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entitled 'Energy-Water Nexus: Improvements to Federal Water Use Data 
Would Increase Understanding of Trends in Power Plant Water Use' which 
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Report to the Chairman, Committee on Science and Technology, House of 
Representatives: 

United States Government Accountability Office: 
GAO: 

October 2009: 

Energy-Water Nexus: 

Improvements to Federal Water Use Data Would Increase Understanding of 
Trends in Power Plant Water Use: 

GAO-10-23: 

GAO Highlights: 

Highlights of GAO-10-23, a report to the Chairman, Committee on Science 
and Technology, House of Representatives. 

Why GAO Did This Study: 

In 2000, thermoelectric power plants accounted for 39 percent of total 
U.S. freshwater withdrawals. Traditionally, power plants have withdrawn 
water from rivers and other water sources to cool the steam used to 
produce electricity, so that it may be reused to produce more 
electricity. Some of this water is consumed, and some is discharged 
back to a water source. 

In the context of growing demands for both water and electricity, this 
report discusses (1) approaches to reduce freshwater use by power 
plants and their drawbacks, (2) states’ consideration of water use when 
reviewing proposals to build power plants, and (3) the usefulness of 
federal water data to experts and state regulators. GAO reviewed 
federal water data and studies on cooling technologies. GAO interviewed 
federal officials, as well as officials from seven selected states. 

What GAO Found: 

Advanced cooling technologies that rely on air to cool part or all of 
the steam used in generating electricity and alternative water sources 
such as treated effluent can reduce freshwater use by thermoelectric 
power plants. Use of such approaches may lead to environmental benefits 
from reduced freshwater use, as well as increase developer flexibility 
in locating a plant. However, these approaches also present certain 
drawbacks. For example, the use of advanced cooling technologies may 
result in energy production penalties and higher costs. Similarly, the 
use of alternative water sources may result in adverse effects on 
cooling equipment or regulatory compliance issues. Power plant 
developers must weigh these drawbacks with the benefits of reduced 
freshwater use when determining which approaches to pursue. 

Consideration of water use by proposed power plants varies in the 
states GAO contacted, but the extent of state oversight is influenced 
by state water laws, related state regulatory policies, and additional 
layers of state regulatory review. For example, California and Arizona—
states that historically faced constrained water supplies, have taken 
formal steps aimed at minimizing freshwater use at power plants. In 
contrast, officials in five other states GAO contacted said that their 
states had not developed official policies regarding water use by power 
plants and, in some cases, did not require a state permit for water use 
by new power plants. 

Federal agencies collect national data on water availability and water 
use; however, of these data, state water agencies rely on federal water 
availability data when evaluating power plants’ proposals to use 
freshwater more than federal water use data. Water availability data 
are collected by the U.S. Geological Survey (USGS) through stream flow 
gauges, groundwater studies, and monitoring stations. In contrast, 
federal data on water use are primarily used by experts, federal 
agencies, and others to identify industry trends. However, these data 
users identified limitations with the federal water use data that make 
them less useful for conducting trend analyses and tracking industry 
changes. For example, the Department of Energy’s (DOE) Energy 
Information Administration (EIA) does not systematically collect 
information on the use of advanced cooling technologies and other data 
it collects are incomplete. Similarly, USGS discontinued distribution 
of data on water consumption by power plants and now only provides 
information on water withdrawals. Finally, neither EIA nor USGS collect 
data on power plant developers’ use of alternative water sources, which 
some experts believe is a growing trend in the industry. Because 
federal data sources are a primary source of national data on water use 
by various sectors, data users told GAO that without improvements to 
these data, it becomes more difficult for them to conduct comprehensive 
analyses of industry trends and limits understanding of changes in the 
industry. 

What GAO Recommends: 

To improve federal data collection efforts, GAO is making several 
recommendations, including that EIA consider collecting and reporting 
data on power plants’ use of advanced cooling technologies and 
alternative water sources, and that USGS consider reinstating 
collection of data on power plant water consumption and distributing 
data on the use of alternative water sources. USGS agreed with our 
recommendations. DOE provided technical comments that we incorporated, 
as appropriate. 

View [hyperlink, http://www.gao.gov/products/GAO-10-23] or key 
components. For more information, contact Anu Mittal or Mark Gaffigan 
at (202) 512-3841 or mittala@gao.gov or gaffiganm@gao.gov. 

[End of section] 

Contents: 

Letter: 

Background: 

Advanced Cooling Technologies and Alternative Water Sources Can Reduce 
the Use of Freshwater at Power Plants, but Their Adoption Poses Certain 
Drawbacks: 

States We Contacted Vary in the Extent to Which They Consider Water 
Impacts When Reviewing Power Plant Development Proposals: 

Some Federal Water Data Are Useful for Evaluating Power Plant 
Applications, but Limitations in Other Federal Data Make the 
Identification of Certain Water Use Trends More Difficult: 

Conclusions: 

Recommendations for Executive Action: 

Agency Comments and Our Evaluation: 

Appendix I: Objectives, Scope and Methodology: 

Appendix II: Review of Proposals to Use Water in New Power Plants in 
Arizona: 

Appendix III: Review of Proposals to Use Water in New Power Plants in 
California: 

Appendix IV: Review of Proposals to Use Water in New Power Plants in 
Georgia: 

Appendix V: Limitations to Federal Water Use Data Identified by Those 
GAO Contacted: 

Appendix VI: Comments from the Department of the Interior: 

Appendix VII: GAO Contacts and Staff Acknowledgments: 

Tables: 

Table 1: Estimated Water Withdrawals by Thermoelectric Power Plants in 
the United States in 2000: 

Table 2: Selected Estimates of Water Withdrawn and Consumed for Power 
Plant Cooling by Cooling Technology and Plant Type: 

Table 3: Percentage Difference in Annual Net Plant Electricity Output 
for Theoretical Combined Cycle Plants with Different Cooling Systems at 
Four Geographic Locations in California: 

Table 4: State Water Laws and Permit Requirements for Water Supply in 
Seven Selected States: 

Table 5: Water Data Considered in Support of State Water Regulators' 
Permitting Decisions: 

Table 6: Power Plants Implemented, Approved or Planned Since January 1, 
2004, by Cooling Type: 

Table 7: Thermoelectric Power Plant Applications for Water Withdrawal 
Permits in Georgia Between January 2004 and December 2008: 

Figures: 

Figure 1: Diagram of a Boiler Water Loop in a Power Plant: 

Figure 2: Total Freshwater Withdrawal in 1995 as a Percentage of 
Available Precipitation: 

Figure 3: Diagram of a Once-through Cooling System: 

Figure 4: Diagram of a Wet Recirculating System with a Cooling Tower: 

Figure 5: Diagram of a Dry Cooling System: 

Figure 6: Diagram of a Hybrid Cooling System: 

Figure 7: Water Based Cooling Systems by Technology and Water Source: 

Figure 8: Cumulative Number of Discontinued U.S. Geological Survey 
Streamflow Gauges with 30 or More Years of Record, 1933-2007: 

Abbreviations: 

CEC: California Energy Commission: 

DOE: Department of Energy: 

EIA: Energy Information Administration: 

EPA: Environmental Protection Agency: 

USGS: U.S. Geological Survey: 

[End of section] 

United States Government Accountability Office: 
Washington, DC 20548: 

October 16, 2009: 

The Honorable Bart Gordon:
Chairman:
Committee on Science and Technology:
House of Representatives: 

Water and electricity are inexorably linked and mutually dependent, 
with each affecting the other's availability. Electricity is required 
to supply, purify, distribute, and treat water and wastewater; water is 
needed to generate electricity and to extract and process fuels used to 
generate electricity. Freshwater and electricity are important to our 
health, quality of life, and economic growth, and demand for both of 
these resources is rising. Freshwater is increasingly in demand to meet 
the needs of the public in growing cities and suburbs, farms, 
industries, and for recreation and wildlife. At the same time, 
electricity demand is projected to continue to grow in the United 
States, with the Department of Energy (DOE) estimating that U.S. 
electricity consumption will increase by an average of about 1 percent 
each year from 2007 through 2030. Limited availability of freshwater 
may make it more difficult to build new power plants, particularly in 
communities concerned about the adequacy of their water supply and 
maintaining the quality of aquatic environments. Periodic water 
shortages may also make it difficult for existing plants to satisfy 
demand for electricity. In recent years, water shortages and high water 
temperatures have caused reductions in electricity production at power 
plants in the United States and abroad, according to news reports. 

In 2007, around three-fourths of the United States' electricity 
generating capacity consisted of thermoelectric power plants, which 
rely heavily on water for cooling. Thermoelectric power plants use a 
fuel source--for example, coal, natural gas, nuclear material such as 
uranium, or the sun--to boil water (boiler water) to produce steam. The 
steam turns a turbine connected to a generator that produces 
electricity. The steam is then cooled back into boiler water, a process 
which traditionally involves transferring heat from the steam to a 
separate water source (cooling water) and reusing it. Because the 
cooling water takes on the heat of the boiler water, some of it may 
evaporate, and the amount that evaporates varies, depending on the type 
of cooling technology that is used. In recent years, the majority of 
new thermoelectric power generating units have been combined cycle 
units, which use two processes to produce electricity, one of which is 
thermoelectric. In this type of plant, electricity is first generated 
by a simple cycle turbine that turns a generator directly as a result 
of burning fuel in the turbine--similar to jet engines used in 
aircraft. The heat produced by the simple cycle turbine that would 
otherwise be released to the atmosphere is used to produce steam which 
turns a steam turbine connected to a generator to produce electricity. 
Because some of the electricity is generated via the simple cycle 
turbine--a non-thermoelectric process--combined cycle plants use less 
water for cooling than similarly sized plants using only steam to 
produce electricity. Non-thermoelectric power plants, which accounted 
for the other one-quarter of 2007 U.S. electricity generating capacity, 
do not use water for cooling but still require water for other plant 
purposes, such as water for improving turbine performance on non- 
thermoelectric natural gas plants, as well as water for housekeeping 
activities. 

Water use by thermoelectric power plants can be generally characterized 
as withdrawal, consumption, and discharge. Water withdrawals refer to 
water removed from the ground or diverted from a surface water source--
for example, an ocean, river, or lake--for use by the plant. In 2000, 
the most recent USGS data available, thermoelectric power plants 
accounted for 39 percent of total U.S. freshwater withdrawals. Water 
consumption refers to the portion of the water withdrawn that is no 
longer available to be returned to a water source, such as when it has 
evaporated. In 1995, the most recent USGS data available, 
thermoelectric power plants accounted for 3 percent of freshwater 
consumption in the United States. Discharge refers to the return of 
water to its original source or a new source and represents the 
difference between withdrawals and consumption. For many thermoelectric 
power plants, much of the water they withdraw is later discharged, 
although often at higher temperatures. The amount of water discharged 
from a thermoelectric power plant depends on a number of factors, 
including the type of cooling technology used, plant economics, and 
environmental regulations. 

Decisions to build a new power plant may be made independently by the 
power plant developer or with the consent of a state public utility 
commission. In either case, power plant developers must obtain approval 
from a number of state and local officials, generally by obtaining 
preconstruction and operating permits, before they can proceed with 
building their plant in a particular location. This process is meant to 
balance any adverse impacts a power plant may have on nearby 
communities and environments with the benefits it provides, such as 
energy supply and jobs. This regulation of the electricity industry's 
water use is complex and involves both state and federal laws. States 
are primarily responsible for managing the allocation and use of 
freshwater supplies. However, federal laws provide for control over the 
use of water in specific cases, such as on federal lands or in 
interstate commerce. In addition to the water power plants may 
withdraw, for which developers have to seek permits or purchase a water 
right, power plants may have to obtain permits to discharge water, 
since water discharged from a plant is regulated by the federal 
government and the states to ensure that it meets certain quality 
standards and does not harm protected species.[Footnote 1] In some 
cases, plants may design their operations so they discharge no water 
into sources outside the plant boundaries, known as zero-liquid 
discharge. 

Two federal agencies--the Department of the Interior's U.S. Geological 
Survey (USGS) and the Energy Information Administration (EIA), the 
independent statistical and analytical agency within DOE--collect key 
data that address how power plants use water. In addition, Congress 
recently passed the Omnibus Public Land Management Act of 2009, which 
included provisions known as the Secure Water Act.[Footnote 2] The law 
authorizes, among other things, additional funding for the Department 
of the Interior to report water data to Congress, including 
thermoelectric power plant withdrawal data. Congress is also 
considering pending legislation related to energy and water. The Energy 
and Water Integration Act of 2009, among other things, calls for the 
National Academy of Sciences to conduct an analysis of the impact of 
energy development and production on U.S. water resources, including an 
assessment of water used in electricity production.[Footnote 3] 
Similarly, the Energy and Water Research Integration Act directs DOE to 
take such steps as advancing energy and energy efficiency technologies 
that minimize freshwater use, increase water use efficiency, and 
utilize alternative water sources.[Footnote 4] It also provides for the 
creation of a council to enhance energy and water resource data 
collection, including improving data on trends in power plant water 
use, among other things. 

Because of the importance of freshwater to the public and society at 
large, the environment, and many industries, information about the 
country's current and expected use of freshwater and electricity is 
critical to making appropriate decisions about how these resources are 
managed. In this context, you asked us to provide information about the 
relationship between water and energy, which we will be addressing in 
several reports.[Footnote 5] This report discusses water use in 
electricity production. More specifically, this report (1) describes 
technologies and other approaches to help reduce freshwater use by 
power plants and what, if any, drawbacks there are to using them, (2) 
describes the extent to which selected states consider water impacts of 
power plants when reviewing power plant development proposals, and (3) 
evaluates the usefulness of federal water data to experts and state 
regulators who evaluate power plant development proposals. We focused 
our evaluation on thermoelectric power plants, such as nuclear, coal, 
and certain natural gas plants. We did not consider the water supply 
issues associated with hydroelectric power, since the process through 
which hydroelectric plants use water is substantially different from 
that of thermoelectric plants and water is used to generate 
hydroelectric power without being directly consumed. We also limited 
our review to water used during the production of electricity at power 
plants and did not include water issues associated with extracting 
fuels used to produce electricity. 

To understand technologies or other approaches to help reduce 
freshwater use by power plants and what, if any, drawbacks there are to 
using them, we reviewed industry, federal, and academic studies on 
alternative water sources and advanced cooling technologies that 
discussed these alternatives' benefits, as well as their drawbacks. We 
discussed the trade-offs associated with the use of these alternatives 
with power plant and cooling system manufacturers, U.S. national 
laboratory staff, academics, and other industry experts. To determine 
the extent to which selected states consider water impacts of power 
plants when reviewing power plant development proposals, we conducted 
case study reviews of three states: Arizona, California, and Georgia. 
We selected these states because of their differences in water 
availability and water law, high energy production, and large 
population centers. For each of these states, we met with state water 
regulators and siting authorities, power plant developers, water 
research institutions, and other subject matter experts. We also 
reviewed state water laws and policies for power plant water use. To 
supplement our case studies, we spoke with water regulators from four 
additional states: Nevada and Alabama, which shared watersheds with the 
case study states, and Illinois and Texas, which are large electricity 
producing states with sizable population centers. We did not attempt to 
determine whether states' efforts were reasonable or effective, rather, 
we only describe what states do to consider water impacts when making 
power plant siting decisions. To understand the usefulness of federal 
water data to experts and state regulators who evaluate power plant 
development proposals, we reviewed data and analysis from USGS and 
DOE's EIA and National Energy Technology Laboratory. We also conducted 
interviews about the usefulness of federal data with data users, 
including federal agencies; regulators from state departments of water 
resources and public utility commissions; and experts from 
environmental and water organizations, industry, and academia. A more 
detailed description of our scope and methodology is presented in 
appendix I. 

We conducted this performance audit from October 2008 to October 2009, 
in accordance with generally accepted government auditing standards. 
Those standards require that we plan and perform the audit to obtain 
sufficient, appropriate evidence to provide a reasonable basis for our 
findings and conclusions based on our audit objectives. We believe that 
the evidence obtained provides a reasonable basis for our findings and 
conclusions based on our audit objectives. 

Background: 

Power plant developers consider many factors when determining where to 
locate a power plant, including the availability of fuel, water, and 
land; access to electrical transmission lines; electricity demand; and 
potential environmental issues. Often, developers will consider several 
sites that meet their minimum requirements, but narrow their selection 
based on economic considerations such as the cost of accessing fuel, 
water, or transmission lines, or the costs of addressing environmental 
factors at each specific site. 

One key requirement for thermoelectric power plants is access to water. 
Thermoelectric power plants use a heat source to make steam, which is 
used to turn a turbine connected to a generator that makes electricity. 
As shown in figure 1, the water used to make steam (boiler water) 
circulates in a closed loop. This means the same water used to make 
steam is also converted back to liquid water--referred to as 
condensing--in a device called a condenser and, finally, moved back to 
the heat source to again make steam. In typical thermoelectric plants, 
water from a separate source, known as cooling water, flows through the 
condenser to cool and condense the steam in the closed loop after it 
has turned the turbine. 

Figure 1: Diagram of a Boiler Water Loop in a Power Plant: 

[Refer to PDF for image: illustration] 

Noted on the illustration are the following: 

Heat source; 
Boiler; 
Boiler water; 
High pressure steam; 
Turbine; 
Low pressure steam; 
Cool cooling water; 
Condenser; 
Warm cooling water. 

Source: GAO analysis of various national laboratory and industry 
sources. 

[End of figure] 

Consideration of water availability during the power plant siting 
process can pose different challenges in different parts of the country 
because precipitation and, relatedly, water availability varies 
substantially across the United States. Figure 2 shows the total amount 
of freshwater withdrawn in the United States as a percentage of 
available precipitation. Areas where the percentage is greater than 
100--where more water is withdrawn than locally renewed through 
precipitation--are indicative of basins using other water sources 
transported by natural rivers and manmade flow structures, or may 
indicate unsustainable groundwater use. 

Figure 2: Total Freshwater Withdrawal in 1995 as a Percentage of 
Available Precipitation: 

[Refer to PDF for image: U.S. map] 

Indicated on the map are the following Total Freshwater Withdrawal 
areas: 

Less than 1%; 
1 to less than 5%; 
5 to less than 30%; 
30 to less than 100%; 
100 to less than 500%; 
500% or more. 

Source: Electric Power Research Institute. A Survey of Water Use and 
Sustainability in the United States With a Focus on Power
Generation. (Palo Alto, CA. 2003.) 1005474; Map (Mapinfo). 

Note: According to an Electric Power Research Institute official, the 
organization plans to update this analysis once USGS publishes 2005 
freshwater withdrawal data. 

[End of figure] 

Power plants can use various types of water for cooling--such as 
freshwater or saline water--and different water sources, including 
surface water, groundwater, and alternative water sources. An example 
of alternative water sources is reclaimed water such as treated 
effluent from sewage treatment plants. To make siting decisions, power 
plant developers typically consider the water sources that are 
available and least costly to use. Fresh surface water is the most 
common water source for power plants nationally, as shown in table 1. 

Table 1: Estimated Water Withdrawals by Thermoelectric Power Plants in 
the United States in 2000: 

Millions of gallons per day: 

Saline water: 
Surface Water: 59,500; 
Groundwater: 0. 

Freshwater: 
Surface Water: 135,000; 
Groundwater: 409. 

Source: U.S. Geological Survey, Estimated Use of Water in the United 
States in 2000, (Reston, Virginia, 2004). 

[End of table] 

Cooling Technologies: 

Power plant developers must also consider what cooling technologies 
they plan to use in the plant. There are four general types of cooling 
technologies. Traditional cooling technologies that have been used for 
decades include once-through and wet recirculating cooling systems. 
Advanced cooling technologies that have focused on reducing the amount 
of cooling water used are relatively newer in the United States and 
include dry cooling and hybrid cooling. Specifically: 

Once-through cooling systems. In once-through cooling systems, large 
amounts of cooling water are withdrawn from a water body such as a 
lake, river, or ocean, and used in the cooling loop. As shown in figure 
3, the cooling water passes through the tubes of a condenser. As steam 
in the boiler water loop exits the turbine, it passes over the 
condenser tubes. This contact with the condenser tubes cools and 
condenses the steam back into boiler water for reuse. After the cooling 
water passes through the condenser tubes, it is discharged back into 
the water body warmer than it was when it was withdrawn.[Footnote 6] 
Once-through cooling systems withdraw a significant amount of water but 
directly consume almost no water. However, because the water discharged 
back into the water body is warmer, experts believe that once-through 
systems may increase evaporation from the receiving water body. 
Furthermore, because of concerns about the harm withdrawal for once- 
through systems can have on aquatic life--when aquatic organisms are 
pulled into cooling systems, trapped against water intake screens, or 
their habitat is adversely affected by warm water discharges--these 
systems are rarely installed at new plants. 

Figure 3: Diagram of a Once-through Cooling System: 

[Refer to PDF for image: illustration] 

The following are indicated on the diagram: 

Heat source; 
Boiler; 
Boiler water; 
High pressure steam; 
Turbine; 
Generator; 
Electricity; 
Low pressure steam; 
Cool cooling water intake from river; 
Condenser; 
Warm cooling water discharge back to river. 

Source: GAO analysis of various national laboratory and industry 
sources. 

[End of figure] 

Wet recirculating systems. Wet recirculating systems differ from once-
through cooling systems in that they reuse cooling water multiple 
times. The most common type of recirculating system, shown in figure 4, 
uses cooling towers to dissipate the heat from the cooling water to the 
atmosphere. Similar to the once-through system, steam exiting the 
turbine is brought in contact with the tubes of a condenser that 
contain cooling water. The cooling water condenses the steam back into 
water for reuse in the boiler. The cooling water, warmed from the 
condenser, is then pumped to a cooling tower where it is exposed to the 
air. The heat from the warm cooling water is transferred to air flowing 
through the cooling tower, primarily through evaporation. In this 
process, some of the warm cooling water is consumed as it evaporates 
from the cooling tower, but most of it is returned to the condenser and 
used again. Over time, the quality of the cooling water is diminished 
as minerals and other dissolved and suspended solids present in the 
water are concentrated because of the water lost to evaporation. A 
portion of the cooling water containing the minerals and other 
dissolved solids must be discharged (known as blowdown) to prevent 
accumulation of those minerals and dissolved solids in the condenser, 
which could have adverse effects on condenser and cooling tower 
performance. For example, the National Energy Technology Laboratory 
estimated that a 520 megawatt wet recirculating system with a cooling 
tower circulates approximately 188,000 gallons of cooling water per 
minute. It withdraws around 5,000 gallons of water per minute to make 
up for the nearly 4,000 gallons per minute consumed through evaporation 
and approximately 1,000 gallons per minute discharged in the blowdown 
process. Some wet recirculating plants do not use a cooling tower but, 
instead, discharge cooling water to a pond, allowing it to cool before 
it is returned to the plant for reuse. For a wet recirculating system, 
water is only withdrawn from a water body to replace cooling water lost 
through evaporation and blowdown; thus, considerably less water is 
withdrawn than in a once-through cooling system. As a result, plants 
equipped with wet recirculating systems have relatively low water 
withdrawal but higher direct water consumption compared to once-through 
systems. 

Figure 4: Diagram of a Wet Recirculating System with a Cooling Tower: 

[Refer to PDF for image: illustration] 

The following are indicated on the diagram: 

Heat source; 
Boiler; 
Boiler water; 
High pressure steam; 
Turbine; 
Generator; 
Electricity; 
Low pressure steam; 
Cooling tower; 
Evaporation; 
Fan; 
Ambient air; 
Small amount of makeup water from Lake; 
Cool cooling water; 
Condenser; 
Warm cooling water. 

Source: GAO analysis of various national laboratory and industry 
sources. 

[End of figure] 

Dry cooling systems. Dry cooling systems rely primarily on air, rather 
than water, for cooling. In dry cooling systems, steam exiting the 
turbine flows through condenser tubes and is cooled directly by fans 
blowing air across the outside of these tubes to condense the steam 
back into liquid water. The cooled boiler water can then be reheated 
into steam to turn the turbine. In this approach, water is not used for 
cooling, although water still may be used for other plant purposes, 
such as pollution control equipment. As with the other systems, the 
steam, once cooled back into liquid water, is returned to the turbine 
for reuse.[Footnote 7] See figure 5 for an illustration of dry cooling. 

Figure 5: Diagram of a Dry Cooling System: 

[Refer to PDF for image: illustration] 

The following are indicated on the diagram: 

Heat source; 
Boiler; 
Boiler water; 
High pressure steam; 
Turbine; 
Generator; 
Electricity; 
Low pressure steam; 
Air cooled condenser; 
Air in; 
Fan; 
Air out. 

Source: GAO analysis of various national laboratory and industry 
sources. 

[End of figure] 

Hybrid cooling systems. Hybrid cooling technology offers a middle-
ground option between wet and dry cooling systems, where wet and dry 
cooling components can be used either separately or simultaneously, as 
shown in figure 6. The system can operate both the wet and dry 
components in unison to increase cooling efficiency or may rely only on 
dry cooling to conserve water as needed.[Footnote 8] 

Figure 6: Diagram of a Hybrid Cooling System: 

[Refer to PDF for image: illustration] 

The following are indicated on the diagram: 

Heat source; 
Boiler; 
Boiler water; 
High pressure steam; 
Turbine; 
Generator; 
Electricity; 
Low pressure steam; 
Air cooled condenser; 
Air in; 
Air out; 
Cooling tower; 
Evaporation; 
Fan; 
Ambient air; 
Small amount of makeup water from Lake; 
Cool cooling water; 
Condenser; 
Warm cooling water. 

Source: GAO analysis of various national laboratory and industry 
sources. 

[End of figure] 

In 2008, the National Energy Technology Laboratory--a U.S. DOE 
laboratory that conducts and implements science and technology research 
and development programs in energy--estimated that 42.7 percent of U.S. 
thermoelectric generating capacity uses once-through cooling, 41.9 
percent uses cooling towers, 14.5 percent uses cooling ponds, and 0.9 
percent uses dry cooling.[Footnote 9] Figure 7 illustrates the 
prevalence of different cooling technologies across the United States. 

Figure 7: Water Based Cooling Systems by Technology and Water Source: 

[Refer to PDF for image: U.S. map] 

The locations of the following water based cooling systems are 
indicated on the map: 

Water type: 
Fresh; 
Saline. 

Cooling type: 
Cooling pond; 
Once through; 
Recirculating with cooling towers. 

Source: National Energy Technology Laboratory, based on EIA-collected 
data; Map (Mapinfo). 

Note: The National Energy Technology Laboratory developed this graphic 
based on 2000 and 2005 data collected by EIA and, as a result, power 
plants with a capacity less than 100 megawatts are not shown. According 
to an official from the National Energy Technology Laboratory, it was 
not possible using EIA data to determine the water type of cooling 
ponds. Additionally, as discussed later in the report, it is not 
possible to use EIA data to comprehensively identify the universe of 
plants with dry or hybrid cooling systems. 

[End of figure] 

Federal Data Collection: 

Although a number of federal agencies collect data on water, two 
collect key data that are used to analyze the impacts of thermoelectric 
power plants and water availability: USGS and EIA. 

* USGS's mission is to provide reliable scientific information to 
manage water, energy and other resources, among other things. USGS 
collects surface water and groundwater availability data through a 
national network of stream gauges and groundwater monitoring stations. 
USGS currently monitors surface and groundwater availability with 
approximately 7,500 streamflow gauges and 22,000 groundwater monitoring 
stations located throughout the United States. 

* USGS compiles data and distributes a report every 5 years on national 
water use that describes how various sectors, such as irrigation, 
mining, and thermoelectric power plants, use water. USGS data related 
to thermoelectric power plants include(1) water withdrawal data at the 
state and county level organized by cooling technology--once-through 
and wet recirculating; (2) water source--surface or groundwater; and 
(3) whether water used was fresh or saline. USGS compiles water use 
data from multiple sources, including state water regulatory officials, 
power plant operators, and EIA. If data are not available for a 
particular state or use, USGS makes estimates. 

* EIA's mission is to provide policy-neutral data, forecasts, and 
analyses to promote sound policy making, efficient markets, and public 
understanding regarding energy and its interaction with the economy and 
the environment. In carrying out this mission, EIA collects a variety 
of energy and electricity data nationwide, about topics such as energy 
supply and demand. For certain plants producing 100 megawatts or more 
of electricity, EIA collects data on water withdrawals, consumption, 
discharge, as well as some information on water source and cooling 
technology type. EIA annually collects water use data directly from 
power plants by using a survey. 

State Water Laws: 

The variety of state water laws relating to the allocation and use of 
surface water can generally be traced to two basic doctrines: the 
riparian doctrine, often used in the eastern United States, and the 
prior appropriation doctrine, often used in the western United States. 

* Under the riparian doctrine, water rights are linked to land 
ownership--owners of land bordering a waterway have a right to use the 
water that flows past the land for any reasonable purpose. In general, 
water rights in riparian states may not be bought or sold. Landowners 
may, at any time, use water flowing past the land, even if they have 
never done so before. All landowners have an equal right to use the 
water, and no one gains a greater right through prior use. In some 
riparian states, water use is closely tracked by requiring users to 
apply for permits to withdraw water. In other states, where water has 
traditionally not been scarce, water use is not closely tracked. When 
there is a water shortage, water users share the shortage in proportion 
to their rights, or the amount they are permitted to withdraw, to the 
extent that it is possible to determine. 

* Under the prior appropriation doctrine, water rights are not linked 
with land ownership. Instead, water rights are property rights that can 
be owned independent of land and are linked to priority and beneficial 
water use. A water right establishes a property right claim to a 
specific amount of water--called an allotment. Because water rights are 
not tied to land, water rights can be bought and sold without any 
ownership of land, although the rights to water may have specific 
geographic limitations. For example, a water right generally provides 
the ability to use water in a specific river basin taken from a 
specific area of the river. Water rights are also prioritized--water 
rights established first generally have seniority for the use of water 
over water rights established later--commonly described as "first in 
time, first in right." As a result, once established, water rights 
retain their priority for as long as they remain valid. For example, a 
water right to 100 acre feet of Colorado River water established in 
1885 would retain that 1885 priority and allotment, even if the right 
was sold by the original party who established it. Water rights also 
must be exercised in order to remain valid, meaning rights holders must 
put the water to beneficial use or their right can be deemed abandoned 
and terminated--commonly referred to as "use it or lose it." When there 
is a water shortage in prior appropriation states, shortages fall on 
those who last obtained a legal right to use the water. As a result, a 
shortage can result in junior water rights holders losing all access to 
water, while senior rights holders have access to their entire 
allotment. 

For some states, the legal framework for groundwater is similar to that 
of surface water as they use variants of either the riparian or prior 
appropriation doctrine to allocate water rights. However, in other 
states, the allocation of groundwater rights follows other legal 
doctrines, including the rule of capture doctrine and the doctrine of 
reasonable use. Under the rule of capture doctrine, landowners have the 
right to all the water they can capture under their land for any use, 
regardless of the effect on other water users. The doctrine of 
reasonable use similarly affords landowners the right to water 
underneath their land, provided the use is restricted to an amount 
necessary for reasonable use. In some cases, permits may be required 
prior to use and additional regulation may occur if a groundwater 
source is interconnected with surface water. 

Power Plant Applications: 

A number of state agencies may be involved in considering or approving 
applications to build power plants or to use water in power plants. In 
some states, a centralized agency considers applications to build new 
power plants. In other states, applications may be filed with multiple 
state agencies. State water regulators issue water permits for power 
plants and other sectors to regulate water use and ensure compliance 
with relevant state laws and regulations. Public Utility Commissions, 
or the equivalent, may also have a role in authorizing the development 
of a power plant. In many states where retail electricity rates are 
regulated, these commissions are primarily responsible for approving 
the rates (or prices) electric utilities charge their customers and 
ensuring they are reasonable. As part of approving rates, these 
commissions approve utility investments into such things as new power 
plants and, as a result, may consider whether specific power plant 
design and cooling technologies are reasonable. 

Thermoelectric Power Plants and Water Availability: 

Based on figures from EIA's 2009 Annual Energy Outlook, thermoelectric 
power plant generating capacity will increase by about 15 percent 
between 2006 and 2030. Depending on which cooling approaches are used, 
such an increase could further strain water resources. A variety of 
additional factors may also affect the availability of water for 
electricity generation and other uses, as well as the amount of water 
used to produce electricity. Some studies indicate that climate change 
will result in changes in local temperatures and more seasonal 
variations, both of which could cause increased levels of water 
consumption from thermoelectric power plant generation. Climate change 
may also result in changes in local precipitation and water 
availability, as well as more and longer droughts in some areas of the 
country. To the extent that this occurs, power plant operators may need 
to reduce the use of water for power plant cooling. In addition, some 
technologies aimed at reducing greenhouse gas emissions, such as carbon 
capture technologies, may require additional water. The combination of 
environmental laws, climate change, and the inclusion of new water 
intensive air emission technologies may impact water availability and 
require power plants operators to reduce water use in the future. In 
addition, since the water inlet structures used at once-through cooling 
plants can either trap or draw in fish and other aquatic life--referred 
to as impingement and entrainment--there is increased pressure to 
reduce the use of once-through cooling at existing plants. 

Advanced Cooling Technologies and Alternative Water Sources Can Reduce 
the Use of Freshwater at Power Plants, but Their Adoption Poses Certain 
Drawbacks: 

Advanced cooling technologies and alternative water sources can reduce 
freshwater use by thermoelectric power plants, leading to a number of 
benefits for plant developers; however, incorporating each of these 
options for reducing freshwater use into thermoelectric power plants 
also poses certain drawbacks. Benefits of reducing freshwater use may 
include social and environmental benefits, minimizing water-related 
costs, as well as increasing a developer's flexibility in determining 
where to locate a new plant. On the other hand, drawbacks to using 
advanced cooling technologies may include potentially lower net 
electricity output, higher costs, and other trade-offs. Similarly, the 
use of alternative water sources, such as treated effluent or 
groundwater unsuitable for drinking or irrigation, may have adverse 
effects on cooling equipment, pose regulatory challenges, or be located 
too far from a proposed plant location to be a viable option. Power 
plant developers must weigh the trade-offs of these drawbacks with the 
benefits of reduced freshwater use when determining what approaches to 
pursue, and must consider both the economic costs over a plant's 
lifetime and the regulatory climate. For example, in a water-scarce 
region of the country where water costs are high and there is 
significant regulatory scrutiny of water use, a power plant developer 
may opt for a water-saving technology despite its drawbacks. 

Advanced Cooling Technologies and Alternative Water Sources Can Reduce 
Freshwater Use, Leading to a Number of Benefits: 

Advanced cooling technologies under development and in limited 
commercial use and alternative water sources can reduce the amount of 
freshwater needed by plants, resulting in a number of benefits to both 
the environment and plant developers. As shown in table 2, dry cooling 
can eliminate nearly all the water withdrawn and consumed for power 
plant cooling. 

Table 2: Selected Estimates of Water Withdrawn and Consumed for Power 
Plant Cooling by Cooling Technology and Plant Type[A]: 

Gallons per megawatt hour by type of plant: Coal; 
Once-through: Withdrawal: 20,000 - 50,000; 
Once-through: Consumption[B]: 300; 
Wet recirculating with cooling tower: Withdrawal: 500-600; 
Wet recirculating with cooling tower: Consumption: 480; 
Dry cooling: Withdrawal: 0; 
Dry cooling: Consumption: 0. 

Gallons per megawatt hour by type of plant: Combined cycle; 
Once-through: Withdrawal: 7,500-20,000; 
Once-through: Consumption[B]: 100; 
Wet recirculating with cooling tower: Withdrawal: 230; 
Wet recirculating with cooling tower: Consumption: 180; 
Dry cooling: Withdrawal: 0; 
Dry cooling: Consumption: 0. 

Gallons per megawatt hour by type of plant: Nuclear; 
Once-through: Withdrawal: 25,000 - 60,000; 
Once-through: Consumption[B]: 400; 
Wet recirculating with cooling tower: Withdrawal: 800-1,100; 
Wet recirculating with cooling tower: Consumption: 720; 
Dry cooling: Withdrawal: [C]; 
Dry cooling: Consumption: [C]. 

Gallons per megawatt hour by type of plant: Solar thermal (trough); 
Once-through: Withdrawal: [Empty]; 
Once-through: Consumption[B]: [Empty]; 
Wet recirculating with cooling tower: Withdrawal: 600-850[D]; 
Wet recirculating with cooling tower: Consumption: [D]; 
Dry cooling: Withdrawal: 0; 
Dry cooling: Consumption: 0. 

Sources: Coal, natural gas and nuclear estimates: Electric Power 
Research Institute, Water and Sustainability (Volume 3): U.S. Water 
Consumption for Power Production--The Next Half Century. (Palo Alto, 
CA, 2002). 1006786. Dry cooling and solar thermal: Electric Power 
Research Institute, Water Use for Electric Power Generation, (Palo 
Alto, CA, 2008). 1014026. 

Note: We did not include water use estimates for hybrid cooling in this 
table, because these systems' water use is very dependent on their 
design and operation, including the proportion of wet versus dry 
cooling. Additionally, for wet recirculating systems, we provided water 
use estimates only for those systems with cooling towers, since 
according to work conducted by the National Energy Technology 
Laboratory, they are more common than wet recirculating systems with 
cooling ponds. 

[A] In addition to cooling water, water may be used for other plant 
purposes, such as environmental controls; make-up boiler water; and 
water for cleaning, drinking, and sanitation. As a result, while dry 
and hybrid systems may eliminate or minimize water needs for cooling, 
total plant water use will not be eliminated entirely. Furthermore, 
some plants, such as natural gas simple cycle, solar photovoltaic, and 
wind, are not considered thermoelectric and do not use water for 
cooling but may use water for other plant purposes. 

[B] Once-through cooling systems discharge water at a warm temperature; 
therefore, water consumption in these systems occurs via evaporation 
downstream of the plant. 

[C] Representatives from one engineering firm and some power plant 
developers we spoke to explained that the large size of dry cooling 
systems needed for plants that derive all of their electricity 
production from the steam cycle, for example, nuclear and coal plants, 
may introduce challenges. Furthermore, according to another expert, one 
type of dry cooled technology may not be approved for use with certain 
nuclear reactors because of safety concerns. 

[D] This estimate for solar thermal (trough) water withdrawals is from 
the Electric Power Research Institute's 2008 report. This report did 
not identify a comparable range for water consumption. Other sources we 
reviewed estimated water consumption rates for solar trough plants 
ranging from 740 gallons to 920 gallons per megawatt hour. 

[End of table] 

Hybrid cooling systems, depending on design, can reduce water use-- 
generally to a level between that of a wet recirculating system with 
cooling towers and a dry cooling system. According to the Electric 
Power Research Institute, hybrid systems are typically designed to use 
20-80 percent of the water used for a wet recirculating system with 
cooling towers.[Footnote 10] 

In addition to using advanced cooling technologies, power plant 
operators can reduce freshwater use by utilizing water sources other 
than freshwater. Alternative water sources include treated effluent 
from sewage treatment plants; groundwater that is unsuitable for 
drinking or irrigation because it is high in salts or other impurities; 
sea water; industrial water and water generated when extracting 
minerals like oil, gas, and coal. For example, the oil and gas 
production process can generate wastewater, which is the subject of 
research as a possible source of cooling water for power plants. 

Use of alternative water sources by power plants is increasing in some 
areas, and two power plant developers we spoke with said they routinely 
consider alternative water sources when planning new power plants, 
particularly in areas where water has become scarce, tightly regulated, 
or both. A 2007 report by the DOE's Argonne National Laboratory 
identified at least 50 power plants in the United States that use 
reclaimed water for cooling and other purposes, with Florida and 
California having the largest number of plants using reclaimed water. 
[Footnote 11] According to the report, the use of reclaimed water at 
power plants has become more common, with 38 percent of the plants 
using reclaimed water doing so after 2000. One example of a power plant 
using an alternative to freshwater is Palo Verde, located near Phoenix, 
Arizona--the largest U.S. nuclear power plant, with a capacity of 
around 4,000 megawatts. Palo Verde uses approximately 20 billion 
gallons of treated effluent annually from treatment plants that serve 
several area municipalities, comprising over 1.5 million people. 

Reducing the amount of freshwater needed for cooling leads to a number 
of social and environmental benefits and may benefit developers by 
lowering water-related costs and providing more flexibility in choosing 
a location for a new plant, among other things. 

Social and Environmental Benefits: 

Reducing the amount of freshwater used by power plants through the use 
of advanced cooling technologies and alternative water sources has the 
potential to produce a number of social and environmental benefits. For 
example, limiting freshwater use may reduce the impact to the 
environment associated with withdrawals, consumption, and discharge. 
Freshwater is in high demand across the United States. Reducing 
freshwater withdrawals and consumption by the electricity sector makes 
this limited resource more available for additional electricity 
production or competing uses, such as public water supplies or wildlife 
habitat. Furthermore, eliminating water use for cooling entirely, such 
as by using dry cooling, could minimize or eliminate the water 
discharges from power plants, a possible source of heat and pollutants 
to receiving water bodies, although regulations limit the amount of 
heat and certain pollutants that may be discharged into water bodies. 

Water-Related Cost Savings: 

By eliminating or minimizing the use of freshwater for cooling, power 
plant developers may reduce some water-related costs, including the 
costs associated with acquiring, transporting, treating, and disposing 
of water. Depending on state water laws, a number of costs may be 
associated with acquiring water--purchasing a right to use water, 
buying land with a water source on or underneath it, or buying a 
quantity of freshwater from a municipal or other source. Eliminating 
the need to purchase water for cooling by using dry cooling could 
reduce these water-related expenses. Using an alternative water source, 
if less expensive than freshwater, could reduce the costs of acquiring 
water, although treatment costs may be higher. Power plant developers 
and an expert from a national laboratory told us the costs of acquiring 
an alternative water source are sometimes less than freshwater, but 
vary widely depending on its quality and location. In addition to 
lowering the costs associated with acquiring water, if water use for 
cooling is eliminated entirely, plant developers may eliminate the need 
for a pipeline to transport the water, as well as minimize costs 
associated with treating the water. Water-related costs are one of 
several costs that power plant developers will consider when evaluating 
alternatives to freshwater. Since the cost of freshwater may rise as 
demand for freshwater increases, a developer's ability to minimize 
power plant freshwater use could become increasingly valuable over 
time. 

Siting Flexibility and Other Benefits: 

Minimizing or eliminating the use of freshwater may offer a plant 
developer increased flexibility in determining where to locate a power 
plant. According to power plant developers we spoke with, siting a 
power plant involves balancing factors such as access to fuel, 
including natural gas pipelines, and access to large transmission lines 
that carry the electricity produced to areas of customer demand. Some 
explained that finding a site that meets these factors and also has 
access to freshwater can be challenging. Power plant developers we 
spoke with said options such as dry cooling and alternative water 
sources have offered their companies the flexibility to choose sites 
without freshwater, but with good access to fuel and transmission. 

According to power plant developers and an expert from a national 
laboratory we spoke with, eliminating or lowering freshwater use can 
lead to other benefits, such as minimizing regulatory hurdles like the 
need to acquire certain water permits. Furthermore, using a 
nonfreshwater source may be advantageous in areas with more regulatory 
scrutiny of or public opposition to freshwater use. 

Adoption of Advanced Cooling Technologies May Reduce Electricity 
Production, Increase Costs, and Pose Other Drawbacks: 

Despite the benefits associated with the lower freshwater requirements 
of advanced cooling technologies, these technologies have a number of 
drawbacks related to electricity production and costs that power plant 
developers will have to consider during their decisionmaking process. 

Energy Production Penalties: 

Despite the many benefits advanced cooling technologies offer, both dry 
cooling and hybrid cooling technologies may reduce a plant's net energy 
production to a greater extent than traditional cooling systems-- 
referred to as an "energy penalty." Energy penalties result in less 
electricity available outside the plant, which can affect plant 
revenues, and making up for the loss of this electricity by generating 
it elsewhere can result in increases in water use, fuel consumption, 
and air emissions. Energy penalties result from (1) energy consumed to 
run cooling system equipment, such as fans and pumps, and (2) lower 
plant operating efficiency--measured as electricity production per unit 
of fuel--in hot weather due to lower cooling system performance. 
Specifically, energy penalties include: 

* Energy needed for cooling system equipment. Cooling systems, like 
many systems in a power plant, use electricity produced at the plant to 
operate, which results in less electricity available for sale. 
According to experts we spoke with, because dry cooling systems and 
hybrid cooling systems rely on air flowing through a condenser, energy 
is needed to run fans that provide air flow, and the amount of energy 
needed to run cooling equipment will depend on such factors as system 
design, season, and region.[Footnote 12] A 2001 EPA study estimated 
that for a combined cycle plant, energy requirements to operate a once- 
through system (pumps) are 0.15 percent of plant output, 0.39 percent 
of plant output for a wet recirculating system with cooling towers 
(pumps and fans), and 0.81 percent of plant output for a dry cooled 
system (fans).[Footnote 13] 

* Plant operating efficiency and cooling system performance. Plants 
using a dry cooling component, whether entirely dry cooled or in a 
hybrid cooled configuration, may face reduced operating efficiency 
under certain conditions. A power plant's operating efficiency is 
affected by the performance of the cooling system, among other things, 
and power plants with systems that cool more effectively produce 
electricity more efficiently. A cooling system's effectiveness is 
influenced both by the design of the cooling system and ambient 
conditions that determine the temperature of that system's cooling 
medium--water in once-through and wet recirculating systems and air in 
dry cooling systems. In general, the effectiveness of a cooling system 
decreases as the temperature of the cooling medium increases, since a 
warmer medium can absorb less heat from the steam. Once-through systems 
cool steam using water being withdrawn from the river, lake, or ocean. 
Wet recirculating systems with cooling towers, on the other hand, use 
the process of evaporation to cool the steam to a temperature that 
approaches the "wet-bulb temperature"--an alternate measure of 
temperature that incorporates both the ambient air temperature and 
relative humidity. In contrast, dry cooled systems transfer heat only 
to the ambient air, without evaporation. As a result, dry cooled 
systems can cool steam only to a temperature that approaches the "dry- 
bulb temperature"--the measure of ambient air temperature measured by a 
standard thermometer and with which most people are familiar. In 
general, once-through systems tend to cool most effectively because the 
temperature of the body of water from which cooling water is drawn is, 
on average, lower than the wet-or dry-bulb temperature. Moreover, wet- 
bulb temperatures are generally lower than dry-bulb temperatures, often 
making recirculating systems more effective at cooling than dry cooled 
systems. Further, according to one report that we reviewed, greater 
fluctuations in dry-bulb temperatures seasonally and throughout the day 
can make dry cooled systems harder to design.[Footnote 14] Dry bulb 
temperatures can be especially high in hot, dry parts of the country, 
such as the Southwest, leading to significant plant efficiency losses 
during periods of high temperatures, particularly during the summer. 
According to experts and power plant developers we spoke with, plant 
efficiencies may witness smaller reductions during other parts of the 
year when temperatures are lower or in cooler climates.[Footnote 15] 
Nevertheless, in practice, lower cooling system performance can result 
in reduced plant net electricity output or greater fuel use if more 
fuel is burned to produce electricity to offset efficiency losses. 
Plant developers can take steps to reduce efficiency losses such as by 
installing a larger dry cooling system with additional cooling 
capability, but such a system will result in higher capital costs. 

A plant's total energy penalty will be a combination of both effects 
described--energy needed for cooling system equipment and the impact of 
cooling system performance on plant operating efficiency. Energy 
penalties may result in lost revenue for the plant due to the net loss 
in electricity produced for a given unit of fuel, especially during the 
summer when electricity demand and prices are often the highest. Energy 
penalties may also affect the price consumers pay for electricity in a 
regulated market, if the cost of the additional fuel needed to produce 
lost electricity is passed on to consumers by regulators. Finally, 
energy penalties may affect emissions of pollutants and carbon dioxide 
if lost output is made up for by an emissions producing power plant, 
such as a coal-or natural gas-fueled power plant. This is because 
additional fuel is burned to produce electricity that offsets what was 
lost as a result of the energy penalty, and, thus, additional carbon 
dioxide and other pollutants are released. 

Recent studies comparing total energy penalties between cooling systems 
have used differing methodologies to estimate energy penalties and have 
reached varying conclusions.[Footnote 16] For example, a 2001 EPA study 
estimates the national average, mean annual energy penalties--lower 
electricity output--for plants operating at two-thirds capacity with 
dry cooling to be larger than those with wet recirculating systems with 
cooling towers. In this study, EPA estimated penalties of 1.7 percent 
lower output for a combined cycle plant with a dry system compared to a 
wet recirculating system with a cooling tower, and 6.9 percent lower 
output for a fossil fueled plant run fully on steam, such as a coal 
plant.[Footnote 17] Similarly, a separate study conducted by two DOE 
national labs in 2002 estimated larger annual energy penalties for 
hypothetical 400 megawatt coal plants in multiple regions of the 
country retrofitted to dry cooling--these penalties ranged between 3 to 
7 percent lower output on average for a plant retrofitted with a dry 
cooled system compared to a plant retrofitted with a wet recirculating 
system with a cooling tower. On the hottest 1 percent of temperature 
conditions during the year, this energy penalty rose to between 6 and 
10 percent lower output for plants retrofitted to dry cooling compared 
with those retrofitted to a wet recirculating system with cooling 
towers[Footnote 18]. However, some experts we spoke with told us energy 
penalties are higher in retrofitted plants than when a dry cooled 
system is designed according to the unique specifications of a newly 
built plant. 

A 2006 study conducted for the California Energy Commission estimated 
electricity output and other characteristics for new, theoretical 
combined cycle natural gas plants in four climatic zones of California 
using different cooling systems. The study found that dry cooling 
systems result in significant water savings, but that plants using wet 
cooling systems generally experience higher annual net electricity 
output, as shown in table 3, and lower fuel consumption. Furthermore, 
while the study estimates that plant capacity to produce electricity is 
limited on hot days for both types of cooling systems, the hot day 
capacity of the dry cooled plant to produce electricity is up to 6 
percent lower than the wet recirculating plant with cooling tower. 
[Footnote 19] 

Table 3: Percentage Difference in Annual Net Plant Electricity Output 
for Theoretical Combined Cycle Plants with Different Cooling Systems at 
Four Geographic Locations in California: 

Geographic locations: Desert (hot, arid); 
Percentage difference in annual net plant electricity output for a wet 
recirculating system with cooling towers compared to a dry cooled 
system: 1.07. 

Geographic locations: Valley (hot, humid); 
Percentage difference in annual net plant electricity output for a wet 
recirculating system with cooling towers compared to a dry cooled 
system: 1.46. 

Geographic locations: Coast (cool, humid); 
Percentage difference in annual net plant electricity output for a wet 
recirculating system with cooling towers compared to a dry cooled 
system: 0.37. 

Geographic locations: Mountain (variable, elevated); 
Percentage difference in annual net plant electricity output for a wet 
recirculating system with cooling towers compared to a dry cooled 
system: 1.87. 

Source: Maulbetsch, J. S. and M.N. DiFilippo, Cost and Value of Water 
Use at Combined-Cycle Power Plants, California Energy Commission, PIER 
Energy-Related Environmental Research, CEC-500-2006-034. April 2006. 

[End of table] 

Power plant developers can take steps to address the energy penalties 
associated with dry cooling technology by designing their plants with 
larger dry cooled systems capable of performing better during periods 
of high ambient temperatures. Alternatively, they can use a hybrid 
technology that supplements the dry system with a wet recirculating 
system with a cooling tower during the hottest times of the year. 
However, in making this decision, developers must weigh the trade-offs 
between the costs associated with building and operating a larger dry 
cooled system or a hybrid system and the benefits of lowering their 
energy penalties. 

Higher Costs: 

According to some power plant developers and experts we spoke with, 
another drawback to using dry and hybrid cooling technologies is that 
these technologies typically have higher capital costs. Experts, power 
plant developers, and studies indicated that while capital costs for 
each system can vary significantly, as a general rule, capital costs 
are lowest for once-through systems, higher for wet recirculating 
systems, and highest for dry cooling. Some told us the capital costs of 
hybrid systems--as a combination of wet recirculating and dry cooling 
systems--generally fall in between these two systems. Furthermore, 
according to some of the experts we spoke with and studies we reviewed, 
the capital costs of a plant's cooling system vary based on the 
specific characteristics of a given plant, such as the costs of the 
cooling towers, the circulating water lines to transport water to and 
around the plant, pumps, fans, as well as the extent to which a dry 
cooled system is sized larger to offset energy penalties. As with 
energy penalties, studies estimating capital costs for dry and hybrid 
systems have used differing methodologies and provide varying estimates 
of capital costs.[Footnote 20] One study by the Electric Power Research 
Institute estimated dry cooling system capital costs for theoretical 
500 megawatt combined cycle plants in 5 climatic locations to be 3.6 to 
4.0 times that of wet recirculating systems with cooling towers. 
[Footnote 21] Experts from an engineering firm we spoke with also 
explained that capital costs for dry and hybrid cooled systems can be 
many times that of a wet recirculating system with cooling towers. They 
estimated that, in general, installing a dry system on a 500 megawatt 
combined cycle plant instead of a wet recirculating system with a 
cooling tower could increase baseline capital costs by $9 to $24 
million, depending on location--an increase in baseline capital costs 
that is 2.0 to 5.1 times higher than if a wet recirculating system with 
a cooling tower were used. They estimated dry cooling to be more costly 
on a 500 megawatt coal plant, with dry cooling resulting in an increase 
in baseline capital costs that was 2.6 to 7.0 times higher than if a 
wet recirculating system with a cooling tower were used. 

With respect to annual costs, according to experts we spoke with and 
studies we reviewed, annual cost differences between alternative 
cooling technologies and traditional cooling technologies are variable 
and may depend on such factors as the costliness of obtaining and 
treating water, the extent to which cooling water is reused within the 
system, the need for maintenance, the extent to which energy penalties 
result in lost revenue, and the extent to which a cooling system is 
sized larger to offset energy penalties. Estimates from four reports we 
reviewed calculated varying cooling system annual costs for a range of 
plant types and locations using different methodologies, and found 
annual costs of dry systems to generally range from one and a half to 
four times those of wet recirculating systems with cooling towers. One 
of these studies, however, in examining the potential for higher water 
costs, found that dry cooling could be more economical on an annual 
basis in some areas of the country with expensive water or become more 
economical in the future if water costs were to rise.[Footnote 22] 
Furthermore, an expert from an engineering firm we spoke with explained 
that cooling system costs are only one component of total plant costs, 
and that while one cooling system may be expensive relative to another, 
its impact on total plant costs may not be as significant in a relative 
sense if the plant's total costs are high. 

Space, Noise, and Suitability Issues: 

There may be other drawbacks to dry cooled technology, including space 
and noise considerations. Towers, pumps, and piping for both dry cooled 
and wet cooled systems with cooling towers require substantial space, 
but according to experts we spoke with, dry cooled systems tend to be 
larger. For example, according to one expert we spoke with, a dry 
cooled system for a natural gas combined cycle plant that derives one- 
third of its electricity from the steam cycle could be almost as large 
as two football fields. Moreover, according to others, the large size 
of dry cooling systems needed for plants that derive all of their 
electricity production from the steam cycle--for example, nuclear and 
coal plants--may make the use of dry cooling systems less suitable for 
these kinds of power plants. Experts we spoke with explained that 
because full steam plants produce all of their electricity by heating 
water to make steam, they require larger cooling systems to condense 
the steam back into usable liquid water. As a result, the size of a dry 
cooling system for a full steam plant could be three times that of a 
dry cooling system for a similarly-sized combined cycle plant that only 
produces one-third of its electricity from the steam cycle. 

Furthermore, according to one expert we spoke with, the most efficient 
type of dry cooled technology may not be approved for use with certain 
nuclear reactors, because of safety concerns. Finally, the motors, 
fans, and water of both dry cooled and wet recirculating systems with 
cooling towers may create noise that disturbs plant employees, nearby 
residents, and wildlife. Noise-reduction systems may be used to address 
this concern, although they introduce another cost trade-off that plant 
developers must consider. 

Use of Alternative Water Sources May Also Pose Certain Drawbacks: 

Despite the growth in plants using alternative water sources, there are 
a number of drawbacks to using this water source instead of freshwater. 
While some of these drawbacks are similar to those faced by power 
plants that use freshwater, they may be exacerbated by the lower 
quality of alternative water sources. These drawbacks include adverse 
effects to cooling equipment, regulatory compliance issues, and access 
to alternative water sources, as follows. 

Adverse Effects to Cooling Equipment: 

Water used in power plants must meet certain quality standards in order 
to avoid adverse effects to cooling equipment, such as corrosion, 
scaling, and the accumulation of micro or macrobiological organisms. 
While freshwater can also cause adverse effects, the generally lower 
quality of alternative water sources make them more likely to result in 
these effects. For example, effluent from a sewage treatment plant may 
be higher in ammonia than freshwater, which can cause damage to copper 
alloys and other metals. High levels of ammonia and phosphates can also 
lead to excessive biological growth on certain cooling tower 
structures. Chemical treatment is used to mitigate such adverse effects 
of alternative water sources when they occur, but this treatment 
results in additional costs. According to one power plant operator we 
spoke with, alternative water sources often require more extensive and 
expensive treatment than freshwater sources, and it can be a 
challenging process to determine the precise makeup of chemicals needed 
to minimize the adverse effects. 

Regulatory Compliance Issues: 

Power plant developers using alternative water sources may face 
additional regulatory challenges. Depending on their design, power 
plants may discharge water directly to a water source, such as a 
surface water body, or release water into the air through cooling 
towers. As a result, power plants must comply with a number of water 
quality and air regulations, and the presence of certain pollutants in 
alternative water sources can make compliance more challenging. For 
example, reclaimed water from sewage treatment plants is treated to 
eliminate bacteria and other contaminants that can be harmful to 
humans. Similarly, water associated with minerals extraction may 
contain higher total dissolved and suspended solids and other 
constituents, which could adversely affect the environment if 
discharged. Addressing these issues through the following actions 
entail additional costs to the power plant operators: (1) chemical 
treatment prior to discharging water to another water source, (2) 
discharging water to a holding pond unconnected to another water source 
for evaporation, or (3) eliminating all liquid discharges by, for 
example, evaporating all the water used at the plant and disposing of 
the resulting solid waste into a facility such as a landfill. 

Access to Alternative Water Sources: 

As with freshwater sources, the proximity of an alternative water 
source may be a drawback that power plant developers have to consider 
when pursuing this option. Power plant developers wishing to use an 
alternative water source must either build the plant near that source--
which can be challenging if that water source is not also near fuel and 
transmission lines--or pay the costs of transporting the water to the 
power plant's location, such as through a pipeline. Furthermore, two 
power plant developers we spoke with told us that certain alternative 
water sources, like treated effluent, are in increasing demand in some 
parts of the country, making it more challenging or costly to obtain 
than in the past. 

Power Plant Developers Must Weigh Trade-offs When Evaluating Options to 
Reduce Freshwater Use: 

A power plant developer may want to reduce the use of freshwater for a 
number of reasons, such as when freshwater is unavailable or costly to 
obtain, to comply with regulatory requirements, or to address public 
concern. However, power plant developers we spoke with told us that 
when considering the viability of an advanced cooling technology or 
alternative water source, they must weigh the trade-offs between the 
water savings and other benefits these alternatives offer with the 
drawbacks to their use. For example, in a water-scarce region of the 
country where water costs are high and there is much regulatory 
scrutiny of water use, a power plant developer may determine that, 
despite the drawbacks associated with the use of advanced cooling 
technologies or alternative water sources, these alternatives still 
offer the best option for getting a potentially profitable plant built 
in a specific area. Furthermore, according to power plant developers we 
spoke with, these decisions have to be made on a project by project 
basis because the magnitude of benefits and drawbacks will vary 
depending on a plant's type, location, and the related climate. For 
example, dry cooling has been installed in regions of the country where 
water is relatively plentiful, such as the Northeast, to help shorten 
regulatory approval times and avoid concerns about the adverse impacts 
that other cooling technologies might have on aquatic life. In making a 
determination about what cooling technology to use, power plant 
developers evaluate the net economic costs of alternatives like dry 
cooling or an alternative water source--its savings compared to its 
costs--over the life of a proposed plant, as well as the regulatory 
climate. Experts we spoke with told us this involves consideration of 
both capital and annual costs, including how expected water savings 
compare to costs related to energy penalties and other factors. 
Anticipated future increases in water-related costs could prompt a 
developer to use a water-saving alternative. For example, a recent 
report by the Electric Power Research Institute estimates that a power 
plant's economic trade-offs vary considerably depending on its location 
and that high water costs could make dry cooling less expensive 
annually than wet cooling[Footnote 23]. 

The National Energy Technology Laboratory is funding research and 
development projects aimed at minimizing the drawbacks of advanced 
cooling technologies and alternative water sources. In 2008, the 
laboratory awarded close to $9 million to support research and 
development of projects that, among other things, could improve the 
performance of dry cooled technologies, recover water used to reduce 
emissions at coal plants for reuse, and facilitate the use of 
alternative water sources in cooling towers. Such research endeavors, 
if successful and deemed economical, could alter the trade-off analysis 
power plant developers conduct in favor of nontraditional alternatives 
to cooling. 

States We Contacted Vary in the Extent to Which They Consider Water 
Impacts When Reviewing Power Plant Development Proposals: 

The seven states that we contacted--Alabama, Arizona, California, 
Georgia, Illinois, Nevada, and Texas--vary in the extent to which they 
consider the impacts that power plants will have on water when they 
review power plant water use proposals. Specifically, these states have 
differences in water laws that may influence their oversight of power 
plant water use. Some also have other regulatory policies and 
requirements specific to power plants and water use. Still other states 
require additional levels of review that may affect their states' 
oversight of how power plants use water. 

States We Contacted Have Differences in Water Laws that Influence Their 
Oversight of Water Use by Proposed Power Plants: 

Differences in water laws in the seven states we contacted--Alabama, 
Arizona, California, Georgia, Illinois, Nevada, and Texas--influence 
the steps that power plant developers need to take to obtain approval 
to use surface or groundwater, and provide for varying levels of 
regulatory oversight of power plant water use. Table 4 shows the 
differences in water laws and water permitting for the seven states we 
contacted. 

Table 4: State Water Laws and Permit Requirements for Water Supply in 
Seven Selected States: 

State: Alabama; 
Type of state water laws: Surface water: Riparian; 
Type of state water laws: Groundwater: Reasonable use; 
State water permit required: Surface water: No[A]; 
State water permit required: Groundwater: No[A]. 

State: Arizona; 
Type of state water laws: Surface water: Prior appropriation; 
Type of state water laws: Groundwater: Reasonable use[B]; 
State water permit required: Surface water: Yes; 
State water permit required: Groundwater: Yes[B]. 

State: California; 
Type of state water laws: Surface water: Riparian and prior 
appropriation; 
Type of state water laws: Groundwater: Reasonable use and prior 
appropriation; 
State water permit required: Surface water: Yes; 
State water permit required: Groundwater: No. 

State: Georgia; 
Type of state water laws: Surface water: Riparian; 
Type of state water laws: Groundwater: Reasonable use; 
State water permit required: Surface water: Yes[C]; 
State water permit required: Groundwater: Yes[C]. 

State: Illinois; 
Type of state water laws: Surface water: Other doctrine[D]; 
Type of state water laws: Groundwater: Reasonable use; 
State water permit required: Surface water: Yes[E]; 
State water permit required: Groundwater: No. 

State: Nevada; 
Type of state water laws: Surface water: Prior appropriation[F]; 
Type of state water laws: Groundwater: Prior appropriation[F]; 
State water permit required: Surface water: Yes; 
State water permit required: Groundwater: Yes. 

State: Texas; 
Type of state water laws: Surface water: Prior appropriation; 
Type of state water laws: Groundwater: Rule of capture; 
State water permit required: Surface water: Yes; 
State water permit required: Groundwater: No[G]. 

Source: GAO analysis of state laws, documents, and discussions with 
state officials. 

[A] Alabama issues a certificate of use upon registration to users with 
a capacity to withdraw 100,000 gallons of water per day or more. 

[B] Arizona issues state permits for groundwater in areas of severe 
water overdraft where water shortages could occur, known as Active 
Management Areas, established under Arizona law. Reasonable use would 
not apply in these areas. 

[C] Georgia issues water permits for users withdrawing more than 
100,000 gallons a day. 

[D] Illinois surface water law is based on various state statutes. 

[E] Illinois issues surface permits only for public water bodies, which 
excludes some surface water. 

[F] In Nevada, water appropriated from either surface or underground 
sources is limited to that which is reasonably required for beneficial 
use. 

[G] Water use permits can be required locally in Texas through 
Groundwater Conservation Districts. 

[End of table] 

With regard to surface water--the source of water most often used for 
power plant cooling nationally--of the seven states we contacted, all 
but Alabama required power plant developers to obtain water permits 
through the state agency that regulates the water supply. However, the 
states requiring permits varied in how the permits were obtained and 
under what circumstances. For example, in general, under Illinois law, 
water supply permits are only necessary if the surface water is defined 
as a public water body, which covers most major navigable lakes, 
rivers, streams, and waterways as defined by the Illinois Office of 
Water Resources. However, for any other surface water body, such as 
smaller rivers and streams, no such permit is required. To obtain a 
permit to use water in a power plant in Illinois, developers must file 
an application with the Illinois Office of Water Resources. In 
determining whether to issue a permit, the Office of Water Resources 
requires the applicant to address public comments and evaluates USGS 
streamflow data to determine whether restrictions on water use are 
needed. In some instances, such as to support fish and other wildlife, 
the state may designate a minimum level of flow required for a river or 
stream and restrict the amount of water that can be used by a power 
plant or other water user when that minimum level is reached. The 
Director of the Office of Water Resources told us that the office has 
sometimes encouraged power plant operators to establish backup water 
sources, such as onsite reservoirs, for use when minimum streamflow 
levels are reached and water use is restricted. In contrast, under 
Georgia and Alabama riparian law, landowners have the right to the 
water on and adjacent to their land, and both states require users who 
have the capacity to withdraw (Alabama) or actually withdraw (Georgia) 
an average of more than 100,000 gallons per day to provide information 
to the state concerning their usage and legal rights to the water. 
However, this requirement is applied differently in the two states. 
Alabama requires that water users register their planned water use for 
informational purposes with the Alabama Office of Water Resources but 
does not require users to obtain a permit for the water withdrawal or 
conduct analysis of the impact of the proposed water use.[Footnote 24] 
In contrast, Georgia requires water users to apply for and receive a 
water permit from the Georgia Environmental Protection Division. In 
determining whether to issue a permit for water use, this Georgia 
agency analyzes the potential effect of the water use on downstream 
users and others in the watershed. State water regulators in Georgia 
told us they have never denied an application for water use in a power 
plant due to water supply issues since there has historically been 
adequate available water in the state. For more details on Georgia's 
process for approving water use in power plants, see appendix IV. 

Groundwater laws in the selected states we reviewed also varied and 
affected the extent to which state regulators provided oversight over 
power plant water use. In four of the seven states--Alabama, 
California, Illinois, and Texas--groundwater is largely unregulated at 
the state level, and landowners may generally freely drill new wells 
and use groundwater as they wish unless restricted by local entities, 
such as groundwater conservation districts. However, in three of the 
seven states we contacted--Arizona, Georgia, and Nevada--state-issued 
water permits are required for water withdrawals for some or all 
regions of the state. For example, in Nevada, which has 256 separate 
groundwater basins, and in which most of the in-state power generation 
uses groundwater for cooling, state water law follows the doctrine of 
prior appropriation. A power plant developer or other entity wanting to 
acquire a new water right for groundwater must apply for a water permit 
with the Nevada Division of Water Resources. In evaluating the 
application for a water permit, the Division determines if water is 
available--referred to as unappropriated; whether the proposed use will 
conflict with existing water rights or domestic wells; and whether the 
use of the water is in the public interest. In determining whether 
groundwater is available, if the Division of Water Resources determines 
that the amount of water that replenishes the groundwater basin 
annually is greater than the existing committed ground water rights in 
a given basin, unappropriated water may be available for appropriation. 
[Footnote 25] In two cases where groundwater was being considered for 
possible power plants, the State Engineer, the official in the Division 
of Water Resources who approves permits, either denied the application 
or expressed reservations over the use of groundwater for cooling. 
[Footnote 26] For example, in one case, the State Engineer noted that 
large amounts of water should not be used in a dry state like Nevada 
when an alternative, like dry cooling, that is less water intensive was 
available. 

In contrast, in Texas, where 8 percent of in state electricity capacity 
uses groundwater for cooling, state regulators do not issue groundwater 
use permits or routinely review a power plant or other users' proposed 
use of the groundwater. Texas groundwater law is based on the "rule of 
capture," meaning landowners, including developers of power plants that 
own land, have the right to the water beneath their property. 
Landowners can pump any amount of water from their land, subject to 
certain restrictions, regardless of the effect on other wells located 
on adjacent or other property.[Footnote 27] Although Texas state water 
regulators do not issue water permits for the use of groundwater, in 
more than half the counties in Texas, groundwater is managed locally 
through groundwater conservation districts which are generally 
authorized by the Texas Legislature and ratified at the local level to 
protect groundwater. These districts can impose their own requirements 
on landowners to protect water resources. This includes requiring a 
water use permit and, in some districts, placing restrictions on the 
amount of water used or location of groundwater wells for landowners. 
[Footnote 28] 

States We Contacted Have Other Regulatory Policies That Influence the 
Extent of Water Use Oversight for Proposed Power Plants: 

Oversight of water use by proposed power plants in the selected states 
may be influenced by regulatory policies and requirements that formally 
emphasize minimizing freshwater use by power plants and other new 
industrial users. With respect to regulatory policies, of the 7 states, 
California and Arizona have established formal policies or requirements 
to encourage power plant developers to consider alternative cooling 
methods and reduce the amount of freshwater used in a proposed power 
plant. Specifically: 

* California, a state that has faced constrained water supplies for 
many years, established a formal policy in 1975 that requires 
applicants seeking to use water in power plants to consider alternative 
water sources before proposing the use of freshwater.[Footnote 29] More 
recently, the California Energy Commission, the state agency that is to 
review and approve power plant developer applications, reiterated in 
its 2003 Integrated Energy Policy Report, the 1975 policy that the 
commission would only approve power plants using freshwater for cooling 
in limited circumstances.[Footnote 30] Furthermore, state regulators at 
the Commission told us that in discussing potential new power plant 
developer applications, commission staff encourage power plant 
developers to consider using advanced cooling technologies, such as dry 
cooling or alternative water sources, such as effluent from sewage 
treatment plants. Between January 2004 and April 2009, California 
regulators approved 10 thermoelectric power plants--3 that will use dry 
cooling; 6 that will use an alternative water source, such as reclaimed 
water; and 2 that will use freshwater purchased from a water supplier, 
such as a municipal water district, for power plant cooling.[Footnote 
31] Of 20 additional thermoelectric power plant applications pending 
California Energy Commission approval, developers have proposed 11 
plants that plan to use dry cooling, 8 plants that plan to use an 
alternative water source, and 1 that plans to use freshwater for 
cooling.[Footnote 32] For more details on California's process for 
approving water use in power plants, see appendix III. 

* In Arizona, where there is limited available surface water and where 
groundwater is commonly used for power plant cooling, the state has 
requirements to minimize how much water may be used by power plants. 
Specifically, in Active Management Areas--areas the state has 
determined require regulatory oversight over the use of groundwater-- 
the state requires that developers of new power plants 25 megawatts or 
larger using groundwater in a wet recirculating system with a cooling 
tower, design the plants to reuse the cooling water to a greater extent 
than what is common in the industry. Plants must cycle water through 
the cooling loop at least 15 times before discharging it, whereas, 
according to an Arizona public utility official, outside of Active 
Management Areas plants would generally cycle water 3 to 7 times. 
[Footnote 33] These additional cycles result in water savings, since 
less water must be withdrawn from ground or surface water sources to 
replace discharges, but can require plant operators to undertake more 
costly and extensive treatment of the cooling water and to more 
carefully manage the plant cooling equipment to avoid mineral buildup. 
[Footnote 34] Arizona officials also told us they encourage the use of 
alternative water sources for cooling and have informally encouraged 
developers to consider dry cooling. According to Arizona state 
officials, no plants with dry cooling have been approved to date in the 
state and, due mostly to climatic conditions, dry cooling is probably 
too inefficient and costly to currently be a viable option. For details 
on Arizona's process for approving water use in power plants, see 
appendix II. 

In contrast to California and Arizona, water supply and public utility 
commission officials in the other 5 selected states told us their 
states had not developed official state policies regarding water use by 
power plants. For example, Alabama, a state where water has 
traditionally been plentiful, has not developed a specific policy 
related to power plant water use or required the use of advanced 
cooling technologies or alternative water sources. Additionally, the 
state does not require that power plant developers and other proposed 
water users seek a water use permit; rather power plant operators are 
only required to register their maximum and average expected water use 
with the state and report annual usage. State officials told us that 
they require this information so that they can know how much water is 
being used but that their review of power plant water use is limited. 
Officials from the state's Public Service Commission, responsible for 
certifying the development of power plants, said their office does not 
have authority to regulate a utility's water use and, therefore, 
generally does not analyze how a proposed power plant will affect the 
water supply. Rather, their office focuses on the reasonableness of 
power plant costs.[Footnote 35] 

Similarly, Illinois, where most power plants use surface water for 
cooling and water is relatively plentiful, has not developed a policy 
on water use by thermoelectric power plants or required the use of 
advanced cooling technologies or alternative water sources, according 
to an official at the Office of Water Resources. However, the Illinois 
Office of Water Resources does require power plant operators, like 
other proposed water users, to apply for water permits for use of 
surface water from the major public water bodies. 

States We Contacted May Require Additional Levels of Review That Affect 
Oversight: 

Three of the states we selected--Arizona, Nevada, and California-- 
conduct regulatory proceedings that consider water availability, in 
addition to determining whether to issue a water permit, while the 
other states do not. In Arizona, water use for power plants is subject 
to three reviews: (1) the process for a prospective water user to 
obtain a water permit, if required; (2) review by a committee of the 
Arizona Corporation Commission, known as the Arizona Power Plant and 
Transmission Line Siting Committee; and (3) review by the Commission as 
part of an overall evaluation of the plant's feasibility and its 
potential environmental and economic impacts. Both the Committee and 
Commission evaluate water supply concerns, along with other 
environmental issues, and determine whether to recommend (Committee) or 
issue (Commission) a Certificate of Environmental Compatibility, which 
is necessary for the plant to be approved.[Footnote 36] Water supply 
concerns have been a factor in denying such a certificate for a 
proposed power plant. For example, in 2001, the Commission denied an 
application to build a new plant over concerns that groundwater 
withdrawals for cooling water would not be naturally replenished and, 
thereby, would reduce surface water availability which could adversely 
affect the habitat for an endangered species. For more details on 
Arizona's processes for approving water use in power plants see 
appendix II. 

Similarly, in Nevada and California, several state agencies may play a 
role in the approval of water use and the type of cooling technology 
used by power plants. In Nevada, although water permits for groundwater 
and surface water are issued by the State Engineer, the Public 
Utilities Commission oversees final power plant approval under the 
Utility Environmental Protection Act. Even if the power plant developer 
has obtained a water permit, water use could play a role in the review 
process if the plant's use of the cooling water or technologies has 
environmental effects that need to be mitigated. Additionally, as in a 
number of states where electricity rates are regulated, the Public 
Utilities Commission could consider the effect of dry cooling on 
electricity rates. In California, the California Energy Commission 
reviews all aspects of power plant certifications, including issuing 
any water permits and approvals for cooling technologies.[Footnote 37] 
According to a California Energy Commission official, during this 
process the Commission works with other state and local agencies to 
ensure their requirements are met. 

The other four states we contacted do not conduct reviews of how power 
plants will affect water availability beyond issuing a water use permit 
or certificate of registration. Public utility regulators in Illinois, 
Texas, Alabama, and Georgia told us they had no direct role in 
regulating water use or cooling technologies in power plants. Officials 
from the Public Utility Commission of Texas noted that since they do 
not regulate electricity rates in most of the state, the Commission 
plays no role in the approval of power plants in most areas. In other 
areas, they told us water use and cooling technologies were not 
reviewed by the Commission. Similarly, in Illinois--a state that does 
not regulate electricity rates--an official from the Illinois Commerce 
Commission stated that the agency had no role in reviewing water use or 
cooling technologies for power plants. While Georgia and Alabama are 
states that regulate electricity rates, officials from their Public 
Service Commissions--the state agencies regulating electricity rates-- 
noted that they focus on economic considerations of power generation 
and not the impact that a power plant might have on the state's water 
supply. 

Some Federal Water Data Are Useful for Evaluating Power Plant 
Applications, but Limitations in Other Federal Data Make the 
Identification of Certain Water Use Trends More Difficult: 

State water regulators rely on data on water availability collected by 
USGS's streamflow gauges and groundwater studies and monitoring 
stations when they are evaluating developers' proposals for new power 
plants. In contrast, state water regulators do not routinely rely on 
federal data on water use when evaluating power plant applications, 
although these data are used by water and industry experts, federal 
agencies, and others to analyze trends in the industry. However, these 
users of federal data on water use identified a number of limitations 
with the data that they believe limits its usefulness. 

State Water Regulators and Others Rely on Federal Data on Water 
Availability to Evaluate Power Plant Proposals: 

State water regulators, federal agency officials, and water experts we 
spoke with agreed that federal data on water availability are important 
for multiple purposes, including for deciding whether to approve power 
plant developer proposals for water permits and water rights. Most 
state water regulators we contacted explained that they rely upon 
federal data on water availability, particularly streamflow and 
groundwater data collected by USGS, for permitting decisions and said 
these data helped promote more informed water planning. For example, 
water regulatory officials from the Texas Commission on Environmental 
Quality--the agency that evaluates surface water rights applications 
from prospective water users in Texas--told us that streamflow data 
collected by USGS are a primary data source for their water model that 
predicts how water use by power plants and others applying for water 
rights will impact state water supplies and existing rights holders. 

USGS's network of streamflow gauges and groundwater monitoring stations 
provide the only national data of their kind on water availability over 
long periods. As a result, state officials told us that these data are 
instrumental in predicting how much water is likely to be available in 
a river under a variety of weather conditions, such as droughts. For 
example, state regulators in Georgia and Illinois told us that they 
rely on USGS streamflow data to determine whether or not to establish 
special conditions on water withdrawal permits, such as minimum river 
flow requirements that affect the amount of cooling water a power plant 
can withdraw during periods when water levels in the river are low. 
State water regulators in Nevada also told us they rely on a number of 
data sources, including USGS groundwater studies, to determine the 
amount of time necessary for water to naturally refill a groundwater 
basin. This information helps them ensure that water withdrawals for 
power plants and others are sustainable and do not risk depleting a 
groundwater basin. 

State regulators told us that while federal water availability data is 
a key input into their decisionmaking process for power plant permits, 
they also rely on a number of other sources of data, as shown in table 
5. These include data that they themselves collect and data collected 
by universities; private industry, such as power plant developers; and 
various other water experts. 

Table 5: Water Data Considered in Support of State Water Regulators' 
Permitting Decisions: 

State: Alabama; 
USGS data on water availability: Groundwater: [A]; 
USGS data on water availability: Streamflow: [A]; 
State, industry, academic, or other data: [A]. 

State: Arizona; 
USGS data on water availability: Groundwater: [B]; 
USGS data on water availability: Streamflow: [B]; 
State, industry, academic, or other data: [B]. 

State: California; 
USGS data on water availability: Groundwater: [C]; 
USGS data on water availability: Streamflow: Yes; 
State, industry, academic, or other data: Yes. 

State: Georgia; 
USGS data on water availability: Groundwater: Yes; 
USGS data on water availability: Streamflow: Yes; 
State, industry, academic, or other data: Yes. 

State: Illinois; 
USGS data on water availability: Groundwater: [C]; 
USGS data on water availability: Streamflow: Yes; 
State, industry, academic, or other data: Yes. 

State: Nevada; 
USGS data on water availability: Groundwater: Yes; USGS data on water 
availability: Streamflow: Yes; [Empty]; State, industry, academic, or 
other data: Yes. 

State: Texas; 
USGS data on water availability: Groundwater: [C]; 
USGS data on water availability: Streamflow: Yes; 
State, industry, academic, or other data: Yes. 

Source: GAO analysis of information provided by state regulators. 

[A] Alabama officials told us they are not authorized to issue water 
withdrawal permits and, thus, do not rely on USGS water availability 
data for this purpose. However they rely on these data for a variety of 
other purposes. 

[B] Arizona officials told us that, in practice, they do not often rely 
on USGS streamflow data for permitting because surface water is fully 
allocated throughout the state. Similarly, groundwater availability 
data is not routinely relied upon for permits for groundwater rights in 
Active Management Areas, since most power plant developers purchase 
existing rights, rather than apply for a new right. Outside of Active 
Management Areas, water users only seek drilling permits, which 
requires limited review. However, surface and groundwater availability 
data may be relied on to support the Line Siting Committee and the 
Arizona Corporation Commission's decision to issue a Certificate of 
Environmental Compatibility. 

[C] These states do not issue permits for groundwater at the state 
level. However, in California, any groundwater use for a power plant 
would be permitted, if necessary, through the California Energy 
Commission, which regulates the licensing of power plants. 

[End of table] 

Some state regulators and water experts we spoke with expressed concern 
about streamflow gauges being discontinued, which they said may make 
evaluating trends in water availability and water planning more 
difficult in the future. Without accurate data on water availability, 
decisions about water planning and allocation of water resources-- 
including power plant permitting decisions--may be less informed, 
according to regulators and experts. For example, an official from 
Arizona told us that a reduction in streamflow gauges would adversely 
impact the quality of the states' water programs and that state budget 
constraints have made it increasingly difficult to allocate the 
necessary state funds to ensure cooperatively-funded streamflow gauges 
remain operational. Similarly, an official from the Texas Commission on 
Environmental Quality told us that if particular streamflow gauges were 
discontinued, water availability records would be unavailable to update 
existing data for their water availability models--which are relied 
upon for water planning and permitting decisions--and alternative data 
would be needed to replace these missing data. USGS officials told us 
that the cumulative number of streamflow gauges with 30 or more years 
of record that have been discontinued has increased, as seen in figure 
8, due to budget constraints. 

Figure 8: Cumulative Number of Discontinued U.S. Geological Survey 
Streamflow Gauges with 30 or More Years of Record, 1933-2007: 

[Refer to PDF for image: line graph] 

Year: 1933; 
Number of Discontinued Streamflow Gauges: 1. 

Year: 1938; 
Number of Discontinued Streamflow Gauges: 5. 

Year: 1943; 
Number of Discontinued Streamflow Gauges: 13. 

Year: 1948; 
Number of Discontinued Streamflow Gauges: 24. 

Year: 1953; 
Number of Discontinued Streamflow Gauges: 47. 

Year: 1958; 
Number of Discontinued Streamflow Gauges: 119. 

Year: 1963; 
Number of Discontinued Streamflow Gauges: 232. 

Year: 1968; 
Number of Discontinued Streamflow Gauges: 334. 

Year: 1973; 
Number of Discontinued Streamflow Gauges: 690. 

Year: 1978; 
Number of Discontinued Streamflow Gauges: 944. 

Year: 1983; 
Number of Discontinued Streamflow Gauges: 1,459. 

Year: 1988; 
Number of Discontinued Streamflow Gauges: 1,809. 

Year: 1993; 
Number of Discontinued Streamflow Gauges: 2,223. 

Year: 1998; 
Number of Discontinued Streamflow Gauges: 2,729. 

Year: 2003; 
Number of Discontinued Streamflow Gauges: 2,955. 

Year: 2007; 
Number of Discontinued Streamflow Gauges: 3,314. 

Source: U.S. Geological Survey. 

[End of figure] 

Water Experts, Federal Agencies, and Others Value Federal Data on Water 
Use for Analyzing Industry Trends but Identified Limitations In These 
Data: 

Unlike federal data on water availability, federal data on water use is 
not routinely relied upon by state officials we spoke with to make 
regulatory decisions; but, instead is used by a variety of data users 
to identify trends in the industry. Specifically, data users we spoke 
with, including water experts, representatives of an environmental 
group, and federal agency officials, identified the following benefits 
of the water use data collected by USGS and EIA: 

* USGS Data on Water Use. A number of users of federal water data we 
spoke with told us that USGS's 5-year data on thermoelectric power 
plant water use are the only centralized source of long-term, national 
data for comparing water use trends across sectors, including for 
thermoelectric power plants. As a result, they are valuable data for 
informing policymakers and the public about the state of water 
resources, including changes to water use among power plants and other 
sectors. For example, one utility representative we spoke with said 
that USGS data are important for educating the public about how power 
plants use water and the fact that while thermoelectric power plants 
withdraw large amounts of water overall--39 percent of U.S. freshwater 
withdrawals in 2000--their water consumption as an industry has been 
low--3 percent of U.S. freshwater consumption in 1995. Furthermore, 
some state water regulators told us that USGS's water use data allow 
them to compare their state's water use to that of other states and 
better evaluate and plan around their state's water conditions. 
[Footnote 38] An Arizona Department of Water Resources official, for 
example, told us that USGS's water use data are essential for 
understanding how water is used in certain parts of the state where the 
Department has no ability to collect such data.[Footnote 39] 

* EIA Data on Water Use. EIA's annual data are the only federally- 
collected, national data available on water use and cooling 
technologies at individual power plants; and data users noted that 
EIA's national data were useful for analyzing the water use 
characteristics of individual plants, as well as for comparing water 
use across different cooling technologies. For example, officials at 
USGS and the National Energy Technology Laboratory told us that they 
use EIA data to research trends in current and future thermoelectric 
power plant and other categories of water use. Specifically, USGS 
utilizes EIA's data on individual plant water use, in addition to data 
from state water regulators and individual power plants, to develop 
county and national estimates of thermoelectric power plant water use. 
USGS officials explained that in some of their state offices, such as 
California and Texas, agency staff primarily use EIA and other federal 
data to develop USGS's 5-year thermoelectric power plant water use 
estimates. Officials from USGS also explained that other USGS state 
offices use EIA data on water use to corroborate their estimates of 
thermoelectric power plant water withdrawals and to identify the 
cooling technology utilized by power plants. Similarly, officials at 
the National Energy Technology Laboratory have extensively used EIA's 
data on individual power plant water withdrawals and consumption to 
develop estimates of how freshwater use by thermoelectric power plants 
will change from 2005 to 2030. 

However, data users we spoke with also identified a number of 
shortcomings in the federal data on water use, collected by USGS and 
EIA, that limits their ability to conduct certain types of industry 
analyses and understanding of industry trends. Specifically, they 
identified the following issues, along with others that are detailed in 
appendix V. 

* Lack of comprehensive data on the use of advanced cooling 
technologies. Currently, EIA does not systematically collect 
information on power plants' use of advanced cooling technologies. In 
the EIA database, for example, data on power plants' use of advanced 
cooling technologies is incomplete and inconsistent--not all power 
plants report information on their use of advanced cooling technologies 
or do so in a consistent way. Lacking these national data, it is not 
possible without significant additional work to comprehensively 
identify how many power plants are using advanced cooling technologies, 
where they are located, and to what extent the use of these 
technologies has reduced the use of freshwater. According to a study by 
the Electric Power Research Institute, although the total number of dry 
cooled plants is still small relative to plants using traditional 
cooling systems, the use of advanced cooling technologies is becoming 
increasingly common.[Footnote 40] As these technologies become more 
prevalent, we believe that information about their adoption would help 
policymakers better understand the extent to which advanced cooling 
technologies have been successful in reducing freshwater use by power 
plants and identify those areas of the country where further adoption 
of these technologies could be encouraged. EIA officials told us they 
formally coordinate with a group of selected stakeholders every 3 years 
to determine what changes are needed to EIA data collection forms. They 
told us they have not previously collected data on advanced cooling 
technologies because EIA's stakeholder consultation process had not 
identified these as needed data. However, these officials acknowledged 
that EIA has not included USGS as a stakeholder during this 
consultation process and were unaware of USGS' extensive use of their 
data. In discussing these concerns, EIA officials also said that they 
did not expect that collecting this information would be too difficult 
and agreed that such data could benefit various environmental and 
efficiency analyses conducted by other federal agencies and water and 
industry experts. Furthermore, in discussing our preliminary findings, 
EIA officials also said they believed that EIA could collect these data 
during its triennial review process by, for example, adding a reporting 
code for these types of cooling systems. However, they noted that they 
would have to begin the process soon to incorporate it into their 
ongoing review. 

* Lack of comprehensive data on the use of alternative water sources. 
Our review of federal data sources indicates that they cannot be used 
to comprehensively identify plants using alternative water sources. EIA 
routinely reports data on individual plant water sources, but we found 
that these data do not always identify whether the source of water is 
an alternative source or not. Similarly, while the USGS data identify 
thermoelectric power plants using ground, surface, fresh, and saline 
water, they do not identify those using alternative water sources, such 
as reclaimed water. While a goal of USGS's water use program is to 
document trends in U.S. water use and provide information needed to 
understand the nation's water resources, USGS officials said budget 
constraints have limited the water use data the agency can provide, and 
has led to USGS discontinuing distribution of data on one alternative 
water source--reclaimed water. According to two studies we reviewed, 
use of some alternative water sources is becoming more common and, 
based on our discussions with regulators and power plant developers, 
there is much interest in this nonfreshwater option, particularly in 
areas where freshwater is constrained. As use of these alternative 
water sources becomes more prevalent, we believe that information about 
how many plants are using these resources and in what locations, could 
help policymakers better understand how the use of alternative water 
sources by power plants can replace freshwater use and help identify 
those areas of the country where such substitution could be further 
encouraged. 

* Incomplete water and cooling system data. Though part of EIA's 
mission is to provide data that promote public understanding of 
energy's interaction with the environment, EIA does not collect data on 
the water use and cooling systems of two significant components of the 
thermoelectric power plant sector. First, in 2002, EIA discontinued its 
reporting of water use and cooling technology information for nuclear 
plants. According to data users we spoke with, this is a significant 
limitation in the federal data on water use and makes it more difficult 
for them to monitor trends in the industry. For example, USGS officials 
said that the lack of these data make developing their estimates for 
thermoelectric power plant water use more difficult because they either 
have to use older data or call plants directly for this information, 
which is resource intensive. EIA officials told us they discontinued 
collection of data from nuclear plants due to priorities stemming from 
budget limitations.[Footnote 41] Second, EIA does not collect water use 
and cooling system data from operators of some combined cycle 
thermoelectric power plants. Combined cycle plants represented about 25 
percent of thermoelectric capacity in 2007, and constituted the 
majority of thermoelectric generating units built from 2000 to 2007. 
According to EIA officials, water use and cooling technology data are 
not collected from operators of combined cycle plants that are not 
equipped with duct burning technology--a technology that injects fuel 
into the exhaust stream from the combustion turbine to provide 
supplemental heat to the steam component of the plant. However, these 
plants use a cooling system and water, as do other combined cycle and 
thermoelectric power plants whose operators are required to report to 
the agency. As a result, data EIA currently collects on water use and 
cooling systems for thermoelectric power plants is incomplete. EIA 
officials acknowledged that not collecting these data results in an 
incomplete understanding of water use by these thermoelectric power 
plants; however, budget limitations have thus far precluded collection 
of such data. According to a senior EIA staff in the Electric Power 
Division, since speaking with GAO, the agency has begun exploring 
options for collecting these data as part of its current data review 
process. 

* Discontinued distribution of thermoelectric power plant water 
consumption data. One of the stated goals of USGS's water use program 
is to document trends in U.S. water use, but officials told us that a 
lack of funding has prompted the agency to discontinue distribution of 
data on water consumption for thermoelectric power plants and other 
water users.[Footnote 42] These USGS officials told us they would like 
to restart distribution of the data on water consumption by 
thermoelectric power plants and other water users if additional funding 
were made available, because such data can be used to determine the 
amount of water available for reuse by others. Similarly, some users of 
federal water data told us that not having USGS data on consumption 
limits their and the public's understanding of how power plant water 
consumption is changing over time, in comparison to other sectors. They 
said that the increased use of wet recirculating technologies, which 
directly consume more water but withdraw significantly less than once- 
through cooling systems, has changed thermoelectric power plant water 
use patterns.[Footnote 43] 

In a 2002 report, the National Research Council recommended that USGS's 
water use program be elevated from one of water use accounting to water 
science--research and analysis to improve understanding of how human 
behavior affects patterns of water use.[Footnote 44] Furthermore, the 
council's report concluded that statistical analysis of explanatory 
variables, like cooling system type or water law, is a promising 
technique for helping determine patterns in thermoelectric power plant 
water use. The report suggested these and other approaches could help 
USGS improve the quality of its water use estimates and the value of 
the water data it reports. USGS has proposed a national water 
assessment with the goal of, among other things, addressing some of the 
recommendations made by the National Research Council report. USGS 
officials also told us such an initiative would make addressing some of 
the limitations in USGS water use data identified by water experts and 
others possible, such as reporting data on water consumption and by 
hydrologic code. 

Conclusions: 

While much of the authority for regulating water use resides at the 
state level, the federal government plays an important role in 
collecting and distributing information about water availability and 
water use across the country that can help promote more effective 
management of water resources. However, the lack of collection and 
reporting of some key data related to power plant water use limits the 
ability of federal agencies and industry analysts to assess important 
trends in water use by power plants, compare them to other sectors, and 
identify the adoption of new technologies that can reduce freshwater 
use. Without this comprehensive information, policymakers have an 
incomplete picture of the impact that thermoelectric power plants will 
have on water resources in different regions of the country and will be 
less able to determine what additional activities they should encourage 
for water conservation in these areas. Moreover, although both EIA and 
USGS seek to provide timely and accurate information about the 
electricity sector's water use, they have not routinely coordinated 
their efforts in a consistent and formal way. As a result, key water 
data collected by EIA and used by USGS have been discontinued or 
omitted and important trends in the electricity sector have been 
overlooked. EIA's ongoing triennial review of the data it collects 
about power plants and the recent passage of the Secure Water Act, that 
authorizes funding for USGS to report data on water use to Congress, 
provide a timely opportunity to address gaps in federal data collection 
and reporting and improve coordination between USGS and EIA in a cost- 
effective way. 

Recommendations for Executive Action: 

We are making seven recommendations. Specifically, to improve the 
usefulness of the data collected by EIA and better inform the nation's 
understanding of power plant water use and how it affects water 
availability, we recommend that the Administrator of EIA consider 
taking the following four actions as part of its ongoing review of the 
data it collects about power plants: 

* add cooling technology reporting codes for alternative cooling 
technologies, such as dry and hybrid cooling, or take equivalent steps 
to ensure these cooling technologies can be identified in EIA's 
database; 

* expand reporting of water use and cooling technology data to include 
all significant types of thermoelectric power plants, particularly by 
reinstating data collection for nuclear plants and initiating 
collection of data for all combined cycle natural gas plants; 

* collect and report data on the use of alternative water sources, such 
as treated effluent and groundwater that is not suitable for drinking 
or irrigation, by individual power plants; and: 

* include USGS and other key users of power plant water use and cooling 
system data as part of EIA's triennial review process. 

To improve the usefulness of the data collected by USGS and better 
inform the nation's understanding of power plant water use and how it 
affects water availability, we recommend that the Secretary of the 
Interior consider: 

* expanding efforts to disseminate available data on the use of 
alternative water sources, such as treated effluent and groundwater 
that is not suitable for drinking or irrigation, by thermoelectric 
power plants, to the extent that this information becomes available 
from EIA; and: 

* reinstating collection and distribution of water consumption data at 
thermoelectric power plants. 

To improve the overall quality of data collected on water use from 
power plants, we recommend that EIA and USGS establish a process for 
regularly coordinating with each other, water and electricity industry 
experts, environmental groups, academics, and other federal agencies, 
to identify and implement steps to improve data collection and 
dissemination. 

Agency Comments and Our Evaluation: 

We provided a draft of this report to the Secretary of the Interior and 
to the Secretary of Energy for review and comment. 

The Department of the Interior, in a letter dated September 29, 2009, 
provided written comments from the Assistant Secretary for Water and 
Science. These comments are reprinted in appendix VI. In her letter, 
the Assistant Secretary agreed with GAO's recommendations and noted the 
importance of improving water use data, including data on water 
consumption at thermoelectric power plants. The letter noted that USGS 
plans to reinstate data collection on water consumption as future 
resources allow and will expand efforts to disseminate data on 
alternative water use as information becomes available from EIA. In 
addition, USGS plans to coordinate with EIA to establish a process to 
identify and implement steps to improve and expand water use data 
collection and dissemination by the two agencies. 

In response to our request for comments from the Department of Energy, 
we received emails from the audit liaisons at the National Energy 
Technology Laboratory and the EIA. The laboratory's comments note that 
the report accurately described the energy-water nexus as it relates to 
power plants and accurately documented the current state of power plant 
cooling technologies. These comments expressed the importance of 
completing a full assessment of the energy-water relationship in the 
future, especially in light of climate change regulations. The 
laboratory also provided technical comments, which we incorporated as 
appropriate. EIA provided technical comments, which we incorporated as 
appropriate. 

We are sending copies of this report to interested congressional 
committees; the Administrator of the Energy Information Administration; 
the Secretaries of Energy and the Interior; and other interested 
parties. In addition, the report will be available at no charge on the 
GAO Web site at [hyperlink, http://www.gao.gov]. 

If you or your staff have any questions about this report, please 
contact us at (202) 512-3841 or mittala@gao.gov or gaffiganm@gao.gov. 
Contact points for our Offices of Congressional Relations and Public 
Affairs may be found on the last page of this report. GAO staff who 
made major contributions to this report are listed in appendix VII. 

Sincerely yours, 

Signed by: 

Anu Mittal: 
Director, Natural Resources and Environment: 

Signed by: 

Mark Gaffigan:
Director, Natural Resources and Environment: 

[End of section] 

Appendix I: Objectives, Scope and Methodology: 

At the request of the Chairman of the House Committee on Science and 
Technology, we reviewed (1) technologies and other approaches that can 
help reduce freshwater use by power plants and what, if any, drawbacks 
there are to implementation; (2) the extent to which selected states 
consider water impacts of power plants when reviewing power plant 
development proposals; and (3) the usefulness of federal water data to 
experts and state regulators who evaluate power plant development 
proposals. We focused our evaluation on thermoelectric power plants, 
such as nuclear, coal, and natural gas plants using a steam cycle. We 
did not consider the water supply issues associated with hydroelectric 
power, since the process through which these plants use water is 
substantially different from that of thermoelectric plants (e.g., water 
is used as it passes through a dam but is not directly consumed in the 
process). We also focused the review on water used during the 
production of electricity at power plants, and did not include water 
issues associated with extracting fuels used to produce electricity. 

To understand technologies and other approaches that can help reduce 
freshwater use by power plants and their drawbacks, we reviewed 
industry, federal, and academic studies on advanced cooling 
technologies and alternative water sources that discussed their 
benefits, such as reduced freshwater use, and what, if any, drawbacks 
their implementation entails. These included studies with information 
on power plants' use of water and the drawbacks of nonfreshwater 
alternatives conducted by the Electric Power Research Institute, the 
Department of Energy's National Energy Technology Laboratory, and 
others. We discussed these trade-offs with various experts, including 
power plant and cooling system manufacturers, such as GEA Power Cooling 
Inc., General Electric, Siemens, and SPX Cooling Technologies; other 
industry groups and consultants, such as the Electric Power Research 
Institute, Maulbetsch Consulting, Nalco, and Tetra Tech; an engineering 
firm, Black & Veatch; and federal, national laboratory, and academic 
sources. To get a user perspective on these different technologies and 
alternative water sources, we met with power plant operators, including 
Arizona Public Service Company, Calpine, Georgia Power Company, and 
Sempra Generation. We also spoke with representatives from and reviewed 
reports prepared by other National Laboratories, such as the Department 
of Energy's Argonne National Laboratory, to understand related research 
activities concerning water and electricity. To better understand how 
the differences in cooling technologies and heat sources used by power 
plants affect power plant configuration and design, we toured three 
power plant facilities in Texas--Comanche Peak (nuclear, once-through 
cooling), Limestone (coal, wet recirculating with cooling towers), and 
Midlothian (natural gas combined cycle, dry cooling). 

To determine the extent to which selected states consider water impacts 
of power plants when reviewing power plant development proposals, we 
conducted case study reviews of three states: Arizona, California, and 
Georgia. These states were selected because of their historic 
differences in water availability, differences in water law, high 
energy production, and large population centers. We did not attempt to 
determine whether states' efforts were reasonable or effective, rather 
we only described what states do to consider water impacts when making 
power plant siting decisions. For each of these case study states, we 
met with state water regulators and power plant developers to 
understand how water planning and permitting decisions are approached 
from both a regulatory and private industry perspective. We also met 
with water research institutions and other subject matter experts to 
understand current and future research related to water impacts of 
power plants and the extent to which these research endeavors help 
inform power plant development proposals and regulatory water 
permitting decisions. Specifically, in California we met with the 
California Department of Water Resources; the California Energy 
Commission; the California State Water Resources Control Board; the San 
Francisco Bay Regional Water Quality Control Board; and the U.S. 
Geological Survey's (USGS) California Water Science Center. In Georgia 
we met with the Georgia Environmental Protection Division; the Georgia 
Public Service Commission; the Georgia Water Resources Institute; the 
Metropolitan North Georgia Water Planning District; the U.S. Army Corps 
of Engineers, South Atlantic Division; and the USGS Georgia Water 
Science Center. In Arizona we met with the Arizona Corporation 
Commission; the Arizona Department of Environmental Quality; the 
Arizona Department of Water Resources; the Arizona Power Plant and 
Transmission Line Siting Committee; the Arizona Office of Energy, 
Department of Commerce; the Arizona Water Institute, and the USGS 
Arizona Water Science Center. In addition, we reviewed state water laws 
and policies for thermoelectric power plant water use, selected power 
plant operator proposals to use water, and state water regulators' 
water permitting decisions. We also reviewed selected public utility 
commission dockets and testimonies describing various power plant 
siting decisions to understand what, if any, water issues were 
addressed. To broaden our understanding of how states consider the 
water impacts of power plants when reviewing power plant development 
proposals, we supplemented our case studies by conducting interviews 
and reviewing documents from four additional states: Nevada and 
Alabama--which shared watersheds with the case study states--and 
Illinois and Texas, which are large electricity producing states with 
sizable population centers. For each of these four states, we spoke 
with the primary state water regulatory agencies--the Alabama Office of 
Water Resources, the Illinois Office of Water Resources, the Nevada 
Division of Water Resources, and the Texas Commission on Environmental 
Quality--to understand how state water regulators consider the impacts 
of power plant operators' proposals to use water. In Texas, additional 
discussions were held with the Public Utility Commission of Texas; the 
Texas Water Development Board; the University of Texas; and the USGS 
Texas Water Science Center to further understand how water supply 
issues and energy demand are managed in Texas. In Alabama, we held 
additional discussions with officials from the Alabama Public Service 
Commission and the Alabama Department of Environmental Management to 
learn more about how Alabama's state water regulators and power plant 
operators manage water supply and energy demand. In Nevada, we held a 
discussion with an official from the Public Utilities Commission of 
Nevada to determine how they evaluate cooling technologies and water 
issues in plant siting certification proceedings. We also contacted the 
Illinois Commerce Commission. 

Finally, to determine how useful federal water data are to experts and 
state regulators who evaluate power plant development proposals, we 
reviewed data and analysis from the Energy Information Administration 
(EIA), USGS, and the Department of Energy's National Energy Technology 
Laboratory and analyzed how the data were being used. We also conducted 
interviews with federal agencies, including the Bureau of Reclamation; 
EIA; Environmental Protection Agency; Tennessee Valley Authority; U.S. 
Army Corps of Engineers; and USGS to understand whether each 
organization also collected water data and their opinions about the 
strengths and limitations of EIA and USGS data. We spoke with several 
regional offices for the Bureau of Reclamation, including the Lower 
Colorado and Mid-Pacific offices to understand federal water issues in 
California, Arizona, and Nevada. In addition, to understand how 
valuable federal water data are to experts and state regulators who 
evaluate power plant development proposals to use water, we conducted 
interviews and reviewed documents from state water regulators and 
public utility commissions, as well as water and electricity experts at 
environmental and water organizations, such as the Pacific Institute 
and Environmental Defense Fund; at universities such as the Georgia 
Institute of Technology; Southern Illinois University, Carbondale; and 
the University of Maryland, Baltimore County; and experts from 
industry, national laboratories, and other organizations and 
universities previously mentioned. We also contacted other electricity 
groups, including the North American Electric Reliability Corporation 
and the National Association of Regulatory Utility Commissioners, to 
get a broader understanding of how the electricity industry addresses 
water supply issues. 

We conducted this performance audit from October 2008 through October 
2009, in accordance with generally accepted government auditing 
standards. Those standards require that we plan and perform the audit 
to obtain sufficient, appropriate evidence to provide a reasonable 
basis for our findings and conclusions based on our audit objectives. 
We believe that the evidence obtained provides a reasonable basis for 
our findings and conclusions based on our audit objectives. 

[End of section] 

Appendix II: Review of Proposals to Use Water in New Power Plants in 
Arizona: 

Background: 

Arizona, with a population of 6.5 million, was the 16th most populous 
state in the country in 2008 and was one of the fastest growing states, 
growing at a rate of 2.3 percent from 2007 to 2008. Most of the land in 
Arizona is relatively dry, therefore, water for electricity production 
is limited. For 2007, Arizona accounted for 2.7 percent of U.S. net 
electricity generation, ranking it 13th, with most generation coming 
from coal (36 percent); natural gas (34 percent); nuclear (24 percent); 
and renewable sources, such as hydroelectric (6 percent), although the 
state has a strong interest in developing solar and other renewable 
sources. 

Arizona Water Law and Policy: 

Arizona relies on three water sources for electricity production: (1) 
surface water, including the Colorado River; (2) groundwater; and (3) 
effluent. Arizona water law varies depending on the source and the 
user's location, specifically: 

* Surface water. The use of surface water in Arizona is determined by 
the doctrine of prior appropriation. The Arizona Department of Water 
Resources issues permits to use surface water statewide, with the 
exception of water from the Colorado River.[Footnote 45] The federal 
government developed water storage and distribution via a series of 
canals to divert water from the Colorado River to southern Arizona, and 
the Bureau of Reclamation issues contracts for any new water 
entitlements related to Colorado River water, in consultation with the 
Arizona Department of Water Resources. 

* Groundwater. The use of groundwater depends on its location. Because 
some areas receive seasonal rain and snow, average annual precipitation 
can vary by location, from 3 to over 36 inches of moisture. The state 
established five regions where groundwater is most limited known as 
Active Management Areas. Permits to use groundwater in these five areas 
are coordinated through the Arizona Department of Water Resources, 
which provides several permitting options for power plants.[Footnote 
46] Outside Active Management Areas, the state subjects groundwater to 
little regulation or monitoring and generally only requires users to 
submit a well application to the Department of Water Resources. 

* Effluent. Effluent is owned by the entity that generates it until it 
is discharged into a surface water channel. The owner has the right to 
put effluent to beneficial use or convey it to another entity, such as 
a power plant, that will put it to beneficial use. However, once it is 
discharged from the pipe, generally into a surface water body, such as 
a river, it is considered abandoned and subject to laws governing 
surface water. 

Arizona has no overall statewide policy on the use of water in 
thermoelectric power plants. However, in Active Management Areas, the 
state requires developers of newer power plants with a generating 
capacity of 25 megawatts or larger to use groundwater in a wet 
recirculating system with a cooling tower and to cycle water through 
the cooling loop at least 15 times before discharging it.[Footnote 47] 
An official of an Arizona public utility noted that it was more common 
to cycle water 3 to 7 times outside of Active Management Areas. 

Certification and Water Permitting for New Power Plants: 

Before a power plant developer can begin constructing a power plant 
with a generating capacity of 100 megawatts or larger, it must go 
through a two-step certification process and a permitting process, as 
follows:[Footnote 48] 

* The first step of the certification process involves public hearings 
before the Arizona Power Plant and Transmission Line Siting Committee, 
made up of representatives from five state agencies and six additional 
members appointed by the Arizona Corporation Commission.[Footnote 49] 
Although the Line Siting Committee is not required to evaluate water 
use unless the plant will be located within an Active Management Area, 
it typically considers water rights, water availability for the life of 
the power plant, and the environmental effects of groundwater pumping 
around the plant. Committee members told us they often ask about the 
planned water sources and whether alternative water sources and cooling 
technologies are available. If the plant will be located within an 
Active Management Area, a representative of the Department of Water 
Resources serving on the Committee takes the lead in evaluating the 
plant's potential adverse impacts on the water source, including 
reviewing state data or U.S. Geological Survey (USGS) studies that 
document the status and health of the proposed water source. A 
representative from the Arizona Department of Environmental Quality 
serving on the Committee considers the plant's potential adverse 
effects on water quality. Based on this information, as well as the 
proposed plant's feasibility and its potential environmental and 
economic impacts, the Committee issues a recommended Certificate of 
Environmental Compatibility, if appropriate. 

* In the second step of the certification process, the Arizona 
Corporation Commission reviews the power plant developer's application 
to ensure there is a balance between the state's need for energy and 
the plant's cost and potential environmental impacts, including water 
quality, water supply, ecological, and wetlands impacts. The Commission 
can accept, deny, or modify the Certificate of Environmental 
Compatibility that was recommended by the Line Siting Committee and has 
denied some certificates. The Commission places the burden on the 
applicant to demonstrate that the proposed water supply is sustainable 
and how any water quality impacts will be mitigated. The Commission 
does not collect or review additional water data or conduct quality 
checks on the data provided by the power plant developers. 

* The permitting process applies to both water supply and water 
quality. With respect to water supply, when required, power plant 
developers who plan to use surface water in most areas of the state or 
groundwater in an Active Management Area must obtain a water use permit 
from the Department of Water Resources. When applying for a permit, 
power plant developers are required to provide information on the 
amount of water they will use, the source, points of diversion and 
release, and how the power they generate will be used. For groundwater 
in an Active Management Area, users are strictly limited to a total 
volume of water permitted for withdrawal and are subject to annual 
reporting and an analysis of the impact on other wells. According to an 
official at the Department of Water Resources, the Department has 
extensive data on available groundwater for each Active Management Area 
to assist in determining the effects of groundwater use. With respect 
to water quality, power plant developers must obtain permits which 
regulate water quality through the Department of Environmental Quality. 
Further, power plants discharging into federally-regulated waters also 
need a National Pollutant Discharge Elimination System permit that 
covers effluent limitations and sets discharge requirements. This 
program is intended to ensure that discharges to surface waters do not 
adversely affect the quality and beneficial uses of such water. 

Recent State Decisions about Power Plant Water Use: 

Between January 2004 and July 2009, Arizona has approved three new 
power plants, two of which are simple cycle natural gas plants that do 
not need water for cooling. The third plant is a concentrating solar 
thermal plant using a wet recirculating system with cooling towers. 
According to an official from the Arizona Department or Water 
Resources, once the plant begins operating, it will use 3,000 acre feet 
of water annually from groundwater and surface water, under contract 
from an Irrigation District. 

Between 1999 and 2002, a large number of applications for power plants 
in Arizona were filed, most of which were approved.[Footnote 50] 
However, at least one plant was denied a Certificate of Environmental 
Compatibility due to a water supply concern--the potential loss of 
habitat for an endangered species from possible groundwater depletion. 
Approved plants used a variety of water sources for cooling, including 
recycled wastewater, surface water through arrangements with the 
Central Arizona Project, and groundwater--both directly used or from 
conversion of agricultural land. No dry cooled power plants have been 
approved in Arizona, according to state officials. State officials told 
us dry cooling is too inefficient and costly, but that it may be 
considered in the future if water shortages become more acute. 

[End of section] 

Appendix III: Review of Proposals to Use Water in New Power Plants in 
California: 

Background: 

As of January 2009, California had the nation's largest population--an 
estimated 38.3 million people--and grew at a rate of 1.1 percent 
annually from 2008 to 2009. California has significant variations in 
water availability, with a long coastline; several large rivers, 
particularly in the north; mountainous areas that receive substantial 
snowfall; and arid regions, particularly the Mojave Desert in 
southeastern California. Statewide, California averages 21.4 inches of 
rain annually, but has suffered significant droughts for the past three 
years. For 2007, California accounted for 5.1 percent of U.S. net 
electricity generation, ranking it 4th nationally. California generates 
electricity primarily from natural gas (55 percent); nuclear (17 
percent); and renewable energy sources--primarily hydroelectric, wind, 
solar, and geothermal (25 percent). California imports 27 percent of 
its electricity from other states. 

California Water Law and Policy: 

California water law depends on whether the water is surface water or 
groundwater, specifically: 

* Surface water. The use of surface water is subject to both the 
riparian and appropriative rights doctrines. No permit is needed to act 
upon riparian surface water rights, which result from ownership of land 
bordering a water source, and are senior to most appropriative rights. 
Appropriative rights, on the other hand, must be acquired through the 
State Water Resources Control Board. Applicants for appropriative 
rights must show, among other things, that the water will be put to 
beneficial use. 

* Groundwater. The majority of California's groundwater is unregulated. 
[Footnote 51] Additionally, California does not have a comprehensive 
groundwater permit process in place, except for groundwater that flows 
through subterranean streams, which is permitted by the State Water 
Resources Control Board. 

California has several policies that directly and indirectly address 
how thermoelectric power plants can use water. Specifically: 

* California's State Water Resources Control Board, as the designated 
state water pollution control agency and issuer of surface water 
rights, established a policy in 1975 that states that the use of fresh 
inland waters for power plant cooling will only be approved when it is 
demonstrated that the use of other water supply sources or other 
methods of cooling would be environmentally undesirable or economically 
unsound. Freshwater should be considered the last resort for power 
plant cooling in California. Since that time, according to officials we 
spoke with, the Board has encouraged the use of alternative sources of 
cooling water and alternative cooling technologies. 

* The California Energy Commission (CEC), the state's principal energy 
policy and planning organization, in 2003, reiterated the 1975 policy 
and further required developers to consider whether zero-liquid 
discharge technologies should be used to reduce water use unless it can 
be shown that the use of these technologies would be environmentally 
undesirable or economically unsound. Under these policies, dry cooling 
and use of alternative water for cooling would be the preferred 
alternatives. 

* The State Water Resources Control Board discourages the use of once- 
through cooling in power plants due to potential harm to aquatic 
organisms. The agency is considering a state policy to require power 
plants using this technology to begin using other cooling technologies 
or retire from service. 

Certification and Water Permitting for New Power Plants: 

California has a centralized permitting process for new large power 
plants, including thermoelectric power plants. Developers constructing 
new power plants with a generating capacity of 50 megawatts or larger 
must apply for certification with the CEC, the lead state agency for 
ensuring proposed plants meet requirements of the California 
Environmental Quality Act and generally overseeing the siting of new 
power plants.[Footnote 52] The CEC coordinates review of other state 
environmental agencies, such as the State Water Resources Control Board 
and issues all required state permits (air permits, water permits, 
etc.). Prior to issuing the permits needed to construct a new power 
plant, the CEC conducts an independent assessment, with public 
participation, of each proposed plant's environmental impacts; public 
health and safety impacts; and compliance with federal, state, and 
local laws, ordinances, and regulations. As part of its review, CEC 
staff analyze the effect on other water users of power plant 
developers' proposed use of water for cooling and other purposes, 
access to needed water supplies throughout the life of the plant, and 
the plant's impact on the proposed water source and the state's water 
supply overall.[Footnote 53] The CEC also ensures power plant 
developers have obtained the required water supply agreements; analyzed 
the feasibility of alternative water sources and cooling technologies; 
and addressed water supply, water quality, and wastewater disposal 
impacts. The CEC may require implementation of various measures to 
mitigate the impacts of water use, if it identifies problems. The CEC's 
goal is to complete the entire certification process in 12 months, but 
public objections, incomplete application submittals, staff shortages, 
and limited budgets sometimes delay the process. 

The CEC evaluates several sources of water data before certifying plant 
applicants' water use. These include: 

* the developer's proposals; 

* data from the Department of Water Resources' groundwater database on 
water availability and water quality; 

* U.S. Geological Survey data on water availability through its 
streamflow and groundwater monitoring programs and any specific basin 
studies; 

* the State Water Resources Control Board's information on surface and 
groundwater quality; and: 

* computer groundwater models that analyze the long-term yield of the 
basin. 

With respect to water quality, the CEC coordinates the issuance of 
permits relating to water quality for new power plants, but the State 
Water Resources Control Board sets overall state policy. The Board 
operates under authority delegated to it by the U.S. Environmental 
Protection Agency to implement certain federal laws, including the 
Clean Water Act, as well as authority provided under state laws 
designed to protect water quality and ensure that the state's water is 
put to beneficial uses. Nine Regional Water Boards are delegated 
responsibility for implementing the statewide water quality control 
plans and policies, including setting discharge requirements for 
permits for the National Pollutant Discharge Elimination System Program 
and issuing the permits. 

Recent State Decisions and Current Proposals about Power Plant Water 
Use: 

Since 2004, most power plants the CEC has approved or is currently 
reviewing plan to use dry cooling or a wet recirculating system that 
uses an alternative water source, as shown in table 6. According to a 
state official we spoke with, no plants approved to be built in the 
last 25 years have used once-through cooling technology. Over the last 
7 years, the CEC has also commissioned, or been involved in, 
substantial research into the use and possible effects of using 
alternative cooling technologies. 

Table 6: Power Plants Implemented, Approved or Planned Since January 1, 
2004, by Cooling Type: 

Category[A]: Operational Plant[B,C,D,G]; 
Number of plants: 7; 
Dry cooled: 0; 
Wet recirculating cooling system: Freshwater: 3; 
Wet recirculating cooling system: Reclaimed water: 4; 
Wet recirculating cooling system: Impaired groundwater: 1. 

Category[A]: Approved by the CEC but not yet operational[C,E,G]; 
Number of plants: 10; 
Dry cooled: 3; 
Wet recirculating cooling system: Freshwater: 2; 
Wet recirculating cooling system: Reclaimed water: 4; 
Wet recirculating cooling system: Impaired groundwater: 2. 

Category[A]: Currently under CEC review[F]; 
Number of plants: 20; 
Dry cooled: 11; 
Wet recirculating cooling system: Freshwater: 1; 
Wet recirculating cooling system: Reclaimed water: 7; 
Wet recirculating cooling system: Impaired groundwater: 1. 

Category[A]: Total[D,E,G]; 
Number of plants: 37; 
Dry cooled: 14; 
Wet recirculating cooling system: Freshwater: 6; 
Wet recirculating cooling system: Reclaimed water: 15; 
Wet recirculating cooling system: Impaired groundwater: 4. 

Source: GAO analysis of data from the California Energy Commission for 
plants sited, approved, or currently under review between January 1, 
2004, and April 30, 2009. 

[A] Excludes simple cycle gas plants with no steam cycle. 

[B] Plants that started operating after 1/1/2004. These plants may have 
been approved by the CEC earlier. 

[C] Includes one geothermal plant. 

[D] One plant uses both recycled and impaired groundwater. 

[E] Includes one hybrid plant that combines dry and wet cooling. 

[F] Includes 7 solar thermal plants. 

[G] Totals do not equal due to several plants using multiple water or 
cooling sources. See notes D and E. 

[End of table] 

[End of section] 

Appendix IV: Review of Proposals to Use Water in New Power Plants in 
Georgia: 

Background: 

In 2008, Georgia ranked 9th in population among states, with 9.7 
million people, and had the 4th fastest growing population in the U.S. 
between the years 2000 and 2007. Georgia is historically water rich, 
receiving approximately 51 inches of precipitation annually, but recent 
droughts and growing population have prompted additional focus on water 
supply and management strategies. Georgia ranked 8th in total net 
electricity generation in 2007, accounting for approximately 3.5 
percent of net electricity generation in the United States. Coal and 
nuclear power are the primary fuel sources for electricity in Georgia, 
with coal-fired power plants providing more than 60 percent of 
electricity output. 

Georgia Water Law and Policy: 

Georgia is a regulated riparian state, meaning that the owners of land 
adjacent to a water body can choose when, where, and how to use the 
water. The use must be considered reasonable relative to a competing 
user, with the courts responsible for resolving disputes about 
reasonable use. Since the late 1970s, Georgia law has required any 
water user who withdraws more than an average of 100,000 gallons per 
day to obtain a withdrawal permit from the Georgia Environmental 
Protection Division.[Footnote 54] 

Georgia does not have a policy or guidance specifically addressing 
thermoelectric power plants' water use. However, in response to recent 
droughts and population growth, the state adopted its first statewide 
water management plan in 2008. State water regulators we spoke with 
said they expect the new state water plan to consider how future power 
generation siting decisions align with state water supplies. 

Certification and Water Permitting for New Power Plants: 

Before power plant developers can begin construction, they may be 
required to obtain certification from the Georgia Public Service 
Commission and relevant permits from offices such as the Georgia 
Environmental Protection Division, as follows: 

* Georgia Public Service Commission. Georgia Power Company, the state's 
investor-owned utility, is fully regulated by the Public Service 
Commission and must obtain a certificate of public convenience and 
necessity prior to constructing new power plants. Other power plant 
developers, including municipality-and cooperatively-owned power plants 
and others, are not subject to certification. Public Service Commission 
officials explained that during the certification process, they balance 
the need for the new plant and its costs, but they do not consider the 
impact a plant will have on Georgia's water supply. However, these 
officials explained that, in their capacity to ensure utilities charge 
just and reasonable rates, they could consider the economic impact of 
using an alternative water source or advanced cooling technology, 
should a plant propose to use one. 

* Georgia Environmental Protection Division. Any entity seeking to use 
more than 100,000 gallons of water per day, including power plant 
developers, must obtain a permit from the Georgia Environmental 
Protection Division. The Division analyzes the proposed quantity of 
withdrawals and the water source and determines whether the withdrawal 
amounts and potential effects for downstream water users are 
acceptable. In some instances, the Division may place special 
conditions on power plants to ensure adequate water availability, such 
as requiring on-site reservoirs or groundwater withdrawals for water 
use during droughts. In making their decisions, the Georgia 
Environmental Protection Division reviews the plant's application and 
hydrologic data from a number of sources. Water withdrawal applications 
include many factors, in addition to withdrawal amounts and sources, 
such as water conservation and drought contingency plans; documentation 
of growth in water demand, location, and purpose of water withdrawn or 
diverted; and annual consumption estimates. Other data sources include 
their own and U.S. Geological Survey (USGS) groundwater data, USGS 
streamflow data, and existing water use permits. In some instances, the 
Environmental Protection Division may also use water withdrawal and 
water quality data collected by the U.S. Army Corps of Engineers if an 
applicant is downstream of federally-regulated waters. In addition to 
permitting water use, the Division is also responsible for issuing and 
enforcing all state permits involving water quality impacts. It is 
authorized by the Environmental Protection Agency to issue National 
Pollutant Discharge Elimination System permits that address discharge 
limits and reporting requirements. 

Recent State Decisions about Power Plant Water Use: 

According to Division officials, the Division has never denied a water 
withdrawal permit to a power plant developer on the basis of 
insufficient water, which they attributed partly to the fact that the 
staff meets with applicants numerous times before they submit the 
application to identify and mitigate concerns about water availability. 
Moreover, they told us that thermoelectric power plant developers have 
submitted few applications for water withdrawal permits. For example, 
as shown in table 7, between January 1, 2004, and December 31, 2008, 
the Division received only 6 water withdrawal applications from 
thermoelectric power plant developers; of these, it approved 5. An 
official from the Public Service Commission was unaware of any 
regulated power plant developers proposing the use of advanced cooling 
technologies, such as dry cooling or hybrid cooling, over this time 
period. 

Table 7: Thermoelectric Power Plant Applications for Water Withdrawal 
Permits in Georgia Between January 2004 and December 2008: 

Category: Applied; 
Number of Plants: 6; 
Once-through: 0; 
Recirculating: Groundwater (Freshwater): 4; 
Recirculating: Surface water (Freshwater): 2; 
Recirculating: Reclaimed water: 1. 

Category: Permitted[A]; 
Number of Plants: 5; 
Once-through: 0; 
Recirculating: Groundwater (Freshwater): 3; 
Recirculating: Surface water (Freshwater): 1; 
Recirculating: Reclaimed water: 1. 

Source: GAO analysis of data provided by the Georgia Environmental 
Protection Division. 

Note: Totals do not equal due to one power plant developer submitting 
both a groundwater and surface water withdrawal application. 

[A] As of August 12, 2009, one plant's application is still pending a 
decision by the Georgia Environmental Protection Division. 

Georgia Environmental Protection Division officials told us they do not 
advocate or refuse the use of particular cooling technologies. However, 
officials said they do not expect to receive applications for once- 
through cooling plants because federal environmental regulations make 
the permitting process difficult. 

[End of table] 

[End of section] 

Appendix V: Limitations to Federal Water Use Data Identified by Those 
GAO Contacted: 

Data source: EIA; 
Limitation: Advanced cooling technologies: Data users cannot 
comprehensively identify plants making use of advanced cooling 
technologies, such as dry and hybrid cooling; 
Cause: EIA forms are not designed to collect information on advanced 
cooling technologies; 
Effect: Understanding of trends in the adoption of advanced cooling 
technologies cannot be systematically determined using only EIA data. 

Data source: EIA; 
Limitation: Cooling system codes: Codes used to classify plant cooling 
systems may be incomplete, lack explanation, overlap, or contain 
errors; 
Cause: Cooling system codes are not defined in detail and plants may be 
uncertain about what cooling system code to use; 
Effect: Inconsistent use of cooling tower codes could potentially make 
EIA data less valuable and lead to inaccurate or inconsistent data and 
analysis. 

Data source: EIA; Limitation: Nuclear water data: Water use data 
(withdrawal, consumption and discharge) and cooling information were 
discontinued for nuclear plants in 2002; 
Cause: EIA discontinued reporting nuclear water use data and cooling 
system information due to priorities stemming from budget limitations; 
Effect: Data users must use noncurrent data or seek out an alternate 
source. If this limitation persists, water data will not be available 
for any new nuclear plants constructed. 

Data source: EIA and USGS; 
Limitation: Alternative water sources: It is not possible to 
comprehensively identify power plants using alternative water sources; 
Cause: EIA forms are not designed to collect information on alternative 
water sources. According to USGS, budget constraints have limited the 
amount of water use information the agency can provide; 
Effect: Understanding trends in power plant adoption of alternative 
water sources is limited. 

Data source: EIA and USGS; 
Limitation: Frequency: EIA reports data on annual water use, rather 
than data on water use over shorter time periods, such as monthly. USGS 
reports 5-year data; 
Cause: EIA's form 767, used to collect cooling system and water data, 
was developed and revised in the 1980s, and EIA officials we spoke with 
were not aware of why an annual time period was originally chosen. 
According to USGS, budget constraints have limited the amount of water 
use information the agency can provide; 
Effect: Seasonal trends in water use by power plants are not evident 
from annual EIA or 5-year USGS data. 

Data source: EIA and USGS; 
Limitation: Quality: Reporting of some EIA data elements may be 
inaccurate or inconsistent. USGS data are compiled from many different 
data sources, and the accuracy and methodology of these sources may 
vary. Furthermore, USGS state offices have different methods for 
developing water use estimates, potentially contributing to data 
inconsistency; 
Cause: Respondents may use different methods to measure or estimate 
data and instructions may be limited or unclear. Respondents may make 
mistakes or have nontechnical staff fill out surveys, since EIA's form 
for collecting this data does not require technical staff to complete 
the survey. According to USGS, budget constraints in its water use 
program kept the agency from implementing improvements it would like to 
make to its quality control of water use data; 
Effect: Inaccurate and inconsistent data are more challenging to 
analyze and less relevant for policymakers, water experts and the 
public seeking to understand water use patterns. 

Data source: USGS; 
Limitation: Consumption: USGS discontinued reporting of thermoelectric 
power plant and other water consumption data; 
Cause: According to USGS, budget constraints have caused the agency to 
make cuts in data reporting; 
Effect: Understanding of trends in power plant water consumption 
compared to other industries is limited. Analysis to compare 
thermoelectric power plant withdrawals to consumption is more 
complicated. 

Data source: USGS; 
Limitation: Hydrologic code: USGS discontinued reporting thermoelectric 
power plant and other water use by hydrologic code. It now only reports 
data by county; 
Cause: According to USGS, budget constraints have caused the agency to 
make cuts in data reporting; 
Effect: According to some data users, not having data by hydrologic 
code complicates water analysis, which is often performed by watershed 
rather than county. 

Data source: USGS; 
Limitation: Timeliness: Data are reported many years late. For example, 
data on 2005 water use have not yet been made available to the public; 
Cause: According to USGS, budget constraints have led to limited staff 
availability for water use data collection and analysis, resulting in 
reporting delays; 
Effect: Data are outdated and may be less relevant for analysis. 

Source: GAO analysis of comments gathered during interviews with water 
and electricity experts, environmental groups, and federal agencies. 

[End of table] 

[End of section] 

Appendix VI: Comments from the Department of the Interior: 

United States Department of the Interior: 
Office Of The Secretary: 
Washington, D.C. 20240: 

September 29 2009: 

Ms. Anu Mittal: 
Director, Natural Resources and Environment: 
U.S. Government Accountability Office: 
441 G Street, N.W. 
Washington, D.C. 20548: 

Dear Ms. Mittal: 

Thank you for providing the Department of the Interior (DOI) the 
opportunity to review and comment on the draft Government 
Accountability Office (GAO) Report entitled, "Electricity And Water: 
Improvements to Federal Water Use Data Would Increase Understanding of 
Trends in Power Plant Water Use" (GAO-09-912). 

The DOI agrees with the recommendations made by the GAO. The USGS works 
in cooperation with local, State, and Federal agencies to compile and 
disseminate data on the Nation's water use. Enhancement of water-use 
information is a key element of the Subtitle F-Secure Water of the 
Omnibus Public Lands Management Act of 2009 (P.L. 111-11) and is a high 
priority component of the Water Census of the United States, one of six 
strategic science directions for the USGS. As information becomes 
available from the Energy Information Administration (EIA), the USGS 
will expand efforts to disseminate data on the use of alternative water 
sources by thermoelectric power plants. The USGS views water 
consumption data at thermoelectric plants as an important component of 
the Water Census and will reinstate its collection as future resources 
allow. The USGS will coordinate with EIA to establish a process to 
identify and implement steps to improve water-use data collection and 
dissemination by the two agencies. 

We hope these comments will assist you in preparing the final report. 
If you have any questions, or need additional information, please 
contact Dr. Matt Larsen (703) 648-5215 or Mr. William Cunningham at 
(703) 648-5005. 

Sincerely, 

Signed by: 

Anne J. Castle: 
Assistant Secretary for Water and Science: 

[End of section] 

Appendix VII: GAO Contacts and Staff Acknowledgments: 

GAO Contacts: 

Anu Mittal, (202) 512-3841, Mittala@gao.gov Mark Gaffigan, (202) 512- 
3841, Gaffiganm@gao.gov: 

Staff Acknowledgments: 

In addition to the individuals named above, Jon Ludwigson (Assistant 
Director), Scott Clayton, Philip Farah, Paige Gilbreath, Randy Jones, 
Alison O'Neill, Timothy Persons, Kim Raheb, Barbara Timmerman, Walter 
Vance, and Jimi Yerokun made key contributions to this report. 

[End of section] 

Footnotes: 

[1] The Environmental Protection Agency announced in a September 15, 
2009, press release its plans to revise existing standards for water 
discharges from coal-fired power plants. 

[2] Pub. L. No. 111-11, § 9508 (2009). 

[3] S. 531, 111th Cong. § 2 (2009). 

[4] H.R. 3598, 111th Cong. (2009). 

[5] We provided preliminary information from our work on two of these 
reports--biofuels and water use and thermoelectric power plants and 
water use--in a testimony before the Subcommittee on Energy and 
Environment in July 2009. GAO, Energy and Water: Preliminary 
Observations on the Links between Water and Biofuels and Electricity 
Production. (Washington, D.C.: July 9, 2009). [hyperlink, 
http://www.gao.gov/products/GAO-09-862T]. 

[6] Studies we reviewed indicated a range of temperature increases for 
water discharged from once-through cooling systems. EPA officials we 
spoke with told us that once-through cooling plants often discharge 
cooling water between 10 and 20 degrees Fahrenheit warmer than it was 
when it was withdrawn, but they explained that there are examples of 
plants above and below this range, as well. 

[7] Another method of dry cooling, referred to as indirect dry cooling, 
uses a closed-loop of cooling water to condense the steam exiting the 
turbine--similar to recirculating systems. However, instead of 
dissipating the cooling water's heat through evaporation, a dry cooling 
tower is used to transfer the heat from the cooling water to the 
ambient air. 

[8] Some experts we spoke with and documents we reviewed described two 
other types of hybrid cooling technology designs. One version is 
designed to minimize plumes released from wet recirculating systems 
with cooling towers; although, according to one expert, this version 
has very little effect on the plant's water consumption. The other 
consists of various system configurations designed to improve the 
efficiency of dry cooling by either spraying water on the air-cooled 
condenser directly or using water to lower the temperature of inlet air 
entering the air-cooled condenser. 

[9] Department of Energy, National Energy Technology Laboratory, 
Estimating Freshwater Needs to Meet Future Thermoelectric Generation 
Requirements. 2008. This report did not include statistics regarding 
the use of hybrid systems. 

[10] Electric Power Research Institute, Water Use for Electric Power 
Generation, (Palo Alto, CA, 2008). 1014026. 

[11] Argonne National Laboratory, Use of Reclaimed Water for Power 
Plant Cooling, (Argonne, IL., 2007). 

[12] Energy is also needed in wet recirculating systems with fan-forced 
cooling towers, as well as to operate water pumps in both once-through 
and wet recirculating systems with cooling towers. Wet recirculating 
systems with cooling towers can also be constructed with a type of 
cooling tower that relies on a chimney effect, rather than fans, to 
naturally produce airflow. These natural draft cooling towers are large 
concrete structures that are significantly more expensive to build than 
cooling towers with fans, although they would eliminate the energy 
costs associated with fan operation. 

[13] Environmental Protection Agency, Technical Development Document 
for the Final Regulations Addressing Cooling Water Intake Structures 
for New Facilities, (Washington, D.C., Nov. 2001). These figures were 
higher for a full steam fossil fueled plant, such as a coal plant. 
Representatives from EPA explained that energy penalty and cost 
comparisons between dry cooled systems and wet recirculating systems 
with cooling towers may have changed since EPA's 2001 report was 
issued. The agency is in the process of updating its estimates of 
energy penalties and cooling system costs. 

[14] Burns, John M. and Wayne Micheletti, Emerging Issues and Needs in 
Power Plant Cooling Systems. (Presented at DOE's Workshop on Electric 
Utilities and Water: Emerging Issues and Needs, Pittsburgh, PA, July 23-
24, 2002). 

[15] Plants with once-through systems and wet recirculating systems 
with cooling towers also face efficiency losses as water and wet-bulb 
temperatures rise. As noted, dry cooled plants tend to be less 
efficient than plants with both of these wet cooling systems, but the 
efficiency of dry cooled plants will approach that of wet cooled plants 
at certain times of the year and in certain climatic conditions. For 
example, according to experts we spoke with, there will be a smaller 
difference in efficiency between a plant with a wet recirculating 
system with cooling towers and a dry cooled plant in cool, humid 
climates. 

[16] We include examples from these studies to provide context about 
the magnitude of estimated energy penalties. We have not validated the 
methodology or results of these studies. Estimates are subject to study 
assumptions and methodology, and actual energy penalties depend highly 
on plant design, location, and decisions made by plant developers about 
how to optimize total plant costs. 

[17] Environmental Protection Agency, Technical Development Document 
for the Final Regulations Addressing Cooling Water Intake Structures 
for New Facilities, (Washington, D.C., Nov. 2001). EPA estimated energy 
penalties at peak summer conditions when plants operate at 100 percent 
capacity to be higher. For example, the study estimates national 
average energy penalties at peak summer conditions (100 percent 
capacity) to result in 2.4 percent lower output for combined cycle 
plants with dry cooling systems compared to those with wet recirculated 
systems with a cooling tower. EPA estimated national average energy 
penalties at peak summer conditions (100 percent capacity) to result in 
8.4 percent lower output for full steam fossil fueled plants, such as 
coal plants, with dry cooling systems, compared to those with wet 
recirculated systems with a cooling tower. Representatives from EPA 
explained that energy penalty and cost comparisons between dry cooled 
systems and wet recirculating systems with cooling towers may have 
changed since EPA's 2001 report was issued. The agency is in the 
process of updating its estimates of energy penalties and cooling 
system costs. 

[18] Department of Energy, Office of Fossil Energy, National Energy 
Technology Laboratory and Argonne National Laboratory, Energy Penalty 
Analysis of Possible Cooling Water Intake Structure Requirements on 
Existing Coal-Fired Power Plants. (2002). These estimates refer to a 
dry cooling tower with a 20 degree Fahrenheit approach, the difference 
between the air temperature and the temperature of cold water 
discharged from the condenser. Energy penalty estimates for a dry tower 
with a 40 degree Fahrenheit approach were higher. The 1 percent hottest 
day estimate is for plants with a range of 15 degrees Fahrenheit, where 
the range refers to the difference between the temperature of the water 
entering and leaving the condenser. This study focused on existing 
plants retrofitted with indirect dry cooled systems, which are 
considered less efficient than direct dry systems. Experts we spoke 
with told us energy penalties are higher in retrofitted plants than 
when a dry cooled system is designed according to the unique 
specifications of a newly built plant because indirect dry cooling 
systems are more likely to be used; plant components, like the turbine, 
have not been designed to work most effectively with a dry cooled 
system; and because of size constraints placed on the dry cooled 
system. 

[19] Hot day performance is estimated to be the 1 percent highest dry 
bulb temperature and the corresponding wet bulb temperature for that 
condition. 

[20] We include examples of cost estimates from selected studies and 
expert interviews in this section to provide context about the 
magnitude of estimated capital and operating costs of dry cooling 
systems compared to wet cooling systems. We have not validated the 
methodology or results of these estimates. Estimates are subject to 
each study's assumptions and methodology, and actual costs depend 
highly on plant design, locational factors such as water costs, and 
decisions made by plant developers about how to optimize total costs. 
Furthermore, it should be noted that cooling system costs are but one 
component of total plant costs. 

[21] Electric Power Research Institute, Comparison of Alternate Cooling 
Technologies for U.S. Power Plants. Economic, Environmental, and Other 
Trade-offs, (Palo Alto, CA., 2004). 1005358. Similarly, capital costs 
for a dry cooled system on theoretical 350 megawatt coal plants ranged 
between $43 and $47 million for 5 climatic locations--3.2 to 3.6 times 
that of a wet recirculating system with cooling tower. 

[22] Electric Power Research Institute, Comparison of Alternate Cooling 
Technologies for U.S. Power Plants. Economic, Environmental, and Other 
Trade-offs, (Palo Alto, CA., 2004). 1005358. 

[23] Electric Power Research Institute, Water Use for Electric Power 
Generation. 

[24] These users are issued a Certificate of Use, indicating the use 
has been registered with the State of Alabama. All Certificate of Use 
holders are required to annually report their water usage to the 
Alabama Office of Water Resources. 

[25] If a prospective water user is unable to acquire a new water 
right, he or she may choose to purchase or lease an existing water 
right. 

[26] In the two cases we identified, an official from the Public 
Utilities Commission of Nevada told us the power plants in question 
were never built. He also noted that as many as six power plants have 
been sited in Nevada with dry cooling due to lack of available water. 

[27] Examples of restrictions include 1) to not maliciously injure a 
neighbor, 2) to not willfully waste water, 3) to not drill a well 
slanting under a neighbor's property or 4) to assume liability for 
damages for negligent pumping that causes subsidence of a neighboring 
land. 

[28] California also has local districts, known as Adjudicated 
Groundwater Basins, that may impose similar requirements. 

[29] In 1975, the State Water Resources Control Board established a 
policy that inland freshwater should be considered the water type of 
last resort for power plants and encouraged utilities to study the 
feasibility of effluent from sewage treatment plants for power plant 
cooling. The policy states the use of fresh inland waters for power 
plant cooling will only be approved when it is demonstrated that the 
use of other water supply sources or other methods of cooling would be 
environmentally undesirable or economically unsound. 

[30] The California Energy Commission reiterated the 1975 policy in the 
December 2003 Integrated Energy Policy Report that, consistent with 
that 1975 State Water Resources Control Board policy, it would only 
approve the use of freshwater where alternative cooling technologies 
were shown to be "environmentally undesirable" or "economically 
unsound." 

[31] One of these power plants uses a hybrid cooling system and is 
counted as having a water source and as using dry cooling. 

[32] Simple cycle natural gas plants are excluded from these statistics 
since they do not have a steam cycle and, therefore, do not need water 
for cooling. 

[33] There are variations for different plants in the number of cycles 
required and exemptions for the first full year of operation. 

[34] The most significant loss of water in a wet recirculating system 
with cooling towers is through evaporation from cooling towers. 
However, studies conducted by the Electric Power Research Institute 
indicate that increasing the cycles of concentration can result in 
water savings, though with diminishing returns after a certain number 
of cycles. 

[35] Commission officials noted that their review may indirectly affect 
a power plant's water use since consideration of cooling systems can be 
one component in their consideration of a power plant's feasibility, 
reliability and cost. In general, the Commission will favor the least- 
cost cooling option that ensures electric reliability and defers to 
state water agencies to address issues related to a plant's potential 
impact on water quality and quantity. However, officials also explained 
there may be circumstances where cooling or water issues are raised in 
a public hearing that may need to be considered by the Commission. 

[36] The Line Siting Committee makes a recommendation to the Arizona 
Corporation Commission about whether to issue a Certificate of 
Environmental Compatibility. The Arizona Corporation Commission is 
responsible for the final approval, modification, or denial of the 
certificate. 

[37] Power plants planning to use surface water must have surface water 
rights approved by the State Water Resources Control Board. Board 
officials told us that recent power plant applications for surface 
water rights were rare. According to an official at the California 
Energy Commission, power plants planning to use surface water often 
obtain their supply through a retail water agency, rather than 
obtaining surface water rights directly. 

[38] Unlike federal data on water availability, federal data on water 
use developed by USGS and EIA is not routinely relied upon by 
representatives from most of the state water regulators we spoke with, 
who evaluate applications for water use permits and water rights for 
new power plants. Some said they, instead, used data their offices had 
developed internally, including water use data reported to them by 
water permit and rights holders. 

[39] The Arizona Department of Water Resources collects water use data 
from water users in Active Management Areas, which are statutorily 
designated areas of constrained water supply. However, according to one 
official, the Department does not generally have the ability to collect 
these data outside of Active Management Areas and Irrigation Non- 
expansion Areas. Instead, the Department has entered into a cooperative 
agreement with USGS to collect these data. 

[40] Electric Power Research Institute, Comparison of Alternate Cooling 
Technologies for California Power Plants: Economic, Environmental and 
Other Tradeoffs, (Palo Alto, CA., 2002). 

[41] EIA officials noted that the agency collects environmental 
information from all U.S. plants with an existing or planned organic- 
fueled or combustible renewable stream-electric unit with a generator 
nameplate rating of 10 megawatts or larger. Form 767 instructions 
require cooling system and water information to be reported by plants 
with a nameplate capacity of 100 megawatts or greater. 

[42] EIA reports water consumption data for plants 100 megawatts in 
size or larger, but has not published aggregated data in such a way 
that allows them to be readily used to identify overall trends in 
thermoelectric power plant water consumption compared to withdrawal. 
However, these and other environmental data collected by EIA from 1996 
to 2005 for individual plants are available on EIA's Web site and can 
be assessed by all users at [hyperlink, 
http://www.eia.doe.gov/cneaf/electricity/page/eia767.html]. 

[43] Warm water discharged back into a water body from a once-through 
system may increase evaporation--water consumption--from the receiving 
water body. One expert we spoke with suggested that including this 
indirect form of water consumption in plant estimates would improve the 
federal data. 

[44] National Research Council, Estimating Water Use in the United 
States (Washington, D.C., 2002). 

[45] According to an Arizona Department of Water Resources official, it 
issues a Certificate of Water Right once the water is put to beneficial 
use. Several areas of decreed rights exist, for example, Globe Equity 
Decree on the Upper Gila River. 

[46] According to Arizona Department of Water Resources officials, 
options for obtaining groundwater rights include the following: (1) an 
existing Irrigation Grandfathered Groundwater Right that can be legally 
retired to a Type 1 Non-Irrigation Grandfathered Groundwater Right 
(A.R.S. § 45-469); (2) an existing Type 1 Non-Irrigation Grandfathered 
Groundwater Right (A.R.S. §§ 45-470, 45-472, 45-473, 45-542)); (3) a 
Type 2 Non-Irrigation Grandfathered Groundwater Right, which can be 
purchased or leased from another owner within the same Active 
Management Area (A.R.S. § 45-471); or (4) a General Industrial Use 
Permit, a permit to pump groundwater from a point outside of the 
exterior boundaries of the service area of a city, town, or private 
water company for non-irrigation purposes (A.R.S. § 45-515). Inside the 
Harquahala Irrigation Non-Expansion Area, there are some limitations to 
pumping groundwater for industrial uses, pursuant to A.R.S. § 45-440. 

[47] There are variations for different plants in the number of cycles 
required and exemptions for the first full year of operation. 

[48] Plants smaller that 100 megawatts do not need state siting 
approval. However, they must still comply with any and all local 
ordinances or state ordinances such as zoning, water quality, air 
quality, etc. 

[49] The Committee is chaired by a representative from the Office of 
the Arizona Attorney General. Other agencies represented include the 
Department of Environmental Quality, Department of Water Resources, the 
Office of Energy in the Department of Commerce, and the Arizona 
Corporation Commission. 

[50] Due to declining electricity prices, some of the approved plants 
were never constructed and others were sold to new owners. 

[51] In some areas of California, groundwater is managed locally 
through Adjudicated Groundwater Basins that can regulate the amount of 
groundwater extracted. 

[52] California's local air pollution control and air quality 
management districts have the authority to issue construction permits 
for the operation of power plants with less than 50 megawatts of 
generating capacity. 

[53] Though not common, if a power plant developer plans to make use of 
surface water in California, it may be required to apply for a water 
right from the State Water Resources Control Board. In evaluating the 
permit application, the State Water Resources Control Board would 
conduct its own analysis using a combination of state and federal data 
sources. 

[54] Any entity that withdraws more than 100,000 gallons a day (monthly 
average) of surface water or 100,000 gallons a day (daily average) of 
groundwater requires a water permit from the Division. 

[End of section] 

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