,556,968
   Taxes                                               $4,451,279                $4,625,208              $1,345,019             $4,538,243
  Operations and maintenance                           $2,582,016                $3,156,814              $4,040,562             $3,309,051
Total costs                                           $63,799,523               $63,706,397             $60,468,104            $60,404,263
Net benefit                                          ($14,309,090)               $8,199,255           $157,444,500             $27,646,289
  Percentage of project
  on federal lands                                              5%                          5%                  5%                     5%
Net benefit of federal lands                            ($715,454)                 $409,963              $7,872,225             $1,382,314


Estimated return on investment                                4.93%                   8.56%                 33.40%                 12.10%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Avista.
                                                    FERC annual charges (2002): $21,880.




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Table 23: Pit River, FERC License No. 233

Dollars in 2002 dollars
                                                               1998                        1999                  2000                   2003
   Generation (kwh)                                 2,421,714,000               2,203,044,000           1,973,926,000          2,170,564,000
  Price                                                    $0.0293                     $0.0379                $0.1333                $0.0441
Value of power                                        $70,990,190                 $83,521,066           $263,046,331             $95,704,672
   RCLPD                                             $420,400,000                $408,800,000           $397,200,000            $362,400,000
  Rate of return on investment                                7.22%                      7.22%                 7.22%                   7.22%
Subtotal (return on investment)                       $30,352,880                 $29,515,360             $28,677,840            $26,165,280
  1-year’s depreciation                               $11,600,000                 $11,600,000             $11,600,000            $11,600,000
Total capital costs                                   $41,952,880                 $41,115,360             $40,277,840            $37,765,280
   Taxes                                              $29,693,302                 $24,054,781           ($54,304,717)            $26,874,041
  Operations and maintenance                            $6,244,151                  $5,675,887             $5,072,667             $5,746,843
Total costs                                           $77,890,332                 $70,846,028            ($8,954,211)            $70,386,164
Net benefit                                           ($6,900,142)                $12,675,038           $272,000,542             $25,318,508
  Percentage of project
  on federal lands                                             20%                            20%                20%                    20%
Net benefit of federal lands                          ($1,380,028)                  $2,535,008            $54,400,108             $5,063,702


Estimated return on investment                                5.58%                     10.32%                75.70%                 14.21%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Pacific Gas and Electric.
                                                    FERC annual charges (2002): $49,448.




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Table 24: Priest Rapids, FERC License No. 2114

Dollars in 2002 dollars
                                                               1998                         1999                       2000                   2003
   Generation (kwh)                                 9,432,280,000               11,314,265,000                9,621,814,000         10,671,292,000
  Price                                                    $0.0293                      $0.0379                     $0.1333                $0.0441
Value of power                                       $276,498,114                 $428,942,626               $1,282,207,576           $470,519,412
   RCLPD                                             $857,620,000                 $819,840,000                $782,060,000            $668,720,000
  Rate of return on investment                                7.22%                       7.22%                      7.22%                   7.22%
Subtotal (return on investment)                       $61,920,164                  $59,192,448                  $56,464,732            $48,281,584
  1-year’s depreciation                               $37,780,000                  $37,780,000                  $37,780,000            $37,780,000
Total capital costs                                   $99,700,164                  $96,972,448                  $94,244,732            $86,061,584
   Taxes                                                $7,637,605                   $8,356,892                  $8,652,931             $7,997,248
  Operations and maintenance                          $23,349,213                  $22,000,357                  $25,281,673            $23,882,666
Total costs                                          $130,686,981                 $127,329,696                $128,179,336            $117,941,498
Net benefit                                          $145,811,132                 $301,612,930               $1,154,028,240           $352,577,914
  Percentage of project
  on federal lands                                               8%                           8%                        8%                     8%
Net benefit of federal lands                          $11,664,891                  $24,129,034                  $92,322,259            $28,206,233


Estimated return on investment                              24.22%                       44.01%                    154.78%                 59.94%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Grant County Public Utility District.
                                                    FERC annual charges (2002): $49,262.




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Table 25: Rock Island, FERC License No. 943

Dollars in 2002 dollars
                                                               1998                         1999                        2000                   2003
   Generation (kwh)                                 2,567,863,600                3,184,966,500                 2,747,085,000          2,938,037,000
  Price                                                    $0.0293                      $0.0379                      $0.1333                $0.0441
Value of power                                        $75,274,424                 $120,747,384                 $366,077,873            $129,544,149
   RCLPD                                             $397,600,000                 $383,400,000                 $369,200,000            $326,600,000
  Rate of return on investment                                7.22%                       7.22%                       7.22%                   7.22%
Subtotal (return on investment)                       $28,706,720                  $27,681,480                   $26,656,240            $23,580,520
  1-year’s depreciation                               $14,200,000                  $14,200,000                   $14,200,000            $14,200,000
Total capital costs                                   $42,906,720                  $41,881,480                   $40,856,240            $37,780,520
   Taxes                                                $2,167,707                  $1,870,624                    $1,588,846             $2,019,166
  Operations and maintenance                          $16,274,989                  $17,364,417                   $15,436,263            $16,561,592
Total costs                                           $61,349,416                  $61,116,521                   $57,881,350            $56,361,278
Net benefit                                           $13,925,008                  $59,630,862                 $308,196,523             $73,182,871
  Percentage of project
  on federal lands                                               1%                           1%                         1%                     1%
Net benefit of federal lands                              $139,250                     $596,309                   $3,081,965               $731,829


Estimated return on investment                              10.72%                       22.77%                      90.70%                 29.63%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Chelan County Public Utility District.
                                                    FERC annual charges (2002): $628.




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Table 26: Rocky Reach, FERC License No. 2145

Dollars in 2002 dollars
                                                               1998                         1999                        2000                   2003
   Generation (kwh)                                 5,963,472,049                7,425,230,613                 6,288,474,000          6,694,102,000
  Price                                                    $0.0293                      $0.0379                      $0.1333                $0.0441
Value of power                                       $174,813,383                 $281,502,857                 $838,005,079            $295,156,851
   RCLPD                                             $737,600,000                 $720,800,000                 $704,000,000            $653,600,000
  Rate of return on investment                                7.22%                       7.22%                       7.22%                   7.22%
Subtotal (return on investment)                       $53,254,720                  $52,041,760                   $50,828,800            $47,189,920
  1-year’s depreciation                               $16,800,000                  $16,800,000                   $16,800,000            $16,800,000
Total capital costs                                   $70,054,720                  $68,841,760                   $67,628,800            $63,989,920
   Taxes                                                $5,034,170                  $4,361,056                    $3,637,099             $4,697,613
  Operations and maintenance                          $22,186,765                  $26,363,109                   $25,907,624            $25,154,953
Total costs                                           $97,275,655                  $99,565,925                   $97,173,523            $93,842,486
Net benefit                                           $77,537,728                 $181,936,931                 $740,831,556            $201,314,365
  Percentage of project
  on federal lands                                               1%                           1%                         1%                     1%
Net benefit of federal lands                              $775,377                  $1,819,369                    $7,408,316             $2,013,144


Estimated return on investment                              17.73%                       32.46%                     112.45%                 38.02%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Chelan County Public Utility District.
                                                    FERC annual charges (2002): $2,580.




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Table 27: Skagit River, FERC License No. 553

Dollars in 2002 dollars
                                                               1998                        1999                 2000                   2003
   Generation (kwh)                                 2,182,773,373                3,165,975,767         2,510,464,000          2,766,407,000
  Price                                                    $0.0293                      $0.0379              $0.1333                $0.0441
Value of power                                        $63,985,878                $120,027,413          $334,545,644            $121,976,626
   RCLPD                                             $783,520,000                $767,890,000          $752,260,000            $705,370,000
  Rate of return on investment                                7.22%                       7.22%               7.22%                   7.22%
Subtotal (return on investment)                       $56,570,144                    $55,441,658         $54,313,172            $50,927,714
  1-year’s depreciation                               $15,630,000                    $15,630,000         $15,630,000            $15,630,000
Total capital costs                                   $72,200,144                    $71,071,658         $69,943,172            $66,557,714
   Taxes                                              $13,130,607                    $15,364,581         $16,744,282            $14,247,594
  Operations and maintenance                          $11,499,148                    $11,748,608         $11,948,450            $11,890,426
Total costs                                           $96,829,899                    $98,184,846         $98,635,904            $92,695,734
Net benefit                                          ($32,844,021)                   $21,842,567       $235,909,740             $29,280,892
  Percentage of project
  on federal lands                                             70%                          70%                 70%                    70%
Net benefit of federal lands                         ($22,990,815)                   $15,289,797       $165,136,818             $20,496,624


Estimated return on investment                                3.03%                      10.06%              38.58%                 11.37%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: City of Seattle.
                                                    FERC annual charges (2002): $917,001.




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Table 28: Swift, FERC License No. 2111

Dollars in 2002 dollars
                                                               1998                        1999                2000                   2003
   Generation (kwh)                                   738,349,000                912,943,000            629,872,000            824,169,000
  Price                                                    $0.0293                  $0.0379                 $0.1333                $0.0441
Value of power                                        $21,643,983                $34,611,189            $83,937,047            $36,339,322
   RCLPD                                             $252,800,000               $247,350,000          $241,900,000            $225,550,000
  Rate of return on investment                                7.22%                   7.22%                  7.22%                   7.22%
Subtotal (return on investment)                       $18,252,160                $17,858,670            $17,465,180            $16,284,710
  1-year’s depreciation                                 $5,450,000                $5,450,000             $5,450,000             $5,450,000
Total capital costs                                   $23,702,160                $23,308,670            $22,915,180            $21,734,710
   Taxes                                                $1,842,426                $2,799,349             $1,853,376             $2,320,888
  Operations and maintenance                            $1,729,340                $3,196,729             $3,016,732             $2,755,581
Total costs                                           $27,273,926                $29,304,748            $27,785,288            $26,811,179
Net benefit                                           ($5,629,944)                $5,306,441            $56,151,759             $9,528,143
  Percentage of project
  on federal lands                                              6%                          6%                  6%                     6%
Net benefit of federal lands                            ($337,797)                 $318,386              $3,369,106               $571,689


Estimated return on investment                                4.99%                   9.37%                 30.43%                 11.44%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Pacificorp.
                                                    FERC annual charges (2002): $18,651.




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Table 29: Thompson Falls, FERC License No. 1869

Dollars in 2002 dollars
                                                               1998                       1999                2000                   2003
   Generation (kwh)                                   505,681,000                 523,358,957          506,722,000            497,759,000
  Price                                                    $0.0293                   $0.0379               $0.1333                $0.0441
Value of power                                        $14,823,547                 $19,841,410          $67,526,018            $21,947,227
   RCLPD                                             $121,940,000              $118,430,000          $114,920,000            $104,390,000
  Rate of return on investment                                7.22%                    7.22%                7.22%                   7.22%
Subtotal (return on investment)                        $8,804,068                  $8,550,646           $8,297,224             $7,536,958
  1-year’s depreciation                                $3,510,000                  $3,510,000           $3,510,000             $3,510,000
Total capital costs                                   $12,314,068                 $12,060,646          $11,807,224            $11,046,958
   Taxes                                               $3,511,088                  $3,642,339           $2,238,251             $3,576,713
  Operations and maintenance                           $1,234,231                   $966,774            $1,006,853             $1,082,540
Total costs                                           $17,059,387                 $16,669,759          $15,052,328            $15,706,211
Net benefit                                           ($2,235,840)                 $3,171,651          $52,473,690             $6,241,016
  Percentage of project
  on federal lands                                             11%                        11%                 11%                    11%
Net benefit of federal lands                            ($245,942)                  $348,882            $5,772,106               $686,512


Estimated return on investment                                5.39%                    9.90%               52.88%                 13.20%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: PP&L Montana.
                                                    FERC annual charges (2002): $4,043.




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Table 30: Upper American River Project, FERC License No. 2101

Dollars in 2002 dollars
                                                               1998                        1999                         2000                   2003
   Generation (kwh)                                  2,818,100,622               2,317,979,622                 1,944,354,622          2,476,064,622
  Price                                                    $0.0293                      $0.0379                      $0.1333                $0.0441
Value of power                                        $82,609,879                  $87,878,467                 $259,105,635            $109,174,828
   RCLPD                                            $1,377,020,000             $1,338,290,000                 $1,299,560,000         $1,183,370,000
  Rate of return on investment                                7.22%                       7.22%                       7.22%                   7.22%
Subtotal (return on investment)                       $99,420,844                  $96,624,538                   $93,828,232            $85,439,314
  1-year’s depreciation                               $38,730,000                  $38,730,000                   $38,730,000            $38,730,000
Total capital costs                                  $138,150,844                $135,354,538                  $132,558,232            $124,169,314
   Taxes                                                  $103,413                      $93,043                      $49,249                $98,228
  Operations and maintenance                          $10,759,147                  $10,641,772                   $10,080,115            $10,627,978
Total costs                                          $149,013,405                $146,089,352                  $142,687,596            $134,895,520
Net benefit                                          ($66,403,526)               ($58,210,885)                 $116,418,039           ($25,720,692)
  Percentage of project
  on federal lands                                             59%                          59%                         59%                    59%
Net benefit of federal lands                         ($39,178,080)               ($34,344,422)                   $68,686,643          ($15,175,208)


Estimated return on investment                                2.40%                       2.87%                      16.18%                   5.05%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Sacramento Municipal Utility District.
                                                    FERC annual charges (2002): $285,804.




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Table 31: Upper North Fork Feather River, FERC License No. 2105

Dollars in 2002 dollars
                                                               1998                        1999                 2000                   2003
   Generation (kwh)                                 1,524,166,457               1,297,626,219          1,251,223,000          1,482,681,522
  Price                                                    $0.0293                     $0.0379               $0.1333                $0.0441
Value of power                                        $44,679,457                 $49,195,171          $166,738,581             $65,374,506
   RCLPD                                             $417,360,000                $406,070,000          $394,780,000            $360,910,000
  Rate of return on investment                                7.22%                      7.22%                7.22%                   7.22%
Subtotal (return on investment)                       $30,133,392                 $29,318,254            $28,503,116            $26,057,702
  1-year’s depreciation                               $11,290,000                 $11,290,000            $11,290,000            $11,290,000
Total capital costs                                   $41,423,392                 $40,608,254            $39,793,116            $37,347,702
   Taxes                                              $18,688,224                 $14,168,630          ($34,422,421)            $16,428,427
  Operations and maintenance                            $6,233,997                  $7,331,316            $5,462,547             $6,431,826
Total costs                                           $66,345,614                 $62,108,200            $10,833,243            $60,207,955
Net benefit                                          ($21,666,156)              ($12,913,029)          $155,905,338              $5,166,551
  Percentage of project
  on federal lands                                               4%                           4%                 4%                     4%
Net benefit of federal lands                            ($866,646)                  ($516,521)            $6,236,214               $206,662


Estimated return on investment                                2.03%                      4.04%               46.71%                   8.65%
Sources: Various agencies (data), GAO (analysis).

                                                    Notes: Owner: Pacific Gas and Electric.
                                                    FERC annual charges (2002): $85,389.




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Appendix III

Comments from the Federal Energy
Regulatory Commission                                                         Appendx
                                                                                    iI




Note: GAO’s comments
appear at the end of this
appendix.




See comment 1.




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Comments from the Federal Energy
Regulatory Commission




Page 91                            GAO-03-383 FERC Charges for Federal Lands
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                 Comments from the Federal Energy
                 Regulatory Commission




See comment 2.




See comment 3.




See comment 4.




See comment 5.




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                              Comments from the Federal Energy
                              Regulatory Commission




See comment 6.




Note: Page numbers in
the draft report may differ
from those in this report.

See comment 7.




See comment 5.




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                 Comments from the Federal Energy
                 Regulatory Commission




See comment 5.




See comment 8.




                 Page 94                            GAO-03-383 FERC Charges for Federal Lands
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                 Comments from the Federal Energy
                 Regulatory Commission




                 The following are GAO’s comments on the Federal Energy Regulatory
                 Commission’s letter dated April 2, 2003.



GAO’s Comments   1. We disagree. As we discuss, the value of federal land varied because
                    the wholesale price of electricity varied during the 3 years we
                    reviewed—-not because our analysis was flawed. Furthermore, even
                    the lowest of our estimates of the value of federal lands used for
                    hydropower demonstrates that FERC’s current annual charge system is
                    getting less than 2 percent of the land’s hydropower value. We shared
                    these results in detail with high-level FERC officials—-including
                    FERC’s Executive Director—in September 2002 and February 2003. In
                    contrast to their written comments, FERC officials at those meetings
                    indicated that they had no analytical disagreement with our analysis,
                    and as we indicate in our report, the Executive Director agreed that a
                    reassessment of FERC’s current annual charge system would be
                    appropriate.

                 2. We do not specifically recommend that FERC use a net benefits
                    approach as a mechanism for levying annual charges. However, we do
                    recommend that FERC consider the hydropower value of the land—as
                    well as the Federal Power Act’s other competing goals of encouraging
                    the development of hydropower and avoiding unreasonable rate
                    increases to consumers—to develop a reasonable annual charge. As we
                    reported, FERC’s annual charge system is based on a fee schedule that
                    was not designed for hydropower uses, and that does not accurately
                    assess fair market value for the fee schedule’s original intended
                    purpose. FERC did not address these shortcomings in its comments.
                    Moreover, because FERC officials have not analyzed the value of
                    federal lands used to produce hydropower for more than 15 years, it is
                    difficult for FERC to address such questions as (1) what is the fair
                    market value of these lands, (2) how much does FERC need to discount
                    from fair market value to adequately encourage the development of
                    hydropower, and (3) at what point would annual charges based on the
                    fair market value result in unreasonable rate increases to consumers.
                    After completing such an analysis FERC will be in a better position to
                    determine what annual charges are reasonable.

                 3. As mentioned in comment 2, we do not specifically recommend that
                    FERC adopt a net benefits approach. We recognize that in reassessing
                    its current annual charge system, by whatever method it uses, FERC
                    may have to consider the administrative burden it may pose for itself



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    and licensees. In the end, FERC has to consider the costs and benefits
    of revising its current system. Since our estimates indicate that the
    federal lands are worth hundreds of millions of dollars annually, it is
    likely worthwhile for FERC to expend more resources than it does
    under its existing system. Regarding licensees, FERC currently requires
    many licensees to report an enormous amount of data in its annual
    FERC Form 1 submissions. For several licensees in our sample, the
    completed form was more than an inch thick. In our view, FERC has
    not demonstrated that requiring licensees to provide additional data
    would significantly increase the existing burden on licensees. (See also
    comment 5.)

4. We disagree with FERC’s apparent assertion that the federal land
   management agencies—not FERC—are responsible for determining
   the amount of federal acreage to levy an annual charge, and that
   through the process of issuing a public notice, federal land
   management agencies and the license applicant will resolve any
   questions about the number of federal acres involved. We have two
   concerns about this assertion. First, under the Federal Power Act,
   developing and executing an annual charge system is FERC’s
   responsibility—not that of the federal land management agencies’.
   Accordingly, FERC should ensure that it has accurate and verified
   information on the amount of federal acres that licensees should be
   charged for using. Second, if FERC wants the federal land management
   agencies to verify federal acreage, then FERC needs to formally
   communicate this task to the agencies, develop mutually agreed to
   protocols, and confirm that the work was completed. According to
   officials from the Forest Service and the Department of the Interior,
   none of these actions have occurred.

5. See comment 2. In addition, we do not recommend that FERC perform
   a net benefit analysis every year on all projects that use federal lands.
   Finally, if FERC reassesses its current annual charge system, it needs to
   decide which valuation tools to use, how to balance the competing
   goals of the Federal Power Act, and what revisions to make.

6. If FERC decides to reassess and revise its annual charge system, it does
   not have to use an annual charge system that fluctuates with electricity
   markets. FERC can make decisions on the basis of long-term
   expectations that would tend to mitigate short-term volatility. In the
   past, FERC has approved annual charges for tribal lands that (1) were
   based on a long-term analysis of the value for the use of the land and



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    (2) were a fixed amount so that licensees could plan and budget
    for them.

7. We disagree that our presentation of issues regarding the databases
   supporting FERC’s annual charge program is “misleading.” Even though
   these databases were established for varying reasons, FERC still has to
   correct conflicting information. However, as discussed in the report,
   the databases for several cases we reviewed contained conflicting
   billing or federal acreage information that we could not resolve. More
   importantly, FERC staff had difficulty resolving this conflicting
   information, and in some cases never did.

8. FERC appears to agree with our essential point that, in valuing federal
   lands, what matters is how much these lands contribute to the project’s
   economic benefit. The value of the economic contribution of federal
   lands to hydropower production forms the basis for the approach we
   took in this report. We recognize that for many of the projects in our
   sample, a portion of the acreage is owned by the federal government
   and the remainder is owned by other parties. For our analysis, we
   multiplied the value to hydropower production of all lands in each
   project by the percentage of the project owned by the federal
   government. However, if FERC can differentiate between project lands
   that are more or less important in producing economic value, then
   FERC would be justified in setting annual charges accordingly.




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                                                                                    iIV




Note: GAO’s comments
appear at the end of this
appendix.




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See comment 1.



See comment 2.




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See comment 3.




See comment 1.




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See comment 4.




See comment 1.




See comment 5.




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See comment 6.




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See comment 7.




See comment 8.




See comment 9.




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See comment 10.




See comment 1.




See comment 11.




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See comment 12.




See comment 13.




See comment 14.




See comment 1.




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See comment 15.




See comment 1.




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See comment 15.




See comments 1 and 14.




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See comment 16.




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See comment 17.




See comment 18.




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See comment 1.




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See comment 1.




See comment 1.




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See comment 1.




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See comment 13.




See comment 19.




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See comment 1.




See comment 20.




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See comments 20 and 1.




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See comments 18 and 1.




See comment 21.




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See comment 1.




See comment 3.




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See comment 1.




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See comments 22 and 23.




See comment 24.




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See comment 17.




See comment 1.




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See comment 1.




See comment 1.




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See comment 18.




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See comment 1.




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See comment 14.




See comment 25.




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See comment 26.




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See comment 27.




See comment 28.




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Note: This map may be
viewed in color by going to
www.eia.doe.gov/cheaf/
electricity/chg_str/
regmap.html.




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See comment 29.




See comment 10.




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See comment 18.




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See comment 1.




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                 The following are GAO’s comments on the National Hydropower
                 Association’s letter dated March 31, 2003.



GAO’s Comments   1. We do not specifically recommend that FERC adopt our methodology
                    as a mechanism for levying annual charges, as NHA later acknowledges
                    on page 2 of its comments. Instead, we used the net benefits approach
                    as a tool to value the federal lands used by a sample of FERC-licensed
                    hydropower projects. In so doing, we found that FERC is collecting
                    only a very small percentage of the federal lands’ value in its current
                    annual charge system. We also recognize that an annual charge that
                    better reflects the value of land used for hydropower may likely raise
                    consumers’ costs. Consequently, we recommend that FERC reassess its
                    current annual charge system, and in making any revisions, FERC
                    consider “the federal land’s fair market value as well as the competing
                    goals of encouraging hydropower development and avoiding
                    unreasonable rate increases to consumers.” Under the Federal Power
                    Act, FERC is directed to assess reasonable annual charges for the use
                    of federal land, taking into account the act’s competing goals. However,
                    in our view, it is difficult for FERC to make an informed decision about
                    what represents a reasonable annual charge without having a clear
                    understanding of the land’s fair market value.

                 2. These paragraphs summarize several points that NHA raised in the
                    body of its comments. Our responses to these points are discussed in
                    the comments that follow.

                 3. As the report discusses, while the Federal Power Act does not require
                    FERC to charge fair market value, FERC has determined that fair
                    market value is “the most reasonable method” of compensating the
                    government for the use of its lands.

                 4. Even if we had not included 2000 in our analysis, our core findings
                    would remain the same—that FERC’s annual charges are less than 2
                    percent of the fair market value of federal lands. As we recognize in the
                    report, 2000 was not a representative year. However, by using six
                    different market conditions, we ensured that our estimates would not
                    be overly influenced by market conditions in any single year.

                 5. Our report extensively discusses the potential impacts of increased
                    annual charges on consumers and licensees. These impacts will largely
                    depend on (1) how much of the land’s fair market value FERC levies as



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    an annual charge and (2) whether the relevant project owner operates
    in a regulated or restructured electricity environment. (See also
    comment 1.) In addition, in no case should charging fair market value
    for the land result in an economic project’s becoming uneconomic.
    A net benefit analysis reveals the economic contributions that federal
    lands make to the production of hydropower. Should FERC act at
    some point to capture all or some of this value as an annual charge,
    economic projects will still yield a rate of return that is at or above the
    industry average.

6. The net benefits method that we used is sensitive to short-term
   volatility in electricity market conditions as well as to our annualized
   capital cost estimates. Our estimates of a given project’s replacement
   cost less physical depreciation (RCLPD) may be so high that its
   estimated net benefits could be negative for a low-price year, such as
   1998. A negative net benefits estimate for such a project means that the
   hydropower that it produced was more expensive than the least-cost
   alternative for that year. On the basis of the specific year’s data, an
   investor would pay zero dollars for the right to use this project’s land
   for hydropower generation because there are lower-cost alternatives.

    A project’s negative net benefits estimate for the use of the land for a
    specific year, however, does not mean that the project’s land has no
    value in hydropower generation. Over the lifetime of the project, the
    average year’s net benefits to the land may be positive owing to higher
    average electricity prices. However, a negative net benefit estimate, if
    accurate and representative for expected future market conditions,
    would mean that the full life-cycle cost of the project is above the
    current least-cost alternative. Consequently, an investor considering
    building such a project today would not find it economically feasible.1
    Nevertheless, a consistently negative net benefits estimate for the land
    in hydropower use does not mean that the federal land has no value. It
    may be valuable for other uses, such as cutting timber or grazing
    livestock.



1
  Many hydropower projects were built decades ago under different economic
circumstances. Some projects may or may not be considered economically feasible under
today’s economic conditions. If an existing project would not be considered economically
feasible today, it may still be profitable for the original owner or a future buyer. The majority
of capital costs for most projects were incurred decades ago, and project owners are likely
to have been largely compensated for these costs at rates of return set by regulators.




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    It is important to reiterate, in this regard, that our 1998 estimates are
    low for the western projects in our sample because 1998 wholesale
    prices in the western United States were relatively low. The average
    wholesale prices of electricity in the western United States are not
    likely to be as low for extended periods of time in the future. Our 2003
    scenario, which is based on an estimate of expected long-run average
    wholesale electricity prices into the foreseeable future, yields only four
    negative net benefits estimates. We also note that our net benefits
    estimates for all scenarios are probably conservative because we used
    capital cost estimates based on RCLPD. We used RCLPD because we
    could not obtain reliable data on net book value, which is a more
    appropriate measure of capital costs, given our specific method of
    annualizing capital costs. RCLPD is likely to be systematically higher
    than actual capital costs, resulting in lower net benefits estimates in
    some cases. In addition, for three of our sample projects, we counted
    all capital costs against hydropower benefits, although the projects
    have other primary purposes besides hydropower generation, such as
    water supply conveyance, irrigation, or flood protection. (See app. I. for
    further discussion.)

7. As we state in our report, our methodology recognizes other fixed
   factors of production. It compensates the owners of capital for their
   capital investments at an after-tax rate of return reflecting industry
   averages. Appendix I provides further details on the capital costs that
   we assigned to each project’s physical assets, including “(1) reservoirs,
   dams and waterways, (2) power plant structures, (3) power plant
   equipment, and (4) roads and bridges.” The equation we use for our net
   benefits estimate includes a capital depreciation factor and a return on
   the capital investment based on the electric utility’s average cost of
   capital (for both debt and equity.) We also state in appendix I that the
   appropriate variable in our equation is the net book value (NBV) of the
   assets, but since NBV data were not available, we used estimates of
   RCLPD. We further point out that RCLPD estimates are “likely to be
   systematically higher than the amount that would adequately
   compensate project owners for such costs” because RCLPD is
   measured in today’s dollars, while NBV is measured in historical dollar
   values corresponding to the dates when the investments were made.

    Consistent with economic theory and the land residual technique in the
    appraisal literature, we deduct the cost of all factors of production,
    including the returns to capital, from the value of hydropower in order
    to obtain an estimate of the value of land used in the production of



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    hydropower. Land is the only fixed factor that cannot be readily
    reproduced or substituted.

8. Contrary to NHA’s assertion, ratepayers may not be the only group
   affected by higher annual charges. Shareholders could end up paying
   for higher annual charges, but only when the hydropower projects have
   already been sold to private entities. As our report states:

    In a restructured environment, where electricity rates are based on
    wholesale market prices, increased annual charges are much more
    likely to affect the profitability of the electric utility and its
    shareholders than consumers. Specifically, in a restructured
    environment with competition, the utility may not be able to pass on
    increases in annual charges and still keep its customers. For this
    reason, consumers would less likely be affected.

    We agree with NHA that, in the case of divestiture, bidders for a
    hydropower project are likely to offer lower bids if they think that
    FERC’s charges for the use of federally owned land could increase. If a
    bidder is certain that FERC charges will remain low, chances are higher
    that the winning bid will exceed the NBV of the project. In these
    instances, states have stepped in and used sales proceeds over and
    above the NBV to fund “transition credits,” which lower rates to
    consumers during the transition to a restructured market. We agree that
    lower purchase prices for projects mean lower “transition credits” for
    consumers. The trade-off is between benefits to a local utility’s
    consumers on the one hand and the nation’s taxpayers on the other
    hand.

9. Traditionally, hydropower has provided consumers across the United
   States with relatively low-cost electricity, and it continues to do so
   despite significant rate increases in a number of western jurisdictions
   following the 2000 energy crisis. We recognize that substantial
   increases in annual charges for the use of federal lands could reduce
   this benefit and result in adverse economic impacts under a system of
   cost-based regulation. Under cost-based regulation, low charges for the
   use of federal land means benefits to consumers of hydroelectric power
   in the form of relatively low electricity rates, while higher charges for
   the use of federal land means benefits to U.S. taxpayers in the form of
   greater revenues to the federal government. In this regard, if FERC
   chooses to reassess its current annual charge system, our report
   recommends that FERC consider the federal land’s fair market value as



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    well as the competing goals of encouraging hydropower development
    and avoiding unreasonable rate increases to consumers.

10. We used California Power Exchange (CAPX) price data to value
    hydropower produced by projects in our sample because of the
    integrated nature of the wholesale electricity market in the western
    part of the country, including Idaho, Montana, Oregon, and Washington
    State, as well as California. Large quantities of electric power are
    traded across these states. Despite occasional differences in prices for
    different locations, annual averages for the price of power are similar.
    Furthermore, as discussed in appendix I, we consulted with a number
    of experts—including experts from the Northwest Power Planning
    Council, the California Independent System Operator, and the Idaho
    Public Utility Commission—on this matter, and they agreed that it is
    reasonable to use the annual average of hourly prices in California as a
    proxy for the annual average price for the entire Northwest region.

11. See comment 1. Furthermore, operation and maintenance costs were
    among the least difficult data for us to collect in our analysis. As
    discussed in appendix I, hydropower licensees routinely report these
    costs on either FERC Form 1 or EIA Form 412.

12. We used combined-cycle combustion turbine (CCCT) technology as the
    most likely alternative generating source because it is widely, if not
    universally, recognized as the least-cost alternative to run-of-river
    hydropower projects. In numerous meetings with industry
    representatives, where we presented our methodology and findings in
    detail, there were few, if any, objections to our assumption that the
    CCCT technology was the least-cost alternative to hydropower
    generation. In these meetings, we pointed out that our assumption is
    actually a conservative one. Some hydropower projects are used as
    peak-load resources, for which the alternative is a simple combustion
    turbine, whose life-cycle cost per kilowatt-hour is considerably higher.
    We also recognize that CCCT costs will vary with the price of fuel.

    In addition, contrary to NHA’s assertion, there is always an alternative
    to any existing source of power generation at some price. The more
    expensive the alternative, the higher the net benefits estimate for the
    hydropower project.

13. As discussed in comment 7, we carefully considered the value of the
    plant and equipment used by the hydropower projects in our sample. As



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    discussed in appendix I, our methodology fully compensates project
    owners for these investments by subtracting as a cost (1) an annual
    depreciation factor and (2) a return on investment. We determined the
    return on investment by multiplying the project’s RCLPD by 7.22
    percent—which is the after-tax weighted cost of capital for investor-
    owned utilities estimated by Global Insight for 1998 and 2002. This rate
    is also consistent with guidance from the Office of Management and
    Budget. As we discussed in comment 7, our methodology probably
    overcompensates project owners because it uses RCLPD instead of the
    lower net book value of the utility’s assets.

    Like all capital investments that regulated utilities undertake,
    hydropower projects were developed with the certainty that owners
    would recover their costs (commonly referred to as “rate base”) and
    earn a rate of return determined by state regulators. Risks to capital
    investments in such a “regulated monopoly” environment are generally
    considered lower than they are for entrepreneurs operating in a
    competitive, unregulated environment.

14. FERC decides what lands are required to be included within the
    boundaries of hydropower projects. Some lands are used to generate
    hydropower, while others are included to meet other objectives of the
    Federal Power Act—such as mitigating the negative impacts that
    hydropower may create. We did not try to distinguish between lands
    that meet varying purposes of the law. Rather, we relied on decisions
    that FERC made—and the licensee agreed to—regarding the lands that
    were necessary to operate each project. Furthermore, with regard to
    the public’s receiving other benefits from the project’s operation on
    these lands, these benefits are also a condition of obtaining a license
    from FERC. (Also see comment 18.)

15. Vanceburg was decided about 26 years ago. Since then, FERC has
    determined that a “national average rental value,” discussed with
    approval in Vanceburg, is not the most reasonable method for
    determining annual charges. In fact, on pages 16 and 17 of its
    comments, NHA acknowledges that FERC has recognized that a
    national average rental value is no longer an appropriate measure for
    annual charges. (See also comment 1.)

16. We agree that comparable sales data are the best indicator of land
    value, but we disagree that applicable comparable sales data exist for
    federal lands within the boundaries of hydropower projects. The



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    Uniform Standards for Federal Land Acquisitions provide that income-
    based valuation methods may be used where comparable sales data are
    lacking. The condemnation cases NHA cites did not address FERC’s
    authority to establish annual charges under section 10(e) of the Federal
    Power Act and FERC made no reference to them in discussing its 10(e)
    authority in the 1987 rule making. FERC has stated that the most
    reasonable method for basing annual charges is fair market value, and
    that charges should be proportionate with the benefits conveyed.
    Therefore, the report recommends that FERC reassess its annual
    charge system for the use of federal lands. In doing so, the report also
    recommends that FERC determine methods for (1) estimating the fair
    market value of these lands and (2) assessing annual charges—taking
    into account the competing goals of the Federal Power Act.

    NHA has asserted that lands within project boundaries must be valued
    according to their last use before they were included in the project.
    However, courts have held that these lands may be valued for power
    purposes. For example, in United States v. Pend Oreille PUD No. 1. 28
    F.3d 1544 (9th Cir. 1994), cert. denied 514 U.S. 1015 (1995), the court
    held that the measure of damages for a project’s unauthorized
    inundation of tribal lands was the value of the land for power
    production purposes. (Id. at 1551.)

    For our purpose of estimating the fair market value of the land used to
    produce hydropower, prices of adjacent agricultural lands, for example,
    do not constitute useful comparables. The compensation that a
    landowner receives in a condemnation procedure also does not shed
    light on the value of land in hydropower generation for a similar reason
    because condemnation, by definition, is not a transaction between two
    willing parties.

17. The Federal Power Act states that FERC shall “seek to avoid” increases
    in consumer electricity rates. FERC has interpreted this provision to
    prohibit unreasonable charges that would be passed along to
    consumers—but not to prohibit all charges that would result in rate
    increases.

18. FERC has twice rejected NHA’s assertion that potential annual charges
    for the use of federal land should be adjusted to recognize the public
    benefits provided by hydropower projects, such as recreation, flood
    control, irrigation, and fish and wildlife enhancement. Section 10(a) of
    the Federal Power Act requires FERC to determine, as a condition of



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       issuing a license, that the project will be best adapted to a
       comprehensive plan for waterway development “and for other
       beneficial uses, including recreational purposes.” In 1977 FERC stated:

       The argument that a licensee may reduce its statutory obligation to pay charges for the
       use of lands of the United States by offsetting the value of certain benefits provided,
       when the licensee’s right to construct, maintain, and operate its project depends in part
       on the provision of such benefits, is untenable. The “remuneration” to the licensee, if
       any is due, for providing these benefits is the Commission’s permission to operate the
       project; no further compensation, in the form of a credit to annual charge levies is due
       or owing.2

       FERC reaffirmed this conclusion in its 1987 annual charge rule making.
       In short, under the Federal Power Act, public benefits are provided as a
       condition of receiving the license, and the licensee deserves no
       compensation for merely complying with the law.

19. We do not believe that the Forest Service’s rights-of-way fee system—
    on which the FERC annual charge system is based—is consistent with
    sound appraisal practices. We discussed the significant flaws of the
    Forest Service fee system for rights-of-way and refer to our 1996 report,
    where we examined this system in detail.3 In short, the Forest Service
    stated that its rights-of-way system was not getting fair market value for
    rights-of-way. In fact, according to Forest Service officials, this system
    may be getting as little as 10 percent of the value for federal lands used
    for rights-of-way.

       In addition, lands used for rights-of-way are generally long, narrow
       corridors that accommodate power lines, pipelines, or communication
       lines. These lands contrast significantly with lands capable of
       producing hydropower, which may include large masses of land that
       can be as wide as a large river or large lake. Furthermore, lands suitable
       for rights-of-way are relatively common, while lands suitable for
       hydropower are scarce. Thus, we do not believe that the use of the
       Forest Service’s rights-of-way system is consistent with sound appraisal
       practices in determining the fair market value of lands capable of
       producing hydropower.


2
    42 Fed. Reg. 1229 (1977).
3
  See U.S. General Accounting Office, U.S. Forest Service: Fee System for Rights-of-Way
Program Needs Revision (GAO/RCED-96-84, Apr. 22, 1996).




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Appendix IV
Comments from the National Hydropower
Association




20. We believe that our analysis is consistent with generally accepted
    appraisal practices. As we discuss in our report, we could not use the
    comparable sales approach because there is no active market in lands
    rented for hydropower purposes. As discussed in our report, FERC
    requires licensees, as a condition of obtaining a license, to own the
    lands within the boundary of the projects or obtain an easement in
    perpetuity from another landowner. (Federal lands and lands within
    Indian reservations are not subject to this requirement.) As a result, we
    used a net benefits approach to determine the value of federal lands
    used to produce hydropower. This approach is similar to the income
    approach, which bases the value of property on its income-producing
    potential. Appraisal guidance indicates that in cases where no active
    market exists, a forecast of expected cash flows may aid in estimating
    the value of assets, provided the expected cash flows are discounted at
    a rate proportionate with the risk involved.4 We essentially took this
    approach and modified it by using wholesale market prices to value
    hydropower instead of cost-based utility revenues. (See app I.) Our net
    benefits approach is grounded in economic principles that form the
    basis of the “land residual technique,” detailed in The Appraisal of Real
    Estate—a widely accepted publication on appraisal practices.5

21. As we stated in comment 1, we do not specifically recommend that
    FERC adopt the net benefits approach as a means for assessing annual
    charges. In addition, FERC would have to factor in administrative costs
    into any decision it makes in revising its current annual charge system.
    Furthermore, while it took us nearly 3 years to complete and publish
    our analysis, FERC could likely perform its own analysis much more
    quickly because it has (1) more experience than we did with
    performing this type of analysis, (2) hydropower-engineering expertise
    on staff (we did not and had to contract out for this expertise), and (3)
    detailed information on electricity markets (we spent time and
    resources collecting this type of information).

22. As mentioned in comment 1, we used our methodology as a tool to
    value the federal lands used for hydropower generation. Our
    recommendation is for FERC to consider fair market value in setting
    charges for the use of federal land, but we do not prescribe a specific


4
    See Appraisal Standards Board Advisory Opinion 8 (AO-8).
5
    See The Appraisal of Real Estate, 12th ed. (Chicago: Appraisal Institute: 2001,) pp. 539-543.




Page 147                                          GAO-03-383 FERC Charges for Federal Lands
Appendix IV
Comments from the National Hydropower
Association




       method for setting charges. If FERC desires, a system of annual charges
       can be designed to vary little from year-to-year and could exclude the
       effects of a year such as 2000, which our report recognizes as an outlier.

23. While the Federal Power Act may preclude unilateral changes in license
    terms and conditions, the act does not preclude FERC from changing
    its annual charge system. We note that FERC currently adjusts charges
    for most licenses from year to year under its current system. These
    adjustments reflect the Forest Service’s annual updating of its fee
    system for rights-of-way.

24. We recognize that FERC will have to consider a number of policy
    goals if it decides to reassess its current annual charge system. Even
    though NHA asserts that revising annual charges will go against some
    policy concerns raised in the Congress and the executive branch, we
    note that the Subcommittee on Energy and Water Development,
    House Committee on Appropriations—which oversees FERC’s
    appropriations—has instructed the commission to consider
    making changes to its annual charge system. Specifically, in the
    report that accompanied FERC’s fiscal year 2003 appropriations, the
    Committee stated:

       The General Accounting Office (GAO) has underway an analysis of the land rents
       charged by FERC for non-federal hydropower projects located on federal lands.
       Preliminary results from GAO indicate that the fee schedule presently used by FERC
       significantly underestimates, possibly by as much as two orders of magnitude, the fair
       market value of these project lands used for non-federal hydropower. The Committee
       directs FERC to submit a proposal to Congress that will revise the existing fee
       schedule to a new methodology that will capture more of the real market value of these
       federal lands.6

25. While FERC declined to adopt the net benefits methodology as a
    mechanism for establishing annual charges, FERC approved an
    indexed charge, on the basis of values derived from the net benefits
    methodology.

26. See comments 1 and 4. In addition, there is nothing unusual about using
    a technique that is similar to the income approach to value land. The
    income approach is a widely accepted appraisal practice.



6
    H. R. Rep. No. 107-681 (2002).




Page 148                                        GAO-03-383 FERC Charges for Federal Lands
Appendix IV
Comments from the National Hydropower
Association




27. We disagree. As noted in Vanceburg, a tax is imposed by the sovereign
    without regard to choice or particular benefit. By contrast, an annual
    charge is a fee paid by choice in exchange for a particular benefit.7
    Furthermore, FERC has recognized that annual charges should be
    proportionate to the benefit conferred and that fair market value is the
    most reasonable method to measure that benefit.

28. The map presented in NHA’s comments demonstrates that many states
    have considered or undergone significant change in restructuring their
    electricity markets since FERC issued its annual charge regulations in
    1987.8 In addition, as our report states, FERC’s current policy is to
    encourage greater competition in all wholesale energy markets. Given
    the amount of change in electricity markets that has occurred and the
    potential for additional change, we believe that it is time for FERC to
    reassess its current annual charge system so that, among other things,
    it reflects the current electricity environment.

29. As the report discusses, the Federal Power Act has several goals,
    including the development of hydropower, the prohibition against
    unreasonable rate increases, and the compensation of the United States
    for the use of its lands.




7
    City of Vanceburg v. FERC, 571 F.2d 630, 644 n.48 (D.C Cir. 1977).
8
  This map may be viewed in color by going to
www.eia.doe.gov/cneaf/electricity/chg_str/regmap.html.




Page 149                                         GAO-03-383 FERC Charges for Federal Lands
Appendix V

Comments from the Department of the
Interior                                                                       Append
                                                                                    x
                                                                                    i
                                                                                    V




Note: GAO’s comments
appear at the end of this
appendix.




                            Page 150   GAO-03-383 FERC Charges for Federal Lands
                              Appendix V
                              Comments from the Department of the
                              Interior




Note: Page numbers in
the draft report may differ
from those in this report.


See comment 1.



See comment 2.



See comment 3.




See comment 4.




                              Page 151                              GAO-03-383 FERC Charges for Federal Lands
Appendix V
Comments from the Department of the
Interior




Page 152                              GAO-03-383 FERC Charges for Federal Lands
                 Appendix V
                 Comments from the Department of the
                 Interior




                 The following are GAO’s comments on the Department of the Interior’s
                 letter dated April 3, 2003.



GAO’s Comments   1. We revised the first footnote to state that we did not include Indian
                    reservations in our definition of federal lands.

                 2. For greater clarity, we added a footnote regarding the number of
                    hydropower projects that use federal lands.

                 3. Our report discusses a number of flaws associated with using a fee
                    system designed for rights-of-way to collect annual charges for
                    hydropower uses. For the reasons discussed in the report, we believe it
                    is difficult for FERC to defend its continued use of the current annual
                    charge system. In its comments, the Department of the Interior
                    observes yet another flaw—that federal lands used for rights-of-way
                    remain available for most other uses, while federal lands licensed for
                    use in hydropower projects in many cases do not. This is another
                    reason for FERC to reassess its current annual charge system and
                    consider making revisions.

                 4. The Department of the Interior argued that land rent in a competitive
                    market that is stable in the long run cannot exceed the per-kilowatt cost
                    differential between hydropower and the least-cost alternative for new
                    capacity. Given the Department of the Interior’s assumption of a long-
                    term competitive equilibrium, we agree with this principle and believe
                    that our valuation methodology is consistent with this approach while
                    focusing on the more concrete but variable realization of land values in
                    the shorter term. In practice, the price may be different from the
                    incremental cost of a long-term alternative owing to various market
                    conditions, such as when there are few, if any, options to the spot
                    wholesale market for electricity. For example, to the extent that 2000
                    prices reflect the exercise of market power in California, they yield
                    estimates of land values that are too high and cannot be sustained. In
                    the longer term, low-cost alternatives, such as new production facilities
                    based on natural gas or coal, would limit the value of the land to the
                    cost differential between hydropower and these alternatives. Given the
                    evolving state of the wholesale market for electricity, we chose to
                    estimate fair market value on the basis of as much observable data as
                    possible, while the analysis for 2003 embodies the principle that the
                    market prices move to the price of the least-cost alternative in the
                    long run.



                 Page 153                              GAO-03-383 FERC Charges for Federal Lands
Appendix VI

GAO Contact and Staff Acknowledgments                                                         Appendx
                                                                                                    iVI




GAO Contact       Ned Woodward (202) 512-8051



Acknowledgments   In addition to the individual named above, Robert J. Aiken, Paul
                  Aussendorf, Karen Bracey, Carol Bray, Sandra Cantler, Allen Chan,
                  Mark Connelly, Charlie Cotton, Philip Farah, Scott Farrow, Richard
                  Johnson, Chester Joy, Joseph Kile, Frank Kovalak, Penny Pickett,
                  Carol Herrnstadt Shulman, Donna Weiss, Arvin Wu, and James Yeager
                  made key contributions to this report.




(141460)          Page 154                            GAO-03-383 FERC Charges for Federal Lands
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