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Report to the Chairman of the Select Committee on Energy Independence 
and Global Warming, House of Representatives: 

United States Government Accountability Office: 
GAO: 

September 2008: 

Climate Change: 

Federal Actions Will Greatly Affect the Viability of Carbon Capture and 
Storage As a Key Mitigation Option: 

GAO-08-1080: 

GAO Highlights: 

Highlights of GAO-08-1080, a report to the Chairman of the Select 
Committee on Energy Independence and Global Warming, House of 
Representatives. 

Why GAO Did This Study: 

Key scientific assessments have underscored the urgency of reducing 
emissions of carbon dioxide (CO2) to address climate change. Many have 
cited carbon capture and storage (CCS) as an essential technology 
because it has the potential to greatly reduce CO2 emissions from power 
plants while allowing for projected increases in electricity demand. 
CCS involves capturing CO2 from a power plant’s emissions, transporting 
it to an underground storage location, and then injecting it into a 
geologic formation for long-term storage. 

As requested, GAO examined (1) key economic, legal, regulatory, and 
technological barriers impeding commercial-scale deployment of CCS 
technology and (2) actions the Department of Energy (DOE), 
Environmental Protection Agency (EPA), and other agencies are taking to 
overcome barriers to commercial-scale deployment of CCS technology. 
Among other things, GAO examined key studies and contacted officials 
from pertinent agencies, companies, and environmental groups, as well 
as research and other organizations. 

What GAO Found: 

Nationally-recognized studies and GAO’s contacts with a diverse group 
of industry representatives, nongovernmental organizations, and 
academic researchers show that key barriers to CCS deployment include 
(1) underdeveloped and costly CO2 capture technology and (2) regulatory 
and legal uncertainties over CO2 capture, injection, and storage. Key 
technological barriers include a lack of experience in capturing 
significant amounts of CO2 from commercial-scale power plants and the 
significant cost of retrofitting existing plants that are the single 
largest source of CO2 emissions in the United States. Regulatory and 
legal uncertainties include questions about liability concerning CO2 
leakage and ownership of CO2 once injected. According to the National 
Academy of Sciences and other knowledgeable authorities, another 
barrier is the absence of a national strategy to control CO2 emissions 
(emissions trading plan, CO2 emissions tax, or other mandatory control 
of CO2 emissions), without which the electric utility industry has 
little incentive to capture and store its CO2 emissions. Moreover, 
according to key agency officials, the absence of a national strategy 
to control CO2 emissions has also deterred their agencies from 
resolving other important practical issues, such as how sequestered CO2 
will be transported from power plants to appropriate storage locations 
and how stored CO2 would be treated in a future CO2 emissions trading 
plan. 

Federal agencies have begun to address some CCS barriers but have yet 
to comprehensively address the full range of issues that would require 
resolution for large-scale CCS deployment: 

* DOE’s research strategy has, until recently, devoted relatively few 
resources to lowering the cost of CO2 capture from existing coal-fired 
power plants, focusing instead on innovative technologies applicable to 
new plants. In recent years, however, the agency has begun to place 
greater emphasis on CCS technologies applicable to existing facilities. 

* EPA issued in July 2008 a proposed rule to guide the permitting of 
large volume, or commercial-scale, CO2 injections. It addressed at 
least some of the key issues under the Safe Drinking Water Act but left 
other issues related to EPA’s implementation of its air, hazardous 
waste and substance statutes unresolved. 

* Other agencies, such as Interior and Transportation, have 
jurisdiction over a number of interdisciplinary issues that could delay 
CCS deployment if unaddressed, but which have thus far received little 
attention. These include, among others, a legal and regulatory regime 
for a national CO2 pipeline infrastructure and a plan for addressing 
CO2 emissions reductions from CCS in a future emissions trading plan. 
In addition, unless the effects of CCS deployment are clearly 
explained, public opposition could delay future CCS projects. 

What GAO Recommends: 

Among GAO’s recommendations are that (1) DOE continue to place greater 
emphasis on CO2 capture at existing power plants and (2) EPA examine 
how its statutory authorities can be used to address potential CCS 
barriers. DOE neither explicitly agreed nor disagreed with the first 
recommendation. EPA expressed general agreement with the second 
recommendation. 

To view the full product, including the scope and methodology, click on 
[hyperlink, http://www.gao.gov/cgi-bin/getrpt?GAO-08-1080]. For more 
information, contact John Stephenson at (202) 512-3841 or 
stephensonj@gao.gov. 

[End of section] 

Contents: 

Letter: 

Results in Brief: 

Background: 

Barriers to CCS Deployment Include the High Cost of Current 
Technologies, Regulatory Uncertainty, and the Lack of a National 
Strategy to Control CO2 Emissions: 

Federal Agencies Have Yet to Resolve the Full Range of Issues Requiring 
Resolution for Widespread CCS Deployment: 

Conclusions: 

Recommendations for Executive Action: 

Agency Comments and Our Evaluation: 

Appendix I: Objectives, Scope, and Methodology: 

Appendix II: Comments from the Department of Energy: 

GAO Comments: 

Appendix III: Comments from the Environmental Protection Agency: 

GAO Comments: 

Appendix IV: GAO Contact and Staff Acknowledgments: 

Figures: 

Figure 1: Contribution of Coal-Fired Power Plants and Other Sources to 
Total U.S. CO2 Emissions: 

Figure 2: CO2 Capture, Transport, and Storage in Geologic Formations: 

Figure 3: Pre-combustion (i.e., IGCC) versus Post-combustion (i.e., 
pulverized coal) CO2 Capture: 

Figure 4: Potential Geologic Storage in the United States: 

Abbreviations: 

AoR: Area of Review: 

BLM: Bureau of Land Management: 

CCS: carbon capture and storage: 

CCTP: Climate Change Technology Program: 

CERCLA: Comprehensive Environmental Response, Compensation, and 
Liability Act: 

CO2: carbon dioxide: 

DOE: Department of Energy: 

EPA: Environmental Protection Agency: 

ETS: Emissions Trading Scheme: 

EU: European Union: 

FERC: Federal Energy Regulatory Commission: 

IEA: International Energy Agency: 

IGCC: Integrated Gasification Combined Cycle: 

IPCC: Intergovernmental Panel on Climate Change: 

MIT: Massachusetts Institute of Technology: 

NSR: New Source Review: 

PHMSA: Pipeline and Hazardous Materials Safety Administration: 

RCRA: Resource Conservation and Recovery Act: 

SDWA: Safe Drinking Water Act: 

SO2: sulfur dioxide: 

STB: Surface Transportation Board: 

UIC: Underground Injection Control: 

UNFCCC: United Nations Framework Convention on Climate Change: 

USGS: U.S. Geological Survey: 

[End of section] 

United States Government Accountability Office:
Washington, DC 20548: 

September 30, 2008: 

The Honorable Edward Markey: 
Chairman: 
Select Committee on Energy Independence and Global Warming: 
House of Representatives: 

Dear Mr. Chairman: 

Key scientific assessments have underscored the urgency of reducing 
emissions of carbon dioxide (CO2), the most significant greenhouse gas, 
to help mitigate the negative effects of climate change. Given the 
United States' heavy reliance on coal-burning power plants that emit 
significant quantities of CO2, many have cited carbon capture and 
storage (CCS) as an essential technology because it can greatly reduce 
CO2 emissions from these facilities, while allowing for projected 
increases in electric power demand.[Footnote 1] CCS is a process of 
separating CO2 from other gases produced in fuel combustion and other 
industrial processes, transporting the CO2 via pipeline to an 
underground storage location, and injecting and storing it long-term in 
underground geologic formations. 

While other climate mitigation options exist--such as energy efficiency 
improvements, a switch to less carbon-intensive fuels, nuclear power, 
and renewable energy sources--CCS is considered by many to be a crucial 
component of any U.S. approach or strategy for addressing the climate 
change problem, particularly given the United States' current reliance 
on coal for almost half of its electricity production. Moreover, there 
is a large potential role for CCS in rapidly developing countries, such 
as China and India, which will be relying increasingly on coal to meet 
their energy needs. In fact, as of 2007, Chinese CO2 emissions likely 
exceeded those of the United States, according to the International 
Energy Agency (IEA).[Footnote 2] The IEA projects continued growth in 
CO2 emissions from China and other developing economies. 

At present, there are few commercial-scale CCS projects in operation. 
While recent assessments by the IEA and the Intergovernmental Panel on 
Climate Change (IPCC) have indicated that CCS could be a key 
contributor to controlling greenhouse gas emissions worldwide,[Footnote 
3] a number of barriers may preclude its widespread use. Therefore, 
many organizations, including the IEA, emphasize that it will be 
critical to overcome these barriers and demonstrate the feasibility of 
this technology. In this context, this report examines (1) the key 
economic, legal, regulatory, and technological barriers impeding 
commercial-scale deployment of CCS technology and (2) the actions 
federal agencies are taking to overcome barriers to or facilitate the 
commercial-scale deployment of CCS technology. 

To examine barriers to CCS, we conducted a literature review and 
synthesized CCS-related information contained in a number of key 
reports, including those by the IPCC, the National Academy of Sciences, 
and by various federal agencies. We also contacted a nonprobability 
sample of electric power companies, major oil and gas companies, CO2 
pipeline owners, environmental organizations, and researchers at think 
tanks and universities to determine their perspectives on key barriers 
to CCS deployment at commercial scale. We selected major U.S. energy 
producing companies, as well as organizations and researchers that 
participate actively in ongoing dialogues on CCS. We also selected a 
number of smaller companies and organizations to ensure that we 
obtained a broader range of perspectives on key issues.[Footnote 4] We 
used a semistructured interview guide to (1) obtain information from 
individual stakeholders on key barriers to CCS deployment at commercial 
scale and (2) facilitate an aggregate analysis of stakeholder 
perspectives on key barriers to CCS. 

To examine federal actions to address CCS barriers, we obtained and 
analyzed information from the Environmental Protection Agency (EPA), 
the Department of Energy (DOE), and other federal agencies regarding 
their CCS-related activities. We collected 12 years of budget 
information from DOE's Coal Program and followed up on recommendations 
contained in two recent EPA and DOE advisory committee reports. We also 
attended two EPA Underground Injection Control program workshops and 
followed up with EPA officials on stakeholder concerns expressed at 
these meetings. Using the methodology described for our first 
objective, we obtained the perspectives of industry stakeholders, 
environmental organizations, and researchers at think tanks and 
universities on federal agency actions to overcome barriers to, or to 
facilitate deployment of, commercial-scale CCS in the United States. We 
conducted this performance audit from October 2007 to September 2008 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. 

Results in Brief: 

Nationally-recognized studies and our contacts with a diverse group of 
industry representatives, nongovernmental organizations, and academic 
researchers show that key barriers to CCS deployment include (1) 
underdeveloped and costly CO2 capture technology and (2) regulatory and 
legal uncertainties over CO2 capture, injection, and storage. Among the 
key technological barriers are a lack of experience in capturing 
significant amounts of CO2 from power plants and the significant cost 
of capturing CO2, particularly from existing coal-fired power plants, 
which are the single largest source of CO2 emissions in the United 
States. Compounding these technological issues are regulatory and legal 
uncertainties, including uncertainty regarding liability for CO2 
leakage and ownership of CO2 once injected. According to the IPCC, the 
National Academy of Sciences, and other knowledgeable authorities, 
another barrier is the absence of a national strategy to control CO2 
emissions (emissions trading plan, CO2 emissions tax, or other 
mandatory control of CO2 emissions), without which the electric utility 
industry has little incentive to capture and store its CO2 emissions. 
Moreover, according to key agency officials, the absence of a national 
strategy has also deterred their agencies from addressing other 
important practical issues, such as resolving how stored CO2 would be 
treated in a future CO2 emissions trading plan. 

Federal agencies have begun to address some CCS barriers but have yet 
to comprehensively address the full range of issues that would require 
resolution for commercial-scale CCS deployment: 

* Key technological barriers. DOE has achieved limited results in 
lowering the cost of CO2 capture from existing coal-fired power plants. 
A major reason is that the agency has focused on "Integrated 
Gasification Combined Cycle" (IGCC) technology, a promising technology 
for new coal-fired power plants, but one that is less useful when 
applied to existing coal power plants. The agency has only recently 
begun to shift toward an approach that also emphasizes CCS technologies 
applicable to existing power plants. 

* Key legal and regulatory barriers. The EPA issued a proposed rule in 
July 2008 concerning underground injection of CO2 for geologic 
sequestration. Because of the large injection volumes associated with 
geologic sequestration, this proposed rule would apply to commercial- 
scale injections. The proposed rule was issued under the agency's Safe 
Drinking Water Act (SDWA) authority. However, some issues that fall 
outside of this authority are still unresolved. These include whether 
and how the Comprehensive Environmental Response, Compensation, and 
Liability Act (CERCLA) and the Resource Conservation and Recovery Act 
(RCRA) apply to injected CO2. Also unresolved are issues concerning how 
the Clean Air Act's requirements will apply to existing power plants 
that install CCS. 

* Other considerations. Even if the DOE-and EPA-related issues are 
resolved, there are a number of issues, many of which cross the 
jurisdictions of multiple agencies, that could delay CCS deployment if 
not addressed in a timely fashion. These include whether the federal 
government could be held liable if CO2 stored below public lands leaked 
onto adjoining nonfederal property. In addition, a number of federal 
agencies (such as the Federal Energy Regulatory Commission, the Surface 
Transportation Board, Department of Transportation, DOE, and EPA) will 
need to work together to examine how CO2 pipeline infrastructure might 
be regulated to accommodate commercial-scale CCS. Others will need to 
devise a plan for how CO2 emissions reductions from CCS will be treated 
in a future emissions trading scheme. 

We are making a number of recommendations to agencies with major CCS- 
related responsibilities to address key barriers to CCS deployment. To 
better ensure that DOE's research and development efforts address CCS 
at both new coal-fired power plants and existing plants, we are 
recommending that DOE continue its recent practice of placing a greater 
emphasis on technologies that can reduce CO2 emissions from existing 
coal-fired power plants. In commenting on a draft of this report, DOE's 
September 9, 2008, letter neither explicitly agreed nor disagreed with 
this recommendation but included a number of comments that recognized a 
need for increased funding for CO2 emissions control technologies for 
existing coal-fired power plants. 

To enhance EPA's ability to address barriers that may be affecting CCS 
deployment, we are recommending that EPA more comprehensively examine 
barriers to CCS development beyond those relevant to the SDWA, by 
addressing issues under RCRA, CERCLA, and other statutes within the 
agency's jurisdiction. EPA's September 12, 2008, letter responded that 
providing regulatory certainty on issues related to geological storage 
of CO2 was a high priority for the agency and agreed with the intent of 
the recommendation--to provide clarity on how statutes within the 
agency's jurisdiction may apply. The agency noted that it had made an 
initial effort to identify and discuss these issues in the preamble of 
its July 2008 proposed rulemaking and had requested comments on many of 
the SDWA topics--including some of those identified in our report. It 
said it expected further progress on the SDWA topics after receiving 
input from stakeholders during the comment period (which extends 
through November 24, 2008). 

Finally, we are recommending that an interagency task force (or similar 
mechanism) be established to develop a comprehensive strategy that 
guides cognizant federal agencies in resolving remaining issues that, 
if not addressed proactively, could impede commercial-scale CCS 
deployment. DOE maintained that a coordinating body--the DOE-led 
Climate Change Technology Program (CCTP)--already addresses these kinds 
of issues. However, the CCTP's scope focuses on technology; it does not 
address legal and institutional issues, such as the resolution of CO2 
pipeline regulation and infrastructure, among others. In addition, 
officials from cognizant offices within the Departments of the Interior 
and Transportation told us they have not yet been invited to 
participate in CCTP discussions. Moreover, we continue to believe that 
a more centralized task force with a broader mission, perhaps 
authorized by the Executive Office of the President, would be a 
preferable alternative. 

DOE's and EPA's comments are addressed at the end of this letter and 
reproduced in appendixes II and III, respectively (along with our 
responses to each of their main points). The agencies also provided 
technical comments separately, which have been incorporated in our 
final report, as appropriate. In addition, we sought and received 
clarification and verification on specific issues from the Department 
of the Interior's Bureau of Land Management and U.S. Geological Survey; 
the Department of Transportation's Pipeline and Hazardous Materials 
Safety Administration; the Federal Energy Regulatory Commission; and 
the Surface Transportation Board, and have incorporated their input in 
finalizing the report. 

Background: 

There is growing concern about climate change and the impact it will 
have on people and the ecosystems on which they depend. According to 
the National Academy of Sciences, global temperatures have already 
risen 1.4 degrees Fahrenheit since the start of the 20th century--with 
much of this warming occurring in the last 30 years alone--and 
temperatures will likely rise at least another 2 degrees Fahrenheit, 
and potentially more than 11 degrees, over the next 100 years. This 
warming will cause significant changes in sea level, ecosystems, and 
ice cover, among other impacts. In the Arctic region, temperatures have 
increased almost twice as much as the global average, and the landscape 
is changing rapidly. Most scientists agree that the warming in recent 
decades has been caused primarily by human activities that have 
increased the amount of greenhouse gases in the atmosphere. Greenhouse 
gases, such as CO2, have increased markedly since the Industrial 
Revolution, mostly from the burning of fossil fuels for energy, 
industrial processes, and transportation. According to the National 
Academy of Sciences, CO2 levels are at their highest in at least 
650,000 years and continue to rise. 

In 1992, the first major multilateral treaty on global warming, the 
United Nations Framework Convention on Climate Change (UNFCCC), was 
finalized. One hundred ninety-two countries, including the United 
States, have ratified this treaty and agreed to its objective to 
"achieve…stabilization of greenhouse gas concentrations in the 
atmosphere at a level that would prevent dangerous anthropogenic 
interference with the climate system." The UNFCCC required signatory 
states to publish greenhouse gas emission levels; formulate a national 
response to climate change; and develop and distribute technologies to 
control, reduce, or prevent greenhouse gas emissions. However, its 
mitigation provisions focused on voluntary efforts by signatory states. 
Under the Kyoto Protocol to the UNFCCC, 37 industrialized countries 
have agreed to reduce or limit their greenhouse gas emissions by an 
average of 5 percent below 1990 levels between 2008 and 2012. Also, in 
2005, the European Union (EU) began implementing its Emissions Trading 
Scheme (ETS), a program that limits CO2 emissions in each member state 
and is intended to help states achieve their commitments under the 
Kyoto Protocol. Many countries with significant greenhouse gas 
emissions, including the United States, China, and India, have not 
committed to binding limits on emissions through the Kyoto Protocol or 
other mechanisms as of the date of this report. Despite the UNFCCC's 
ratification, global annual fossil fuel-related CO2 emissions increased 
from an average of approximately 23.5 billion metric tons of CO2 per 
year in the 1990's to approximately 26.4 billion metric tons of CO2 per 
year from 2000 to 2005.[Footnote 5] 

A complicating factor in addressing this increase in temperature is the 
heavy reliance by the United States and other countries on coal-fired 
power plants for electric power generation. Coal accounts for about 
half of electricity generation in the United States. Moreover, 
according to the IEA, coal is used to produce more than half of several 
other nations' electricity, including South Africa, Poland, China, 
Australia, and India. 

Coal-fired power plants are one of the largest sources of CO2 
emissions. In the United States, coal-fired power plants account for 
approximately one-third of total CO2 emissions. Figure 1 shows total 
U.S. CO2 emissions, what portions are from each sector of the economy, 
and sources where CCS could more readily be used.[Footnote 6] 

Figure 1: Contribution of Coal-Fired Power Plants and Other Sources to 
Total U.S. CO2 Emissions: 

[See PDF for image] 

This figure is a pie-chart depicting the following data: 

Contribution of Coal-Fired Power Plants and Other Sources to Total U.S. 
CO2 Emissions: 
Coal-fired power plants: 32.3% (Source for which CCS is applicable); 
Transportation: 31.0%; 
Industrial: 14.4% (Source for which CCS is applicable); 
Other fossil fuel power plants (e.g., natural gas): 6.6% (Source for 
which CCS is applicable); 
Residential: 5.5%; 
Commercial: 3.5%; 
All other: 6.7%. 

Source: GAO analysis of data from the Environmental Protection Agency, 
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006 (April 
2008). 

[End of figure] 

To complicate matters further, increased energy demands are projected 
for the future, both in the United States and worldwide. The IEA 
projects that if governments around the world proceed with current 
policies, the world's energy needs would be over 50 percent higher in 
2030 than today.[Footnote 7] For the United States, an assessment by 
DOE's Energy Information Administration indicates that electricity 
sales will increase 29 percent by 2030, if current policies continue. 
Moreover, the IEA anticipates that the two largest developing 
countries--China and India--will drive increased demand for coal to 
meet growing electricity demand. The IEA notes that China and India's 
heavy reliance on coal has already contributed significantly to recent 
increases in global CO2 emissions, with China likely overtaking the 
United States as the largest CO2 emitter in 2007. 

In order to prevent this dramatic increase in coal-based energy 
production from emitting significant amounts of CO2 to the atmosphere, 
many are suggesting CCS as a unique tool that allows for continued coal 
use, while mitigating its associated effect on the climate. The IEA 
identifies CCS and other clean coal technologies as one of the most 
promising routes for mitigating emissions and notes that "CCS could 
reconcile continued coal burning with the need to cut emissions in the 
longer term." Similarly, the IPCC notes that CCS would help preserve 
existing energy infrastructure, thereby restraining the cost of 
emissions reductions. Looking ahead, the IEA projects that CCS could 
contribute to 21 percent of avoided emissions to stabilize atmospheric 
CO2 concentrations at 450 parts per million, a level which is projected 
to limit the average increase in global temperature to 2.4 degrees 
Celsius (4.3 degrees Fahrenheit). 

The EU is also beginning to highlight the importance of CCS in 
addressing climate change. In 2008, the EU proposed legislation, known 
as a proposed directive, on the geological storage of CO2 that would 
support the EU policy of limiting global average temperature increases 
to less than 2 degrees Celsius (3.6 degrees Fahrenheit). Specifically, 
in 2007, the European Council urged EU member states and the European 
Commission to develop the necessary technical, economic, and regulatory 
framework to remove existing legal barriers to CCS so that the 
technology can be applied to new fossil fuel power plants by 2020, if 
possible. The following year, the European Commission proposed 
legislation that would create a legal framework for capture, transport, 
and geological storage of CO2 within member states' territories. 

CCS is comprised of multiple processes, including CO2 capture and 
compression; transport of the CO2 to a storage location; injection and 
storage in geologic formations; and monitoring to verify that the CO2 
is staying in place. A successful CCS system must integrate all of 
them. The first step in CCS is identifying and verifying a suitable 
location for CO2 storage. Next, CO2 would be captured at power plants 
and other large industrial sources. The goal of CO2 capture is to 
produce a concentrated stream of nearly pure CO2 at high pressure so 
that it can be transported via pipeline to a storage site. Regardless 
of the capture approach used, additional energy, often referred to as 
the energy penalty, is required for capture and compression. Three 
major approaches to capturing or separating CO2 from industrial sources 
have been identified--pre-combustion capture, post-combustion capture, 
and oxyfuel combustion capture.[Footnote 8] 

After CO2 capture and compression, the compressed gas, now in a 
supercritical state,[Footnote 9] would likely be transported via 
pipeline to a storage site, unless a storage site was available at the 
capture facility. Once at a storage site, the CO2 would likely be 
injected well below the surface, at depths of over 800 meters, or about 
2,600 feet, into geologic formations thought to be conducive for long- 
term sequestration (that is, hundreds to thousands of years) from the 
atmosphere. When injected, the CO2 is sequestered by a combination of 
physical and geochemical trapping processes. 

Physical trapping occurs because the relatively buoyant CO2 reaches a 
layer of rock that inhibits further upward migration. Geochemical 
trapping occurs when the CO2 reacts chemically with minerals in the 
geologic formation that result in the precipitation of solid minerals. 
Geologic formations, such as depleted oil and gas reservoirs and saline 
formations, are thought to be particularly favorable for CO2 storage. 
These formations tend to have high porosity, or an abundance of pores 
for CO2 to fill in, and an impermeable barrier, known as a solid 
caprock, to keep the buoyant CO2 from migrating to the surface. Figure 
2 depicts CO2 capture, transport, and storage in geologic formations 
and highlights the characteristics of caprock and the underlying rock 
that are favorable for CO2 storage. DOE and IEA estimates indicate that 
the United States has appropriate geology that could potentially store 
over 3 trillion tons of CO2--enough to store 1,000 years of CO2 
emissions from nearly 1,000 coal-fired power plants. 

Figure 2: CO2 Capture, Transport, and Storage in Geologic Formations: 

[See PDF for image] 

This figure is a drawing depicting CO2 capture, transport, and storage 
in geologic formations. The following data is depicted: 

Underground geology: 

Caprock: 
Grains making up this rock are densely packed with few interconnected 
pore spaces. The low permeability of these rocks makes them ideal 
barriers to prevent the migration of CO2 out of the target storage 
formation. Examples are shale and carbonates. 

Medium-grained sandstone: 
Grains making up this rock are much less tightly packed than the 
caprock. The dark gray areas are voids in the rock that are filled with 
water not suitable for drinking. Injected CO2 would move into these 
void spaces. 

Course-grained sandstone: Grains making up this rock are even less 
tightly packed than the previous sample. This looser packing means that 
all of the voids are well connected to each other allowing the injected 
CO2 to more easily move through the formation. Thus, more CO2 can be 
injected and at a higher rate that in the medium-grained sandstone. 

Coal is used in power plants; 
CO2 is captured at the plants; 
CO2 is transported to an injection station; 
CO2 injection and storage in both medium-grained and course-grained 
sandstone. 

Source: GAO analysis of IPCC and Joint Global Change Research 
Institute, Battelle Pacific Northwest Division data. 

[End of figure] 

Multiple federal agencies have programs and other responsibilities that 
will affect CCS deployment, but the key ones are administered primarily 
by DOE and EPA: 

* DOE is the lead federal agency for supporting the development of 
clean coal technology, including CCS technology. The agency established 
the Carbon Sequestration program in 1997 to ascertain the technical 
viability of CCS. The core research and development in the program 
involves laboratory and pilot-scale research in areas that include CO2 
capture and storage. The demonstration and deployment element of the 
program is designed to show the viability of CCS technologies at a 
scale large enough to overcome real and perceived infrastructure 
challenges. In order to do so, DOE established a network of seven 
Regional Carbon Sequestration Partnerships to develop the technology, 
infrastructure, and regulations necessary to implement CO2 storage in 
different regions of the nation. Other DOE programs are also developing 
technologies related to coal-fueled power generation with CO2 capture; 
including (1) the Advanced Integrated Gasification Combined Cycle 
(IGCC) program to support development of gasification technology to 
enable CO2 capture; (2) the restructured FutureGen program to 
demonstrate IGCC or other advanced coal technology, as well as CO2 
capture; (3) the Innovations for Existing Plants program, which has 
recently focused more attention on developing technology to facilitate 
CO2 capture at existing coal-fired power plants; and (4) the Clean Coal 
Power Initiative, which is supporting advanced coal-based technologies 
that capture and sequester CO2 emissions. 

* EPA has authority under the SDWA to regulate underground injections 
of various substances, including nonhazardous and hazardous wastes into 
injection wells. Injection wells have a range of uses that 
traditionally include waste disposal, enhancing oil production, and 
mining. The SDWA requires EPA to develop minimum federal requirements 
for injection practices that protect public health by preventing 
injection wells from endangering underground sources of drinking water. 
There are five different well types: Class I (injections of hazardous 
wastes, industrial nonhazardous wastes, municipal wastewater); Class II 
(injections associated with enhanced oil and gas production); Class III 
(injections associated with mineral extraction); Class IV (now mostly 
banned,[Footnote 10] but formerly, to inject hazardous or radioactive 
waste above or into an underground source of drinking water); and Class 
V (wells not included in other classes, including wells used in 
experimental technologies, such as pilot CO2 storage).[Footnote 11] EPA 
has given 33 states primacy, or primary enforcement responsibility, to 
administer the Underground Injection Control (UIC) program, and 7 
states have partial responsibility for administering the UIC program. 
[Footnote 12] 

* The prospect of widespread, nationwide use of CCS would also require 
the involvement of other agencies with varied responsibilities. The 
Department of the Interior's Bureau of Land Management, for example, 
would have broad jurisdiction over CO2 injected on public lands. 
Whether the Federal Energy Regulatory Commission or the Surface 
Transportation Board would have regulatory responsibilities for 
pipelines transporting captured CO2 is an issue that needs to be 
resolved. The CCTP, authorized by the Energy Policy Act of 2005, is 
tasked with assisting the interagency coordination of climate change 
technology research, development, demonstration, and deployment. 
Because the CCTP coordinates interagency discussion of climate change 
technology issues, it will likely also be involved in any ongoing 
interagency dialogue on CCS deployment. 

Barriers to CCS Deployment Include the High Cost of Current 
Technologies, Regulatory Uncertainty, and the Lack of a National 
Strategy to Control CO2 Emissions: 

Nationally-recognized studies and our contacts with a diverse group of 
industry representatives, nongovernmental organizations, and academic 
researchers show that key barriers to CCS deployment include (1) the 
high cost of, and lack of experience with, CO2 capture technologies and 
(2) regulatory uncertainties concerning CO2 capture, injection, and 
storage. Among the technological barriers impeding CCS deployment at 
coal-burning power plants are the significant cost of retrofitting 
existing coal-fired power plants and lack of commercial-scale 
demonstrations. Compounding these technological issues are 
uncertainties over regulatory and legal issues, including legal 
uncertainty regarding liability for CO2 leakage and ownership of CO2 
once injected. According to the IPCC, the National Academy of Sciences, 
and other knowledgeable authorities, another barrier is the absence of 
a national strategy to control CO2 emissions (emissions trading plan, 
CO2 emissions tax, or other mandatory control of CO2 emissions), 
without which the electric utility industry has little incentive to 
capture and store its CO2 emissions. Moreover, according to key agency 
officials, the absence of a national strategy to control CO2 emissions 
has also deterred their agencies from resolving other important 
practical issues, such as how stored CO2would be treated in a future 
CO2 emissions trading plan. 

CO2 Capture Must Overcome Significant Technological Hurdles to be a 
Cost-Effective Technology for Coal-Fired Power Plants: 

Capturing CO2 from large electric power plants, particularly coal-fired 
power plants, entails a number of technological challenges that affect 
its cost of deployment, and hence its appeal to industry. Among these 
challenges are (1) the absence of any commercial-scale demonstration of 
the technology at a power plant; (2) certain limitations of coal 
gasification technology for capturing CO2 emissions at new power 
plants; and (3) the high cost of retrofitting CCS to existing 
pulverized coal-fired power plants that will, for the next several 
decades, account for a significant share of U.S. CO2 emissions. 

CCS Has Yet to Be Demonstrated on a Commercial Scale at a Power Plant: 

To date, there have been several small-scale tests of CO2 capture at 
power plants in the United States and other countries, but these 
demonstration projects have typically removed CO2 from only a small 
fraction of the power plant's overall output. Large-scale 
demonstrations of CO2 capture at a power plant have been identified as 
an important step in improving capture technology, as well as securing 
industry support for CCS. Hence, the DOE Carbon Sequestration Program's 
program plan notes that the testing of CCS technologies at a larger 
scale is important to identify and eliminate technical and economic 
barriers to commercialization of CCS technology. With the need to 
accelerate the testing of innovative technologies in mind, two key 
international organizations--the IEA and the Carbon Sequestration 
Leadership Forum--recommend that a minimum of 20 full-scale CCS 
demonstration projects be implemented worldwide by 2020. 

In a similar vein, a DOE advisory committee, the National Coal Council, 
noted that larger-scale demonstrations will be necessary to secure 
industry support. It noted, in particular, that "deployment will 
require successful pilot-scale testing and operation at a demonstration 
scale of 50 to 100 megawatts before companies will have confidence in 
their cost and performance for large scale systems."[Footnote 13] 
Similar opinions were offered by several of the stakeholders we 
interviewed, who told us they thought it would be helpful for testing 
to focus more on actual demonstrations, rather than laboratory testing. 
For example, two electric power company officials told us they thought 
testing on a larger scale was important because the reliability of 
power plants with carbon management has not been adequately considered. 

Despite the importance of gaining this kind of experience with CO2 
capture, CO2 capture has not been demonstrated on a large scale at a 
power plant in the United States or in any other country. The IPCC's 
Special Report on CCS observed that "there have been no applications 
[of carbon capture] at large-scale power plants of several hundred 
megawatts" and emphasized the significance of this omission by 
cautioning that large-scale power plants are the major source of 
current and projected CO2 emissions. 

It should be noted that some progress has been made in testing CCS at 
other types of industrial facilities. Specifically, four industrial 
facilities have received attention as major demonstrations of CO2 
capture and storage technology. These facilities presently capture and 
store anthropogenic CO2 on a large scale.[Footnote 14] Three of these 
projects involve separation of CO2 from natural gas: the Sleipner and 
Snohvit projects, located off the coast of Norway, and the In Salah 
project in Algeria. The fourth project captures CO2 at a facility in 
North Dakota, where coal is gasified to make methane. The captured CO2 
is then injected at an oil field in Weyburn, Canada for the purposes of 
enhanced oil recovery and to permanently store almost all of the 
injected CO2. 

CO2 capture has also been demonstrated at other industrial facilities, 
including plants that purify natural gas and produce chemical products 
(ammonia, alcohols, and synthetic liquid fuels). For example, one 
existing industrial application of CO2 capture is to remove CO2 from 
natural gas--a process called natural gas sweetening--to prevent 
pipeline corrosion and increase the heating value of the gas. However, 
much of the CO2 captured at these facilities is currently vented to the 
atmosphere because there is no requirement or incentive to store it. 
[Footnote 15] 

Nonetheless, according to the IPCC and other knowledgeable authorities, 
key differences may inhibit the transferability of CO2 capture at these 
facilities to coal-fired power plants: 

* Lower CO2 concentrations at coal-fired power plants. A study by 
researchers at the Massachusetts Institute of Technology (MIT) 
indicated that industrial processes, such as natural gas processing and 
ammonia production, produce highly concentrated streams of CO2 as a 
byproduct, facilitating CO2 capture.[Footnote 16] By contrast, CO2 is 
relatively diffuse in the exhaust, or flue gas, produced by coal power 
plants--about 13 to 15 percent by volume--making CO2 capture 
substantially more energy intensive. 

* Challenges in adapting the CO2 removal process to power plants. The 
most commonly-used chemical method for removing CO2 from natural gas 
may be challenging to adapt to capture at power plants. According to 
the IPCC Special Report on CCS, CO2 is most commonly removed from 
natural gas using chemical solvents. However, DOE officials told us 
that one such commonly used solvent, monoethanolamine, is not designed 
to cost-effectively remove the dilute concentrations of CO2 from the 
extremely large volumes of flue gas produced by pulverized coal power 
plants. 

The IPCC report noted that applying CO2 capture and sequestration only 
at these types of industrial facilities--and not at other facilities, 
such as coal-fired power plants--would contribute only marginally to 
addressing climate change. Specifically, it estimates that CO2 capture, 
if widely used at natural gas sweetening facilities, would account for 
less than 1 percent of CO2 emissions per year from large stationary 
sources. 

Coal Gasification Technology Offers Promise in Capturing CO2 at New 
Plants but Has Limitations That May Impede Its Widespread Use: 

DOE has pursued gasification technology--specifically IGCC technology-
-as a key technology for reducing the environmental impact of coal- 
based electricity generation, and which may be advantageous for CO2 
capture. The gasification process chemically decomposes the fuel before 
its combustion to provide a stream of CO2 for separation and storage, 
as well as a stream of hydrogen for electricity production. It is 
advantageous in facilitating CO2 capture because it provides a more 
concentrated stream of CO2 at high pressure for separation and reduces 
the energy required for additional compression of the CO2 for 
transport. DOE also indicates that IGCC plants may enable near-zero 
emissions of pollutants, including sulfur dioxide, nitrogen oxides, and 
particulate emissions, as well as increase fuel efficiency. 

While capturing CO2 at IGCC plants would impose additional costs, 
assessments by DOE and international organizations concluded that these 
costs would be lower than they would be for pulverized coal-fired power 
plants that remove the CO2 after fuel combustion. For example, a 2007 
DOE study concluded that IGCC plants--if built initially with the 
capability to capture CO2 emissions--had a lower adverse impact on 
efficiency and cost of electricity production than equipping a new 
pulverized coal-fired power plant and, therefore, were a less expensive 
option for capturing CO2 emissions.[Footnote 17] DOE officials told us 
that, based on the agency's analysis, the cost of electricity 
production would increase by 35 percent for newly constructed IGCC 
plants with CO2 capture, compared to a 77 percent increase for newly 
constructed pulverized coal power plants equipped with CO2 capture. 
[Footnote 18] Figure 3 illustrates several of the key differences 
between the two capture approaches. 

Figure 3: Pre-combustion (i.e., IGCC) versus Post-combustion (i.e., 
pulverized coal) CO2 Capture: 

[See PDF for image] 

This figure illustrates several of the key differences between the two 
capture approaches, as follows: 

IGCC (pre-combustion): 
Air: enters air separation chamber, oxygen sent to gasification 
chamber; 
Coal: sent to gasification chamber; 
Syngas sent to CO@ capture chamber; 
H2 sent to combustion turbine; electricity is produced; 
CO2 sent to CO2 compression. 

Pulverized coal (post-combustion): 
Coal and air enter boiler; combustion occurs; steam turbine produces 
electricity; 
Flue gas (mostly nitrogen and oxygen) is sent to the CO2 capture 
chamber; nitrogen is vented off; CO2 is sent to compression. 

Source: GAO analysis of IPCC and DOE data. 

[End of figure] 

Nonetheless, while IGCC plants using CCS technology have been planned 
in a number of countries, the outlook for IGCC power plants remains 
uncertain. Among the factors impeding deployment of the technology are 
the following: 

* Cost of constructing IGCC power plants. Recent assessments indicate 
that it may be initially more expensive to build a new IGCC power plant 
than to build a pulverized coal power plant if CO2 emissions are not 
captured. The IEA notes, in particular, that the investment cost for an 
IGCC plant is about 20 percent higher than for a pulverized coal 
combustion plant.[Footnote 19] Moreover, the DOE Cost and Performance 
Baseline for Fossil Energy Plants report states that if the power plant 
does not capture CO2 emissions, both the total cost of the plant as 
well as cost of electricity production would be more expensive at the 
IGCC power plants.[Footnote 20] Furthermore, the IEA notes considerable 
uncertainty in IGCC costs because no coal-fired IGCC plants have 
recently been built. 

* Reliability concerns with IGCC plants. Several stakeholders we 
interviewed expressed concern about the reliability of IGCC plants for 
electricity production. One electric power company official said that 
existing turbines for IGCC power plants are not reliable enough to 
provide base-load power for customers at high levels of CO2 capture. 
Moreover, according to an MIT study, several IGCC power plants 
experienced reliability challenges in the first few years of operation, 
although many of these early problems proved manageable and the 
reliability of the plants subsequently improved.[Footnote 21] However, 
the National Coal Council identifies reliability as one continuing area 
of concern in which IGCC technology could be improved.[Footnote 22] 

* Challenges in building new coal-fired power plants in the United 
States. Using IGCC as an enabling technology for CCS is premised on 
building new coal-fired power plants. However, efforts to build new 
coal-fired power plants, regardless of the technology used, are facing 
increased regulatory scrutiny due to environmental concerns. A 2008 DOE 
report, Tracking New Coal-Fired Power Plants, states that significantly 
fewer new U.S. coal-fired power plants have been built than originally 
planned. Delays and cancellations have been attributed to regulatory 
uncertainty, including climate change concerns and escalating costs. 

Capturing CO2 from Existing Coal-fired Power Plants Requires 
Significant Amounts of Energy and Imposes High Costs: 

Key assessments indicate that post-combustion capture of CO2, which 
would be used at pulverized coal power plants, faces significant 
technical challenges that greatly affect the cost and feasibility of 
its deployment using currently available technology.[Footnote 23] This 
is significant because these pulverized coal facilities account for an 
overwhelming share of the world's coal-fired capacity. 

In a pulverized coal plant, coal is burned with air in the boiler to 
produce steam. The steam then drives a turbine to generate electricity. 
Hence, CO2 would have to be separated from the boiler exhaust, or flue 
gas, after combustion, rather than separating the carbon before 
combustion, as is the case in an IGCC plant. The need to separate CO2 
from the flue gas adds a number of technical challenges that can affect 
the cost and efficiency of CO2 capture: 

* Treating large volumes of flue gas to remove CO2. As noted earlier, 
large volumes of flue gas must be treated to remove dilute 
concentrations of CO2. DOE estimates that CO2 accounts for only about 
15 percent of the volume of the flue gas from a pulverized coal-fired 
power plant, compared to about 40 percent in an IGCC plant. 

* Removing impurities from the flue gas before CO2 removal. Trace 
impurities in the flue gas, such as particulate matter, sulfur dioxide, 
and nitrogen oxides, can reduce the effectiveness of certain CO2 
capture processes. The IPCC notes that it is important to reduce the 
acidic gas components, which would reduce the absorption capacity of 
the solvent used to remove CO2. Additionally, IPCC notes that fly ash 
and soot present in the flue gas could be problematic, if not 
addressed. 

* Compressing the captured or separated CO2. Compressing captured or 
separated CO2 from atmospheric pressure to pipeline pressure represents 
a large auxiliary power load on the overall plant system. The MIT study 
indicated that the energy required to compress the CO2 is the second 
largest factor in reducing the efficiency of the power plant.[Footnote 
24] 

* Significant cost increases in retrofitting CCS to an existing plant. 
An IPCC assessment of several studies concluded that retrofitting a CO2 
capture system to existing coal-fired power plants would increase the 
incremental cost of producing electricity from about 150 to 290 
percent. Similarly, based on a study of a representative coal-fired 
plant in Ohio, DOE estimated that capturing 30 percent of a retrofitted 
plant's CO2 emissions would increase its cost of electricity production 
by 2.3 cents per kilowatt-hour, while capturing 90 percent of the 
plant's CO2 emissions would increase the cost of producing electricity 
by nearly 7 cents per kilowatt-hour.[Footnote 25] For comparative 
purposes, the DOE's Energy Information Administration reports that the 
average retail price of electricity in the United States is 8.9 cents 
per kilowatt hour. 

Regulatory and Legal Uncertainties Also Complicate Capture, Injection, 
and Storage of CO2: 

The IPCC, two federal advisory committee reports, and many stakeholders 
we contacted agreed that key regulatory and legal issues will need to 
be addressed if CCS is to be deployed at commercial scale. Among these 
issues are (1) confusion over the rules for injecting large volumes of 
CO2, (2) long-term liability issues concerning CO2 storage and 
potential leakage, (3) how property ownership patterns may affect CO2 
storage, and (4) how the Clean Air Act will apply to facilities that 
capture CO2. 

Confusion over Rules about Large-Volume Injections of CO2: 

Electric utilities and oil and gas companies have underscored the need 
for guidance on how CCS projects that inject large volumes of CO2 would 
be regulated under EPA's Underground Injection Control (UIC) program, 
which is designed to protect underground sources of drinking water. As 
noted earlier, under the UIC program, EPA regulates underground 
injections of various substances, including nonhazardous and hazardous 
wastes into more than 800,000 injection wells. The SDWA requires EPA to 
develop minimum federal requirements for injection practices that 
protect public health by preventing injection wells from endangering 
underground sources of drinking water. However, the injection of CO2 
for long-term storage raises a new set of unique issues related to its 
relative buoyancy, its corrosiveness in the presence of water, and 
large volumes in which it would be injected. 

Stakeholders suggested that the absence of regulations related to large-
volume CO2 injection and storage was creating considerable uncertainty 
for CCS projects. Recently, EPA proposed a regulation to address this 
uncertainty. Prior to this proposal, nearly half of the 20 stakeholders 
we interviewed said uncertainty regarding CO2 injection and storage 
regulations was a large or very large barrier to CCS deployment. For 
example, one industry stakeholder said that he was uncertain about 
whether injecting CO2 in large volumes was actually legal, since EPA's 
guidance to date only addresses pilot CCS projects. Other stakeholders 
have mentioned that without new EPA guidance on large volume CO2 
injections, they were uncertain about how stringent their well 
construction and monitoring needed to be. In addition, a diverse panel 
at EPA's 2007 UIC workshop on the issue noted that well spacing could 
be a significant issue that needed to be addressed, since the pressure 
effects caused by various CO2 injections could intersect and have a 
major impact due to injection volumes, particularly with the size and 
potential number of CO2 projects. Finally, according to a 2007 report 
by the American Public Power Association, the uncertainty associated 
with UIC permit requirements has complicated commercial scale planning 
for new coal-fired power plants because it has left utilities uncertain 
as to whether they could inject CO2 locally or be required to pipe CO2 
over great distances. 

In July 2008, EPA addressed some of these technical and regulatory 
issues in its proposed rule for underground injection of CO2 for 
geologic sequestration. Preliminary stakeholder reaction to EPA's 
proposed rule, discussed later in this report, suggests that some CO2 
injection-related uncertainties may be headed for resolution through 
the EPA rulemaking but that others will be more challenging to resolve. 

Long-Term Liability Concerns over CO2 Storage and Possible Leakage: 

Beyond the immediate concerns over how to inject large volumes of CO2, 
stakeholders expressed broader concerns over the long-term liability 
associated with its storage. They pointed specifically to a lack of 
clarity regarding who--the injector or the property owner--will 
ultimately be responsible for CO2 injections and storage after the 
wells are capped. If stored CO2 migrated beyond the area in which it 
was intended to be stored, there are two potential outcomes that 
generate concern: 

* Stored CO2 could migrate underground and endanger underground sources 
of drinking water, leading to liability under the SDWA for the party 
responsible. According to EPA, CO2 migration into drinking water can 
cause the leaching of contaminants, such as arsenic, lead, and other 
compounds, into the water. CO2 migration could also result in changes 
in regional groundwater flow and the movement of saltier fluids into 
drinking water, causing its quality to degrade. As the July 2008 
proposed rule's preamble reiterates, under the SDWA, well operators 
remain responsible indefinitely for any migration that endangers 
underground sources of drinking water, and courts could impose civil 
penalties as high as $25,000 per day. Participants in EPA's 2007 UIC 
workshop raised the prospect of environmental and health concerns posed 
by CO2 injections, including the mobilization of previously isolated 
metals, lower pH as a result of CO2 interaction with water, and 
saltwater displacement. 

* Stored CO2 could also migrate beneath adjacent lands. If CO2 was 
injected for geologic storage and it migrated underground into 
neighboring mineral deposits, for example, it could interfere with the 
adjacent mineral owners' abilities to extract those resources, and the 
injection well's operator could be held liable for nuisance, trespass, 
or another tort. 

EPA's 2007 UIC workshop, attended by more than 200 stakeholders, 
revealed liability associated with unintended migration of injected CO2 
to be a critical concern. Similarly, 19 of the 20 stakeholders we 
interviewed told us that liability related to CO2 storage was a large 
or very large barrier to deployment of CCS at commercial scale, with 
some noting that liability concerns have already negatively impacted 
companies' ability to initiate CCS projects. For example, two 
stakeholders reported that these concerns have already made it 
difficult to obtain insurance for CCS projects. They noted specifically 
that insurers have difficulty writing insurance policies because of the 
uncertainties associated with and limited data available for CCS, while 
another added that investors will not support projects like CCS if they 
expose them to unlimited and undefined long-term liabilities, 
especially when future revenue streams are uncertain. 

Property Ownership Patterns May Also Affect CO2 Storage: 

Setting aside any complications that could later arise from CO2 leakage 
onto others' property, electric utilities and other stakeholders note 
that at the outset of a CCS project, it would be essential to identify 
and obtain the consent of all surface and mineral property rights 
owners. Such a determination is not always straightforward because 
ownership of surface land is often severed from ownership of minerals 
located below the land's surface and, in the same vein, ownership of 
saline reservoirs. In these circumstances of severed ownership, state 
law varies on who owns the geologic formation or potential storage site 
that would sequester the CO2. In some states, the surface landowner 
owns the geological formation, but in others, the mineral rights owner 
owns the formation. Moreover, those geologic formations used for CO2 
storage that extend below surface lands could encompass the mineral 
rights of multiple owners. 

Aside from the question of who owns the storage site, it is also not 
clear who would actually own the CO2 once injected--the injector, the 
owner of the surface land, or the owner of the subsurface geologic 
formation--because few state laws or courts have yet to address the 
issue. Some state laws and courts, however, have recognized that 
injectors of natural gas retain ownership of that gas. 

Multiple stakeholders told us that this issue will be a much larger one 
as CCS projects are scaled up to commercial scale and move beyond 
existing enhanced oil recovery projects that inject smaller volumes of 
CO2 in order to extract additional oil from underground reservoirs. 
They noted that the CO2 plume, or pressure front created by injecting 
the CO2 underground, can cover tens to hundreds of square miles, 
affecting numerous property owners. According to one power company 
official, this property rights issue is different from liability- 
related issues, since it could prevent CO2 from being injected into the 
ground in the first place. If they cannot get access rights to the 
formation, they cannot do a project. 

Uncertainty Regarding How the Clean Air Act Will Apply to Power Plants 
with CCS: 

According to EPA air officials, the Clean Air Act's New Source Review 
(NSR) requirements apply to new power plants that are constructed with 
carbon capture technology and may apply to existing power plants that 
install the technology. NSR is triggered when a new facility is built, 
or when an existing facility makes a major modification, a physical or 
operational change that would result in a significant net increase in 
emissions. Under NSR, permitting authorities review the proposed 
facility or modification to establish emission limits and ensure the 
requisite pollution control technologies will be used before granting 
it a permit. Because of the additional energy required for carbon 
capture, EPA officials note that power plants implementing the 
technology might need to burn more coal to generate the same amount of 
electricity. If this increased coal usage resulted in a significant net 
increase of emissions of pollutants regulated under the act, such as 
ozone or sulfur oxide, NSR could be triggered. 

Some note that the NSR requirements, and the additional costs and 
uncertainties associated with them, may discourage facilities such as 
power plants from adopting CCS technology. For example, a recent report 
from a federal advisory committee to the Secretary of Energy states 
that "for existing coal-fired facilities, a major question is whether 
the Clean Air Act, including the NSR requirements of the Act, would 
apply if CCS equipment is installed."[Footnote 26] Multiple 
stakeholders we interviewed agreed that adding CCS equipment to an 
existing power plant could raise problems under NSR. One noted, in 
particular, that NSR challenges were manageable while CCS projects were 
at the demonstration scale but could pose greater problems when CCS is 
deployed at a larger scale. 

The Absence of a National Strategy to Control CO2 Emissions Gives 
Neither Industry Nor Government Agencies an Incentive to Invest in CCS: 

According to the IPCC, the National Academy of Sciences, and other 
knowledgeable authorities, another barrier is the absence of a national 
strategy to control CO2 emissions (emissions trading plan, CO2 
emissions tax, or other mandatory control of CO2 emissions), without 
which the electric utility industry has little incentive to capture and 
store its CO2 emissions. Moreover, according to key agency officials, 
the absence of a national strategy to control CO2 emissions has also 
deterred their agencies from resolving other important practical issues 
that will ultimately require resolution if CCS is to be deployed on a 
large scale. Such issues include lack of clarity regarding who owns 
injected CO2 and how stored CO2 will be addressed in a future emissions 
trading scheme. 

Industry Has Little Incentive to Invest in CO2 Control Technologies 
without a National Strategy to Control CO2 Emissions: 

A wide range of academic, industry, and other knowledgeable authorities 
agree that CCS is unlikely to be used to any substantial extent without 
some kind of national strategy to control CO2 emissions. The IPCC's 
2005 report on CCS observed, for example, that "all models indicate 
that CCS systems are unlikely to be deployed on a large scale in the 
absence of an explicit policy that substantially limits greenhouse gas 
emissions to the atmosphere. With greenhouse gas emission limits 
imposed, many integrated assessments foresee the deployment of CCS 
systems on a large scale within a few decades from the start of any 
significant climate change mitigation regime." It stated further that 
"the stringency of future requirements for the control of greenhouse 
gas emissions and the expected costs of CCS systems will determine, to 
a large extent, the future deployment of CCS technologies relative to 
other greenhouse gas mitigation options."[Footnote 27] 

EPA's Clean Air Act Advisory Committee's Advanced Coal Technology 
Workgroup similarly reported that widespread commercial deployment of 
advanced clean coal technologies, including large-scale CCS, likely 
will not occur without legislation that establishes a significant long- 
term "market driver." The majority of stakeholders we interviewed 
agreed, characterizing the absence of a national strategy to control 
CO2 emissions as a large or very large barrier to CCS deployment on a 
commercial scale, with many stating that without a price on emitting 
CO2, there is no rationale for utilities or other facilities to control 
their emissions. Moreover, according to a leading researcher,[Footnote 
28] "in order for significant progress to be made in reducing 
greenhouse gas emissions, some form of mandatory emissions limits or 
tax on greenhouse gases will be required, just as in every other area 
of environmental regulation where substantial costs of emission 
reductions must be borne." 

One indication as to how emitters might respond to a cost on CO2 
emissions was provided by a Norwegian petroleum company after Norway 
introduced a $40 per metric ton tax on offshore CO2 emissions in 1991. 
The Statoil petroleum company's Sleipner project, a natural gas 
processing project located at a gas field 250 kilometers off the coast 
of Norway, had already been removing CO2 from the natural gas to 
prepare it for sale on the open market. But with no financial incentive 
to do otherwise, Statoil had simply vented the CO2 into the atmosphere. 
At least partly in response to the tax, however, the company, in 1996, 
began to capture approximately 3,000 metric tons of CO2 per day from 
natural gas extraction and store it 800 meters under the North Sea's 
seabed in a geologic formation called a saline reservoir. 

The United States' experience with other pollutants, notably sulfur 
dioxide (SO2), also provides insights into the kind of market-based 
emissions control regime that could emerge if a national strategy to 
control CO2 emissions was adopted. In Title IV of the Clean Air Act 
1990 Amendments, Congress established a goal of reducing annual 
emissions of SO2 by 10 million tons from 1980 emissions levels. 
Specifically, the law established overall emission limitations and 
allocated SO2 emission allowances to individual electric utilities. The 
utilities are required to own enough allowances at the end of each year 
to cover their emissions. Under the law's allowance trading system, 
utilities can trade some or all their allowances in a way that allows 
them greater flexibility in achieving the required emission reductions 
at the lowest cost. In cases where utilities were able to reduce 
emissions below their required allowance, they were able to sell the 
extra allowances at the market price to other utilities. As with the 
SO2 program, analyses by government and academic organizations 
generally indicate that CCS technology will be more extensively used as 
emission limits tighten. 

An important lesson from the SO2 program was that as vendors competed 
to meet utilities' emission reduction needs, they were prompted to seek 
the least expensive means of providing utilities with low-sulfur coal, 
"scrubbers," and other methods for reducing sulfur dioxide emissions. 
[Footnote 29] As a result, the overall cost of reducing emissions 
decreased over time. More generally, a study commissioned by the IEA's 
Greenhouse Gas R&D Program emphasizes the decrease in costs of new 
technologies over time.[Footnote 30] It suggests that for new coal 
emission control technologies, the initial higher plant costs incurred 
are gradually reduced through experience and from continued research 
and development. 

The Absence of a National Strategy to Control CO2 Emissions Has 
Constrained the Federal Government's Efforts to Plan For and Develop 
CCS Projects: 

The absence of a national strategy to control CO2 emissions not only 
leaves the regulated community with little incentive to reduce their 
emissions, it also leaves regulators with little reason to devise the 
practical arrangements necessary to implement the reductions. For 
example, regulators have not addressed how utilities that capture and 
sequester CO2 would be treated under a future emissions trading plan. 
The EU's early experience with CO2 emissions trading illustrates the 
significance of including CCS in an emissions trading plan. EU 
officials told us when the Emissions Trading System (ETS) was 
conceived, the maturity of CCS as a technical reduction option for 
CO2was not clear. Therefore, CCS projects were not systematically 
included in the ETS.[Footnote 31] However, EU officials noted that the 
situation has changed substantially since then. Indeed, a recent 
European Commission report indicates that not systematically including 
CCS in the ETS may be one barrier to its deployment.[Footnote 32] 
Accordingly, the European Commission is now proposing legislation to 
explicitly include, after 2012, facilities involved in the capture, 
transportation, and storage of CO2 in the ETS. These facilities would 
then earn allowances for nonemitted CO2 and would have to surrender 
emissions allowances for any leakages of CO2 that occur. Consequently, 
EU officials told us that the proposed directive, when enacted, would 
remove this barrier. 

Likewise, cognizant agency officials responsible for U.S. programs have 
told us that they will not act on key CCS implementation issues prior 
to Congress establishing a national strategy to control CO2 emissions. 
For example, as noted earlier, the officials told us that uncertainty 
regarding property rights ownership stems from ambiguity over who owns 
the injected CO2, and it is similarly unclear what the government's 
potential liability might be for long-term storage of CO2 on federal 
lands. Bureau of Land Management (BLM) officials said they are aware of 
the issue and of the BLM's jurisdiction in the matter but told us they 
are looking to Congress for a solution before they will take any 
specific actions to address it. These officials also noted that while 
they do have authority to permit CO2 injections on federal lands that 
are solely for sequestration purposes, they are uncertain whether BLM 
has statutory authority to establish a funding mechanism for long-term 
management of sequestration sites on federal lands. 

Other practical issues requiring resolution, which cross the 
jurisdictions of a range of federal agencies and of state and local 
governments, are discussed later in this report. 

Federal Agencies Have Yet to Resolve the Full Range of Issues Requiring 
Resolution for Widespread CCS Deployment: 

While federal agencies have begun to address CCS barriers, they have 
yet to comprehensively address the full range of issues that would 
require resolution for widespread CCS deployment. DOE has achieved 
limited results in lowering the cost of CO2 capture at existing power 
plants, and the agency's focus on gasification technology to date may 
not provide for the needed reductions in emissions because few 
facilities with this technology currently exist. However, DOE's focus 
has recently shifted to better balance the need for capture technology 
at both new and existing power plants. EPA has recently issued a 
proposed rule that clarifies significant regulatory uncertainties 
related to CO2 injection and storage. However, critical questions 
remain about long-term liability for stored CO2. Elsewhere in the 
federal government, agencies have not addressed a number of issues that 
could delay CCS deployment. Among them are how CO2 pipeline 
infrastructure might be developed and how a future emissions trading 
plan would treat avoided CO2 emissions due to CCS. 

DOE Has Only Recently Prioritized Research to Help Control CO2 
Emissions from Existing Power Plants: 

DOE has identified IGCC technology as the key enabling technology for 
reducing CO2 emissions from newly constructed coal-fired power plants 
and has helped to develop and demonstrate IGCC technology. However, key 
assessments by the National Academy of Sciences and international 
organizations have raised questions about how the agency's focus on 
IGCC technology may have affected the broader effort to substantially 
reduce CO2 emissions from coal-based electricity generation because (1) 
as noted earlier, the outlook for widespread deployment of IGCC 
technology is questionable and (2) the agency's funding related to IGCC 
technology has substantially exceeded funding for technologies more 
applicable to reducing emissions from existing coal-fired power plants. 
DOE has recently started to focus greater attention on technologies 
more applicable to reducing emissions from existing power plants. 

DOE Has Achieved Some Advances with IGCC Technology: 

Consistent with DOE's emphasis on IGCC, the agency cites a number of 
accomplishments in advancing the technology, such as its support for 
two operational IGCC power plants, in Florida and Indiana, that produce 
substantial amounts of electricity, while also demonstrating the 
production of high-pressure syngas amenable to CO2 capture.[Footnote 
33] DOE also cites its contributions to the development of several IGCC-
related technologies, which would advance pre-combustion CO2 capture. 
Specifically, recent technological advances cited by the agency include 
successful fabrication and testing of a liquid membrane that is stable 
at high temperatures and that could be used for CO2 capture in IGCC 
plants, as well as a new material with CO2 separation potential for gas 
separation. Moreover, according to a published journal article with 
three DOE co-authors, advances in membranes may be significant in 
advancing CO2 capture because membranes are less energy intensive, 
compared to other separation techniques.[Footnote 34] Taken together, 
the National Academy of Sciences credits DOE's efforts in promoting 
IGCC technology, citing the agency's efforts to develop "a close 
working relationship with the industry to move the technology through 
the commercial demonstration stage."[Footnote 35] 

Looking ahead, DOE hopes to make further investments, and progress, in 
demonstrating IGCC's feasibility to capture CO2 through its FutureGen 
program, which aims to accelerate commercial deployment of IGCC or 
other advanced clean coal-based power generation technology with CCS. 
Moreover, under the restructured FutureGen program, DOE anticipates 
supporting demonstrations at more than one site. 

DOE Funding Decisions Reflect Agency's Focus on IGCC: 

DOE's progress, however, has required both significant time and 
resources. As the National Academy of Sciences noted, the development 
of an integrated IGCC system has been an important component of DOE's 
Fossil Energy Research Development and Demonstration program for more 
than 20 years, and between 1978 and 2000, DOE invested $2.3 billion in 
gasification technology.[Footnote 36] Moreover, DOE budget data 
indicate that in more recent years, the agency has continued to provide 
substantial funding for IGCC technology. Several Fossil Energy programs 
provide substantial support for developing IGCC technology, including 
the IGCC program, the FutureGen program, and the advanced turbines 
program. Together, these programs account for a significant share of 
Fossil Energy's overall budget. The Carbon Sequestration program also 
provides some additional funding for CO2 capture using IGCC technology. 

Developing an exact estimate of DOE funding for IGCC technology is 
challenging because the individual DOE programs pursue multiple 
objectives and funding categories have changed over time. However, an 
examination of DOE's budget information suggests that its support from 
1997 (the year the Carbon Sequestration program began) to present is 
likely on the order of hundreds of millions of dollars and probably in 
excess of $500 million. A DOE official within Fossil Energy 
acknowledged to us that "the bulk of coal program capture funding 
relates to gasification, particularly IGCC," although DOE officials 
said they are now focusing more attention on existing pulverized coal 
power plants. 

IGCC Technology's Potential for Reducing CO2 Emissions Is Uncertain: 

The payoff for this investment, however, will depend heavily on the 
extent to which IGCC technology is used in newly constructed power 
plants--both in the United States and worldwide. In this regard, the 
National Academy of Sciences said in a recent assessment that the 
Carbon Sequestration program "is taking on a relatively high overall 
risk to create technologies for commercial demonstration by 2012 in 
that it relies heavily on the successful deployment of full-scale IGCC 
plants." The report added that there are only a few IGCC plants 
operating worldwide and advanced, commercial-scale IGCC units are only 
in the design phase and have no CO2 sequestration.[Footnote 37] 

Moreover, as noted earlier, studies by the IEA, DOE, and the National 
Coal Council cite a number of compelling factors, such as the relative 
cost of IGCC plant construction and the limited operational experience 
worldwide with this relatively new technology, which may limit 
commercial deployment of IGCC technology. Several industry stakeholders 
we interviewed expressed concerns about using IGCC technology for 
electricity generation, including the cost of constructing IGCC plants 
and possible reliability concerns. For example, officials from one 
electric power company told us they thought high levels of CO2 capture 
at IGCC plants would necessitate the use of a turbine, which has not 
yet been commercially demonstrated. Looking ahead, the IEA's 2007 World 
Energy Outlook notes that "for IGCC to establish itself in the market, 
further development to bring down costs and improve operational 
flexibility is necessary." 

DOE Has Thus Far Achieved Limited Success in Reducing CO2 Emissions 
from Existing Power Plants: 

Until recently, DOE budget decisions reflected a view that IGCC 
technology offered greater potential to capture CO2 than technologies 
applicable to pulverized coal-fired power plants. As indicated earlier, 
DOE budget information we reviewed indicates substantial funding for 
IGCC technology, likely in the order of hundreds of millions of 
dollars. By comparison, DOE support for post-combustion CO2 capture 
technology, most applicable for existing plants, appears more limited, 
likely on the order of tens of millions of dollars. 

As noted earlier, DOE has cited a number of challenges that complicate 
efforts to capture CO2 emissions from pulverized coal-fired power 
plants, including the large volumes of gas that must be treated; trace 
impurities in the exhaust gas (such as particulate matter, sulfur 
dioxide, and nitrogen oxides) that can degrade the effectiveness of 
certain capture processes; and the high amount of energy needed to 
compress CO2 emissions. Among other things, a DOE study concluded that 
if CO2 capture were added to a pulverized coal-fired power plant that 
started operations in 2010, its cost of electricity production would 
increase by approximately 80 percent.[Footnote 38] 

These technological realities, however, are at odds with another 
reality anticipated by a number of organizations: these facilities will 
account for the vast majority of coal capacity in the United States and 
around the world in the near term. Accordingly, in past years, the 
agency has undertaken some initiatives to advance technologies to 
capture CO2 from these facilities and points to a number of 
accomplishments arising from these efforts. Among them, DOE researchers 
reported patenting a technique to capture CO2 from a coal-fired power 
plant's exhaust using ammonia, a technique planned for two capture 
demonstrations at power plants in Ohio and North Dakota. DOE officials 
also point to several other projects related to post-combustion CO2 
capture, including development of ionic liquids with greater absorption 
capacity for CO2 and development of sorbent technology for retrofitting 
existing pulverized coal plants. DOE officials also pointed to 
investments in two other challenging aspects of CO2 capture. One 
involves research to address one of the largest cost drivers, the cost 
of regenerating the absorbent. DOE officials also pointed to work on 
technologies to improve the efficiency of compressing CO2, a major cost 
factor in capturing CO2 at these facilities. 

Nonetheless, DOE's own analysis raises questions concerning the 
agency's progress in helping to reduce the cost of CO2 capture at 
pulverized coal power plants. For post-combustion CO2 capture, DOE 
officials indicated to us that the agency's current goal is to develop, 
by 2012, pilot-scale systems to capture 90 percent of CO2 at no more 
than a 35 percent increase in the cost of electricity production. 
However, it is noteworthy that this goal is to develop pilot-scale 
systems only; commercial-scale units will not come online until the 
2020 time frame. 

An assessment report recently published by DOE indicates the size of 
the challenge DOE faces in reducing the cost of capture. The study 
indicated that CO2 capture would increase the cost of electricity 
production by 77 percent at a pulverized coal power plant starting 
operation in 2010.[Footnote 39] A DOE official within Fossil Energy 
acknowledged to us that owners of existing pulverized coal power 
plants, under a future emissions trading arrangement, might choose to 
purchase carbon allowances, rather than pay for an expensive retrofit, 
and that plant age and other economic considerations will make the 
determination of whether a retrofit or another action, such as 
purchasing allowances, will occur. 

One contributing factor to DOE's limited progress in reducing CO2 
emissions from existing power plants is that it is a relatively lower 
priority for DOE. The National Academy of Sciences noted that the 
Carbon Sequestration program has focused on IGCC technology to achieve 
its goal of reducing the cost of carbon capture.[Footnote 40] Our 
examination of DOE's budget in recent years supports this view: 

* The Carbon Sequestration program has provided limited capture 
funding: DOE officials estimated the Carbon Sequestration program 
provided approximately $50 million in funding related to all types of 
CO2 capture from fiscal year 2002 to fiscal year 2007. While DOE 
officials were able to provide limited information quantifying 
precisely how this funding was split between post-combustion and pre- 
combustion capture, they indicated that the majority of it went toward 
the development of post-combustion and oxy-combustion capture 
technologies. DOE officials suggest that, historically, 20 percent of 
the Carbon Sequestration program's budget has gone toward capture, 
which DOE officials said allowed capture technology development to 
continue as DOE evaluated geologic storage of CO2. However, capture- 
related funding has generally received less funding in the Carbon 
Sequestration program's budget than other areas, such as the regional 
partnerships. 

* Post-combustion capture has not been supported by related programs: 
Until recently, post-combustion CO2 capture had not received large 
amounts of funding from other programs in Fossil Energy. Specifically, 
until fiscal year 2008, no other major Fossil Energy programs provided 
substantial funding related to post-combustion capture, in contrast to 
those programs' support for IGCC technology. 

DOE Has Recently Focused More Attention on Existing Plants: 

Looking ahead, DOE officials told us that the agency is now focusing 
more attention on reducing CO2 emissions from existing plants by 
shifting the focus of a related Fossil Energy program, the Innovations 
for Existing Plants program, so that it emphasizes the development of 
post-combustion capture of CO2. Among the factors cited in this 
decision were (1) the large number of pulverized coal power plants in 
the United States; (2) congressional direction in the report 
accompanying the agency's fiscal year 2008 appropriation to focus more 
attention on this issue; and (3) the applicability of advances in this 
area to the large number of pulverized coal power plants under 
construction in China and India. 

In February 2008, DOE announced that it was soliciting applications for 
projects "specifically focused on developing technologies for CO2 
capture and separation that can be retrofitted to existing pulverized 
coal (PC) power plants." In July 2008, the agency announced it was 
providing $36 million in funding for 15 projects to develop new and 
cost-effective capture technologies for existing power plants. 

Other recent changes in DOE's funding decisions also appear to 
recognize the significance of reducing emissions from existing power 
plants: 

* The Carbon Sequestration program's funding for post-combustion CO2 
capture (including oxyfuel combustion capture) increased from $10.1 
million in fiscal year 2007 to $15.4 million in fiscal year 2008. 

* The network of Regional Carbon Sequestration Partnerships appears to 
be placing more emphasis on demonstrations of CO2 capture at coal power 
plants for an upcoming series of large-scale sequestration projects. 
Specifically, a DOE official identified three projects being planned to 
capture CO2 from coal-fired power plants, including possibly capturing 
500,000 tons of CO2 from a coal-fired power plant in North Dakota. 

* DOE indicated in an August 2008 announcement that the agency's Clean 
Coal Power Initiative program would support coal-based technologies to 
capture and sequester CO2 emissions. For post-combustion CO2 capture, 
the announcement indicated that advanced technologies are sought to 
reduce the cost and additional power load of CO2 capture. 

While it seems too early to evaluate the results of DOE's increased 
focus on post-combustion CO2 capture, key organizations' assessments 
appear supportive of this shift. A 2008 National Coal Council report, 
for example, identifies retrofitting existing coal power plants with 
CCS as part of a larger approach to reducing emissions.[Footnote 41] In 
the same vein, the IPCC notes that the strategic importance of post- 
combustion capture systems becomes evident when one considers the large 
amount of emissions from pulverized coal power plants. 

EPA Has Begun to Address Regulatory Uncertainty Concerning CO2 
Injection and Storage, but Key Issues Remain Unresolved: 

As discussed earlier in this report, CCS stakeholders have stated that 
the absence of regulations governing large-volume CO2 injection and 
storage had created considerable uncertainty about the projects and 
risks associated with CCS. In an effort to address many of these 
concerns, EPA issued a proposed a rule in July 2008 to address 
permitting and other requirements for injection of CO2 for geologic 
sequestration. The proposed rule, issued under the agency's SDWA 
authority, clarifies a number of practical issues for prospective well 
owners and operators concerning CO2 injection and identifies certain 
requirements governing their financial responsibilities, including for 
the period after the CO2 is injected and the well is closed. However, 
as EPA officials note, the rulemaking was not intended to resolve many 
questions concerning how other environmental statutes may apply to 
captured and injected CO2, including the Clean Air Act, CERLCA, and 
RCRA. A number of key issues, therefore, have yet to be addressed. 

EPA Has Issued a Proposed Rule under the SDWA on Permitting Large- 
Volume CO2 Injections: 

EPA's July 2008 proposed rule creates a new "Class VI" well type for 
injection of CO2 for geologic sequestration. In doing so, it clarifies 
a number of issues relating to the more immediate, practical issues 
regarding CO2 injection for geological storage. However, some notable 
ambiguities remain, particularly in the area of longer-term financial 
responsibility requirements. The following summarizes both the issues 
that have been addressed and those which may still need to be 
clarified. In the discussion below, we provide the preliminary views of 
the stakeholders we interviewed. It is important to note, however, that 
the proposed rule's 120-day comment period runs until November 24, 
2008, during which time EPA will obtain a broader array of public 
advice and opinions on its proposed rule. 

Site characterization, well construction, and monitoring requirements. 
The proposed rule specifies a number of requirements concerning the 
location of the CO2 injection well, including (1) the criteria for 
characterizing the site of the geologic formation and (2) requirements 
for reviewing the wider geographic area surrounding the storage site 
prior to injection. Regarding site characterization, the well owner or 
operator must demonstrate that the well will be located in an area with 
a suitable geologic system, including a confining zone for the injected 
CO2 that is free of faults or fractures, that would contain the CO2. 
The proposed rule also specifies that injection of CO2 above the 
lowermost formation containing an underground source of drinking water 
is prohibited. Regarding the wider geographic area surrounding the 
storage site that may be impacted by the injection, it requires well 
owners and operators to delineate an Area of Review (AoR) within which 
the owner or operator must identify all penetrations, such as wells, 
that may penetrate the confining zone and determine whether the wells 
have been plugged in a manner that prevents the movement of CO2 or 
associated fluids that may endanger underground sources of drinking 
water. 

The proposed rule also includes standards for well construction, 
operation, and monitoring. For example, although EPA does not specify 
which materials must be used, the proposed rule does require the use of 
materials that meet or exceed industry standards, that are compatible 
with injected CO2, and that are designed for the life of the well. The 
proposed rule also contains an injection pressure limitation so that an 
injection does not create new fractures or cause movement of injected 
CO2 that endangers underground sources of drinking water. It requires 
continuous monitoring of injection pressure, rate, and volume, and 
requires semiannual reporting of this data to EPA. The proposed rule 
also requires well owners and operators to submit, with their permit 
application, a testing and monitoring plan to verify that the CO2 
storage project is operating as permitted and is not endangering 
underground sources of drinking water. 

The proposed rule also addresses stakeholder concerns about how current 
CO2 injection wells operating as Class I industrial wells, Class II 
injection wells that use CO2 for enhanced oil or natural gas 
extraction, and Class V experimental CO2 injection wells would be 
regulated if they transition to use for long-term storage. It specifies 
that owners of these existing wells may apply for the new Class VI 
permit and that the UIC program director would have the discretion to 
grandfather the well's pre-existing construction requirements if the 
director determined that doing so would not endanger underground 
sources of drinking water. With this exception, the project would have 
to meet all other Class VI requirements in order to obtain a Class VI 
permit. 

Financial responsibility requirements. EPA's proposed rule specifies 
that well owners and operators must demonstrate and maintain financial 
responsibility for corrective action (that is, repairs or other actions 
necessary to assure that wells within the AoR do not serve as conduits 
for the movement of fluids into underground sources of drinking water), 
well plugging, post-injection site care for a period of 50 years 
following cessation of injections, site closure, and emergency and 
remedial response. The UIC program director can adjust the 50-year time 
period for post-injection site care depending on whether the project 
poses an endangerment to underground sources of drinking water. If the 
UIC program director chooses to lengthen the post-injection site care 
time period, the owner and operator must continue to demonstrate 
financial responsibility until the end of that period. Although the 
financial responsibility demonstration requirement ends when the post- 
injection site care time period does, the proposed rule's preamble 
indicates that well operators remain responsible indefinitely for any 
endangerment of underground sources of drinking water. 

In addition to clarifying well site care, the proposed rule also 
requires that well owners and operators periodically update their cost 
estimate for corrective action, well plugging, post-injection site care 
and site closure, and emergency and remedial response, and that they 
redemonstrate financial responsibility for these increased costs as the 
UIC program director deems necessary. It also requires well owners and 
operators to notify the UIC program director of any adverse financial 
conditions they encounter, such as bankruptcy. 

While stakeholders acknowledge EPA's progress in clarifying some key 
financial responsibility requirements, they cite several other 
concerns: 

* Although EPA's proposed rule establishes a post-injection site care 
period, it does not include a provision allowing well operators to be 
released from liability for endangerment of underground sources of 
drinking water during the hundreds of years that CO2 will be stored in 
a geologic storage project. While it is beyond EPA's authority to 
release injection well owners and operators from liability, a 
discussion of long-term liability is included in the proposed rule's 
docket. Stakeholders told us that they were concerned by the 
unspecified period of time for which they may be liable for stored CO2. 

* The proposed rule only specifies a duty to demonstrate financial 
responsibility, stating that guidance will be developed at a later date 
describing the types of financial mechanisms that owners or operators 
can use. Currently, financial responsibility for other well classes is 
demonstrated through third-party instruments, such as a surety bond 
that establishes a trust fund, or self-insurance instruments, such as a 
corporate financial test. However, EPA's existing financial 
responsibility requirements have been criticized as inadequate and the 
agency is currently reviewing its approach. EPA is evaluating whether 
to revise its financial responsibility guidance in light of these 
criticisms and is seeking public comments on various financial 
responsibility topics. Moreover, EPA officials told us that the 
Miscellaneous Receipts Statute limits the financial responsibility 
regulations because it prevents EPA from requiring a cash deposit or 
receiving money as a trustee.[Footnote 42] The proposed rule's preamble 
also notes that EPA does not have the statutory authority to transfer 
financial responsibility from the well owner or operator to a third 
party. 

Finally, there is some question as to whether EPA will have sufficient 
resources to implement the expanded UIC program. EPA has not examined 
the level of resources that will be needed to administer the UIC 
program once commercial-scale deployment of CCS occurs. However, a 2007 
report by DOE's Argonne National Laboratory did examine the issue and 
concluded that if CO2 were stored in large enough volumes to have a 
meaningful impact on global warming, it is likely that thousands or 
tens of thousands of injection wells would need to be developed and 
permitted in the United States. The report noted that this would 
require that state and regional UIC programs expand their staff and 
capabilities. In this connection, it observed that the annual national 
budget for the UIC program--approximately $11 million--has remained 
static for many years, even as UIC agencies have been asked to take on 
additional responsibilities. It warned that failure to provide 
sufficient resources would likely create permitting backlogs, resulting 
in a bottleneck in the overall carbon sequestration effort. 

Multiple stakeholders agreed that EPA needs additional resources for 
the UIC program, including permit writers. One industry representative 
expressed concern that it can take up to 2 years to obtain a permit for 
a well under EPA's UIC program, and that if CCS projects become more 
widespread, EPA will be responsible for permitting thousands of 
additional injection wells. 

Key Legal and Regulatory Issues outside of the SDWA Have Been Largely 
Unaddressed: 

While EPA has addressed at least some of the legal and regulatory 
issues on how CO2 injectors are to protect underground sources of 
drinking water, it has thus far not resolved a number of key 
environmental issues that fall under the jurisdiction of other 
statutes, including the Clean Air Act, RCRA, and CERCLA. 

Clean Air Act. As noted earlier, the Clean Air Act's New Source Review 
(NSR) requirements could be triggered if an existing facility's 
installation of capture technology makes a major modification that 
significantly increases emission of regulated pollutants. EPA officials 
acknowledge concerns that NSR could cause delays and impose added costs 
to CCS projects. However, they said that an assessment of how NSR might 
impact the feasibility of CCS projects cannot be made globally because 
it depends on site-specific factors, such as geological and 
hydrological considerations, the CCS technology that will be used, how 
it will operate, and how that operation could affect the rest of the 
plant. 

Laws governing hazardous wastes and substances. RCRA and CERCLA could 
pose similar complications for CCS projects. RCRA authorizes EPA to 
establish regulations governing the treatment, storage, and disposal of 
hazardous waste. A hazardous waste is generally defined as a solid 
waste that either (1) exhibits certain characteristics (ignitability, 
corrosivity, reactivity, or toxicity) or (2) has been listed as a 
hazardous waste by EPA. CERCLA established the Superfund program to 
clean up sites that have been contaminated by hazardous substances. 
CERCLA authorizes EPA to compel the parties statutorily responsible for 
the hazardous substances to bear the costs of cleaning up the 
contaminated site or to carry out cleanups itself and recover costs 
from the responsible parties. Hazardous substances are those which may 
present substantial danger to the public health, welfare, or 
environment when released and include all hazardous wastes subject to 
RCRA. 

Whether any given injected CO2 stream is categorically a hazardous 
waste or hazardous substance has not been resolved by EPA. The preamble 
to EPA's proposed rule notes that pure CO2 in and of itself is not 
listed as a hazardous substance under CERCLA. However, the rule's 
preamble cautions that injected CO2 streams could contain hazardous 
constituents that would make these streams "hazardous."[Footnote 43] It 
notes that since the chemical composition of individual injected CO2 
streams vary, no categorical determination can be made as to whether 
all injected CO2 streams are hazardous wastes. Accordingly, the 
preamble says that it will be up to the well owners and operators to 
make this determination on the basis of their particular circumstances. 
EPA officials said that they lacked the information about the 
composition of CO2 streams captured from coal-fired power plants 
necessary to determine whether those streams should categorically be 
listed as a hazardous waste under RCRA. 

Thus, considerable uncertainties over how owners and operators of CCS 
projects would be treated under key environmental laws other than the 
SDWA remain unresolved. An EPA federal advisory committee working group 
had emphasized, in particular, that the EPA address the liability 
implications concerning CO2 injection under RCRA and CERCLA.[Footnote 
44] However, the proposed rule is unclear as to whether the two laws 
even apply to injected CO2, and it is therefore uncertain whether 
injectors will be subject to hazardous waste disposal requirements and 
liability for hazardous substance releases. 

Other Key Issues That Should Be Proactively Addressed to Support a 
National CCS Framework: 

In addition to the technical and legal issues affecting CCS's 
prospects, key studies, federal advisory committees, and the 
stakeholders we interviewed also identified an array of other issues 
that would need to be resolved if the technology is to be deployed 
within a time frame scientists believe is needed to address climate 
change. Moreover, whereas many of the technical and regulatory issues 
discussed earlier fall within the domain of two agencies (DOE and EPA), 
these other issues cross the jurisdictions of the Departments of the 
Interior and Transportation, the Federal Energy Regulatory Commission, 
and other agencies in a manner that would require collaboration between 
agencies and, in many cases, coordination with state governments and 
other entities. 

Property Rights and Liability Issues Related to CO2 Injection on Both 
Federal and Nonfederal Lands: 

Under a national CCS program, CO2 could be sequestered on both federal 
and nonfederal lands and would raise complex property rights issues 
needing resolution in both instances. In the case of federal lands, 
BLM, which manages the federal government's mineral resources, is 
required by the Energy Independence and Security Act of 2007[Footnote 
45] to report by December 2008 on a framework to manage geological 
carbon sequestration activities on public lands. According to BLM 
officials, the report will include a discussion of the unresolved 
property ownership and liability issues related to long-term CO2 
storage. They note that the report will also discuss the statutory 
authority BLM currently has and what it lacks, such as the authority to 
establish a funding mechanism for monitoring and mitigation efforts 
associated with sequestration sites. They cautioned, however, that the 
report will not recommend solutions to current uncertainties and 
explained that since injected CO2 can move onto adjacent private or 
state lands, resolving them will require collaboration with private 
landowners and state agencies. 

Nationwide CO2 sequestration would also pose major challenges on 
nonfederal lands. EPA notes that states with primacy for the UIC 
program have typically addressed such challenges when they have arisen 
under that program. The agency acknowledged the additional 
complications that would arise as stored CO2 crossed state boundaries, 
but noted that such cross-jurisdictional issues typically occur under 
the UIC program and that states have worked together to address them. 
Nonetheless, the significantly larger scale of a future CCS program 
could magnify the problems posed by these jurisdictional issues. EPA 
officials noted that they are hoping that the proposed rule's comment 
process will surface ideas to address these problems. However, EPA 
officials also note that the agency lacks authority to issue 
regulations resolving these issues. 

Furthermore, while EPA's proposed rule reaffirms liability related to 
underground sources of drinking water, ambiguity remains regarding who-
-the injector or the property owner--is ultimately responsible for 
unanticipated releases of the injected CO2 that have other effects. As 
discussed earlier, the released CO2 could interfere with the adjacent 
mineral owners' abilities to extract those resources, and the injection 
well's operator could be held liable for nuisance, trespass, or another 
tort. 

CO2 Pipeline Regulation: 

Pipelines are the preferred method of transporting large amounts of 
CO2. The Department of Transportation's Pipeline and Hazardous 
Materials Safety Administration (PHMSA) administers safety regulations 
for CO2 pipelines that affect interstate commerce and certifies states 
that have adopted regulations compatible with the minimum federal 
safety standards to regulate their intrastate pipelines. No federal 
agency has claimed jurisdiction over siting, rates, or terms of service 
for interstate CO2 pipelines.[Footnote 46] However, early assessments 
indicate that a nationwide CCS program could require a network of 
interstate CO2 pipelines that would raise cross-jurisdictional issues 
and involve multiple regulatory authorities--all in the unprecedented 
context of a nationwide program to transport massive volumes of CO2. 

Neither the Federal Energy Regulatory Commission (FERC) or Surface 
Transportation Board (STB) currently regulate interstate CO2 pipelines 
and have not developed any guidance for possible regulation because, 
according to agency officials, neither agency has statutory authority 
to do so. FERC has the statutory authority to regulate the siting, 
rates, and terms of service for interstate pipelines transporting 
natural gas, which is defined as "natural gas unmixed or any mixture of 
natural and artificial gas."[Footnote 47] FERC has interpreted this 
statutory language to mean a gaseous mixture of hydrocarbons that is 
used as a fuel.[Footnote 48] According to FERC officials, under this 
interpretation, CO2 pipelines fall outside of the commission's 
jurisdiction.[Footnote 49] According to the FERC Chairman's 
congressional testimony, he would not recommend that Congress preempt 
the states on CO2 pipelines because state siting has not been a 
failure, unlike the situation that led to federal preemption of natural 
gas pipeline siting.[Footnote 50] FERC officials noted that the 
commission could have a prospective role in regulation of CO2 
pipelines, which could be modeled on its natural gas transport and 
storage work, but that it would need statutory authority to take such a 
role. 

The STB has statutory jurisdiction over pipelines that transport a 
commodity "other than water, gas, or oil."[Footnote 51] STB's 
predecessor, the Interstate Commerce Commission, interpreted its 
organic statute as excluding all gas types (including CO2), regardless 
of origin or source, from its jurisdiction.[Footnote 52] Therefore, the 
commission concluded that it lacked jurisdiction over interstate CO2 
pipelines. STB staff told us that if a party sought reconsideration of 
the prior decision disclaiming jurisdiction over interstate CO2 
pipelines, the board would consider re-examining the commission's 
earlier decision. 

While neither FERC nor STB has developed guidance for the regulation of 
interstate CO2 pipelines, the stakeholders we interviewed had differing 
views on whether federal regulation of CO2 pipelines should be 
expanded. Several stakeholders thought it would be necessary for the 
federal government to take a more active role in siting issues and CO2 
pipeline rates. On the other hand, several other stakeholders expressed 
concern that expanding federal regulation could have unintended 
consequences. For example, one industry stakeholder told us that 
regulating pipeline rates could discourage investment in new pipelines. 

Other factors may need to be considered for CO2 pipelines that cross 
federal lands managed by BLM. According to stakeholders, one key 
question will be whether new CO2 pipelines should operate as common 
carriers under federal law. As common carriers, pipelines' terms of 
service would need to be just, reasonable, and nondiscriminatory. Under 
the Federal Land Policy Management Act, BLM has the authority to grant 
rights-of-way for pipelines across federal lands but not to require 
them to operate as common carriers. In addition, BLM officials told us 
they are not assessing the rights-of-way on federal lands for CO2 
pipelines because their current statutory authority for rights-of-way 
is sufficient. 

DOE's Southwestern and West Coast Regional Carbon Sequestration 
Partnerships are presently conducting a CO2 pipeline study, in 
conjunction with MIT and Sandia National Laboratories, which may inform 
the discussion about future CO2 pipelines. According to DOE officials, 
the report will be issued next year. The officials note that it is not 
clear whether the report will address all of the relevant issues, 
including regulatory jurisdiction and siting decisions.[Footnote 53] 

Detailed Assessment of Feasible CO2 Storage Sites: 

In recent years, DOE has worked with state geologic survey offices and 
other partners to construct a national carbon sequestration geographic 
information system that provides information that can be used to 
evaluate the potential for CO2 geologic sequestration across the United 
States. However, knowledgeable authorities agree that a more detailed 
evaluation of these sites' actual capacity is needed. As figure 4 
shows, the geology of much of the United States may be well suited for 
CO2 sequestration. However, a more detailed evaluation would determine 
whether these potential sites are actually appropriate for long-term 
CO2 sequestration. For example, it is currently not known whether the 
caprock overlying these geologic formations is sufficient to contain 
stored CO2. 

Figure 4: Potential Geologic Storage in the United States: 

[See PDF for image] 

This figure is a map of the continental United States with potential 
geologic storage areas indicated by shading. 

Source: GAO analysis of DOE data. 

[End of figure] 

The Energy Independence and Security Act of 2007[Footnote 54] requires 
the U.S. Geological Survey (USGS) to develop a methodology for, and 
conduct an assessment of, the capacity for sequestration of CO2 in the 
United States. USGS officials explained that their approach will be to 
explore geologic formations at the individual sedimentary basin level, 
and they will take storage integrity and injectivity into account. They 
plan to begin with oil and gas reservoirs because these are the most 
familiar geologic formations in terms of the integrity of the 
reservoirs and their ability to store CO2. USGS officials will then 
assess saline formations, about which less data are available. 
According to USGS officials, the methodology should be completed by 
March of 2009, at which time it will be released for external technical 
review and public comment. Following any needed revisions to the 
methodology and receipt of funding, the USGS will proceed with the 
actual assessment. 

Potential Public Opposition Arising from Health Concerns over CO2 
Storage and Transport: 

According to the preamble to EPA's proposed rule, improperly operated 
injection activities or ineffective long-term storage could result in 
release of injected CO2 to the atmosphere, resulting in the potential 
to impact human health. EPA's summaries of stakeholder workshops 
indicate that public health concerns have been expressed about such 
issues. One concern is the risk that improperly operated injections 
could result in the release of CO2, and that at very high 
concentrations and with prolonged exposure, CO2 can lead to 
suffocation. Concerns have also been raised that improperly injected 
CO2 could raise the pressure in a geologic formation and, if it became 
too high, could cause otherwise dormant faults to trigger seismic 
events, such as earthquakes. The IPCC has noted, however, that 99 
percent of the CO2 stored in appropriately selected and managed 
formations is very likely to be retained for over 100 years,[Footnote 
55] and EPA states in the preamble to its proposed rule that the risk 
of asphyxiation and other health effects from airborne exposure to CO2 
resulting from injection activities is minimal. 

Thus far at least, there has been little public opposition to the CO2 
injections that have taken place in states such as Texas to enhance oil 
recovery. However, several notable studies explain that this lack of 
publicly-expressed concern may reflect more a lack of knowledge about 
CCS rather than confidence that the process is safe.[Footnote 56] This 
is suggested in the IPCC's 2005 report on CCS which stated, for 
example, that there is insufficient public knowledge of climate change 
issues and of the various mitigation options and their potential 
impact. In another 2005 study, researchers surveyed 1,200 people, 
representing a general population sample of the United States, and 
found that that less than 4 percent of the respondents were familiar 
with the terms carbon dioxide capture and storage or carbon storage. 

Some of the stakeholders we interviewed explained that public 
opposition could indeed grow when CCS extends beyond the relatively 
small projects used to enhance oil and gas recovery, to include much 
larger CO2 sequestration projects located in more populated areas. One 
noted, in particular, that a lack of education about CCS's safety could 
potentially create confusion and fear when commercial-scale CCS is 
implemented. 

Citing such concerns, a recent report by the National Academy of 
Sciences underscored the importance of public outreach, noting that 
while the success of DOE's carbon capture program depends heavily on 
its ability to reduce the cost of the technology, "the storage program 
cannot be successful if a significant fraction of the public views it 
as dangerous or unacceptable. Thus, the technologies must not only be 
safe and effective, they must be explainable to the public and the 
regulatory community in such a way as to instill confidence that they 
are in fact safe and effective."[Footnote 57] The report went on to 
caution that "the federal government in general and the DOE in 
particular have not had a good track record in accomplishing this task 
in other programs." For its part, EPA received similar advice from its 
Clean Air Act Advisory Committee's Advanced Coal Technology Work Group. 
The Work Group's January 2008 report recommended that the agency 
immediately develop, in consultation with other agencies, a public 
outreach effort to explain carbon capture and sequestration.[Footnote 
58] A diverse group of panel members at EPA's 2007 UIC workshop made 
similar recommendations for public outreach and participation. 

Accounting System for Measuring CO2 Stored by CCS for Use in a CO2 
Emissions Trading Plan: 

According to a recent federal advisory committee report, an accounting 
system, or protocol, will be needed to quantify the CO2 emissions from 
CCS. The accounting protocol could clarify uncertainty related to 
monitoring, reporting, quality assurance and control, and cross-border 
issues. Establishing this protocol would be a necessary step to 
integrate projects that prevent CO2 from being emitted to the 
atmosphere into a future regulatory regime that addresses climate 
change. The advisory committee report also notes that the IPCC has 
released national greenhouse gas inventory guidelines for CO2 capture, 
transport, injection, and storage, and that a comprehensive CCS 
accounting protocol developed by EPA and other agencies would provide 
needed guidance for applying IPCC Guidelines in the United States. 

The European Union's experience suggests that in planning for future 
CCS deployment, it is important to address such practical issues early 
in the process, particularly how to address reductions in emitted CO2 
achieved by CCS. Specifically, the European Commission proposes to 
revise the EU ETS to include CO2 capture facilities, pipelines, and 
storage sites. A European Commission report acknowledges that 
resolution of this important practical matter is important to remove 
barriers to future CCS deployment.[Footnote 59] Although EU member 
states can seek to include CCS projects in their national emissions cap 
by gaining approval from the European Commission on a case-by-case 
basis, proposed legislation would explicitly include, after 2012, 
facilities involved in the capture, transportation, and storage of CO2 
in the ETS. These facilities would then earn allowances for nonemitted 
CO2 and would have to surrender emission allowances for any leakages of 
CO2 that occur. 

Thus far, EPA's Office of Air and Radiation has begun to develop a rule 
requiring mandatory reporting of greenhouse gas emissions from all 
sectors of the economy.[Footnote 60] The agency is not, however, 
developing a protocol clarifying how emissions avoided as a result of a 
CCS project would be measured, nor how a future emissions trading plan 
would treat the avoided emissions. EPA officials explained that, given 
the pressure of other priorities, they would only develop such a 
protocol when mandated by Congress to do so. However, they noted that 
such an accounting system would be closely linked to the design of 
voluntary programs, future policies, and regulations to reduce 
greenhouse gas emissions. 

Conclusions: 

Recent federal and international assessments indicate that the United 
States will need to rely on CCS as an essential mitigation option to 
achieve appreciable reductions in greenhouse gas emissions. Federal 
agencies whose action--or inaction--will greatly affect the prospects 
for timely CCS deployment have taken early steps that address some 
barriers to CCS, but have left critical gaps that impede our 
understanding of CCS's full potential for reducing CO2 emissions and 
that could affect CCS deployment on a broader scale. 

DOE has invested heavily in advancing CCS in IGCC plants, but 
knowledgeable authorities agree that these facilities will account for 
only a small percentage of power plants' CO2 emissions in the next 
several decades to come. DOE has recently begun to shift its approach 
in a way that also emphasizes development of CCS technology for 
existing coal-fired power plants. Given the broad consensus that the 
technology used by these plants will dominate coal-fired power plant 
capacity for the next several decades--both in the United States and 
around the world--we believe the agency should continue this trend. EPA 
has begun to address some of the regulatory uncertainties under the 
SDWA that will need resolution for a national CCS program to move 
forward, but other key issues associated with other environmental 
statutes--such as RCRA, CERCLA, and the NSR provisions of the Clean Air 
Act--have not been addressed. 

In addition to these key barriers, there is an array of other issues 
that would need to be resolved if the technology is to be deployed 
within a time frame scientists believe is needed to address climate 
change. Moreover, whereas many of the technical and regulatory issues 
discussed earlier fall within the domain of two key agencies (DOE and 
EPA), these other issues cross the jurisdictions of the Departments of 
the Interior and Transportation, FERC, and other agencies in a manner 
that would require collaboration between agencies and, in many cases, 
coordination with state governments and other entities. While the DOE- 
led CCTP coordinates climate change technology research, development, 
demonstration, and deployment among federal agencies, it has not been 
tasked with resolving the issues of CO2 pipeline regulation and 
infrastructure and liability for stored CO2, among other issues. 
Furthermore, officials from relevant offices within the Departments of 
the Interior and Transportation told us they have not yet been invited 
to participate in CCTP discussions. 

Recommendations for Executive Action: 

We recommend that the Secretary of Energy direct the Office of Fossil 
Energy to continue its recent budgetary practice of helping to ensure 
that greater emphasis is placed on supporting technologies that can 
reduce greenhouse gas emissions at existing coal-fired power plants. 

We recommend that the Administrator of EPA more comprehensively examine 
barriers to CCS development by identifying key issues that fall outside 
the agency's SDWA authority. Specifically, we recommend that the 
Administrator direct the cognizant EPA offices to collectively examine 
their authorities and responsibilities under RCRA, CERCLA, and the 
Clean Air Act for the purposes of (1) obtaining the information 
necessary to make informed decisions about the regulation of (and 
potential liabilities associated with) the capture, injection, and 
storage of CO2; (2) using this information to develop a comprehensive 
regulatory framework for capture, injection, and underground storage of 
CO2; and (3) identifying any areas where additional statutory authority 
might be needed to address key regulatory and legal issues related to 
CO2 capture, injection, and storage. 

We recommend that the Executive Office of the President establish an 
interagency task force (or other mechanism as deemed appropriate) to 
examine the broad range of issues that, if not addressed proactively, 
could impede large-scale commercial CCS deployment and to develop a 
strategy for cognizant federal agencies to address these issues. Among 
the issues this task force should examine are: (1) identifying 
strategies for addressing regulatory and legal uncertainty that could 
impede the use of federal lands for the injection, storage, and 
transport of CO2; (2) examining how any regulation of carbon emissions 
will address leakage of stored CO2 into the atmosphere; (3) developing 
an accounting protocol to quantify the CO2 emissions from capture, 
transport, injection, and storage of CO2 in geologic formations; (4) 
examining CO2 pipeline infrastructure issues in the context of 
developing a large-scale national CCS program; (5) developing a public 
outreach effort to explain CCS; (6) evaluating the efficacy of existing 
federal financial incentives authorized by the Energy Policy Act of 
2005 and other relevant laws in furthering the deployment of CCS; and 
(7) examining the federal and state resources required to implement the 
EPA's expanded UIC program incorporating commercial-scale CCS. 

Agency Comments and Our Evaluation: 

We provided a draft of this report to the Secretary of DOE and the EPA 
Administrator for review and comment. DOE's September 9, 2008, letter 
first "commend[s]… the comprehensiveness of this study, including the 
analysis of potential barriers to widespread commercialization of CCS 
and the potential need for involvement by multiple Federal agencies." 
The letter's subsequent comments are also consistent with the report's 
recommendations that (1) DOE continue to place greater emphasis on 
pursuing increased funding for CO2 emissions control technologies for 
existing coal-fired power plants and (2) an interagency task force be 
established to examine critical CCS issues and develop a comprehensive 
CCS strategy. However, the agency expressed disagreement with our 
rationale for placing greater emphasis on CCS technologies applicable 
to these facilities and suggests a different approach for the 
interagency task force we recommended: 

* Placing greater emphasis on existing coal-fired power plants. DOE 
says that while it agrees with the report's findings concerning the 
importance of pursuing CCS options for existing coal-fired power 
plants, these findings incorrectly imply "that DOE has focused too 
heavily on the IGCC option for new plants at the expense of retrofit 
opportunities." We are not second-guessing decisions DOE made in past 
decades. Rather, we are concerned about how the agency can best move 
forward in light of the new emphasis on substantially reducing CO2 
emissions and the scientific consensus that CCS will be needed to help 
reduce emissions. 

* Establishing an interagency CCS Task Force. DOE maintained that a 
coordinating body--the DOE-led CCTP--already addresses these kinds of 
issues. However, the CCTP's scope focuses on technology; it does not 
address legal and institutional issues such as the resolution of CO2 
pipeline regulation and infrastructure or liability for stored CO2, 
among others. In addition, officials from cognizant offices within the 
Departments of the Interior and Transportation told us they have not 
yet been invited to participate in CCTP discussions. Moreover, we 
continue to believe that a more centralized task force, with a broader 
scope than the technology-focused CCTP, may be a preferable 
alternative. 

DOE's letter appears in appendix II, along with our responses to each 
of its main points. The agency separately provided technical comments, 
which were incorporated in our final report, as appropriate. 

EPA's September 12, 2008, letter stated that providing regulatory 
certainty on issues related to geological storage of CO2 was a high 
priority for the agency and agreed with the intent of our 
recommendation--to provide clarity on how the broader range of statutes 
within the agency's jurisdiction may apply. The agency noted that it 
had made an initial effort to identify and discuss these issues in the 
preamble of its July 2008 proposed rulemaking and had requested 
comments on many SDWA topics--including some of those identified in our 
report. It said it expected further progress on these SDWA topics after 
receiving input from stakeholders during the comment period (which 
extends through November 24, 2008). EPA did not respond to the 
recommendation that an interagency task force be established to examine 
critical CCS issues and to develop a comprehensive CCS strategy. The 
agency also offered several other comments and clarifications, which 
are presented in appendix III, along with our responses. 

We are sending copies of this report to the Administrator of EPA; the 
Secretary of Energy; the House Select Committee on Energy Independence 
and Global Warming; appropriate congressional committees; and other 
interested parties. We will also make copies available to others on 
request. 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 me at (202)512-3841 or stephensonj@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 
are listed in appendix IV. 

Sincerely yours, 

Signed by: 

John B. Stephenson: 
Director, Natural Resources and Environment: 

[End of section] 

Appendix I: Objectives, Scope, and Methodology: 

We were asked to examine (1) the key economic, legal, regulatory, and 
technological barriers impeding commercial-scale deployment of carbon 
capture and storage (CCS) technology and (2) the actions federal 
agencies are taking to overcome barriers to or facilitate the 
commercial-scale deployment of CCS technology. 

To determine the key economic, legal, regulatory, and technological 
barriers impeding commercial-scale deployment of CCS, we reviewed 
assessments by the Intergovernmental Panel on Climate Change, the 
National Academy of Sciences, federal agencies, nongovernmental 
organizations, and academic researchers. We also contacted a 
nonprobability sample of stakeholders from industry, including 
officials from electric power companies and oil and gas companies, as 
well as stakeholders from nongovernmental organizations and academic 
researchers. We selected major U.S. energy producing companies, as well 
as organizations and researchers that participate actively in ongoing 
dialogues on CCS. We also selected a number of smaller companies and 
organizations to ensure that we obtained a broader range of 
perspectives on key issues.[Footnote 61] We used a semistructured 
interview guide to interview these stakeholders and facilitate analysis 
of what stakeholders identified as key economic, legal, regulatory, and 
technological barriers impeding commercial-scale deployment of CCS. To 
obtain federal agency officials' perspectives on key economic, legal, 
regulatory, and technological barriers, we conducted interviews with 
officials from the Department of Energy's (DOE) Office of Fossil 
Energy, the Environmental Protection Agency's (EPA) Office of Ground 
Water and Drinking Water and Office of Air and Radiation, as well as 
other agencies, primarily in the Department of the Interior and 
Department of Transportation. 

To examine the actions federal agencies are taking to overcome barriers 
to or facilitate the commercial-scale deployment of CCS technology, we 
conducted interviews with officials from the DOE's Office of Fossil 
Energy and the EPA's Office of Ground Water and Drinking Water and the 
Office of Air and Radiation to assess these agencies' efforts to 
overcome barriers to or facilitate the commercial-scale deployment of 
CCS. Moreover, we reviewed a report by the National Academy of Sciences 
assessing DOE's Fossil Energy research and development programs. We 
reviewed reports made by two federal advisory committees, the National 
Coal Council advising the Secretary of Energy and the Clean Air Act 
Advisory Committee advising the EPA Administrator, and asked agency 
officials how they were implementing recommendations contained in these 
reports. We obtained and analyzed 12 years of DOE budget information, 
from fiscal year 1997 through the present, to assess the funding DOE 
has provided for various CO2 capture related technologies. We reviewed 
the proposed EPA rule for the underground injection of CO2 for geologic 
sequestration under the Safe Drinking Water Act. To obtain perspectives 
from outside the government, using the methodology described above we 
contacted a nonprobability sample of stakeholders and used a 
semistructured interview guide to facilitate an aggregate analysis of 
stakeholders' assessments of the actions of federal agencies. To assess 
the extent to which other federal agencies are overcoming barriers to 
or facilitating the commercial-scale deployment of CCS technology, we 
also conducted interviews with officials from federal agencies in the 
Department of the Interior and Department of Transportation (DOT), 
including the U.S. Geological Survey, Bureau of Land Management, 
Surface Transportation Board, and DOT's Pipeline and Hazardous 
Materials Safety Administration, as well as the Federal Energy 
Regulatory Commission. To assess the role of the Climate Change 
Technology Program (CCTP) in coordinating CCS-related activities across 
federal agencies, we interviewed a senior CCTP official and asked 
officials at several federal agencies about their involvement in CCTP 
activities. Finally, we attended two stakeholder workshops the EPA held 
concerning development of proposed regulations for the underground 
injection of CO2 for geologic sequestration under the Safe Drinking 
Water Act. 

We conducted this performance audit from October 2007 to September 2008 
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: Comments from the Department of Energy: 

Note: GAO comments supplementing those in the report text appear at the 
end of this appendix. 

Department of Energy: 
Washington, DC 20580: 

September 9, 2008: 

Mr. John B. Stephenson, Director: 
Natural Resources and Environment: 
U.S. Government Accountability Office: 
441 G Street, NW, Room 2T47: 
Washington, D.C. 20548: 

Dear Mr. Stephenson: 

Thank you for the opportunity to review and submit comments on the GAO 
draft report: Federal Actions Will Greatly Affect the Viability of 
Carbon Capture and Storage As a Key Mitigation Option (GAO-08-1080). 

We commend GAO for the comprehensiveness of this study, including the 
analysis of potential barriers to widespread commercialization of CCS 
and the potential need for involvement by multiple Federal agencies. 

Regarding GAO findings related to DOE's CCS research, development and 
demonstration (RD&D) activities, we agree with the report's finding 
concerning the importance of pursuing CCS options for the sizeable 
existing coal power plant fleet. However, we do not believe that GAO 
has correctly assessed the significance and priority
of other major components of DOE's CCS program, such as the integrated 
gasification combined cycle (IGCC) technology. The report states that 
most coal-related emissions will come from existing plants "for many 
years to come." It further notes that finding for the IGCC Program has 
been much greater that that for the RD&D applicable to existing 
pulverized coal power plants, the implication being that DOE has 
focused too heavily on the IGCC option for new plants at the expense of 
retrofit opportunities. That is not correct. [See comment 1] 
emissions for new plants that could be in service for 50 years cannot 
be ignored, and current trends indicate that globally many new coal 
power plants will continue to be built in coming decades. Of the
various options for combining new coal power plants with CCS, systems 
analysis suggests that advanced IGCC subsystems being developed in the 
DOE program can lead to a dramatic reduction in the overall costs of 
CCS systems. With the addition of lower-cost approached under 
development for capturing CO2 in IGCC plants, IGCC/CCS systems have the 
potential to be the lowest-cost CCS option for coal power plants. The 
goal is to drive CCS cost sufficiently low to encourage large 
developing countries such as China and India to eventually deploy CCS 
as they continue to build their economic expansion on their large, 
domestic coal resource bases. If these countries do not adopt CCS in a 
timely manner, it may not be possible to reduce greenhouse gas 
emissions sufficiently to limit atmospheric concentrations of GHGs to 
acceptable levels. [See comment 2] 

The GAO report supports increased funding for CCS retrofit 
applications, including DOE's recent increased funding requests. These 
funding requests, however, are not the result of recent changes in 
DOE's CCS priorities (which should be sustained), as suggested in the 
report. ALthough DOE funding for CO2 CCS was relatively modest as 
recently as FY 2000, significant work has been underway for much of 
DOE's CCS program history on CO2 capture technologies, including 
retrofit applications. These technologies were in their infancy when 
work first started, and it is important to thoroughly investigate such 
technologies at smaller scale for an extended period before it can be 
determined if larger-scale testing is justified. As a result, capture 
funding has been relatively modest, but is expected to increase as 
promising options are ready to be scaled up. [See comment 3] 

The GAO report also raises the question of priorities based on 
significantly higher current DOE funding for CO2 storage versus capture 
activities. This funding difference again reflects where different 
activities are in the RD&D funding pipeline. CO2 storage technology is 
built on decades of petroleum industry experience, and this has allowed 
work in this area to progress rapidly to field testing. Field testing 
is expensive, particularly due to the cost of CO2, and thus storage 
activities currently account for a relatively large share of the 
Sequestration Program budget. [See comment 4] 

Finally, regarding the GAO recommendation that an interagency task 
force be established to develop a strategy addressing CCS 
commercialization barriers, addressing such barriers is already an 
important focus of the existing interagency U.S. Climate Change 
Technology Program. This program is lead by DOE, has an experienced 
staff, resources, and includes representation from relevant Federal 
agencies. CCTP was authorized by the Energy Policy Act of 2005, Title 
XVI, and directed to develop such strategies, and work is underway. The 
recommended strategy could be carried out under this Program without 
the organizational and delay issues that would likely occur if a new 
group were constituted to address the complex task being proposed. [See 
comment 5] 

Additional general and detailed comments are attached. If you have any 
questions, you may direct them to Kevin Clark, Audit Liaison, 301-903-
4293. 

Sincerely, 

James A. Slutz: 
Assistant Secretary (Acting): 
Office of Fossil Energy: 

The following are GAO's comments on the Department of Energy's letter 
dated September 9, 2008. 

GAO Comments: 

1. DOE says that while it agrees with the report's findings concerning 
the importance of pursuing CCS options for existing coal-fired power 
plants, these findings incorrectly imply "that DOE has focused too 
heavily on the IGCC option for new plants at the expense of retrofit 
opportunities." We are not second-guessing decisions DOE made in the 
decades before concerns about carbon dioxide (CO2) emissions had taken 
on the prominence they have today. Rather, we are concerned about how 
the agency can best move forward in light of the new emphasis on CO2 
emissions and the scientific consensus that CCS will be needed to help 
deal with them. 

2. DOE says that even though CO2 emissions from existing plants are 
important, current global trends indicate that many new coal power 
plants will continue to be built in coming decades and that many would 
choose IGCC as the lowest-cost CCS option if it were available. 
However, a DOE report, Tracking New Coal-Fired Power Plants, indicates 
that the new coal fired power plants currently being built and 
permitted in the United States are predominately using pulverized coal 
technologies, with a smaller number of plant operators opting for IGCC 
technology. Furthermore, DOE cites the importance of controlling CCS 
emissions in developing countries--in particular, China and India. 
However, the International Energy Agency states that "the expansion of 
coal-fired generation in China will continue to be based on pulverized 
coal" and observes that all of India's operating coal-fired power 
plants use a form of pulverized coal technology. That said, our report 
does not call for a radical shift in focus from IGCC to conventional 
technology, but rather a budgetary strategy that appropriately reflects 
a greater emphasis on developing capture technologies that could be 
applied to existing pulverized coal power plants. As our draft report 
noted, such a strategy has in fact already been reflected in recent DOE 
budgets. 

3. DOE acknowledges that it has recently increased requested funding 
for CCS technologies applicable to existing plants, but states that the 
increase does not necessarily reflect a higher priority. Rather, the 
increase reflects an evolution of the technology development process. 
Specifically, it is now moving from investigating such technologies 
from a less costly small scale to the point where costs rise as 
technology development is "scaled up." Recent statements by the agency, 
however, suggest that research applicable to existing coal-fired power 
plant technologies do warrant a higher priority. In particular, DOE's 
recent funding announcement for CCS technology development for existing 
pulverized coal power plants states that this funding opportunity is 
"driven by the fact that existing coal-fired power plants produce a 
sizeable portion of current CO2 emissions from all fossil fuel-based 
sources, and that only about 6 GW of the existing coal-fired 
electricity generating fleet is projected to retire by 2030." 
Similarly, in our discussions with DOE fossil energy officials about 
their fiscal year 2008 budget priorities, they pointed to language in 
House Report 110-185, which recommended "a rigorous research program on 
the potential for retrofitting existing coal plants for CO2 capture and 
sequestration." 

4. DOE questions the report's observation that funding for CO2 storage 
has been significantly higher than the resources devoted to CO2 
capture, noting that the higher funding level for storage-related 
activities reflects the fact that it has evolved to the point where 
advances in storage would now require expensive field-testing. We do 
not dispute the need to invest in the field-testing of storage 
activities. Rather, we note that timely CCS deployment will occur only 
if progress is made with both capture and storage and that considerably 
more progress is needed on the capture front. A comprehensive CO2 
storage capability will mean little if there is no CO2 to store. 

5. DOE maintains that a coordinating body--the DOE-led Climate Change 
Technology Program (CCTP)--already addresses CCS-related issues. 
However, the CCTP's scope focuses on technology; it does not address 
legal and institutional issues such as CO2 pipeline regulation and 
infrastructure or liability for stored CO2, among others. In addition, 
officials from cognizant offices within the Departments of the Interior 
and Transportation told us they have not yet been invited to 
participate in CCTP discussions. Moreover, we continue to believe that 
a more centralized task force, with a broader mission than the 
technology-focused CCTP, may be a preferable alternative. 

[End of section] 

Appendix III: Comments from the Environmental Protection Agency: 

Note: GAO comments supplementing those in the report text appear at the 
end of this appendix. 

United States Environmental Protection Agency: 
Office of Water: 
Washington, D.C. 20460: 
[hyperlink, http://www.epa.gov] 

September 12, 2008: 

John B. Stephenson: 
Director, Natural Resources and the Environment: 
Government Accountability Office: 
Washington, DC 20548: 

Dear Mr. Stephenson: 

Thank you for the opportunity to review the draft Government 
Accountability Office (GAO) Report: Federal Actions Will Greatly Affect 
the Viability of Carbon Capture and Storage as a Key Mitigation Option 
(GAO-08-1080), dated September 2008. The Environmental Protection 
Agency (EPA) coordinated with your Office throughout the study and 
provided additional material at your request, and our professional 
staff was made available for a number of meetings. I want to compliment 
the professional manner in which your staff conducted the study. We 
appreciate their positive responses to the comments we provided on 
earlier drafts. 

Our three major areas of concern are related to authorities under the 
Safe Drinking Water Act (SDWA); the discussion of the interplay with 
the Comprehensive Environmental Response, Compensation and Liability 
Act (CERCLA) and the Resource Conservation and Recovery Act (RCRA); and 
several key issues related to Geologic Sequestration (GS) but outside 
the authority of the SDWA. We will provide you the primary concerns 
within this letter and hope that these can be addressed in the final 
version of your GAO report. 

EPA recognizes the importance of Carbon Capture and Storage (CCS) in 
contributing to CO2 emissions reductions and is committed to working 
with both governmental and external partners to facilitate deployment 
of this technology in a safe and reliable manner. For over twenty-five 
years, the Underground Injection Control (UIC) program has successfully 
protected our nation's drinking water resources by regulating the 
underground injection of fluids and will continue to do so for the 
unique case of GS. 

EPA comments on discussion of SDWA-related issues: 

Early in the report, GAO suggests that EPA "more comprehensively 
examine barriers to CCS development under the Safe Drinking Water Act." 
[See comment 1] EPA believes that the recently proposed UIC GS rule 
(July 15, 2008) fully covers SDWA-related issues. EPA, working with 
partners at the Department of Energy (DOE) and several State regulatory 
agencies, proposed these new UIC regulations specifically for 
commercial-scale GS. The public comment period is currently ongoing for 
this proposed regulation and promulgation of the rule is anticipated in 
late 2010 or early 2011. The GAO report includes a preliminary 
discussion of the recently proposed UIC rule. We suggest that 
information related to this proposed rule should be placed as early in 
the report as possible. Although there may be misunderstandings among 
certain stakeholders regarding the regulatory framework for CO2 
injection, EPA has been clear that there is no regulatory impediment to 
seeking a permit for large-volume injection of CO2 under the existing 
UIC program. In fact, depending on the nature of the injection 
activity, CO2 injection could currently be permitted as a Class I, 
Class II or Class V UIC well. The purpose of the Class VI well category 
which is proposed in EPA's rule is to provide a more appropriate well 
classification for program implementation of this technology on a large 
scale. 

The draft report mentions 'ambiguity' regarding whether the operator of 
a GS site will remain liable indefinitely for potential problems posed 
by leakage of CO2. EPA has been clear during discussions with 
stakeholders that, consistent with current UIC regulations under the 
SDWA applying to all injection wells, the owner/operator of a GS site 
will be held liable indefinitely for potential damages caused by 
leakage of CO2. Some stakeholders may feel confused about this issue; 
GAO's report, however, should represent EPA's position, which is also 
reflected in the proposed rule. [See comment 2] 

In addition, the report discusses government indemnification of the 
potential liability associated with GS sites. It is important to note 
that EPA does not have authority under the SDWA to release or indemnify 
injection well owners/operators from long-term liability. Thus, the 
report should clarify that it is currently beyond the Agency's 
authority to do this. [See comment 3] 

Finally, EPA has stated in the proposed Class VI regulation that owners 
and operators of GS sites must demonstrate financial responsibility for 
the operation and post-injection site care phases of the project. 
However, EPA acknowledges the need for additional information and plans 
to provide guidance on how additional financial responsibility can be 
demonstrated. 

EPA comments on GAO discussion of CERCLA and RCRA 

The GAO report states that ambiguity exists regarding how CERCLA and 
RCRA regulations may apply to GS sites and states that the proposed EPA 
UIC-GS rule does not resolve, does not address and is `unclear' 
regarding these issues. EPA would appreciate if, at the beginning of 
this discussion, GAO would note that EPA has discussed RCRA and CERCLA 
issues in the preamble to the proposed regulation. EPA is currently in 
the process of further evaluating how CERCLA and RCRA may apply to GS 
sites. However EPA's proposed rule is clear that if a CO2 stream meets 
the definition of "hazardous waste" it may only be injected under the 
existing provisions for a Class I hazardous well, which by definition 
is subject to RCRA, and if it falls within certain categories of 
hazardous waste, it may not be injected unless EPA grants a RCRA 
exemption. Such hazardous waste streams would not be subject to the 
proposed Class VI permit. Finally releases of a hazardous substance 
beyond the scope of a federally-permitted release may be subject to 
CERCLA authorities. [See comment 4] 

EPA comments on GAO discussion of issues outside of SDWA authorities: 

The UIC proposed regulations include clarifications on the effect of 
permits on property rights. [See comment 5] 40 CFR 144.35 (b) and (c) 
clearly state that the issuance of a permit does not convey any 
property rights of any sort, or any exclusive privilege, and the permit 
does not authorize any injury to the persons or property or invasion of 
other private rights, or any infringement of State or local law or 
regulations. While EPA's proposed rule includes a discussion of how 
regulations may impact these issues, EPA does not have the authority to 
propose federal regulations related to property rights. To be clear, 
EPA does not anticipate resolving issues outside the scope of the SDWA 
in the context of the regulatory action recently proposed under the UIC 
program. [See comment 6] 

EPA response to specific GAO recommendation: 

GAO recommends that EPA offices "collectively examine their authorities 
and responsibilities under RCRA, CERCLA, and the Clean Air Act..." 
Providing regulatory certainty on issues related to GS is a high 
priority for the Agency and EPA agrees that it is important to provide 
clarity on the various statutes that may apply. EPA made an initial 
effort to identify and discuss issues related to SDWA, RCRA and CERCLA 
in the preamble of its July 2008 proposal and specifically requested 
comments on various topics including some of those identified by GAO. 
We hope that the input we receive through the public comment process, 
in combination with our own efforts to work across EPA to assess 
implications of these various statutes on GS, will shed more light on 
these important issues. 

We have a few additional comments on the draft final report which we 
are providing as an enclosure to this letter. Again, we appreciated the 
opportunity to coordinate with your staff on this project. Should you 
need additional information or have further questions, please let me 
know. You may also contact Cynthia C. Dougherty, Director of the Office 
of Ground Water and Drinking Water, at (202) 564-3750. 

Sincerely, 

Signed by: 

Benjamin H. Grumbles: 
Assistant Administrator: 

Enclosure: 

The following are GAO's comments on the Environmental Protection 
Agency's letter dated September 12, 2008. 

GAO Comments: 

1. EPA says that its recently-proposed UIC rule fully covers Safe 
Drinking Water Act (SDWA)-related issues. We have modified the report 
to more fully reflect the work that EPA is doing to examine SDWA- 
related barriers to CCS deployment. However, while we acknowledge that 
the proposed rule discusses and seeks comments on many issues, we 
continue to believe that it leaves many of these issues unresolved. 
While EPA's proposed rule prohibits the injection of CO2 above the 
lowermost formation containing an underground source of drinking water, 
EPA is still exploring whether the UIC director should be given the 
authority to approve such an injection--an issue that can affect 
whether unmineable coal seams are used for CO2 storage. 

2. EPA suggests that the report should state EPA's position on whether 
the operator of an injection well will remain liable indefinitely for 
potential problems posed by leakage of CO2. Pages 23 and 39 of the 
draft report did in fact state that well operators remain responsible 
indefinitely for any endangerment for underground sources of drinking 
water caused by such leakage. However, the draft report also addressed 
other unresolved liability issues of concern to stakeholders, which are 
unrelated to endangerment of underground sources of drinking water. We 
have added language to further emphasize these issues. 

3. EPA says that it is important to note that the agency does not have 
authority under the SDWA to release injection well owners or operators 
from long-term liability. The draft report had already done so on page 
39 and 40, where it explained that EPA does not have the statutory 
authority to release well owners or operators from liability or 
transfer financial responsibility from the well owner or operator to a 
third party. In response to EPA's comments, we have added language to 
the report to further clarify this point. 

4. EPA suggests that GAO note in its final report that EPA had 
discussed RCRA and CERCLA issues in the preamble to its proposed rule. 
The draft report had, in fact, mentioned that EPA addressed RCRA and 
CERCLA issues in the preamble. For example, page 42 of the draft noted 
that the preamble explained that pure CO2 in and of itself is not 
listed as a hazardous substance under CERCLA, and cautioned that 
injected CO2 streams could contain hazardous constituents that would 
make these streams "hazardous." That said, we continue to believe that 
the preamble's limited treatment of these issues still leaves much to 
be resolved about the implications of the Resource Conservation and 
Recovery Act (RCRA) and the Comprehensive Environmental Response, 
Compensation, and Liability Act (CERCLA) for CO2 sequestration. 
Specifically, EPA suggests that determinations about whether injected 
CO2 is a hazardous waste or substance will be made on a case-by-case 
basis. Moreover, EPA says it is "currently in the process of further 
evaluating how CERCLA and RCRA may apply to [geologic sequestration] 
sites." 

5. EPA notes that the proposed rule includes clarifications on the 
effect of permits on property rights. However, these effects were not 
among the property rights-related issues of greatest concern to the 
stakeholders we interviewed. As we stated in the report, these 
stakeholders told us they were concerned about a lack of clarity 
regarding ownership of injected CO2 and ownership of geologic 
formations. 

6. Notwithstanding the permit-related property rights issues raised in 
comment 5 above, EPA explains that it does not have the authority to 
propose federal regulations related more broadly to property rights 
issues. We agree that EPA's authority does not extend to many of these 
issues discussed in the report, which is why the report notes that the 
resolution of this and other issues will require the involvement of 
other federal agencies and, in some cases, states. 

[End of section] 

Appendix IV: GAO Contact and Staff Acknowledgments: 

GAO Contact: 

John B. Stephenson, (202) 512-3841 or stephensonj@gao.gov: 

Staff Acknowledgments: 

In addition to the contact named above, Steve Elstein, Assistant 
Director; Chuck Bausell; Cindy Gilbert; Katheryn Summers Hubbell; 
Michael O'Neill; Ben Shouse; Jeanette Soares; and Michelle Woods made 
major contributions to this report. Additional assistance was provided 
by Katherine M. Raheb and Melinda Cordero. 

[End of section] 

Footnotes: 

[1] CCS can also be used to reduce the CO2 emissions from industrial 
production of hydrogen, chemicals, substitute natural gas, and 
transportation fuels. 

[2] The International Energy Agency (IEA) is an intergovernmental 
organization founded in 1974 that acts as energy policy advisor to 27 
member countries. The IEA's current work focuses on climate change 
policies, market reform, and energy technology collaboration and 
outreach. 

[3] The Intergovernmental Panel on Climate Change (IPCC) is a 
scientific body set up by the World Meteorological Organization and by 
the United Nations Environment Programme. The IPCC was established to 
provide decision makers with an objective source of information about 
climate change. 

[4] Results from nonprobability samples cannot be used to make 
inferences about a population. This is because, in a nonprobability 
sample, some elements of the population being studied have no chance or 
an unknown chance of being selected as part of the sample. 

[5] The IPCC notes that these emissions include those from the 
production, distribution, and consumption of fossil fuels and as a by- 
product from cement production. The data from 2004 and 2005 are interim 
estimates. 

[6] CCS is not considered suitable for reducing emissions from the 
transportation, residential, and commercial sectors because sources in 
these sectors tend to emit small quantities of CO2. 

[7] The IEA's 2007 World Energy Outlook also assesses two alternative 
scenarios. These include a scenario in which world demand for energy 
and coal generally increases less than otherwise expected due to 
changes in government policies that address climate change concerns and 
a scenario in which world demand increases more than otherwise expected 
due to higher rates of economic growth in China and India. 

[8] This report focuses primarily on pre-and post-combustion capture. 

[9] When the temperature and pressure of CO2 are increased, the CO2 
enters a fluid, or supercritical state. 

[10] An exception is made for groundwater remediation at hazardous 
waste sites. 

[11] Class V wells are typically shallow wells that place a variety of 
fluids directly below the land surface. 

[12] EPA administers the UIC program in 10 states and for all Indian 
tribes. 

[13] National Coal Council, Technologies to Reduce or Capture and Store 
Carbon Dioxide Emissions (June 2007). 

[14] The IEA defines large scale as injecting over 0.5 Mt (500,000 
metric tons) per year. 

[15] The IPCC Special Report on CCS notes that some of the CO2 captured 
from natural gas processing and ammonia production facilities is used 
for enhanced oil recovery, a process which may result in the 
sequestration of a substantial amount of the CO2 from the atmosphere. 

[16] Howard Herzog and Dan Golomb, "Carbon Capture and Storage from 
Fossil Fuel Use," Encyclopedia of Energy, 2004. 

[17] Department of Energy, National Energy Technology Laboratory, Cost 
and Performance Baseline for Fossil Energy Plants--Volume 1: Bituminous 
Coal and Natural Gas to Electricity, Final Report (2007). 

[18] DOE officials told us these estimates were based on Cost and 
Performance Baseline for Fossil Energy Power Plants--Volume 1. 

[19] International Energy Agency, Energy Technology Perspectives 2008: 
Scenarios and Strategies to 2050 (Paris, 2008). 

[20] DOE officials told us that the study was based on current 
technology and not on possible advanced technology being developed. 

[21] MIT, The Future of Coal (2007). 

[22] The National Coal Council, Technologies to Reduce or Capture and 
Store Carbon Dioxide Emissions. 

[23] Nearly all existing coal-fired power plants are pulverized coal 
power plants. 

[24] MIT, The Future of Coal. 

[25] Department of Energy, National Energy Technology Laboratory, 
Carbon Dioxide Capture from Existing Coal-Fired Power Plants (2007). 

[26] The National Coal Council, The Urgency of Sustainable Coal 
(Washington D.C., 2008). 

[27] IPCC, IPCC Special Report on Carbon Dioxide Capture and Storage 
(2005). 

[28] J.M. Antle, University Fellow, Resources for the Future, Is There 
a Role for Geologic and Terrestrial Carbon Sequestration in Greenhouse 
Gas Mitigation? (February 2008). 

[29] GAO, Air Pollution: Allowance Trading Offers an Opportunity to 
Reduce Emissions at Less Cost, [hyperlink, http://www.gao.gov/cgi-
bin/getrpt?GAO/RCED-95-30] (Washington, D.C.: December 16, 1994) and 
Air Pollution: Overview and Issues on Emissions Allowance Trading 
Programs, [hyperlink, http://www.gao.gov/cgi-bin/getrpt?GAO/RCED-97-
183] (Washington, D.C.: July 9, 1997). 

[30] Edward S. Rubin et al, "Use of Experience Curves to Estimate 
Future Cost of Power Plants with CO2 Capture," International Journal of 
Greenhouse Gas Control, vol. 1, issue 2 (2007). 

[31] EU member states can seek to include CCS projects in their 
national emission cap by gaining approval from the European Commission 
on a case-by-case basis. 

[32] EU Commission Staff Working Document, accompanying document to the 
Proposal for a Directive of the European Parliament and of the Council 
on the Geologic Storage of Carbon Dioxide (January 23, 2008). 

[33] Syngas is the gas produced by the gasification process, composed 
of hydrogen, carbon monoxide, and minor amounts of other constituents. 
While DOE considers the gas stream amenable to CO2 recovery, CO2 
capture was not actually demonstrated in the projects. 

[34] Jose D. Figueroa, Timothy Fout, Sean Plasynski, Howard McIlvried, 
and Rameshwar D. Srivastava, "Advances in CO2 capture technology-The 
U.S. Department of Energy's Carbon Sequestration Program," 
International Journal of Greenhouse Gas Control, vol. 2 (2008). 

[35] National Research Council, National Academy of Sciences, Energy 
Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy 
Research 1978 to 2000 (Washington, D.C., 2001). 

[36] National Academy of Sciences, Energy Research at DOE: Was It Worth 
It? 

[37] National Research Council, National Academy of Sciences, 
Prospective Evaluation of Applied Energy Research and Development at 
DOE (Phase Two) (Washington, D.C., 2007). 

[38] DOE, Cost and Performance Baseline for Fossil Energy Plants-- 
Volume 1. 

[39] DOE, Cost and Performance Baseline for Fossil Energy Power Plants-
-Volume 1. 

[40] National Academy of Sciences, Prospective Evaluation. 

[41] The National Coal Council, The Urgency of Sustainable Coal. 

[42] 31 U.S.C. § 3302(b). 

[43] The proposed rule's preamble notes that if a CO2 stream contains 
hazardous waste as a constituent, it must be permitted as a Class I 
well. Class I wells are intended for hazardous materials. 

[44] Clean Air Act Advisory Committee Advanced Coal Technology Work 
Group, Final Report of the Advanced Coal Technology Work Group (Jan. 
29, 2008). 

[45] Pub. L. No. 110-140 (2007). 

[46] FERC has jurisdiction over interstate pipelines that transport oil 
or natural gas. STB has jurisdiction over interstate pipelines that 
transport a commodity other than water, gas, or oil. 

[47] 15 U.S.C. § 717a(5). 

[48] Cortez Pipeline Company, 7 F.E.R.C. ¶ 61,024 (1979). 

[49] Id. 

[50] Testimony of the Honorable Joseph T. Kelliher, Chairman, Federal 
Energy Regulatory Commission, before the Committee on Energy and 
Natural Resources, United States Senate, January 31, 2008. 

[51] 49 U.S.C. § 15301. 

[52] 45 Fed. Reg. 85,178 (Dec. 24, 1980); 46 Fed. Reg. 18,805 (Mar. 26, 
1981). 

[53] DOE officials note that several of the Regional Partnerships, 
including the Southwest, West Coast, Southeast, Midwest, and Plains CO2 
reduction partnerships, have completed or are working on pipeline 
studies for their individual regions. 

[54] Pub. L. No. 110-140 (2007). 

[55] IPCC, IPCC Special Report on Carbon Dioxide Capture and Storage. 

[56] IPCC, IPCC Special Report on Carbon Dioxide Capture and Storage 
(2005); National Academy of Sciences, Prospective Evaluation; and 
Congressional Research Service, Community Acceptance of Carbon Capture 
and Sequestration Infrastructure: Siting Challenges (July 2008). 

[57] National Academy of Sciences, Prospective Evaluation. 

[58] Clean Air Act Advisory Committee Advanced Coal Technology Work 
Group, Final Report of the Advanced Coal Technology Work Group. 

[59] EU Commission Staff Working Document, accompanying document to the 
Proposal for a Directive of the European Parliament and of the Council 
on the Geologic Storage of Carbon Dioxide, January 23, 2008. 

[60] Specifically, EPA officials told us they are developing a proposal 
that would require "upstream" producers and "downstream" sources above 
appropriate thresholds to report their greenhouse gas emissions. 

[61] Results from nonprobability samples cannot be used to make 
inferences about a population. This is because, in a nonprobability 
sample, some elements of the population being studied have no chance or 
an unknown chance of being selected as part of the sample. 

[End of section] 

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