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

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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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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

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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

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Appendix I

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
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Appendix I Estimating the Fair Market Value of Federal Land Used to
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Appendix I Estimating the Fair Market Value of Federal Land Used to
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Appendix I Estimating the Fair Market Value of Federal Land Used to
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Appendix I Estimating the Fair Market Value of Federal Land Used to
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Appendix I Estimating the Fair Market Value of Federal Land Used to
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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
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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
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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
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Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
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Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
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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
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Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
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Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
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Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
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Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
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Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
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Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
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Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
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Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
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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
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Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
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Appendix II Net Benefits Analysis for Each of the 24 Projects in Our
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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 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 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 V Comments from the Department of the Interior

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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. ***