Energy-Water Nexus
Improvements to Federal Water Use Data Would Increase Understanding of Trends in Power Plant Water Use Gao ID: GAO-10-23 October 16, 2009In 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 Traditionally, power plants have withdrawn water from rivers and other water sources to cool the steam used to produce electricity, so that it may be reused to produce more electricity.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.
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.
RecommendationsOur recommendations from this work are listed below with a Contact for more information. Status will change from "In process" to "Open," "Closed - implemented," or "Closed - not implemented" based on our follow up work.
Director: Team: Phone:GAO-10-23, Energy-Water Nexus: Improvements to Federal Water Use Data Would Increase Understanding of Trends in Power Plant Water Use
This is the accessible text file for GAO report number GAO-10-23
entitled 'Energy-Water Nexus: Improvements to Federal Water Use Data
Would Increase Understanding of Trends in Power Plant Water Use' which
was released on October 16, 2009.
This text file was formatted by the U.S. Government Accountability
Office (GAO) to be accessible to users with visual impairments, as part
of a longer term project to improve GAO products' accessibility. Every
attempt has been made to maintain the structural and data integrity of
the original printed product. Accessibility features, such as text
descriptions of tables, consecutively numbered footnotes placed at the
end of the file, and the text of agency comment letters, are provided
but may not exactly duplicate the presentation or format of the printed
version. The portable document format (PDF) file is an exact electronic
replica of the printed version. We welcome your feedback. Please E-mail
your comments regarding the contents or accessibility features of this
document to Webmaster@gao.gov.
This is a work of the U.S. government and is not subject to copyright
protection in the United States. It may be reproduced and distributed
in its entirety without further permission from GAO. Because this work
may contain copyrighted images or other material, permission from the
copyright holder may be necessary if you wish to reproduce this
material separately.
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]
GAO's Mission:
The Government Accountability Office, the audit, evaluation and
investigative arm of Congress, exists to support Congress in meeting
its constitutional responsibilities and to help improve the performance
and accountability of the federal government for the American people.
GAO examines the use of public funds; evaluates federal programs and
policies; and provides analyses, recommendations, and other assistance
to help Congress make informed oversight, policy, and funding
decisions. GAO's commitment to good government is reflected in its core
values of accountability, integrity, and reliability.
Obtaining Copies of GAO Reports and Testimony:
The fastest and easiest way to obtain copies of GAO documents at no
cost is through GAO's Web site [hyperlink, http://www.gao.gov]. Each
weekday, GAO posts newly released reports, testimony, and
correspondence on its Web site. To have GAO e-mail you a list of newly
posted products every afternoon, go to [hyperlink, http://www.gao.gov]
and select "E-mail Updates."
Order by Phone:
The price of each GAO publication reflects GAO‘s actual cost of
production and distribution and depends on the number of pages in the
publication and whether the publication is printed in color or black and
white. Pricing and ordering information is posted on GAO‘s Web site,
[hyperlink, http://www.gao.gov/ordering.htm].
Place orders by calling (202) 512-6000, toll free (866) 801-7077, or
TDD (202) 512-2537.
Orders may be paid for using American Express, Discover Card,
MasterCard, Visa, check, or money order. Call for additional
information.
To Report Fraud, Waste, and Abuse in Federal Programs:
Contact:
Web site: [hyperlink, http://www.gao.gov/fraudnet/fraudnet.htm]:
E-mail: fraudnet@gao.gov:
Automated answering system: (800) 424-5454 or (202) 512-7470:
Congressional Relations:
Ralph Dawn, Managing Director, dawnr@gao.gov:
(202) 512-4400:
U.S. Government Accountability Office:
441 G Street NW, Room 7125:
Washington, D.C. 20548:
Public Affairs:
Chuck Young, Managing Director, youngc1@gao.gov:
(202) 512-4800:
U.S. Government Accountability Office:
441 G Street NW, Room 7149:
Washington, D.C. 20548:
