    Federal Energy Regulatory Commission: Charges for Hydropower
    Projects' Use of Federal Lands Need to Be Reassessed (20-MAY-03,
    GAO-03-383).

    Hydropower projects generate power valued at billions of dollars.
    For projects located on federal lands, FERC is required to assess
    "reasonable annual charges" to use these lands. FERC agrees that
    fair market value is the most reasonable basis for assessing
    these charges. This report examines FERC's annual charge system
    and the extent to which it reflects the federal lands'
    contributions to hydropower. GAO described and assessed FERC's
    annual charge system, estimated the fair market value for the use
    of federal lands, and discussed the implications of higher
    charges on consumers and project owners.
    -------------------------Indexing Terms-------------------------
    REPORTNUM:   GAO-03-383
        ACCNO:   A06912
      TITLE:     Federal Energy Regulatory Commission: Charges for
    Hydropower Projects' Use of Federal Lands Need to Be Reassessed
         DATE:   05/20/2003
      SUBJECT:   Federal property
    	     Hydroelectric energy
    	     Land management
    	     User fees

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    GAO-03-383

                                           A

    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

    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

    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

    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

    This is a work of the U. S. Government and is not subject to copyright
    protection in the United States. It may be reproduced and distributed in
    its entirety without further permission from GAO. It may contain
    copyrighted graphics, images or other materials. Permission from the
    copyright holder may be necessary should you wish to reproduce copyrighted
    materials separately from GAO*s product.

    Le tt e r

    May 20, 2003 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.

    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

    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

    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.

    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

    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.

    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).

    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.

    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.

    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).

    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.

    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.

    FERC*s System for While FERC has recognized that using the fair market
    value of land is a

    Determining reasonable approach for determining annual fees, it currently
    uses a fee

    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 Is Based on Values

    system was designed by the U. S. Forest Service and the Bureau of Land for
    Rights- of- Way,

    Management (BLM) to collect fees for federal lands used for power lines,
    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

    Schedule for Determining methods for determining annual charges for the
    use of federal lands by

    Annual Charges for hydropower projects including appraisals and national
    average land

    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).

    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).

    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 Fee
    System

    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 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).

    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

    in Our Sample Are annual economic contribution that federal lands make to
    the production

    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
    Valuable Than

    least $157 million. However, under FERC*s modified linear rights- of- way
    FERC*s Current

    fee schedule, these 24 projects paid about $2.7 million in annual charges
    to 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.

    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
    Significant Value

    market value of federal lands used by our sample of 24 hydropower 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.

    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 Calendar years

    estimate sensitivity Quantity Price analysis

    sensitivityanalysis

    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

    and 2000 the wholesale price of electricity varied accordingly. These data

    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.

    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 power 10 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).

    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.

    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.

    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

    Based on Our Analysis of actual historical data that we reviewed. The
    sensitivity analyses illustrates

    1999 Data the effect that uncertainty in two key variables* price and
    quantity* has

    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.

    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.

    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.

    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.

    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 Our Sample Are Worth

    years and for most projects. However, for each project, the value of the
    Significantly More Than

    federal land can change dramatically with a significant change in supply
    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.

    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

    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

    Annual Charges on fair market value for the use of the land, the effects
    on consumers and

    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
    Project Owners Will

    the project is located has been restructured. 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

    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.

    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

    Environment lands used for hydropower. Some of the states that could be
    affected by

    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.

    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

    to Increase Annual fair market value for the use of federal lands by
    hydropower projects until

    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 Limited by Electricity revenue. Specifically, FERC*s ability to raise
    annual charges may be limited

    Market Restructuring after states restructure the generation segment of
    their electricity market 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

    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.

    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).

    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

    Executive Action in light of the (1) information we are providing
    concerning the estimated

    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.

    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

    Comments the National Hydropower Association* a hydropower industry group*

    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

    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.)

    Scope and To determine FERC*s current system for assessing annual charges,
    we

    Methodology reviewed relevant laws, regulations, and FERC rulings. In
    addition, we

    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.

    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.

    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

    Appendi xes Estimating the Fair Market Value of Federal

    Appendi x I

    Land Used to Produce Hydropower 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

    Choosing the Net to estimate fair market value and describes our
    methodology in detail. Our

    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

    to Estimate Fair full nonland cost of producing it. In the absence of
    comparable market

    Market Value sales, the net benefits methodology provides an alternative
    for estimating

    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.

    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.

    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

    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.

    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.

    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.

    A Description of We used a net benefits methodology to estimate the fair
    market value of

    Our Methodology federal lands used to generate electricity at a sample of
    24 FERC- licensed

    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.

     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

    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 = si ( )  * NB (,) i t (1)

    NB (,) i t = pi (,) t  * Qi (,) t * Ci (,) 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& Mi (,) t ++ Ti (,) t Ki (,) 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.

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

    K (,) i t = Di ( ) + 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 =

    CDrB ++ (  * ) , 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.

    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 aftertax, 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.

    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 Benefits Methodology

    implement the net benefits methodology for estimating fair market value.
    It 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

    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.

    Table 6: Profiles of Our Sample of 24 Hydropower Projects

    Dollars in millions

    FERC project number Project name State Ownership type a 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.

    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

    Land for Six Scenarios analysis for 1999 estimates by constructing
    hypothetical examples to test

    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
    megawatt12

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

    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

    the Net Benefits key variables. This section describes the price and
    quantity data we used to

    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.

    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.

    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.

    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.

    Table 7: Prices Used to Value Hydropower for Our Sample of 24 Projects
    Project by location California and the Northwest a Coosa River, Alabama
    Bath County Pumped Storage b Year Price c Basis Price c Basis Price c
    Basis

    1998 $27. 40 Hydro- specific $40.01 Simple average of

    $36.86 Average of hourly realtime average of hourly

    hourly prices for the prices for PJM*

    prices from CAPX, Southeast Reliability

    Western Hub, weighted by hourly Council region,

    weighted by project generation d

    excluding Florida hourly generation

    1999 35. 43 Hydro- specific 42. 14 Simple average of 55.16 Average of
    hourly realtime

    average of hourly hourly prices for the

    prices for PJM* prices from CAPX,

    Southeast Reliability Western Hub, weighted by hourly

    Council region, weighted by project

    generation d 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 generation d

    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 realtime

    price costs from least- cost costs from least- cost

    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 realtime hydropower

    average of hourly hourly prices for the

    prices for PJM* generation

    prices from CAPX, Southeast Reliability

    Western Hub, sensitivity weighted by hourly

    Council region, weighted by project

    generation d 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.

    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.

    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.

    (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

    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
    projectspecific 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
    investorowned 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.

    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.

    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.

    Net Benefits Analysis for Each of the

    Appendi x II

    24 Projects in Our Sample 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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    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

    Tot al cost s $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.

    Comments from the Federal Energy

    Appendi x III

    Regulatory Commission Note: GAO*s comments appear at the end of this
    appendix.

    See comment 1.

    See comment 2. See comment 3. See comment 4. See comment 5.

    See comment 6. Note: Page numbers in the draft report may differ from
    those in this report.

    See comment 7. See comment 5.

    See comment 5. See comment 8.

    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

    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

    (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.

    Comments from the National Hydropower

    Appendi x IV

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

    See comment 1. See comment 2.

    See comment 3. See comment 1.

    See comment 4. See comment 1. See comment 5.

    See comment 6.

    See comment 7. See comment 8.

    See comment 9.

    See comment 10. See comment 1.

    See comment 11.

    See comment 12. See comment 13.

    See comment 14. See comment 1.

    See comment 15. See comment 1.

    See comment 15. See comments 1 and 14.

    See comment 16.

    See comment 17. See comment 18.

    See comment 1.

    See comment 1. See comment 1.

    See comment 1.

    See comment 13. See comment 19.

    See comment 1. See comment 20.

    See comments 20 and 1.

    See comments 18 and 1. See comment 21.

    See comment 1. See comment 3.

    See comment 1.

    See comments 22 and 23. See comment 24.

    See comment 17. See comment 1.

    See comment 1. See comment 1.

    See comment 18.

    See comment 1.

    See comment 14. See comment 25.

    See comment 26.

    See comment 27. See comment 28.

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

    electricity/ chg_ str/ regmap. html.

    See comment 29. See comment 10.

    See comment 18.

    See comment 1.

    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

    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.

    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

    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

    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

    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 investorowned 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

    Uniform Standards for Federal Land Acquisitions provide that incomebased
    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

    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).

    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.

    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).

    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.

    Comments from the Department of the

    Appendi x V

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

    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.

    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 longterm
    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.

    Appendi x VI

    GAO Contact and Staff Acknowledgments 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)

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    a

    GAO United States General Accounting Office

    Since 1987, FERC*s charges for hydropower projects on federal lands have
    been based on a linear rights- of- way fee schedule that was originally
    used to determine the annual fees other agencies charged for the rights to
    locate, among other things, powerlines, pipelines, and communication lines
    on federal lands* uses that are generally less valuable than hydropower.
    FERC chose this system primarily because it was simple and predictable and
    would not subject the commission to appeals from the electricity industry.
    However, this system has no relationship to the economic benefit of the
    federal lands used to produce hydropower. In addition, in implementing
    this system, FERC does not ensure that (1) the charges it collects achieve
    the hydropower annual charge program objectives, (2) it has accurate
    information on the amount of federal lands licensees use, or (3) its
    billing system collects all charges due the federal government for the use
    of its lands.

    The annual charges FERC currently collects from hydropower projects for
    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 less than 2 percent of the annual fair market value for
    the use of these lands. In performing its analysis, GAO examined multiple
    electricity market scenarios, including three that estimated the value of
    federal lands using actual industry data from three recent years. Under
    these scenarios, the fair market value for the use of federal lands by
    GAO*s sample of hydropower projects is at least $157 million annually and,
    under some market conditions, hundreds of millions of dollars more. In
    comparison, FERC collected about $2.7 million in annual charges from these
    projects in 2002.

    GAO reached these conclusions on the basis of its analysis of a stratified
    random sample of 24 projects that use federal lands. This sample was drawn
    from 56 projects that collectively account for about 90 percent of the
    hydropower produced on federal lands. Although this sample of 24 projects
    was not representative of all hydropower projects on federal lands, these
    projects produced about 60 percent of all electricity generated by
    FERClicensed hydropower projects that use federal land and represent about
    35 percent of all federal lands used for hydropower production.

    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.

    FEDERAL ENERGY REGULATORY COMMISSION

    Charges for Hydropower Projects* Use of Federal Lands Need to Be
    Reassessed

    www. gao. gov/ cgi- bin/ getrpt? GAO- 03- 383. To view the full report,
    including the scope and methodology, click on the link above. For more
    information, contact Barry T. Hill at (202) 512- 3841. Highlights of GAO-
    03- 383, a report to

    Congressional Requesters

    May 2003

    Hydropower projects generate power valued at billions of dollars. For
    projects located on federal

    lands, FERC is required to assess *reasonable annual charges* to use these
    lands. FERC agrees that fair market value is the most reasonable basis for
    assessing

    these charges. This report examines FERC*s annual charge system and the
    extent to which it reflects the federal lands*

    contributions to hydropower. GAO described and assessed FERC*s annual
    charge system, estimated the fair market value for the use of federal
    lands, and discussed the

    implications of higher charges on consumers and project owners. FERC
    should reconsider its current system and develop new strategies and
    options for assessing annual charges that are proportionate with the
    economic benefits conveyed to hydropower licensees. While FERC is
    developing this

    strategy, it should better manage its current system by verifying the
    amount of federal lands hydropower projects use and

    resolving discrepancies among its multiple billing and land databases.

    In its comments, FERC disagreed with our valuation of federal lands but
    agreed with our recommendations to resolve discrepancies among its
    databases. The National Hydropower

    Association also disagreed with our valuation of federal lands.

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

    Contents

    Contents

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

    Contents

    Page iii GAO- 03- 383 FERC Charges for Federal Lands

    Page 1 GAO- 03- 383 FERC Charges for Federal Lands United States General
    Accounting Office

    Washington, D. C. 20548 Page 1 GAO- 03- 383 FERC Charges for Federal Lands

    A

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    Appendix I

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

    Page 41 GAO- 03- 383 FERC Charges for Federal Lands

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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    Appendix II

    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
    Sample

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    Appendix III

    Appendix III Comments from the Federal Energy Regulatory Commission

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    Appendix III Comments from the Federal Energy Regulatory Commission

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    Appendix III Comments from the Federal Energy Regulatory Commission

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    Appendix III Comments from the Federal Energy Regulatory Commission

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    Appendix III Comments from the Federal Energy Regulatory Commission

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    Appendix III Comments from the Federal Energy Regulatory Commission

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    Appendix III Comments from the Federal Energy Regulatory Commission

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    Appendix IV

    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix IV Comments from the National Hydropower Association

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    Appendix V

    Appendix V Comments from the Department of the Interior

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    Appendix VI

    United States General Accounting Office Washington, D. C. 20548- 0001
    Official Business Penalty for Private Use $300 Address Service Requested

    Presorted Standard Postage & Fees Paid

    GAO Permit No. GI00
    *** End of document. ***