Report of the 

Interagency Task Force on 

Carbon Capture and Storage 

August 2010 
Table of Contents 

Executive Summary ..........................................................................................................................................7
 

Introduction ................................................................................................................................................7
 

Status of CCS Technologies....................................................................................................................8
 

Status of CCS in the United States........................................................................................................9
 

Proposed Plan to Overcome Barriers ................................................................................................11
 

Support for Technology Development.......................................................................................11
 

Providing Legal & Regulatory Clarity and Support ..................................................................12
 

Public Outreach...............................................................................................................................13
 

Conclusion.................................................................................................................................................14
 

I. Background.........................................................................................................................................15
 

II. Role of CCS in Administration Climate Policy & Global Initiatives.......................................19
 

II.A Projected Scale of CCS in U.S. Climate Policy.................................................................20
 

II.B Role of CCS in Global Climate Strategy............................................................................23
 

III. State of CCS Technology ................................................................................................................27
 

III.A CO2 Capture............................................................................................................................27
 

III.A.1 Introduction .................................................................................................................27
 

III.A.2 Status of Capture Technology .................................................................................28
 

III.A.3 Planned Demonstrations of CO2 Capture Technologies ..................................32
 

III.A.4 CO2 Capture Cost .....................................................................................................33
 

III.A.5 Technical Challenges to CO2 Capture for Coal-Based Power Generation ..34
 

III.B CO2 Transport ........................................................................................................................36
 

III.B.1 Introduction .................................................................................................................36
 

III.B.2 Existing CO2 Pipeline Infrastructure.......................................................................36
 

III.B.3 CO2 Design Construction, Operations and Safety .............................................36
 

III.B.4 CO2 Transport Cost..................................................................................................37
 

III.B.5 Anticipated Future CO2 Pipeline Development...................................................37
 

III.C CO2 Storage.............................................................................................................................38
 

III.C.1 Introduction .................................................................................................................38
 

III.C.2 Status of Technology..................................................................................................38
 

III.C.3 Demonstrations of CO2 Storage Technologies ...................................................43
 

III.C.4 CO2 Storage Cost.......................................................................................................44
 

III.C.5 Technical and Other Considerations for CO2 Storage......................................45
 

III.D Conclusions..............................................................................................................................50
 

III.D.1 CO2 Capture................................................................................................................50
 

III.D.2 CO2 Transport ............................................................................................................50
 

III.D.3 CO2 Storage.................................................................................................................51
 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization................53
 

IV.A Market Failures........................................................................................................................54
 

Report of the Interagency Task Force on Carbon Capture and Storage 2 
IV.A.1	 Overview ......................................................................................................................54
 

IV.A.2	 Failure to Account for Social Cost of Greenhouse Gas Emissions.................54
 

IV.A.3	 Knowledge Spillovers from Research and Development of CCS 

Technology ...................................................................................................................55
 

IV.B	 Regulatory Framework Governing the Capture, Transportation, and Storage 

of CO2 .......................................................................................................................................56
 

IV.B.1	 Current Framework...................................................................................................57
 

IV.B.2	 Legal and Regulatory Challenges .............................................................................66
 

IV.C Long-Term Liability Regarding Storage of CO2 ...............................................................68
 

IV.C.1	 Overview ......................................................................................................................68
 

IV.C.2	 Policy Considerations for a Long-Term Liability Arrangement........................73
 

IV.D Public Information, Education, and Outreach...................................................................76
 

IV.D.1	 Overview ......................................................................................................................76
 

IV.D.2	 Elements of a Successful Outreach Strategy.........................................................77
 

IV.D.3	 Status and Key Gaps...................................................................................................78
 

V. Framework for Addressing Market Failures ...............................................................................81
 

V.A Framework for Incentivizing CCS Technology for Public Gain....................................81
 

V.A.1	 Key Principles for Assessing CCS Drivers and Incentives.................................82
 

V.A.2	 Public Funds Require Adaptive Resource Management .....................................83
 

V.B Tailoring Public Funding for Targeted CCS Projects......................................................84
 

V.C Technology-Push Drivers for CCS .....................................................................................87
 

V.C.1	 Demonstration of Current CCS Technologies....................................................87
 

V.C.2	 RD&D of CCS Technologies....................................................................................89
 

V.C.3	 International Collaboration ......................................................................................90
 

V.D Market-Pull Incentives for CCS ...........................................................................................93
 

V.D.1	 Loan Guarantees.........................................................................................................93
 

V.D.2	 Tax Treatment.............................................................................................................94
 

V.D.3	 Greenhouse Gas “Bonus” Allowance Allocation ................................................98
 

VI. Options for Enhancing the Legal/Regulatory Framework..................................................... 101
 

VII. Approaches for Legal or Regulatory Structures to Deal with Potential Liabilities ......... 109
 

VII.A Existing Legal and Regulatory Framework ..................................................................... 109
 

VII.B Substantive or Procedural Limitations on Claims ........................................................ 111
 

VII.C Federal Legislation Facilitating Private Insurance Coverage....................................... 112
 

VII.D Liability Fund ......................................................................................................................... 113
 

VII.E	 Government Ownership or Direct Liability .................................................................. 114
 

VII.F	 Governmental Indemnification.......................................................................................... 116
 

VII.G	 Transfer of Liability to the Federal Government after Site Closure and 

Governmental Certification............................................................................................... 117
 

VIII. Options for Federal Government Action on Public Outreach and Education ................ 119
 

IX. Conclusions and Recommendations.......................................................................................... 123
 

Table of Contents 3 
IX.A Conclusions........................................................................................................................... 123
 

IX.B Recommendations ............................................................................................................... 124
 

IX.B.1 Early Projects............................................................................................................ 124
 

IX.B.2 Wider Deployment ................................................................................................. 126
 

X. List of Acronyms............................................................................................................................ 129
 

XI. References ....................................................................................................................................... 131
 

Appendix A. CO2 Capture – State of Technology Development: Supplementary Material......A-1 

Appendix B. CO2 Pipeline Transport – State of Technology Development: Supplementary 

Material.........................................................................................................B-1
 

Appendix D. CO2 Reuse...................................................................................D-1 

Appendix E. Research, Development, & Demonstration..............................................E-1 

Appendix F. Applicability of Selected Environmental Laws to the Storage Phase of Carbon 

Appendix C. CO2 Storage – State of Technology Development: Supplementary Material.......C-1
 

Capture and Storage........................................................................................F-1 

Appendix G. Applicability of the National Environmental Policy Act, the Endangered Species
 

Act, and the National Historic Preservation Act to Carbon Capture and Storage Activities...G-1 

Appendix J. Government Indemnification................................................................J-1 

Appendix K. Liability Associated with DOE CCS RD&D Programs.................................K-1 

Appendix M. Siting Considerations for CO2 Pipelines.................................................M-1 

Appendix N. International Collaboration Background.................................................N-1 

Appendix References....................................................................................Ref-1 

Appendix H. Potential Causes of Long-Term Storage Risk and/or Liability........................H-1 

Appendix I. Price Anderson Act Private Insurance Program...........................................I-1 

Appendix L. Property Rights................................................................................L-1 

Report of the Interagency Task Force on Carbon Capture and Storage 4 
This report provides a background discussion on a range of factual, policy and legal issues. The 

discussion contained in this report is not intended to create rights or remedies that benefit the 

public or any regulated entity. The background discussion in this report also should not be 

construed to provide an authoritative or binding analysis or interpretation of any statute or 

regulation; such interpretations are issued through other processes. Finally, this report does 

not reflect the legal position of the United States. 

5 

Executive Summary 

Introduction 

Carbon capture and storage (CCS) refers to a set of technologies that can greatly reduce 

carbon dioxide (CO2) emissions from new and existing coal- and gas-fired power plants, 

industrial processes, and other stationary sources of CO2. In its application to electricity 

generation, CCS could play an important role in achieving national and global greenhouse gas 

(GHG) reduction goals. However, widespread cost-effective deployment of CCS will occur only 

if the technology is commercially available and a supportive national policy framework is in 

place. 

In keeping with that objective, on February 3, 2010, President Obama established an 

Interagency Task Force on Carbon Capture and Storage composed of 14 Executive 

Departments and Federal Agencies. The Task Force, co-chaired by the Department of Energy 

(DOE) and the Environmental Protection Agency (EPA), was charged with proposing a plan to 

overcome the barriers to the widespread, cost-effective deployment of CCS within ten years, 

with a goal of bringing five to ten commercial demonstration projects online by 2016. 

Composed of more than 100 Federal employees, the Task Force examined challenges facing 

early CCS projects as well as factors that could inhibit widespread commercial deployment of 

CCS. In developing the findings and recommendations outlined in this report, the Task Force 

relied on published literature and individual input from more than 100 experts and 

stakeholders, as well as public comments submitted to the Task Force. The Task Force also 

held a large public meeting and several targeted stakeholder briefings. 

While CCS can be applied to a variety of stationary sources of CO2, its application to coal-fired 

power plant emissions offers the greatest potential for GHG reductions. Coal has served as an 

important domestic source of reliable, affordable energy for decades, and the coal industry has 

provided stable and quality high-paying jobs for American workers. At the same time, coal-fired 

power plants are the largest contributor to U.S. greenhouse gas (GHG) emissions, and coal 

combustion accounts for 40 percent of global carbon dioxide (CO2) emissions from the 

consumption of energy. EPA and Energy Information Administration (EIA) assessments of 

recent climate and energy legislative proposals show that, if available on a cost-effective basis, 

CCS can over time play a large role in reducing the overall cost of meeting domestic emissions 

reduction targets. By playing a leadership role in efforts to develop and deploy CCS 

technologies to reduce GHG emissions, the United States can preserve the option of using an 

affordable, abundant, and domestic energy resource, help improve national security, help to 

maximize production from existing oil fields through enhanced oil recovery (EOR), and assist in 

the creation of new technologies for export. 

While there are no insurmountable technological, legal, institutional, regulatory or other 

barriers that prevent CCS from playing a role in reducing GHG emissions, early CCS projects 

Executive Summary 7 
 

 

 

face economic challenges related to climate policy uncertainty, first-of-a-kind technology risks, 

and the current high cost of CCS relative to other technologies. Administration analyses of 

proposed climate change legislation suggest that CCS technologies will not be widely deployed 

in the next two decades absent financial incentives that supplement projected carbon prices. In 

addition to the challenges associated with cost, these projects will need to meet regulatory 

requirements that are currently under development. Long-standing regulatory programs are 

being adapted to meet the circumstances of CCS, but limited experience and institutional 

capacity at the Federal and State1

 level may hinder implementation of CCS-specific 

requirements. Key legal issues, such as long-term liability and property rights, also need 

resolution. 

A climate policy designed to reduce our Nation’s GHG emissions is the most important step 

for commercial deployment of low-carbon technologies such as CCS, because it will create a 

stable, long-term framework for private investments. A concerted effort to properly address 

financial, economic, technological, legal, institutional, and social barriers will enable CCS to be a 

viable climate change mitigation option that can over time play an important role in reducing 

the overall cost of meeting domestic and global emissions reduction targets. Federal and State 

agencies can use existing authorities and programs to begin addressing these barriers while 

ensuring appropriate safeguards are in place to protect the environment and public health and 

safety. 

Status of CCS Technologies 

CCS is a three-step process that includes capture and compression of CO2 from power plants 

or industrial sources; transport of the captured CO2 (usually in pipelines); and storage of that 

CO2 in geologic formations, such as deep saline formations, oil and gas reservoirs, and 

unmineable coal seams. Technologies exist for all three components of CCS. 

 Capture of CO2 from industrial gas streams has occurred since the 1930s using a variety 

of approaches to separate CO2 from other gases. These processes have been used in the 

natural gas industry and to produce food and chemical-grade CO2. Existing capture 

technologies are energy-intensive, and consequently their application to coal-fired power 

plants and other industrial sources is expensive. 

 The history of transporting CO2 via pipelines in the United States spans nearly 40 years. 

Approximately 50 million tonnes of CO2 are transported each year in the United States 

through 3,600 miles of existing CO2 pipelines. 

1

 References to “States” also include Tribal governments. 

Report of the Interagency Task Force on Carbon Capture and Storage 8 
 

 Globally, there are four commercial CCS facilities sequestering captured CO2 into deep 

geologic formations and applying a suite of technologies to monitor and verify that the 

CO2 remains sequestered.2,3 These four sites represent 25 years of cumulative 

experience on safely and effectively storing anthropogenic CO2 in appropriate deep 

geologic formations (Dooley et al., 2009). DOE estimates that there are hundreds to 

thousands of years of storage potential in similar geologic formations in North America 

(NETL, 2008). Similarly, the Department of the Interior’s U.S. Geological Survey (USGS) 

is leveraging DOE’s efforts to generate a comprehensive catalogue of national 

sequestration potential. 

Though CCS technologies exist, “scaling up” these existing processes and integrating them with 

coal-based power generation poses technical, economic, and regulatory challenges. In the 

electricity sector, estimates of the incremental costs of new coal-fired plants with CCS relative 

to new conventional coal-fired plants typically range from $60 to $95 per tonne of CO2 avoided 

(DOE, 2010a). Approximately 70–90 percent of that cost is associated with capture and 

compression. Some of this cost could be offset by the use of CO2 for EOR for which there is an 

existing market, but EOR options may not be available for many projects. 

Research, development, and demonstration (RD&D) programs such as those currently being 

conducted by DOE can help reduce project uncertainty and improve technology cost and 

performance. The focus of CCS RD&D is twofold: 1) to demonstrate the operation of current 

CCS technologies integrated at an appropriate scale to prove safe and reliable capture and 

storage; and 2) to develop improved CO2 capture component technologies and advanced 

power generation technologies to significantly reduce the cost of CCS, to facilitate widespread 

cost-effective deployment after 2020. 

Status of CCS in the United States 

The Federal government is already pursuing a set of concrete initiatives to speed the 

commercial development of safe, affordable, and broadly deployable CCS technologies in the 

United States, including: RD&D of CCS technologies; the development of regulations that 

address the safety, efficacy, and environmental soundness of injecting and storing carbon 

dioxide underground; and the assessment of the country's geologic capacity to store carbon 

dioxide. All of this work builds on the firm scientific basis that now exists for the viability of 

CCS technology. 

2

 Since the 1970s, engineered injection of CO2 into geologic reservoirs has taken place for purposes of enhanced 

oil recovery, resulting in the development of many aspects of reservoir management and operation needed for safe 

large-scale injection and geologic storage of CO2. 

3

 Sleipner in the North Sea, Snøhvit in the Barents Sea, In Salah in Algeria, and Weyburn in Canada. 

Executive Summary 9 
 

Long-term integrated testing and validation programs are needed for technical, economic, and 

regulatory reasons. DOE is currently pursuing multiple demonstration projects using $3.4 

billion of available budgetary resources from the American Recovery and Reinvestment Act4 in 

addition to prior year appropriations. Various other incentives, such as tax credits and loan 

guarantees, are also available to many projects. 

Up to ten integrated CCS demonstration projects supported by DOE are intended to begin 

operation by 2016 in the United States. These demonstrations will integrate current CCS 

technologies with commercial-scale power and industrial plants to prove that they can be 

permitted and operated safely and reliably. New power plant applications will focus on 

integrating pre-combustion CO2 capture, transport, and storage with Integrated Gasification 

Combined Cycle (IGCC) technology. Power plant retrofit and industrial applications will 

demonstrate integrated post-combustion capture. These projects, plus others supported by 

Federal loan guarantees, tax incentives, and State-level drivers, cover a large group of potential 

CCS options. However, some proposed demonstration projects may not proceed for 

economic or other reasons. Looking toward long-term deployment, additional actions may be 

required to help overcome the uncertainty of evolving climate change policy and the high cost 

of applying currently available CCS technology, consistent with addressing market failures. 

Barriers to CCS Deployment 

The lack of comprehensive climate change legislation is the key barrier to CCS deployment. 

Without a carbon price and appropriate financial incentives for new technologies, there is no 

stable framework for investment in low-carbon technologies such as CCS. Significant Federal 

incentives for early deployment of CCS are in place, including RD&D efforts to push CCS 

technology development, and market-pull mechanisms such as tax credits and loan guarantees. 

However, many of these projects are being planned by the private sector in anticipation of 

requirements to reduce GHG emissions, and the foremost economic challenge to these 

projects is ongoing policy uncertainty regarding the value of GHG emissions reductions. 

Even with financial support, challenges such as legal and regulatory uncertainty can hinder the 

development of CCS projects. Regulatory uncertainty has been widely identified as a barrier to 

CCS deployment. Though early CCS projects can proceed under existing laws, there is limited 

experience at the Federal and State levels in applying the regulatory framework to CCS. 

Ongoing EPA efforts will clarify the existing regulatory framework by developing requirements 

tailored for CCS, which will reduce uncertainty for early projects and help to ensure safe and 

effective deployment. Experience gained from regulating and permitting the first five to ten CCS 

projects will further inform potential changes to existing requirements and the need for an 

enhanced regulatory framework for widespread CCS deployment. 

4

 Public Law 111-5. 

Report of the Interagency Task Force on Carbon Capture and Storage 10 
The Task Force identified a range of views concerning potential long-term liabilities (i.e., those 

arising after closure of a CO2 storage site) and the extent of any potential impacts on 

widespread deployment. Many States planning CCS projects are taking steps to address longterm liabilities associated with geologic storage of CO2. The Task Force’s preliminary 

assessment is that the existing Federal and State legal framework should be adequate for at 

least an initial group of five to ten commercial-scale projects. However, because of divergent 

views on the topic and limited time to analyze a complex set of underlying issues and drivers, 

additional analysis is needed to determine the most appropriate legal or regulatory structures 

for addressing potential long-term liabilities associated with widespread deployment. 

Aggregation of pore space and associated property rights are also important for CCS projects. 

Historically, pore space issues have been handled by States. Several States are taking actions to 

address aggregation of pore space for geologic storage on private lands. Based on experience 

thus far, the Task Force believes States are best positioned to address pore space issues on 

private lands. 

Public awareness and support are critical to the development of new energy technologies and 

are widely viewed as vital for CCS projects (IPCC, 2005; CRS, 2008; IEA, 2009c). Whether the 

public will support or oppose commercial-scale CCS projects is largely unknown (Malone et al., 

2010), and the public’s reaction may be project-specific. However, enhanced and coordinated 

public outreach will improve awareness of the role of CCS as one option to reduce GHG 

emissions. Integration of public information, education, and outreach efforts throughout the 

lifecycle of CCS projects will help identify key issues, foster public understanding, and build 

trust between communities and project developers. 

Proposed Plan to Overcome Barriers 

Support for Technology Development 

To foster the success of early CCS projects, including five to ten commercial-scale 

demonstrations by 2016, DOE and EPA should create a Federal agency roundtable to act as a 

single point of contact for project developers seeking assistance to overcome financial, 

technical, regulatory, and social barriers facing planned or existing projects. As needed, this 

roundtable should provide technical support to State and Federal permitting authorities and 

permit applicants. This roundtable should also create a technical committee composed of 

experts from the power and industrial sectors, NGOs, State officials, and research community. 

Together with DOE and EPA, the technical committee would conduct a periodic review of CCS 

demonstration projects to track their progress and, broadly, identify any additional research, 

risk management, or regulatory needs. The technical committee could also, as requested by 

DOE or EPA, provide input on a range of CCS technical, economic, or policy issues. 

Executive Summary 11 
 

DOE should continually review the adequacy of capture technologies and classes of storage 

reservoirs to enable safe and cost-effective widespread CCS deployment within ten years. This 

ongoing assessment, coupled with input from the technical committee outlined above, will assist 

the Administration in targeting any remaining technology gaps. 

Increased Federal coordination would enhance the government's ability to assist these projects 

by providing more effective incentives and/or addressing barriers. DOE, in coordination with 

EPA, Treasury, and USDA, should track the use and efficacy of Federal financial support for 

CCS projects. Increased coordination will enhance the government's ability to tailor Federal 

funding and assistance to each project’s market context, improve the clarity of eligibility criteria 

for projects to receive Federal support, allocate resources efficiently, and enable the 

Administration to more effectively consult with Congress and the States on the efficacy of 

existing incentives. 

The Administration should continue to support international collaboration that complements 

domestic CCS efforts and facilitates the global deployment of CCS. Most CCS technology 

RD&D is being supported by the United States and other developed countries. Leveraging 

resources and sharing results across these countries will improve the viability of CCS and 

potentially speed up global commercialization. Energy and economic modeling suggests that 

CCS in coal-dependent emerging economies plays a key role under some future policy and 

economic scenarios in achieving global climate change mitigation goals. The United States 

should continue its cooperation with large coal-dependent emerging economies with rapidly 

expanding power sectors, to facilitate a constructive dialogue and help to avert the locking in of 

inefficient, high-GHG emission power generation assets for decades. Failure to do so may make 

subsequent CCS deployment more difficult and increase the cost of global climate change 

mitigation. 

Providing Legal & Regulatory Clarity and Support 

Federal agencies must work together to design requirements for CCS using existing authorities 

in complementary ways. By late 2010, EPA should finalize rulemakings for geologic 

sequestration wells under the Safe Drinking Water Act (SDWA) and GHG reporting for CO2 

storage facilities under the Clean Air Act (CAA), and propose a Resource Conservation and 

Recovery Act (RCRA) applicability rule for CO2 that is captured from an emission source for 

purposes of sequestration. EPA guidance to support implementation of these rules should also 

be provided at the same time. By late 2011, EPA should finalize the RCRA applicability rule. EPA 

and the Department of the Interior (DOI) should immediately formalize coordination and 

prepare a strategy to develop regulatory frameworks for CCS for onshore and offshore Federal 

lands. Ratification of the London Protocol (LP) and associated amendment of the Marine 

Protection, Research, and Sanctuaries Act (MPRSA) as well as amendment of the Outer 

Continental Shelf Lands Act (OCSLA) will ensure a comprehensive statutory framework for the 

storage of CO2 on the outer continental shelf. 

Report of the Interagency Task Force on Carbon Capture and Storage 12 
 

Federal and State agencies must work together to enhance regulatory and technical capacity for 

safe and effective CCS deployment. Specifically, EPA, in coordination with DOE, DOI, and State 

agencies, should develop capacity-building programs for underground injection control 

regulators. Educating permit writers and other key officials will greatly enhance their capability 

and efficiency in issuing and enforcing technically sound permits. These programs should 

leverage existing efforts such as the DOE Regional Carbon Sequestration Partnerships (RCSPs). 

DOE and EPA should also identify data needs and tools to support regulatory development, 

permitting, and project development. 

The Task Force emphasizes that appropriate monitoring, oversight, and accountability for CCS 

activities will be essential to ensure the integrity of CCS operations, enable a sustainable CCS 

industry, and provide a strong foundation for public confidence. DOE and EPA, in consultation 

with other agencies, should track regulatory implementation for early commercial CCS 

demonstration projects and consider whether additional statutory revisions are needed. This 

will enable the Administration to more effectively consult with Congress and the States if the 

existing framework proves ineffective. 

Federal agencies should begin to develop National Environmental and Policy Act (NEPA) 

analyses related to CCS as early as possible to help ensure timely completion of robust and 

comprehensive environmental reviews. Where appropriate to Federal agency decision-making, 

agencies should consider development of Programmatic Environmental Impact Statements for 

use in tiered NEPA analysis and initiate this process. CEQ should consider development of 

CCS-specific NEPA guidance. 

Efforts to improve long-term liability and stewardship frameworks should continue. By late 

2011, EPA, DOE, Department of Justice (DOJ), DOI, and Treasury should further evaluate and 

provide recommendations to address long-term liability and stewardship in the context of 

existing and planned regulatory frameworks. Of the seven options identified by the Task Force, 

the following four approaches, or combinations thereof, should be considered: (1) reliance on 

the existing framework for long-term liability and stewardship; (2) adoption of substantive or 

procedural limitations on claims; (3) creation of an industry-financed trust fund to support longterm stewardship activities and compensate parties for various types and forms of losses or 

damages that occur after site closure; and (4) transfer of liability to the Federal government 

after site closure (with certain contingencies). Open-ended Federal indemnification should not 

be used to address long-term liabilities associated with CO2 storage. 

Public Outreach 

To enhance and coordinate public outreach for CCS, DOE and EPA should leverage existing 

efforts to coordinate among Federal agencies, States, industry, and NGOs to gather information 

and evaluate potential key concerns around CCS in different areas of the United States. Using 

this information, DOE and EPA should develop a comprehensive outreach strategy among the 

Executive Summary 13 
Federal government, States, industry, and NGOs having two components: a broad strategy for 

public outreach, targeted at the general public and decision makers, and a more focused 

engagement with communities that are candidates for CCS projects, to address issues such as 

environmental justice. A first step should be to immediately establish a clearinghouse for public 

access to unbiased, high-quality information on CCS. Over time, outreach tools should be 

developed for project developers and regulators with input from DOE, EPA, Department of 

Transportation (DOT), and DOI. 

Conclusion 

CCS can play an important role in domestic GHG emissions reductions while preserving the 

option of using abundant domestic fossil energy resources. However, barriers hamper nearterm and long-term demonstration and deployment of CCS technology. While the largest of 

these barriers is the absence of a Federal policy to reduce GHG emissions, the Task Force has 

outlined specific actions the Federal government could take under existing authority and 

resources to address these barriers. For widespread cost-effective deployment of CCS, 

additional action may be needed to address specific barriers, such as long-term liability and 

stewardship. Timely development of cost-effective CCS could reduce the costs of achieving our 

Nation’s climate change goals. 

CCS can also play a major role in reducing GHG emissions globally. Continued leadership to 

develop and deploy CCS technologies as one option to address global climate change will 

position the United States as a leader in climate change technologies and markets. However, 

widespread cost-effective deployment of CCS will occur only if the technology is commercially 

available at economically competitive prices and supportive national policy frameworks are in 

place. 

Report of the Interagency Task Force on Carbon Capture and Storage 14 
I. Background 

On February 3, 2010, President Obama sent a memorandum to the heads of 14 Executive 

Departments and Federal Agencies establishing an Interagency Task Force on Carbon Capture 

and Storage (CCS). Representatives from the following Federal Agencies and Executive 

Departments participated in the Task Force: Department of State, Department of the Treasury, 

Department of Justice, Department of the Interior, Department of Agriculture, Department of 

Commerce, Department of Labor, Department of Transportation, Department of Energy, 

Office of Management and Budget, Environmental Protection Agency, Federal Energy 

Regulatory Commission, Office of Science and Technology Policy, and Council on 

Environmental Quality. 

The goal was to develop a comprehensive and coordinated Federal strategy to speed the 

commercial development and deployment of carbon capture and storage technologies in line 

with the Administration’s goals for climate protection. The Task Force, co-chaired by the 

Department of Energy and the Environmental Protection Agency, was charged with proposing a 

plan to overcome the barriers to the widespread, cost-effective deployment of CCS within 10 

years, with a goal of bringing five to ten commercial demonstration projects online by 2016. 

In his memorandum, the President requested that within 180 days the Task Force explore 

incentives for commercial CCS adoption and address any financial, economic, technological, 

legal, institutional, social, or other barriers to deployment. The Task Force was to consider 

how best to coordinate existing administrative authorities and programs, including those that 

build international collaboration on CCS, as well as identify areas where additional 

administrative authority could be necessary. 

Under the joint leadership of the Department of Energy and the Environmental Protection 

Agency, the Task Force was assembled, comprising over 100 Federal employees from multiple 

Federal agencies. The Task Force examined challenges facing early CCS projects as well as 

factors that could inhibit widespread commercial deployment of CCS. In developing the findings 

and recommendations outlined in this report, the Task Force relied on published literature and 

individual input from over 100 experts and stakeholders from the research community, States, 

environmental organizations, industry, and business groups, as well as public comments 

submitted to the Task Force. 

Engaging the public in an open, transparent fashion was an important element of the Task 

Force's work. The Task Force's comprehensive outreach included a website hosted by the 

Council on Environmental Quality which included information about the Task Force, its 

meetings, and a mechanism for submitting public comments. The Task Force held an open 

public meeting on May 6, 2010, in Washington, D.C., which was simultaneously webcast. Over 

200 people attended the meeting and 200 more watched online. The meeting included several 

I. Background 15 
 

 

 

 

panels of experts on various components of CCS systems and opportunity for public input and 

questions. The video, expert presentations, and meeting transcript were posted on the website. 

The Task Force also met with individual groups, companies, and organizations who asked to 

provide input. Task Force staff held a series of targeted meetings with representative groups of 

stakeholders, including environmental organizations, labor organizations, State governments 

(including representatives from 14 governors' offices), the coal sector, and the oil/gas sector. 

The Task Force held a briefing on Capitol Hill and met with many Congressional staff from 

individual offices and committees to ensure their ideas and concerns were heard and addressed. 

The Task Force recognizes the contributions of States in evaluating and beginning to address 

barriers to CCS deployment. States are supporting RD&D activities, developing regulatory 

frameworks, and providing incentives for CCS deployment. For example, several State 

universities are studying and assessing the potential for CCS. Some States have created task 

forces or directed State agencies or energy commissions to assess potential storage sites (both 

onshore and offshore) and develop reports with recommendations to accelerate CCS and 

address barriers to CCS.5

 In some cases, grant programs and trust funds have been used to 

support CCS research and development.6 To address legal and regulatory barriers, some States 

have developed legislation to define jurisdiction for CO2 injection,7 designed regulations for 

injection wells,8,9 established rules for permitting storage sites and CO2 pipelines,10 provided 

eminent domain powers for CCS development,11 and developed laws related to liability12 and 

property rights.13 

5

 See, for example, California AB 1925, 2006., Colorado HB 06-1322, 2006; Illinois HB 3854, 2009; Massachusetts 

HB 5018, 2008; Minnesota SF 2096, 2007; Oklahoma SB 1765, 2008 and SB 679, 2009; Texas SB 1387, 2009; Texas 

HB 1796, 2009; Pennsylvania HB 2200, 2008; and West Virginia HB 2860, 2009. 

6

 See, for example: Illinois SB 1592, 2007; Louisiana HB 661, 2009; Massachusetts HB 5018, 2008; North Dakota SB 

2095, 2009; and Texas HB 1796, 2009. 

7

 Oklahoma SB 610, 2009 and Texas HB 1796, 2009. 

8

 Kansas HB 2419, 2007; Washington Administrative Code 173-218-115; and West Virginia HB 2860, 2009; 

Wyoming HB 90, 2008. 

9

 West Virginia HB 2860, 2009; Wyoming HB 90, 2008. 

10 West Virginia HB 2860, 2009; Wyoming HB 90, 2008; Utah Senate Bill 202, 2008; Indiana Code 8-1-22.5, 2009; 

South Dakota HB 1129; a HB 661, 2009; and Montana HB 24, 2007. 

11 Louisiana HB 661, 2009. 

12 North Dakota SB 2095, 2009; Illinois HB 1704, 2007; Louisiana HB 661, 2009; New Mexico Executive Order 

2006-069; Utah SB 202; Wyoming HB 58; Kentucky HB 491; Michigan SB 775; New York AB 5836; Pennsylvania 

HB 80 2009; and Montana SB 498, 2009. 

13 Oklahoma SB 610, 2009; North Dakota SB 2139; Montana SB 498; Louisiana SB 1117; Texas HB 149; West 

Virginia SB 2860; Wyoming HB 57, 58, 80, 89, and 90; Michigan SB 775; New Mexico SB 145; and New York AB 

5836 and 8802. 

Report of the Interagency Task Force on Carbon Capture and Storage 16 
 

 

Several States are providing incentives for CCS deployment such as portfolio standards that 

include generation of electricity from power plants with CCS14, alternative fuel standards,15 

emission standards,16 prioritization of CCS during power plant permitting processes,17 tax 

incentives (including tax exemption, reduced sales tax, taxation at lowered market value, tax 

credits),18 and provision of full or partial cost recovery through authorized rate changes for 

power plants with CCS.19 

In addition to specific individual actions, several States have formed regional partnerships for 

promoting CCS, including, for example, the Midwestern Energy Security and Climate 

Stewardship Platform,20 the Midwestern Regional Greenhouse Gas Reduction Accord,21 the 

Regional Greenhouse Gas Initiative (RGGI),22 the Western Climate Initiative (WCI),23 and the 

Western Governors’ Association (WGA) Clean and Diversified Energy Initiative.24 

The legislative agenda of the U.S. Congress continues to support to the development and 

deployment of CCS. In addition to provisions for CCS in the Energy Policy Act of 2005 and the 

2009 American Recovery and Reinvestment Act (ARRA), five recent legislative proposals in the 

U.S. Congress include provisions related to CCS: American Power Act (APA) of 2010 -- KerryLieberman25; S. 1462, American Clean Energy Leadership Act (ACELA) of 2009 -- Bingaman; S. 

2877, Carbon Limits and Energy for America's Renewal (CLEAR) Act -- Cantwell-Collins; S. 

3464, Practical Energy and Climate Plan (PECP) Act of 2010 -- Lugar, Graham & Murkowski; 

and H.R. 2454, American Clean Energy and Security Act (ACES Act) of 2009 -- WaxmanMarkey. Although the approaches and specifics vary, most of the bills authorize funding for 

14 Illinois SB 1987, 2009; Pennsylvania HB 80 2009; Ohio SB 21, 2008; and Massachusetts SB 2768, 2008. 

15 Pennsylvania HB 1202, 2007. 

16 California SB 1368, 2006; Illinois SB 1987, 2009; Maine LD 2126, 2008; Massachusetts SB 2768, 2008; Montana 

SB 25, 2007; Oregon SB 101, 2009; and Washington SB 6007, 2009. 

17 Illinois SB 1592, 2007; Rhode Island Code 42-98-2 and 42-98-3; and Montana HB 25, 2007. 

18 Kansas HB 2419, 2007; Mississippi HB 1459, 2009; Montana HB3, 2007; North Dakota HB 1365, 2007 and SB 

2221, 2009; Colorado HB 06-1281, 2006; Florida HB 549, 2007; Kentucky HB 1, 2007; New Mexico SB 994, 2007; 

Wyoming HB 61, 2006; Michigan HB 4016, 2009; and Texas HB 469, 2009 and HB 3732, 2007. 

19 Arkansas HB 2812, 2007; Colorado HB 06-1281, 2006; Florida HB 549, 2007; New Mexico SB 994, 2007; 

Virginia SB 1416, 2007; and West Virginia Code 24-2-1g. 

20 Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, South Dakota, 

Wisconsin, and the Canadian Province of Manitoba. 

21 Illinois, Iowa, Kansas, Michigan, Minnesota, Wisconsin, and the Premier of the Canadian Province of Manitoba. 

22 Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, 

and Vermont. 

23 Arizona, California, New Mexico, Oregon, and Washington. 

24 California, New Mexico, North Dakota, Utah, and Wyoming. 

25 Discussion draft released on May 12, 2010. 

I. Background 17 
 

 

development and demonstration of CCS technologies, create incentives for commercial 

deployment of CCS, and address legal and regulatory issues (CRS, 2010). For example, the 

ACELA authorizes funding for up to 10 CCS demonstration projects through a competitive 

selection process26 and the ACES Act and the APA would establish a CCS fund to finance either 

the first five27 or the first 10 GW28 of commercial-scale demonstration projects (CRS, 2010; 

Pew, 2010b; Pew, 2010a; Pew, 2010c; Pew, 2010d; Pew, 2010e).29 

Beyond these bills, several different amendments and legislative proposals have been introduced 

over the past few years supporting CCS development and deployment. For example, Senators 

Rockefeller and Voinovich introduced legislation in March 2010 to promote research and 

create incentives to develop and deploy full scale CCS. Congressman Boucher introduced 

legislation in 2009 to establish a $1 billion annual fund, derived from fees on the generation of 

electricity from coal, oil and natural gas, to provide grants to large-scale projects advancing the 

commercial availability of CCS technology. Senator Boxer introduced an amendment in 2008 to 

the Lieberman-Warner Climate Security Act establishing a long-term incentives and legal 

framework for CCS. Senator Barasso introduced an amendment in 2009 to clarify that the 

Federal government owns the pore space below Federal land. Senators Casey and Enzi 

introduced a bill for creating a framework for addressing legal and financial responsibilities for 

commercial carbon storage operations. 

Other legislators have voiced support for CCS and facilitated stakeholder discussions on 

promoting CCS as a technology critical to the continued use of coal in a carbon constrained 

future.30 For example, Senator Dorgan established a Clean Coal and CCS Technology Initiative 

in the fall of 2009 to facilitate discussion on promoting CCS.31 

26 S. 1462/ACELA would authorize funding for the DOE to support up to 10 CCS demonstration projects for 

large-scale integrated capture and sequestration of CO2 from industrial sources (including power plants). 

27 H.R. 2454/Waxman-Markey would authorize financial support to at least five commercial-scale CCS 

demonstration projects, pending approval by the States. 

28 APA/Kerry-Lieberman would authorize a special funding program to support CCS projects that result in the 

capture of CO2 emissions from at least 10 GW and would only be available for fossil-fueled electric generation 

projects of at least 100 MW, with at least 80 percent of funds awarded going to projects of at least 300 MW. 

29The proposed CCS fund would be financed through a charge to electric utilities burning fossil fuels based on the 

carbon content of each fuel. This charge would be highest for coal and lowest for natural gas. 

30See, for example, statements by Congressman Rahall and Senator Byrd 

http://www.rahall.house.gov/index.cfm?sectionid=10&parentid=5§iontree=5,10&itemid=981; 

http://byrd.senate.gov/mediacenter/view_article.cfm?ID=525. 

31 http://dorgan.senate.gov/issues/energy/cleancoal/index.cfm. 

Report of the Interagency Task Force on Carbon Capture and Storage 18 
 

II. Role of CCS in Administration Climate Policy & Global 

Initiatives 

As one of relatively few low-carbon electricity generation technologies, carbon capture and 

storage (CCS) could play an important role in achieving national and global greenhouse gas 

(GHG) reduction goals, and its commercial availability could broaden the options available to 

achieve those goals. For example, the American Clean Energy Security Act and the American 

Power Act are estimated to induce about 30 percent of fossil-fuel-based electricity generation 

to come from power plants with CCS by 2040, rising to approximately 59 percent by 2050 (15 

percent and 16 percent respectively of total electricity generation) (EPA, 2010). 

The Administration is committed to a range of policies that address the market failures that 

would otherwise impede the deployment of low-carbon technologies such as CCS. Examples of 

such policies include putting a price on carbon, tax incentives, and investments in research, 

development, and demonstration (RD&D). Private firms tend to under invest in research since 

they cannot capture the full social value of their investments, so there is a strong rationale for 

government policy to support technology-neutral RD&D32. Investments in RD&D may bring a 

technology closer to deployment by reducing uncertainty related to cost or performance, 

thereby enabling its commercial viability. 

To jump-start the transition to a low-carbon economy, the Administration provided roughly 

$60 billion in direct spending and $30 billion in tax credits through the American Recovery and 

Reinvestment Act of 2009 (ARRA). These investments were chosen carefully to support a 

broad spectrum of low-carbon-related activities. In particular, ARRA authorized $3.4 billion to 

support CCS RD&D initiatives that range from analysis of the sequestration33 potential of 

geologic formations to public-private cost-shared demonstrations of advanced CCS 

technologies. 

Globally, CCS can play a major role in reducing GHG emissions, with 20–40 percent of global 

CO2 emissions in 2050 projected to be suitable for capture—including 30–60 percent of all 

emissions from electric power (IPCC, 2005). The early development of a robust domestic 

industry in advanced CCS technology would further the Administration’s goals for continued 

leadership in the global market for innovation. American firms could become leading exporters 

of advanced CCS technology. However, widespread cost-effective deployment of CCS will 

occur only if the technology is commercially available and a supportive national policy 

framework is in place. Global partnerships are now working to address these challenges. 

32 See IV.A.3 for more on knowledge spillovers from research and development of CCS Technology. 

33“CO2 sequestration”, “geologic sequestration”, and “CO2 storage” are used synonymously in this report. 

II. Role of CCS in Administration Climate Policy & Global Initiatives 19 
 

 

II.A Projected Scale of CCS in U.S. Climate Policy 

The timing and scale of CCS deployment are dependent on a carbon price and any other 

financial incentives for low-carbon technology, as well as the costs of CCS relative to other 

technologies. Figure II-1 shows carbon prices in the modeling of legislation with emissions 

targets that are largely consistent with the Administration’s climate change goals.34,35 In the base 

case, allowance prices in 2020 are $24 and $31 per tonne CO2 equivalent36 (CO2e) for the U.S. 

Environmental Protection Agency (EPA) and the U.S. Energy Information Administration (EIA) 

analyses, respectively. If international offsets are unavailable or not allowed in the program, 

carbon prices are higher, at $52 per tonne CO2e for both the EPA and EIA analyses. Finally, if 

international offsets are unavailable, nuclear and dedicated biomass electricity generation are 

unavailable beyond business-as-usual levels, and CCS deployments are limited37, allowance 

prices rise to $59 - $89 per tonne CO2e in 2020 (EPA 2010; EIA 2010). These results reinforce 

the concept that availability of mitigation options (whether offsets or more cost-effective 

technologies) lowers the price of allowances, and thus the overall economic cost of averting 

climate change. 

34 Analyses by EPA and EIA of climate proposals consistent with the President’s GHG emission reduction goals of 

17 percent by 2020 and 83 percent by 2050 from 2005 levels estimate the range of carbon prices that achieve the 

President’s emission reduction goals, the cost to the United States economy of achieving such reductions, and the 

role that CCS is projected to play in transforming the way we consume and produce energy. 

35 As with all models of the energy economy, the outputs are based on a set of assumptions regarding economic 

growth, energy demand, resource availability, and the long-run cost of producing energy using various technologies. 

Each model incorporates improvements in technology characteristics over time, in this case extending from 20 to 

40 years into the future. Modeling assumptions vary among analyses. For example, CCS retrofits are not explicitly 

modeled in these analyses. These studies are widely recognized and respected in the climate policy discussion. 

36 CO2 equivalent is a measure used to compare the emissions from various greenhouse gases based upon their 

global warming potential (GWP). CO2 equivalent for a gas is derived by multiplying the tonnes of the gas by the 

associated GWP. Tonne CO2e = (tonne of a gas) * (GWP of the gas). The GWP of carbon dioxide is 1, by 

definition. 

37 EPA analysis of APA Scenario 7 assumes that CCS is not commercially available until after 2030. 

Report of the Interagency Task Force on Carbon Capture and Storage 20 
 

$0 

$50 

$100 

$150 

$200 

$250 

Allowance Price ($/tCO2 e) 

EPA - Base Case (scenario 2) 

EIA - Base Case 

EPA - No International Offsets (scenario 5) 

EIA - No International Offsets 

EPA - Delayed CCS + No International 

Offsets (scenario 7) 

EIA - No International Offsets + Limited 

Alternatives 

Figure II-1 Range of Domestic Allowance Prices in Economic Modeling of Proposed 

Policy 

2015 2020 2025 2030 2035 2040 2045 2050 

Source: EPA and EIA analyses of the American Power Act. 

The policy shown above refers to a discussion draft (not yet introduced) of Senate legislation 

that includes bonus allowances to promote CCS deployment above and beyond what the 

market would support in response to a price on GHG emissions. To understand the effect of 

these bonus allowances,38 EPA ran a comparison scenario without them. As Figure II-2 below 

shows, the bonus allowances are projected to shift CCS deployment 15–20 years ahead of 

when it would deploy in their absence. 

However, it is necessary to understand the broader implications of using additional financial 

incentives, such as bonus allowances, to promote earlier CCS deployment. The bonus 

allowances encourage firms to invest in CCS even though there are less costly means of 

achieving emissions reductions that do not receive bonus allowances. To the extent that such 

additional financial incentives distort the efficiency of the market, the overall economic cost of 

meeting the carbon target would be expected to rise. As with any technology, the increase in 

overall economic cost due to early deployment incentives would be reduced to the extent that 

early deployment lowers technical and commercial risk and enables CCS technology 

improvements that lower the cost of later widescale deployment. 

38 Recent legislative proposals for GHG cap-and-trade systems have reserved a share of emission allowances for 

free allocation to CCS applications. Bonus allowances are discussed in detail in Section V.D.3. 

II. Role of CCS in Administration Climate Policy & Global Initiatives 21 
Figure II-2 CCS Deployment (GW) EPA Modeling of Proposed Policy GW 

120 

100 

80 

60 

40 

20 

0 

2015 2020 2025 2030 2035 2040 2045 2050 

EPA - With Allowances (core policy scenario) EPA - No bonus allowances 

Source: EPA (2010) 

Figure II-3 shows the projected deployment of CCS as a result of the legislation under several 

different scenarios that were modeled by EPA and EIA. Consistent with the previous discussion, 

the bonus allowance provisions would drive deployment through 2030 in the cases where CCS 

technology is not delayed. The availability of international offsets does not significantly change 

the impact of bonus allowances on CCS deployment. However, by 2050, CCS deploys 

economically and in greater quantities in the “no international offset” scenarios due to higher 

allowance prices (i.e., more reductions must occur domestically and these have higher costs 

associated with them than opportunities available internationally). These scenarios provide 

reasonable bounds on the expected range of CCS deployment under a climate policy that caps 

emissions. 

Report of the Interagency Task Force on Carbon Capture and Storage 22 
 

 

Figure II-3 CCS (GW) EPA and EIA Modeling of Proposed Policy39 

350 

0 

50 

100 

150 

200 

250 

300 

GW 

EPA - Base Case (scenario 2) 

EIA - Base Case 

EPA - No International Offsets (scenario 5) 

EIA - No International Offsets 

EPA - Delayed CCS + No International Offsets (scenario 7) 

EIA - No International Offsets + Limited Alternatives 

2020 2030 2050 

Source: (EIA, 2010; EPA, 2010). Note: EIA analysis only extends to 2035 and therefore is not shown for 2050. CO2 

captured assumed to be 90 percent. A typical 550MW net output coal-fired power plant capturing 90 percent of the CO2 

would capture about 5 million tonnes of CO2 per year. 

These modeling exercises show that CCS may play an important role in helping the United 

States meet carbon reduction targets. The key to broad, cost-effective, commercial deployment 

of CCS is a climate policy that provides the right incentives to produce low-carbon energy, 

along with policies to promote RD&D in CCS and other potential low-carbon technologies. 

However, even with appropriate market signals from comprehensive energy and climate policy, 

non-economic barriers could prevent projected CCS deployment. To the extent that legal, 

regulatory, social, and economic barriers hinder the availability of CCS as a mitigation option, 

they would raise the overall cost of meeting the Administration’s climate goals. Thus, the 

Administration is committed to addressing these barriers to deployment. 

II.B Role of CCS in Global Climate Strategy 

Key insights into the value of international deployment of low-carbon technologies as part of a 

global climate strategy can be gleaned from a series of papers published in Energy Economics 

39 Prohibiting international offsets from entering the American Power Act emissions reduction program in EPA 

scenario 5 increases allowance prices and forces greater amounts of GHG abatement to occur in covered sectors, 

including the power sector. CCS deployment is actually lower in scenario 5 than in scenario 2. With high 

allowance prices in scenario 5, the small amount of GHG emissions from CCS, which is assumed to have 90% 

capture efficiency, make nuclear the preferred option in the ADAGE model. Given the joint constraint in ADAGE 

on nuclear and CCS, as nuclear increases in scenario 5 relative to scenario 2, CCS decreases to stay within the 

model constraint. 

II. Role of CCS in Administration Climate Policy & Global Initiatives 23 
 

(see Clarke et al., 2009 for an overview). These papers summarize the results from the 

Stanford Energy Modeling Forum EMF-22 exercise, which included ten of the world’s leading 

integrated climate assessment models (models with detailed representations of the energy 

sector that explicitly include GHG emissions and climate feedbacks). 

Figure II-4 shows selected results for the full global participation case in which a 550 ppm CO2 

concentration target is not exceeded.40 It shows the amount of CO2 averaged across all the 

models that is projected to be captured and stored by four major participants (the United 

States, European Union, China, and India). The message is relatively straightforward: a policy 

framework for global GHG emissions reductions will create a price signal that has the potential 

to drive commercial deployment of CCS absent additional barriers. However, such rapid 

deployment will require careful attention to any non-economic barriers not captured in the 

models. In addition to domestic efforts, the Administration is committed to continuing its 

engagement with other nations as described in Sections V and VI. 

Figure II-4 Projected CO2 Sequestration for Four Major Participants in a Global 

Regime 

0.0 

0.5 

1.0 

1.5 

2.0 

2.5 

3.0 

United States European Union China India 

GtCO2 / year

2020 

2030 

2040 

2050 

The technical potential to deploy CCS in a given country or region is dictated by the availability 

of suitably large, secure geologic reservoirs. Many developed countries, including the United 

States, are collecting information about the availability of such reservoirs. However, emerging 

economies generally lack the resources and expertise to acquire the information needed for 

detailed assessments with a high degree of confidence. In some countries, the information 

currently available is not sufficiently detailed to determine whether CCS could be considered as 

a climate change mitigation option. Additional detailed assessments of geologic formations are 

40 This concentration target corresponds to roughly a 3 degree Celsius increase in long-run global mean 

temperature relative to pre-industrial levels (IPCC, Fourth Assessment Report). 

Report of the Interagency Task Force on Carbon Capture and Storage 24 
 

necessary to develop commercial-scale CCS projects. The United States, along with several 

other developed countries, is providing technical assistance to emerging economies (China, in 

particular) on their initial geologic sequestration assessments through a variety of development 

assistance and cooperative RD&D programs. 

The 2nd edition of the Carbon Sequestration Atlas of the United States and Canada (Atlas II) is a 

good example of the type of data needed to assess the technical potential to deploy CCS in a 

given country or region (NETL, 2008). This atlas provides a comprehensive update of CCS 

potential across the majority of the United States and portions of Canada. It also presents 

updated information on the location of stationary CO2 emission sources and the locations and 

sequestration potential of various geologic sequestration sites, and provides information about 

the commercialization opportunities for CCS technologies. The USGS is leveraging DOE’s 

efforts to generate a comprehensive catalogue of national sequestration potential, using their 

recently finalized methodology to assess CCS resources in the United States. 

In addition to the U.S. efforts, Australia, China, Japan, and European countries are currently 

publishing data on their geologic storage potential. However, there is no single reference at 

sufficient detail for the rest of the world. Global capacity estimates use simplistic methods and 

assumptions and therefore have considerable uncertainty (IPCC, 2005). In contrast, country 

estimates, such as those reported in the Atlas II for the United States and Canada, are 

generated regionally using consistent methodologies and assumptions, making them more 

reliable. 

International partnerships have been formed to address the various challenges associated with 

widescale global CCS deployment, as described further in Section V.C.3. These partnerships 

offer the opportunity for countries to share their knowledge and experience gained from early 

efforts to deploy CCS technology. The important role that CCS can play in transitioning to a 

low-carbon global economy was also highlighted in the June 2010 G8 declaration, which noted 

that the G8 welcomes “the progress already made on our Toyako commitments to launch the 

20 large-scale CCS demonstration projects globally by 2010 and to achieve the broad 

deployment of CCS by 2020, in cooperation with developing countries. Several of us commit to 

accelerate the CCS demonstration projects and set a goal to achieve their full implementation 

by 2015.”41 Such efforts may play an important role in enabling CCS to become a key 

technology option in efforts to reduce global CO2 emissions. 

41 Page 7, paragraph 24 of G8 text at http://www.whitehouse.gov/sites/default/files/g8_muskoka_declaration.pdf. 

II. Role of CCS in Administration Climate Policy & Global Initiatives 25 

 

III. State of CCS Technology 

CCS is a three-step process that includes the capture of CO2 from power plants or industrial 

sources, transport of the captured CO2 (usually in pipelines), and storage of that CO2 in 

suitable geologic reservoirs. Technologies exist for all three components of CCS, but they have 

not yet been deployed at the scale necessary to help achieve GHG reduction targets. Cost 

estimates of current technology for CCS in power production range between $60 and $114 

per tonne of CO2 avoided42 depending on the power plant type (DOE, 2010a). Approximately 

70–90 percent of that cost is associated with capture and compression. The subsections below 

describe the current state of technology development for capture, transport, and storage of 

CO2. The small-scale CCS efforts that have been conducted to date are presented along with 

upcoming larger-scale demonstration projects. 

III.A CO2 Capture 

III.A.1 Introduction 

This section of the report presents a brief history of CO2 capture technology, the current state 

of technology development, and planned large-scale demonstration projects. Additional 

supporting material can be found in Appendix A. 

Although CO2 capture is new to coal-based power generation, removal of CO2 from industrial 

gas streams is not a new process. Gas absorption processes using chemical solvents to separate 

CO2 from other gases have been in use since the 1930s in the natural gas industry and to 

produce food and chemical grade CO2 from gas streams containing 3 to 25 percent CO2 (see 

Appendix A, Figure A-1). In the 1950s and 1960s, gas adsorption processes were developed to 

separate CO2 from gas streams associated with hydrogen (H2) production (refineries), nitrogen 

(N2) separation, and dehydration. In the 1970s and 1980s, gas separation membranes were 

developed for EOR (oil/gas separation) and natural gas processing applications (Kohl and 

Nielsen, 1997). 

The licensing history of the Econamine FG process provides a good example of past 

applications of CO2 removal technologies (Chapel et al., 1999). Prior to 1999, 25 facilities were 

built with CO2 capture capacities ranging from 635 to 365,000 tonnes per year using this 

process (see Appendix A, Table A-1). Three were coal-fired applications capturing 600 to 1,600 

tonnes of CO2 per year. The captured CO2 from these facilities was used for enhanced oil 

recovery (EOR), urea production, and in the food and beverage industry. The capture rates of 

42 Note that these values are not the same as the emission allowance price at which CCS would become 

economically viable. Rather, as the incremental cost per tonne sequestered relative to the same technology 

without CCS, these values represent a lower bound on the allowance price above which CCS would become 

economic. 

III. State of CCS Technology 27 
these facilities reflect the fact that they were built to serve a specific commercial market for 

CO2. Other amine-based processes (e.g., ABB/Lummus) were implemented at similar capture 

rates during this period. By comparison, a single 550 megawatt (MW) net output coal-fired 

power plant capturing 90 percent of the emitted CO2 will need to separate approximately 5 

million tonnes of CO2 per year. Scaling up these existing processes represents a significant 

technical challenge and a potential barrier to widespread commercial deployment in the near 

term (DOE, 2010a). 

A 2009 review of commercially available CO2 capture technologies identified 17 operating 

facilities using either chemical or physical capture solvents (see Appendix A, Table A-2) (Dooley 

et al., 2009). These included four natural gas processing operations and a syngas production 

facility in which more than 1 million tonnes of CO2 are being captured per year. The largest (a 

natural gas processing operation in Wyoming) captures 3.6 million tonnes per year, similar to 

the volumes that can be expected from electricity generating plants. However, it is unclear how 

transferable the experience with natural gas processing is to separation of power plant flue 

gases, given the significant differences in the chemical make-up of the two gas streams. In 

addition, integration of these technologies with the power cycle at generating plants present 

significant cost and operating issues that will need to be addressed to facilitate widespread, 

cost-effective deployment of CO2 capture. 

III.A.2 Status of Capture Technology 

III.A.2.1 Industrial Sectors 

One-quarter of U.S. CO2 emissions come from the industrial sector, with the highest emissions 

coming from petroleum refining, chemical production, cement production, pulp and paper, and 

iron and steel production. Few studies or demonstration projects have enabled the evaluation 

of the applicability of CO2 capture technologies to these industrial sources. Some industrial 

facilities (e.g., lime production, petroleum refineries, natural gas processing, and ammonia 

plants) produce relatively concentrated CO2 streams. As previously mentioned, scrubbers have 

been used at some of these industrial facilities, though at very small scale, to capture CO2 for 

specific use, such as EOR. The CO2 from many of these facilities could likely be captured at 

lower cost, as the CO2 is often already separated as part of the industrial process and thus may 

require little additional processing. However, there are currently few incentives, either 

regulatory or economic, to capture GHG emissions from these industrial sources. As a 

consequence, few of the available technologies are being employed on a wide scale. 

III.A.2.2Coal-Fired Power Generation 

In general, CO2 capture technologies applicable to coal-fired power generation can be 

categorized into three approaches (IPCC, 2005; DOE, 2007): 

Report of the Interagency Task Force on Carbon Capture and Storage 28 
 

 Pre-combustion systems are designed to separate CO2 and H2 in the high-pressure 

syngas produced at Integrated Gasification Combined Cycle (IGCC) power plants. 

 Post-combustion systems are designed to separate CO2 from the flue gas produced by 

fossil-fuel combustion in air. 

 Oxy-combustion uses high-purity oxygen (O2), rather than air, to combust coal and 

therefore produces a highly concentrated CO2 stream. 

Each of these approaches results in increased capital and operating costs and decreased 

electricity output (or energy penalty43), thereby significantly increasing the cost of electricity 

(COE) (Rubin, 2008; DOE, 2010a). The energy penalty occurs because the CO2 capture 

process uses some of the energy produced from the plant. The capture approaches and their 

impacts on COE and electricity production are summarized below. 

Pre-Combustion CO2 Capture 

Pre-combustion capture is mainly applicable to IGCC plants, where fuel is converted into 

gaseous components (“syngas fuel”) by applying heat under pressure in the presence of steam 

and limited O2. The carbon contained in the syngas is captured before combustion and power 

production occur (see Appendix A, Figure A-2). The cost of electricity (COE) for an IGCC 

power plant without CCS is higher than that for a pulverized coal (PC) power plant. Using the 

SelexolTM process to capture CO2 at an IGCC power plant increases the COE by 

approximately 40 percent relative to the same plant without a capture system. 44 By 

comparison, adding an amine scrubber to capture CO2 from a PC power plant increases the 

COE by nearly 80 percent relative to the same plant without a capture system. The energy 

penalty for capturing and compressing 90 percent CO2 in pre-combustion IGCC applications is 

approximately 20 percent (Rubin, 2008; Hamilton, 2009; DOE, 2010a). 

Post-Combustion CO2 Capture 

Post-combustion CO2 capture refers to removal of CO2 from combustion flue gases prior to 

discharge to the atmosphere (see Appendix A, Figure A-4). Separating CO2 from this flue gas is 

challenging for the following reasons: 

 A high volume of gas must be treated because the CO2 is dilute (13 to 15 percent by 

volume in coal-fired systems, three to four percent in natural-gas-fired systems); 

43 The energy penalty represents the percentage reduction in the power plant operating efficiency. For example, a 

reduction in efficiency from 30 percent to 20 percent represents a 10 percentage point drop in efficiency, which is 

equivalent to a 33 percent energy penalty. 

44 The 30-year levelized costs are calculated in current (i.e., real) dollars using 2009 as the base year. 

III. State of CCS Technology 29 
 the flue gas is at low pressure (near atmosphere); trace impurities (particulate matter 

[PM], sulfur oxides [SOx], nitrogen oxides [NOx], etc.) can degrade the CO2 capture 

materials; and 

 compressing captured CO2 from near atmospheric pressure to pipeline pressure (about 

2,000 pounds per square inch absolute) requires a large auxiliary power load (Rubin, 

2008; Hamilton, 2009; Herzog, 2009; Herzog et al., 2009). 

Post-combustion CO2 capture offers the greatest near-term potential for reducing power 

sector CO2 emissions because it can be used to retrofit existing PC power plants. Although 

post-combustion capture technologies would typically be applied to conventional coal-fired 

power plants, they could also be applied to the flue gas from IGCC power plants, natural gas 

combined cycle (NGCC) power plants, and industrial facilities that combust fossil fuels. 

Currently, there are several commercially available solvent-based capture processes. In 

addition, a wide variety of processes employing solvents, solid sorbents, and membranes are at 

varying stages of development (EPRI, 2008; Ciferno et al., 2009). 

Installing current amine post-combustion CO2 capture technology on new conventional 

subcritical, supercritical, and ultra-supercritical coal-fired power plants would increase the COE 

by about 80 percent. Further, the large quantity of energy required to regenerate the amine 

solvent and compress the CO2 to pipeline conditions would result in about a 30 percent energy 

penalty (DOE, 2010a). 

Oxy-Combustion 

Oxy-combustion systems for CO2 capture rely on combusting coal or other fuels with 

relatively pure O2 diluted with recycled CO2 or CO2/steam mixtures. Under these conditions, 

the primary products of combustion are water and CO2, with the CO2 purified by condensing 

the water (see Appendix A, Figure A-6) (Bohm, 2006; Hamilton, 2009; Herzog, 2009). 

There are multiple technical and economic advantages of coal oxy-combustion that provide a 

high potential for a significant reduction in CO2 capture costs compared with current state-ofthe-art amine scrubbing. All critical components required for a commercial power plant are in 

operation today at scale, including cryogenic air separation units (ASU) and CO2 purification 

and compression equipment. This corresponds to little or no equipment scale-up barriers. The 

technology components can be readily applied to new and existing coal-fired power plants and 

the removal of other criteria pollutants such as NOx, SOx, and mercury (Hg) is enhanced during 

the oxy-combustion process. Finally, significant cost reductions and efficiency improvements can 

be realized by incorporating advanced ultra-supercritical boiler materials and advanced CO2 

purification/compression. 

However, first-mover oxy-combustion power plants come with a few key challenges, namely 

the capital cost and energy consumption for a cryogenic ASU to produce oxygen, boiler air 

Report of the Interagency Task Force on Carbon Capture and Storage 30 
infiltration (mainly N2), and excess O2 contaminating in the CO2 sequestration stream. 

Construction of a new supercritical oxy-combustion coal-fired power plant equipped with a 

commercially available cryogenic ASU would increase the COE by about 60 percent and have a 

25 percent energy penalty compared with a new supercritical air-fired, coal-based power plant 

without CO2 capture (DOE, 2010a; DOE, 2010b). 

III.A.2.3 CO2 Capture Experience Associated with Power Production 

Commercially available CO2 capture technologies are currently being used in various industrial 

applications. However, one of the key barriers to their more widespread commercial 

deployment as a climate change mitigation strategy is the lack of experience with these systems 

at the appropriate scale in power plant settings (Kuuskraa, 2007). The following is a brief 

summary of currently operating CO2 capture systems in coal-based power plant applications. 

AES’s coal-fired Warrior Run (Cumberland, Maryland) and Shady Point (Panama, Oklahoma) 

power plants are equipped with amine scrubbers developed by ABB/Lummus. They were 

designed to process a relatively small percentage of each plant’s flue gas. At Warrior Run, 

approximately 110,000 tonnes of CO2 per year are captured, whereas at Shady Point 66,000 

tonnes of CO2 per year are captured. The CO2 from both plants is subsequently used in the 

food processing industry (Dooley et al., 2009). 

At the Searles Valley Minerals soda ash plant in Trona, California, approximately 270,000 

tonnes of CO2 per year are captured from the flue gas of a coal power plant via amine 

scrubbing and used for the carbonation of brine in the process of producing soda ash (IEA, 

2009a; SourceWatch, 2009). 

In September 2009, American Electric Power Co. (AEP) began operating the Alstom postcombustion chilled ammonia pilot process to capture 100,000 tonnes of CO2 per year on the 

Mountaineer Plant in New Haven, West Virginia, and store it in deep geologic formations 

beneath the Mountaineer site. 

A pre-combustion Rectisol® system is used for CO2 capture at the Dakota Gasification 

Company’s synthetic natural gas (SNG) production plant located in North Dakota, which is 

designed to remove approximately 1.6 million tonnes of CO2 per year from the synthesis gas. 

The CO2 is purified, transported via a 200-mile pipeline, and injected into the Weyburn oilfield 

in Saskatchewan, Canada. However, this experience is based on a gasification plant, not an 

IGCC power plant (Dakota Gasification Company, Undated). 

Oxy-combustion of coal is being demonstrated in a 10 MWe facility in Germany. The Vattenfall 

plant in eastern Germany (Schwarze Pumpe) has been operating since September 2008. It is 

designed to capture 70,000 tonnes of CO2 per year (Vattenfall, Undated). 

III. State of CCS Technology 31 
III.A.3 Planned Demonstrations of CO2 Capture Technologies 

While the efforts described above are worthwhile and important in advancing CO2 capture 

technologies, they still are not at a large enough scale to overcome technical uncertainty 

associated with scale-up needed for widespread cost-effective deployment. One means of 

addressing these uncertainties is through demonstration programs such as those currently 

being conducted by DOE. 

DOE’s Clean Coal Power Initiative (CCPI) is focused on accelerating availability of technologies 

for use by the private sector in new and existing coal-based power plants. CCPI is pursuing 

three pre-combustion and three post-combustion CO2 capture demonstration projects using 

currently available technologies (see Appendix A, Table A-8). 

The pre-combustion projects involve CO2 capture from IGCC power plants. The specific 

projects include the following: 

 Summit Texas Clean Energy: a 400 MW facility in west Texas burning Powder River 

Basin coal where 2.7 million tonnes per year of CO2 will be captured using a SelexolTM 

process and used in an EOR application. 

 Southern Company Kemper: a 582 MW facility in Mississippi burning Mississippi lignite 

where 1.8 million tonnes per year of CO2 will be captured using a SelexolTM process and 

used in an EOR application. 

 Hydrogen Energy California: a 257 MW facility in south-central California burning coal 

and petroleum coke where 1.8 million tonnes per year of CO2 will be captured using a 

Rectisol® process and used in an EOR application. 

The post-combustion projects will capture CO2 from a portion of the PC plant’s flue gas 

stream. The specific projects include the following: 

 Basin Electric: amine-based capture of 900,000 tonnes per year of CO2 from a 120 MW 

equivalent slipstream at a North Dakota plant for use in an EOR application and/or saline 

storage. 

 NRG Energy: amine-based capture of 400,000 tonnes per year of CO2 from a 60 MW 

equivalent slipstream at a Texas plant for use in an EOR application. 

 American Electric Power: ammonia-based capture of 1.5 million tonnes per year of CO2 

from a 235 MW equivalent slipstream at a West Virginia plant for saline storage. 

Similar to the CCPI projects, the FutureGen project will demonstrate carbon capture from a 

200 MW advanced oxy-combustion unit in Meredosia, Illinois, integrated with CO2 storage in 

Report of the Interagency Task Force on Carbon Capture and Storage 32 
 

Mattoon, Illinois. FutureGen aims to capture and store at least one million tonnes of CO2 per 

year. 

In addition to the CCPI program, CO2 capture demonstration projects are being conducted 

under the DOE Industrial Carbon Capture and Storage (ICCS) program (see Appendix A, Table 

A-9) (DOE, 2010c). These projects are pursuing capture technologies that are similar to those 

being demonstrated for power plants and are of similar magnitude to the CCPI demonstrations. 

Eleven projects were initially selected for the ICCS program. In June 2010 three projects were 

selected to move forward to full demonstrations. These include the following: 

 Leucadia Energy: a methanol plant in Louisiana where 4 million tonnes per year of CO2 

will be captured and used in an EOR application. 

 Archer Daniels Midland: an ethanol plant in Illinois where 900,000 tonnes per year of 

CO2 will be captured and stored in a saline formation directly below the plant site. 

 Air Products: a hydrogen-production facility in Texas where 900,000 tonnes per year of 

CO2 will be captured and used in an EOR application. 

The large-scale CO2 capture demonstrations that are currently planned under DOE’s initiatives 

will generate operational knowledge and enable future commercialization and widespread costeffective deployment of these technologies. In addition to the selected projects, information has 

been compiled for 20 to 25 other domestic CCS efforts in various stages of development that 

could contribute to the deployment of CCS.Though it is unclear how many of these will move 

forward, they have the potential to contribute important additional information to future CCS 

development. 

III.A.4 CO2 Capture Cost 

DOE analyses indicate that for a new 550 MWe net output power plant, addition of currently 

available pre-combustion CO2 capture and compression technology increases the capital cost of 

an IGCC power plant by approximately $400 million (~25 percent) compared with the noncapture counterpart. For a similarly sized new supercritical PC plant, post-combustion and oxycombustion capture would increase capital costs by approximately $900 million (80 percent) 

and $700 million (65 percent) respectively. For post-combustion CO2 capture on a similarly 

sized new NGCC plant, the capital cost would increase by $340 million or 80 percent. 

In terms of cost per tonne of CO2 avoided, values range from $60/tonne for IGCC to 

$114/tonne for NGCC.45 Figure III-1 shows the range of these costs for various types of power 

45 The dollar per tonne of CO2 avoided is the incremental cost of CO2 emissions avoided by applying CCS and is 

compared to a similar non-captured facility. It is calculated by dividing the difference in COE, $/MWh, by the 

difference in CO2 emissions with and without CO2 capture, tonnes/MWh. The dollar per tonne CO2 captured is 

III. State of CCS Technology 33 
     

   

     

                                           

                                        

                     

 

plants (DOE, 2010a). In terms of cost per tonne of CO2 captured, values range from $49/tonne 

for IGCC to $95/tonne for NGCC. Improvements to currently available CO2 capture and 

compression processes are important in reducing the costs incurred for CO2 capture. 

Figure III-1 CCS Costs for Different Types and Configurations of Power Plants 

0

20

40

60

80

100

120

140

160

New IGCC New Post‐

Combustion

New Oxy‐

Combustion

New NGCC Retrofit Post‐

Combustion

110

85 85

77

27

150 151

140

121

116

60

95

68

114

103

LCOE w/o CCS, $/MWh

LCOE w/CCS, $/MWh

Avoided Cost, $/tonne CO2

LCOE, $/MWh

Avoided Cost, $/tonne CO2

LCOE‐‐Levelized Costof Electricity is a cost of generating elecricity for a particular system. Itis an economicassessment ofthe costofthe

energy‐generating systemincluding all the costs overits lifetime:initial investment, operations andmaintenance, costof fuel, costof capital.

See Appendix A.4for acomplete description of financial assumptions and costing methodology

III.A.5 Technical Challenges to CO2 Capture for Coal-Based Power 

Generation 

As discussed above, CO2 removal technologies are not ready for widespread implementation 

on coal-based power plants, primarily because they have not been demonstrated at the scale 

necessary to establish confidence for power plant application (Kuuskraa, 2007). Since the CO2 

capture capacities used in current industrial processes are generally much smaller than the 

capacity required for the purposes of GHG emissions mitigation at a typical power plant, there 

is considerable uncertainty associated with process scale-up. For example, maintaining adequate 

the incremental cost per tonne of CO2 captured and is calculated by dividing the difference in COE, $/MWh, by 

the total CO2 emissions captured, tonnes/MWh. 

Report of the Interagency Task Force on Carbon Capture and Storage 34 
gas and/or liquid flow distribution in the larger absorption and regeneration reactors required 

for power plant applications could prove difficult. 

Other technical challenges associated with the application of these CO2 capture technologies to 

coal-based power plants include high capture and compression auxiliary power loads, capture 

process energy integration with existing power system, impacts of flue gas contaminants (NOx, 

SOx, PM) on CO2 capture system, increased water consumption and cost effective O2 supply 

for oxy-combustion systems (see Appendix A, Table A-3) (Kuuskraa, 2007). The following is a 

brief summary of two of the more significant technical challenges of applying these technologies. 

III.A.5.1 CO2 Capture Impacts on Water Use 

CO2 capture uses large quantities of water due to the cooling water requirements of capture 

and compression (Ciferno et al., 2010). As part of recent DOE/NETL studies, subcritical PC, 

supercritical PC, oxy-combustion, and IGCC configurations, both with and without capture, 

were evaluated for a variety of factors including water withdrawal (water removed from a 

surface or groundwater source) and consumption (water not returned to the source) (DOE, 

2010a; DOE, 2010b). The evaluations indicated that there will be a significant increase in overall 

water use by the subcritical and supercritical PC plants (80 to 90 percent), with more modest 

increases for IGCC and oxy-combustion plants (35 to 60 percent), while maintaining a constant 

net power output (see Appendix A, Figure A-8). 

III.A.5.2 CO2 Capture Impacts on Existing Plant Retrofits 

The EIA estimates that U.S. electricity demand will grow at the average annual rate of 0.9 

percent through 2035 under current policy (EIA, 2010). Analyses of current and previous 

climate legislation have shown that electricity demand growth would be substantially less than in 

the business as usual case. This relatively low growth rate implies that the bulk of power sector 

emission reductions will need to come from the existing fleet, making the availability of costeffective retrofits an important issue. Implementation of CCS to retrofit plants will be 

challenging because the size and space requirements for CO2 capture process equipment are 

significantly greater than for conventional air pollution controls. Providing adequate space for 

CCS retrofits could prove difficult for certain plants. In addition, construction will have to be 

completed around the existing equipment at the plant. Another retrofit issue relates to the 

steam energy required for solvent regeneration. Diversion of power plant steam requires 

careful integration of the steam cycle and the CO2 capture technology. Retrofits could also face 

challenges associated with proximity to a geologic sequestration site and/or a CO2 pipeline. 

III. State of CCS Technology 35 
III.B CO2 Transport 

III.B.1 Introduction 

The transportation of CO2 is a vital component of the CCS process. Even though CO2 

transportation will likely be less costly than CO2 capture, developing a transportation 

infrastructure to accommodate future CCS projects may encounter challenges regarding 

technology, cost, regulation, policy, rights-of-way, and public acceptance. However, given that 

CO2 pipelines exist today and the similarity of this infrastructure to others that have been 

developed, such as natural gas pipelines, none of these challenges is expected to be a major 

barrier to deployment. Additional supporting material appears in Appendix B. 

Pipelines are expected by many to be the most economical and efficient method of transporting 

CO2 for future commercial CCS facilities (IPCC, 2005; Parfomak and Folger, 2007). Although 

capital costs are higher for pipelines, once constructed, they reduce the uncertainty associated 

with logistics, fuel costs, and reliance on other infrastructure that could increase the cost of 

CO2 transportation. 

CO2 pipelines require the same attention to design, monitoring for leaks, and protection against 

overpressure as natural gas pipelines. The operational experience and similarity between 

construction and operation of CO2 and natural gas pipelines provides experience that can be 

used to estimate future CO2 transportation costs (Cosham and Eiber, 2008). 

III.B.2 Existing CO2 Pipeline Infrastructure 

The history of transporting CO2 via pipelines in the United States spans over 35 years. The 

oldest long distance CO2 pipeline in the United States is the 140-mile Canyon Reef Carriers 

Pipeline in Texas, which began service for EOR in regional oilfields in 1972. In contrast, 

pipelines for natural gas transmission originated almost exactly 100 years earlier in 1872, when 

the first pipelines were built in Titusville, Pennsylvania, the birthplace of the modern oil 

industry. Approximately 50 million tonnes per year of CO2 are transported through 

approximately 3,600 miles of CO2-dedicated pipelines in the United States (see Appendix B, 

Figure B.1) (Dooley et al., 2008). To put this in perspective, there are approximately 500,000 

miles of hazardous liquid and natural gas pipelines, not including the 2.2 million miles of natural 

gas distribution lines, in the United States today (PHMSA, 2010). 

III.B.3 CO2 Design Construction, Operations and Safety 

The design, construction, operation, and safety requirements for CO2 pipelines have been 

developed over the past 30 years and are not considered barriers to the deployment of CCS 

technologies for the five to ten commercial projects planned by 2016 or commercial efforts 

after 2020. The standards for CO2 pipelines are detailed in 49 C.F.R. § 194 and administrated by 

the US Department of Transportation Pipeline and Hazardous Materials Safety Administration 

Report of the Interagency Task Force on Carbon Capture and Storage 36 
(PHMSA) and various State agencies. Additional information on design, construction, operation, 

and safety requirements are discussed in Appendix B. 

III.B.4 CO2 Transport Cost 

Cost estimates for constructing new CO2 pipelines and for transporting CO2 through these 

pipelines depend on a variety of factors such as the distance between the capture and storage 

points, the terrain the pipeline has to pass through, the anticipated flow rate of CO2, and 

population and infrastructure development density. In certain circumstances, it may be more 

economical to transport CO2 a longer distance to a lower cost high-quality storage formation 

than it is to transport it over a short distance to a more expensive storage operation in a lower 

quality storage field. Local costs for labor and materials will also affect overall CO2 

transportation costs. Recent studies have shown that CO2 pipeline transport costs for a 100­

kilometer (62 mile) pipeline transporting 5 million tonnes per year range from approximately 

$1 per tonne to $3 per tonne, depending on the factors discussed above (McCollum and 

Ogden, 2006; McCoy and Rubin, 2008). 

Transporting CO2 via pipelines presents opportunities for cost sharing if multiple capture 

facilities could use parts or all of the same pipeline system to become fully integrated with 

storage sites. 

III.B.5 Anticipated Future CO2 Pipeline Development 

If CCS becomes commercially deployed, pipelines are expected to become the principal form of 

transport to bring CO2 from point sources to geologic storage sinks such as saline formations, 

coal seams, and oil and gas fields (Dooley et al., 2008). A review of the 500 largest CO2 point 

sources (primarily coal-fired power plants) in the United States shows that 95 percent are 

within 50 miles of a possible storage site (Dooley, 2006). However, until a geologic storage 

formation is fully characterized, the length of the pipeline needed cannot be assumed. In 

addition, incentives for CO2 storage and EOR could influence how a pipeline network may 

evolve. 

Modeling of the ACES Act of 2009 projects that by 2020 and 2030, approximately 180 and 480 

million tonnes, respectively, would be captured, transported, and securely sequestered in deep 

geologic formations. These quantities of CO2 represent between 4 and 10 times the amount of 

CO2 transported in the United States in 2009, resulting in a need to construct new pipelines. 

Separate studies completed by the Interstate Natural Gas Association of America (INGAA) and 

the Pacific Northwest National Laboratory (PNNL) looked at the amount of infrastructure 

necessary to support future CCS deployment (Dooley et al., 2008; The INGAA Foundation, 

III. State of CCS Technology 37 
 

 

2009).46 The estimated length of pipelines needed for commercial deployment of CCS ranged 

from 5,000 to 13,000 miles in 2020 and from 22,000 to 36,000 miles through 2030. Between 

1998 and 2007 the natural gas industry built 20,829 miles of pipelines in the United States (EIA, 

2008). While expected construction rates seem reasonable, CO2 pipeline development will 

compete for resources, training needs, and additional draws on quantities of available 

commodities such as steel. 

III.C CO2 Storage 

CO2 storage refers to the process of injecting CO2 into subsurface formations for long-term 

sequestration. CO2 storage projects are multi-phase operations that include: (1) a pre-injection 

phase of site characterization that involves geologic evaluation of site suitability, modeling to 

predict the extent of the CO2 plume and pressure front, and identification and plugging of 

artificial penetrations that could serve as conduits for fluid movement; (2) an operational phase 

during which CO2 is injected and the injection well is tested, ground water geochemistry is 

monitored, and the CO2 plume is tracked; and (3) a post-injection phase of site monitoring to 

verify that the project poses no risk to underground sources of drinking water (USDWs) and 

site closure. 

This section of the report presents a brief overview of CO2 storage in geologic reservoirs. CO2 

reuse is not addressed in this section, but is considered a potential alternative approach to 

mitigating CO2 emissions and is discussed in Appendix D. 

III.C.1Introduction 

Although engineered storage of CO2 in geologic reservoirs is a relatively new concept, largescale natural CO2 formations are known in numerous reservoirs worldwide, and many natural 

gas formations contain CO2. These natural examples demonstrate that large volumes of CO2 

can be retained in the subsurface stably over geologic time. Natural reservoirs can store as 

much as 5,600 million tonnes (100 trillion cubic feet) of CO2 and can be as pure as 98 percent. 

They also provide natural laboratories to test the long-term interaction of CO2 with subsurface 

fluids, reservoir mineralogy, and seals. 

III.C.2 Status of Technology 

III.C.2.1 CO2 Enhanced Oil Recovery 

Since the 1970s, engineered injection of CO2 into geologic reservoirs has occurred in the 

context of EOR. CO2-EOR and enhanced gas recovery technologies are used in oil and gas 

46 CCS deployment rates in the INGAA study are based on a summary of projections from a variety of legislative 

and other scenarios (page 57). CCS deployment rates in the PNNL study are based on WRE 450 and WRE 550 

climate stabilization policies. 

Report of the Interagency Task Force on Carbon Capture and Storage 38 
 

 

reservoirs to improve production efficiency. Injection of CO2 is one of several enhanced 

recovery techniques that have successfully been used to boost production efficiency of oil and 

gas by re-pressurizing the reservoir, and in the case of oil, by also increasing mobility. Although 

some features of CO2 storage may differ from EOR operations, these operations have 

developed many aspects of reservoir management and operation needed for the large-scale 

injection of CO2. Use of such large volumes of CO2 in EOR has shown that CO2 can be injected 

at an industrial scale safely for long periods of time. Currently, approximately 50 million tonnes 

of CO2 per year are injected, produced with the oil, captured, and re-injected. These 

operations are large in scale, with some injecting millions of tonnes of CO2 per year, and some 

having already accumulated tens of millions of tonnes (Sweatman et al., 2009). As of year-end 

2010, there were 114 CO2-EOR projects within the United States producing 272,000 barrels of 

oil per day (Oil and Gas Journal, 2010). 

Future deployment of CCS may fundamentally alter EOR in the United States. Many early 

geologic storage projects may be sited in, or below, depleted or active oil and gas reservoirs 

because the reservoirs have already been characterized for hydrocarbon recovery, may have 

suitable infrastructure (e.g., wells and pipelines) in place, and may provide revenues associated 

with recovery of additional crude oil. In addition, oil and gas fields now considered to be 

depleted may resume operation if there is an increase in availability and decrease in cost of 

anthropogenic CO2. However, the extent that CO2-EOR will be coupled with CCS remains 

uncertain (Dooley et al., 2010a). 

In the context of CCS coupled with EOR, new reservoir management strategies may be 

needed: current strategies minimize CO2 used per barrel of oil produced, whereas CCS 

strategies will likely seek to maximize CO2 stored. These changes in use of the reservoir would 

result in pressure increases. EPA is developing tailored regulatory requirements and 

management strategies to safeguard public health and the environment in light of this effect (see 

section IV.B for details). 

III.C.2.2 CO2 Storage Potential 

CO2 storage potential is estimated to be large. Estimates based on DOE and International 

Energy Agency (IEA) studies indicate that areas of the United States with appropriate geology 

could theoretically provide storage potential for more than 3,000 billion tonnes of CO2—large 

enough to store the amount of CO2 emissions currently emitted from the entire coal fired 

electricity sector in the United States for over 1,000 years.47 

As an outgrowth of efforts in the Regional Carbon Sequestration Partnership (RCSP) program, 

DOE produced the 2008 Carbon Sequestration Atlas of the United States and Canada, which 

47 The coal fired electricity sector emitted 1,945.9 million tonnes of CO2 in 2008. (EIA, 2009) 

III. State of CCS Technology 39 
 

evaluated geologic storage potential with respect to three categories of storage reservoirs. The 

Atlas reports that storage resource and capacity48 in various types of formations in the United 

States and parts of Canada could be as high as: 

 Oil/gas fields: approximately 140 billion tonnes; 

 “Unmineable”49 coal seams: approximately 160–180 billion tonnes; and 

 Saline formations: approximately 3,300–12,600 billion tonnes. 

Storage resource estimates are regionally variable, but details are being refined in ongoing 

efforts by both DOE and USGS. Estimates of the magnitude of storage resource contain 

uncertainties arising from a number of factors, including geologic factors (e.g., heterogeneity in 

reservoir porosity/permeability, caprock integrity, etc.) and hydrologic factors (e.g., movement 

of CO2, brines, and pressure fronts). These storage resource estimates do not assess economic 

feasibility. 

The Intergovernmental Panel on Climate Change (IPCC) concluded that there is need for 

“more development and agreement on assessment methodologies” for estimates of storage 

resource (IPCC, 2005). Research by DOE and USGS is addressing some of the factors 

contributing to uncertainties in estimates, for example: 

 Improvements to the efficiency factors (the portion of pore space that the CO2 can 

occupy) used in estimates of storage resource and capacity; 

 Clarification of open vs. closed reservoirs and potential impact on estimates of storage 

resource capacity; and 

 Expansion of site-specific details necessary for rigorous assessments. 

Under authority provided to it in the Energy Independence and Security Act of 2007 (P.L. 111­

140), the USGS has published a methodology for carrying out a national assessment for geologic 

sequestration (Brennan et al., 2010). USGS is using this methodology to begin an assessment of 

the United States’ potential for geologic carbon sequestration in petroleum reservoirs and 

saline formations. 

48 Storage capacity implies a very high level of confidence in the accuracy of the estimates of pore volume available 

for storage and ready for commercial development. This results from significant investment of funding into site 

characterization activities to prove the certainty of the injection zones to safely store the commercial quantities 

needed by the point source operator. Storage resources, however, do not have commercial status. Instead they 

can be categorized based on the amount of characterization that has been performed to reduce the uncertainty of 

the pore volume to be able to accept and permanently store commercial quantities of CO2. 

49 An official definition of “unmineable” has yet to be determined and varies with technological advances and 

economics; the Atlas numbers assume 2008 technology and economics, as discussed in detail in Appendix C. 

Report of the Interagency Task Force on Carbon Capture and Storage 40 
 

III.C.2.3 CO2 Storage Security 

The technical community believes that many aspects of the science related to geologic storage 

security are relatively well understood. For example, IPCC concluded that “it is considered 

likely50 that 99 percent or more of the injected CO2 will be retained for 1,000 years” (IPCC, 

2005). However, additional information (including data from large-scale field projects with 

comprehensive monitoring) is needed to confirm predictions of the behavior of natural systems 

in response to introduced CO2 and to quantify rates for long-term processes that contribute to 

trapping and, hence, risk profiles (e.g., IPCC, 2005). 

Commercial-scale experience is limited but encouraging; these efforts are working to 

demonstrate that application of the best available science and technology is central to ensuring 

storage integrity at each site. Experience at commercial-scale sites includes the following: 

 Up to 14 years of continuous monitoring at large-scale CCS projects demonstrates 

geologic storage security (e.g., Sleipner, Snøhvit, Weyburn, In Salah); and 

 Monitoring at large EOR sites provides additional data that suggests nearly 40 years of 

storage security (e.g., sites in the Permian basin of West Texas). 

Additional commercial-scale experience is needed to confirm these estimates for a range of 

geological conditions. 

EPA has also developed a Vulnerability Evaluation Framework (Figure III-2) to systematically 

identify those conditions that could increase the potential adverse impacts from geologic 

storage and that provides a basis for identifying key factors to minimize risk. 

50 The IPCC definition of “likely” is a probability between 66 and 90 percent. 

III. State of CCS Technology 41 
 

 

Figure III-2 Vulnerability Evaluation Framework for Geologic Sequestration of CO2 

Source: EPA (2009a) 

Broad consensus exists51 regarding potential failure modes and impacts associated with CO2 

storage. Key potential impacts could result from slow sustained releases as well as from rapid 

releases. For example, if improperly managed, CO2 storage may endanger USDWs. While CO2 

itself is not a drinking water contaminant, CO2 in the presence of water forms a weak acid, 

known as carbonic acid, that, in some instances, could cause leaching and mobilization of 

naturally-occurring metals or other contaminants from geologic formations into ground water 

(e.g., arsenic, lead, and organic compounds). Additionally, pressures induced by injection may 

force native brines (naturally occurring salty water) into USDWs, causing degradation of water 

quality and affecting drinking water treatment processes. 

CO2 is not explosive or combustible. Rapid release of CO2 could, however, damage an injection 

well during operation and provide a conduit for contamination of USDWs. If supercritical CO2 

is injected into shallow formations where pressures are not high enough to maintain its 

supercritical state and the CO2 reverts to a gas, it could cause expansion of gaseous CO2, a 

drop in temperature (the Joule-Thomson effect), and then freezing and thermal shock in the 

vicinity of the well. This thermal shock could compromise the integrity of the injection well, 

increasing potential for fluid movement and contamination of USDWs. 

51 See, for example, the EPA Vulnerability Evaluation Framework in Figure III-2 or (Carbon Sequestration 

Leadership Forum, 2009). 

Report of the Interagency Task Force on Carbon Capture and Storage 42 
 

In addition to risks to USDWs, injection activities could pose risks to the atmosphere, surface 

water, human health, ecosystems, and the physical environment. While CO2 is not toxic, direct 

exposure to elevated levels of CO2 can cause both chronic (e.g., increased breathing rate, vision 

and hearing impairment) and acute health effects to humans, animals, and vegetation, depending 

on the concentration and duration of exposure. The measures taken to prevent migration of 

CO2 to USDWs would also minimize the risk of CO2 migration to the surface. 

It is expected that, should these impacts arise, they can be detected through appropriate 

monitoring, allowing consequences to be mitigated through readily available technology. 

The risk of a rapid release of large and sustained amounts of CO2 from the storage reservoir is 

believed to be low when appropriate natural and engineered factors are accounted for, 

including: 

 During injection, pressures at the wellbore are monitored and maintained well below 

critical pressures for the reservoir to prevent over-pressurization. 

 Injection pressures drop off rapidly away from the wellbore vicinity, lowering any 

potential for rapid release. 

 Proposed SDWA Underground Injection Control (UIC) Class VI requirements for 

wellbores (see Section IV.B.1.2 for detail) specify cementing along the entirety of the 

wellbore, greatly reducing the chance of leaving an open space section for CO2 flow 

along the wells. 

 Natural mechanisms associated with the small pores in which CO2 is stored further act 

to restrict rates and volumes of CO2 released should a wellbore fail. 

Best practices documents are being developed to promote storage security, including several 

documents as products from the RCSP program and a number of guidance documents from 

EPA that will accompany its new rule-making. 

III.C.3 Demonstrations of CO2 Storage Technologies 

III.C.3.1 Regional CO2 Sequestration Partnership Projects 

In 2003, DOE initiated the Regional Carbon Sequestration Partnership (RCSP) program to 

provide guidance and experience related to developing the technology, infrastructure, and 

regulations needed to implement storage of CO2 in the various regions and geologic formations 

found across the United States. The RCSP program has three phases: identification and 

characterization of potential sequestration opportunities (Phase I), small-scale testing (Phase II), 

and large-scale testing (Phase III). Phase I has been completed, and Phase II is nearly completed. 

Phase III was initiated in 2008 and includes nine large-scale projects, one of which has already 

begun injection operations. The more than 20 small-scale field tests that were conducted as 

III. State of CCS Technology 43 
 

 

part of Phase II have already yielded valuable information on how to safely and efficiently store 

and monitor CO2 in common formations found in the United States.52 

Additional studies are planned or underway. Based on data tracked by EPA and DOE, as of 

April 2010, a total of 56 active storage or integrated capture and storage projects are in various 

phases: 13 percent are undergoing site selection/characterization, 33 percent in the preliminary 

design/ infrastructure development phase, 24 percent are in the process of obtaining permits, 4 

percent are drilling wells, and 26 percent are injecting. (See Appendix C.1.3 for more detail.) 

III.C.3.2International Geologic Storage Projects 

Engineered storage of CO2 is occurring at several large-scale operations: Sleipner in the North 

Sea, Snøhvit in the Barents Sea, In Salah in Algeria, and Weyburn in Canada. Although limited in 

number, these projects demonstrate CO2 storage at commercial scale over a variety of geologic 

conditions and monitoring approaches that will be applicable to many potential CO2 storage 

sites worldwide. (See Appendix C for details). 

III.C.4CO2 Storage Cost 

Costs associated with CO2 storage have been estimated to be approximately $0.4–20/tonne.53 

For example, the IPCC summarized several studies from 2002–2005 reporting estimates in the 

range $0.4–12.2/tonne CO2 stored plus $0.16–0.30/tonne CO2 stored (undiscounted) for 

monitoring (IPCC, 2005). Estimates vary depending on numerous factors, including type of 

reservoir, existing information/infrastructure for the site, onshore versus offshore storage, 

extent of monitoring, regional factors, etc. Costs may vary regionally and could affect 

“dispatching” of geologic storage options, which, in turn, would affect strategies for 

development of any pipeline networks. Costs may vary over time as earlier operations exploit 

more certain and lower-cost storage sites. Recent estimates of storage costs derived from 

current commercial-scale projects are $11–17 per tonne (Sleipner); $20 per tonne (Weyburn) 

and $6 per tonne (In Salah). 

Additional revenues from oil production may offset some costs for CO2 storage in the context 

of an EOR operation. CO2-EOR provides two potential economic incentives for encouraging 

the deployment of CCS, 1) CO2 sales revenues at the individual project level, and 2) an increase 

in the total amount of domestic crude oil production. At the present time, an important limiting 

factor in new CO2-EOR projects is a shortage of CO2. 

52 Additional information about the partnership projects is available at 

http://www.netl.doe.gov/technologies/carbon_seq/partnerships/partnerships.html. 

53 Cost estimates are limited to capital and operational costs, and do not include potential costs associated with 

long-term liability. 

Report of the Interagency Task Force on Carbon Capture and Storage 44 
The willingness of oil producers to pay for CO2 supplies has the potential to defray a portion of 

the cost of building carbon capture and transportation facilities, particularly for those projects 

built first, as it is understood that the total EOR requirements are likely to be significantly less 

than most scenarios for the deployment of CCS. For example, several CCS projects listed in 

Table V-2 plan to sell their captured CO2 for EOR. Along with Federal funding, the CO2 sales 

are an important part of the project funding. 

The second potential benefit of EOR for deployment of CCS is associated with increasing total 

domestic crude oil production which, in turn, reduces crude oil and product import 

dependency and the associated net expenditures on imports. For example, in EIA’s AEO2010 

reference case crude oil production from CO2-EOR in 2035 is projected to be 1.3 million 

barrels per day. EIA found in its analysis of the American Power Act of 2010 that the additional 

CCS deployment spurred by the legislation would result in 0.8 to 1.0 million barrels per day of 

additional crude oil production (EIA, 2010). The resulting reduction in U.S. net import 

expenditures from the incremental domestic crude oil production would range from $36 billion 

to $45 billion per year using a case crude oil price of $124 per barrel. 

Additional information is needed from ongoing CCS projects, as well as information related to 

costs associated with regulatory compliance (including monitoring costs and long-term 

stewardship costs) (e.g., IPCC, 2005). 

III.C.5Technical and Other Considerations for CO2 Storage 

III.C.5.1 Geologic Siting and Area of Review Monitoring 

Site characterization is a fundamental component of selecting safe locations for geologic 

storage. The proposed new Class VI regulation under the SDWA UIC program requires 

owners or operators of CO2 storage wells to perform detailed assessments of the geologic, 

hydrogeologic, geochemical, and geomechanical properties of the proposed CO2 storage site. 

These assessments are intended to ensure that sequestration wells are sited in appropriate 

locations and inject into suitable formations that can receive and confine injected fluids to 

ensure protection of USDWs from endangerment in the onshore environment and the subseabed within State territorial waters. Data collected during site characterization also inform 

the development of construction and operating plans, provide inputs for area-of-review (AoR) 

delineation models (see below), and establish baseline information to which geochemical, 

geophysical, and hydrogeologic site monitoring data collected over the life of the injection 

project can be compared. 

Under the UIC Class VI proposed rule, operators of geologic storage projects must also model 

the AoR, which includes the region surrounding the geologic storage project where USDWs 

may be endangered by the injection activity. The AoR is delineated using computational 

modeling that accounts for the physical and chemical properties of all phases of the injected 

CO2 stream; it is based on available data collected during the site characterization process. 

III. State of CCS Technology 45 
Operators must also periodically reevaluate the AoR over the life of the project to incorporate 

CO2 monitoring and operational data into models in order to ensure that the CO2 plume is 

moving within the subsurface as predicted. 

III.C.5.2 Monitoring, Verification, and Accounting 

Monitoring, verification, and accounting (MVA) are important components of managing a 

geologic storage project and ensuring that the CO2 plume and associated pressure front are 

moving through the subsurface as predicted. In the proposed new Class VI regulation under the 

SDWA UIC program, during injection operations, operators must develop and implement a 

comprehensive testing and monitoring plan for their projects that includes injectate monitoring; 

corrosion monitoring of the well’s tubular, mechanical, and cement components; pressure falloff testing; mechanical integrity testing of the well; ground water quality monitoring; and CO2 

plume and pressure front tracking. A rigorous monitoring regime will provide information 

about site performance when compared against baseline information, previous monitoring 

results, and simulation models of site operations. 

Wide-scale deployment will need validated quantifiable protocols for each stage of a CCS 

project. Variation in local surface and subsurface characteristics necessitate that these 

monitoring strategies are site-specific, but general approaches (including the establishment of 

standards) are needed, particularly in the context of wide-scale deployment of CCS. In addition, 

the development of risk-based monitoring protocols may also be appropriate to verify 

predictions of the site performance and/or to integrate with risk-minimization strategies. 

Additional information on MVA technologies can be found in the EPA General Technical 

Support Document to the proposed GHG reporting rule for CO2 sequestration facilities (EPA, 

2009b), IPCC Guidelines for National Greenhouse Gas Inventories (IPCC, 2006), API/IPIECA 

Guidelines for CCS (IPIECA, 2007), Department of Energy MVA Best Practices Manual (NETL, 

2009a), and the International Energy Agency GHG R&D Programme monitoring tool Web site 

(IEA, 2009b). In addition, Dooley et al. have summarized MVA technologies being deployed at 

current CCS projects (Dooley et al., 2009). 

Continued development is needed for MVA tools to improve aspects related to quantification 

and resolution of CO2 in the subsurface, detection of fractures and other potential leakage 

paths, intermittent leakage, etc. (IPCC, 2005). 

III.C.5.3Post Injection Site Care 

The proposed new UIC Class VI regulation under the UIC program (see Section IV.B.1.2 for 

details) includes detailed requirements for monitoring following cessation of injection; under 

this proposed regulation, operators of geologic sequestration wells will be required to perform 

comprehensive and extended post-injection monitoring and site care to verify that the CO2 

plume is moving as predicted. This monitoring continues until it can be demonstrated that 

Report of the Interagency Task Force on Carbon Capture and Storage 46 
 

movement of the CO2 plume and pressure front have stabilized and the injectate does not pose 

a risk to USDWs. 

III.C.5.4 Long-Term Stewardship 

Geologic storage security is expected to increase over time through post-closure, resulting in a 

decrease in potential risks. This expectation is based in part on a technical understanding of the 

variety of trapping mechanisms that work to reduce CO2 mobility over time (e.g., IPCC, 2005). 

In addition, site characterization, site operations, and monitoring strategies can work in 

combination to promote storage security.54 As a result, risk profiles are expected to decline 

over time (Figure III-3). 

Figure III-3 Qualitative Profile of Environmental Risk Over Time 

for a CO2 Storage Operation. 

Risk is expected to increase during the injection phase of a storage project but decline over time as the system equilibrates 

and multiple trapping mechanisms engage. 

Source: Adapted from Benson (2007) 

Risk factors depend on site-specific characteristics, so they must be assessed for each potential 

geologic storage site. However, experience from large demonstrations, oil/gas industry, etc. has 

provided insight into a number of key considerations for minimizing risks, including ensuring 

wellbore integrity, ensuring seal integrity, and maintaining appropriate injection pressures. 

Long-term stewardship will require a quantitative, probabilistic methodology to calculate risk 

profiles at geologic storage sites. Large-scale tests and commercial projects are developing field 

experience to confirm methodologies and tools that form the technical basis for long-term 

predictions; natural analog sites are available for observations to confirm long-term predictions. 

54 DOE is developing best practices documents on these factors based on experience from the Regional Carbon 

Sequestration Partnership program. 

III. State of CCS Technology 47 
DOE’s National Risk Assessment Partnership (NRAP) initiative is building the scientific basis for 

quantifying risk profiles. NRAP comprises a broad interdisciplinary team of scientists and 

engineers drawn from across the DOE complex developing and confirming (through targeted 

laboratory and field observations/experiments) a suite of science-based tools for calculating the 

residual risk associated with specific geologic storage sites. 

III.C.5.5Potential Impact of Impurities in the CO2 Stream 

Purity of the injected CO2 stream is a consideration for storage because co-captured impurities 

could affect the storage processes in a number of ways, including by changes in pH and 

oxidation state that might affect dissolution and precipitation reactions as well as mobility of 

metals present in the reservoir rocks. These factors can be incorporated into evaluations of a 

proposed storage operation. Details on the potential impacts of impurities are discussed in 

Appendix C.3.2. 

III.C.5.6Multiple Injections in a Single Basin 

Scale-up from a limited number of demonstration projects to widescale commercial 

deployment increases the likelihood of multiple injections within the same storage basin. This 

may necessitate consideration of basin-scale interactions and impacts. For example, brine 

displacement and/or pressure buildup could have impacts both locally (e.g., integrity of the 

caprock) and basin-wide (e.g., overlap of pressure fronts, which could limit effective storage 

capacity). Pressure management schemes, such as brine extraction from deep storage 

reservoirs, may be options to mitigate some of the basin-scale factors associated with widescale deployment. 

III.C.5.7 Property Rights 

Deployment of CO2 sequestration would necessitate addressing several land use and property 

rights issues, including obtaining permission from the surface owner for the injection well(s) and 

related surface facilities; securing rights-of-way (e.g., for pipelines); placement and access to 

monitoring wells and devices at various locations; subsurface movement of injectate; and 

elevated regional pressure fronts due to injection. New Federal requirements proposed under 

the UIC Program for CO2 storage wells include a provision that owners or operators of a 

geologic sequestration well submit a corrective action plan as part of their permit application. 

The plan should identify how site access would be guaranteed for areas requiring future 

corrective action. Access may also be needed for other aspects of the CO2 storage operation, 

such as groundwater monitoring outside of the injection zone. Stakeholders noted aggregation 

of subsurface pore space within target injection formations as particularly critical to the success 

of CO2 storage projects in the near- and long-term. 

Report of the Interagency Task Force on Carbon Capture and Storage 48 
 

 

Pore Space Ownership 

CO2 sequestration project developers would have to identify the owners of property rights or 

interests in the pore space of a target injection formation and confining layer. Injectors would 

need to obtain the rights to ownership or use of pore space in which they are storing CO2. 

Pore space ownership issues will vary from State to State. In States where there is no prior 

mineral severance, the owner of the surface estate is deemed to be the owner of the 

subsurface pore space. This would make the owner of the surface estate the entity from which 

the project developer would need to obtain ownership, a lease, or access to, the pore space. 

Where subsurface minerals exist, many surface owners may have severed ownership of the 

subsurface mineral rights and conveyed them to third parties. In these arrangements, generally 

the subsurface owner has the legal right to reasonable use of the surface estate for production 

of the minerals. A potential conflict may result when there are competing uses of the surface 

estate for the purposes of CO2 storage and mineral production. 

Aggregation of Pore Space 

Pore space could be acquired through an agreement with a single owner who owns all surface 

and subsurface rights. However, issues may arise where pore space needs for CO2 storage 

extend over an area where numerous owners hold rights. Currently in most States, owneroperators would need to engage in private commercial transactions with property owners to 

acquire ownership or lease the pore space. While this is a feasible approach where relatively 

few owners have rights to large areas of pore space and are willing to sell or lease, the use of 

private commercial transactions can become more challenging where owner-operators would 

need to engage in individual negotiations with an extremely large number of property owners. 

Several options for reducing uncertainty about the ownership of pore space in the United 

States, including both on the State and Federal levels, have been proposed by stakeholders, 

addressing the scale of subsurface pore space required for CO2 storage. These options are 

diverse; some would rely on private transactions, some on action by State government, and 

some on Federal intervention. These options are discussed in Appendix L. Which option or 

options are appropriate will depend on, among other factors, the success of private commercial 

transactions in resolving pore space issues and the extent and nature of State legislation in this 

area. In addition, several States have taken action to clarify or to codify the rules relating to 

CO2 storage property-rights issues such as ownership, access to pore space, interaction 

between mineral estate interests and CO2 injection operations.55 

55 Selected State legislation relating to CO2 sequestration property rights as of April 2010 includes Louisiana (La. 

Rev. Stat. Ann. § 30:2104(E) (2010)), Montana (Lont. Code Ann. § 82-11-180 (2010)), North Dakota (N.D. Cent. 

Code §§ 38-20-10, 47-31 (2010), Oklahoma (Okla. Stat. 27A § 3-5-105(A) (2010)), Texas (Texas Nat. Res. Code 

Ann. § 120.002 (2010)), and Wyoming (Wyo. Stat. Ann. §§ 34-1-152, 34-1-202, 35-11-316 (2010)). 

III. State of CCS Technology 49 
 

 

III.D Conclusions 

III.D.1 CO2 Capture 

 Carbon dioxide gas separation technologies have been developed and employed in the 

industrial sector (e.g. petroleum refining, natural gas purification) for more than 70 

years. 

 Current technologies could be used to capture CO2 from new and existing fossil energy 

power plants; however, they are not ready for widespread implementation primarily 

because they have not been demonstrated at the scale necessary to establish confidence 

for power plant application. Since the CO2 capture capacities used in current industrial 

processes are generally much smaller than the capacity required for the purposes of 

GHG emissions mitigation at a typical power plant, there is considerable uncertainty 

associated with capacities at volumes necessary for commercial deployment. 

 Cost estimates for employing current technologies on new and existing fossil energy 

power plants in terms of cost per tonne of CO2 avoided, range from $60/tonne for 

IGCC, $95/tonne for PC to $114/tonne for NGCC.56 

 Existing CO2 separation technologies deployed on new and existing fossil energy power 

plants will result in a significant energy penalty, up to 30 percent. 

 Ten large-scale power plant and industrial plant demonstrations projects are currently 

being pursued by DOE and will provide information and experience regarding 

operations at scale. 

III.D.2 CO2 Transport 

 Technologies for the transport of supercritical CO2 through pipelines exist today. 

 Approximately 3,600 miles of CO2-dedicated pipelines exist in the United States, 

carrying approximately 50 million tonnes to enhanced oil recovery projects. 

 It is anticipated that comprehensive climate change legislation could incentivize the 

deployment of the technology and require industry to expand the existing network of 

CO2 pipelines. 

 No technology barriers have been identified that would hinder the development of 

these additional pipelines in the United States. 

56 The dollar per tonne of CO2 avoided is the incremental cost of CO2 emissions avoided by applying CCS and is 

compared to a similar non-captured facility. It is calculated by dividing the difference in COE, $/MWh, by the 

difference in CO2 emissions with and without CO2 capture, tonnes/MWh. The dollar per tonne CO2 captured is 

the incremental cost per tonne of CO2 captured and is calculated by dividing the difference in COE, $/MWh, by 

the total CO2 emissions captured, tonnes/MWh. 

Report of the Interagency Task Force on Carbon Capture and Storage 50 
 Challenges may exist with respect to resource constraints that the industry and market 

place will need to address over time. 

III.D.3 CO2 Storage 

 Large-scale CO2 injection for sequestration purposes is already occurring at several 

sites, providing a foundation for commercial-scale demonstrations. 

 Ongoing regional-scale assessments suggest a large resource potential for storage in the 

United States. Detailed site assessments (e.g., ongoing DOE and USGS efforts) aim to 

demonstrate site capacities that can lead to refined national capacity estimates. 

 To enable widespread, safe, and effective CCS, CO2 storage should continue to be fielddemonstrated for a variety of geologic reservoir classes, with large-scale projects 

targeted at high-priority reservoir classes and smaller-scale projects covering a wider 

range of classes that are important regionally. 

 Storage security is believed to increase over time. Field-validated methodologies will 

help to quantify potential for risks tied to long-term liability. 

 Scale-up from a limited number of demonstration projects to widescale commercial 

deployment may necessitate the consideration of basin-scale factors (e.g., brine 

displacement, overlap of pressure fronts, spatial variation in depositional environments, 

etc.). 

III. State of CCS Technology 51 

 

 

IV. Current Barriers and Concerns for CCS Deployment and 

Commercialization 

There are four major concerns for near- and long-term deployment of CCS technologies: 

 The existence of market failures, especially the lack of a climate policy that sets a price 

on carbon and encourages emission reductions. 

 The need for a legal/regulatory framework for CCS projects that facilitates project 

development, protects human health and the environment, and provides public 

confidence that CO2 can be stored safely and securely. 

 Clarity with respect to the long-term liability for CO2 sequestration, in particular 

regarding obligations for stewardship after closure and obligations to compensate parties 

for various types and forms of legally compensable losses or damages. 

 Integration of public information, education, and outreach throughout the lifecycle of 

CCS projects in order to identify key issues, foster public understanding, and build trust 

between communities and project developers. 

In addition, some stakeholders have voiced concerns about training/workforce capacity and 

physical/infrastructure capacity. The widespread cost-effective deployment of CCS will require 

hiring, training, and retaining a large workforce of highly skilled professionals in the private 

sector to design, build, and operate facilities. Similar workforce challenges will face the public 

sector in meeting the need for permitting and regulating CCS activities. 

The Task Force recognizes that aggregation of pore space can be a barrier to deployment of 

CO2 sequestration projects, as noted earlier, and that several States are taking actions to 

address this issue.57 Several options to address aggregation of pore space are presented in 

Appendix L. 

Siting considerations for CO2 pipelines may evolve with time as a function of CCS deployment 

rate and geographic distribution. This report reviews varying models of oversight between 

Federal, State and local entities. (See Appendix M for more details.) 

This section outlines current barriers and concerns for CCS deployment for the four major 

issues identified above. Options for addressing each issue and their advantages and 

disadvantages are presented in Sections V, VI, VII, and VIII. 

57 See Section III.C.5.7. 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 53 
IV.A Market Failures 

IV.A.1 Overview 

The role for government in the deployment and commercialization of CCS is based on the 

premise that it is subject to market failures (instances where the free market does not yield an 

optimal outcome). Economists generally propose that government intervention in the economy 

is justified when there is both an identifiable market failure and a feasible means for overcoming 

or compensating for the market failure in such a way that the net benefits are likely to be 

positive. The costs of intervention involve the potential for introducing inefficiencies, such as 

distortions to capital and labor markets that result from policies that are poorly targeted in 

scope or size, and from distortionary taxes used to raise revenue to pay for the intervention. 

The opportunity cost of lost spending on other government priorities is another important 

consideration. 

The market failures that prevent investors from capturing the full social benefit of investments 

in technologies that mitigate GHG emissions result in less than optimal levels of investment in 

these technologies, and may impede cost-effective deployment. CCS is not unique in this regard 

– it is one of many technologies affected by this market failure. Cost, in and of itself, is not a 

barrier, because markets use cost information as a guide for investment behavior to deliver 

least-cost solutions. However, the two market failures described below impede early CCS 

deployment that could provide learning and lower future costs. Therefore, a complementary 

portfolio of measures to target these market failures will introduce incentives for the costeffective deployment of CCS. 

IV.A.2 Failure to Account for Social Cost of Greenhouse Gas Emissions 

The foremost economic barrier to developing and deploying low-carbon technology is the 

market’s failure to price the negative externality of GHG emissions that drive anthropogenic 

climate change, in other words, a price on carbon. Establishing a clear price signal on GHG 

emissions that rises over time will incentivize businesses to look for ever-cheaper ways to 

reduce emissions. It will also put established low-carbon technologies on a level playing field 

with conventional carbon-emitting technologies, yield near-term opportunities for emerging 

technologies, and create greater market certainty for long-term investments in new or 

improved low-carbon energy technology development. 

Internalizing the cost of GHG emissions is a threshold barrier for further CCS technological 

development. Without an economic consequence for emitting GHGs, there is no economic 

rationale for capturing and storing emissions. However, a GHG price signal does not address 

the other major market failure affecting CCS development, as described below, which requires 

a separate policy remedy. 

Report of the Interagency Task Force on Carbon Capture and Storage 54 
IV.A.3 Knowledge Spillovers from Research and Development of CCS 

Technology 

Even with clear market signals that internalize the full cost of GHG emissions, technological 

progress can be delayed by another market failure: the inability of private-sector innovators to 

incorporate the full benefits from the knowledge they create in researching, developing, and 

deploying new technologies. This phenomenon, known as “knowledge spillovers,” leads private 

sector actors to under-invest in RD&D. Private sector actors will tend to invest only to the 

extent that their RD&D costs are less than the appropriable, private benefits, even though such 

investment may provide additional social benefits. Put simply, individual firms will not typically 

take on investments for the good of the broader industry or society as a whole unless there is a 

clear return on that investment to the firm. Therefore, the private market has a limited 

incentive to invest in “shared learning” that would lead to an improved economic outcome for 

society as a whole. This market failure is most pronounced for research in the basic sciences, 

which can yield highly valuable but difficult to appropriate economic returns. 

Investments that create knowledge further down the chain of technology development and 

deployment can also create spillovers. For instance, the experience of designing, fabricating, and 

operating the initial CCS installations (including separating, transporting, and storing CO2) 

creates knowledge (often referred to as learning-by-doing), and some portion of the gains from 

that knowledge cannot be captured by the firm making the investments. 

As a technology moves through the life cycle from basic research to more targeted 

development and ultimately deployment, the share of the knowledge generated––and therefore 

the benefits of that knowledge––that is not appropriable by the investor tends to get smaller. 

This is largely because a larger share of the total social benefit created by innovations in the 

technology can be captured by those making the investments through patents or other means. 

The smaller spillovers that occur as technologies mature, along with the fact that we do not 

know ex ante which particular technologies will be the most cost-effective, suggest that care 

must be taken in targeting incentives so as not to create distortions that outweigh the gains to 

society of promoting a particular technology. 

Figure IV-1 shows a stylistic representation of the relationship between spillovers as a share of 

the total benefit to society of new knowledge and the phase of knowledge/technology 

development. Section V of this report describes how policy makers can address the market 

failure of knowledge spillovers, including the advantages and disadvantages of applying a variety 

of incentive structures for the public share of investment in CCS technology. 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 55 
 

Figure IV-1 Private versus Spillover Benefits of Knowledge Creation 

IV.B Regulatory Framework Governing the Capture, Transportation, 

and Storage of CO2 

Regulatory uncertainty is widely identified as a key barrier to CCS deployment in the United 

States. Existing environmental statutes and programs such as the SDWA UIC Program apply to 

geologic sequestration of CO2. However, because CCS has not been widely deployed, there is 

uncertainty about how environmental statutes will apply, whether there are gaps or overlaps, 

and if the current framework is adequate for both near- and long-term deployment of CCS. 

This section describes how key provisions of current environmental, natural resources, and 

other laws may govern the capture, transportation, and sequestration phases of CCS.58,59 This 

58 The full array of Federal, State, and local laws, as applicable, will govern any particular CCS project. Appendix F 

and Appendix G analyze in greater detail how selected environmental, natural resource, and other laws may apply 

to CCS. Acquisition of property rights needed to inject and store CCS and short- and long-term liability potentially 

Report of the Interagency Task Force on Carbon Capture and Storage 56 
 

section also identifies some near- and longer-term challenges with implementing the existing 

regulatory framework. 

IV.B.1 Current Framework 

The current regulatory framework supports CCS projects moving forward now. The discussion 

below highlights two types of “cross-cutting” laws that may apply to all phases of CCS; 

examines those laws most relevant to each phase of CCS as deployed on private, onshore 

lands; and explains the regulatory framework uniquely applicable to deployment of CCS on 

Federal lands. Section VI provides more information on aspects of the current regulatory 

framework for CCS. 

IV.B.1.1 Selected Cross-Cutting Laws 

National Environmental Policy Act (NEPA) 

CCS activities may trigger various Federal and State environmental planning review obligations. 

Of these, the Federal statute likely to be applicable to most phases of CCS projects is the 

National Environmental Policy Act (NEPA), 42 United States Code (U.S.C.) §§ 4321 to 4370f.60 

NEPA establishes national policy and goals to improve Federal planning by considering and 

minimizing impacts to the environment, and requires all Federal executive branch agencies to 

undertake specified assessments before they make final decisions about Federal actions that 

could have environmental effects. The environmental review process under NEPA also provides 

multiple opportunities for the public, States, Tribes, and local governments, among others, to 

participate in the Federal agency decision-making process, which will be critical to the success 

of CCS. Compliance with NEPA provides the opportunity for Federal agencies to cooperate 

throughout the NEPA process to ensure that the analysis addresses all relevant issues and to 

use a single document as the basis for final permitting decisions. 

NEPA applies to a broad range of actions subject to Federal control or responsibility. Use of 

Federal or Tribal lands for the purposes of CO2 pipeline siting or sequestration will require 

NEPA analysis. Non-Federal projects, which are not normally subject to NEPA, may become 

Federal actions where they are financed, assisted, or approved in whole or in part by the 

Federal government; however, this is a very complex area of the law and requires a factaccruing from CCS are addressed in section III.C.5.7 and IV.C, respectively; the role of public lands in deployment 

of CCS is covered in section IV.B.1.3. 

60 Other cross-cutting Federal statutes may be relevant to a CCS project in some instances. For example, where 

Federal or private actions in CCS deployment might affect endangered or threatened species and their habitats in 

specified ways, the Endangered Species Act, 16 U.S.C. §§ 1531 to 1599, is applicable. Similarly, the NHPA, 16 

U.S.C. §§ 470-470a-2, like NEPA, requires Federal agencies to evaluate impact of Federal actions on sites listed on, 

or eligible for, the National Register of Historic Places. See Appendix G for further discussion of these statutes. 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 57 
 

intensive analysis to determine when a private project has become federalized. Because Federal 

agencies will likely be significantly involved, at least in the short-term, in the planning, financing, 

and permitting of CO2 sequestration projects on private and Federal lands (on and offshore), 

NEPA could apply to those activities. Some permitting activities may be exempt from NEPA, 

however, where a statute or regulation provides for a similar environmental review process 

and public participation. For example, the issuance of a SDWA UIC permit for CO2 injection by 

EPA would not require preparation of a NEPA analysis because the UIC permit process is 

considered to be the “functional equivalent” to the NEPA process. 

NEPA requires the development of an Environmental Impact Statement (EIS), a more detailed 

evaluation of an action and alternatives to it, when a Federal agency determines that the 

environmental consequences of an action may be significant. Review under NEPA may be 

streamlined in some contexts, such as when Federal land will be used for CCS activities, 

through development of Programmatic Environmental Impact Statements (PEISs).61 A PEIS could 

analyze the environmental impacts at a region-wide scale for either a pipeline corridor or 

network, or for regional CO2 sequestration. Site-specific analysis under NEPA would still be 

required for specific pipeline or sequestration siting, but these site-specific EISs may be 

streamlined by being able to “tier” off the PEIS. 

Conducting a programmatic NEPA analysis is rigorous, and that analysis should commence very 

early in the planning process for CCS. In fact, the law directs agencies to integrate the NEPA 

process into early planning efforts in order that appropriate NEPA analysis is performed and to 

reduce delay.62 A PEIS can take two or more years to prepare and will involve public comment 

and substantial interagency coordination and analysis. Once site-specific projects are identified, 

NEPA analysis for such projects will require additional time, on the scale of two or more years, 

depending on the complexity of the project and the significance of the impacts. If this analysis is 

conducted early, it may provide an opportunity to further clarify many of the issues discussed in 

this report. On the other hand, attempting to conduct such an analysis late in the planning 

process would undercut the utility of the NEPA process and could cause delays in the 

implementation of CCS. 

61 NEPA review may potentially be streamlined by the use of a “categorical exclusion.” A categorical exclusion can 

apply when an agency has determined that certain actions “do not individually or cumulatively have a significant 

effect.” 40 C.F.R. § 1508.4. A categorical exclusion, however, does not exempt a project completely from 

environmental review; an agency still must review for “extraordinary circumstances” that could remove a project 

from the categorical exclusion if a normally excluded action may have significant environmental effects. Id. At this 

stage, because of the novelty of many CCS activities, an agency is not likely to have an existing categorical 

exclusion that could be used, and would need to establish in conjunction with the Council on Environmental 

Quality that the applicable regulatory criteria for a new categorical exclusion are met. 

62 40 C.F.R. § 1501.1(a). 

Report of the Interagency Task Force on Carbon Capture and Storage 58 
 

 

Resource Conservation and Recovery Act (RCRA) 

The Solid Waste Disposal Act, 42 U.S.C. § 6901 et seq, as amended (commonly referred to as 

RCRA), regulates “solid wastes,” with Subtitle C of the Act addressing management of solid 

wastes that are also “hazardous wastes.” RCRA Subtitle C establishes a comprehensive “cradle 

to grave” regulatory scheme, including requirements for generators and transporters, along 

with permitting and other requirements for hazardous waste “treatment, storage, or disposal” 

facilities.63 

Under EPA’s regulations, a solid waste is a hazardous waste if, among other things, it exhibits 

the characteristic of toxicity.64,65,66,67 CO2 captured from sectors amenable to CCS, such as 

electric generating facilities, could contain toxic chemical constituents such as arsenic, mercury, 

and selenium (IPCC, 2005; Apps, 2006). Whether a particular CO2 stream is a hazardous waste 

based on toxicity will depend on whether it contains specific chemical constituents at levels 

above the toxicity characteristic concentrations in Table 1 of 40 C.F.R. § 261.24(b). A captured 

CO2 stream that meets the definition of a hazardous waste will have to comply with all 

applicable RCRA requirements. 

Various groups and studies have characterized potential RCRA applicability as a possible barrier 

to CCS deployment due to its complex regulatory regime.68 Characterization of a CO2 stream 

as “hazardous waste” would make the RCRA waste management scheme applicable to the 

generation, transportation, treatment, sequestration, and/or disposal of the CO2 stream. This 

determination would mean that underground injection and sequestration of such a CO2 stream 

would need to meet the requirements for Class I hazardous waste wells under the SDWA UIC 

63 RCRA §§ 3001-05; 40 C.F.R. Parts 260-279. 

64 A solid waste is a hazardous waste if it is a listed hazardous waste, or if it exhibits any of four characteristics 

(ignitability, corrosivity, reactivity, or toxicity). 40 C.F.R. §§ 261.30-.33 and 261.20-.24. 

65 40 C.F.R. § 261.24. 

66Hazardous secondary material which is used or re-used as a substitute for a commercial product or as an 

ingredient in an industrial process to make a product may be excluded from the definition of solid waste under 

RCRA regulations. EPA's regulatory exclusion may apply to CO2 that has been geologically sequestered if it is being 

stored for re-use in a product or ingredient. See 40 C.F.R. §§ 261.1(c)(5) and 261.2(e). To qualify for this exclusion, 

however, the hazardous secondary material must be legitimately recycled. In addition the hazardous secondary 

material cannot be accumulated speculatively, meaning, generally, that 75 percent of the accumulated secondary 

material must be used within a calendar year. 40 C.F.R. § 261.1(c)(8). Further, the EPA regulations state that this 

hazardous secondary material may not be burned for energy recovery nor re-used in a manner that constitutes 

disposal (i.e., being put on the land or used to make a product that is put on the land). See 40 C.F.R. § 261.2(c). 

See Appendix D for a discussion of potential end uses of CO2. 

67 40 C.F.R. § 261.2(a)(1)-(2), (b)(1). 

68 See, e.g., (GAO, 2008). 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 59 
 

Program, §§ 1421 et seq., 42 U.S.C. §§ 300h et seq.,69 rather than for the Class VI geologic 

sequestration wells proposed to be established under Federal Requirements Under the UIC 

Program for Carbon Dioxide (CO2) Geologic Sequestration Wells, 73 Fed. Reg. 43492, 43503 

(July 25, 2008). 

EPA is evaluating how and whether RCRA hazardous waste requirements may apply to certain 

CO2 injectate. EPA is planning a proposed rule under RCRA to explore a number of options, 

including a conditional exemption from the RCRA requirements for hazardous CO2 streams in 

order to facilitate implementation of geologic sequestration while protecting human health and 

the environment. EPA has created “conditional exemptions” in the past defining secondary 

materials as hazardous waste only if they are not managed pursuant to specified conditions (see, 

e.g., Military Toxics Project v. EPA, 146 F.3d 948 (D.C. Cir. 1998)). 

IV.B.1.2 Selected Laws Applicable to Phases of Deployment of CCS on 

Private Onshore Lands 

Capture of CO2 

One Clean Air Act (CAA) requirement that specifically applies to CO2 capture is Subpart PP of 

the GHG Reporting Program. Facilities that capture CO2 will be required to regularly monitor 

and report their emissions, as specified under 40 C.F.R. Part 98, Subpart PP. Subpart PP 

requires the reporting of CO2 supplied to the economy and applies to all facilities with CO2 

production wells, facilities with production process units that capture and supply CO2 for 

commercial applications or that capture and maintain custody of a CO2 stream to sequester or 

otherwise inject it underground, and to importers and exporters of bulk CO2. 

Other relevant Clean Air Act provisions may apply to the capture of CO2. For example, the 

New Source Review Program requires an existing major stationary source that undergoes a 

“major modification” that results in a “significant increase in emissions” to install state-of-theart pollution control equipment.70 As discussed in Section III.A energy is needed to capture and 

compress CO2. This energy could be derived from diverting some of the energy produced by 

the facility, or by using energy from offsite. If a plant increases its production of energy to 

compensate for that loss, and if that results in a significant increase in emissions of other 

regulated air pollutants, the plant could be required to upgrade the balance of its air pollution 

control equipment. 

69 Treating a geologic sequestration project as a Class I hazardous UIC well may result in a longer permit process 

than anticipated for the proposed Class VI geologic sequestration UIC well due to the additional requirement to 

obtain a RCRA permit. Additionally, the proposed Class VI geologic sequestration UIC well is specifically tailored 

to address CO2’s unique characteristics, unlike Class I hazardous UIC well requirements. 

70 CAA §§ 165 and 173, 42 U.S.C. §§ 7475 and 7503; 40 C.F.R. §§ 52.21(j)(3), 51.166(j)(3), and 51.165(b)(1). 

Report of the Interagency Task Force on Carbon Capture and Storage 60 
 

 

Transportation of CO2 

Captured CO2 may be transported by pipeline, truck, rail, barge, or supertanker. As discussed 

above in Section III.B, pipelines are considered to be the most economical and thus the most 

likely future method of transportation of CO2. A mix of State and Federal laws applies to 

pipeline siting, construction, and operation.71 Siting and construction of the approximately 3,600 

miles of existing onshore CO2 pipelines in the United States have generally been the province 

of State and local government.72 State law also governs the rates, terms, and conditions of 

service provided by CO2 pipelines. 

The U.S. Department of Transportation (DOT), through the Office of Pipeline Safety in the 

PHMSA, has oversight responsibility for the safety of liquid CO2 pipelines pursuant to the 

Hazardous Liquid Pipeline Act of 1979, as amended, 49 U.S.C. § 60101 et seq., and the 

Hazardous Materials Transportation Act, 40 U.S.C. 5101 et seq. Design, construction, 

operational, and emergency response requirements for CO2 pipelines are contained in 49 

C.F.R. Parts 190–199 and 40 C.F.R. Parts 171–180. 

Storage of CO2 

Due to their importance and public interest, this section highlights the applicability of the 

SDWA UIC, CAA, and Comprehensive Environmental Response, Compensation, and Liability 

Act (CERCLA, commonly known as Superfund) programs to CO2 sequestration. RCRA is 

discussed in Section IV.B.1.1. 

71 In addition to the Federal laws discussed below, siting, construction, and operation of pipelines with significant 

Federal involvement may trigger NEPA review or ESA and NHPA requirements in some instances, as explained 

above. Operation of pipelines containing hazardous waste must also comply with RCRA, as discussed earlier, and 

may have various other obligations under environmental statutes such as the Comprehensive Environmental 

Response, Compensation and Liability Act (CERCLA), EPCRA and the CAA, where applicable by their terms. 

72 In 1979, the Federal Energy Regulatory Commission (FERC) ruled that because CO2 pipelines do not transport 

natural gas (described as a gaseous mixture having hydrocarbons for heating value), they are not subject to the 

Commission’s broad authority over the construction and operation of natural gas pipelines under the Natural Gas 

Act, 15 U.S.C. §§ 717 et seq. Cortez Pipeline Company, 7 FERC ¶ 61024. In 1981, the Interstate Commerce 

Commission (ICC), the predecessor agency to the Surface Transportation Board, ruled that Congress excluded all 

types of gas from its jurisdiction under former section 1(1)(b) of the Interstate Commerce Act, then 49 U.S.C. § 

10501(a)(1)(C). Cortez Pipeline Company--Petition for Declaratory Order--Commission Jurisdiction over Transportation of 

Carbon Dioxide by Pipeline, 45 Fed. Reg. 85177 (Dec. 24, 1980); 46 Fed. Reg. 18805 (March 26, 1981). The Surface 

Transportation Board has not addressed the question of whether it has jurisdiction over CO2 pipelines. 

Most current and projected future CO2 pipelines transport CO2 as a supercritical liquid, so they are subject to 

regulation as hazardous liquids. 

However, future projects may increasingly require transport of CO2 in a gaseous state. While PHMSA does not 

currently have statutory authority to regulate the safety of the transport of CO2 in a gaseous state, if those 

authorities were to arise, any regulatory activity associated with exercising those authorities would be subject to 

public notice and comment. 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 61 
 

 

SDWA UIC Program 

SDWA’s UIC Program regulates the underground injection of fluids into the subsurface to 

prevent endangerment of underground sources of drinking water.73 Supercritical CO2 falls 

under the definition of “fluid” (40 C.F.R. § 144.3); thus underground CO2 injection falls within 

the scope of the SDWA UIC Program and will require a UIC permit before injection occurs. In 

preparation for the commercial deployment of CCS, EPA proposed minimum Federal 

requirements for underground injection of CO2 for purposes of geologic sequestration.74 The 

proposal builds on experience from the existing regulatory program, which provides the 

technical framework, expertise, and experience for permitting CO2 sequestration. The rule 

proposes a new Class VI UIC well type for injection of CO2. The proposal applies to owners or 

operators of geologic sequestration wells that will be used to inject CO2 into the subsurface for 

long-term sequestration. The proposed Class VI UIC well requirements address site 

characterization, area of review, well construction, well operation, site monitoring, postinjection site care, public participation, financial responsibility (through post-injection site care), 

and site closure. These proposed requirements are tailored to address the unique 

characteristics of CO2, including its large volumes, buoyancy, viscosity, and corrosivity. The 

SDWA does not provide EPA with the authority to shift liability to a third party or to indemnify 

owners or operators; therefore, the owner or operator may remain liable for endangerment to 

USDWs from unintended migration of fluid movement even after site closure occurs under 

SDWA §1431, CERCLA, or tort law. The final rule is anticipated to be published in late 2010. 

Until the geologic sequestration rulemaking goes final and into effect, CCS will continue to be 

permitted under the existing SDWA UIC Program, including existing State primacy authorities. 

Current options for permitting UIC wells that inject CO2 include Class I industrial, Class II 

EOR, or Class V experimental wells, depending on individual conditions. 

SDWA provides States an option to assume primary enforcement responsibility, or primacy, to 

oversee injection wells in their State. States issue UIC permits for injection wells onshore and 

could implement those requirements for wells inside State territorial waters. EPA encourages 

States to assume primacy for Class VI wells because it believes that States may provide for a 

comprehensive approach to managing CCS projects by promoting the integration of 

sequestration activities under SDWA into a broader framework for managing CCS 

Furthermore, sequestration operations involve ancillary activities (e.g., pipeline operations, pore 

space ownership, land use rights, and surface access) for which States can call upon other 

authorities that exist at the State level (but outside UIC authority) to provide a more 

comprehensive CCS management approach. The Federal government will maintain a robust 

73 SDWA §1421, 42 U.S.C. § 300(h). 

74 73 Fed. Reg. 43492 (July 25, 2008). 

Report of the Interagency Task Force on Carbon Capture and Storage 62 
 

 

role in assuring that minimum Federal standards for GS wells in primacy States are met through 

periodic review of their UIC programs. 

The SDWA UIC Class VI rule will be effective 60 days after the final rule is published in the 

Federal Register. Following final promulgation of the rule, States will have 270 days to submit a 

complete Class VI primacy application to EPA for review and approval. During this time, States 

with existing UIC primacy for all other well classes under §1422 of SDWA that receive Class VI 

permit applications may consider using existing authorities (e.g., Class I, Class II, or Class V), as 

appropriate, to issue permits for CO2 injection for sequestration while EPA is evaluating their 

Class VI primacy application. 

After 270 days from final promulgation, EPA will establish a Federal Class VI primacy program 

in States that choose not to seek primacy for the Class VI portion of the UIC Program within 

the approval timeframe established under § 1422(b)(1)(B) of the SDWA. EPA will publish a list 

of the States where the Federal Class VI requirements have become applicable in the Federal 

Register. States may not issue Class VI permits until their Class VI UIC Programs are approved. 

During the first 270-days and prior to EPA approval of a Class VI primacy application, States 

without existing §1422 primacy programs must direct all Class VI geologic sequestration permit 

applications to the appropriate EPA Region. EPA Regions will issue permits using existing 

authorities and well classifications (e.g., Class I, Class II, or Class V), as appropriate. If a State 

submits a primacy application after the 270-day deadline and the application is approved, EPA 

will publish a subsequent notice of the approval in the Federal Register. 

CAA Monitoring, Reporting, and Verification 

EPA has proposed reporting and recordkeeping requirements for owners and operators of 

CO2 sequestration facilities.75 CO2 sequestration facilities would be required to develop and 

implement an EPA-approved, site-specific monitoring, reporting, and verification plan. This rule 

would not establish performance standards for CO2 sequestration facilities but would require 

annual reporting of the amount of CO2 sequestered. Under the proposal, reports would be 

submitted annually, with the first reports due to EPA in 2012 for CO2 injected during 2011. A 

final rule is anticipated to be published in late 2010. 

CERCLA 

CERCLA, 42 U.S.C. §§ 9601 to 9675, may apply to certain releases from a CO2 sequestration 

site of hazardous substances, or pollutants or contaminants that present an imminent and 

substantial danger into the environment. This means, among other things, that the President 

75 Mandatory Reporting of Greenhouse Gases: Injection and Geologic Sequestration of Carbon Dioxide, Proposed Rule, 75 

Fed. Reg. 18576, 18578 (April 12, 2010). 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 63 
 

 

may have response authority under CERCLA § 104, 42 U.S.C. § 9604, and liability may be 

established under CERCLA § 107, 42 U.S.C. § 9607. 

From available information on the potential chemical composition of CO2 injectate, it appears 

that under likely capture scenarios, the CO2 could contain “hazardous substances” (e.g., arsenic 

and selenium). CO2 sequestration projects would likely fall within the definition of a “facility” 

(as a site where a hazardous substance is deposited or stored), and owners and operators of 

CO2 sequestration projects are among the persons covered by CERCLA that could qualify as 

responsible persons if a plaintiff were to incur cleanup costs. Consequently, CERCLA liability 

could apply, unless an owner or operator could establish a defense.76 If CO2 enters 

groundwater, it might also cause hazardous substances, such as some metals, to be dissolved by 

the groundwater from enclosing strata. If that constitutes a release of hazardous substances 

from a "facility," such as the strata, then the owner of that facility could be liable for any 

response costs caused by that release. 

Various stakeholder groups and published studies have characterized potential CERCLA liability 

as a barrier to CCS deployment (GAO, 2008). To the extent that injected CO2 streams fall 

within the scope of a permit under the SDWA UIC Program, EPA may find that owners and 

operators are exempt from CERCLA liability if the injection qualifies as a “Federally Permitted 

Release;” however, EPA may evaluate whether a statutory change is necessary to exempt CO2 

injectate. Because CERCLA plays an important role in ensuring that there are financial 

resources and an accountable party (or parties) able to respond to any release occurring during 

CCS activities, any analysis of statutory changes would need to address the potential need for 

alternative methods of providing for such capabilities. 

IV.B.1.3 Selected Laws Applicable to Deployment of CCS on Federal Lands 

This subsection focuses on key elements of the regulatory framework applicable to two of the 

largest holders of surface and subsurface rights on Federal lands: the Bureau of Land 

Management (BLM) of the Department of the Interior (DOI), which manages 253 million acres 

and 700 million subsurface acres, and the Forest Service of the Department of Agriculture, 

which manages 193 million acres. Provisions of Federal law, as discussed below, may allow the 

siting of pipelines for transportation of CO2 and the sequestration of CO2 on BLM and Forest 

Service lands. 

Title V of the Federal Land Policy and Management Act (FLPMA), 43 U.S.C. §§ 1761–1771, 

authorizes BLM and the Forest Service to grant, issue, or renew rights-of-way to public and 

76 There are four elements necessary to establish liability under CERCLA § 107(a) 42 U.S.C. § 9607(a): (1) there 

must be a release or threatened release of a hazardous substance, (2) the release must occur at a facility, (3) the 

release must cause the plaintiff to incur costs not inconsistent with the National Contingency Plan, and (4) the 

defendant must fall within one of the four categories of responsible persons. See Young v. United States, 394 F.3d 

858, 862 (10th Cir. 2005). 

Report of the Interagency Task Force on Carbon Capture and Storage 64 
 

private entities for pipelines and other systems for the transportation or distribution of liquids 

and gases (excluding those governed by the Mineral Leasing Act, 30 U.S.C. § 185 (MLA)), on 

public lands and Forest Service lands, subject to certain terms and conditions to protect 

specified social, aesthetic, and environmental values and Federal property and economic 

interests. See also 43 C.F.R. Part 2800. FLPMA also authorizes Federal agencies to hold a rightof-way for transportation or distribution of liquids and gases governed by the MLA. FLPMA 

does not require such rights-of-way to be constructed, operated, or maintained as common 

carriers (i.e., transporting CO2 on a non-discriminatory or open access basis). BLM also has the 

authority under the MLA to authorize rights-of-way to business entities for pipelines carrying 

CO2 from a natural gas stream across BLM lands or Federal lands administered by two or more 

Federal agencies. Such pipelines must be constructed, operated, and maintained as common 

carriers with certain limited exceptions, and Federal agencies are not included among qualified 

applicants. Due to the vast tracts of Federal lands in the western United States, many CO2 

pipelines may cross Federal lands and need a Federal right-of-way, even if a proposed 

sequestration site is located on non-Federal land. 

No provision of FLPMA expressly authorizes the sequestration of CO2 on public lands; 

however, subsection (a)(2) of § 501, which is applicable to BLM and the Forest Service, 

authorizes rights-of-way for transportation and distribution of certain gases and liquids “and for 

storage and terminal facilities in connection therewith.”77 Subsection 501(a)(7) authorizes 

rights-of-way for such other necessary transportation or other systems or facilities which are in 

the public interest and which require rights-of-way over, upon, under, or through such lands. 

Section 302(b) of FLPMA also provides BLM with authority to undertake any use and 

development of public lands not specifically forbidden by law and not authorized by other laws 

or regulations. See also 43 C.F.R. § 2920.1-1. The MLA provides authority to lease lands for the 

extraction of minerals; however, it does not authorize disposal of wastes, except those arising 

from lease operations. There is no MLA provision analogous to § 302(b) of FLPMA that might 

provide authority for CO2 sequestration. 

Section 202 of FLPMA, 43 U.S.C. § 1712, requires that BLM prepare resource management 

plans to provide for the use of the public lands and that management be on the basis of multiple 

use and sustained yield. Regulations at 43 C.F.R. 1610.5-3 require that all future resource 

management actions conform to the plans. Similar, though not identical, requirements exist for 

the Forest Service through the National Forest Management Act, 16 U.S.C. §§ 1600-1614. 

Preparation of the plans involves considerable public participation and compliance with the 

77 Where the source of CO2 was a natural gas stream, section 501(a)(2) was found to be inapplicable to the 

transportation of CO2. Exxon Corp., 97 IBLA 45 (1987), aff’d, Exxon Corp. v. Lujan, 730 F. Supp. 1535 (1990), 

aff’d, 970 F.2d 757 (10th Cir. 1992). A right-of-way under section 28 of the MLA, 30 U.S.C. 185(a), was found to 

be appropriate. Thus, the origin of CO2 may be important in identifying whether Title V provides authority for 

CO2 storage. 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 65 
NEPA, Endangered Species Act (ESA), National Historic Preservation Act (NHPA), and other 

laws. The requirements of the SDWA UIC, CAA, RCRA, CERCLA and other provisions of law 

applicable to sequestration on private lands are also generally applicable to sequestration on 

Federal lands. 

See Appendix M for a discussion of siting considerations for CO2 pipelines across Federal lands, 

including the potential use of energy corridors. 

IV.B.2 Legal and Regulatory Challenges 

As the CCS industry matures, the existing set of regulations is likely to face a variety of 

management and implementation challenges. The unique characteristics of CO2 sequestration, 

uncertainty around technology development, variety of industry and regulatory actors, and 

potential scale of injection operations all present uncertainties and potential areas that could 

stress the application of existing regulations and resources. These considerations may warrant 

additional actions that the Federal government could take to strengthen the existing regulatory 

framework and its implementation. 

The Task Force evaluated whether the existing regulatory framework, or elements thereof, 

could be integrated into a single framework for governing CCS and found that there are 

differences in scope, implementation approaches, administrative procedures, compliance 

assurance, and enforcement mechanisms, among other issues, that present challenges for 

creating a unified framework. 

Regulatory requirements and implementing agencies will differ depending on conditions such as 

the location of the sequestration project. Factors that may affect the regulatory requirements 

and implementing agencies include type of project (e.g., experimental vs. commercial), source of 

funding (e.g., government vs. private), land ownership (e.g., public vs. private), location of 

injection wells (e.g., onshore, offshore but generally within 3 miles, offshore and generally 

beyond 3 miles), type of sequestration reservoir and/or project purpose (e.g., saline vs. oil 

field), purity of CO2 stream, and source of CO2 (e.g., power generation vs. industrial 

processes). 

Enhanced coordination on legal and regulatory issues will be needed between Federal agencies 

as well as between the Federal government and the States. Stakeholders noted that State UIC 

programs have faced resource limitations in implementing the SDWA UIC Program. Significant 

increases in permit applications could overwhelm the capacity of both EPA and primacy States. 

While some States may be able to take on many of these challenges, others may have difficulties 

in certain areas such as reviewing and validating the results of complex computational models. 

As can be expected in a nascent industry, regulatory agencies will be challenged to gain the 

expertise needed to ensure they have capacity to adequately implement the program, and avoid 

lengthy delays in permitting. 

Report of the Interagency Task Force on Carbon Capture and Storage 66 
 

Permitting and regulatory authorities may face challenges in terms of training and workforce 

capacity. CO2 pipeline infrastructure deployment would be aided through training and 

designated resources to assist Federal, State, and local agencies with permitting, compliance, 

and public outreach, as well as for training first responders. For sequestration, stakeholders 

have expressed concern that States may not have sufficient technical resources in very 

specialized areas related to CO2 sequestration that will be critical in the review of permit 

applications, such as new site characterization technologies, specialized CO2-compatible well 

construction techniques, computational modeling, geochemistry, injection formation dynamics, 

and financial responsibility. States may not have sufficient staff to review a large number of Class 

VI permit applications, write permits, and review and enforce those permits. 

Several challenges need to be addressed for onshore Federal lands to be fully used in an 

efficient and effective manner for CO2 sequestration. First, the BLM and the U.S. Forest Service 

(USFS) currently lack clear authority for long-term CO2 sequestration. Second, the authority 

that may be applicable does not address issues of long-term liability, stewardship, ownership of 

pore space, and the appropriate rent for the use of Federal pore space. As discussed in Section 

IV.C, CO2 sequestration presents unique challenges related to long-term liability and 

stewardship, since it is contemplated that the CO2 will remain stored indefinitely, perhaps for 

hundreds or even thousands of years. BLM and USFS current authorities do not deal with these 

unique issues. Third, sequestration on split estate lands also presents complications due to 

ownership of pore space and limitations that may need to be placed on surface and subsurface 

uses to ensure integrity of sequestration. 

Moreover, amendments to resource management plans may be needed prior to authorizing any 

sequestration projects on public lands. These plan amendments often involve complex and 

lengthy compliance with NEPA 42 U.S.C. § 4321, the ESA, 16 U.S.C. § 1531, Clean Water Act, 

33 U.S.C. §1251, and the NHPA, 16 U.S.C. § 470, as well as agency and Tribal consultations. 

There are also several opportunities for public comment. 

In addition, BLM does not currently have a statutory or regulatory mechanism that directly 

addresses the assurances sought by current applicants for a noncompetitive preference right to 

develop future CCS projects after initial site characterization studies. Other applicants may 

seek the same assurances. 

Finally, authorizing the use of onshore Federal lands for geologic CO2 sequestration may 

potentially conflict with other subsurface uses, including existing and future mines, oil and gas 

fields, coal resources, geothermal fields, and drinking water sources. CO2 sequestration could 

also have potential impacts on other surface land uses and programs such as recreation, grazing, 

cultural resource protection, and community growth and development. 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 67 
IV.C Long-Term Liability Regarding Storage of CO2 

IV.C.1 Overview 

Many stakeholders have expressed the view that legal and regulatory liabilities constitute 

barriers to the widespread cost-effective deployment of CCS. This section examines legal and 

regulatory mechanisms and summarizes options for government intervention to address 

liabilities associated with the long-term underground sequestration of CO2. The subsection 

begins by providing background and an overview of long-term liability issues. It then discusses 

considerations that are relevant to deciding whether governmental actions to address such 

liabilities are required, and what types of interventions are appropriate, if any. It then analyzes 

the present legal regime relating to long-term liabilities. 

There are two major categories of liabilities: (1) obligations to perform (e.g., to comply with 

regulatory standards); and (2) obligations to compensate parties for various types and forms of 

legally compensable losses or damages. Although financial responsibility is required until closure 

of the CO2 sequestration site, the focus of this section is “long-term” liabilities arising during 

the post-closure period. The Task Force focused its analysis on long-term liabilities because the 

risks during the operational and post-closure monitoring period of CO2 sequestration projects 

are similar to current industrial activities that can be underwritten in the financial and insurance 

sectors. Liabilities associated with the capture or transportation of CO2 do not fall within the 

scope of this discussion. The discussion below also does not address liability or stewardship of 

CO2 sequestration sites before the end of the post-closure phase. Ensuring adequate 

stewardship and financial responsibility during that period is, however, an important 

consideration in ensuring that long-term liabilities do not arise later. 

IV.C.1.1 Existing Laws and Regulations Related to Long-Term Liability 

Existing legal authorities include a range of approaches to liabilities related to long-term CO2 

sequestration. As noted below, although there is no comprehensive, integrated Federal 

framework specifically directed to defining or allocating long-term liability, there are a number 

of Federal and State laws that bear on long-term liability. The discussion below provides a 

summary of existing authorities as they relate to long-term liability; those authorities are 

analyzed in more detail in Section VII. 

Under the SDWA, 42 U.S.C. §§ 300f-300j, for example, EPA has issued a proposed rule through 

its SDWA UIC Program to require owners or operators of underground geologic 

sequestration facilities to demonstrate financial responsibility through post-injection site care. 

See 40 C.F.R. Part 146. The proposed rule provides for owners or operators of sequestration 

sites to demonstrate and maintain financial responsibility to ensure that resources will be 

available to address adverse situations related to underground sources of drinking water 

throughout the lifetime of a project, even if the operator experiences financial difficulty. The 

Report of the Interagency Task Force on Carbon Capture and Storage 68 
 

UIC regulations specify that owners or operators must ensure that resources are available to 

address all needed corrective action on wells in the area of review, injection well plugging, postinjection site care and site closure, and emergency and remedial response.78 Operators must 

also review and adjust the financial responsibility cost estimates at least annually to account for 

any amendments to the required project plans for the above activities or to address inflation or 

other changes to the estimated costs. Financial responsibility under this proposed rule will 

remain with the owner or operator through post-injection site care. Long-term liability (i.e., 

liability that addresses the time period after site closure is authorized) is outside of the scope of 

EPA’s regulation. 

Under the proposed rule, the owner or operator would continue to conduct monitoring as 

specified in the Director-approved post-injection site care and site closure plan for at least 50 

years following the cessation of injection, or until (either more or less than 50 years) the owner 

or operator can demonstrate to the Director79 that their geologic sequestration project no 

longer poses an endangerment to USDWs. Once all regulatory requirements have been met, 

the owner or operator will be released from SDWA requirements, and therefore, liability for 

enforcement under §1423 of that Act. SDWA does not provide authority to shift liability under 

the Act to another entity other than UIC owners or operators. In addition, an owner or 

operator may be liable under §1431 of the SDWA after site closure has been approved if there 

is unanticipated migration that threatens imminent and substantial harm to a USDW. In 

addition, tort and other remedies will continue to be available after site closure. Other Federal 

environmental statutes, e.g., CAA, 42 U.S.C. §§ 7401-7671; CERCLA, 42 U.S.C. §§ 9601-9675; 

and RCRA, 42 U.S.C. §§ 6901-6992k, potentially apply as well to the risks created by the longterm sequestration of CO2. 

Additionally, a number of States have begun to establish local regimes for long-term liability 

transfer. The Task Force has not undertaken a comprehensive review of State law, but a 

number of examples are illustrative. Four States (Louisiana, Montana, North Dakota, and 

Oklahoma) have developed a “certificate of completion” model whereby the operator of a 

geologic sequestration site can transfer title and liability to the State after demonstrating to the 

relevant agency that the site is stable for a certain period of time after the last CO2 has been 

injected and the site has been closed; until the time of transfer, the operator remains liable for 

damages related to CO2 migration or leaks. Two States (Illinois and Texas) have accepted 

liability for certain CCS pilot projects within their borders. Two other States (Washington and 

Wyoming) have disclaimed State liability from long-term CO2 sequestration unless otherwise 

78 40 C.F.R. 146.85. 

79 The Director is the person responsible for permitting, implementation, and compliance of the UIC program. For 

UIC programs administered by EPA, the Director is the EPA Regional Administrator; for UIC programs in Primacy 

States, the Director is the person responsible for permitting, implementation, and compliance of the State, 

Territorial, or Tribal UIC program. 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 69 
 

 

specified by law. Additionally, two States (Kansas and Utah) have given hereto-unexercised 

regulatory authority to State administrative agencies, which may encompass the ability to 

address long-term liability. 

IV.C.1.2 Stakeholder Views 

Experts and stakeholders have expressed a range of views as to whether long-term liability is a 

barrier to commercial deployment of CCS. A number of stakeholders, particularly from private 

industry, have said that they consider long-term liabilities to be a key barrier to the commercial 

deployment of CCS. They expressed the concern that these liabilities are difficult to quantify on 

corporate balance sheets. Although the technical community believes that many aspects of the 

science related to geologic storage security are relatively well understood,80 the time frame 

over which the long-term risks might exist is long, in the hundreds or thousands of years. To 

the extent that some uncertainty remains, that uncertainty is magnified by the time frames 

involved. Even after discounting this long-term risk to net present value, stakeholders believe 

that there is significant remaining uncertainty, and said that businesses are uncomfortable 

undertaking these long-term risks. Moreover, even apart from the actual likelihood that longterm liabilities will accrue, these stakeholders have said that such liabilities are novel enough 

that businesses may encounter difficulties in reflecting them in their accounting statements. 

Such statements will be subject to the audit committee of a company’s board of directors, as 

well as review by its independent auditor. If the company is a public company, the chief 

executive officer and the chief financial officer will be required by the Sarbanes-Oxley legislation 

to sign a certification that based, on the officer’s knowledge, corporate reports do not contain 

any untrue statement of material fact or material omissions.81 

A second set of issues involves the availability of insurance for long-term risks. Insurers state 

that they are able to issue coverage for the period through site closure.82 But underwriting the 

risk over the “long-term” or perpetual time horizon of underground sequestration may present 

a challenge to both the private and public sector. Some entities in the private sector are 

concerned over insurance requirements because the long-term horizon of geologic 

sequestration and its novelty appear to be limiting the availability of coverage. Insurers state 

that they currently will not write policies to cover post-closure risks associated with CCS. 

Although they will underwrite conventional operational risks, they explain that currently they 

80 See Section III.C.2.3. 

81 Communications from representatives of the Coal Utilization Research Council, North American Carbon 

Capture and Storage Association, and AEP. 

82 See, e.g., communication from representative of Zurich Financial Services. Zurich stated, however, that it would 

not issue coverage for the cost of replacing CO2 lost from a storage reservoir even in the shorter-term period, in 

light of the uncertainty as to the future per tonne price of CO2 under future legislation. Thus, if a market for CO2 

comes into existence through future legislation, it will become necessary to determine whether insurance for this 

type of risk has become available, and, if not, whether other financial assurance mechanisms will be needed. 

Report of the Interagency Task Force on Carbon Capture and Storage 70 
 

are not able to estimate the costs of such policies, their typical business does not encompass 

claims that may not arise for centuries, and they are not institutionally suited to underwrite 

risks arising in such a long time frame. Furthermore, without insurance or a comparable risk 

management mechanism, private lending facilities may not be willing to extend credit to finance 

the construction of facilities conducting CO2 sequestration.83 

A third set of issues identified by commentators involves the potential “joint and several” 

nature of the liabilities at issue (such as CERCLA liability).84 Under joint and several liabilities, it 

is possible that every entity that generates CO2 and contributes it to a particular reservoir 

could be held liable for the entire cost of any liability that ensues, particularly if no other party 

is available to pay those costs. This concern is particularly acute for shared reservoirs and in 

instances in which a CO2 stream is acquired from third parties, because of the larger number of 

parties that could potentially be involved in such transactions. 

Other stakeholders and experts have questioned the substantiality of these concerns. They 

have said that a description of long-term liabilities associated with CO2 sequestration is 

ordinarily sufficient for recognition purposes in audited financial statements where an entity 

cannot establish a quantified estimate of such liabilities, and that therefore quantifying long-term 

liabilities on corporate balance sheets is overstated.85 Some stakeholders have also expressed 

concern that relieving businesses of long-term risks could undermine the incentives to those 

businesses to take appropriate precautions in their activities (Center for Biological Diversity et 

al., 2010).86 Moreover, in other circumstances, similar long-term risks do not appear to deter 

businesses from participating in commercial activities. For example, businesses handle 

hazardous materials notwithstanding the potentially indefinite nature of CERCLA liability. 

Material sent to a landfill can likewise generate indefinite liabilities under CERCLA. (One 

possible distinction, however, is that insurance may be available in those settings.) 

IV.C.1.3 Risks, Harms and Potential Liabilities Associated With CCS 

The long-term sequestration of CO2 gives rise to an assortment of potential risks, harms, and 

legal liabilities. Potential categories of risks include scientifically identifiable risks, e.g., the 

migration of CO2 in ways that are scientifically understood; anomalous or unpredicted 

83 Communication from GE Financial Services. 

84 Communications from Coal Utilization Research Council, North American Carbon Capture and Storage 

Association, and AEP Representatives. 

85 See, e.g., S. 1013, the statement of Chiara Trabucchi on the Department of Energy Carbon Capture and 

Sequestration Program Amendments Act of 2009, before the S. Comm. on Energy & Natural Resources, 111th 

Cong. (Trabucchi, 2009). In addition, under Financial Accounting Standards Board requirements, if an entity 

determines that it cannot reasonably estimate fair value of an environmental liability, an entity would recognize the 

liability and include a description of the obligation in its audited financial statements (Lee and Trabucchi, 2008). 

86 Communication from Center for Biological Diversity et al. to Senator Reid (May 17, 2010). 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 71 
 

 

behaviors, e.g., unpredicted geophysical or chemical reactions; operator or regulatory errors, 

mistakes, or oversights; falsifications and illegal conduct; policy changes; and acts of God. 

As discussed in Section III.C, present scientific research has concluded that there is substantial 

evidence that the great majority of CO2 in a sequestration facility will remain in place for 

extended periods (centuries, millennia, or longer). This research assumes that the injection site 

is chosen properly, injection operations are conducted accurately, the site is monitored 

adequately, and closure and post-closure operations are conducted appropriately. To the 

extent that there is any significant risk in CCS activities, it is likely to arise from human error in 

one of these activities. Possible sources of such error are discussed in Appendix H. 

Section III.C also explains that the risks associated with underground geologic sequestration of 

CO2 are expected to be highest during the operational phase of the project when insurance is 

available, and then decrease over time. In order for a project operator to close a sequestration 

site, in accordance with Federal and State laws, the operator would have to make a 

demonstration that the risks were at a very low level. 

The above risks can give rise to a variety of potential harms.87 One issue is direct harm from 

CO2. Exposure to CO2 released into the air or water may have injurious toxicological effects 

on human and animal life or on surface waters (depending on concentration, scale, and other 

factors). Another concern is groundwater harm. CO2 migration underground can cause toxic 

substances (such as lead or arsenic) in surrounding rocks to dissolve into groundwater, through 

acidification or other mechanisms. Groundwater could also be contaminated by brine displaced 

by CO2 injection. CO2 migration may also harm mineral deposits.88 Finally, harm to the climate 

(or loss of benefits of sequestration) is associated with the release of CO2.

89 

Potential legal liabilities associated with the above harms include both performance and 

compensatory liabilities, as noted above. Performance liabilities include stewardship obligations 

of private entities, States, or the Federal government under environmental regimes (e.g., the 

proposed SDWA UIC Program described below), which may range from monitoring to cleanup 

or other obligations. Compensatory liabilities include tort liabilities under Federal or State law 

pursuant to various personal injury or property damage theories, including trespass, nuisance, 

negligence, and abnormally dangerous activities/strict liability; liabilities arising from government 

action constituting a taking of private property; contract liabilities between parties to a 

87 Additional discussion of potential harms is found in Section III.C. 

88 To the extent that a harm would involve impairment of a property right, e.g., in pore space, it is addressed in 

Section III.C.5.7. Tort claims are within the scope of the present section. 

89 There are also additional potential harms that are largely associated with the injection phase, rather than with 

long-term stewardship. These include surface shifts (ground movement) and induced microseismic activity, which is 

generally at a scale that would not be detectable except with scientific equipment. They are noted here for 

completeness. 

Report of the Interagency Task Force on Carbon Capture and Storage 72 
 

 

sequestration transaction; and liabilities of site operators, on indemnification or other theories. 

Finally, if future legislation imposes a price on CO2 emissions, a release of CO2 could give rise 

to a claim for the replacement costs of lost CO2.

90 

It bears noting that EOR activities in oil- or gas-producing areas for a number of years have 

included underground injection of CO2 as a means of re-pressurizing the reservoir and 

increasing oil and gas recovery. EOR operations are widespread and appear to be able to 

proceed without being constrained by concerns about long-term liability.91 This raises the 

question of why CCS activities, which involve underground injection of CO2 in a manner very 

similar to EOR activities, should be chilled by long-term liability concerns. There are, however, 

a number of potential distinctions. First, the process of producing oil reduces underground 

pressure levels, so that addition of CO2 as part of EOR operations may not lead to pressure 

levels as high as at a CCS site. Because high pressures are one source of risk, EOR may be less 

risky than CCS. Moreover, at the end of an EOR operation, much of the CO2 is removed from 

an EOR site for use in other fields. Although some CO2 typically remains in the reservoir, this 

also means that EOR operations may be comparatively lower risk. Finally, CO2 has been used 

for EOR purposes for decades, which has helped to reduce technical and economic 

uncertainties. 

IV.C.2 Policy Considerations for a Long-Term Liability Arrangement 

In Section IV.C.1.1, the Task Force outlined the present legal rules governing long-term liability. 

Then, in Section VII, the Task Force outlines seven possible approaches for addressing longterm liability. The analysis of these approaches, and the implementation of any particular 

approach, should turn on a full analysis of risks, costs, and benefits. Several policy 

considerations also could guide the selection of the most appropriate option or combinations 

of options. These policy considerations include encouraging CCS deployment, minimizing moral 

hazard,92 minimizing negative impacts on existing insurance markets and sources of financing, 

90 A future CCS regime is likely to incorporate financial incentives to sequester CO2, whether in the form of a capand-trade system or in some other program. Thus, if CO2 escapes sequestration, there is likely to be a cost of 

replacing the sequestration capacity in question, whether a per-tonne cost based on the then-current price of CO2 

credits, or a cost of repaying the incentive amounts paid for sequestration, or some other cost. 

91 EOR operations generally occur where a field has been “unitized.” With unitization, oil or gas field leases for 

resource development are combined, thereby creating a field-wide operation. In this circumstance, liability is 

generally removed as a concern as between the owners of producing interests because production and profits are 

shared by all unit members and the entire field is managed to optimize resource recovery. In EOR operations that 

have not been unitized, liability is usually imposed on the operator for mineral loss on the basis of trespass and 

nuisance. See (University of Houston Law School, 2008). 

92 “Moral hazard” is an economic behavioral term used to describe a situation where the risk of an event may 

increase due to actions the responsible party takes because it is partially insulated from being held fully liable for 

resulting harm and attendant damages. Moral hazard is a concern with any system of risk pooling because 

corporations are not liable for the entire costs of their own accidents. (“Risk pooling” is a general term for a wide 

range of mechanisms, from insurance to liability funds or other arrangements). (Hamilton, 1980). 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 73 
 

 

 

providing for appropriate long-term stewardship of sequestration sites, being sensitive to 

federalism concerns at the State level and the possibility that some approaches may be better 

handled at that level, ensuring that those who are harmed can be compensated, and equitably 

distributing the costs of liability (e.g., determining whether liability costs should fall on those 

entities that generate CO2; on sequestration facility owners/operators; on utility ratepayers, in 

the case of CO2 generated as a byproduct of electricity generation; or on the taxpayers 

generally).93 

Whatever approach is adopted should take into account the continued need for long-term 

stewardship, defined as oversight of an underground geologic sequestration facility after the 

post-closure period. Due to the permanent nature of long-term stewardship, some have argued 

the need to establish a public entity responsible for the long-term stewardship of underground 

geologic sequestration sites once the period of commercial activity at the site (including the 

generation of any revenue) and the term of regulatory financial assurance have passed.94 

Another policy consideration is whether, in order to foster the CCS industry, different liability 

rules could be applied to early projects versus later projects. Some commentators have 

questioned whether incentivized treatment of early projects has a reasonable prospect of 

yielding data helpful in the design of later projects, in light of the long time horizons involved. 

Finally, in designing a comprehensive framework for regulating CCS activities, the most critical 

features relating to long-term liability will be those that serve to prevent such liability from 

occurring. Appropriate site selection is especially important in minimizing risks of CO2 

sequestration activities. Also critical are robust monitoring, regulatory oversight, and 

enforcement. To reduce the potential moral hazard, liability assumption or transfer, if 

warranted, could be conditioned on strong siting and operational standards as well as the 

environmental performance of the CO2 sequestration project through a site closure 

certification process to ensure that the site does not pose an environmental, health, or safety 

risk.95 These requirements are anticipated to be addressed in EPA's final geologic sequestration 

rulemaking under SDWA.96 

93 Although this discussion is focused on long-term liability, a similar set of considerations apply to any analysis of 

shorter-term liabilities, which are likewise affected by considerations of moral hazard and the other factors 

discussed in the text. Notably, however, insurance is available for shorter-term liabilities. The desire to avoid 

undercutting private insurance markets may therefore be the dispositive factor as to such liabilities. A number of 

commentators have taken the position that CCS operators should rely on private insurance while a storage site is 

active. See, e.g., CCS Regulatory Project (2009a). 

94 See Section VIII for more discussion. 

95 A number of experts have made comments to this effect. See World Resources Institute, (2008). 

96 Under the UIC proposal, EPA would establish detailed site closure requirements. 73 Fed. Reg. 43492, 43540-1. 

Specifically, owners or operators would be required to prepare, maintain, and comply with a plan for post-injection 

site care that includes monitoring of pressure data in the injection area and reporting of monitoring data. After 

Report of the Interagency Task Force on Carbon Capture and Storage 74 
 

Any policy that allows a party to submit a demonstration of financial responsibility in the form 

of commercial liability insurance, pooled fund, or bond pool could foster moral hazard if it 

encouraged undue or irresponsible risk-taking by insureds (Zimmerman, 1990). Any of these 

measures should therefore be linked to monitoring, enforcement, and other accountability 

mechanisms to deter such conduct. Financial responsibility97 requirements imposed to address 

liability risks, either shorter- or long-term, should also be linked to a site-specific risk 

assessment that attempts to value potential liabilities and future costs (including such costs as 

the cost of long-term monitoring and any necessary remedial action). Financial responsibility 

mechanisms could be held by an individual owner/operator or pooled across multiple 

owners/operators. If held by individual owners/operators, this could encourage responsible site 

operation by tying the use of mechanism funds directly to the actions of the CCS project 

operator (Wilson et al., 2009). If pooled, they could appropriately be based on a site-specific 

risk assessment (and thus would potentially vary between sequestration facilities, rather than 

being uniform across such facilities) (Dooley et al., 2010b). These risk assessments, and the 

associated fees, could be reevaluated periodically based on any new information about the site 

in question (as well as about CCS operations more generally), which will help to ensure that 

available funds are tailored to actual needs and to provide an adaptive management framework 

for CCS operations.98 

There are potential negative implications of changing existing liability arrangements, depending 

on how the relevant programs are structured. As has been explained in this report, Federal 

involvement in CCS liabilities has the potential to raise moral hazard and equity issues. In this 

context, if stakeholders know they will not face liability, such a circumstance arguably may 

create a disincentive to proceed in a safe and environmentally sound manner. Nongovernmental organization (NGO) commentators have highlighted this concern (Center for 

Biological Diversity et al., 2010). The development of a far-reaching program to address private 

liability could also be misinterpreted as a signal to the public that the technology is too 

dangerous to use or as a “bailout” of private industry with an attendant socialization of 

injection has ceased, owners and operators must monitor the site to show the position of the CO2 plume and 

pressure front and show that drinking water supplies are not being endangered. Monitoring must continue for at 

least 50 years or until the geologic sequestration project no longer poses an endangerment to underground 

sources of drinking water. Prior to closing a site, the owner or operator must provide a report containing a survey 

plot indicating the location of the injection well relative to permanently surveyed benchmarks; documentation of 

appropriate notification to governmental entities that have authority over drilling activities so that they may 

impose appropriate conditions on subsequent activities in the area; and records that reflect the nature, 

composition, and volume of the CO2 stream. 

97 Financial responsibility requirements are designed to ensure that owners and operators maintain adequate 

financial resources to fulfill their current and future environmental obligations. See (EPA, 2008). 

98 See generally S. 1013, the Department of Energy Carbon Capture and Sequestration Program Amendments Act 

of 2009 Before the S. Comm. on Energy & Natural Resources, 111th Cong. (2009) (statement of Chiara Trabucchi, 

Principal, Industrial Economics Incorporated). 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 75 
significant potential environmental impacts and/or widespread environmental contamination. 

Liability caps and indemnities may be seen as indirect subsidies to CCS developers, possibly at 

the expense of investment in alternative technologies, and Federal assumption of CCS liability 

may create a precedent sought by other industries. Also, except where a regulatory program is 

specifically designed to foster private insurance, government action could be read to undermine 

private insurance markets. 

IV.D Public Information, Education, and Outreach 

IV.D.1 Overview 

Public awareness and support have been recognized as critical components in the development 

of new energy infrastructure, and are widely viewed as vital for cost-effective CCS deployment 

(IPCC, 2005; CRS, 2008; IEA, 2009c). Lack of public acceptance can serve as a barrier if project 

developers fail to recognize the importance of integrating public engagement and education 

throughout the lifecycle of their project. Support or opposition for new technologies can have a 

big impact on their deployment: for example, public opposition has been cited as a key reason 

that no new refineries have been built and no nuclear plants have been ordered since the 1970s 

(CRS, 2008). Whether or not the public and local communities will support or oppose 

commercial-scale CCS projects is to a large extent unknown. Most studies, in fact, have shown 

that the public is largely unaware of CCS (IPCC, 2005; Johnsson et al., 2010; Malone et al., 

2010). 

Public perception of the risks associated with CCS can be significant and—as demonstrated 

during previous CCS projects—there is the potential for concern by local communities that 

they will be subjected to high risks while others derive the benefit. Early experience has shown 

that local opposition can cause or contribute to project delays and cancellations. Geologic 

sequestration projects planned in Spremburg, Germany and Greenville, Ohio were cancelled, in 

part, due to concerns from residents about escaping CO2 endangering public health, reduced 

property values, and induced seismicity (Associated Press, 2009; Slavin and Alok, 2009). 

Residents of Barendrecht, Netherlands have expressed vocal opposition to a nearby 

sequestration project, causing project developers to look for alternative sites (Pals, 2009; 

Voosen, 2010). 

Other CCS projects in the United States provide examples of positive experiences with public 

outreach and engagement. The Regional Carbon Sequestration Partnerships (RCSP) have 

managed the implementation of 21 small scale and several large scale CO2 sequestration 

projects that have either been completed or are currently injecting CO2 in deep saline, coal 

seams, or oil and gas fields. The participants from these projects have worked to consolidate 

their experiences and lessons learned on community engagement and acceptance into a best 

practices guide for public outreach and education (DOE, 2009). 

Report of the Interagency Task Force on Carbon Capture and Storage 76 
 

In order for CCS to be successfully deployed at scale it will be critical to address public 

perceptions of CCS technologies, their risks, and their role in reducing GHG emissions. The 

primary avenues for such work are through outreach and education efforts, and through direct 

engagement with project communities. When done successfully, these efforts can help identify 

key issues, foster public understanding, and build trust between communities and project 

developers. The Federal government can play a useful role in such efforts, though much of that 

role will be in providing information for use by project developers, project communities, and 

the general public. Stakeholder groups could include residents; local, regional, and national 

business owners and organizations; labor and related organizations; environmental 

organizations; environmental justice organizations; employers; employees; academia; emergency 

responders; media; policy leaders; and other institutions. 

IV.D.2 Elements of a Successful Outreach Strategy 

Under the RCSP, DOE has been engaging with local communities to educate and inform them 

about planned pilot and demonstration projects in their areas. DOE’s Best Practices for Public 

Outreach and Education for Carbon Storage Projects presents lessons learned through the planning 

and implementation of CCS projects, as well as best practices for community engagement. The 

World Resources Institute also has issued recommendation for regulators, project developers, 

and local decision-makers for engaging with communities. Many of these recommendations 

center on common themes: 

 Integrate public engagement and outreach efforts into core project management systems, 

from the earliest possible point in time; 

 Provide information about CCS, its risks, and the laws or requirements that are in place 

to minimize risks to human health or the environment; 

 Provide easily accessible information about CCS projects; 

 Engage the community during the planning stage and maintain engagement throughout 

the project lifetime; 

 Communicate the potential benefits of future CCS projects, such as job creation and 

stimulus to the local economy, and decreases in local air pollution;99 

 Provide local communities with several opportunities to raise concerns, and address 

those concerns in a timely manner; 

99 Advanced technologies such as IGCC are more efficient and virtually zero emissions when coupled with carbon 

capture. Replacing existing plants with IGCC facilities would results in reduced air emissions of criteria pollutants. 

In retrofits of existing plants, since the ability to capture CO2 from a power plant will require the plant to install 

NOx and SOx capture systems reducing the emissions of these criteria air pollutants. In oxyfuel plants it is 

expected that all criteria pollutants will be reduced. (MIT, 2009). 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 77 
 Focus on creating an open dialogue with the public, as opposed to a one-sided 

conversation; 

 Create mechanisms and systems to monitor and gauge public reactions and opinions; and 

 Discuss why CCS is important (climate risks, need for sufficient and reliable energy). 

IV.D.3 Status and Key Gaps 

Several key gaps must be addressed to facilitate public acceptance of CCS. Public acceptance 

could be improved by initiatives designed to better understand public acceptance of CCS and 

engage with the public. 

There are a number of claims that the public will be largely opposed to CCS; in reality, the 

public is largely unaware of CCS (Malone et al., 2010). Public engagement activities performed 

under the RCSP pilot projects are beginning to yield a better understanding of community 

concerns, as well as successful strategies for engagement. In general, there is a significant need 

to better understand how the public will view CCS, what their concerns will be, and how they 

can be addressed. 

There is a considerable lack of awareness and understanding of CCS and associated 

risks. Early engagement and communication will be essential, as misinformation and 

misperceptions can quickly spread; once initial opinions are formed, they can be slow to change 

(Ashworth et al., 2010). Studies have shown that public perceptions about CCS become more 

positive with more information, and NGOs are trusted most as conveyers of this information. 

The public is less likely to trust information coming from a single source, particularly coming 

solely from industry or government (Shackley et al., 2009; Ashworth et al., 2010). The general 

public will primarily be concerned about big-picture issues: levels of government funding, impact 

on electricity prices, risks of the technology, and the benefits of CCS compared with other 

energy technologies. 

Communities near planned projects will require targeted engagement. These 

communities may have concerns about how a particular project will affect them: risks to health, 

drinking water, property values, as well as benefits in the form of jobs, stimulus to the local 

economy, and potential reductions in air pollution. Communities could play a significant role in 

how and whether new energy infrastructure projects are constructed. Such communities can 

get involved through various means, including site selection and approval, permitting processes, 

litigation, or less formal means such as protests and media campaigns. In the United States, CCS 

projects implemented to date have been met with support by project communities, with a few 

exceptions. 

Promoting meaningful involvement for disproportionately impacted populations 

requires special efforts. Involving communities already burdened by human health and 

environmental concerns can be particularly important in preventing unintended negative 

Report of the Interagency Task Force on Carbon Capture and Storage 78 
consequences. Minority, low-income, Tribal, and other populations historically underrepresented in environmental decision-making present challenges that are different from those 

presented by the general public. These communities often have a wide range of educational 

levels, literacy, access to the Internet, and proficiency in English. It will be necessary to tailor 

outreach materials to ensure that they are concise, understandable, and readily accessible. 

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 79 

V. Framework for Addressing Market Failures 

As identified in Section IV.A, two key market failures impede the pathway to CCS deployment. 

The Administration’s proposal to establish a market signal by pricing GHG emissions would 

resolve the most significant market failure by internalizing the cost of emissions. The second 

market failure of knowledge spillovers from technology development remains, but is already 

being addressed at least in part by current Federal incentives for CCS. A key objective of this 

section is to outline a framework for assessing what, if any, additional drivers and incentives 

may be warranted beyond those proposed or already in place. 

Several factors serve to widen the gap between the social and private returns to CCS 

technology development relative to those experienced by other low-carbon technologies at a 

comparable stage of development. The deployment of CCS, unlike other low-carbon 

technologies, is entirely dependent on adoption of measures to limit greenhouse gas 

emissions, adding to uncertainty for private investors. As outlined in this report, the widespread 

deployment of CCS also hinges on other unresolved non-economic issues, which again reduce 

expected private returns to CCS development. Finally, the global nature of the externalities 

associated with greenhouse gas emissions and international markets for CCS further increase 

the expected gap between private and social returns to CCS development. 

The fundamental balance that must be achieved in determining the nature and extent of such 

incentives is between ensuring the availability of a cost-effective technology (as a hedge against 

risk to the economy posed by climate change) and over-investing in a technology, leading to 

inefficient allocation of scarce public resources to subsidize what should be private sector 

actions (which distorts economic decision-making and displaces lower-cost solutions). 

Determining the relative efficacy and cost-effectiveness of potential drivers and incentives that 

may spur CCS technology deployment is challenging. Careful consideration should be given to 

any economic costs associated with such policies. This section summarizes existing incentives 

for the development of CCS and provides principles for evaluating the extent to which 

additional drivers or incentives may be considered. The ultimate objective of public investment 

in CCS technology is to support the achievement of GHG emission reduction goals at the 

lowest cost possible, and these options are discussed with this objective in mind. 

V.A Framework for Incentivizing CCS Technology for Public Gain 

There are a number of public policy tools that can be used to channel investment to incentivize 

the commercialization of CCS technology. The following section describes the context in which 

these incentives operate and how they should be assessed. Later sections offer more detail on a 

suite of existing and potential incentives and drivers for CCS technology. 

V. Framework for Addressing Market Failures 81 
V.A.1 Key Principles for Assessing CCS Drivers and Incentives 

Any assessment of policy drivers and incentives should be grounded in the context of the 

related policy goal. Table V-1 shows several key principles to which incentives for CCS should 

adhere. In this report’s context, the purpose of drivers and incentives is to overcome those 

market failures that impede widescale, cost-effective availability of CCS consistent with market 

signals, including a price on GHGs. This goal is not easily translated into a measure of capacity 

deployed or GHG abated, and for good reason, as the market will be the determinant of CCS 

capacity deployed, and GHG abatement will be governed by the cap on emissions. The 

incentives and drivers to be considered should address CCS deployment not as an end in itself, 

but as a means to achieve cost-effective abatement of GHG emissions. 

Table V-1: Key Principles of Public Policy Tools that Address CCS Deployment 

Market Failures 

Incentives should: 

1 Reflect the nature and magnitude of the specific market failure targeted; 

2 Adjust to changing circumstances and information over time; 

3 Enable maximum possible flexibility of private sector response; 

4 Be coordinated with and reflective of interactions with other incentives; and 

5 Maximize achievement of policy objective per dollar of taxpayer and consumer 

cost. 

Reflect the nature and magnitude of the market failure: Potential drivers and incentives should be 

assessed singly and together on the basis of their ability to address a particular market failure. 

The scale and scope of an incentive in this context should be matched as closely as possible to 

the scale and scope of the identified market failure impeding widespread cost-effective 

commercial availability. For example, an incentive addressing market failures related to CCS 

should not be so broad as to affect the cost or financing of already commercialized, mature 

technologies for which spillovers are likely to be very small. 

Adjust to changing circumstances and information over time: The criterion of scale is complex 

because the size of market failures impeding cost-effective CCS commercial availability is not 

only difficult to judge, but will also change over time as the technology matures. Consequently, 

even if it is properly scaled to initial conditions, an open-ended incentive that does not adjust to 

reflect changes in the targeted market failure would introduce inherently inefficient allocations 

of scarce public resources due to inflexibility of the policy tool. Thus, incentives should be 

assessed for their ability to re-scale over time, so that public investment channeled through the 

Report of the Interagency Task Force on Carbon Capture and Storage 82 
incentive structure keeps pace with changes in the magnitude of the market failure it is designed 

to address. Since economic incentives can create their own constituencies, making their 

reduction or removal politically difficult, policy makers should consider the conditions under 

which they should phase out prior to committing to providing them. 

Flexibility of private sector response: To the greatest extent practical, incentives should allow the 

market to decide which particular technologies will be developed. Private investors with their 

own money at risk will have the right incentives and expertise to invest in technologies that are 

most likely to become commercially sustainable. 

Coordinated incentives: Different incentives may address the same market failure to a greater or 

lesser extent, indicating the need to coordinate incentives. Uncoordinated, overlapping 

incentives are more likely to lead to over-subsidy, distortions in investment behavior, and a 

failure to properly scale public intervention to the targeted market failures. The need for 

coordination should be considered both in evaluating the possibility of multiple Federal 

incentives, and in evaluating Federal, State, and local incentives in light of one another. 

Transparency and coordination will also make it more feasible for policy makers to assess the 

effectiveness of CCS incentives. 

Cost-effectiveness: Incentives and drivers should also be assessed for their ability to maximize 

achievement of policy objective per dollar of taxpayer and consumer cost. In pursuing this goal 

of cost-effectiveness, consideration should be given to relevant institutional details of the 

targeted markets, such as differences between publicly owned and investor-owned utilities, or 

differences between cost-of-service territory and competitive power markets. Properly 

targeted and scaled incentives help reduce the cost to taxpayers and consumers relative to the 

benefits provided. But the cost-effectiveness of an incentive for CCS commercialization will also 

depend on its ability to avoid subsidizing investment that would have been made even without 

the incentive. 

V.A.2 Public Funds Require Adaptive Resource Management 

Policy makers should also plan for CCS incentives under an adaptive resource management 

structure, which can restructure public investment programming as new information appears 

about CCS economics and finance. For example, it is very difficult to assess the value of shared 

technological learning. Existing policy tools such as patents help firms capture some portion of 

technological learning from private investments. This appropriated knowledge has value to firms 

and is not a market failure. In contrast, shared technological learning may range from narrow 

spillovers for a single competitor firm to broad spillovers for the larger market, and that 

portion constitutes a market failure. 

Accurate quantification of the magnitude of these spillovers is challenging and undoubtedly 

technology-specific. Attempts to measure it using metrics such as progress ratios cannot fully 

V. Framework for Addressing Market Failures 83 
 

distinguish between efficiency gains driven by shared technology learning and those driven by 

other factors. In this context, Federal policy should conservatively balance potential subsidies 

against their costs. These costs include potential economic distortions from taxation and 

spending, the risk of having subsidies effectively pick technology “winners,” opportunity costs of 

not using funds elsewhere, and the increasing risk of subsidizing “free-rider” investments that 

would have occurred anyway as CCS commercialization advances. 

Federal support targeting CCS-related market failures should leverage considerable non-Federal 

public and private resources. As the market begins to mature, growing experience with CCS 

plants operating under varied conditions and configurations will shrink information gaps, 

thereby weakening the case for continued Federal support. Yet the endpoint for public 

incentives is not obvious. Policy makers should consider at what point incentives should be 

terminated, prior to committing to provide them. Moreover, there should be continual reevaluation of the merits of continuing subsidies as more is learned about the magnitude of any 

market failures that those incentives are expected to address. Nevertheless, it should be 

recognized that subsidies, once enacted, are difficult to terminate. 

V.B Tailoring Public Funding for Targeted CCS Projects 

Creating a long-run price on GHG emissions through a market-based mechanism can 

internalize the social cost of emissions to the extent that the cap reflects society’s judgment of 

acceptable emission levels. A policy requiring CO2 abatement is a necessary precondition to the 

economic relevance of CCS projects at any scale beyond what the market currently supports 

for EOR and beneficial reuse of CO2.

100 

For purposes of supporting a limited number of initial CCS projects to address the market 

failure of knowledge spillovers, the economic gap to viability of those CCS applications must be 

addressed. Policy makers must acknowledge that such an economic gap would be narrowed 

under a cap-and-trade program by the allowance price for each tonne of CO2 emissions 

avoided (i.e., incentive design for public investment should complement, not duplicate, the 

market’s willingness to pay for mitigation). 

A variety of policies can capture shared technological learning in the demonstration and 

deployment phases of CCS development. Any portfolio of incentives would need to be carefully 

coordinated to address both the construction and operation of plants using CCS.101 For 

example, production-based incentives would improve the project’s frequency of operation (and 

100 For example, while Denbury Resources’s willingness to pay up to $7 per tonne of CO2 for EOR assists CCS 

projects’ economic standing, Tenaska’s planned Taylorville CCS plant relies significantly on the recently enacted 

Clean Coal Portfolio Standard in Illinois. See (Bloomberg New Energy Finance, 2010). 

101 If incentives are sufficient to drive construction, but not subsequent operation of the CCS capability, then costeffective acquisition of knowledge spillovers may suffer. 

Report of the Interagency Task Force on Carbon Capture and Storage 84 
 

thus would increase the learning-by-doing that may yield knowledge spillovers), while 

investment subsidies may be more appropriate when the government has a comparative 

advantage in raising capital for riskier technology applications (such as demonstration 

projects).102 

To address knowledge spillovers from demonstration and initial deployment, policy makers will 

need to determine how such potential spillovers impair the market’s willingness to invest in the 

face of early CCS project risk and cost. The following sections detail these factors. 

Large-scale demonstrations of CO2 capture technologies are very important for encouraging 

the successful commercial deployment of CCS (Kuuskraa, 2007; MIT, 2007; National Research 

Council, 2007; GAO, 2008). While industrial CO2 separation processes have been commercially 

available for some time, they have not been deployed at the scale required for large power 

plant applications. The CO2 capture capacities for current industrial processes are typically an 

order of magnitude smaller than the capacity required for a typical power plant. 

A concern regarding CO2 capture technologies is whether they will safely and reliably work 

when applied to coal-based power generation. Based on previous experience of CO2 capture 

technologies in industrial applications, it would appear that these systems should be effective at 

larger scale in power generation applications. However, until these systems are constructed and 

successfully demonstrated at full scale, uncertainty over the technology’s performance and cost 

yield a substantial risk premium for early projects. 

The International Risk Governance Council recently identified five categories of risk affecting 

CO2 capture applied to coal-based power generation. These categories included technical risks; 

economic and financial risks; health, safety, and environmental risks; legal and regulatory risks; 

and public acceptance risks (Oak Ridge National Laboratory, 2007; IEA, 2008; International Risk 

Governance Council, 2009). The latter three categories include “threshold” risk challenges, 

which are addressed in other sections of this report. Successful resolution of those threshold 

risks (such as long-term liability management) is necessary but not sufficient to overcome the 

market failures to first-mover adoption of commercial-scale CCS technology. 

Technical risk from the scale-up of currently available CO2 capture technologies includes 

unforeseen problems in plant operation that could require design and/or operational reform. In 

addition, the gas streams being treated with current industrial CO2 capture processes have 

different compositions and characteristics than flue gas generated by commercial-scale coalbased power plants that could adversely affect process performance. Only commercial-scale 

102 Production incentives also theoretically improve a project’s ability to secure private-sector financing by 

improving expected gains. However, if investors are risk-averse, then pairing production incentives with 

investment incentives may be more cost-effective by lowering the cost of capital associated with relatively high-risk 

projects. 

V. Framework for Addressing Market Failures 85 
demonstrations on actual flue gas will generate operational data to inform accurate estimates of 

the cost and performance of these technologies. 

Primarily as a result of technical risk, there are also economic and financial risks associated with 

application of CO2 capture technologies to coal-based power generation. Acquiring adequate 

financing for early adoption of CO2 capture systems could be difficult until there is a positive 

track record of cost and performance. The risk of cost uncertainty is compounded by uncertain 

benefits from investing in utility-scale CCS technology in the absence of a price on CO2 

emissions. 

Uncertainty over technology cost and performance has a greater impact on investment 

decisions in the power sector, as projects require large upfront capital for long-term use. To 

justify a high-risk investment, private sector financing seeks a correspondingly high potential 

reward. Uncertainty of the actual costs of building and operating CCS may lead utilities and 

regulatory commissioners to postpone such investments, locking in potentially suboptimal 

established technologies for decades. 

To ensure viability for those commercial-scale demonstrations and early deployments of CCS 

power projects that are supported by public funds - on the basis of anticipated technological 

learning - appropriate incentives should bridge the gap between a project’s COE and the 

projected market electricity price. COE projections for these projects are above-expected 

electricity prices in the near term because currently available CCS technologies are relatively 

expensive and energy-intensive, due to the energy required to capture, compress, transport, 

and store CO2 into geologic formations (Herzog et al., 2009). 

Because CCS projects require relatively high capital cost outlays, they are highly sensitive to 

changes in the cost of obtaining capital, which is a function of the project’s perceived risk by 

investors. Therefore, narrowing the gap between these projects’ COE values and expected 

market electricity prices can be achieved both by reducing upfront project cost, and by 

reducing the risk to financiers of providing capital for the projects in addition to establishing a 

price on carbon. 

To address the market failure of knowledge spillovers, the Federal government currently 

pursues two complementary pathways for public funding of targeted CCS applications. The first 

pathway, referred to as “technology push,” includes direct Federal expenditures and authorized 

ratepayer funding for RD&D of CCS technologies. The second pathway, referred to as “market 

pull,” offers a variety of publicly funded financial and economic incentives structured to 

encourage private investment in advancement and deployment of CCS technology. The 

advantages and considerations of the tools within these investment pathways are discussed in 

the following two sections. 

Report of the Interagency Task Force on Carbon Capture and Storage 86 
 

V.C Technology-Push Drivers for CCS 

CCS technologies currently exist but are not likely to be widely deployed at coal-fired power 

plants and other large industrial point sources without additional knowledge generated by 

research, development, and demonstration activities. The current focus of RD&D activities is 

thus two-fold: 

 Demonstrate the operation of current CCS technologies integrated at an appropriate 

scale to prove safe and reliable capture and storage. 

 Develop improved CO2 capture component technologies and advanced power 

generation technologies to significantly reduce the cost of CCS, to facilitate widespread 

cost-effective deployment after 2020. 

DOE’s Office of Fossil Energy partners with industry and others to manage and perform RD&D 

activities on low-carbon fossil energy technologies. The thrust of these activities, implemented 

by DOE’s National Energy Technology Laboratory (NETL), is the efficient and cost-effective 

reduction and removal of CO2 from power plant fuel and flue gas streams and sequestration in 

geologic formations. DOE’s current RD&D program is structured to leverage the strengths of 

its public and private sector partners to conduct applied research, proof-of-concept technology 

evaluation, and pilot-scale testing leading to large-scale demonstrations. DOE’s RD&D efforts 

support the goal of widespread, cost-effective deployment of CCS technologies by addressing 

the knowledge spillover market failure that impedes private sector investment in low-carbon 

technologies. DOE’s efforts are guided by the Secretary of Energy’s goal to support RD&D so 

that widespread cost-effective deployment of CCS can begin in eight to ten years (Chu, 2009). 

Currently funded DOE activities103 are expected to have a significant impact, as described below 

and further detailed in Appendix E. In addition, a detailed description of these RD&D activities 

can be found in the President’s FY2011 Congressional Budget Request for the Office of Fossil 

Energy. 

V.C.1 Demonstration of Current CCS Technologies 

The integration of CO2 capture, transportation, and permanent sequestration at commercialscale, coal-fired power generating facilities has not yet been demonstrated. From a technical 

perspective, the ability to capture CO2, compress it for pipeline delivery, and sustain delivery at 

pressures adequate to ensure dependable injection and reservoir permeability must be 

confirmed. DOE is currently pursuing multiple demonstration projects, using $3.4 billion of 

available budgetary resources from American Recovery and Reinvestment Act in addition to 

prior year appropriations. Successful implementation of these projects will meet the President’s 

103 DOE appropriations for CCS applications include about $400 million annually for RD&D in fiscal years 2009, 

2010, and 2011 (requested), as well as $3.4 billion of ARRA funding for DOE-sponsored demonstration projects 

for CCS projects at industrial facilities and power plants. 

V. Framework for Addressing Market Failures 87 
 

goal of five to ten commercial scale demonstrations online by 2016, but will require carefully 

structured financial plans to manage the large costs associated with these projects. 

Up to 10 integrated CCS demonstration plants in the power and industrial sectors are 

expected to begin operation in the United States under DOE’s CCPI, FutureGen (funded by the 

ARRA and prior year funds), and ICCS solicitation (funded by ARRA). These demonstrations 

will integrate state-of-the-art CCS technologies with commercial coal and industrial plants to 

show that they can be permitted and reliably operated. New power plant applications will focus 

on bringing together IGCC technology with pre-combustion CO2 capture, transport, and 

geologic sequestration. Power plant retrofit and industrial applications will demonstrate 

integrated post-combustion capture. Table V-2 summarizes the planned DOE CCS 

demonstration projects. These projects, in tandem with other projects supported by Federal 

loan guarantees, tax incentives, and State-level drivers, cover a large group of potential CCS 

options. However, ongoing reviews of early projects may identify any remaining gaps in the 

demonstration of capture technologies and classes of storage reservoirs. Early low-carbon 

energy projects, including these 10 CCS demonstration projects, may face economic challenges, 

such as the absence of a carbon price. To the extent appropriate, additional actions may be 

required to support these projects, consistent with the approach of addressing market failures 

in a targeted manner. 

Table V-2: Planned DOE CCS Demonstration Projects 

Performer Location Capture 

Technology 

Capture 

Rate 

(tonnes per 

year) 

Target 

Formation 

Start 

Date 

Pre-Combustion Capture 

Summit Texas 

Clean Energy 

Odessa, TX SelexolTM 2,700,000 EOR 2014 

Southern 

Company 

Kemper 

County, MS 

SelexolTM 1,800,000 EOR 2014 

Hydrogen Energy 

California 

Kern County, 

CA 

Rectisol® 1,800,000 EOR/Saline 2016 

Post-Combustion Capture 

Basin Electric Beulah, ND Amine 450,000­

1,360,000 

EOR/Saline 2014 

NRG Energy Thompsons, 

TX 

Amine 400,000 EOR 2015 

Report of the Interagency Task Force on Carbon Capture and Storage 88 
American Electric New Haven, Chilled 1,500,000 Saline 2015 

Power WV Ammonia 

Oxy-Combustion 

FutureGen Meredosia and Oxy- 1,000,000 Saline 2015 

Mattoon, IL Combustion 

Industrial 

Leucadia Energy 

Lake Charles 

Lake Charles, 

LA 

Rectisol® 4,000,000 EOR 2014 

Air Products Port Arthur, 

TX 

Amine 900,000 EOR 2013 

Archer Daniels 

Midland 

Decatur, IL Amine 900,000 Saline 2014 

Congress is considering another means of supporting large-scale integrated CCS 

demonstrations projects in the form of an additional wires charge to the sale of fossil-based 

electricity. The fees would be weighted based on carbon content of the fuel: coal-based 

generation would be assessed a charge higher than oil-based, which is in turn higher than 

natural-gas-based generation. Existing legislative proposals would make between $1 billion and 

$2 billion available annually to support CCS demonstrations for up to 10 years. 

V.C.2 RD&D of CCS Technologies 

In the context of the DOE Fossil Energy RD&D program, state-of-the-art (“1st generation”) 

CCS technology is described in Section III. As part of its R&D programs, DOE is pursuing 

advanced (“2nd generation”) technologies that could significantly reduce the cost and energy 

penalties associated with 1st generation CCS technologies. For a full description of 2nd 

generation technologies, see Appendix E. Current DOE efforts include advanced computational 

modeling, simulation, and analysis to accelerate the development of 2nd generation CCS 

technologies. This includes the development of science-based models of fossil fuel conversion 

processes; advanced high-temperature materials; and robust sensors to improve system 

performance. 

RD&D and learning-by-doing could transform CCS from a technology only affordable to 

industrialized nations to a cost-effective GHG mitigation option with a global impact. Long-term 

RD&D could also support biomass co-firing with CCS, which, if the biomass is sustainably 

harvested, could result in “net negative” GHG emissions. DOE estimates that for new plants, 

2nd generation CO2 capture technologies combined with advanced power generation 

technologies could limit the increase in COE at the plant gate to 30 percent compared with a 

V. Framework for Addressing Market Failures 89 
modern supercritical PC plant without CCS. For current 1st generation CCS plants, DOE 

estimates this increase to be 60–80 percent. For CCS retrofits, DOE estimates that the 

increase in cost could be reduced by two-thirds with 2nd generation technology (NETL, 2009b). 

For example: 

 Advanced gasification-based technology could achieve high capacity factors and include 

membrane technology for O2 supply and H2/CO2 separation, warm gas cleanup, and 

either high-efficiency H2 turbines or pressurized solid oxide fuels cells to generate 

electricity. 

 New PC plants could be designed for more efficient operation using advanced high 

pressure-high temperature power cycles. 

 New and retrofit power plants and industrial facilities could use advanced 2nd generation 

CO2 capture technologies including solvents, solid sorbents, and membranes for postcombustion capture. 

 Oxy-combustion power plants could use membranes for O2 supply and other 

innovations to improve plant efficiency. Better understanding of flame characteristics, 

burner and coal-feed design, and analyses of the interactions between products of 

combustion and boiler materials could improve the development of low-cost and 

efficient oxy-combustion power plant systems. 

CO2 sequestration technology will continue to evolve, allowing safe and permanent 

sequestration in more challenging formations, and enabling the wider deployment of CCS. 

Large-scale geologic CO2 sequestration tests are being conducted across the country under the 

Regional Carbon Sequestration Partnership Program that complement RD&D aimed at 

improving the ability to predict and track the flow of CO2 injected into geologic formations, 

including an improved understanding of geologic trapping mechanisms that can reduce CO2 

sequestration concerns, and establish best practices that facilitate permitting. 

One option for improving the cost-effectiveness of CCS deployment is to accelerate the 

availability of 2nd generation CCS technologies, and DOE is currently working to utilize 

Recovery Act funding for this purpose. This accelerated program will focus on developing 

more efficient, lower capital cost CCS technologies, and help to meet the President’s goal to 

enable widespread, cost-effective deployment of CCS within ten years. 

V.C.3 International Collaboration 

Widescale deployment of fully integrated, efficient, cost-effective CCS systems depends strongly 

on RD&D efforts to advance CCS technologies. U.S. government collaboration with other 

countries on fossil energy technologies is motivated by the premise that joint technology 

RD&D can help to improve energy security, address climate change challenges, and position 

U.S. businesses as global technology leaders. Mutually beneficial RD&D with foreign partners 

Report of the Interagency Task Force on Carbon Capture and Storage 90 
and promotion of U.S. clean energy technologies in foreign markets are central to the U.S. 

government’s desire to address the environmental impacts of producing and using fossil fuels. 

International collaboration offers several potential advantages: First, the technology 

development cycle can be shortened via cooperation with experts working on creative 

concepts in foreign RD&D organizations that have invested in unique facilities; second, 

international collaboration can lower the cost to U.S. taxpayers of achieving programmatic and 

national objectives via meaningful, coordinated, cost-shared RD&D; and third, access to worldclass foreign researchers, who often look at the problems associated with taking a technology 

from the lab to the marketplace through different “lenses,” can help to create more practical, 

globally acceptable technology solutions to the problems associated with producing and using 

fossil fuels. 

Most CCS technology RD&D is being sponsored by and occurring in the United States and 

other developed countries. Collaboration with other developed countries may help to prove 

the viability of CCS as a long-term climate change mitigation option by speeding global 

acceptance and commercialization and by leveraging resources and sharing of results. However, 

as discussed in Section II, emerging economies will also need to widely deploy low- and zerocarbon electricity generation technologies, such as CCS, to achieve global climate change 

mitigation goals. The United States should continue its leadership role engaging large, coaldependent emerging economies with rapidly expanding power sectors to avoid locking in 

inefficient, high GHG emission power generation assets for decades. Failure to do so may make 

subsequent CCS deployment more difficult and increase the cost of meeting global GHG 

reduction targets. 

Currently 10 countries (China, United States, India, Russia, Japan, South Africa, Germany, 

Republic of Korea, Australia, and Poland—ordered by annual emissions) account for 83 percent 

of the global CO2 emissions from coal use. Despite efforts being undertaken in various fora, 

data on the potential geologic CO2 sequestration capacity for these countries are not available 

on a consistent basis. However, an assessment of available data indicates that sufficient 

sequestration capacity is likely available where needed relative to these countries’ current coalbased emissions. Most of these countries likely have hundreds to thousands of years of 

potential sequestration capacity, based on current emissions from coal combustion in all 

sectors (Appendix N). 

The recently established Global Carbon Capture and Storage Institute has cataloged and 

analyzed potential CCS projects worldwide (Global CCS Institute, 2010). A total of 80 largescale integrated projects in 17 countries (Algeria, Australia, Canada, China, Czech Republic, 

Finland, France, Germany, Italy, Republic of Korea, Netherlands, Norway, Poland, Spain, United 

Arab Emirates, United Kingdom, and the United States) were identified and classified according 

to their development status and progress toward key decision points for project design, 

definition, cost estimation, execution planning, and risk analysis. Each of these projects was 

V. Framework for Addressing Market Failures 91 
assessed against criteria developed by the IEA to ascertain whether they would meet the 

commitment made by G8 leaders in 2008 at their Hokkaido Toyako Summit to launch 20 largescale CCS demonstration projects by 2010, with a view to beginning broad deployment of CCS 

by 2020. Thirty-one of the 80 large-scale integrated CCS projects that were identified and 

assessed by GCCSI are located in the United States. The GCCSI found “...that most projects 

require significant work to narrow the gap to be considered launched at this time under the G8 

criteria” They also indicated that while “the growing pipeline of projects is a positive 

development and is suggestive of a wider deployment of CCS by 2020,” that “broader scale 

deployment in this all encompassing sense is still faced with significant challenge.” Global 

cooperation on these projects is important for advancing CCS technology and gaining public 

acceptance. 

In addition to enhancing RD&D, international collaboration may help to address other barriers 

to deployment that will advance domestic objectives. Ensuring that a means is available for U.S. 

interests to participate in CCS projects in other countries can allow the United States to 

benefit from both the knowledge created in these projects and from potential export 

opportunities. In some instances, it might also allow U.S. companies to acquire international 

offset credits for use in compliance with domestic legislation. 

The United States is involved in many bilateral and multilateral cooperative agreements and 

initiatives in which CCS is either the focus or a key element of the cooperation. These costshared activities span cooperation with both developed and developing countries focusing on a 

wide range of objectives (RD&D, capacity building, regulatory development, finance, market 

assessments, engineering analyses, and information exchange) that help advance CCS 

technology development and acceptance in the United States. The Carbon Sequestration 

Leadership Forum (CSLF) is an example of multilateral cooperation focused on the 

development of improved cost-effective technologies for the separation and capture of CO2 

and its transport and long-term, safe geologic sequestration. The mission of the CSLF is to 

facilitate the development and deployment of such technologies via collaborative efforts that 

address key technical, economic, and environmental obstacles. Other multilateral efforts are 

being conducted through the IEA, the Asia-Pacific Partnership for Clean Development and 

Climate, the Asia Pacific Economic Cooperation, the Global Carbon Capture and Storage 

Institute and the Major Economies Forum’s Global Partnership. Examples of current bilateral 

cooperation include RD&D and demonstration activities being undertaken with Australia, Brazil, 

Canada, China, Japan, Republic of Korea, and Norway. In addition, more than 25 organizations 

from some 15 countries participate in DOE RCSP efforts. 

Coordination of efforts being undertaken through bilateral and multilateral cooperation on CCS 

technology RD&D, policy development, and public engagement is critical to ensure maximum 

effectiveness, both from the standpoint of making wise investments of taxpayer dollars and to 

rapidly advance the most promising technologies through the development cycle into early 

Report of the Interagency Task Force on Carbon Capture and Storage 92 
deployment and wide acceptance. The Office of Clean Energy Collaboration within the Office 

of Fossil Energy leads coordination of DOE’s CCS cooperation with other countries and within 

the Department, engaging with the State Department as appropriate. Periodic reviews of 

ongoing and planned activities are conducted, usually with input from the private sector. 

Bilateral engagement on CCS is coordinated within DOE through strategic energy policy 

dialogues, with participation by the State Department, to ensure consistency with the 

Administration’s broader international priorities and climate and energy goals. Coordination of 

efforts being undertaken through multilateral cooperation is more difficult given the number of 

countries in these organizations, different funding cycles, varying levels of involvement by key 

countries, and at times different political objectives for participation. The State Department has 

a leading role in coordination of multilateral RD&D cooperation along with DOE’s Office of 

Policy & International Affairs. 

Information on key design parameters from CCS projects being implemented by leading RD&D 

organizations and private-sector firms in other countries, along with lessons learned on their 

operational issues (especially from projects with similar geologic formations), will help the 

United States in proving the long-term safe and effective geologic sequestration of CO2. The 

United States is currently participating in 10 large-scale CCS projects in other countries to gain 

additional information sooner on key technologies and issues (Table N-2 in Appendix N). U.S. 

scientists are intimately involved in field experiments for site characterization and well 

monitoring, performing reservoir simulation modeling, and developing and testing an array of 

monitoring, verification and accounting techniques and technologies—all of which will yield 

information that will help to overcome technological barriers to CCS deployment domestically. 

V.D Market-Pull Incentives for CCS 

V.D.1 Loan Guarantees 

Government loan guarantees can help promising, early-stage commercial technologies 

penetrate markets in which providers of capital are either unable or unwilling to provide 

financing without public assistance. Such reluctance may reflect substantial capital requirements, 

the complexity and unproven nature of the technologies, regulatory uncertainty concerning 

CO2 emissions, and/or the impaired functioning of markets that would normally supply capital, 

particularly debt. 

The capital structure of projects receiving loan guarantees generally includes a significant 

amount of debt. By statute, candidate projects are required to have a reasonable prospect that 

project sponsors will repay the underlying loans. For projects receiving a DOE loan guarantee, 

debt can fund up to 80 percent of project costs, although a candidate project is generally more 

attractive the greater the proportion of equity at stake. Equity contributed by the project 

sponsors would fund the remaining costs. In any financing in which a large amount of debt is 

used to finance the project, it is important that sponsors maintain substantial equity capital at 

V. Framework for Addressing Market Failures 93 
risk during the life of the debt. This creates a compelling incentive for the sponsor not simply to 

develop a project, but to work toward its long-term success so that the debt will be repaid in 

the manner in which the underlying loan anticipates. DOE’s Loan Guarantee Program (LGP) for 

fossil fuel energy projects currently is evaluating CCS projects that gasify coal or petroleum 

coke and produce a range of products from power and natural gas to transportation fuel and 

chemical manufacturing feedstock such as ammonia and methanol. 

The USDA’s Rural Utilities Service (RUS) makes direct loans and loan guarantees to electric 

utilities, and is already supporting at least one CCS project. All plant improvement projects are 

reviewed based on need to meet either current or pending regulations, the project’s technical 

feasibility, net present worth economic analysis, and the borrower’s financial ratings. Up to 100 

percent financing of CCS projects could potentially be provided based on the review of these 

requirements. 

A CCS project can support a loan (and a loan guarantee) only if it creates a consistent cash flow 

stream with which to service the debt. For this reason, pre-commercial projects with uncertain 

performance projections are typically better candidates for grant funding than for loan 

guarantees. Moreover, the current field of candidate projects for loan guarantees is relatively 

limited by the inability of CCS projects to rely on cash flow from CO2 abatement prior to 

enactment of a policy to create a carbon market. Establishment of a domestic carbon price 

could markedly improve the financial profile of CCS projects. The foundation for a candidate 

project’s creditworthiness requires, among other things, sound supply agreements, product 

sales agreements, reliable operations, and a high level of maintenance of the production facility. 

Therefore, projects under consideration to date rely on low-risk capture and sequestration 

methods based on commercial technology, such as pre-combustion capture techniques with 

beneficial reuse of the CO2 produced. 

Prospective financial success, sponsor expertise, and each project’s contribution towards 

reducing, avoiding, or sequestering greenhouse gas emissions should govern the admission and 

vetting of investments in a loan guarantee program. Loan guarantees should be structured to 

complement, not displace, the private sector’s efforts to finance large capital projects in power 

generation, oil and gas, petrochemicals, infrastructure, and public works. 

The process of issuing loan guarantees is contingent on the ability to underwrite the risks in 

CCS projects, a complex task in the absence of clear regulatory and legal frameworks. Section 

VII lays out potential responses to CCS legal and regulatory issues in greater detail. 

V.D.2 Tax Treatment 

The Internal Revenue Code already contains a number of incentives to support CCS 

technology development and deployment. Section 41 and Section 174 include a special tax 

credit for qualifying research expenditures and a deduction for research expenditures incurred. 

Report of the Interagency Task Force on Carbon Capture and Storage 94 
 

 

The research and experimentation (R&E) tax credit is 20 percent of qualified research expenses 

above a base amount determined by the taxpayer’s historical research intensity. Taxpayers can 

elect the alternative simplified research credit (ASC), which is equal to 14 percent of qualified 

research expenses that exceed a base amount equal to 50 percent of the average qualified 

research expenses for the three preceding taxable years. The R&E tax credit also provides a 

credit for 20 percent of basic research payments above a base amount, and for all eligible 

payments to an energy research consortium for energy research. The R&E credit expires for 

amounts paid or incurred after December 31, 2009. However, the Administration’s FY 2011 

Budget has proposed to make this tax credit permanent. 

Taxpayers currently may elect to deduct the amount of certain research or experimental 

expenditures paid or incurred in connection with a trade or business, notwithstanding the 

general rule that business expenses to develop or create an asset that has a useful life extending 

beyond the current year must be capitalized. However, these deductions are reduced by the 

amount of the taxpayer’s research tax credit determined for the taxable year. Taxpayers may 

alternatively elect to claim a reduced R&E tax credit amount in lieu of reducing deductions 

otherwise allowed. 

The present tax credits for R&E generally do not favor one particular technology over another 

because credits are available for all qualifying scientific research expenditures. The government 

is not attempting to “pick winners”—the firm decides what R&E investments to undertake. 

Research expenditures on clean energy technologies and CCS are potentially eligible for the 

present credits provided they meet certain eligibility criteria.104 

An investment tax credit under section 48A is available for power generation projects that use 

IGCC or other advanced coal-based electricity generation technologies. As originally enacted in 

2005, the credit amount is 20 percent for investments in qualifying IGCC projects and 15 

percent for investments in qualifying projects that use other advanced coal-based electricity 

generation technologies. The Secretary of the Treasury may allocate $800 million of credits to 

IGCC projects and $500 million to projects using other advanced coal-based electric generation 

technologies. Under the 2008 amendments to this provision, the credit rate is increased to 30 

percent for new IGCC and other advanced coal projects and the Secretary is permitted to 

allocate an additional $1.25 billion of credits to qualifying projects. The 2008 amendments also 

provide that qualifying projects must include equipment that separates and sequesters 65 

percent of the project’s total CO2 emissions. 

104 Qualified research is research that is undertaken for the purpose of discovering information that is technological 

in nature, the application of which is intended to be useful in the development of a new or improved business 

component of the taxpayer, and substantially all of the activities of which constitute elements of a process of 

experimentation for functional aspects, performance, reliability, or quality of a business component. 

V. Framework for Addressing Market Failures 95 
 

Under section 48B, as originally enacted in 2005, a tax credit of 20 percent was available for 

investments in certain qualifying gasification projects. The Secretary may not allocate more than 

$350 million in credits. Under the 2008 amendments to the provision, the gasification project 

credit rate is increased to 30 percent and the Secretary is authorized to allocate an additional 

$250 million of credits to qualified projects that separate and sequester at least 75 percent of 

total CO2 emissions.105 

Under section 169, a taxpayer may elect to recover over a period of 60 months the cost of any 

certified pollution control facility that is used in connection with a plant or other property that 

was in operation before January 1, 1976. An air pollution control facility, if used in connection 

with electric generation property that is primarily coal-fired and was placed in operation after 

December 31, 1975, may qualify for an amortization period of 84 months.106 

Under section 45Q, a credit of $10 per tonne is available for qualified CO2 that is captured at a 

qualified facility, used as a tertiary injectant in a qualified enhanced oil or natural gas recovery 

project and disposed of in secure geological sequestration. In addition, a credit of $20 per 

tonne is available for qualified CO2 captured by a taxpayer at a qualified facility and disposed in 

secure geological sequestration without being used as a tertiary injectant. The credit sunsets at 

the end of the calendar year in which the Treasury Secretary certifies, in consultation with the 

Administrator of the Environmental Protection Agency, that 75 million tonnes of qualified CO2 

have been captured and sequestered. As a point of reference, a 1,000 MW CCS power plant 

that captures 90 percent of its CO2 emissions and has a utilization rate of 80 percent would 

capture a cumulative amount of about 75 million tonnes over an 11-year period. 

In general, the value of tax subsidies may not be equal among firms because some firms may not 

have sufficient tax liability against which to claim the credit. Further, non-taxable entities, such 

as governmental bodies and cooperative electric companies, cannot take direct advantage of 

investment or sequestration tax credits, although they could benefit from tax credit bonds. 

Firms without enough tax liability to take advantage of the credits will have less incentive to 

invest in tax-favored investments than those firms that can take immediate advantage of the 

credits. Firms generally may carry unused credits back one year and use them to offset tax 

liability that year or forward to a future period when they have enough tax liability to use the 

105 As of June 14, 2010, all $350 million 48B credits and $908.5 million 48A credits authorized under sections 48A 

and 48B as originally enacted have been allocated. All $250 million 48B credits and approximately $1 billion of the 

48A credits authorized under the 2008 amendments have been allocated. 

106 Thus, special amortization may be allowed for certain qualified CCS property. The CO2 capture equipment 

must be certified by EPA that its function is the abatement or control of air pollution and that it is in compliance 

with applicable Federal regulations. The equipment cannot alter the nature of the production process and cannot 

significantly increase the output or capacity, extend the useful life, or reduce the total operating costs of the 

production plant. 

Report of the Interagency Task Force on Carbon Capture and Storage 96 
 

credits, but credits that are carried forward have a lower present value than credits that can be 

claimed in the year they are earned.107 Carlson and Metcalf (2008) found that between 2000 and 

2005, the ability of corporations to take energy-related tax credits was significantly curtailed by 

limitations in the regular tax on the use of general business credits. For example, for most 

years, between half and two-thirds of the renewable electricity production credit could be 

taken in the current year. In 2003 and 2004, however, only one-quarter of the credits could be 

taken immediately. In addition, the corporate alternative minimum tax (AMT) can reduce the 

value of preferential depreciation rates for energy-related capital investment and energy-related 

tax credits by deferring the time at which they may be claimed. Firms can form a partnership 

with other firms that have sufficient taxable income to take advantage of energy-related tax 

credits. In this context, the latter firms are referred to as “tax equity investors.” However, the 

costs associated with the financial arrangements necessary for the partnership also reduce the 

value of the tax credits. As was seen in the recent financial crisis, a disruption in the tax equity 

markets may significantly reduce the ability of firms to take advantage of tax credits. 

An additional consideration is whether a proposed tax subsidy would yield additional 

investment in qualifying facilities, or instead simply subsidize activity that would have taken place 

anyway. For example, at least some recipients of Federal renewable tax credits likely would 

have deployed renewable energy sources in response to State renewable portfolio standards; 

the tax credits were not necessarily a motivating factor. The R&E credit attempts to focus the 

incentive on research that would not have been taken in the absence of the credit by requiring 

that research exceed a base amount related to the firm’s historical research activity. However, 

the base amount may not accurately measure the amount of research that would have been 

taken anyway, so some R&E credits likely are claimed for expenditures that would have taken 

place in the absence of incentives. Further, the energy research credit does not have a base 

amount (i.e., it is available for the first dollar of qualified energy research expenditures) and thus 

likely subsidizes some research that would have been undertaken anyway. 

In cases where the incentive subsidizes an activity that would have been undertaken even in the 

absence of a subsidy, some of the reductions in Federal tax receipts offer no additional 

environmental or technological benefit. Insofar as CCS would be the economic response of 

choice by the private sector to other policies (such as a price on carbon) in the future, tax 

credits would divert revenue but fail to deliver additional benefits. 

Finally, it is important to remember that in order to be deficit-neutral, tax credits must be paid 

for with higher distortionary taxes elsewhere in the economy. Thus, the cost of a tax credit to 

107 Generally, the general business credit may not exceed net income tax less the greater of the taxpayer’s 

tentative minimum tax liability or 25 percent of net regular tax liability above $25,000. Unused general business 

credits may be carried back one year and forward twenty years. 

V. Framework for Addressing Market Failures 97 
 

 

the public budget is typically greater than the revenue foregone from the affected tax, insofar as 

the shift in the tax burden yields suboptimal conditions in the national economy. 

V.D.3 Greenhouse Gas “Bonus” Allowance Allocation 

Recent legislative proposals for GHG cap-and-trade systems have reserved a share of emission 

allowances for free allocation to CCS applications. For example, the American Power Act of 

2010 discussion draft (APA) reserves about 6.3 percent of total allowances from vintage years 

2017–2034 for a “bonus allowance” program for CCS installations. Qualifying industrial facilities 

and electricity generators, including retrofits, receive the incentive for the first 10 years of their 

CCS operation. However, industrial facilities are limited to receive collectively no more than 15 

percent of the total incentive awarded. Electricity generators must burn at least 50 percent coal 

or petroleum coke fuel to qualify, and coal-to-liquids facilities cannot qualify for the incentive. 

The APA discussion draft structures the bonus allowance incentive in three project tranches. 

Projects in the first tranche of 10 gigawatts (GW) of CCS receive between $50 and $96 per 

tonne of CO2 sequestered (plus $10 per tonne if online by 2017), with the precise value 

determined by a project’s rate of CO2 capture and sequestration (between 50 and 90 percent). 

Projects in the second tranche of 10 GW receive between $50 and $85 per tonne based on a 

similar scale of percentage of emissions sequestered. Developers of projects in the third 

tranche of up to 50 additional GW of CCS would participate in reverse auctions to establish 

the disbursement price per tonne of CO2 sequestered. 

The total value of this incentive is a function of the total number of allowances reserved and 

their market prices. Under the carbon prices modeled in EPA’s recent analysis of the APA 

discussion draft, the total value of the CCS bonus allowance incentive is about $166 billion in 

2005 dollars.108 

Under this incentive structure, recipients are paid a particular sum (fixed in statute or 

determined in a reverse auction, based on the tranche) for each tonne of CO2 sequestered, but 

the payment is denominated in allowances. A CCS project being awarded $90 per tonne of 

sequestered CO2 would receive nine allowances (for each tonne sequestered) if the carbon 

price is $10, or only six allowances if the carbon price is $15.109 The monetary value of the total 

incentive disbursement is the same between those scenarios, but more allowances are required 

for the award when the carbon price is lower. The total value available via this incentive is 

capped by a fixed number of allowances (not by total funding disbursed). Therefore, a lower 

carbon price path reduces the total deployment potential using this incentive, while a higher 

carbon price path would increase the amount of sequestration supported by bonus allowances. 

108 Environmental Protection Agency, June 2010 Analysis of the American Power Act, 

http://epa.gov/climatechange/economics/economicanalyses.html. 

109 Carbon pricing is per tonne of CO2 (the same measure for each greenhouse gas allowance). 

Report of the Interagency Task Force on Carbon Capture and Storage 98 
 

The differences in the incentive structure between each project tranche are significant. In the 

first two tranches, the incentive value is fixed on a per-tonne of CO2 sequestered basis. Such a 

sequestration incentive should target the economic gap between the cost of sequestration and 

what the private market is willing to pay. The latter factor is directly reflected by the carbon 

price under a cap-and-trade system, which is the market value of each tonne of CO2 abated. 

Thus, the economic gap to sequestration will shrink or grow as the carbon price rises or falls. 

A fixed per-tonne incentive fails to accommodate both for the market’s willingness to pay for 

CCS and for the ultimate cost of CCS, which may lead the incentive to fall short of or exceed 

the economic gap for qualifying CCS deployment. This potential mismatch of the fixed pertonne bonus value to the CCS economic gap impairs this incentive’s cost-effectiveness. If the 

fixed value is set too low, then otherwise-qualifying CCS projects will not be economically 

viable and at least some of the incentive will go unclaimed. If it is set too high, then the limited 

value of the total incentive is depleted faster for fewer results and the public investment will 

have displaced at least some willing private investment. 

The third tranche replaces the fixed per-tonne values with a system for conducting reverse 

auctions for qualifying projects. The concept of a reverse auction positions the government as a 

“sequestration buyer” and multiple candidate CCS projects as “sequestration sellers.” If the 

reserve auction process is structured to screen out fraudulent or unqualified bidders, the 

resulting competition between candidate projects greatly increases the cost-effectiveness of the 

allocated CCS bonus allowances. The auction process allows participants in the marketplace to 

make informed bids based on knowledge of CCS costs and the market value of CO2 abatement 

(e.g., the allowance price); these variables are unpredictable in advance and sometimes 

unknowable to policy-makers.110 Reverse auction bidding would calibrate the incentive’s pertonne value to match the economic gap for qualifying CCS. In addition, the competition 

between projects should yield the most sequestration possible for the value of the total bonus 

allocation awarded in the second tranche. Like other auction procedures, a reverse auction 

approach for CCS bonus allowances would need to establish safeguards against failure of 

participants to deliver on their bids and against potential collusion between participants.111 

110 In expert Congressional testimony, one CCS vendor observed that “climate legislation proposals, which 

arbitrarily set CCS incentive prices, would result in less cost-effective CCS technologies being subsidized, while 

plant owners/developers and regulators gain little or no information on what real CCS costs are” (Alix, 2009). 

111 A recent report proposes several options for vetting reverse auction bids: “For instance, the [qualifying 

project’s development] plan could demonstrate that the bidder is able, within 12 months of the bid being accepted, 

to finalize EOR or transport sequestration agreements, obtain final air permits, secure final financial commitments, 

and break ground on the project. The development plan could also demonstrate the ability of the bidder to 

achieve commercial operation within four years of the bid being accepted. These requirements will help ensure 

that auction participants are serious bidders capable of building and operating the proposed projects in a timely 

and effective manner” (Clean Air Task Force, 2010). 

V. Framework for Addressing Market Failures 99 
 

The magnitude of bonus allowances does not appear calibrated to address specific market 

failures. Public investment on the order of $166 billion, if structured properly to be matched to 

economic gaps as discussed above, may drive a substantial amount of geologic sequestration of 

CO2. However, policy-makers cannot know with certainty in advance of a cap-and-trade system 

if such a level of sequestration would be the efficient, cost-minimizing reaction of the 

marketplace to the carbon price path established by the cap. 

If bonus allowances fund CCS deployment beyond the demonstration and early deployment 

projects relevant to the market failure of knowledge spillovers, then this incentive will have 

distorted the economic reaction to the carbon price signal by substituting high-cost for lowcost emission reductions. Simultaneously, such potential over-subsidization of CCS deployment 

would artificially lower electricity prices, which muffles the carbon price signal to consumers 

and reduces the incentive for efficiency in electricity consumption (among the lowest-cost 

potential CO2 emissions mitigation options).112 

112 McKinsey & Company (2007). 

Report of the Interagency Task Force on Carbon Capture and Storage 100 
 

VI. Options for Enhancing the Legal/Regulatory Framework 

A key consideration for both near- and long-term deployment of CCS is whether the existing 

framework—with proposed modifications—can adequately and effectively govern CCS. The 

Task Force evaluated select current environmental, natural resources, and other laws 

potentially relevant to geologic sequestration of CO2 as discussed in Section IV.B.1 and 

Appendix F of the report and concluded that the current statutory framework can be used to 

regulate CCS projects. 

Some regulatory actions will be necessary in the near term, to help meet the goal of bringing 

five to ten commercial demonstration projects online by 2016. As discussed above in Section 

IV.B.1, new requirements under SDWA, expected to be finalized in late 2010, will establish a 

new well class for geologic sequestration under the SDWA UIC Program. The new GHG 

reporting provisions for geologic sequestration facilities under the CAA, also expected in late 

2010, will ensure that CO2 emissions to the atmosphere from capture and sequestration are 

monitored and reported in both the onshore and offshore environments. Clarification of the 

regulatory status of CO2 and/or CO2 injectate under existing statutes, particularly RCRA, may 

also be needed, as well as further development of risk evaluation tools to support regulatory 

development and permitting. 

In the longer term, as discussed in Section IV.B, additional actions may be needed to facilitate 

widespread, cost-effective deployment of CCS within 10 years. Because current environmental 

laws and programs were not designed with CCS in mind, a “comprehensive” framework may be 

needed to protect human health and natural resources, while providing a simple, 

straightforward regulatory system to oversee CCS and speed deployment of these technologies 

(RFF, 2007; CCS Regulatory Project, 2008; Harvard Kennedy School, 2009). However, 

particularly for near-term deployment, it may be appropriate to build upon the existing 

framework (with some modifications) (IEA, 2008; CCS Regulatory Project, 2009b; Harvard 

Kennedy School, 2009). The Task Force has assessed the existing regulatory framework with 

respect to its ability to meet key regulatory goals outlined below. 

To facilitate widespread, cost-effective deployment of CCS within 10 years, a future regulatory 

framework could be designed to balance multiple goals: reducing CO2 emissions; increasing 

energy security; and protecting human health, the environment, and our resources. With this in 

mind, the Task Force has identified two paths for moving forward for long-term deployment of 

CCS: 

Option 1: Build Upon Existing Authorities that Regulate CCS Projects. Current 

statutes and programs—including SDWA, CAA, RCRA, CERCLA, FLPMA, MPRSA, OCSLA, 

HLPA and others—could be modified as needed to ensure safe and efficient deployment. 

Permitting and reporting processes could be streamlined, where appropriate, exemptions could 

VI. Options for Enhancing the Legal/Regulatory Framework 101 
be considered for early projects to accelerate deployment and learning by doing, and regulatory 

certainty could be enhanced. 

Option 2: Create a New Statutory Framework for CCS. A new statutory framework 

could be developed to include all regulatory considerations and mechanisms under one 

program. This program would be designed to address all stages of CCS (from the point of 

capture through long-term stewardship), articulate all potential liabilities, and address all goals 

of a comprehensive framework. It would establish clear requirements for how geologic 

sequestration sites could receive a fungible emissions “credit,” harmonizing provisions with 

future climate regulations. 

Under either of these options, it would be important to clearly articulate the roles and 

responsibilities of Federal and State agencies onshore and offshore. Federal involvement could 

provide consistency in how sites are selected and managed and help address the entire range of 

potential environmental and legal issues, particularly if long-term stewardship of sites will be 

assumed or shared by Federal agencies. States are likely to be responsible for most of the 

permitting and oversight of geologic sequestration sites on private lands; thus coordination and 

clear delineation of roles will be needed to clarify regulatory authorities and processes. 

Creation of a “comprehensive” regulatory framework could address concerns that additional 

clarity with respect to the existing framework may be needed to facilitate widespread costeffective deployment. Through a review of the literature, consultation with experts, and 

interagency dialogue, the Task Force identified eight key goals of a regulatory framework for 

geologic sequestration of CO2. The goals are discussed in more detail below: 

A comprehensive framework would: 

 Be tailored to ensure the integrity of the emissions reductions associated with CO2 

sequestration; 

 Address the full range of potential impacts to human health and the environment, 

including environmental justice; 

 Include clear standards, regulatory approaches, and legal or financial mechanisms that 

might be needed throughout the life of the CO2 sequestration project, from site 

selection and operation to long-term stewardship; 

 Promote national consistency, yet address existing differences in authorities between the 

onshore (Private vs. Federal) and offshore (State vs. Federal), and clearly articulate the 

role of States; 

 Include strong compliance assurance and enforcement mechanisms; 

 Create flexibility to account for site variability and be adaptive to accommodate learning; 

Report of the Interagency Task Force on Carbon Capture and Storage 102 
 

 Build knowledge and public confidence by making information available and creating 

opportunities for public engagement; and 

 Be designed to meet international obligations as appropriate. 

Goal 1: Tailor for CO2 sequestration as a climate change mitigation approach. Given 

that the purpose of CCS is to address climate change, it will be paramount to ensure that 

projects reduce CO2 emissions, and that regulations and programs are designed to consider 

linking CCS with a future climate regime (RFF, 2007; CCS Regulatory Project, 2009b). EPA has 

proposed new Federal requirements under the SDWA for the underground injection of CO2 

for the purpose of geologic sequestration, which will create a new class of well under EPA’s 

SDWA UIC Program. This program was designed to protect USDWs, but has limitations with 

respect to addressing other aspects of CCS, such as GHG mitigation and long-term stewardship 

of geologic sequestration sites (beyond the post-injection site care period) (CCS Regulatory 

Project, 2008; Harvard Kennedy School, 2009). While SDWA UIC Program permitting does 

not directly address air emissions, EPA has proposed methodologies and approaches for 

monitoring and verification of CO2 injected and stored as discussed above. In conjunction with 

data collected under other subparts of EPA’s Greenhouse Gas Reporting Program, the data 

collected under this proposal on the amount of CO2 injected and geologically stored in the 

United States would allow EPA and others to track the amount, growth, and efficacy of geologic 

sequestration over time and to evaluate relevant policy options related to this climate change 

mitigation strategy. 

Goal 2: Address the full range of potential impacts to human health and the 

environment, including environmental justice. The SDWA UIC statute is focused on 

protection of USDWs from endangerment, and public health as it relates to endangerment of 

USDWs; it does not provide authority to address other human health and ecosystem impacts. 

Proposed UIC Class VI requirements for geologic sequestration wells seek to permanently 

contain CO2 by addressing leakage pathways and requiring comprehensive monitoring plans to 

track movement of CO2 plumes. These requirements may indirectly protect against some 

impacts other than those associated with USDWs. However, as discussed in Section III.C 

improperly operated CO2 injection activities could conceivably result in release of CO2 to the 

atmosphere from underground locations far afield from USDWs. Such releases may have a 

range of effects on human health and exposed terrestrial and aquatic ecosystems. Other 

Federal government authority to address human health and environmental impacts exists under 

various statutes, such as CAA, RCRA, CERCLA, and the Emergency Planning and Community 

Right-to-Know Act (EPCRA). However, because these authorities differ in scope and coverage, 

significant efforts by implementing agencies would be needed in order to address all possible 

impacts from CCS, appropriately balance environmental and safety objectives, reduce 

redundancy, and streamline regulatory requirements across those regulatory programs. 

VI. Options for Enhancing the Legal/Regulatory Framework 103 
 

Environmental justice issues concerning the storage phase of CCS can be addressed through 

the SDWA UIC Program permitting process. The SDWA provides that EPA can deny permits 

or establish permit limits where such injection may “endanger” public health. As a result, in 

those States,113 territories, and Federal lands where EPA issues permits, the SDWA provides 

EPA with authority to establish additional permit requirements to those already required under 

40 C.F.R. §144.51 when EPA finds that injection activity may result in drinking water supply 

contamination that may adversely affect the health of minority, low-income, Tribal, or other 

vulnerable populations. Attention should also be devoted to avoid impacting areas traditionally 

used for subsistence consumption, sacred sites, and other culturally important practices. 

Goal 3: Include clear standards, regulatory approaches, and legal or financial 

mechanisms that might be needed throughout the life of the CO2 sequestration 

project (and beyond). A successful regulatory framework will include all requirements that 

must be complied with over the entire lifetime of a project (e.g., health and safety standards; 

operations; monitoring, reporting, and verification; financial assurance; long-term stewardship; 

and enforcement). For example, the current SDWA UIC framework includes requirements for 

site characterization, well construction, operation, closure, and post-closure monitoring, but 

does not address long-term stewardship of sequestration sites, or address liability after the 

post-injection site care period. Currently, liability would remain with the owner/operator of the 

injection well only through the operating life of the facility and the specified post-closure 

period. To change that situation, the SDWA UIC statute would need to be revised. Liability 

issues are discussed in more detail in Section IV.C of the report. 

Goal 4: Promote national consistency, yet addresses existing differences in 

authorities between the onshore and offshore, and clearly articulate the role of 

States. SDWA’s UIC Program regulates the underground injection of fluids into the subsurface 

onshore and the sub-seabed of State territorial waters to prevent endangerment of USDWs. 

Under the SDWA UIC Program, State and Tribal UIC programs have primary enforcement 

responsibility (or primacy) once their UIC programs have been approved by EPA. Technical 

capacity to operate the program will vary from State to State, along with how regulatory 

requirements are implemented. To facilitate deployment of well-managed CCS projects 

throughout the United States, minimum Federal standards will be important. It is important to 

note that EPA will not approve primacy applications from States that are unable to achieve 

minimum Federal standards as required under the SDWA § 1422. National consistency is also 

important to ensure that CO2 emissions reductions associated with geologic sequestration of 

CO2 can be included in future climate programs. 

While the Federal Government does have authority for regulating CCS offshore, further clarity 

in statutory authority would ensure that it can provide the kind of comprehensive management 

113 References to “States” in this section also include Tribal governments. 

Report of the Interagency Task Force on Carbon Capture and Storage 104 
described in this report. Under ideal circumstances, a unified framework for the regulation of 

offshore sequestration would be established under new legislation. An international agreement, 

the 1996 London Protocol to the 1972 Convention on the Prevention of Marine Pollution by 

Dumping of Wastes and Other Matter (also known as the London Protocol), addresses 

offshore carbon sequestration in the sub-seabed. Two guidance documents were developed by 

the Parties to the London Convention and Protocol, the international body established to 

address prevention of marine pollution by dumping of wastes and other matter (i.e., ocean 

dumping of materials). The two documents together are intended to provide guidance in 

evaluating applications for sequestration of CO2 into sub-seabed geological formations (and not 

in the water column), and the other restrictions applicable under the London Protocol. The 

Specific Guidelines include sections addressing, among other things, the conduct of a waste 

prevention audit, consideration of waste management options, consideration of the chemical 

and physical properties of the CO2 stream, site selection and characterization, assessment of 

potential effects, monitoring and risk management, the issuance of permits, and the 

development of permit conditions. 

The United States has signed and has been working toward ratification of the London Protocol 

for several years, and the London Protocol is on the Administration’s Treaty Priority List for 

the 111th Congress. Senate advice and consent on ratification will require amending the 

language in the Marine Pollution, Research, and Sanctuaries Act (MPRSA) to address differences 

between the London Convention and the London Protocol. Conforming statutory amendments 

were proposed to the last Congress but would require re-submission to this Congress. The 

Administration is currently developing a revised MPRSA amendment package, and, will likely 

address amendments to the OCSLA either in this package or in a separate package, to submit 

to Congress. Such amendments would result in a comprehensive statutory framework for the 

leasing and regulation of sub-seabed sequestration facilities on the OCS. The Task Force 

recommends that the Administration commit to working toward a comprehensive framework 

for CCS that addresses a broad range of issues and applies the necessary environmental 

protections for offshore sequestration in a manner similar to the regulation of onshore 

sequestration. 

Goal 5: Include strong compliance and enforcement mechanisms. A successful legal 

and regulatory framework will include compliance and enforcement mechanisms that cover all 

aspects of CCS. It may be necessary to expand and clarify areas of SDWA to ensure that the 

broader scope of CCS activities and their environmental impacts are covered. 

The Federal government currently has authority under SDWA to collect information, conduct 

inspections, monitor compliance, and take civil or criminal action related to the protection of 

VI. Options for Enhancing the Legal/Regulatory Framework 105 
 

underground sources of drinking water.114 The United States may also respond to an imminent 

and substantial threat to a source of drinking water, and take an enforcement action to remedy 

the situation.115,116 Absent a specific regulatory or permit requirement, SDWA allows Federal 

information gathering and inspection under the SDWA UIC Program, by regulation, and only 

for regulatory development or determination of individual well owner or operator compliance 

with UIC program requirements. Adequate compliance and enforcement of all aspects of CCS 

may require the utilization of other environmental statutes and possibly the strengthening of 

some SDWA provisions. 

Because SDWA is focused on the protection of drinking water sources, it may require 

clarification to support actions to address or remedy ecological or non-drinking water human 

health impacts arising from the injection and sequestration of CO2. 

The injection and sequestration of CO2 will require access and authority to monitor the 

migration of CO2 over long distances in large geologic formations beyond the property of the 

UIC well owner or area of review of the UIC permit. The UIC well owner/operator will need 

to install monitoring wells in an extended area, and State and Federal officials will need access 

to gather information for enforcement purposes. SDWA could be clarified to provide for 

extended access to property for monitoring and enforcement purposes and authority to 

request CCS-related information that may not required by UIC regulations. 

CO2 sequestration on a national scale may present opportunities for fraudulent conduct. It will 

be important to enhance SDWA’s civil and criminal enforcement authorities (including, e.g., to 

provide significant sanctions for making false statements) to deter such behavior and ensure 

that a national CCS program meets its critical environmental goals. Methods to provide the 

capability to verify quantities of CO2 captured, transferred and stored, and to document 

transfers of CO2 through this system should be designed. Participation in such a monitoring, 

reporting and verification system should be mandatory for all recipients of CCS-related Federal 

funding, and the regime should be robust enough to detect and quantify CO2 loss at every 

phase of capture, transport and storage. The accuracy of the data in this system should be 

verified through signed reports, certified by a responsible corporate official, to ensure there is a 

remedy in the event of an incorrect or fraudulent report. A market-wide CCS system is likely 

to require a robust accounting system of this type to ensure system integrity. 

114 Section 300j-4(a)-(b), 42 U.S.C. § 1445(a)-(b); 40 C.F.R. §§ 144.17 and 144.27; section § 300h-2, 42 U.S.C. § 

1423. 

115 Section 300i, 42 U.S.C. § 1431. 

116 The Federal government may exercise these compliance assurance and enforcement authorities in primacy 

States. Primacy States must also demonstrate that their programs are at least as stringent as Federal minimum 

requirements, which include specified compliance assurance and enforcement authority. 40 C.F.R. Part 145. 

Report of the Interagency Task Force on Carbon Capture and Storage 106 
 

 

While other Federal statutes such as the CAA, RCRA, and CERCLA may provide stronger 

compliance and enforcement mechanisms where they are applicable, again, significant efforts by 

implementing agencies would be needed in order to address all possible impacts from CCS, 

appropriately balance environmental and safety objectives, reduce redundancy, and streamline 

regulatory requirements across those regulatory programs. 

Finally, SDWA authorities could be expanded to allow EPA to serve as trustee or beneficiary of 

any financial instrument used to establish financial assurance under the UIC Program. 

Goal 6: Create flexibility to account for site variability and is adaptive to 

accommodate learning. Various stakeholders have been advocating a CCS regulatory 

framework flexible enough to accommodate a wide range of technologies and geologies, and 

that can adapt as knowledge and experience are gained as the industry matures (CCS 

Regulatory Project, 2009b). These goals have been taken into account by EPA in the proposed 

Class VI rulemaking, which is largely performance-based, allows for site variability, provides for 

regularly updated plans, and includes requirements that must be updated as new information is 

collected. The anticipated framework will allow for a diversity of projects to be developed 

across the country and offshore, and reduce compliance costs while maintaining safe and 

effective projects. These goals have also been taken into account by EPA in the CAA GHG 

reporting proposal for CO2 sequestration facilities by allowing such facilities to develop sitespecific monitoring, reporting, and verification plans. 

Goal 7: Build knowledge and public confidence by making information available and 

creating opportunities for public engagement. Public acceptance of CCS has been 

recognized as critical to its widespread deployment. The general public and local communities 

will seek access to information, involvement in decision-making processes, and assurance that 

projects are well-sited and well-managed. The SDWA UIC Program takes and requires primacy 

States to have actions by rulemaking (which has formal public participation elements), features 

Part 124 requirements for permitting (including appeal to the Environmental Appeals Board), 117 

and allows citizens to bring suit challenging UIC program actions.118 The public and affected 

States will be notified of and have the ability to comment on CO2 sequestration projects via the 

NEPA and other regulatory programs as applicable. EPA’s CAA GHG reporting proposal for 

CO2 sequestration would also provide public information on the amount of CO2 injected and 

stored in the United States. 

Goal 8: Be designed to meet international obligations as appropriate. To ensure that 

the United States meets its international obligations and adheres to international law, the 

regulatory framework could consider agreements and treaties that may apply. For example, the 

117 40 C.F.R. Part 124. 

118 Section 300j-8, 42 U.S.C. §1449. 

VI. Options for Enhancing the Legal/Regulatory Framework 107 
United States is required to submit an annual Inventory of Greenhouse Gas Emissions and Sinks 

under the United Nations Framework Convention on Climate Change, which includes 

reporting of CCS. The United States is also party to the Convention on the Prevention of 

Marine Pollution by Dumping of Wastes and Other Matter (referred to as the London 

Convention or LC). The 1996 London Protocol (LP) to the LC (Protocol) strengthens and 

updates the LC. The United States is not yet a Party to the Protocol, but has signed it. As a 

signatory, the United States must refrain from acts that would defeat the object and purpose of 

the Protocol, but is not bound by the terms of the Protocol itself. In 2006, the Protocol was 

amended by placing “carbon dioxide streams from carbon dioxide capture processes for 

sequestration” on the exclusive list of substances that may be considered for dumping under 

certain conditions. The effect of the amendment was to provide for sub-seabed sequestration 

of CO2 under the LP subject to controls, including the issuance of a permit. Transboundary 

issues, such as tracking/regulating CO2 plume movement across national boundaries, could also 

be considered. 

Report of the Interagency Task Force on Carbon Capture and Storage 108 
 

 

VII. Approaches for Legal or Regulatory Structures to Deal 

with Potential Liabilities 

As discussed in Section IV.C, many stakeholders have identified long-term liabilities associated 

with CO2 sequestration as a potential barrier to CCS deployment. These potential long-term 

liabilities could be addressed using seven different general approaches: (1) reliance on existing 

legal and regulatory framework; (2) substantive or procedural limitations on claims; (3) Federal 

legislation facilitating private insurance coverage; (4) establishment of a liability fund; (5) 

government ownership or direct government liability; (6) governmental indemnification: and (7) 

transfer of long-term risk to the Federal government after site closure. These approaches, 

discussed in more detail below, are not mutually exclusive and can be combined in various 

hybrid formats.119 

The purpose of the Task Force’s analysis was not to recommend a specific approach for dealing 

with potential liabilities, but rather to evaluate the advantages and disadvantages of various 

approaches and recommend removal of certain options from consideration. 

VII.A Existing Legal and Regulatory Framework 

As discussed in Section IV.C.1.1, there already exist Federal and State laws governing CCS 

activities. In particular, several States have adopted legislation that provides for transfer of longterm liability to the State by various mechanisms. One option would be to not seek additional 

legal authority, and to proceed on the basis of this existing body of law. 

A key question is whether, assuming liability concerns will in fact impair adoption of CCS 

technology, there are ways to address those concerns under this existing legal framework, or 

whether Congressional action would be required to address those concerns. The existing 

Federal framework largely does not provide for a release or transfer of liability from the 

owner/operator to other persons, although some States are experimenting with alternative 

approaches for addressing concerns about long-term liability under existing law. One 

mechanism involves States agreeing to take on the long-term liability by undertaking the CCS 

project themselves, by assuming liability from CCS operators, or by providing a mechanism for 

transfer of liability. At least six States, and possibly more, have already adopted various forms of 

legislation that would achieve this result. 

Another option would involve designing CCS operations so that the Federal government 

acquires the CO2 at the time of injection and sequestration facilities are Federally-owned, with 

the goal of preventing private parties from incurring risks of long-term liabilities. It appears, 

119 The discussion that follows reflects information and analysis contained in a number of preexisting reports, 

including EPA (2008); Wilson et al. (2008), Wilson, et al. (2007); and the IOGCC (2007). 

VII. Approaches for Legal or Regulatory Structures to Deal with Potential Liabilities 109 
however, that private entities that contribute CO2 to such a reservoir still would have potential 

liabilities, as would any private contractors involved in the facility’s operations, and that there 

are not mechanisms available under existing law to address those liabilities. Thus, this 

mechanism would probably not suffice to address all liability concerns those entities might have. 

Appendix KAppendix provides a discussion of liability arrangements under existing DOE CCS 

programs. Under the FutureGen program, Illinois law provides for the State to accept liability. 

DOE has declined to accept liability under two other programs, the CCPI and the RCSP. 

Instead, liability under these two programs is presumably governed by State law and existing 

Federal law where applicable. This supports the view that State law may provide a possible basis 

for proceeding, at least in the short term. 

The Task Force’s preliminary assessment is that the existing mechanisms could be adequate to 

facilitate at least an initial group of five to ten commercial-scale operations. A group of States 

has already adopted legislation to address long-term liability from CCS operations; see Section 

IV.C.1.1. If additional States adopt similar legislation, that could suffice to provide the basis for 

early movers, including the five to ten commercial-scale projects planned by 2016. The Task 

Force would need to confirm that the State legislation in question adequately addresses 

potential sources of liability, including, for example, CERCLA. Nonetheless, under an approach 

that relies on the States to address long-term liability, the Task Force would emphasize that the 

Federal government will need to maintain a very active oversight role over the initial group of 

CCS facilities, and should not cede the oversight function to the States. 

There are also reasons that economy-wide deployment (beyond the initial group of early 

movers) could require Federal legislation. If there are different liability regimes at the State 

level, the group of participating States may be narrow, and that may constrain the settings in 

which CCS can be deployed. Additionally, the number of participating States may be limited by 

the suitability of geologic formations; i.e., only some States or regions will be suitable for the 

commercial-scale development of CO2 sequestration. Some States will be reluctant to adopt 

legislation on long-term liability, or may face fiscal constraints that prevent them from enacting 

effective legislative programs. If many States are in this category, CCS deployment may be 

geographically limited as a result. Moreover, circumstances that could give rise to the existence 

of long-term liabilities include inadequate oversight of siting of geologic sequestration locations, 

inadequate regulation of CCS activities, and/or operator error. Widespread cost-effective 

deployment of CCS has the potential to strain regulatory capacity, which in turn heightens 

these concerns. That suggests the need for an additional legal framework designed both to 

prevent liability from arising and to ensure that harms can be addressed in the event they do 

occur. Proper design of the initial five to ten projects may help to test these premises and 

develop information on appropriate regulatory approaches that might be included in such a 

framework. 

Report of the Interagency Task Force on Carbon Capture and Storage 110 
 

 

Advantages: This approach avoids the need to seek new legal authority or Congressional action. 

Because the timing and scope of Congressional action cannot be predicted, this is a significant 

advantage. States could implement frameworks specific to their region and unique 

circumstances, which could encourage development of best practices. The lengthy process of 

creating a new regulatory framework could be avoided, which might allow demonstration 

projects to be implemented more quickly. 

Disadvantages: Inconsistent State approaches to regulation could impede CCS projects that 

cross State lines. Potential parties could be discouraged from investing in projects if they 

perceive a barrier related to balance-sheet recognition of the cost of potential liabilities or the 

insurability of risks. Limitations in State resources and regulatory capacity may limit their ability 

to approve and oversee CCS activities, which may in turn constrain adoption of CCS. 

VII.B Substantive or Procedural Limitations on Claims 

Another approach to addressing long-term liability concerns would be to adopt substantive or 

procedural limitations on claims. These might include, for example, providing for removal of 

actions to Federal courts; establishing a uniform Federal standard of liability; and limiting or 

barring punitive damages.120 Some commentators have proposed reliance on liability caps, at 

least for an initial group of projects (Jacobs and Stump, 2010). The Task Force assumes that any 

limitations on claims would principally address private claims against the entity; ongoing 

obligations imposed by the government, such as the obligation to monitor the site and respond 

to any problems that might develop, would not be appropriately limited in this way. 

Advantages: Establishing uniform Federal standards may help to ease uncertainties from the 

business community and insurers over the extent of potential liabilities and address uncertain 

or inconsistent State standards. Federal liability standards could facilitate projects that cross 

State lines. 

Disadvantages: Severe limitations on remedies could raise potential legal or constitutional 

concerns, depending on how they were drafted. They could also raise federalism issues, to the 

extent that the effect would be to displace State law. By contrast, more modest limitations on 

remedies may not suffice to reassure stakeholders who are concerned about long-term liability. 

Also, if remedies are limited, the result may be that harms to individuals and their property 

120 There are a number of examples of statutes that modify or limit State remedies in various ways. For example, 

the Price-Anderson Act requires removal of claims to Federal court, 42 U.S.C. § 2210(n)(2) and 42 U.S.C. § 

2014(hh), and bars punitive damages. Federal law contains a similar provision allowing removal of MTBE-related 

tort claims to Federal court. A Federal law imposes a range of limitations on the application State law to businesses 

selling qualified anti-terrorism products, including prohibiting punitive damages, capping damages at the level of 

(mandatory) insurance coverage, and prohibiting imposition of joint and several liability. 6 C.F.R.25.7 (2010). And 

CERCLA contains a provision establishing a uniform Federal period for accrual of statutes of limitations for State 

tort claims relating to hazardous waste sites. 42 U.S.C. § 9658. 

VII. Approaches for Legal or Regulatory Structures to Deal with Potential Liabilities 111 
 

 

associated with CCS activities go uncompensated, unless some other compensation mechanism 

is established. In addition, limitations on claims could raise moral hazard concerns. 

VII.C Federal Legislation Facilitating Private Insurance Coverage 

A third approach involves legislation that facilitates private insurance coverage of long-term 

liabilities. (The Task Force does not analyze the approach of establishing a pooled liability fund 

in this section; that option is instead discussed in the section that follows. The present 

discussion focuses only on approaches that rely on existing insurance companies and their 

capital.) The Task Force notes that the availability of private insurance is an important 

consideration, since insurance often is required by lenders and thus is a prerequisite to the 

availability of private financing for the construction of necessary facilities. 

One approach for facilitating private insurance coverage would be to require owners or 

operators to purchase such insurance, thereby creating a pool of insured entities and a stream 

of premiums that may in turn allow insurers to provide coverage. That approach is reflected in 

the Price-Anderson Act, which mandates that the owners/operators of nuclear reactors obtain 

private insurance at prescribed levels. Additional information regarding the Price-Anderson 

private insurance approach is presented in Appendix I. 

The Task Force anticipates that private insurance will be available and utilized up to the postclosure phase. Our understanding is that insurers are prepared to issue policies for CCS 

activities for that period.121 However, preliminary discussions with insurers have indicated a 

reluctance to issue policies in the present to cover long-term (post-closure) CCS-related risks. 

Insurers state that they have difficulty valuing those risks because of their novelty that they are 

not institutionally suited to issuing policies where risks may not accrue for centuries or even 

longer, and that such policies would be highly unusual for their business.122 

It is not clear whether government action could address these concerns, especially the second 

one, and induce insurers to issue long-term insurance policies to cover post-closure risk. 

Potential government actions might include: (1) mandating the purchase of insurance coverage; 

(2) requiring insurance only for a defined level of exposure (up to a specified dollar limit; liability 

might be capped at the insurance company limit or additional risks could be addressed through 

some other mechanism); and (3) allowing shorter-term policies and the periodic re-rating of 

insurance company risks. These three elements are all features of the existing hybrid insurance 

arrangements established for nuclear power facilities under the Price-Anderson Act. The 

operation of those arrangements is set forth in detail in Appendix I. 

121 Insurers state that they may not currently be willing to issue policies covering the replacement cost of CO2 lost 

from a CCS storage reservoir, however, due to the uncertainty as to the future per-tonne replacement cost. 

122 Communication from representative of Zurich Financial Services. 

Report of the Interagency Task Force on Carbon Capture and Storage 112 
 

 

The Task Force recommends soliciting further input from the insurance industry to explore 

whether there are circumstances under which private insurers would issue insurance policies to 

cover long-term risks of CO2 sequestration. As part of this analysis, the government would also 

need to make an independent determination as to whether the insurers in question can provide 

the necessary capital over the relevant time scale (which may, again, be measured in centuries). 

There are considerable uncertainties as to how insurers would be able to address this issue. 

Because of these uncertainties, and the statements of insurers that they will not issue this type 

of coverage, the Task Force does not provide a listing of advantages and disadvantages for this 

option. 

VII.D Liability Fund 

Many commentators and experts have proposed establishment of some form of liability fund 

(see, e.g., CCS Regulatory Project, 2009a; Jacobs et al., 2010). Such a fund would be a substitute 

for private insurance, in which the government takes on the function of pooling risks and 

evaluating claims. Examples of existing, similar funds include the Superfund,123 the Oil Spill 

Liability Trust Fund,124 and the National Flood Insurance Act of 1968.125 The pooled industry 

insurance established by the Price-Anderson Act, under which the nuclear reactor industry is 

required (after a facility’s mandatory commercial insurance policy is exhausted) to contribute to 

insurance to cover the costs of a cleanup in the event of an incident, also has some similarities 

to such an arrangement. It provides a pooling approach that is funded after an incident, rather 

than beforehand. 

The fund could be administered either by the government or by a private entity (presumably 

with extensive governmental oversight), and could be supported through a fee on the 

underlying activity. The precise structure of the fee would depend on how the underlying 

activity was defined; it might take the form of a fee on each tonne of CO2 sequestered, or of a 

123 CERCLA, 42 U.S.C. 9601-9675, creates a fund for use in cleaning up contaminated sites. Monies for the fund 

originally derived from taxes on related industries and activities, and from recoveries of costs obtained from 

defined responsible parties. 

124 The Oil Spill Liability Trust Fund (OSLT) compensates parties for recovery and mitigation expenses in excess of 

the responsible party’s limit on liability. There have been criticisms of the operation of this fund, however. See 

(Wood, 2009). 

125 The National Flood Insurance Act of 1968, as amended at 42 U.S.C. § 4001-4129, provides for the 

establishment of a government-administered fund supported by premiums paid by policyholders. Claims are paid 

out of the fund and the intent of the legislation is not to finance the fund from the U.S. Treasury. Unfortunately, 

for a number of reasons, the Fund has had to borrow from the U.S. Treasury in order to subsidize some policies 

and to replenish the Fund. See Legislative Proposals to Reform the National Flood Insurance Program: Hearing Before the 

Subcomm. on Housing and Community Opportunity of the H. Comm. on Financial Resources,111th Cong. (2010) 

(statement of Orice Williams Brown, Director, Financial Markets and Community Investment, United States 

Government Accountability Office). Any CCS liability fund should be designed to avoid these difficulties. 

VII. Approaches for Legal or Regulatory Structures to Deal with Potential Liabilities 113 
fee imposed more broadly on energy production or large emitters. The amount of the fee 

would be based on a risk analysis (potentially varying by site characteristics), and would be 

tailored to generate insurance coverage or fund of a size adequate to address potential claims. 

The fund should be designed to avoid moral hazard. There could be clear rules for drawing 

against the fund and safeguards against unapproved uses of fund monies. If not properly 

protected, the fund could be drained for other purposes unrelated to CCS long-term liability. 

The fund could have the ability to seek to recover its costs from responsible parties (e.g., those 

who failed to report required data or violated applicable requirements) Such authority both 

deters negligent conduct and helps to ensure that the fund is not depleted, 

Operators could be required to make payments to the fund during the operational phase of 

their sites, because this would prevent operators from defaulting on future payment of fees; 

also, future legislation creating a market for CO2 may generate a revenue stream during the 

operational phase, which would fund such payments. Transferring long-term liability away from 

the owner/operator creates the potential for moral hazard; a risk-based payment into a fund 

mitigates that moral hazard to some extent. (By contrast, payments assessed after an incident 

occurs may not have a similar incentive effect.) Appropriate funding is necessary to ensure that 

the fund is not depleted, in which case the costs for CCS liabilities could fall to the public or be 

left unaddressed. 

Advantages: A liability funding mechanism would provide a source of funding to address any 

problems developing as a result of CCS activities. The costs would be paid by the relevant 

industry in advance; this is beneficial because the responsible entity might no longer exist by the 

time a long-term liability arose. Fund monies might also be helpful for certain other purposes, 

especially those that would help prevent liability from arising. Examples could be the costs of 

emergency response or of oversight and monitoring activities by State or Federal authorities. 

Depending on how the fund is designed, each operation could be completely responsible for its 

own post-closure liabilities, which can encourage responsible project management. 

Disadvantages: A liability funding mechanism could be costly to establish and administer, and 

would impose additional costs on CCS activities. It could also be institutionally difficult to 

maintain the funding mechanism for the indeterminate period (possibly centuries). Also, a highly 

conservative approach to designing a liability fund could mean maintaining very large sums of 

money over this time period, which could have significant opportunity costs. 

VII.E Government Ownership or Direct Liability 

The fifth option involves the Federal government taking on ownership or direct liability for the 

risks of long-term CO2 sequestration from the beginning of sequestration operations (that is, 

upon injection of CO2). Government liability arguably could arise as a result of government 

planning, design, and construction of CCS facilities or government ownership of sequestration 

Report of the Interagency Task Force on Carbon Capture and Storage 114 
 

locations, equipment, or the CO2 itself, or government operation of the CCS facility and 

equipment. 

The precise analysis of governmental liability varies by legal context. As to tort claims, there are 

legal limits on Federal government liability under the Federal Tort Claims Act’s (FTCA) 

Discretionary Function Exception, 28 U.S.C. 2680(a), and the FTCA’s bar on strict liability 

claims. See United States v. Gaubert, 499 U.S. 315, 322-23, 325 (1991) (limited waiver of 

sovereign immunity contained in the FTCA does not extend to governmental activity that (1) 

did not violate a pertinent statute, regulation, or policy that prescribed a specific course of 

action and (2) was “susceptible to policy analysis” involving “social, economic, or political” 

policy considerations); Laird v. Nelms, 406 U.S. 797 (1972) (the FTCA does not permit suits 

based on theories of strict liability). 

To the extent that the Federal government operates through contractors, those contractors 

would still have tort liability, but that liability would be limited by the Government Contractor 

Defense, set forth in Boyle v. United Technologies Corp., 487 U.S. 500, 512 (1988).126 In such 

situations, a company that has dealt fairly and above-board with the United States (and was not 

allegedly negligent in a manner beyond the following of specific government instructions) has a 

defense against tort suits. But, otherwise, the company can still be liable under State tort law.127 

Nor do such contractor defenses against tort claims foreclose congressional action providing 

for compensation of affected parties or penalties or assessments under applicable 

environmental laws, such as CERCLA.128 

The legal analysis could be different under existing environmental statutes. To the extent that 

the government owns land on which sequestration occurs, this arguably could give rise to 

governmental liability by operation of law. Similarly, governmental ownership of CO2; 

ownership of pipelines or other equipment; and even governmental oversight, financing, and 

encouragement of CCS activities could be claimed to give rise to governmental liability. (The 

government might contest the claim depending on the particular facts at issue.) There is no 

discretionary function or government contractor defense available under these statutes, and 

126 Basing its ruling on the policy underpinnings of the FTCA’s Discretionary Function Exception, the Supreme 

Court decided that State tort liability cannot be imposed when “(a) the United States approved reasonably precise 

specifications; (b) the equipment conformed to those specifications; and (c) the supplier warned the United States 

about dangers in the use of the equipment known to the supplier but not to the United States.” 

127 While most circuits have ruled that the Government Contractor Defense applies to all government 

contractors, the Ninth Circuit has ruled that the defense only applies to military equipment. 

128 In high-visibility situations, such as the destruction of much of Texas City, Texas, due to an explosion of 

fertilizer bound for war-ravaged Europe in 1947 and exposure to radiation of “downwinders” in the wake of 

above-ground nuclear testing during the height of the Cold War, Congress acted with either private legislation or 

administrative programs funded by the Federal taxpayers to compensate those injured. 

VII. Approaches for Legal or Regulatory Structures to Deal with Potential Liabilities 115 
government contractors that are involved in geologic sequestration operations in any of a range 

of ways would not necessarily be immune from such liability. 

Advantages: Structuring a program so that the government is directly liable for CCS activities, 

and no private party has remaining liability, could reduce the complexity of assigning long-term 

liability. 

Disadvantages: Although this approach would add the government as a liable party, it would not 

necessarily eliminate CERCLA liability or common-law tort liability for private parties. For 

example, completely eliminating a party’s status as a CERCLA potentially responsible party 

could be difficult without statutory or regulatory changes; although there is precedent for 

making such changes, they are quite infrequent. Thus, it is not clear whether this approach will 

entirely address stakeholder concerns. Moreover, if the government takes on liability by these 

methods, as a result of its role in endorsing or promoting CCS, rather than intentionally 

undertaking certain liabilities as part of a structured program, various problems may result. 

First, there will be less opportunity to set baseline rules governing liability and cleanup. Because 

the government will already be a liable party, it might find it difficult to condition its own 

financial support on compliance with a particular regulatory regime. Second, there will be 

significantly less incentive for private parties and States to take precautions to prevent harm. 

VII.F Governmental Indemnification 

Governmental indemnification is another approach to handling the liability risks of long-term 

geologic sequestration. However, under the Anti-Deficiency Act, the United States may not 

agree to open-ended indemnification arrangements absent specific Congressional authorization. 

See 31 U.S.C. 1341(a)(1)(B). Such authorizations have rarely been granted due to their inherent 

open-ended risk to the Federal government and taxpayers. Accordingly, sound public policy and 

legislative precedent counsel that authority to indemnify be strictly limited to activities of 

absolutely vital national security interests, and then only when private insurance is unavailable 

(e.g., agreements indemnifying Department of Energy contractors for liability arising out of 

nuclear incidents; and agreements indemnifying certain Department of Defense contractors). 

See Pub. L. No. 85-804 (codified as 50 U.S.C. § 1431 et seq.); the Price-Anderson Act, 42 U.S.C. 

§ 2210; and Hercules Inc. v. United States, 516 U.S. 417, 426-29 & n.11 (1996). Additional 

information regarding the indemnification option appears in Appendix J. 

Advantages: As with several of the other options, indemnification would provide additional 

certainty to industry. 

Disadvantages: In addition to the statutory requirements discussed above, and the dangers of 

setting unnecessary precedents for providing Federal indemnification, indemnification is 

questionable as a matter of policy because it potentially severs day-to-day control of an activity 

from the associated costs and risks, and thereby blurs or reduces accountability. 

Report of the Interagency Task Force on Carbon Capture and Storage 116 
 

 

VII.G Transfer of Liability to the Federal Government after Site 

Closure and Governmental Certification 

Another approach to dealing with liabilities from long-term CO2 sequestration is to provide for 

the transfer of non-Federal entity liability to the Federal government after site closure and 

governmental certification, with private liability limited to circumstances similar to those 

prescribed for liability under Government Contractor Defense standards. The approach could 

apply to both compensatory as well as performance liabilities. A number of commentators have 

endorsed this approach, which is a variation on the option discussed above involving 

government ownership or direct liability (Jacobs et al., 2010). If an analysis indicates that risks 

will diminish significantly after a particular number of years following completion of the 

sequestration, Federal regulators may be able to certify that the CO2 is safely sequestered and 

will continue to remain so. Upon such certification, liability could be transferred to the Federal 

government or a Federal corporation. As to tort claims, liability would be limited to activities 

that are outside the Discretionary Function Exception, discussed above. As long as the United 

States did not violate any self-imposed specific obligations and its decisions were susceptible to 

policy analysis, there could be no tort liability against the United States. Under this approach, 

the former private owners/operators of the sites would no longer be potentially liable following 

certification, unless an injured party or government agency could affirmatively show that the 

former owner/operator failed to meet certain standards associated with the certification 

process. For example, if the former owner/operator failed to follow pertinent Federally 

mandated specifications or withheld adverse information from the United States, liability would 

attach.129 

Advantages: As with several of the other options listed here, this approach would provide 

additional certainty to industry, something that could be very important given the arguably 

insurmountable difficulties inherent in costing private insurance for the post-closure period. 

Given the uncertainties as to whether specific private entities will still exist in the extremely 

long time periods associated with CO2 sequestration, putting the government in charge 

provides the greatest assurance that an entity will be available to perform stewardship 

responsibilities. Moreover, the requirement that CCS operators meet certain standards in 

order to qualify for a transfer of liability (and that the transfer is legally ineffective if it later is 

determined that those standards were not met) would provide an additional mechanism for 

oversight of participants in CCS activities, and lessen the moral hazard problem. 

Disadvantages: As with the other approaches restricting liability, this option could create some 

moral hazard. Moreover, unless the statute authorizing a transfer of liability expressly 

129 Industry stakeholders indicated in conversations with the Task Force that a transfer of liability would be of 

significant value in addressing concerns about long-term risks even if it included these types of limitations on the 

transfer of liability. 

VII. Approaches for Legal or Regulatory Structures to Deal with Potential Liabilities 117 
encompasses environmental laws such as CERCLA, there is no assurance that the Federal 

government’s assumption of long-term liability will provide the former owners/operators with 

the sort of immunity they would have from tort suits. Also, while some States have already 

adopted laws under which they would assume liabilities in a similar manner, as described above, 

these State laws do not exempt the owners/operators from any potential liabilities under 

Federal law. Such liability is, in theory, potentially large and open-ended, and it is very unusual 

for the United States to assume such liability that has been incurred by other entities. 

Monitoring and remediation responsibilities are generally undertaken by the private sector in 

the first instance in other contexts (such as closure of hazardous waste sites), and the private 

sector is generally thought to be able to perform these functions. 

Report of the Interagency Task Force on Carbon Capture and Storage 118 
VIII. Options for Federal Government Action on Public 

Outreach and Education 

Public outreach and education is critical to the deployment of any new technology. CCS will 

require that the Federal and State governments work to educate the general public and other 

stakeholders on the facts about CCS, including the benefits of the technology for the economy 

and as a tool to mitigate GHG emissions. Several options could be pursued to facilitate CCS 

outreach and education for communities and the general public. 

Option 1: Support social science research to better understand the elements and 

potential extent of concerns around CCS. A coordinated effort among Federal agencies, 

industry, and NGOs could be undertaken to gather information and evaluate potential key 

concerns around CCS in different areas of the United States. To inform a larger engagement 

strategy, it would be helpful to first understand how the public may perceive CCS, and how 

that perception changes from region to region. As indicated in recent literature, only a small 

percentage of the public is aware of CCS and how it may play a role as a technology to mitigate 

GHGs and climate change. Consequently, there is significant opportunity to inform the public 

debate. Research on likely concerns and successful ways to address these concerns will 

improve public outreach initiatives. 

Option 2: Develop and implement a public outreach initiative on CCS, drawing on 

lessons learned from previous projects. This initiative will be critical to both near-term 

and long-term CCS deployment. A comprehensive outreach strategy could be developed 

between the Federal government, industry, and NGOs. It could be built on the experience and 

lessons learned from CCS stakeholders, such as RCSP, and include regulatory agencies, power 

companies, oil and natural gas producing companies, and NGOs. Roles of agencies and other 

key players could be defined and coordinated through an advisory board. Materials could be 

developed and disseminated through different agency websites but also linked through a 

common portal for information. This strategy will have two components, based on two 

different audiences: 1) a broad strategy for public outreach, targeted at the general public and 

decision makers; 2) a more focused engagement with communities that are candidate for CCS 

projects. 

Broad Public Outreach 

Federal agencies should develop a coordinated strategy with NGOs, project developers, and 

other stakeholders to educate the public about CCS. Studies have shown that perceptions 

about CCS generally become more positive with additional information. Therefore, it will likely 

be more efficient to proactively initiate efforts to educate the public about CCS prior to the 

active, widespread development of CCS projects. As demonstrated in Barendrecht, 

Netherlands, once projects have been initiated and potentially negative information about CCS 

VIII. Options for Federal Government Action on Public Outreach and Education 119 
has been communicated to the public from other sources, it could be more time-intensive and 

expensive to work from a defensive position to educate people about the positive aspects of 

CCS. Federal activities to engage the general public should include direct engagement and 

interaction, rather than just providing information. 

Project Community Outreach 

Acceptance from communities where projects are planned will be critical, so community 

engagement activities warrant a specialized strategy. Engagement should follow best practices 

that have been identified by a number of studies and groups (discussed further below). 

Communities should be informed about what CCS is, why it is being pursued, benefits, risks, 

and regulations in place to ensure safe and secure sites. 

The project developer will most likely play the central role in any community outreach efforts, 

but a role may exist for the Federal government as well. Each project will require a different 

strategy and level of effort for public engagement, depending largely on a community’s past 

experiences with industry or energy projects. Project developers will lead the organizational 

team for community outreach and engagement, but where appropriate the Federal government 

can advise on best practices and lessons learned from RCSP injection projects; it can also 

provide standardized education materials. 

DOE, through its Public Outreach and Education Best Practices Manual, provides lessons learned 

from the RCSP pilot-scale and large-scale injection projects. This manual focuses on the key 

elements of a successful community engagement strategy. RCSP experience confirms that the 

development of trust between the host or project developer and local community greatly 

decreases the potential for opposition. Therefore, proactive and interactive communication 

between the host and the community will be critical to public acceptance (DOE, 2009). 

Option 3: Incorporate Principles into Regulations. Environmental laws often require or 

provide the opportunity for public comment and input into permitting processes. Federal 

regulations bearing upon CCS, or any new relevant legislation, could incorporate such 

mechanisms to ensure a formal process exists for community or stakeholder involvement. 

For example, EPA, under the proposed class VI rule for sequestration of CO2, includes public 

engagement requirements of the public notice of pending sequestration site permitting actions. 

The permitting authority would be required to provide public notice (newspaper 

advertisement, postings, mailing to interested parties) and a 30-day comment period for public 

input. The permitting agency would then be required to prepare a responsiveness summary that 

would then become public record. In addition, all Federal funded actions or projects being 

constructed through Federal lands are required to comply with NEPA, which has requirements 

for public engagement. 

Report of the Interagency Task Force on Carbon Capture and Storage 120 
Option 4: Develop Clearinghouses of High-Quality Information on CCS. Over the 

past several years, Federal agencies, the RCSP, industry, trade organizations, and others have 

developed and publicized an abundance of materials concerning CCS, including best practice 

manuals, scientific studies and journal articles, and basic educational materials. As part of the 

broader engagement strategy, the Federal government could establish a Federal clearinghouse 

online, where the public can access unbiased, high-quality information on CCS. While such 

material can currently be found across various websites from different organization, centralizing 

some of the higher-quality material could facilitate public familiarity with CCS. The website 

would follow Federal government guidelines for accessibility for broad audience. This gateway 

could also act as a gateway to other organizations that are providing similar material. 

Separately, and in order to address community concerns around planned geologic sequestration 

sites, Federal agencies could work together to develop a web-accessible “toolkit” for project 

developers and regulators. This interagency toolkit could be developed with input from DOE 

(best practices from RCSP), EPA (permitting/regulatory processes), and DOT (pipeline 

transportation and siting). The toolkit could build on the principles and tools discussed in the 

best practices from the RCSP Public Outreach and Education manual and regulations for public 

engagement. These could be used from as early as possible and throughout the development of 

the project. The toolkit could also include a broad spectrum of educational materials, from 

various regulatory agencies to educate potential neighbors of sequestration sites about CCS 

technologies, site characterization processes, risk assessment and mitigation, and the process of 

sequestration. 

Option 5: Provide support for third-party public outreach efforts. As mentioned, in 

order to maximize the chances for project success, it is necessary to plan and integrate public 

outreach efforts early in the process, and to engage stakeholders from different organizations 

on developing the consensus-based messages that may be necessary to communicate to the 

public. Working with a trustworthy messenger is an important first step since the credibility of 

the person or organization delivering the information can make a significant difference how the 

public reacts. 

The Federal government could help facilitate this through various initiatives. For example, a 

Federal department or agency could assist an interstate compact or a Federal advisory group 

that could advocate for State interests in CCS-related activities. Or the Federal government 

could work with NGOs involved in the development and dissemination of CCS-related 

information in project communities. 

Option 6: Encourage Opportunities for Early Success. Early successes with the 

deployment of new technologies are invaluable in providing evidence to the general public and 

other stakeholders that a new technology is safe, reliable, and beneficial. Real and inferred 

technical and economic risks may lead to social perception issues that could affect future 

deployments. Several successful early projects would demonstrate to the public that CCS 

VIII. Options for Federal Government Action on Public Outreach and Education 121 
technologies would be effective in mitigating GHG emissions, and could be widely and safely 

deployed after 2020. 

The Federal government could take steps to ensure that early projects maximize chances for 

successful deployment. Some of these steps are touched upon elsewhere in this report. Other 

steps could include identification and characterization of potential sequestration sites on 

Federal lands. Proactive efforts to fully characterize these sites, assess the risks, and perform 

programmatic reviews of the projects’ impacts and infrastructure requirements in the region 

could provide the information necessary to communicate with stakeholders the impacts and 

benefits of conducting CCS at these sites. 

Report of the Interagency Task Force on Carbon Capture and Storage 122 
IX. Conclusions and Recommendations 

IX.A Conclusions 

 There are no insurmountable technological, legal, institutional, or other barriers that 

prevent CCS from playing a role in reducing GHG emissions. 

 Widescale cost-effective deployment of CCS will occur only when driven by a policy 

designed to reduce GHG emissions. Ultimately, comprehensive energy and climate 

legislation will provide the largest incentive for CCS deployment as an option for climate 

change mitigation, because it will create a stable, long-term, market-based framework to 

channel private investment into low-carbon technologies. 

 Existing Federal programs are being used to deploy at least five to ten large-scale 

integrated CCS projects. These projects, expected to be online by 2016, are intended to 

demonstrate a range of current generation CCS technologies applied to coal-fired power 

plants and industrial facilities. Early CCS projects face challenges related to climate policy 

uncertainty in addition to the challenges associated with cost, performance, legal and 

regulatory uncertainty, and early project technology risks. Prior to enactment of a 

comprehensive climate policy, early climate change mitigation projects such as these will 

rely on other incentives. 

 RD&D can enable deployment of CCS by helping to reduce project uncertainty and 

improve technology cost and performance. The focus of RD&D is twofold: 

o	 Demonstrate the operation of current CCS technologies integrated at an 

appropriate scale to prove safe and reliable capture and storage. 

o	 Develop improved CO2 capture component technologies and advanced power 

generation technologies to significantly reduce the cost of CCS, to facilitate 

widespread cost-effective deployment after 2020. 

 Increased Federal coordination would enhance the government’s ability to assist these 

projects by providing more efficient incentives and/or addressing barriers. 

 CCS projects are proceeding under existing laws. Developing and clarifying regulatory 

requirements for CCS would reduce uncertainty for early projects and ensure safe and 

effective deployment. Additional Federal actions to enhance regulatory authority, address 

long-term liability, and strengthen stewardship frameworks could enable wider 

deployment. Some of these actions would require additional legislative authority. 

 Open-ended Federal indemnification should not be used to address long-term liabilities 

associated with CO2 storage. 

 International collaboration complements domestic efforts on CCS and facilitates its 

global deployment. 

IX. Conclusions and Recommendations 123 
 

 Public awareness and support are critical to the development of new energy technologies 

and are widely viewed as vital for CCS projects. 

IX.B Recommendations 

IX.B.1 Early Projects 

Establish a Federal Agency Roundtable and Technical Committee to Facilitate Early Projects. 

To ensure the success of early projects, including five to ten commercial CCS demonstrations 

by 2016, DOE and EPA should create a Federal agency roundtable to act as a single point of 

contact for project developers seeking assistance to overcome financial, technical, regulatory, 

and social barriers facing planned or existing projects. As needed, this roundtable should 

provide technical support to permitting authorities and permit applicants. 

DOE and EPA should create a technical committee composed of experts from the power and 

industrial sectors, NGOs, State officials, and academia. This group could provide input on a 

range of CCS technical, economic, and policy issues. 

Increase Coordination in Applying Drivers and Incentives to Enhance the Government's Ability to Assist 

Early Projects. 

To ensure the success of five to ten commercial demonstration projects by 2016, DOE, in 

coordination with EPA, Treasury, and USDA, should track the use and efficacy of Federal 

financial support for CCS projects. Increased coordination will: 

 enhance the government's ability to tailor Federal funding and assistance to each 

project’s market context (such as whether the project involves publicly owned utilities, 

independent power producers, or competitive industrial sources); 

 improve the clarity and transparency of eligibility criteria for projects to receive Federal 

support; and 

 enable the Administration to allocate resources efficiently and more effectively consult 

with Congress and the States on the efficacy of existing incentives. 

DOE should determine if early projects will sufficiently demonstrate an adequate breadth of 

capture technologies and classes of storage reservoirs to enable widespread cost-effective CCS 

deployment. This assessment will allow the Administration to target any remaining technology 

gaps in a manner consistent with addressing market failures. 

Report of the Interagency Task Force on Carbon Capture and Storage 124 
 

 

Ensure that Relevant Agencies Work Quickly and Collaboratively to Propose, Finalize, and Implement 

the Regulatory Framework to Ensure Safe and Effective CCS Deployment. 

Federal agencies should work together to design requirements for CCS using existing 

authorities in complementary ways. 

 By late 2010, EPA should simultaneously: 

o	 finalize rulemakings for geologic sequestration wells under SDWA and GHG 

reporting for CO2 storage facilities under CAA; 

o	 propose RCRA applicability rule for CO2 that is captured from an emission 

source for purposes of sequestration; and 

o	 develop guidance to support implementation of these rules. 

 By late 2011, EPA should finalize the RCRA applicability rule. 

 EPA, USDA, and DOI should immediately formalize coordination and prepare a strategy 

to develop regulatory frameworks for onshore and offshore Federal lands. 

Federal agencies should work together to enhance regulatory and technical capacity for safe 

and effective CCS deployment. Specifically, 

 EPA, in coordination with DOE and DOI, should develop capacity-building programs for 

UIC regulators. Educating permit writers and other key officials will greatly enhance their 

capability and efficiency in issuing and enforcing technically sound permits. These 

programs should leverage existing efforts such as the DOE RCSPs. 

 Federal agencies should begin to develop NEPA analyses related to CCS as early as 

possible to help ensure timely completion of environmental reviews. Where appropriate 

to Federal agency decision-making, agencies should consider development of 

Programmatic Environmental Impact Statements for use in tiered NEPA analysis and 

initiate this process. CEQ should consider development of CCS-specific NEPA guidance. 

 DOE and EPA should identify data needs and tools to support regulatory development, 

permitting, and project development. 

 EPA and DOE should study methods to monitor and account for CO2 as it moves from 

capture, through a pipeline or other transportation system, to a storage facility. Because 

system design is likely to be time-consuming, Federal agencies should begin to put in 

place the basic architecture of such a system. 

IX. Conclusions and Recommendations 125 
Enhance and Coordinate Public Outreach to Raise Awareness of CCS. 

DOE, DOI, and EPA should: 

 Coordinate among Federal agencies, States, industry, and NGOs to gather information 

and evaluate potential key concerns around CCS in different areas of the United States. 

 Develop a comprehensive outreach strategy between the Federal government, industry, 

and NGOs. This strategy will have two components: a broad strategy for public 

outreach, targeted at the general public and decision makers, and a more focused 

engagement with communities that are candidates for CCS projects. 

 Immediately establish a clearinghouse for public access to unbiased, high-quality 

information on CCS. 

 Develop outreach tools for project developers and regulators with input from DOE 

(best practices from RCSPs), EPA (permitting/regulatory processes), DOT (pipeline 

transport), and DOI (Federal lands). 

IX.B.2 Wider Deployment 

Address Key Market Drivers. 

Congress should enact comprehensive energy and climate legislation. The Administration 

should apply the key principles in this report and lessons learned from early projects to 

evaluate whether further drivers and incentives are needed to enable widescale deployment of 

advanced CCS technologies as a potential climate change mitigation option. 

Enhance Regulatory and Long-term Liability and Stewardship Framework. 

Congress should consider whether changes to statutory authorities to facilitate regulatory 

development and implementation are necessary. Revisions to SDWA could provide 

enforcement and compliance assurance and financial assurance authorities necessary to support 

wider CCS deployment. Ratification of the London Protocol (LP) and associated amendment of 

the Marine Protection, Research, and Sanctuaries Act (MPRSA) as well as amendment of the 

Outer Continental Shelf Lands Act (OCSLA) will ensure a comprehensive statutory framework 

for the storage of CO2 on the outer continental shelf. 

DOE and EPA, in consultation with other agencies, should track regulatory implementation and 

consider whether additional statutory revisions are needed. These actions will enable the 

Administration to more effectively consult with Congress and the States on the efficacy of the 

existing framework. 

By late 2011, EPA, in coordination with DOE, DOJ, and Treasury, should further evaluate and 

provide further recommendations to address long-term liability and stewardship in the context 

Report of the Interagency Task Force on Carbon Capture and Storage 126 
of existing and planned regulatory frameworks. Of the seven options identified by the Task 

Force, the following four approaches should be considered (noting that a recommendation may 

include a hybrid of these or other approaches): 

 Reliance on the existing framework for long-term liability and stewardship. 

 Adoption of substantive or procedural limitations on claims. 

 Creation of a fund to support long-term stewardship activities and compensate parties 

for various types and forms of losses or damages that occur after site closure. 

 Transfer of liability to the Federal government after site closure (with certain 

contingencies). 

Promote International Cooperation 

DOE, EPA, State Department, and other interested agencies and stakeholders should continue, 

and where appropriate enhance, engagement in international collaborative efforts on CCS. 

These activities assist in global penetration of CCS technologies, leverage U.S. funding, and 

increase access to international expertise and experiences. In addition, international 

cooperation on CCS could potentially open markets to U.S. companies, while demonstrating 

U.S. leadership. 

IX. Conclusions and Recommendations 127 

X. List of Acronyms 

ACES American Clean Energy and Security Act of 2009 

AEP American Electric Power 

API American Petroleum Institute 

ARRA American Reinvestment and Recovery Act 

ASME American Society of Mechanical Engineers 

ASU Air separation unit 

BLM Bureau of Land Management 

BOEM Bureau of Ocean Energy Management, Regulation, and Enforcement 

CAA Clean Air Act 

CCPI Clean Coal Power Initiative 

CCS Carbon capture and storage 

CERCLA Comprehensive Environmental Response, Compensation and Liability Act 

C.F.R. Code of Federal Regulations 

CO Carbon monoxide 

CO2 Carbon dioxide 

CO2e Carbon dioxide equivalent 

COE Cost of electricity 

CZMA Coastal Zone Management Act 

DOE U.S. Department of Energy 

DOI U.S. Department of the Interior 

DOT U.S. Department of Transportation 

EIA Energy Information Administration 

EIS Environmental impact statement 

EOR Enhanced oil recovery 

EPA U.S. Environmental Protection Agency 

EPCRA Emergency Planning and Community Right-To-Know Act 

FERC Federal Energy Regulatory Commission 

FLPMA Federal Land Policy and Management Act 

FTCA Federal Tort Claims Act 

GHG Greenhouse gas 

GW Gigawatts 

H2 Hydrogen 

ICCS Industrial Carbon Capture and Storage 

IEA International Energy Agency 

IGCC Integrated gasification combined cycle 

ILI Inline inspection 

INGAA Interstate Natural Gas Association of America 

IPCC Intergovernmental Panel On Climate Change 

X. List of Acronyms 129 
LC London Convention 

LGP DOE Loan Guarantee Program 

LP London Protocol 

MEA Monoethanolamine 

MIT Massachusetts Institute of Technology 

MLA Mineral Leasing Act 

MPRSA Marine Protection, Research, and Sanctuaries Act 

MVA Monitoring, verification, and accounting 

MW Megawatt 

MWe Megawatt electrical 

N2 Nitrogen 

NEMS National Energy Modeling System 

NEPA National Environmental Policy Act 

NETL National Energy Technology Laboratory 

NGCC Natural gas combined cycle 

NGO Non-governmental organization 

NHPA National Historic Preservation Act 

NOx Nitrogen oxides 

NRAP National Risk Assessment Partnership 

O2 Oxygen 

OCS Outer Continental Shelf 

OCSLA Outer Continental Shelf Lands Act 

PC Pulverized coal 

PEIS Programmatic environmental impact statement 

PM Particulate matter 

PHMSA Pipeline and Hazardous Materials Safety Administration 

R&E Research and experimentation 

RCRA Resource Conservation and Recovery Act 

RCSP Regional Carbon Sequestration Partnerships 

RD&D Research, development, and demonstration 

RUS Rural Utilities Service 

SCADA Supervisory control and data acquisition 

SDWA Safe Drinking Water Act 

SOx Sulfur oxides 

UIC Underground Injection Control 

U.S.C. United States Code 

USDW Underground source of drinking water 

USFS U.S. Forest Service 

USGS U.S. Geological Survey 

WGS Water-gas shift 

Report of the Interagency Task Force on Carbon Capture and Storage 130 
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Appendices to the Report of the 

Interagency Task Force on Carbon 

Capture and Storage 
 

Appendix A. CO2 Capture – State of Technology 

Development: Supplementary Material 

Approximately 70-90 percent of the cost of CCS is associated with capture. This appendix 

presents a brief history of CO2 capture technology, the current state of technology 

development, and planned large-scale demonstration projects. It is an expanded version of the 

CO2 capture section in the main body of the report. 

A.1 CO2 Capture History 

Although CO2 capture is new to coal-based power generation, removal of CO2 from industrial 

gas streams is not a new process. The history of removal of CO2 from industrial gas streams is 

depicted in Figure A-1. 

Figure A-1. Previous Experience with Removal of CO2 from Gas Streams 

1930 1940 1950 1960 1970 1980 1990 2000

Natural Gas Purification 

Food & Chemical Grade CO2 

Gasifiers 

Coal-Fired Boilers 

Hydrogen 

Ammonia 

Hydrocarbon Refining 

Chemical Synthesis 

Dehydration 

Gas Processing 

Air Separation 

Nitrogen 

Enhanced Oil Recovery 

Air Separation 

Chemical Plants 

Carbon Dioxide 

Natural Gas Processing 

Enhanced Oil Recovery 

Time 

Technology Enablers 

1. Comparatively small volumes 

200 to 4,000 Tonnes/day CO2 

2. High value products 

3. Specialized operating 

environments 

GAS ABSORPTION 

Physical Solvents 

GAS ABSORPTION 

Chemical Solvents 

GAS ADSORPTION 

GAS SEPARATION 

MEMBRANES 

Gas absorption processes using chemical solvents, such as amines, to separate CO2 from other 

gases have been in use since the 1930s in the natural gas industry and to produce food and 

chemical grade CO2. Chemical solvents are used to separate CO2 from gas streams containing 

three to 25 percent CO2. In the 1940s, physical solvents were developed to absorb CO2 from 

gas streams with higher CO2 concentration (25 to 70 percent) and higher pressure 

(approximately 1,500 Psia), such as those encountered in high-pressure natural gas processing. 

In the 1950s and 1960s, gas adsorption processes were developed to remove CO2 from gas 

streams. In the 1970s and 1980s, gas separation membranes were developed (Kohl and Nielsen, 

1997). 

The licensing history of the Econamine FG process (one of a handful of commercially available 

amine-based chemical solvent CO2 separation processes) provides a good example of past 

applications of CO2 removal technologies (Chapel et al., 1999). Prior to 1999, 25 capture 

Appendix A. CO2 Capture – State of Technology Development: Supplementary Material A-1 
   

   

   

   

       

   

           

     

         

   

   

         

       

   

   

   

   

   

     

   

facilities were built that captured CO2 quantities ranging from 635 to 365,000 tonnes/year using 

the Econamine FG process (Table A-1). 

Table A-1. CO2 Capture Plants Built Prior to 1999 Using the Econamine Process 

Capture Rate

Owner Location Fuel (tonnes per CO2 Use

year)

Carbon Dioxide Technology Lubbock, TX Natural Gas 331,000 EOR

Northeast Energy Associates Bellingham, MA Natural Gas 106,000 Food Industry

Luzhou Natural Gas Sechuan, China Natural Gas 53,000 Urea Plant Feed

Sumitomo Chem/Nippon Oxygen Chiba, Japan Heavy Fuel Oil 53,000 Food Industry

Indo Gulf Fertilizer Uttar Predesh, India Natural Gas 50,000 Urea Plant Feed

Prosint Rio de Janeiro, Brazil Natural Gas 30,000 Food Industry

N‐Ren Southwest Carlsbad, NM Natural Gas 30,000 EOR

Messer Greisheim do Brazil Sao Paulo, Brazil Natural Gas 26,000 Food Industry

Liquid Air Australia Altona, Australia Natural Gas 20,000 Food Industry

Liquid Air Australia Botany, Australia Natural Gas 20,000 Food Industry

Messer Greisheim do Brazil Sao Paulo, Brazil NR 16,000 Food Industry

San Miguel Corp. San Fernando, Philippines NR 15,000 Food Industry

European Drinks Sudrigiu, Romania NR 12,000 Food Industry

Cervezaria Baveria Barranquilla, Colombia NR 8,000 Food Industry

Paca Israel NR 8,000 Food Industry

Industrial de Gaseoses Quito, Ecuador NR 2,000 Food Industry

Pepsi Cola Manila, Philippines NR 2,000 Food Industry

Pepsi Cola Quezon City, Philippines NR 2,000 Food Industry

Cosmos Bottling San Fernando, Philippines NR 2,000 Food Industry

Coca Cola Cairo, Egypt NR 2,000 Food Industry

Azucar Liquida Santo Domingo, Dom. Rep. NR 2,000 Food Industry

Tokyo Electric Power Yokosuka, Japan Coal 1,600 Pilot Plant

Boundary Dam Power Plant Saskatchewan, Canada Coal 1,000 Pilot Plant

Kansei Electric Power Osaka, Japan Natural Gas 635 Pilot Plant

Sundance Generating Alberta, Canada Coal 635 Pilot Plant

NR ‐ Not Reported

The ten largest facilities captured more than 20,000 tonnes of CO2/year. Nine of these large 

facilities captured CO2 from flue gas generated by the combustion of natural gas. The one 

exception used flue gas generated by firing a variety of fuels, including heavy fuel oil. The 

process was also used for pilot-scale testing of three coal-fired applications capturing 635 to 

1,600 tonnes/year. The captured CO2 from these facilities was used for enhanced oil recovery 

(EOR), urea production, and in the food and beverage industry. The capture rates for these 

facilities reflect the fact that they were built to serve a specific commercial market for CO2. 

Other amine-based processes (e.g., ABB/Lummus) were implemented at similar capture rates 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A-2 
during this time period. By comparison, a single 550-MW net output coal-fired power plant 

capturing 90 percent of the emitted CO2 will need to separate approximately five million 

tonnes per year of CO2. This large difference in capacity represents a significant barrier to 

widespread commercial deployment of CO2 removal technologies for coal-fired power plants 

(DOE, 2010a). 

A 2009 review of commercially available CO2 capture technologies identified 17 facilities (using 

both chemical and physical capture solvents) in current operation (Table A-2) (Dooley et al., 

2009). These facilities include four natural gas processing operations and a syngas production 

facility in which approximately 1 million tonnes of CO2 are captured per year. The largest (the 

Shute Creek natural gas processing plant in Wyoming) captures 3.6 million tonnes per year, 

which approaches the volume required for capture at electric generating plants. However, the 

degree to which experience with natural gas processing is transferrable to separation of power 

plant flue gases is unclear, given the significant differences in the chemical make-up of the two 

gas streams. In addition, integration of these technologies with the power cycle at generating 

plants presents significant cost and operating issues that must be addressed in order to facilitate 

widespread, cost-effective deployment of CO2 capture. CO2 Capture in Coal-Fired Power 

Generation 

In general, CO2 capture technologies applicable to coal-fired power generation can be 

categorized into three approaches: pre-, post-, and oxy-combustion (IPCC, 2005; DOE, 2007). 

Pre-combustion systems are designed to separate CO2 and hydrogen (H2) in the high-pressure 

syngas produced at IGCC power plants. Post-combustion systems are designed to separate 

CO2 from the flue gas—primarily nitrogen (N2)—produced by fossil-fuel combustion in air. This 

is the technology type that would be applicable to most of the existing coal-fired power plants 

in the United States. Oxy-combustion uses high-purity oxygen (O2) rather than air to combust 

coal and therefore produces a highly concentrated CO2 stream. 

Application of any of these approaches results in an increase in the cost of electricity and in a 

decrease in electricity output, or an energy penalty (Rubin, 2008). The energy penalty occurs as 

a result of the diversion of some of the energy produced by the plant (in the form of both 

steam and electricity) in order to operate the CO2 capture process. Thus the diversion of 

energy represents a loss in revenue as well as a loss of electrical power that must be 

recuperated by some other means. 

Appendix A. CO2 Capture – State of Technology Development: Supplementary Material A-3 
   

       

       

       

       

       

     

     

   

     

     

   

   

   

   

       

           

       

       

         

             

       

         

         

         

Table A-2. Summary of CO2 Capture Facilities Operating in 2009 

CO2 Source/Project Name Location

Capture Rate

(tonnes per

year)

Capture

Technology CO2 End Use

Post‐Combustion Capture from Pulverized Coal‐fired Electric Power Plants

AES Warrior Run Power Plant Cumberland, MD 109,000 Amine Food/beverage

AES Shady Point Power Plant Panama, OK 66,000 Amine Food/beverage

Searles Valley Minerals Trona, CA 270,000 Amine Soda Ash Production

AEP Mountaineer Power Plant New Haven, WV 100,000 Ammonia Geologic Storage

CO2 Capture from Coal Gasification

Great Plains Synfuels Plant Beulah, ND 1,800,000 Rectisol EOR

CO2 Capture from Oxygen‐fired Coal Combustion

Vattenfall Schwarze Pumpe Plant Germany 68,000 Compression Various Industrial

Post‐Combustion Capture from Natural Gas‐fired Facilities

Sumitomo Chemicals Plant Japan 54,000 Amine Food/beverage

Prosint Methanol Production Plant Brazil 27,000 Amine Food/beverage

CO2 Capture from Natural Gas Reforming

Indian Farmers Fertilizier Co. India 544,000 Amine Manufacturing

Petronas Fertilizer Malaysia 50,000 NR Urea Production

Ruwais Fertilizer Industries UAE 131,000 Amine NR

Luzhou Natural Gas Chemicals China 50,000 Amine Urea Production

CO2 Capture from Natural Gas Production

Snohvit LNG Project Norway 635,000 Amine Geologic Storage

Sleipner West Field Norway 900,000 Amine Geologic Storage

In Salah Natural Gas Production Algeria 1,090,000 Amine Geologic Storage

Shute Creek Natural Gas Processing La Barge, WY 3,630,000 Selexol EOR

Val Verde Natural Gas Plants Terrell/Pecos, TX 1,270,000 NR EOR

DTE Turtle Lake Gas Processing Otsego, MI 181,000 Amine EOR/Geologic Storage

NR ‐ Not Reported

A.1.1 Pre-Combustion CO2 Capture 

Pre-combustion capture is applicable mainly to gasification (Integrated Gasification Combined 

Cycle) plants, where fuel is converted into gaseous components by applying heat under 

pressure in the presence of steam and limited O2, as shown in Figure A-2. 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A-4 
Figure A-2. Pre-Combustion CO2 Capture for an IGCC Power Plant 

By carefully controlling the amount of O2, only a portion of the fuel burns to provide the heat 

necessary to decompose the fuel and produce syngas, a mixture of H2 and carbon monoxide 

(CO), along with minor amounts of other gaseous constituents. To enable pre-combustion 

capture, the syngas is further processed in a water-gas shift (WGS) reactor, which converts CO 

into CO2 while producing additional H2. A physical solvent removal system, such as SelexolTM, 

can then be used to separate the CO2 from the H2. Because CO2 is present at much higher 

concentrations in syngas (after WGS) than in flue gas, and because the syngas is at higher 

pressure, CO2 capture is less expensive for pre-combustion capture than for post-combustion 

capture. After CO2 removal, the H2 can be used as a fuel in a combustion turbine combined 

cycle to generate electricity (Rubin, 2008; Hamilton, 2009; DOE, 2010a). The advantages of this 

type of system compared with post-combustion capture (described below) are the higher CO2 

concentration (partial pressure) and the lower volume of syngas to be handled, which result in 

smaller equipment sizes and lower capital costs. 

The current state-of-the-art CO2 capture technologies that could be applied to IGCC systems 

include the glycol-based, two-stage SelexolTM process, the methanol-based Rectisol® process, 

the pyrolidone-based Purisol process, and the polypropylene carbonate-based Fluor solvent 

(IEA, 2008). All employ physical solvents that preferentially absorb CO2 from the syngas 

mixture. However, these systems have not yet been built for full-scale IGCC power plants. 

Using the two-stage SelexolTM process as an example (Figure A-3), in the first stage, untreated 

syngas enters the first of two absorbers where H2S is preferentially removed using CO2-rich 

solvent from the CO2 absorber. The gas exiting the H2S absorber passes through the second 

absorber, where CO2 is removed using both semi-lean and lean solvent streams. The treated 

syngas exits the absorber and is sent to the combustion turbine. The CO2-rich solvent exits the 

CO2 absorber, and a portion is sent to the H2S absorber, while the remainder is sent to a 

series of flash drums for regeneration. The CO2 product stream is obtained from the flash 

Appendix A. CO2 Capture – State of Technology Development: Supplementary Material A-5 
drums, and the semi-lean solvent is returned to the CO2 absorber. The H2S/CO2-rich solvent 

exiting the H2S absorber is sent to the acid gas stripper, where the absorbed gases are released 

using a steam heated reboiler. The acid gas from the stripper is sent to a Claus plant to 

produce elemental sulfur for commercial use, and the lean solvent exiting the stripper is 

returned to the CO2 absorber (UOP, 2009). 

Figure A-3. Schematic Diagram of the Pre-Combustion SelexolTM CO2 Capture 

Process 

The advantage of physical solvents is that less energy is required in the solvent regeneration 

step, which involves a temperature increase and/or pressure reduction, leading to an energy 

penalty of about 20 percent (versus 30 percent energy penalty for chemical solvents used for 

post-combustion CO2 capture). Furthermore, although the cost of electricity (COE) for a base 

IGCC power plant is higher than that for a coal-fired plant, the high thermodynamic driving 

force for CO2 capture and reduced CO2 compression demands at IGCC facilities leads to an 

increase in COE of less than 40 percent using SelexolTM technology, compared with nearly 80 

percent for a conventional coal-fired power plant equipped with an amine scrubber for CO2 

control (as described below) (DOE, 2010a). 

A.1.2 Post-Combustion CO2 Capture 

Post-combustion CO2 capture refers to removal of CO2 from combustion flue gas prior to 

discharge to the atmosphere, as shown in Figure A-4 (Herzog, 2009). In a typical coal-fired 

power plant, fuel is burned with air in a boiler to produce steam that drives a turbine/generator 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A-6 
 

to produce electricity (Bohm, 2006). Flue gas from the boiler consists mostly of N2 and CO2. 

Separating CO2 from this flue gas is challenging for several reasons: 

•	 a high volume of gas must be treated 

o	 about 2 million cubic feet per minute for a 500 MWe size plant 

•	 CO2 is dilute requiring chemical solvents for extraction 

o	 12 to 14 volume percent in coal-fired systems 

o	 6 to 8 volume percent in gas-fired turbines 

•	 flue gas is at low pressure 

o	 15 to 25 pounds per square inch absolute [psia] 

•	 flue gas contains trace impurities that can degrade the CO2 capture materials (e.g., 

solvent); 

o	 particulate matter [PM] 

o	 sulfur oxides [SOx] 

o	 nitrogen oxides [NOx], etc. 

Figure A-4. Post-Combustion CO2 Capture for a Pulverized Coal Power Plant 

PC Boiler 

Flue Gas 

Volume % 

CO2 12-14% 

N2 ~65% 

H2O ~18% 

O2 ~2% 

15 Psi/150oF 

Sulfur 

Removal 

Particulate 

Removal 

Ash 

STEAM 

CYCLE 

CO2 Capture 

Process 

Air 

Power 

CO2 

Compression 

Flue Gas 

CO2 To Storage 

Low Pressure Steam 

Optional Bypass 

Coal 

Post-combustion CO2 capture offers the greatest near-term potential for reducing power 

sector CO2 emissions because it can be retrofitted to existing plants and can be tuned for 

various levels of CO2 capture (optional bypass shown in Figure A-4), which may accelerate 

market acceptance. Although post-combustion capture technologies would typically be applied 

to conventional coal-fired power plants, they can also be applied to the combustion flue gas 

from IGCC power plants, natural gas combined cycle (NGCC) power plants, and industrial 

Appendix A. CO2 Capture – State of Technology Development: Supplementary Material A-7 
facilities that combust fossil fuels. Currently, several solvent-based capture processes are 

commercially available, but they have not yet been demonstrated at the scale necessary to help 

achieve GHG reduction targets. Many projects are in the planning stages for demonstration 

scale-up including, the Alstom chilled ammonia process and several amine-based processes (e.g., 

Fluor [Econamine], ABB/Lummus, Mitsubishi Heavy Industries [MHI], HTC Purenergy, Aker 

Clean Carbon, Cansolv, et al.) (Herzog et al., 2009). In addition, a wide variety of processes are 

at varying stages of development employing solvents, sorbents, and membranes (EPRI, 2008; 

Ciferno et al., 2009). 

As noted above, amine scrubbing represents a post-combustion capture technology that is 

currently available, but they have not yet been demonstrated at the scale necessary to help 

achieve GHG reduction targets. Amines chemically react with CO2 via reversible reactions to 

form water-soluble compounds. Despite the low CO2 partial pressure in combustion flue gas, 

amines are capable of achieving high levels of CO2 capture due to fast kinetics and strong 

chemical reactions. However, the absorption capacity for commercially available amines is 

chemically limited, requiring two molecules of amine for each molecule of CO2. In addition, 

usable amine solution concentrations are typically limited by viscosity and corrosion. Therefore, 

current amine systems are only between 20 and 30 percent amine with the remaining being 

water. Although the water present in the solution helps control the solvent temperature during 

absorption, which is an exothermic reaction, the water also requires significant amounts of 

sensible heating and stripping energy upon CO2 regeneration. Not every amine system is the 

same, and various vendors offer different designs. In general, depending on the amount of heat 

integration, anywhere from 1,550 to greater than 3,000 British thermal units (Btu) per pound of 

CO2 in the form of low pressure steam (approximately 45 psia) is required to regenerate the 

solvent to produce a concentrated CO2 stream at a pressure of approximately 25 psia (Herzog, 

2009). 

An amine-based post-combustion capture process is depicted in Figure A-5. 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A-8 
Figure A-5. Schematic Diagram of Amine-based CO2 Capture Process 

After conventional air pollutant cleanup (SOx, NOx, PM), the combustion flue gas enters an 

absorber reactor and flows counter-currently to a CO2-lean solvent where CO2 is absorbed 

into, and chemically reacts with the amine solution. The treated flue gas (mostly N2) is 

discharged to the atmosphere, and the CO2-rich amine solution is pumped to a solvent 

regeneration column where the CO2-rich solution is heated in order to reverse the chemical 

reactions between the CO2 and amine solvent. Steam extracted from the turbine cycle, 

provides the heat for regeneration of the amine solvent in the solvent regeneration column. 

Consequently, CO2 is released, producing a concentrated stream that exits the regeneration 

column and is then cooled and dehumidified in preparation for compression, transport, and 

storage. From the solvent regeneration column, the CO2-lean solution is cooled and returned 

to the absorber for reuse (Herzog, 2009). 

Installing the current state-of-the-art amine post-combustion CO2 capture technology on new 

conventional subcritical (SubC), supercritical (SC), and ultra-supercritical (USC) coal-fired 

power plants would increase the levelized cost of electricity (LCOE) by about 80 percent. 

Further, the large quantity of energy required to regenerate the amine solvent and compress 

the CO2 to pipeline conditions would result in about a 30 percent energy penalty (DOE, 

2010a). 

Appendix A. CO2 Capture – State of Technology Development: Supplementary Material A-9 
A.1.3 Oxy-Combustion 

Oxy-combustion systems for CO2 capture rely on combusting coal with relatively pure oxygen 

diluted with recycled CO2 or CO2/steam mixtures, as shown in Figure A-6 (Herzog, 2009). The 

primary products of combustion are water and CO2, with the CO2 separated by condensing the 

water and removing any other gas constituents that infiltrated the combustion system. 

Figure A-6. Pulverized Coal Power Plant with Oxy-Combustion CO2 Capture 

Oxy-combustion overcomes the technical challenge of low CO2 partial pressure normally 

encountered in conventional coal combustion flue gas by producing a highly concentrated CO2 

stream (~60 percent), which is separated from water vapor by condensing the water through 

cooling and compression. An additional purification stage for the highly concentrated CO2 flue 

gas may be necessary to produce a CO2 stream that meets transportation and storage 

requirements. This purification step should have significantly less cost than a conventional postcombustion capture system, due to the high CO2 concentration and reduced flue gas volume 

(Herzog, 2009). 

However, the appeal of oxy-combustion is tempered by a few key challenges, namely the capital 

cost and energy consumption for a cryogenic air separation unit (ASU), boiler air infiltration 

that dilutes the flue gas with N2, and excess O2 contained in the concentrated CO2 stream. Flue 

gas recycle (~70 to 80 percent) is also necessary to approximate the combustion characteristics 

of air, since currently available boiler materials cannot withstand the high temperatures 

resulting from coal combustion in pure O2. Consequently, the economic benefit of oxycombustion compared to amine-based scrubbing systems is limited. Construction of a new 

supercritical oxy-combustion coal-fired power plant equipped with a commercially available 

cryogenic ASU would increase the COE by about 60 percent and have a 25 percent energy 

penalty compared with a new supercritical air-fired, coal-based power plant without CO2 

capture (DOE, 2010a; DOE, 2010b). 

A.1.3.1 Chemical Looping Combustion 

Chemical looping combustion (CLC) is an advanced coal oxy-combustion technology that 

involves the use of a metal oxide or other compound as an O2 carrier to transfer O2 from the 

combustion air to the fuel, avoiding direct contact between fuel and combustion air (Figure 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A-10 
A-7). Subsequently, the products from combustion (CO2 and H2O) will be kept separate from 

the rest of the flue gases. Chemical looping splits combustion into separate oxidation and 

reduction reactions. In one potential configuration, chemical looping is carried out in two 

fluidized beds. The metal oxide (e.g., iron, nickel, copper, or manganese) releases the O2 in a 

reducing atmosphere and the O2 reacts with the fuel. The metal is then recycled back to the 

oxidation chamber where the metal oxide is regenerated by contact with air. The advantage of 

using the CLC process is that no separate ASU is required and CO2 separation takes place 

during combustion (NETL, 2009a). 

Figure A-7. Chemical Looping Combustion 

Air 

Air 

(Oxidizing) 

Reactor 

MxOy 

N2, O2 

MxOy-1 

Fuel 

CO2, H2O 

Fuel 

(Reducing) 

Reactor 

N2, O2 CnHm

Depleted Air Combustion Products 

A related area of research is chemical looping gasification (CLG). In this system, two or three 

solid particle loops are used to provide the O2 for gasification and to capture CO2. A loop, 

similar to that of CLC, is used to gasify the coal and produce syngas (H2 and CO). A second 

solid loop is used in a WGS reactor. In this reactor, steam reacts with CO and converts it to 

H2 and CO2. The circulating solid absorbs the CO2, thereby providing a greater driving force 

for the WGS reaction. The CO2 is then released in a calcination step that produces nearly pure 

CO2 for further compression and storage. 

A.2 Technical Challenges to CO2 Capture for Coal-Based Power 

Generation 

As discussed above, in their current state of development, CO2 removal technologies are not 

ready for implementation on coal-based power plants for three primary reasons: 

1) they have not been demonstrated at the larger scale necessary for power plant 

application, 

2) the energy penalty associated with CO2 capture would significantly decrease power 

generating capacity, and 

Appendix A. CO2 Capture – State of Technology Development: Supplementary Material A-11 
                     

                           

             

                       

                         

                   

                       

                       

                           

                         

                           

                         

                

                       

                           

                         

                         

         

                               

                             

                           

                           

         

                         

                             

3) if successfully scaled up, they would not be cost effective at their current level of 

process development (Kuuskraa, 2007). 

Other technical challenges associated with the application of these CO2 capture technologies to 

coal-based power plants include high capture and compression auxiliary power loads, capture 

process energy integration with existing power system, impacts of flue gas contaminants (NOx, 

SOx, PM) on CO2 capture system, increased water consumption and cost effective O2 supply 

for oxy-combustion systems (Table A-3). The following is a brief summary of a few of the more 

significant technical challenges. 

Table A-3. Key Technical Challenges for CO2 Capture 

Parameter Technical Challenge

Scale‐Up While industrial‐scale CO2 separation processes are now commercially available, they have not

been deployed at the scale required for large power plant applications and consequently, their

use could significantly increase electricity production costs.

Cost‐

Effectiveness

Recent studies conducted by NETL show that current technologies are expensive and energy‐

intensive, which seriously degrade the overall efficiency of both new and existing coal‐fired

power plants. For example, installing the current state‐of‐the‐art post‐combustion CO2 capture

technology – chemical absorption with an aqueous monoethanolamine (MEA) solution – is

estimated to increase the levelized COE by about 75 to 80 percent.

Auxiliary

Power

A significant amount of auxiliary power is required to operate currently available CO2 capture

technologies. The auxiliary power decreases the net electrical generation of the power plant.

Energy

Efficiency

The large quantity of energy required to regenerate the solvent in commercially available CO2

capture technologies (~1,550 to 3,000 British thermal units [Btu] per pound of CO2 removed)

would significantly reduce the total power plant output.

Energy

Integration

The energy required to regenerate the solvent in commercially available CO2 capture

technologies would be provided by steam extraction from the power plant. This activity requires

careful integration of the power plant steam cycle to the CO2 capture technology.

Flue Gas

Contaminants

Constituents in the flue gas, particularly sulfur, can contaminate CO2 capture technologies,

leading to increased operational expenses.

Water Use

CO2

Compression

A significant amount of water use is required for CO2 capture and compression cooling.

To enable storage, significant power is required to compress the captured CO2 to typical pipeline

levels (1,500 to 2,200 psia depending on storage scheme and location). Reducing this power

requirement is essential to improving overall plant efficiency and facilitating CO2 storage at both

existing and future power plants.

Oxygen Supply An oxy‐combustion power plant requires a supply of high‐purity oxygen. Currently available

technology – cryogenic air separation unit (ASU) – is not considered to be cost effective.

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A-12 
       

     

A.2.1 CO2 Capture Impacts on Water Use 

CO2 capture typically results in the consumption of large quantities of water due to the cooling 

water requirements of capture and compression (Ciferno et al., 2010). As part of recent 

DOE/NETL studies, subcritical PC, supercritical PC, oxy-combustion, and IGCC configurations, 

both with and without capture, were evaluated for a variety of factors including water 

withdrawal (water removed from a surface or groundwater source) and consumption (water 

not returned to the source) (DOE, 2010a; DOE, 2010b). The evaluations indicate that there 

will be a significant increase in overall water use by the PC plants, with a more modest increase 

for IGCC plants, as shown in Figure A-8. A subsequent study has evaluated five different 

scenarios for future freshwater withdrawal and consumption requirements for the U.S. 

thermoelectric generation sector using the Annual Energy Outlook (AEO) 2009 projections for 

capacity additions and retirements (EIA, 2009). Results from this study indicate that the addition 

of CCS will increase water withdrawal by five to seven percent by 2030, but consumption will 

increase by 88 to 100 percent over the same time period (DOE, 2009; DOE/NETL, 2009) 

Figure A-8. Relative Water Use for New PC and IGCC Plants With and Without 

CO2 Capture 

0

200

400

600

800

1000

1200

1400

Subcritical

PC

Subcritical

PC w/CO2

Capture

Supercritical

PC

Supercritical

PC w/CO2

Capture

Oxy‐

Combustion

w/CO2

Capture

IGCC IGCC w/CO2

Capture

Water(gal/MWhr)

Withdrawal

Consumption

Source: (DOE/NETL, 2009) 

A.2.2 CO2 Capture Impacts on Cost and Performance 

As indicated above, technologies exist that will allow for the capture of CO2 generated during 

the production of electricity. However, there are significant costs and energy penalties 

associated with the application of those technologies in their current state of development. 

Analyses indicate that for a nominal 550 MWe net output power plant, addition of CO2 capture 

Appendix A. CO2 Capture – State of Technology Development: Supplementary Material A-13 
     

   

     

technology increases the capital cost of a new IGCC facility by $400 million and results in an 

energy penalty of 20 percent. For post-combustion and oxy-combustion capture, the increases 

in capital costs are $900 million and $700 million respectively, and the energy penalty would be 

30 and 25 percent. For a natural gas combined cycle (NGCC) plant, the capital cost would 

increase by $340 million and an energy penalty of 15 percent would result from the inclusion of 

CO2 capture. The costs associated with CO2 capture in terms of increases in the LCOE or cost 

per tonne of CO2 avoided are shown in Figure A-9. The LCOE ranges from $116/MWh to 

$151/MWh, depending upon the type of facility and whether the application is for a new plant 

or a retrofit of an existing plant. This compares to an LCOE of $85/MWh for a new 

supercritical PC plant and a $27/MWh LCOE for the existing fleet of power plants. In terms of 

costs per tonne of CO2 avoided, values range from $60/tonne to $114/tonne. 

Figure A-9. Comparison of Levelized Cost of Electricity for Different Types and 

Configurations of Power Plants 

New IGCC New Post‐ New Oxy‐ New NGCC Retrofit Post‐

Combustion Combustion Combustion

Source: (DOE, 2010a; DOE, 2010b) 

A.3 Cost Estimating Methodology 

A summary of the costing assumptions behind the levelized cost of electricity (LCOE) 

calculation referred to throughout the Task Force CCS report is contained here. A fully 

documented methodology can be found in DOE (2010a) and DOE (2010b). 

Capital Costs 

0

20

40

60

80

100

120

140

160

110

85 85

77

27

150 151

140

121

116

60

95

68

114

103

LCOE w/o CCS, $/MWh

LCOE w/CCS, $/MWh

Avoided Cost, $/tonne CO2

LCOE, $/MWh

Avoided Cost, $/tonne CO2

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A-14 
       

   

               

                 

             

                 

                 

     

                     

         

                   

     

         

           

       

                       

                   

     

   

   

   

               

                       

                 

                 

                 

All capital costs are presented as “overnight costs” expressed in December 2009 dollars. 

Capital costs are presented at the total plant cost (TPC) level. TPC includes: 

 equipment (complete with initial chemical and catalyst loadings), 

 materials, 

 labor (direct and indirect), 

 engineering and construction management, and 

 contingencies (process and project). 

Owner’s Costs 

Owner’s costs were subsequently calculated and added to the TPC. The result is defined as 

total overnight cost (TOC) and is the capital expenditure used in the calculation of LCOE. The 

owner’s costs included in the TOC cost estimate are shown in Table A-4. 

Table A-4. Owner’s Costs Included in TOC 

Owner’s Cost Comprised of

Preproduction Costs

• 6 months O&M, and administrative & support labor

• 1 month maintenance materials @ 100% Capacity Factor (CF)

• 1 month non‐fuel consumables @ 100% CF

• 1 month of waste disposal costs @ 100% CF

• 25% of one month’s fuel cost @ 100% CF

• 2% of TPC

Inventory Capital • 60 day supply of fuel and consumables @100% CF

• 0.5% of TPC (spare parts)

Land • $3,000/acre (300 acres for greenfield IGCC and PC, and 100

acres for NGCC)

Financing Costs • 2.7% of TPC

Other Owner’s Costs • 15% of TPC

Initial Cost for Catalyst

and Chemicals • All initial fills not included in bare erected cost (BEC)

Prepaid Royalties • Not included in owner’s costs (included with BEC)

Allowance for Funds

Used During

Construction (AFUDC)

and Escalation

• Varies based on levelization period and financing scenario

• 33‐yr IOU high risk: Total As‐Spent Capital Cost (TASC) = TOC *

1.078

• 33‐yr IOU low risk: TASC = TOC * 1.075

• 35‐yr IOU high risk: TASC = TOC * 1.140

• 35‐yr IOU low risk: TASC = TOC * 1.134

The category labeled “Other Owner’s Costs” includes the following: 

 preliminary feasibility studies, including a Front-End Engineering Design (FEED) study; 

Appendix A. CO2 Capture – State of Technology Development: Supplementary Material A-15 
 

 economic development (costs for incentivizing local collaboration and support); 

 construction and/or improvement of roads and/or railroad spurs outside of site 

boundary; 

 legal fees; 

 permitting costs; 

 owner’s engineering (staff paid by owner to give third-party advice and to help the owner 

oversee/evaluate the work of the EPC contractor and other contractors); and 

 owner’s contingency: sometimes called “management reserve”, these are funds to cover 

costs relating to delayed startup, fluctuations in equipment costs, unplanned labor 

incentives in excess of those for a 5 day, 10 hours per day work schedule. 

Cost items excluded from “Other Owner’s Costs” include: 

 EPC Risk Premiums, 

 transmission interconnection, 

 taxes on capital costs, and 

 unusual site improvements. 

Operations and Maintenance 

The production costs or operating costs and related maintenance expenses (O&M) pertain to 

those charges associated with operating and maintaining the power plants over their expected 

life. These costs include: 

 operating labor, 

 maintenance – material and labor, 

 administrative and support labor, 

 consumables, 

 fuel, 

 waste disposal, and 

 co-product or by-product credit (that is, a negative cost for any by-products sold). 

Thirty-Year, Current-Dollar LCOE 

The revenue requirement method of performing an economic analysis of a prospective power 

plant has been widely used in the electric utility industry. This method permits the 

incorporation of the various dissimilar components for a potential new plant into a single value 

that can be compared to various alternatives. The revenue requirement figure-of-merit is a 

current-dollar, 30-year LCOE. The effective levelization period is the sum of the operational 

levelization period (30 years for all plants) and the capital expenditure levelization period 

(assumed to be 3 years for NGCC plants and 5 years for IGCC and PC plants). The sum results 

in an effective levelization period of 33 years for the NGCC cases and 35 years for the IGCC 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A-16 
 

and PC cases. The LCOE is expressed in mills/kWh (numerically equivalent to $/MWh). The 

current-dollar, 30-year LCOE was calculated using a simplified equation derived from the NETL 

PSFM (Power Systems Financial Model Version 5.0, 2006). 

The equation used to calculate LCOE is as follows: 

(CCFP)(TOC) + (LF)[(OCF1) + (OCF2) + ...] + (CF)(LF)[(OCV1) + 

(OCV2) + ...] LCOEP = 

(CF)(MWh) 

where: 

LCOEP = levelized cost of electricity over P years, $/MWh 

P = levelization period (e.g., 10, 20 or 30 years) 

CCFP = capital charge factor for a levelization period of P years 

TOC = total overnight cost, $ 

LF = levelization factor (a single levelization factor is used in each case because a single 

escalation rate is used for all costs) 

OCFn = category n fixed operating cost for the initial year of operation (but expressed in 

“first-year-of-construction” year dollars) 

CF = plant capacity factor 

OCVn = category n variable operating cost at 100 percent CF for the initial year of 

operation (but expressed in “first-year-of-construction” year dollars) 

MWh = annual net megawatt-hours of power generated at 100 percent CF 

All costs are expressed in December 2009 year dollars, and the resulting LCOE is expressed in 

mixed year dollars. 

Although their useful life is usually well in excess of 30 years, 33-year (NGCC) and 35-year 

(IGCC and PC) levelization periods (including the variable capital expenditure levelization 

periods as defined above) are the levelization periods used in this study. 

The technologies modeled in this study were divided into one of two categories for calculating 

LCOE: Investor Owned Utility (IOU) high risk and IOU low risk. All IGCC cases as well as PC 

and NGCC cases with CO2 capture are considered high risk. The non-capture PC and NGCC 

cases are considered low risk. The resulting CCF and LFs are shown in Table A-5. 

Appendix A. CO2 Capture – State of Technology Development: Supplementary Material A-17 
  

   

  

   

   

  

  

   

  

  

   

  

     

   

                 

         

     

       

   

           

             

     

       

       

     

             

         

         

             

           

             

         

               

     

                   

 

 

Table A-5. Economic Parameters for LCOE Calculation 

High Risk

5 year

construction

Low Risk

5 year

construction

High Risk

3 year

construction

Low Risk

3 year

construction

Capital Charge Factor 0.1773 0.1691 0.1567 0.1502

Levelization Factor 1.42689 1.45104 1.41094 1.43262

The economic assumptions used to derive the CCFs are shown in Table A-6. The difference 

between the high risk and low risk categories is manifested in the debt-to-equity ratio and the 

weighted cost of capital. The values used to generate the CCFs and LFs in this study are shown 

in Table A-7. 

Table A-6. Parameter Assumptions for Capital Charge Factors 

Parameter Value

TAXES

Income Tax Rate 38% (Effective 34% Federal, 6% State)

Capital Depreciation 20 years, 150% declining balance

Investment Tax Credit 0%

Tax Holiday 0 years

FINANCING TERMS

Repayment Term of Debt 15 years

Grace Period on Debt Repayment 0 years

Debt Reserve Fund None

TREATMENT OF CAPITAL COSTS

Capital Cost Escalation During Construction

(nominal annual rate) 3.6%1

Distribution of Total Overnight Capital over the

Capital Expenditure Period (before escalation)

3‐Year Period: 10%, 60%, 30%

5‐Year Period: 10%, 30%, 25%, 20%, 15%

Working Capital zero for all parameters

% of Total Overnight Capital that is Depreciated

100% (this assumption introduces a very

small error even if a substantial amount of

TOC is actually non‐depreciable)

INFLATION

LCOE, O&M, Fuel Escalation (nominal annual 3.0%2 COE, O&M, Fuel

1

 A nominal average annual rate of 3.6% is assumed for escalation of capital costs during construction. This rate is 

equivalent to the nominal average annual escalation rate for process plant construction costs between 1947 and 

2008 according to the Chemical Engineering Plant Cost Index. 

2

 An average annual inflation rate of 3.0% is assumed. This rate is equivalent to the average annual escalation rate 

between 1947 and 2008 for the U.S. Department of Labor's Producer Price Index for Finished Goods, the socalled "headline" index of the various Producer Price Indices. (The Producer Price Index for the Electric Power 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A-18 
               

       

               

   

   

     

   

   

 

Parameter Value

rate)

Escalation rates must be the same for LCOE

approximation to be valid

Table A-7. Financial Structure for Investor Owned Utility High and Low Risk 

Projects 

Type of Security % of Total

Current

(Nominal) Dollar

Cost

Weighted

Current

(Nominal) Cost

After Tax

Weighted Cost of

Capital

Low Risk

Debt 50 4.5% 2.25%

Equity 50 12% 6%

Total 8.25% 7.39%

High Risk

Debt 45 5.5% 2.475%

Equity 55 12% 6.6%

Total 9.075% 8.13%

A.4 Planned Demonstrations of CO2 Capture Technologies 

DOE/NETL is currently engaged in two major CCS demonstration programs. 

The Clean Coal Power Initiative (CCPI) is an innovative technology demonstration program 

that fosters more efficient clean coal technologies for use in new and existing coal-based power 

plants. The intent of CCPI is to accelerate technology adoption and thus rapidly move 

promising new concepts to a point where private-sector decisions on deployment can be made. 

CCPI is currently pursuing three pre-combustion and three post-combustion CO2 capture 

demonstration projects (Table A-8). The pre-combustion projects involve CO2 capture from 

IGCC power plants. The generating capacities at the demonstration facilities range from 257 to 

582 MW. The capture efficiencies range from 67 percent to 90 percent, and total CO2 captured 

ranges from 1.8 to 2.7 million tonnes per year. The demonstrations will be initiated between 

2014 and 2016, and the projects will run for 2-3 years. The post-combustion projects will 

capture CO2 from pulverized coal (PC) plant slipstreams representing the equivalent of 60 to 

235 MW of power production. Each will capture 90 percent of CO2 emissions with total 

capture of 0.4 to 1.5 million tonnes per year. 

Generation Industry may be more applicable, but that data does not provide a long-term historical perspective 

since it only dates back to December 2003.) 

Appendix A. CO2 Capture – State of Technology Development: Supplementary Material A-19 
     

         

         

         

       

       

           

   

   

           

       

     

 

Similar to the CCPI projects, the FutureGen project will demonstrate carbon capture from a 

200 MW advanced oxy-combustion unit in Meredosia, Illinois, integrated with CO2 storage in 

Mattoon, Illinois. FutureGen aims to capture and store at least one million tonnes of CO2 per 

year. 

Table A-8 Capture Projects Being Conducted as part of CCPI and Future Gen 

Performer Location Capture

Technology

Capture Rate

tonnes/year

Start

Date

Pre‐Combustion Capture

Summit Texas Clean

Energy Odessa, TX Selexol 2,700,000 2014

Southern Company Kemper County, MS Selexol 1,800,000 2014

Hydrogen Energy

California Kern County, CA Rectisol 1,800,000 2016

Post –Combustion Capture

Basin Electric Beulah, ND Amine 450,000 ‐ 1,360,000 2014

NRG Energy Thompsons, TX Amine 400,000 2015

American Electric

Power

New Haven, WV Chilled Ammonia 1,500,000 2015

Oxy‐Combustion

FutureGen

Meredosia and

Mattoon, Il Oxy‐Combustion 1,000,000 2015

In addition to the demonstrations under the CCPI and FutureGen programs, additional CO2 

capture demonstration projects are being conducted under the Industrial Carbon Capture and 

Storage (ICCS) program (Table A-9). Several of the ICCS projects are pursuing capture 

technologies that are similar to those that are being demonstrated for power plants. These 

projects are of similar magnitude to the CCPI capture demonstrations (90 percent capture, ~1-

4 million tonnes/year captured). Eleven projects were initially selected for the ICCS program. In 

June 2010 there was a down-selection of three projects that will move forward to full 

demonstrations. These include the Leucadia Energy Lake Charles project, the Archer Daniels 

Midland project, and the Air Products project. 

Table A-9. Projects Selected Under the Industrial Carbon Capture and Storage 

Initiative 

Performer

Leucadia Energy

Charles

Lake

Location

Lake Charles, LA

Capture

Technology

Rectisol

Product

Methanol

Capture Rate

Tonnes/year

4,000,000

Start Date

2014

Archer Daniels Midland Decatur, IL Amine Power, Ethanol 900,000 2014

Air Products Port Arthur, TX Amine Hydrogen 900,000 2013

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A-20 
Appendix B. CO2 Pipeline Transport – State of Technology 

Development: Supplementary Material 

B.1 Existing Pipeline Networks in the United States 

There are several CO2 pipeline systems in the United States that were built largely to transport 

CO2 from natural sources to consuming oil fields for EOR. CO2 sources for these systems 

include natural deposits, natural gas processing plants, and other high-purity industrial vents. 

The longest existing pipeline system, the Cortez Pipeline, delivers CO2 over a distance of 500 

miles in the Permian basin of Texas, Colorado, and New Mexico (Parfomak and Folger, 2007). 

Other systems transport CO2 along the Gulf Coast (Mississippi and Louisiana), through 

Colorado and Wyoming, from North Dakota into Canada, and in Northern Michigan. In 

addition, there are many smaller CO2 pipelines connecting sources with specific customers. 

Figure B-1 and Table B-1 summarize the CO2 pipelines in the United States. 

Figure B-1. Existing and Planned CO2 Pipelines in the United States with Sources 

Source: NETL using data from Energy Velocity Database (2010). 

Appendix B. CO2 Pipeline Transport – State of Technology Development: Supplementary Material B-1 
Table B-1. CO2 Pipeline Summary 

Company 

In Service 

Pipeline System 

Length (Miles) 

Proposed 

Pipeline System 

Length (Miles) 

Total Pipeline 

System Length 

(Miles) 

Number of 

State Border 

Crossings 

Anadarko 261.6 302.0 563.6 0 

Chaparral Energy 22.2 0.0 22.2 0 

ChevronTexaco 147.6 0.0 147.6 2 

Core Energy, LLC 10.3 0.0 10.3 0 

Dakota Gasification 215.6 0.0 215.6 1 (U.S. /Canada) 

Denbury Resources 202.6 599.3 801.9 3 

ExxonMobil 362.7 0.0 362.7 1 

Hess 43.4 0.0 43.4 0 

Kinder Morgan 1,108.5 0.0 1,108.5 3 

Occidental Petroleum 

Corp. 390.4 0.0 390.4 1 

Oxy Permian 293.5 0.0 293.5 1 

Penn West Petroleum 7.0 0.0 7.0 0 

Petro Source 147.1 0.0 147.1 0 

Transpetco 120.6 0.0 120.6 2 

Trinity CO2 223.5 0.0 223.5 4 

Wiser 26.7 0.0 26.7 0 

Source: NETL Generated from Energy Velocity Database, April 2010. 

B.2 Pipeline Design 

The primary design considerations for CO2 pipelines are similar to those of natural gas and 

hazardous liquid pipelines, such as operating pressure and temperature, protection from 

outside forces, and control room management using Supervisory Control and Data Acquisition 

(SCADA) systems. CO2 poses a number of specific threats that can be mitigated in the pipeline 

design stage. One major threat to the integrity of CO2 systems is the generation of carbonic 

acid from ambient moisture in the pipeline. The following are some of the design considerations 

germane to reducing integrity risks and consequence of failure: 

 CO2 composition, impurities, and phase behavior; 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage B-2 
 

 Line pipe material selection and fracture control; 

 Valve, seal, elastomer, and pumping material selection; 

 Valve spacing; and 

 Leak detection. 

Pipeline operators must follow specific requirements of the DOT Pipeline and Hazardous 

Materials Safety Administration (PHMSA) listed in its Hazardous Liquid Pipeline Safety 

Regulations (49 C.F.R. Part 195) that address many of these design considerations. Most of the 

regulations are identical for transportation of hazardous liquids and CO2, with a few notable 

differences. For example, components for CO2 pipelines must be “made of materials that are 

suitable” for low temperatures that may be associated with “rapid pressure reduction or during 

the initial fill of the line.” Also, fracture propagation must be mitigated against when designing a 

CO2 pipeline. Lastly, valve materials must be compatible with CO2. The presence of impurities 

lowers the saturation pressure of the gases which affect the susceptibility of pipeline materials 

to arrest fractures. This can be mitigated by increasing the thickness of the steel and the use of 

mechanical crack arrestors (Cosham and Eiber, 2008). These requirements, along with industry 

design standards from the American Society of Mechanical Engineers (ASME) and the American 

Petroleum Institute (API), which are incorporated into 49 C.F.R. Part 195 by reference, are in 

place to reduce pipeline risks from CO2 pipeline systems. 

B.3 Pipeline Construction 

Construction requirements and standards are virtually identical for CO2 and gas transmission 

and hazardous liquids pipelines, and are not considered a barrier to CCS deployment. One 

major goal is to avoid damage to system components during transportation or during the actual 

construction activity. These construction requirements and standards are in place to protect 

pipelines from damage and to maximize the integrity of the system over its operating lifespan. 

There are construction-related concerns that, if left unresolved, could have a negative impact 

on the long- and short-term integrity of the pipeline. Resolution can involve procedure 

revisions, additional personnel training, modification to construction practices, or physical 

repairs to the pipeline, pipeline coating, or auxiliary pipeline features. PHMSA inspections help 

to ensure that these issues are corrected prior to the pipeline being buried and operated. 

Hydrostatic pressure tests and inline inspection (ILI) tool runs are also procedures that help 

assess pipeline integrity.3 

B.4 Pipeline Operation and Safety 

There are a number of operational challenges for liquid CO2 pipelines. Maintaining the 

supercritical phase, as well as controlling impurities and moisture content, are paramount for 

the safe operation of these systems. CO2 pipelines generally operate above 2,000 pounds-force 

per square inch gauge (psig) in order to maintain the product in the liquid phase. Impurities 

directly affect the phase behavior, and if not controlled adequately can lead to pump cavitation 

3

 See http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/maop_determination.pdf. 

Appendix B. CO2 Pipeline Transport – State of Technology Development: Supplementary Material B-3 
 

and localized reduction in pressure. Excessive water in the pipeline may lead to carbonic acid 

corrosion and the formation of ice plugs, and must be strictly avoided. In addition, impurities 

directly affect the arrest of propagating fractures, and must be considered in design. 

The risk assessment during the design stage may lead to the consideration of shorter distances 

between sectionalizing (block) valves, which shut off flow on either side of a detected leak in 

the pipeline. The potential consequence of shorter spacing is the creation of more possible leak 

paths from the valves themselves. The goal of SCADA systems and tighter valve spacing is to 

detect pressure reductions from ruptures so that the volumes released are minimized. 

Monitoring of key parameters, including pressure, temperature, and flow rate, allow for timely 

intervention and smaller releases. In addition, they reduce the likelihood of ice plugs around 

valves, which could impede safety operations. 

Traditional leak detection systems used for natural gas transmission and hazardous liquids 

pipelines can be effective, but only after tailoring them to CO2 pipelines. Gaseous CO2 must be 

odorized using hydrocarbon-based odorants. The fading of odorant due to changing 

concentrations of impurities creates challenges for odorant detection using traditional leak 

detection technologies. Airborne leak monitoring can be useful in identifying leaks, since 

PHMSA regulations require several right-of-way surveys per year. In addition, liquid CO2 system 

leakage creates detectable localized reductions in the temperature around the leak that can be 

detected using thermal imaging. 

The regulations for hazardous liquids pipeline integrity programs require that all hazardous 

liquids systems located in High Consequence Areas4 (HCA) have a baseline pipeline integrity 

assessment, and be periodically reassessed. The use of ILI technology, or “smart pigging,” is a 

major component of these assessments. CO2 pipelines can create greater wear on these ILI 

tools compared with the assessments of other hazardous liquids pipelines, which may lead to 

higher costs to the operator. 

System maintenance and incident response may require occasional blow-down of pipeline 

contents. For CO2 pipelines, the blow-down rate must be strictly controlled, and in many cases 

the contents will be captured. Also, pipeline integrity operations may create hazards. As 

inspection tools are removed from a CO2 pipeline, they may entrain liquid CO2 into 

components which could break apart forcibly as the CO2 decompresses. 

The CO2 pipeline safety record, with respect to both the frequency and consequence of failure, 

is comparable to traditional gas transmission and hazardous liquids pipelines. Given their 

relatively low mileage, the frequency of failures, and the mainly rural systems, CO2 pipelines 

have been less prone to excavation damage, which is the primary cause of failures for other 

Department of Transportation (DOT) regulated pipelines. The risk profile for CO2 pipelines is 

somewhat different than for traditional gas transmission and hazardous liquids pipelines. Special 

4

 HCA are defined as current class 3 and 4 locations; facilities with persons who are mobility-impaired, confined, 

or hard to evacuate, and places where people gather for recreational and other purposes. For facilities with 

mobility-impaired, confined, or hard-to-evacuate persons and places where people gather, the corridor of 

protection from the pipeline is 300 feet, 660 feet or 1000 feet depending on the pipeline's diameter and operating 

pressure. See http://www.epa.gov/EPA-IMPACT/2002/August/Day-06/i19840.htm. 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage B-4 
care must be given to a variety of design, operational, and human safety considerations in order 

to better compensate for CO2 system-specific issues. DOT assumed the safety oversight of 

liquid CO2 pipelines in 1988 and codified design, operational, and emergency response 

requirements in 49 C.F.R. Parts 194 and 195. That action, and the strengthening of related 

integrity management requirements in 2001, is focused on safe and secure liquid CO2 pipeline 

operation. 

Emergency responders are trained to respond safely to pipeline incidents. Specific training 

(Hazardous Waste Operations and Emergency Response) is required for both pipeline operator 

personnel and emergency responders. In addition, 49 C.F.R. Part 194 requires operators to 

have spill response plans and to hold spill drills in coordination with local officials, and to 

implement public awareness plans addressing the threats coming from hazardous liquid systems. 

A partnership between PHMSA and the National Association of State Fire Marshals resulted in 

the creation of training materials covering the risks associated with transportation of all pipeline 

commodities, which are available at http://pipeline.mindgrabmedia.com/main.aspx. 

Appendix B. CO2 Pipeline Transport – State of Technology Development: Supplementary Material B-5 

 

Appendix C. CO2 Storage – State of Technology 

Development: Supplementary Material 

C.1 CO2 Storage History 

CO2 fields are often found in regions that also host hydrocarbon resources. For example, Bravo 

Dome (New Mexico), McElmo Dome (Colorado), Escalate Reservoir (Utah), Farnham 

Reservoir (Utah), Woodside Reservoir (Utah), and LaBarge Dome (Wyoming) are some of the 

natural CO2 reservoirs in the Colorado Plateau. Like many natural CO2 accumulations, most of 

these deposits were discovered during hydrocarbon exploration. CO2 from these reservoirs 

can be as pure as 98 percent. Contaminants often include natural gas and other hydrocarbon 

compounds. 

C.1.1 CO2 Storage Experience Associated with CO2 Enhanced Oil Recovery 

CO2-enhanced oil recovery (EOR) and enhanced gas recovery (EGR) technologies are used in 

oil and gas reservoirs to improve production efficiency. Injection of CO2 is one of several 

enhanced recovery (ER) techniques that have successfully been used to boost production 

efficiency of oil and gas by re-pressurizing the reservoir, and in the case of oil, by also increasing 

mobility. 

CO2 currently injected for CO2-EOR in the United States comes from both natural and 

anthropogenic sources, which provide 79 percent and 21 percent, respectively, of CO2 supply 

(NETL, 2008). Historically, CO2 purchases comprise about 33 to 68 percent of the cost of a 

CO2-ER project (EPRI, 1999). For this reason, CO2 injection volumes are carefully managed at 

ER sites. CO2 recovered from production wells during ER is recycled (i.e., separated and reinjected) and, at the conclusion of an ER project, as much CO2 as possible is recovered and 

transported to other ER facilities to be used again. However, a certain incidental amount of 

CO2 remains underground. 

As of 2008, there were 105 CO2-EOR projects within the United States (Oil and Gas Journal, 

2008). The majority (58) of these projects are located in Texas, and the remaining projects are 

located in Mississippi, Wyoming, Michigan, Oklahoma, New Mexico, Utah, Louisiana, Kansas, 

and Colorado. CO2-EOR projects recovered 323,000 barrels of oil per day in 2008, 6.5 percent 

of total domestic oil production. A total of 6,121 CO2 injection wells among the 114 projects 

were used to inject approximately 50 million tonnes of CO2. Compared with CO2-EOR, CO2­

EGR remains largely in the development stage (e.g., Oldenburg et al., 2001; NETL, 2008; Oil 

and Gas Journal, 2008; EIA, 2009). 

C.1.1.1 Large-Scale Geologic Storage Projects 

Following are brief descriptions of several large-scale operations of engineered storage of CO2: 

The Sleipner project, started in 1996, is the longest-running commercial-scale CO2 storage 

project in the world. The Norwegian project injects 98 percent pure CO2 separated from 

produced natural gas in order to avoid paying a carbon tax to vent the CO2 imposed by the 

Norwegian government. The project injects one million tonnes of CO2 annually through one 

horizontal well into the 250m thick Utsira Sand, a high permeability, high porosity sandstone 

Appendix C. CO2 Storage – State of Technology Development: Supplementary Material C-1 
unit roughly 1,100m below the sea surface. The reservoir is sealed with shales, and mudstones 

and shale baffles (discontinuous shale lenses) are present in the reservoir to further deter 

upward movement of CO2. Based on its somewhat unique lithologic properties, the Utsira Sand 

is considered a good analogue for an optimal storage reservoir. 

The Weyburn project is a combined EOR/geologic storage project operated by EnCana in 

southern Saskatchewan near the North Dakota Border. The project began in 2000 and uses a 

mix of 29 horizontal and vertical wells to annually inject roughly 1.8 million tonnes of 96 

percent pure supercritical CO2 from a nearby synfuels plant into two adjacent carbonate layers. 

Successful CO2-EOR operations at the site have demonstrated the applicability of EOR/GS 

technology to thin, less-than-ideal formations at moderate depth. 

The Snøhvit project in the Barents Sea started operation in 2010. Natural gas produced from the 

Snøhvit Field contains ~5 vol% CO2. The CO2 is removed from the natural gas at the receiving 

station located at Melkopya, near Hammerfest. The carbon dioxide produced with the gas from 

the Snøhvit field is sent back near the site of production via pipeline and injected through a 

dedicated well 2,600 meters beneath the seabed at the edge of the reservoir in the Tubåsen 

sandstone formation. This formation is located below the producing formations. The project is 

expected to store approximately 0.7 million tonnes CO2 each year. 

In Salah is a commercial-scale CO2 storage project located in the Sahara Desert in Southern 

Algeria. It uses three horizontal wells to annually inject roughly 1.2 million tonnes of 

supercritical 98 percent pure CO2 separated from produced natural gas. The reservoir is a 

1,800m deep, 21m thick, low-porosity, low-permeability laterally heterogeneous muddy 

sandstone. Successful utilization of this reservoir relied on measurement-while-drilling 

techniques, which were able to target higher-quality regions of the formation in real-time as the 

wells were drilled. This project demonstrated that reservoirs previously thought of as marginal 

or unusable could successfully store commercial-scale quantities of CO2. 

Other non-commercial scale test projects are underway across the globe. Projects such as 

Ketzin (Germany), Lacq (France), Otway (Australia), Gorgon (Australia), KB12 (Netherlands), 

and Nagaoka (Japan) either have already been completed, are underway, or are anticipated to 

commence injection in the next five years. In total, these and other projects have committed to 

store an additional eight million tonnes of CO2 and report on which methods for transport, 

purification, injection, monitoring, and other parameters were successful in the diverse 

environments these projects reflect. 

C.1.1.2 EPA and DOE Tracking of Geologic Storage Projects 

As of May 2010, 56 active storage or integrated capture and storage projects are planned or 

underway. The active storage projects are located across the nation in 22 States and the Navajo 

Nation. Eighteen of these States and the Navajo Nation have UIC program primacy for at least 

one class of injection well (EPA directly implements the program in the other four States). Ten 

of these States are in the process of developing regulations to address liability and/or property 

rights. 

 55 percent of the active storage projects are large: they plan to inject over one million 

tonnes of CO2 total. 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage C-2 
 

 The RCSP Phase II storage projects that are complete as of 2009 have collectively 

injected a total of 1,450,290 tonnes of CO2. This includes 63,790 tonnes injected into 

saline formations; 1,369,500 tonnes for EOR projects; and 17,700 tonnes into coal. 

 Forty-one storage projects have been funded by the U.S. government through 

cooperative agreements, of which 12 are complete. The total cost of these projects was 

nearly $8.6 billion (this figure represents a mix of government and participant cost 

share). 

 Over half of the active storage projects (51 percent) are EOR/EGR projects. The 

remaining are saline (37 percent), EOR/saline (6 percent), and Enhanced Coalbed 

Methane (ECBM) (6 percent).
 

 The storage projects involve injecting into several different depositional classes of 

geologic formations (e.g., basalts, carbonates, clastic rocks, and coal) to assess issues with 

injectivity, capacity, and containment associated with the varied geology across the U.S. 

C.2 CO2 Storage Capacity 

A range of geologic formations is being assessed as potential target formations for injecting and 

storing CO2. Target formations with the greatest geologic storage capacity include deep saline 

formations, depleted oil and gas reservoirs, unmineable coal seams, and other formations. 

While saline formations clearly offer the greatest potential storage resource and capacity, as 

noted in the body of the report, many of the first geologic storage projects will likely be in oil 

and gas reservoirs because these sites have been previously characterized and have existing 

infrastructure to support injection activities. 

Deep saline formations: These formations are sedimentary rock layers that are generally more 

than 800 meters deep and are saturated with waters or brines that have a high total dissolved 

solids (TDS) content (i.e., over 10,000 mg/L TDS). Deep saline formations are found 

throughout the United States, and many of these formations may be overlain by laterally 

extensive, impermeable formations that may restrict upward movement of injected CO2. 

Depleted oil and gas reservoirs: Because many of these reservoirs have trapped liquid and gaseous 

hydrocarbon resources for millions of years, it is believed that they can also be used to store 

CO2. Hydrocarbons are commonly trapped structurally, by faulted, folded, or fractured 

formations, or stratigraphically, in porous formations bounded by impermeable rock 

formations. These same trapping mechanisms can effectively store CO2 for geologic storage in 

depleted oil and gas reservoirs. 

Unmineable coal seams: Currently, ECBM operations exploit the preferential chemical affinity of 

coal for CO2 relative to the methane that is naturally found on the surfaces of coal. When CO2 

is injected, it is adsorbed to the coal surface and releases methane, which can then be captured 

and produced for economic purposes. Studies suggest that for every molecule of methane 

displaced in ECBM operations, three to thirteen CO2 molecules are adsorbed. This process 

effectively “locks” the CO2 to the coal, where it remains stored. 

Appendix C. CO2 Storage – State of Technology Development: Supplementary Material C-3 
 

Capacity estimates are regionally variable, but details are being refined in ongoing efforts (e.g., 

in both DOE and USGS). In 2008, USGS initiated development of a methodology for estimating 

the capacity to store CO2 in geologic formations of the United States. While previous capacity 

estimates published by DOE/National Energy Technology Laboratory have been broad in scope 

(i.e., geologic basin-wide), the USGS is focusing on smaller-scale, refined estimates. In 2010, 

USGS published a proposed, geology-based probabilistic methodology for geologic storage 

capacity estimation and will undertake a national estimate starting in 2010.5 Estimated capacities 

contain uncertainties arising from a number of factors, including geologic (e.g., subsurface 

heterogeneity and materials properties), hydrologic (e.g., movements of fluids and pressure 

fronts), and economic (e.g., variability in site-specific constraints and costs). 

C.3 Technical Considerations for Geologic Storage 

C.3.1 Monitoring, Verification, and Accounting 

As noted in the report, monitoring, verification, and accounting (MVA) are important 

components of managing a geologic storage project and ensuring that the CO2 plume and 

associated pressure front are moving through the subsurface as predicted. Baseline monitoring 

data are necessary to differentiate natural phenomena from signals associated with storage. 

Data collected during site characterization (such as baseline geochemistry, pre-injection 

reservoir pressure, etc.) are necessary to ensure that baseline information is available to form 

the basis for comparison during geologic storage operation and post-injection. For example, the 

baseline geochemical information will allow the owner or operator and permitting authority to 

evaluate monitoring data and identify any changes in subsurface geochemistry that may indicate 

fluid movement. Operational-phase monitoring can demonstrate that a geologic storage project 

is performing as predicted, or provide warning that unexpected fluid movement has occurred 

and USDWs may be endangered or other adverse impacts associated with leakage of stored 

CO2 may occur. For example, monitoring data can demonstrate that the injectate is confined in 

the injection zone, identify potential corrosion of well materials and signal needed well 

construction/mechanical integrity fixes, or identify changes in formation fluid geochemistry (e.g., 

pH decreases that could cause metals to leach into ground water). Post-injection monitoring 

can help ensure that there is no USDW endangerment or contamination or other adverse 

impacts associated with a geologic storage site until the CO2 plume and pressure front stabilize. 

Appropriate monitoring of a geologic storage site can also provide data to maintain the 

efficiency of the storage operation, minimize costs, improve site modeling, and target needed 

future corrective action. Robust MVA is also needed to ensure the integrity of CO2 storage as a 

mitigation strategy under a carbon-constrained regulatory regime. 

Several large projects involve extensive monitoring: 

 At the Sleipner project, gravity and seismic surveys have been used to track the 

migration of the CO2 plume. Both methods have been able to successfully image the 

5

 This report, A Probabilistic Assessment Methodology for the Evaluation of Geologic Carbon Dioxide Storage, is available 

at http://energy.usgs.gov/. 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage C-4 
 

 

plume and verify that the CO2 is behaving as expected. No leaks have been detected at 

the site. 

 At Weyburn, monitoring using seismic, pressure, and geochemical techniques also 

indicated that no leaks had taken place, even though more than 1,072 wells dating back 

to the 1960s were present within Weyburn field. This is an important finding because 

abandoned wells are thought to be an important potential leakage path for CO2. 

 At In Salah, in additional to standard seismic and geochemical techniques, the project also 

used satellite monitoring to measure uplift of the earth surface to monitor CO2 

migration within the reservoir. This technology was able to successfully image 

unexpected developments within the plume due to a previously uncharacterized fracture 

pattern in the subsurface. Discovery of the new migration pattern led to the detection of 

a leak at an old monitoring well, which was then permanently sealed. This event 

confirmed that innovative monitoring techniques are capable of successfully identifying 

leaks. 

 The DOE Regional Carbon Sequestration Partnerships (RCSP) projects also involve 

testing of monitoring technologies. The results from the small scale field tests are 

summarized in a best-practices document that will be updated as results emerge from 

the large-scale field efforts.6 

Recent experience involving injection of municipal wastewater via Class I municipal disposal 

wells in Florida offers an insight into the importance of monitoring at geologic storage sites. 

Ground water monitoring data detected upward fluid movement of some of the injected 

wastewater, which had a lower density (lower TDS) than the native formation fluids through 

preferential pathways, such as fractures in karstic rock formations. While this situation 

identified the need for more rigorous site characterization, which was addressed in a 

rulemaking (70 Fed. Reg. 70513, November 22, 2005), it illustrates the importance of 

monitoring to identify fluid movement and an adaptive approach to address problems identified. 

Continued development is needed for MVA tools to improve aspects related to quantification 

and resolution of CO2 in the subsurface, detection of fractures and other potential leakage 

paths, intermittent leakage, etc. (e.g., IPCC, 2005). 

C.3.2 Potential Impact of Impurities in the CO2 Stream 

Impurities in CO2 streams are manageable but could affect technical and non-technical 

considerations. Proper characterization of CO2 injection streams will be required for 

determining well classification (e.g., proposed UIC Class VI well) and the applicability of other 

regulatory programs. Different CO2 streams will have different compositions. For example, 

certain industrial processes (e.g., ammonia production and biofuel production) produce streams 

that are nearly pure CO2. Natural gas combustion also produces a relatively pure waste stream. 

However, CO2 streams from coal-fired power plants may contain minor impurities carried 

through from the coal. 

6

 See http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdf. 

Appendix C. CO2 Storage – State of Technology Development: Supplementary Material C-5 
Potential co-captured impurities that could affect subsurface processes include hydrogen sulfide 

(H2S), and oxides of sulfur and nitrogen (SOx and NOx). In a post-combustion scenario (i.e., 

capture from a conventional coal-fired power plant), impurities may include sulfur dioxide 

(SO2), NOx, and oxygen (O2). Emissions from an IGCC plant would contain H2S instead of SO2 

and ammonia (NH3) instead of NOx. Also, the more volatile heavy metals (e.g., mercury, 

selenium, arsenic, and cadmium) and some organic impurities may be present in trace amounts. 

The amounts of these impurities are expected to be low, and would depend on the 

composition of the coal and efficiencies of any scrubbing steps (e.g., desulfurization), as well as 

the CO2 capture technology. 

SO2 raises concerns because it may become oxidized to sulfate. Potential impacts include 

changes to the chemistry of the reservoir fluids (e.g., affecting the acidity or the oxidation 

potential) and dissolution or precipitation of minerals, which could, in turn, affect reservoir 

performance (e.g., injectivity and/or storage integrity). Modeling studies have approximated the 

effects of impurities on pH (e.g., Xu et al., 2004; Knauss et al., 2005). Their numerical 

simulations have indicated the potential for lowering of pH due to co-injection of SO2. 

However, current understanding is limited by lack of knowledge about the rates of reactions 

between the injectate, formation fluids, and rock formations. Also, because there are currently 

no conventional coal-fired power plants that are capturing and injecting CO2 into the 

subsurface, there are no field data with which to refine estimates from modeling. At this point, 

it is difficult to predict with certainty the effects of injection of trace SO2. More research is 

needed, especially to assess the potential long-term effects on seal integrity. 

H2S is not expected to severely affect pH. Neither Xu et al. (2004) nor Knauss et al. (2005) 

predicted a significant pH change when H2S co-injection was simulated. Although low pH does 

not appear to be a concern with H2S injection, hydrogen sulfide is known to promote corrosion 

in steel. However, experience from analog operations (e.g., acid-gas disposal in Canada) is 

encouraging and suggests that the impact of impurities on (at least) some reservoirs is 

manageable. 

Potential heavy metal concentrations in a captured CO2 stream have been calculated by Apps 

(2006) and are expected to be very low. Non-volatile metals tend to remain associated with fly 

ash in coal combustion, and are not anticipated in CO2 streams. Volatile and semi-volatile 

elements (mercury, arsenic, cadmium, and selenium) have a greater potential for remaining with 

the flue gas and being captured. Post-combustion treatment for particulates and SO2 can 

remove a portion of the metals, but prediction of metals in a captured CO2 injectate is difficult 

because of differences in coal compositions and plant operations. If conventional pulverized coal 

plants were to be retrofitted with CCS, newer Hg removal technologies and any improvements 

in fine particulate removal might render the issue of trace metals as potential constituents in 

CO2 injectate insignificant. Only trace concentrations of organic compounds are expected (Sass 

et al., 2005). 

All of these impurities would be injected along with the CO2 into a well that must meet EPA’s 

requirements for Class VI wells, which were developed based on the requirements and 

standards for Class I industrial and hazardous waste wells. The corrosion-resistant construction 

standards, periodic corrosion monitoring and mechanical integrity testing requirements in the 

geologic storage rule are specifically designed to address this risk. 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage C-6 
Experience from analog operations (e.g., acid-gas disposal in Canada) is encouraging and 

suggests that the impact of impurities on (at least) some reservoirs is manageable, but more 

research is needed to assess the potential long-term effects on seal integrity. Acid-gas injection 

is found to be a good analogue for CO2 storage, as it results in the long-term storage of 

significant amounts of CO2. Because the equipment and geologic formations involved in acid-gas 

injection are similar to those required for CO2 injection, much of the knowledge gained from 

acid-gas injection is directly applicable to CO2 storage. 

C.4 Additional Needs for Widescale Deployment 

Workforce capacity may be a barrier for widespread deployment, including both projectrelated workforce needs (e.g., reservoir engineers, etc.) and permitting-related workforce 

needs at both the State and Federal levels. 

Technical Capacity 

Current technical capacity of State and Federal UIC programs to permit and ensure compliance 

may be a barrier to deployment. Current EPA training for UIC staff focuses on the key 

elements of UIC permits and on evaluating permit applications for completeness and technical 

accuracy. The UIC Program’s training materials address evaluating geologic data (e.g., on 

USDWs and formation testing); well construction and pre-operational testing data; permit 

conditions for construction, operation, maintenance and monitoring; well plugging and 

abandonment requirements; addressing well failures; financial responsibility; and public 

participation in the UIC permitting process. 

The new requirements for Class VI geologic sequestration wells would necessitate 

enhancements or additions to this training. New UIC Training Modules would need to be 

developed for UIC staff to complement the forthcoming Class VI guidances and provide the 

necessary detail to support the UIC Program’s critical mission to ensure that USDWs are 

protected from endangerment. These modules may include the following: 

 Applying for Class VI Primacy. 

 Evaluating a Permit application for the construction of a Class VI well. 

o	 New site characterization considerations for the unique nature of CO2 geologic 

storage. 

o	 Evaluating the proposed well design and construction, including the use of 

materials that are compatible with CO2. 

o	 Evaluating the proposed Area of Review (AoR) for a Class VI well and the 

proposed multi-phase computational model. 

o	 Evaluating Class VI testing and monitoring plans, including the monitoring 

necessary to track the CO2 and pressure front in the subsurface and the ground 

water monitoring plan. 

o	 Evaluating a Financial Responsibility demonstration. 

Appendix C. CO2 Storage – State of Technology Development: Supplementary Material C-7 
 Granting Approval for CO2 Operations. 

o Evaluating the Final AoR based on logging and testing. 

o Evaluating the testing to establish operating parameters and well shut-off triggers. 

 Evaluating post-injection monitoring data and non-endangerment demonstrations. 

State UIC Program Capacity Limitations 

As noted in the report body, stakeholders have concerns about State UIC Programs’ lack of 

adequate resources to handle the number and complexity of geologic sequestration projects. 

Workforce and technical capacity issues could be addressed by providing training to States on 

unique technical issues associated with geologic sequestration, providing technical support on 

permit reviews and issuance, or supporting compliance and enforcement activities. In addition 

to the workforce capacity development needs discussed in the body of the report, permitters 

will need guidance, training, and contractor assistance to analyze financial responsibility 

submissions in CCS permit applications. Currently, State or Federal permitters may not have 

the ability to assess financial instruments used to cover financial responsibility requirements for 

CCS. For example, if a permit application is submitted with insurance as part of the financial 

responsibility package, a permitter may not have the tools to determine if the right coverage 

limit was selected or if the risk analysis performed by the insurance company was adequate. In 

the case of self-insurance (financial statement), permitters will need guidance and training to 

select the appropriate financial ratios based on the financial health of the company. In addition 

to guidance and training for program staff, access to expert consultants who can troubleshoot 

will be critical for adequate review of CCS financial responsibility submissions. Additionally, 

State UIC primacy agencies’ efforts could be aided by a national data system that would 

promote regulatory certainty, efficiency, and accountability, while allowing transparency of all 

geologic sequestration related information to improve public acceptance of CCS. 

Pore Space 

Definition of the ownership of injected CO2 and pore space will be needed for wide-scale 

deployment. An efficient process for obtaining access to and the right to use surface property 

and pore space for site characterization and the life of the project may also be needed 

(unitization, etc.). 

C.5 Outreach 

Public outreach on geologic storage projects is critical to providing citizens with access to 

decision-making processes that may affect them, ensuring that the community receives 

adequate information about the proposed injection project, and allowing the permitting 

authority and owners or operators to become aware of public viewpoints on the project. Early 

and frequent public involvement through education and information exchange is key to the 

success of geologic storage and can provide insight into how the local community and 

surrounding communities perceive potential environmental, economic, or health effects 

associated with a specific geologic storage project. 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage C-8 
It is important to ensure that mechanisms are in place for the public to access and synthesize 

storage project data (generally and on an individual site basis), including the following: 

 stakeholders interested in launching and regulating projects, 

 public education to address/forestall misinterpretations about this new technology, and 

 engender commercial, regulatory, and public confidence. 

Several efforts are already underway to developing a portfolio of outreach tools and 

approaches, including the following: 

 Regional Carbon Sequestration Partnerships (RCSP)—each Partnership has tailored 

outreach to regional needs and stakeholders; outreach also tailored to each of the 

phases of the Partnerships (characterization phase, validation phase with small-scale 

injections, and demonstration phase with large-scale injections). RCSP experience 

suggests outreach to various stakeholders is critical from beginning of project throughout 

execution. Outreach needs may vary both between stakeholder groups and regionally. 

 Best practice manual for outreach (based on RCSP experience) is anticipated to be 

released in 2010; Keystone Center has developed elementary and high-school curricula 

for CCS. 

EPA plans to work with permitting authorities and geologic storage well owners or operators 

to involve the public by providing communities information about a geologic storage project as 

early in the process as possible. EPA is also developing outreach tools on geologic storage such 

as fact sheets, visual aids, and the use of social media, and will hold public meetings. 

Appendix C. CO2 Storage – State of Technology Development: Supplementary Material C-9 

 

Appendix D. CO2 Reuse 

CO2 reuse or utilization is the conversion of captured CO2 to a useable product.7 Similar to 

geologic storage of CO2, such utilization allows for a net reduction of CO2 emissions into the 

atmosphere by using CO2 either directly or as a feedstock (IPCC, 2005). Such net reduction is 

possible only if two conditions are met: (1) use of the captured CO2 must not simply replace a 

source of CO2 that would then be vented to the atmosphere, and (2) compounds produced 

from the captured CO2 must have a long lifetime (IPCC, 2005). For industrial processes, it is 

important to properly determine the system boundary in order to get an accurate 

determination of the net lifecycle CO2 emissions based on material and energy balances (see 

IPCC, 2005 section 7.3.1 for more details). 

CO2 is a valuable industrial gas, and currently there are at least 22 commercial end-use sectors 

that use gaseous, liquid, or solid CO2 (EPA, 2009), including food and beverage manufacturing 

and various chemical, pharmaceutical, and other processes that use CO2 as an end product. 

This number excludes intermediate CO2 processors and enhanced oil and gas recovery. 

However, it remains to be determined whether there is a net reduction of lifecycle CO2 

emissions from industrial processes using CO2. Furthermore, the amount of CO2 reuse in 

industrial processes is very small compared with the magnitude of CO2 emissions from 

industrial sources. Industrial sources in the United States alone emit approximately 1.4 billion 

tonnes of CO2 annually (EIA, 2010a). 

Several options that are under investigation for CO2 reuse range from conversion to biomass 

(e.g., via algae, microbes, plants), to conversion to a solid (e.g., plastics or ceramics), among 

others. The following sections briefly discuss the key options. 

D.1 Potential Options for Reuse 

Enhanced Oil Recovery: Current EOR processes in the United States are based mostly on 

CO2 obtained from natural sources. Replacing the use of natural CO2 with captured CO2 would 

result in a net reduction of emissions to the atmosphere, assuming that a part of the injected 

CO2 remains stored underground. Through 2008, approximately 560 million tonnes (NETL, 

2010) of CO2 have been injected in the United States for EOR. Currently, the United States 

uses approximately 50 million tonnes of CO2 per year for EOR (Dooley, 2008). Using EOR, 30– 

60 percent of the reservoir’s original oil can be extracted compared with 20–40 percent using 

primary and secondary recovery (DOE, 2010a). Figure D-1 shows annual U.S. oil production 

using EOR. 

In this technique, CO2 is injected into an operational oil field, where, in most cases, it mixes 

with the crude oil, causing it to swell and become less viscous—thereby maintaining reservoir 

pressures and oil production rates. CO2 injection can also be used to sweep oil toward 

production wells. In both cases, revenue accrued through the sale of the additional oil produced 

can help to offset CO2 injection costs. 

7

 Note that by this description and the discussion in this appendix, the Task Force does not intend to take a 

position on whether a particular process involves a solid waste subject to the requirements of RCRA. 

Appendix D. CO2 Reuse D-1 
 

Figure D-1. Growth of U.S. Oil Production from CO2-based EOR 

Source: (NETL, 2010) 

Fuel Production: Most carbon-based fuels are made up of carbon, hydrogen, and oxygen. 

CO2 can be hydrogenated to create low-carbon-chain fuel such as methanol. These 

hydrogenation reactions are exothermic in nature, although they require catalysts such as 

copper, zinc, or alumina. Procuring hydrogen requires energy for hydrolysis of water or partial 

oxidation of natural gas. If this energy can be based on non-fossil sources, then the complete 

process could have very low or even negative life-cycle carbon emissions footprint. However, 

Herzog et al. have shown that about six units of solar (or other non-fossil) energy would be 

needed to recycle the CO2 generated from producing one unit of energy in a coal-fired power 

plant, if the hydrogen came from electrolysis of water (Herzog et al., 1993). 

Chemical Synthesis: Ceramics, fertilizers, rubber, and many other small-scale industries 

require CO2 at some stage of their manufacturing process. However, the amount of CO2 that 

could be potentially used in these plants is rather small compared with emissions of CO2. 

The largest use of CO2 in this area is in fertilizer plants, where CO2 is captured from the 

exhaust gases of NH3 reformer units and used to manufacture urea. Such chemical synthesis is 

already under application, and CO2 emission from power plants can be routed to such units— 

although it is not clear if there will be net negative emissions from such applications. Laying of 

new pipeline for CO2 would also be quite expensive and increase lifecycle CO2 emissions. 

Polymer Synthesis:8

 CO2 can be viewed as a C1 building block of a long carbon chain 

polymer. However, using CO2 requires the development of efficient catalysts and additional 

energy for reducing CO2. Finding an efficient reducing catalyst or net low-energy-intensive 

process to reduce the CO2 has been the challenge so far. However, CO2 can be used in place of 

phosgene in polyurethane and polycarbonate manufacturing, as phosgene is toxic. Overall 

potential for CO2 use in polymer synthesis is not significant because of additional energy uses 

and low consumption. For example, if the U.S. plastic industry relies exclusively on captured 

8

 Summarized from Section 7.3.3.1 of IPCC (2005). 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage D-2 
CO2, it can potentially use about 100 million tonnes of CO2, around 5 percent of annual CO2 

emission from the power sector (Herzog et al., 1997). 

Bio-fuel production using Algae: Plants convert CO2 and water into starch using sunlight 

during the photosynthesis process. Although more advanced plants are not very effective in 

conversion of large quantities of CO2, micro-algae can use high concentrations of CO2 to 

create starch. The biomass product can be used to recycle CO2 into valuable industrial fuel 

such as methane, methanol, hydrogen and bio-diesel. However, the CO2 removed by 

conversion to bio-fuel will be added back in the environment once it is burned. Also, it will 

require additional energy to convert the CO2 to bio-fuel such as in harvesting, fertilizers, etc. 

Overall, the conversion efficiency is limited by photosynthetic efficiency. At present, microalgae convert solar energy with one percent efficiency, implying that a solar collection area as 

large as 20 square miles is needed to convert CO2 emissions of a 100 MW power plant. 

However, there is significant ongoing research in this area (IPCC, 2005). 

Carbonation: Alkaline earth metal oxides react with CO2 to create insoluble carbonates. 

Rocks with high metal oxide concentrations can be used to store significant amounts of CO2 in 

the form of carbonates. The technology for mineral carbonation is not yet mature enough to 

allow for a proper assessment of costs and performance, but there will be rather high costs 

associated with mining (similar to the scale of current global coal mining) and disposal issues. 

D.2 Role of CO2 Utilization in Climate Change Mitigation 

Several factors determine the viability of CO2 reuse, and there are currently significant technical 

barriers to commercial-scale reuse. First, rates of conversion must be comparable to rates of 

CO2 capture. Second, energy requirements for conversion must be low. Third, potential 

volumes of reactants and/or products may limit the scale of reuse relative to total emissions. 

Finally, reuse options need to consider the long-term fate of CO2 and its lifecycle emissions. 

In summary, there are limited commercial uses for captured CO2, such as in food and beverage 

manufacturing, pulp and paper manufacturing, the rubber and plastic industry, fire suppression, 

and refrigeration and cooling. No market is expected to develop for reuse of CO2 on a scale 

that would significantly affect a strategy to roll out CCS on a national basis by 2016. 

Appendix D. CO2 Reuse D-3 

Appendix E. Research, Development, & Demonstration 

E.1 Research and Development 

Capture 

Two Research, Development and Demonstration (RD&D) technology pathways are being 

pursued globally for combining coal-fueled power generation with CCS. The first is based on 

pulverized coal (PC) power plant technology, which is used worldwide in nearly all utility-scale 

coal power plants. It will be the focus of retrofit applications, and could also find applications 

for new power plants. The second is based on coal gasification technology. Gasification-based 

power generation is far less mature than PC technology, but it is believed by many to be the 

pathway leading to the most cost-effective CCS options. 

The highest priority RD&D is on capture technology using innovative solvents, solid sorbents, 

and membranes to extract CO2 from flue gas. RD&D is focused on areas such as reducing 

regeneration energy and material cost, and increasing reaction speed (solvents and sorbents), 

durability, and tolerance to pollutants, and CO2 selectivity (membranes). Advanced capture 

technology could reduce the increased cost of electricity due to adding CCS to a supercritical 

PC power plant from current estimates of an 80 percent increase to as low as a 30 percent 

increase. Further CO2 reductions would be possible if advanced boiler materials are developed 

leading to a new generation of more efficient ultra supercritical PC power plants that have a 

significantly smaller carbon footprint per power output. 

Although several IGCC demonstration plants (as described in Appendix A) are operating 

worldwide, the strategy for IGCC RD&D is to continue to improve the cost and performance 

of key plant components, including those that will lead to higher availability. Current RD&D is 

focused primarily on advanced combustion turbines, warm gas clean-up and H2/ CO2 separation 

membranes, coal feed pumps, and ion transport membranes for low-cost oxygen production. 

The ongoing DOE CO2 capture technology R&D program for post-combustion and oxycombustion capture is working to develop advanced 2nd generation technologies capable of 90 

percent CO2 capture with a target of less than a 30 percent increase in the COE over a 

comparable plant without CCS. For pre-combustion capture (IGCC applications), the DOE goal 

is to provide electricity with less than a 10 percent increase in the COE compared to the same 

power plant without CCS. As shown in Figure E-1 and Figure E-2, accomplishing these goals will 

require significant efficiency and cost improvements (capital and operating) for conventional PC 

and IGCC power plants. The current DOE CO2 capture technology R&D timeline to 

accomplish those goals includes the following major milestones (DOE, 2010): 

 By 2016, complete small-scale field testing of 2nd generation CO2 capture technologies 

and components that demonstrate significant reduction in CO2 capture cost and energy 

penalties compared with current technologies. The field testing will be between 0.5 to 5 

MWe scale from pilot plant facilities and/or slipstream treatment at operating coal-based 

power plants. 

Appendix E. Research, Development, & Demonstration E-1 
   

   

  

 By 2020, complete large-scale field testing at 25 MWe of 2nd generation CO2 capture 

technologies and integrated oxy-combustion systems that demonstrate significant 

reduction in CO2 capture cost and energy penalties compared with current technologies. 

As shown in Figure E-1 below, accomplishing these goals will require significant efficiency 

improvements for IGCC and conventional PC power plants. The IGCC with 2nd generation 

CCS efficiency improvement includes advances in air separation (membranes), hot/warm gas 

cleanup, combustion turbines and CO2 capture and compression technologies. With successful 

development of these technologies, the IGCC with 2nd generation CCS efficiency increases 

from 33 percent to 40 percent. Likewise, improvements in advanced air separation, ultrasupercritical boiler materials, CO2 capture and compression technologies will improve the PC 

with 2nd generation CCS efficiency from 28 percent to 35 percent. 

Figure E-1. DOE CCS R&D Efficiency Improvement Targets 

45 

40 

35 

30 

25 

IGCC with CCS

Combustion with CCS

2010 Combustion

Demo‐Scale

Current IGCC

and Combustion

technologies

without CCS

2010 IGCC

Demo‐Scale

1st Generation	 2nd Generation 

Source: NETL (2009b) and NETL (2009c) 

As shown in Figure E-2 below, accomplishing these COE goals will also require significant 

capital cost improvements. Combined with efficiency improvements, the COE for IGCC with 

2nd generation CCS would decrease by 32 percent (from 150 mills/kWh to 102 mills/kWh). 

Likewise, improvements in PC plant capital costs (such as smaller CO2 capture and Power Plant Efficiency [% HHV] 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage E-2 
   

   

   

   

   

   

   

   

compression equipment size) would result in a 30 percent decrease in COE (from 151 

mills/kWh to 110 mills/kWh). 

Figure E-2: DOE CCS Cost Improvement Targets 

160 

COE

2010 Combustion

without CCS COE

2010

Demo‐Scale

2010 IGCC

without CCS COE

2010 Combustion

without CCS Capital

2010 IGCC

without CCS Capital

Capital Cost

IGCC with CCS

Combustion with CCS

5000 

150 

4500 140 

130 4000 

120 

110 3500 

100 

3000 90 

80 2500 

70 

60 2000 

1st Generation 2nd Generation 

Source: NETL (2009b) and NETL (2009c) 

Upon successful development at the laboratory through pilot-scale (5-25 MW), the advanced 

2nd generation technologies showing the most promise in terms of reducing costs and energy 

penalties could warrant further development and demonstration at full-scale before commercial 

acceptance, which may take on the order of a decade. The relative roles of the government and 

the private sector in these more advanced stages of CCS development and scale-up should be 

carefully evaluated. 

Storage 

DOE’s CO2 storage activities involve three key elements for technology development: Core 

RD&D, Infrastructure, and Global Collaborations. The Core RD&D element includes geologic 

storage, MVA, and simulation and risk assessment. It also includes American Recovery and 

Reinvestment Act (ARRA) University Projects, which focus on training undergraduate and 

graduate students in the five Core RD&D focus areas. Applied research is identified through 

lessons learned from the Infrastructure and Global Collaborations elements and conducted 

through the Core RD&D Program to meet the following goals: COE [mills/kW-h]

Capital Cost [$/kW] 

Appendix E. Research, Development, & Demonstration E-3 
 Validate enhanced CO2 trapping and storage capacity, determine reservoir theoretical 

capability to store CO2 (with impurities if present), and test stimulation and completion 

technologies to enhance injectivity of storage formations. 

 Assess the development of a cost-effective “toolbox” to monitor plume migration in 

deep geologic formations, complete a material balance, and develop protocols to enable 

99 percent of stored CO2 to be accredited as net emissions reductions. 

 Assess the improvements to existing simulation codes to enhance prediction of plume 

migration, develop a “systems” approach(es) to risk assessment for field sites, and 

develop and validate coupled risk assessment process models for large-scale projects. 

 Determine promising areas of CO2 utilization, using fundamental and bench-scale testing 

and research. 

 Determine viability of managing produced water from geologic storage projects for 

beneficial applications. 

Technologies are validated at test sites in the United States and Canada, and ongoing data 

collection is used to confirm geologic storage capacity and effectiveness. 

The second element, infrastructure, includes the RCSP Initiative, other large-scale projects, and 

ARRA Regional Technology Training and Site Characterization. The focal point of the 

Infrastructure element is the RCSP Initiative, which is a government/industry cooperative effort 

tasked with developing guidelines for the most suitable technologies, regulations, and 

infrastructure needs for CCS in different regions of the United States and Canada. The RCSP 

Initiative is composed of seven partnerships encompassing 43 States, four Canadian provinces 

and more than 350 organizations, including NGOs. The RCSP Initiative is implemented in three 

phases: 

 Characterization Phase (2003–2005): The partnerships completed the initial 

characterization of their regions’ potential to store CO2 in different geologic formations. 

 Validation Phase (2005–2010): The partnerships are concluding validation of the most 

promising regional storage opportunities through a series of small-scale field tests. This 

phase builds upon the Characterization Phase accomplishments and field tests of geologic 

and terrestrial storage technologies to provide the technical foundation for Development 

Phase activities. 

 Development Phase (2008–2017): The partnerships are beginning to implement largescale field testing involving at least 1 million tonnes of CO2 per project to confirm that 

CO2 injection and storage can be achieved safely, permanently, and economically. 

Data and maps generated through all three phases of the RCSP Initiative are used to estimate 

the potential U.S. geologic CO2 storage capacity. This information is integrated into the Carbon 

Sequestration Atlas and the National Carbon Sequestration Database (NATCARB) and 

Geographical Information System. The Atlas is updated every two years, and NATCARB is 

updated in real time. 

ARRA project areas also contribute to the Infrastructure element. Regional Technology 

Training provides training to next-generation engineers and scientists; and Site Characterization 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage E-4 
characterizes additional promising formations for geologic storage through investigations at 10 

site locations. Work conducted through the RCSP Initiative and other Infrastructure activities 

benefits the DOE CCS Program by developing human capital, encouraging stakeholder 

networking, providing data for policy development, and developing visualization knowledge 

centers, best practices manuals, and public outreach and education. 

The majority of CO2 operations today are occurring in tandem with business-as-usual EOR, 

with little effort spent on accounting for the CO2. To enable widespread, safe, and effective 

CCS within the next 10 years, commercial demonstration projects should include storage in 

different geologic reservoir classes. DOE is currently conducting its CCPI and ICCS 

demonstration projects to determine effects of variation in CO2 supply on storage operations. 

In addition, the RCSP program plans to conduct nine large-scale injection and storage 

demonstration projects in a variety of geologic reservoirs. Knowledge generated from 

monitoring the fate and transport of the injected CO2 at these projects will help inform the 

production of Best Practice Manuals to guide future deployment of CCS. 

E.2 Demonstrations of CCS Technology 

DOE’s CCPI is a cost-shared collaboration between the Federal government and industry to 

speed investment in low-emission coal technology by demonstrating and accelerating the 

commercial deployment of advanced coal-based power generation technologies. Recent project 

selections have focused on proving the feasibility of integrating CO2 management and power 

production, and facilitating the movement into the marketplace of technologies emerging from 

DOE’s core research and development activities. Six integrated CCS projects are currently 

proceeding under CCPI. Of these, three are new IGCC plants with pre-combustion capture 

and three are post-combustion capture from PC power plants. 

In addition to fossil-fueled power plants, there are large industrial CO2 emitters that could be 

candidates for CCS. Industrial plants may find it more difficult than power plants to finance 

early CCS projects because they cannot necessarily rely on consumers to pay the incremental 

cost of the technology (whereas public utility regulators may approve such cost recovery 

mechanisms for regulated utilities). Recognizing the importance of this CCS market, Congress 

recently made funding available through ARRA for industrial CCS demonstrations. These 

projects currently include large-scale CCS for commercial and industrial sources such as 

cement plants, chemical plants, refineries, steel and aluminum plants, and manufacturing 

facilities. 

The above suite of demonstration projects, in tandem with commercial projects supported by 

Federal loan guarantees, tax incentives, and various incentives at the State level, should cover a 

sufficiently large group of CCS options to allow widespread deployment. However, certain key 

areas may not be adequately covered. For example, a relatively small number of the abovementioned projects plan to inject captured CO2 into deep saline formations. None of the 

current suite of projects inject into offshore formations. Additionally, based on historical 

program data and especially given current economic conditions, not all of these projects should 

be expected to move forward to completion. 

Appendix E. Research, Development, & Demonstration E-5 

 

 

 

 

Appendix F. Applicability of Selected Environmental Laws 

to the Storage Phase of Carbon Capture and Storage 

F.1 Introduction 

The purpose of this appendix is to consider the applicability of the Safe Drinking Water Act; 

the Resource Conservation and Recovery Act; the Comprehensive Environmental Response, 

Compensation, and Liability Act; the Emergency Planning and Community Right-To-Know Act; 

and the Clean Air Act to the storage phase of CCS.9 In the recently proposed rule entitled 

Mandatory Reporting of Greenhouse Gases: Injection and Geologic Sequestration of Carbon Dioxide, 75 

Fed. Reg. 18576, 18578 (April 12, 2010), EPA noted that it may be appropriate for a wide 

variety of sources to mitigate sizeable GHG emissions through CCS. This includes sources in 

such sectors as “electric power plants (existing and new), natural gas processing facilities, 

petroleum refineries, iron & steel foundries, ethylene plants, hydrogen production facilities, 

ammonia refineries, ethanol production facilities, ethylene oxide plants, and cement kilns.” Id. 

F.2 Safe Drinking Water Act (SDWA) 

CO2 underground storage sites are regulated through the SDWA Underground Injection 

Control (UIC) Program. 

Underground injection wells are regulated under the authority of Part C of SDWA. SDWA 

§1421, 42 U.S.C. § 300h, requires EPA to establish requirements for State UIC programs to 

prevent endangerment of USDWs from “the subsurface emplacement of fluids by well injection 

. . . .” 40 C.F.R. Parts 144-148. 40 C.F.R. § 144.3 defines “fluid” as “any material or substance 

which flows or moves whether in a semisolid, liquid, sludge, gas, or any other form or state.” 

UIC permits are issued for injection wells onshore and those requirements can be implemented 

for wells inside State territorial waters.10 

Since 1974, EPA has established requirements for five classes of UIC wells: industrial, municipal, 

hazardous, and radioactive waste wells (Class I); wells associated with enhanced oil and gas 

production and waste disposal (Class II); solution mining wells (Class III); shallow hazardous 

waste wells (Class IV, which are essentially banned); and all other wells (Class V).11 

Under § 1421(b), SDWA mandates that EPA develop minimum Federal requirements for State 

UIC primary enforcement responsibility, or primacy, to ensure protection of USDWs.12 In 

9

 These environmental statutes are directly implicated by CCS; however, there may be circumstances in which 

other environmental laws, such as the Federal Water Pollution Control Act in the case of a discharge of a 

pollutant from a point source to a water of the United States, would apply in the context of CCS. 33 U.S.C. §§ 

1311(a) and 1362(7), (12). Further, natural resources and public lands laws such as the National Environmental 

Policy Act (NEPA), the Endangered Species Act, the Federal Land Policy and Management Act, and the Mineral 

Leasing Act, will also apply according to their terms. 

10 40 C.F.R. § 144.1(g)(1). 

11 40 C.F.R. Parts 144, 146, and 148. 

12 Reference to “States” includes tribes and territories. 

Appendix F. Applicability of Selected Environmental Laws to the Storage Phase of CCS F-1 
 

 

 

 

order to implement the SDWA UIC Program, States, Tribes, and territories must apply to EPA 

for primacy approval. Under § 1422, States have 270 days to submit their program to EPA for 

approval. A State applying for primacy (except for Class II) under § 1422 must show that its 

program is at least as stringent as the Federal minimum requirements provided for in the 

Federal regulations.13 Within 90 days of a State’s application, and after there has been 

“reasonable opportunity for presentation of views, the Administrator shall by rule either 

approve, disapprove, or approve in part and disapprove in part, the State’s underground 

injection control program.”14 

Injectate CO2, which is a supercritical fluid, meets the definition of “fluid” in SDWA.15 CO2 

exists as a supercritical fluid at high pressures and temperatures, and in this state exhibits 

properties of both a liquid and a gas. SDWA’s UIC regulations apply to all CO2 sequestration 

well sites across the United States, including wells that are located inside a State’s territorial 

waters. CO2 sequestration well sites are regulated under the UIC program regardless of 

capture technology. Current options for permitting UIC wells that inject CO2 include Class I 

industrial, Class II, or Class V experimental wells.16 

In 2008, EPA proposed Federal requirements for underground injection of CO2 for purposes of 

geologic sequestration.17 The proposal applies to owners or operators of wells that will be used 

to inject CO2 into the subsurface for the purpose of long-term storage. It proposes a new class 

of well (Class VI) and tailors minimum technical criteria for geologic site characterization, area 

of review, corrective action, well construction, operation, mechanical integrity testing, 

monitoring, well plugging, post-injection site care, and site closure to the unique nature of CCS. 

This is to ensure that the injection of large volumes of CO2 in a variety of geologic formations 

would not endanger USDWs. EPA plans to go final with the Class VI rulemaking in late 2010. 

Until the Class VI rulemaking goes final and into effect, CCS will continue to be permitted 

under the existing UIC program including existing State primacy authorities. 

F.3 Resource Conservation and Recovery Act (RCRA) 

RCRA provides authority to address waste injectate CO2 that may present an imminent and 

substantial endangerment to human health and the environment. RCRA hazardous waste 

requirements may apply to certain injectate CO2. 

The Solid Waste Disposal Act, as amended (commonly referred to as RCRA), generally 

regulates “solid wastes,” with Subtitle C of the Act addressing management of solid wastes that 

are also “hazardous wastes.” RCRA Subtitle C is designed to be implemented by authorized 

13 40 C.F.R. Part 145. 

14 SDWA § 1422(b)(2), 42 U.S.C. § 300h-1(b)(2). 

15 In § 706 of the Energy Independence and Security Act of 2007, 42 U.S.C. § 17254, Congress made SDWA 

applicable to CCS through the provisions of the Department of Energy Carbon Capture and Sequestration 

Research, Development, and Demonstration Act of 2007. 

16 In March 2007, EPA issued Using the Class V Experimental Technology Well Classification for Pilot Geologic 

Sequestration Projects—UIC Program Guidance (UICPG #83). 

17 73 Fed. Reg. 43492 (July 25, 2008). 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage F-2 
 

 

 

 

 

States in lieu of a Federal program, with Federal oversight. RCRA Subtitle C establishes a 

comprehensive “cradle to grave” regulatory scheme, including requirements for generators and 

transporters, along with permitting and other requirements for hazardous waste “treatment, 

storage, or disposal” facilities. Violations of RCRA Subtitle C requirements are subject to civil 

and criminal enforcement, and RCRA provides authority for the United States to take civil 

action to prevent imminent and substantial endangerment due to the handling, transporting, 

disposing, or other actions related to a solid or hazardous waste.18 

RCRA defines “solid waste” as “any garbage, refuse, sludge from a waste treatment plant, water 

supply treatment plant, or air pollution control facility and other discarded material, including 

solid, liquid, semisolid or contained gaseous material resulting from industrial, commercial, 

mining, and agricultural operations . . . .”19 EPA has promulgated extensive regulations further 

defining what is a solid waste for hazardous waste regulatory purposes.20 

RCRA applies at the point at which a waste is generated.21 Among the possible points of 

“generation” are: (1) the point at which CO2 is captured as a gas, (2) the point at which CO2 is 

compressed to form a supercritical fluid (exhibiting the properties of both a liquid and gas), and 

(3) the point at which CO2 is injected as a supercritical fluid. At any of these points, CO2 bound 

for permanent sequestration is likely to be considered a “solid waste” under the RCRA statute 

because it would be subsequently “discarded” “liquid [or] contained gaseous material resulting 

from industrial [or] commercial . . . operations . . . .” This means that, irrespective of its status 

as a hazardous waste, RCRA § 7003 is available to address activities concerning CO2 bound for 

sequestration that may present an imminent and substantial endangerment to human health and 

the environment. 

CO2 bound for permanent sequestration, if it were to qualify as a hazardous waste, is also likely 

a solid waste for purposes of the RCRA hazardous waste regulations. It is “liquid [or] contained 

gaseous material resulting from industrial [or] commercial . . . operations . . .” being “discarded” 

(abandoned for disposal). 22,23,24 

18 RCRA §§ 3001-05, 3007-08, and 7003, 42 U.S.C. §§ 6921-25, 6927-28, and 6973; 40 C.F.R. Parts 260-279. 

19 § 1004(27), 42 U.S.C. § 6903(27). 

20 40 C.F.R. § 261.2. 

21 Regulation from the point of generation has been upheld as a permissible construction of the RCRA statute. 

Chemical Waste Management v. EPA, 976 F.2d 2, 14 (D.C. Cir. 1992), reh’g denied, 985 F.2d 1075 (D.C. Cir.), cert. 

denied, 507 U.S. 1057 (1993). 

22 Hazardous secondary material which is used or re-used as a substitute for a commercial product or as an 

ingredient in an industrial process to make a product may be excluded from the definition of solid waste under 

RCRA regulations. EPA's regulations may apply to CO2 that has been geologically sequestered if it is being stored 

for re-use in a product or ingredient. See 40 C.F.R. §§ 261.1(c)(5) and 261.2(e). To qualify for this exclusion, 

however, the hazardous material must be legitimately recycled. In addition, the hazardous material cannot be 

accumulated speculatively, meaning generally that 75 percent of the accumulated material must be used within a 

calendar year. 40 C.F.R. § 261.1(c)(8). Further, the EPA regulations state that this hazardous material may not be 

burned for energy recovery nor re-used in a manner that constitutes disposal (i.e., being put on the land or used 

to make a product that is put on the land). See 40 C.F.R. § 261.2(c). Currently, there are 22 commercial end-use 

sectors that use gaseous, liquid, or solid CO2 (excluding enhanced oil and gas recovery); see the General Technical 

Support Document for Injection and Geologic Sequestration of Carbon Dioxide—Appendix A in the docket to the Proposed 

Appendix F. Applicability of Selected Environmental Laws to the Storage Phase of CCS F-3 
 

Under EPA’s regulations, generators of solid waste are required to determine whether their 

wastes are hazardous wastes.25 A solid waste is a hazardous waste if it exhibits any of four 

characteristics of a hazardous waste (ignitability, corrosivity, reactivity, or toxicity),26 or is a 

listed waste27 (these include various used chemical products, byproducts from specific 

industries, or unused commercial products). 

CO2 is not a listed RCRA hazardous waste. From current technical knowledge, it is unlikely to 

exhibit the characteristics of ignitability, reactivity, or corrosivity at the point of capture or 

compression or injection for permanent storage. CO2 captured from sectors amenable to CCS 

could contain toxic chemical constituents such as arsenic, mercury, and selenium (IPCC, 2005; 

Apps, 2006). Whether a particular CO2 stream is a hazardous waste based on toxicity will 

depend on whether it contains one or more specific chemical constituents at levels above the 

toxicity characteristic concentrations in Table 1 of 40 C.F.R. § 261.24(b). EPA stated in the 

proposed UIC CCS regulation, 73 Fed. Reg. at 43503, that it “cannot make a categorical 

determination as to whether injected CO2 is hazardous under RCRA.” (EPA could make a 

categorical determination through the rulemaking process.) EPA noted that “[t]he composition 

of the captured CO2 stream will depend on the source, the flue gas scrubbing technology for 

removing pollutants, additives, and the CO2 capture technology. In most cases, the captured 

CO2 will contain some impurities, however, concentrations of impurities are expected to be 

very low.”28 Should a facility adjust its processes to create a solid waste that does not contain 

chemical constituents at levels above the toxicity characteristic concentrations in Table 1 of 40 

C.F.R 261.24(b), such waste stream likely would not be subject to Subtitle C requirements as a 

RCRA hazardous waste. 

In response to that proposal, EPA received comments asking for clarification of how RCRA 

hazardous waste requirements apply to CO2 streams. EPA is planning a proposed rule under 

RCRA to explore a number of options. Among the options under consideration by EPA is the 

development of a “conditional exemption” from RCRA requirements for hazardous CO2 

streams in order to facilitate implementation of CCS while protecting human health and the 

Rule for Mandatory Reporting of Greenhouse Gases: Injection and Geologic Sequestration of Carbon Dioxide (75 Fed. 

Reg.18576). However, while there might be limited commercial uses for captured CO2, such as in food and 

beverage manufacturing, pulp and paper manufacturing, the rubber and plastic industry, fire suppression, and 

refrigeration and cooling, no market is expected to develop for re-use of stored CO2 in the regulatory time frame 

and the amounts at which CO2 storage should occur on national scale-up of the CCS program. 

23 For purposes of this report, it is assumed that the CO2 is captured from one source and transported to a 

permanent storage site. On scale-up of a national CCS program, it is possible that different waste streams of CO2 

may be combined for transport to a storage site or sites. Depending on the nature of the CO2 streams being 

mixed, the resultant mixture may contain different co-constituents at different concentrations, and may need to be 

re-evaluated. This is a highly fact-specific analysis, which we merely flag for purposes of this report. 

24 40 C.F.R. §§ 261.2(a)(1)-(2), (b)(1). 

25 40 C.F.R. § 262.11. 

26 40 C.F.R. §§ 261.20-.24. 

27 40 C.F.R. §§ 261.30-.33. 

28 73 Fed. Reg. at 43503. 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage F-4 
 

 

environment. EPA has created “conditional exemptions” in the past defining waste as hazardous 

only if it is not managed pursuant to specified conditions.29 

F.4 Comprehensive Environmental Response, Compensation, and 

Liability Act (CERCLA) 

CERCLA may apply to certain releases from a CO2 storage site. CERCLA § 104(a), 42 U.S.C. § 

9604(a), authorizes the President to respond to a release or substantial threat of release of 

hazardous substances, or pollutants or contaminants that present an imminent and substantial 

danger into the environment. Under § 101(22), 42 U.S.C. § 9601(22), “release” is broadly 

defined and includes “any spilling, leaking, pumping, pouring, emitting, emptying, discharging, 

injecting, escaping, leaching, dumping, or disposing into the environment . . . .” Under § 101(8), 

42 U.S.C. § 9601(8), “environment” is broadly defined and includes surface water, ground 

water, land surface or subsurface strata, and ambient air within the United States or under the 

jurisdiction of the United States. Under §101(14), 42 U.S.C. § 9601(14), “hazardous substance” 

is any substance EPA has designated under specified provisions of the Clean Air Act, the Clean 

Water Act, the Toxic Substances Control Act, and the Resource Conservation and Recovery 

Act. EPA may also designate additional substances as hazardous substances under CERCLA. 

EPA maintains and updates a list of hazardous substances in 40 C.F.R. Part 302. Under § 

101(33), 42 U.S.C. § 9601(33), “pollutant” or “contaminant” is any other substance not on the 

list of hazardous substances that “will or may reasonably be anticipated to cause” adverse 

effects in organisms or their offspring. 

There are four elements necessary to establish liability under CERCLA § 107(a) 42 U.S.C. § 

9607(a): (1) there must be a release or threatened release of a hazardous substance, (2) the 

release must occur at or from a facility,30 (3) the release must cause the plaintiff to incur 

response costs not inconsistent with the National Contingency Plan, and (4) the defendant must 

fall within one of the four categories of responsible persons. See Young v. United States, 394 F.3d 

858, 862 (10th Cir. 2005). Liability under CERCLA is strict without regard to fault. Liability is 

also generally joint and several, which means that any one responsible party can be held liable 

for cleanup costs even if other parties are also responsible for the release, unless the 

responsible party can show that the harm is divisible. As is common under CERCLA, there is 

no statutory or regulatory exclusion for CCS activities, and it is this potential liability that has 

raised concern about the viability of CCS projects. 

Based on information we have to date on the potential chemical composition of the injectate, it 

appears that under likely capture scenarios the injectate will contain hazardous substances (e.g., 

arsenic and selenium). CO2 storage projects almost certainly fall within the definition of a 

facility.31 Current owners and operators of CO2 storage projects, past owners or operators at 

29 See, e.g., Military Toxics Project v. EPA, 146 F.3d 948 (D.C. Cir. 1998). 

30 The terms “release” and “facility” are defined broadly in the statute and can be found at CERCLA §§ 101(22) and 

101(9), respectively, 42 U.S.C. § 9601(22) and (9) (see above). 

31 CERCLA defines the term “facility,” inter alia, as “any site or area where a hazardous substance has been 

deposited, stored, disposed of, or placed, or otherwise come to be located . . . .” CERCLA § 101(9), 42 U.S.C. § 

9601(9). 

Appendix F. Applicability of Selected Environmental Laws to the Storage Phase of CCS F-5 
 

the time of disposal, persons who arranged for the disposal of injectate at a storage project, and 

persons who transported captured CO2 to a storage project are subject to liability under 

CERCLA if a plaintiff were to incur cleanup costs responding to a release of hazardous 

substances at or from the facility. Consequently, CERCLA liability could apply, unless such 

persons could establish a defense. Moreover, if CO2 released to groundwater caused the 

additional release of hazardous substances, such as heavy metals, from adjacent substrata, then 

the owner of that “facility” (the substrata) could be considered a facility owner under CERCLA 

§ 107(a)(1), 42 U.S.C. § 9607(a), who might become liable for any response costs caused by that 

release. 

One potential defense for CCS project owners and operators is to argue that the injectate 

qualifies as a “Federally permitted release” under CERCLA § 101(10)(G), 42 U.S.C. § 

9601(10)(G). Permits issued under the underground injection control program could qualify for 

an exception to CERCLA liability under CERCLA § 107(j), 42 U.S.C. § 9607(j). Courts, 

however, have applied the exception narrowly. Liability protection applies to releases that 

occur under a finalized permit, within the scope of the language and limits of the permit, and 

during the time the permit is valid. Releases which occur outside of a permitted area would 

likely not qualify for the exception.32 Accordingly, permits that define the permitted area 

broadly to include the entire subsurface that CO2 is reasonably expected to occupy through 

migration would provide for the broadest application of the “Federally permitted release” 

exclusion. 

There are no regulatory options for exempting CCS projects from CERCLA liability. Because 

the term “hazardous substance” is broadly defined in CERCLA § 101(14), 42 U.S.C. § 9601(14), 

CO2 injectate would still be considered a hazardous substance even if regulatory exemptions 

are created under other statutes, such as RCRA. In other words, if the injectate were to be 

conditionally exempt under RCRA, but still contained hazardous substances listed in 40 C.F.R. 

Part 302, the injectate would still be potentially subject to CERCLA response actions and 

potential liability. Accordingly, absent qualifying as a Federally permitted release, some kind of 

statutory change would be required if a policy decision were made that a CERCLA exemption 

for CO2 injectate would be appropriate. 

CO2 injectate could also be subject to release reporting requirements under CERCLA § 103(a), 

42 U.S.C. § 9603(a), which serves to alert Federal authorities so they may make a timely 

evaluation of whether a response action is needed. There is, however, an exception for 

Federally permitted releases. 

32 At least one court has found that seepage from permitted tailings ponds into an underlying aquifer did not fall 

within the scope of the permit for the tailings ponds. United States v. United Nuclear Corp., 814 F. Supp. 1552, 1564­

65 (D.N.M. 1992). The court found that the permits were clear and did not authorize the seepage, even though 

the permit holders and the regulatory authorities knew there would be some seepage. Id. 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage F-6 
 

F.5 Emergency Planning and Community Right-To-Know Act 

(EPCRA) 

If EPA interprets “facility” to include the subsurface injection site, EPCRA would impose 

emergency planning requirements. Release reporting requirements might apply to certain 

releases outside the facility or outside the scope of a Federal permit. 

In general, EPCRA establishes release reporting requirements and emergency planning 

requirements for hazardous substances (HS) listed in 40 C.F.R. § 302.4 and extremely 

hazardous substances (EHS) listed in 40 C.F.R. Part 355 App. A, B. Based on information we 

have to date on the chemical composition of the injectate, it appears that under likely capture 

scenarios the injectate will contain both HS and EHS. How these hazardous substances are 

treated for release reporting and emergency planning purposes will depend on what is 

considered as the CCS “facility.”33 Release reporting and planning requirements will differ 

depending on whether the agency interprets the facility to include only the structures on land 

surface, or whether the facility also includes the subsurface injection site. 

EPCRA § 304, 42 U.S.C. § 11004, requires the owner or operator of a facility to notify State 

and local authorities of unpermitted releases into the environment of a reportable quantity 

(RQ) of an HS or EHS. Releases that occur solely within the facility boundaries or that are 

Federally permitted are exempt from having to report. If the agency chooses to interpret the 

EPCRA facility as including the subsurface injection site, release reporting under EPCRA § 304 

would not be required if the release does not cross the facility boundaries. Release reporting 

would be required if the release crossed the facility boundaries, the release was not Federally 

permitted, and the amount of HS or EHS in the CO2 injectate exceeded the RQ. 

EPCRA § 302, 42 U.S.C. § 11002, requires the owner or operator of a facility to provide a onetime written notification to State and local authorities of an EHS present at the facility at any 

one time in amounts equal to or greater than the threshold planning quantity (TPQ) for that 

substance. If the agency chooses to interpret the EPCRA facility as including the subsurface 

injection site, emergency planning requirements would apply under ECPRA § 302 if the amount 

of EHS in the CO2 injectate exceeded the TPQ. 

There is no exclusion for CCS projects from EPCRA reporting requirements. If a policy 

decision were made that an exemption would be appropriate, EPA could explore the possibility 

of a regulatory exemption as it did for radionuclides in 40 C.F.R. § 355.40. 

F.6 Clean Air Act (CAA) 

The CAA’s nonattainment new source review (NSR) and prevention of significant deterioration 

(PSD) preconstruction review programs may apply to some geologic sequestration facilities.34 

EPA has proposed a rule to require monitoring and reporting of CO2 injection and 

sequestration. 

33 EPCRA § 329(4), 42 U.S.C. § 11049(4). 

34 CAA §§ 173 and 165, 42 U.S.C. §§ 7503 and 7475. 

Appendix F. Applicability of Selected Environmental Laws to the Storage Phase of CCS F-7 
 

 

NSR applies to the emissions of any criteria pollutant for which an area is designated as 

nonattainment for a national ambient air quality standard (NAAQS); PSD applies to emissions of 

criteria pollutants in areas designated as in attainment of the NAAQS and of all other regulated 

pollutants (except those designated as “hazardous air pollutants” under § 112 of the CAA). 

Although CO2 is not currently a regulated air pollutant under the CAA, this will change once 

the standards in EPA’s Light-Duty Vehicle Rule take effect in 2011.35 At this time, the change in 

the regulatory status of CO2 is not anticipated to have a direct substantial impact on the PSD 

requirements applicable to geologic sequestration facilities. 

The question of whether either the NSR or PSD program would apply to a geologic 

sequestration facility will depend on the amount of potential air emissions from the equipment 

at the facility. A geologic sequestration facility with sufficient potential air emissions to trigger 

NSR or PSD would be required to obtain a permit before commencing construction. (For 

GHGs, EPA addressed the triggering threshold for PSD by issuing a rule exempting smaller 

sources of these pollutants from PSD permitting until at least 2016.36) An NSR or PSD permit 

would require the installation of state-of-the art pollution controls on emissions units at the 

geologic sequestration facility, such as compressors. In addition, under certain circumstances, 

permitting authorities might also consider whether controls on fugitive emissions of CO2, if any, 

would be appropriate as part of a PSD review; however, it is worth noting that a well-designed 

geologic sequestration facility is unlikely to have significant potential emissions of CO2. As a 

result, the CO2 sequestered underground at such a facility would not normally trigger PSD 

review or be subject to PSD control requirements. 

The NSR and PSD programs are generally implemented by the States, under an EPA-approved 

State Implementation Plan. A few States do not have approved PSD programs; in these areas, 

EPA or States acting under a delegation from EPA issue PSD permits. EPA is also the PSD 

permitting authority on tribal lands. The tribes may adopt PSD rules but none have done so 

thus far. For sources located offshore of the United States, the CAA requires certain sources 

located on the Outer Continental Shelf to obtain permits that meet the requirements of PSD. 

EPA is the permitting authority for these sources. 

EPA has also proposed to amend the Greenhouse Gases Reporting Program at 40 C.F.R. Part 

98, issued under the authority of CAA § 114, 42 U.S.C. § 7414, to add reporting and 

recordkeeping requirements for owners and operators of facilities that conduct injection and 

geologic sequestration of CO2.

37 Facilities that conduct geologic sequestration would be 

required to develop and implement an EPA-approved site-specific monitoring, reporting, and 

verification plan; and to annually report the amount of CO2 sequestered, by subtracting total 

CO2 emissions (such as the amount if any leaked to the surface or vented from surface 

equipment) from the CO2 injected in the reporting year. 

35 75 Fed. Reg. 17004 (April 2, 2010). 

36 75 Fed. Reg. 31514 (June 3, 2010). 

37 75 Fed. Reg. 18576. 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage F-8 
 

Appendix G. Applicability of the National Environmental 

Policy Act, the Endangered Species Act, and the National 

Historic Preservation Act to Carbon Capture and Storage 

Activities 

The purpose of this paper is to discuss the potential applicability of the National Environmental 

Policy Act (NEPA), 42 U.S.C. §§ 4321-4370h, the Endangered Species Act (ESA), 16 U.S.C. §§ 

1531-1544, and the National Historic Preservation Act (NHPA), 16 U.S.C. §§ 470-470x-6, to 

CCS activities. This paper also discusses requirements under State NEPA statutes that can 

affect CCS deployment efforts. 

G.1 The National Environmental Policy Act 

G.1.1 The Role of NEPA 

The two main goals of NEPA are to inject environmental considerations into the Federal 

agency’s decision-making process and to inform the public of the environmental information 

that a Federal agency has considered.38,39 NEPA requires agencies to identify and assess 

alternatives to proposed actions that avoid or mitigate adverse environmental impacts. Thus, 

NEPA serves as a basis for transparency in Federal government decisions and is an essential 

part of engaging the public in a collaborative process that ultimately leads to greater public 

awareness and better agency decisions that reflect an understanding of environmental 

consequences. The NEPA process provides multiple and meaningful opportunities for public 

engagement. For example, during the process by which the scope of the issues and alternatives 

to be examined in an Environmental Assessment or Environmental Impact Statement (EIS) is 

determined, there can be many public meetings with local communities and stakeholders. 

Moreover, the public has an opportunity to comment on environmental documents. 

G.1.2 Environmental Review is Required when there is a “Major Federal 

Action” 

NEPA requires agencies to prepare an EIS for “every recommendation or report on proposals 

for legislation and other major Federal actions significantly affecting the quality of the human 

environment.”40 Although NEPA itself does not define “Federal actions,” the regulations 

promulgated by the Council on Environmental Quality (CEQ) to implement NEPA define a 

“major Federal action” as an action that is “potentially subject to Federal control and 

38 See Dep’t of Transp. v. Pub. Citizen, 541 U.S. 752, 768 (2004); Citizens Against Rails-to-Trails v. Surface Transp. Bd., 

267 F.3d 1144, 1151 (D.C. Cir. 2001). 

39 For more information on the stages of a NEPA analysis, see (see Council on Environmental Quality, 2007).
 

40 42 U.S.C. § 4332(2)(C); see 40 C.F.R. § 1502.3.
 

Appendix G. Applicability of NEPA, ESA, and NHPA to CCS Activities G-1 
 

 

 

responsibility.”41 In contrast, where an agency lacks discretion to affect the environmental 

outcome of its actions, there is no “major Federal action” triggering NEPA.42 

Although non-Federal projects are normally not subject to NEPA, they may be “major Federal 

actions” if they are “entirely or partly financed, assisted, conducted, regulated, or approved by 

Federal agencies.”43 Such actions may include approval of specific projects or private actions 

approved by permit or other regulatory decision.44 “No litmus test exists to determine what 

constitutes ‘major Federal action.’”45 Ultimately, for a non-Federal project to become a major 

Federal action, the Federal agency must have some measure of control over the 

environmentally pertinent aspects of a non-Federal project, some “ability to influence or 

control the outcome [of the project] in material respects.”46 

G.1.2.1 Federal CCS Activities That Require Preparation of a NEPA Document 

Use of Federal lands for the purposes of CO2 pipeline siting or storage will require NEPA 

analysis. The first NEPA analysis that may be considered is a Programmatic Environmental 

Impact Statement (PEIS) that would analyze the environmental impacts on a region-wide scale 

for either a pipeline corridor or network, or for regional CO2 storage. More specifically, CO2 

storage on Federal land will require amendment to the appropriate land use planning 

documents (i.e., National Forest Plans (Forest Plans) or Bureau of Land Management Resource 

Management Plans (RMPs)) to allow the use of Federal lands for such purpose. Amendment to 

Forest Plans or RMPs can be accomplished with a PEIS that would amend all plans within a given 

region. For example, one NEPA document can be prepared to amend the 11 forest plans 

applicable to National Forests within the Sierra Nevada mountain range. In some instances, a 

joint PEIS can be prepared between two or more agencies.47 As discussed below, consultation 

under the Endangered Species Act would likely be required for a PEIS, and could be an arduous 

and time-consuming endeavor where the area of analysis is large. Site-specific analysis under 

NEPA would still be required for specific pipeline or storage siting, but these site-specific NEPA 

documents may be somewhat streamlined by being able to “tier” off of the PEIS. The sitespecific NEPA documents will evaluate local conditions that might impact local resources, such 

as endangered or threatened species, requiring consultation under the ESA, or sites on the 

National Register of Historic Places, requiring analysis under the NHPA. 

41 40 C.F.R. § 1508.18. The NEPA regulations further indicate that the term “[m]ajor reinforces but does not have 

any meaning independent of significantly,” id., and thus does not go to whether an action is a “Federal” action 

triggering an agency’s NEPA obligations. 

42 See Surface Transp. Bd., 267 F.3d at 1151 (stating that NEPA is inapplicable if the information NEPA provides can 

have no affect on the agency’s actions). 

43 40 C.F.R. § 1508.18(a); Macht v. Skinner, 916 F.2d 13, 20 (D.C. Cir. 1990). 

44 See 40 C.F.R. § 1508.18(b)(4). 

45 Mineral Policy Ctr. v. Norton, 292 F. Supp. 2d 30, 54 (D.D.C. 2003) (citation omitted). 

46 Save Barton Creek v. Federal Hwy. Admin., 950 F.2d 1129, 1134 (5th Cir. 1992) (citation omitted); see also United 

States v. S. Fla. Water Mgmt. Dist., 28 F.3d 1563, 1572 (11th Cir. 1994) (“The touchstone of major Federal activity 

constitutes a Federal agency’s authority to influence non-Federal activity.”). 

47 See (Bureau of Land Management and Forest Service, 2010). 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage G-2 
 

 

 

 

Conducting a programmatic NEPA analysis is likely to be time-consuming, and that analysis 

should be commenced very early in the planning process for CCS. In fact, the law directs 

agencies to integrate the NEPA process into early planning efforts in order that appropriate 

NEPA analysis is performed and to reduce delay.48 A PEIS can require two or more years to 

prepare, and will involve public comment and substantial interagency coordination and analysis. 

Some examples of timelines for PEIS preparation, from scoping to publication of the Record of 

Decision, are as follows: 1.5 years for the Geothermal Resources Leasing PEIS (covering 11 

western States and Alaska);49 1.75 years for the Outer Continental Shelf Alternative Energy 

PEIS;50 2.25 years for the Implementation of a Wind Energy Development Program and 

Associated Land Use Plan Amendments PEIS (Wind Energy PEIS) (covering 11 western States 

and amending 52 BLM land use plans);51 and 3.25 years for the West-wide Energy Corridor PEIS 

(covering 11 States).52 Preparation of some PEISs can take close to six years depending on the 

details covered, the complexity of the program, and the existence of controversy about the 

program.53 

Once site-specific projects are identified, NEPA analysis for such a project will require 

additional time, on the scale of two or more years, depending on the complexity of the project 

and the significance of the impacts. Preparation of a PEIS can have substantial benefits, however, 

including streamlined site-specific environmental review, minimization of environmental effects, 

and better integration with land use plans and other environmental concerns. For example, a 

PEIS may identify areas of special concern and allow agencies to site pipelines or storage 

facilities to avoid significant known resources, threatened or endangered species, or other 

environmental or land use conflicts. A PEIS may also be used to support a program to promote 

certain policies, develop long-term systematic planning, establish mitigation strategies, and 

generally set the stage for potential site-specific actions that may have significant environmental 

impacts.54 

48 40 C.F.R. § 1501.1(a). 

49 See (Bureau of Land Management, 2010b). 

50 See (U.S. Department of the Interior, 2010). 

51 See (Bureau of Land Management, 2010c). 

52 See (Bureau of Land Management et al., 2010). 

53 See e.g., (Bureau of Land Management, 2010a). 

54 The Wind Energy PEIS provides an example of how region-wide planning can work to streamline site-specific 

review: 

[The PEIS ]. . . establish[es] policies and BMPs [Best Management Policies] to address the 

administration of wind energy development activities and identify minimum requirements for 

mitigation measures. These programmatic policies and BMPs will be applicable to all wind energy 

development projects on BLM-administered public lands. Site-specific concerns and speciesspecific concerns, and the development of additional mitigation measures, would be addressed in 

project-level reviews, including NEPA analyses, as required. To the extent appropriate, future 

project-specific analyses will tier from the analyses conducted in the PEIS and the decisions in the 

resultant Record of Decision (ROD) to allow project-specific analyses to focus just on the 

critical, site-specific issues of concern. In addition, under this alternative, a number of BLM land 

Appendix G. Applicability of NEPA, ESA, and NHPA to CCS Activities G-3 
 

 

 

If such an analysis is conducted early, it may provide an opportunity to further clarify many of 

the issues discussed in the present set of reports and analyses. On the other hand, attempting 

to conduct such an analysis late in the planning process would undercut the utility of the NEPA 

process and could cause delays in the implementation of CCS. 

NEPA review may potentially be streamlined by the use of a categorical exclusion. A categorical 

exclusion can apply when an agency has determined that certain actions “do not individually or 

cumulatively have a significant effect.”55 A categorical exclusion, however, does not exempt a 

project completely from environmental review; an agency still must review for “extraordinary 

circumstances” that could remove a project from the categorical exclusion if a normally 

excluded action may have significant environmental effects.56 At this stage, because of the 

novelty of many CCS activities, an agency is not likely to have an existing categorical exclusion 

that could be used. Establishment of a new categorical exclusion by an agency (performed in 

conjunction with the CEQ) would include developing a basis for the exclusion and gathering 

information to substantiate it.57 

G.1.2.2 Private CCS Activities That May Trigger the Federal Government’s NEPA 

Obligations 

Private activities may not necessarily be exempt from the NEPA process. A private project that 

receives some sort of assistance from the Federal government could, in some circumstances, 

trigger the Federal government’s NEPA obligation.58 Some Federal activities that may trigger the 

government’s NEPA obligations can include providing loans, loan guarantees, grants, or other 

forms of Federal financial assistance for the design or construction of CCS facilities, approval of 

permits or rights-of-way for pipeline and/or storage facilities either on Federal or Tribal land 

held in trust by the United States, approval of a permit required by statute or regulation for 

CO2 transport or storage on private land.59 Additionally, the transfer of land to another entity 

for the purposes of CCS activities may require NEPA review. 

The question of when a private activity becomes “Federalized” (i.e., becomes a major Federal 

action) is a very complex area of law, and one that is frequently litigated. Ultimately, resolving 

the question requires a fact-intensive analysis and the question of whether a private project has 

use plans will be amended to address wind energy development, including adoption of the 

programmatic policies and BMPs and identification of exclusion areas. 

(Bureau of Land Management, 2006). 

55 40 C.F.R. § 1508.4. 

56 Id. 

57 CEQ’s draft memorandum provides guidance on applying existing or establishing new categorical exclusions. See 

(Council on Environmental Quality, 2010). 

58 40 C.F.R. § 1508.18. 

59 Some permitting activities may be exempt from NEPA where a statute or regulation provides for a similar 

environmental review process and public participation. For example, a Safe Drinking Water Act underground 

injection control permit for CO2 storage approved by EPA would not require preparation of a NEPA document by 

EPA. 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage G-4 
 

 

become Federalized can turn on very specific circumstances. Therefore, each situation must be 

evaluated independently. Agencies should carefully consider their involvement in non-Federal 

projects to determine whether their NEPA obligations may be triggered. 

G.1.3 Specific NEPA Considerations for Environmental Review of CCS 

Projects 

Because of the complexity and novelty of CCS, NEPA may present a formidable challenge to 

agencies in dealing with uncertainty in science and risk assessment, missing information, and 

consideration of new risks to human welfare or the environment from the deployment of CCS. 

Potential impacts that may need to be evaluated include: impacts to human and animal life or 

the environment from the direct release of CO2 in the air or ocean, impacts to underground 

water supplies from migration of CO2, induced seismicity from the storage of CO2, and impacts 

to the climate if accidental release occurs. In addition, there will also be challenges in 

determining the cumulative impacts of CCS projects, what direct and indirect effects are 

reasonably foreseeable, and the scope of the analysis area. These challenges occur in the 

context of NEPA’s express requirement that the information used to write an EIS must be of 

high quality and the scientific analysis must be accurate and sound, conditions that can be 

difficult to attain in the arena of emerging and developing technological systems. Agencies 

should consider the NEPA document as a way to inform the public on the relative risks and 

benefits of a new and unfamiliar technology and promote its acceptance. Refusal to address 

such issues will only serve to undermine the credibility of the agency and the technology. 

The CEQ regulations implementing NEPA specify an agency’s obligations in the event of 

incomplete or unavailable information. First, the agency must make it clear that information is 

lacking. If the missing information is “essential to a reasoned choice among alternatives,” an 

agency must obtain the information unless “the overall costs of obtaining it are exorbitant or 

the means to obtain it are not known.”60 If the agency cannot obtain the information because it 

is too costly or the means are unknown, then the agency must include in the NEPA document: 

(1) a statement that such information is incomplete or unavailable; (2) a 

statement of the relevance of the incomplete or unavailable information to 

evaluating reasonably foreseeable significant adverse impacts on the human 

environment; (3) a summary of existing credible scientific evidence which is 

relevant to evaluating the reasonably foreseeable impacts on the human 

environment; and (4) the agency’s evaluation of such impacts based upon 

theoretical approaches or research methods generally accepted in the scientific 

community.61 

Uncertainty in science and risk assessment may present itself when an agency lacks precise key 

data or estimates, when there is an incomplete knowledge of system dynamics, or when 

evaluating the probability of credible catastrophic outcomes. Prior NEPA documents 

inadequately confronting issues of uncertainty provided a forum to learn from past mistakes and 

60 See 40 C.F.R. § 1502.22. 

61 Id. § 1502.22(b). 

Appendix G. Applicability of NEPA, ESA, and NHPA to CCS Activities G-5 
 

 

 

 

understand how uncertainty should be honestly assessed not simply for a legally sufficient NEPA 

document, but also for a NEPA document that will be acceptable to the public.62 When risk is 

unclear, there should be a candid discussion of the range of risk and a delineation of the 

uncertainties. Further, models, their assumptions, and their accuracy should be explained and 

disclosed. Ultimately, the NEPA document should provide an honest assessment of a projects 

risks and uncertainties and provide the public with the confidence that regulatory agencies have 

sufficiently addressed legitimate public concerns. 

G.2 The Endangered Species Act 

The ESA may also impose certain requirements on CCS development. 

G.2.1 The Role of the ESA in CCS 

In 1973, Congress enacted the ESA “to provide a means whereby the ecosystems upon which 

endangered species and threatened species depend may be conserved, [and] to provide a 

program for the conservation of such endangered species and threatened species....”63 

As relevant to CCS, Section 7 of the ESA outlines the procedures for Federal interagency 

cooperation to conserve Federally listed species and designated critical habitats. Section 7(a)(1) 

directs the Secretary (Secretary of the Interior/Secretary of Commerce) to review other 

programs administered by them and utilize such programs to further the purposes of the ESA. 

It also directs all other Federal agencies to utilize their authorities in furtherance of the 

purposes of the ESA by carrying out programs for the conservation of species listed pursuant 

to the ESA. 

Section 7(a)(2) of the ESA requires each Federal agency to ensure that any action authorized, 

funded, or carried out by that agency “is not likely to jeopardize the continued existence of any 

endangered species or threatened species” or “result in the destruction or adverse 

modification” of designated critical habitat.64 To achieve this objective, the agency proposing the 

action is required to consult with the U.S. Fish and Wildlife Service (USFWS) or the National 

Marine Fisheries Service (NMFS) (collectively, the Services) whenever a Federal action “may 

affect” a threatened or endangered species.65 In fulfilling these requirements, each agency must 

use the best scientific and commercial data available.66 

G.2.2 Consultation is Required when there is a “May Affect” Determination 

ESA consultation will be determined by the presence of endangered or threatened species in 

specific project areas. If a determination is made that the action “may affect” listed species, the 

action agency must pursue some form of consultation (“informal” or “formal”) with either the 

62 For a full discussion, see (Farber, 2009). 

63 16 U.S.C. § 1531(b). 

64 16 U.S.C. § 1536(a)(2). 

65 50 C.F.R. § 402.14(a). 

66 16 U.S.C. § 1536(a)(2). 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage G-6 
 

 

 

 

 

 

Service or NMFS depending on the species involved. The action agency may prepare a biological 

assessment (BA) to evaluate the potential effects of a proposed action.67 

BAs are required if an agency is proposing to engage in a “major construction activity,”68 

although agencies often prepare them voluntarily as a convenient mechanism to facilitate the 

consultation. 

As part of a formal consultation process, the consulting agency will issue a biological opinion 

detailing how the proposed action will affect the listed species.69 

If the USFWS or NMFS determines that the proposed action is likely to jeopardize the species, 

it must develop reasonable and prudent alternative actions that the Services believe the agency 

or the applicant may take to avoid the likelihood of jeopardy to the species or destruction or 

adverse modification of designated critical habitat.70 

If the USFWS or NMFS determines that the proposed action—whether standing alone or as 

modified by a reasonable and prudent alternative—is not likely to jeopardize the species, but 

may result in the incidental “take”71 of individuals of the species, the consulting agency provides 

an incidental take statement (ITS) along with the biological opinion.72 The ITS must specify the 

impact of the incidental taking on the species and specify those reasonable and prudent 

measures that the USFWS or NMFS considers “necessary or appropriate to minimize such 

impact.”73 “[A]ny taking that is in compliance with the terms and conditions specified in a 

written [ITS]... shall not be considered to be a prohibited taking of the species concerned.”74 

G.2.2.1 Federal CCS Activities That Require Preparation of an ESA Document 

Where there is an effect on ESA listed species, use of Federal lands for the purposes of CO2 

pipeline siting or storage requires ESA consultation, which can be undertaken in conjunction 

with NEPA obligations. The use of programmatic consultations, however, described in 

subsection A.2.i. above, may present additional challenges in the ESA context. As opposed to 

individual, site-specific projects, a programmatic plan, for example, establishing a national plan 

for the development of CCS infrastructure, would involve an “action” that is extremely broad. 

Moreover, concrete and on-the-ground effects would not be readily apparent or even existent 

until particular projects or actions are proposed pursuant to the programmatic decision. Thus, 

the effects of the action—which may cover the entire United States—may be difficult to assess 

67 50 C.F.R. § 402.12(a). 

68 50 C.F.R. § 402.12(b). 

69 16 U.S.C. § 1536(b)(3)(A). 

70 50 C.F.R § 402.14(h)(3). 

71 The term "take" means to "harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt to 

engage in any such conduct." 16 U.S.C. § 1532(19). 

72 16 U.S.C. § 1536(b)(4)(i)-(ii). 

73 Id. 

74 Id. at § 1536(o)(2). 

Appendix G. Applicability of NEPA, ESA, and NHPA to CCS Activities G-7 
 

 

 

at a level that is more than theoretical and speculative. The precise circumstances in which ESA 

consultation is required in such contexts are not entirely clear, but courts have required 

consultation and issuance of an ITS in some situations.75 If a programmatic consultation is 

undertaken, site-specific consultations, as in the NEPA context, may be somewhat more 

efficient by being able to be tiered off of the programmatic consultation documents. 

As with NEPA, obligations under the ESA may vary depending on the level of Federal 

involvement, and whether the agency has any discretion, pursuant to a relevant statute, to take 

measures to benefit the protected species.76 Even if the government has sufficient discretion, 

where projects involve non-Federal actors, the issue would be whether Federal participation 

transforms a project into a Federal action. This matter is complex and is frequently litigated; a 

court has said that it “is simply one of degree,”77 but the relevant analysis is not always 

straightforward. One key element is the degree of the Federal agency’s control over the 

environmentally pertinent aspects of the project to require ESA consultation.78 

G.2.3 Private CCS Activities That Trigger the Government’s ESA 

Obligations 

For ESA consulting responsibilities to be triggered, there also would have to be a causal link 

between an agency’s decisions and effects to listed species. While the ESA Section 7(a)(2) does 

not require Federal agencies to protect listed species or critical habitat from harms caused by 

third-party actors, seemingly private activities may not be exempt from the ESA. 

That said, private activities that could trigger the government’s ESA obligation would be similar 

to the triggers in a NEPA context: where the government providing loans, loan guarantees, 

grants, or other forms of Federal financial assistance for the design or construction of CCS 

75 See Center for Biological Diversity v. FWS, 623 F. Supp. 2d 1044, 1053 (N.D. Cal. 2009) (holding that “a 

programmatic forest plan does have an effect upon subsequent land use decisions and therefore upon the land 

itself,” and thus is the cause of incidental take that must be covered by an ITS); see also Natural Resources Def. 

Council v. Evans, 364 F. Supp. 2d 1129 (N.D. Cal. 2003) (holding that NMFS was required to issue an ITS in a 

programmatic consultation on the Navy’s potential use of sonar in as much as 75 percent of the world’s oceans); 

but see Western Watersheds Project v. BLM, 552 F. Supp. 2d 1113 (D. Nev. 2008) (upholding FWS programmatic 

BiOp and finding “no error in the failure of [FWS] to issue an ITS”); Arizona Cattle Growers Ass’n v. FWS, 273 F.3d 

1229, 1233 (9th Cir. 2001) (rejecting the notion that an ITS must accompany every BiOp and holding instead that 

“an Incidental Take Statement must be predicated on a finding of incidental take”). 

76 An agency is required to consult only on actions where it has discretion to implement measures that inure to 

the benefit of protected species. The purposes underlying the relevant statute must allow the agency to consider 

protected species. National Ass’n of Home Builders (NAHB) v. Defenders of Wildlife, 551 U.S. 644, 671-72 (2007); 

Turtle Island Restoration Network v. Nat’l Marine Fisheries Service, 340 F.3d 969, 975 (9th Cir. 2003). In other words, 

the consultation requirement of Section 7(a)(2) of the ESA “covers only discretionary agency actions and does not 

attach to actions . . . that an agency is required by statute to undertake once certain specified triggering events 

have occurred.” NAHB, 551 U.S. at 669. Accordingly, if a new CCS statute dictated that a Federal agency’s only 

role in reviewing CCS permit applications was to ensure certain criteria were met, and the government had no 

discretion, ESA consulting obligations would be less likely to apply. 

77 Ka Makani ‘O Kohala Ohana, Inc. v. Water Supply, 295 F.3d 955, 960 (9th Cir. 2002) (citation omitted). 

78 See Sierra Club v. Babbitt, 65 F.3d 1502, 1512 (9th Cir. 1995) (ESA not triggered where Bureau of Land 

Management could not control development activity under a right-of-way agreement). 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage G-8 
 

 

 

 

facilities; approval of a permit or right-of-way for pipeline and/or storage facilities either on 

Federal or Tribal land held in trust by the United States; or CO2 transport or storage on 

private land if a permit is required by statute or regulation for such activities). 

Finally, the ESA also imposes certain requirements on private actors. For example, the Act 

makes it unlawful for anyone, including a private party, to “take” any species listed under the act 

without first obtaining a permit.79 Therefore, even if a CCS project were to be found not to 

impose Section 7(a)(2) Federal consultation requirements, a private developer would likely still 

consider a project’s potential effects on any listed species as part of its planning. 

G.2.4 Specific ESA Considerations for Environmental Review of CCS 

Projects 

As detailed above, the complexity and novelty of CCS may present a formidable challenge to 

agencies in dealing with uncertainty in science and risk assessment, missing information, and 

consideration of new risks to human welfare or the environment from the deployment of CCS. 

Under the ESA, however, the government cannot await perfect information, but must act 

instead upon “the best scientific and commercial data available.”80 

To that end, the presence of scientific uncertainty, or the fact that evidence may be “weak,” is 

not fatal to an agency’s consultation decision.81 Here, the government would need to evaluate 

even “novel” harms that may befall threatened and endangered species.82 As with NEPA, 

evaluating these uncertainties and risks and informing decision makers and the public may be 

challenging; however, the ESA imposes substantive requirements to avoid likely jeopardy to 

listed species and the adverse modification of critical habitat, and the refusal to address novel 

issues will leave actions vulnerable to legal attack and remand. 

With this in mind, the above NEPA considerations regarding the uncertainty in science and risk 

assessment should apply to ESA consultation (where necessary) as well. The use and limits of 

available science should be explained and disclosed. Assumptions should be supported, and the 

agency should discuss whether other models or other assumptions lead to different 

conclusions. Ultimately, as with the NEPA document, an ESA consultation should provide an 

honest assessment of a project’s risks and uncertainties. 

79 16 U.S.C. § 1538. 

80 Building Indus. Ass’n v. Norton, 247 F.3d 1241, 1246 (D.C. Cir. 2001) (“the Service must utilize the ‘best scientific 

... data available,’ not the best scientific data possible.”). 

81 Greenpeace Action v. Franklin, 14 F.3d 1324, 1337 (9th Cir. 1992) (upholding biological opinion, despite uncertainty 

about the effectiveness of management measures, because decision based on a reasonable evaluation of all available 

data). 

82 However, a causal connection, either directly or indirectly, between the proposed agency action and the effect 

on a listed species must be established. See National Wildlife Federation v. NMFS, 524 F.3d 917, 930 (9th Cir. 

2008); Arizona Cattle Growers' Association v. USFWS,273 F.3d 1229 (9th Cir. 2001). 

Appendix G. Applicability of NEPA, ESA, and NHPA to CCS Activities G-9 
 

 

 

G.3 Other Federal Regulatory Requirements 

CCS activities may trigger other Federal requirements. For example, the National Historic 

Preservation Act, similar to NEPA, requires Federal agencies to evaluate the impact of Federal 

actions on sites listed on, or eligible for, the National Register of Historic Places.83 

G.4 State NEPAs 

Fifteen States have enacted environmental policy acts similar to the Federal NEPA.84 While the 

Federal NEPA is procedural in nature, a number of State counterparts impose substantive 

requirements. For example, the California Environmental Policy Act requires that public 

agencies not approve projects if there are “feasible” alternatives; i.e., if the alternatives are 

“capable of being accomplished in a successful manner in a reasonable period of time, taking 

into account economic, environmental, social, and technological factors.”85 Moreover, different 

types of State action trigger the State NEPA process, and the particular State agencies covered 

by the legislation vary.86 Because currently CO2 pipeline and siting decisions are authorized and 

permitted by States, environmental review through various State NEPAs more frequently 

occurs than Federal NEPA review. If CCS becomes a project national in scope (i.e., through 

inter-state pipelines), a uniform environmental review process may be more desirable. 

83 16 U.S.C. §§ 470-470a-2. 

84 Arkansas, Ark. Stat. Ann. § 8-1-101; California, Cal. Pub. Res. Code §§ 21000 et seq.; Connecticut, Conn. Gen. 

Stat. Ann. §§ 22a-14 et seq.; Florida, Fla. Stat. §§ 380.92 et seq.; Hawaii, Haw. Rev. Stat. §§ 343-1 et seq.; Indiana, Ind. 

Code Ann., §§ 6-981 et seq.; Maryland, Md. Nat. Res. Code Ann. §§ 1-301 et seq.; Massachusetts, Mass. Gen. Laws 

Ann. ch. 30, §§ 61 et seq.; Minnesota, Minn. Stat. Ann. §§ 116D.01 et seq.; Montana, Mont. Code Ann. §§ 75-1-101 et 

seq.; New York, N.Y. Envtl. Conserv. Law §§ 8-0101 et seq.; North Carolina, N.C. Gen. Stat. §§ 113A-1 et seq.; 

South Dakota, S.D. Codified Laws Ann. §§ 34A-9-1 et seq.; Virginia, Va. Code §§ 10.1-1200 et seq.; Washington, 

Wash. Rev. Code §§ 43-21C.010 et seq. 

85 Cal. Pub. Res. Code, § 21061.1. 

86 See Daniel Mandelker, NEPA Law and Litigation, § 12.01 (2d. ed. 1984). 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage G-10 
Appendix H. Potential Causes of Long-Term Storage Risk 

and/or Liability 

Potential causes of long-term storage and/or liability risk include the following: 

1.	 Scientifically understood phenomena. For example, migration of CO2 in 

scientifically understood ways as a result of high injection pressures.
 

2.	 Scientific uncertainties or unknown phenomena that would alter previous 

understandings about risks.
 

3.	 Operator error. For example, an operator misapplies monitoring technology and fails 

to detect migration of CO2, or an operator misuses injection equipment, which fails, and 

CO2 is released from the storage site. 

4.	 Regulatory mistake or oversight. For example, a State or Federal agency reviewing 

a permit application fails to detect a geological feature, or fails to identify migration of 

CO2 in monitoring data. 

5.	 Falsification and illegal conduct. For examples, a site operator falsifies geological 

data in order to obtain a permit; a site operator falsifies monitoring data in order to 

avoid the costs of remediation; or a site operator stores more CO2 than allowed under 

a permit to obtain the associated income stream. 

6.	 Policy changes. For example, a subsequent Administration withdraws funding for CCS 

activities, or the relevant legal framework changes, or a State ceases funding for a 

storage site. 

7.	 Acts of God. For example, an earthquake causes a release from a storage site. 

8.	 Judicial system error. For example, groundwater contamination develops near a 

storage site. The harm is not in fact caused by the site, but would have occurred even 

without the storage activity. A court nevertheless erroneously holds the site operator 

liable, for example on an ultrahazardous activity theory. 

Scope of this list. Note that the foregoing list of sources of long-term storage risk and/or 

liability only addresses risks and/or liabilities associated with storage activities. Capture and 

transportation risks are not included. Certain “garden variety” sources of risks associated with 

industrial activities that will occur at a storage site—such as injuries at the surface facility—are 

also excluded. 

Appendix H. Potential Causes of Long-Term Storage Risk and/or Liability H-1 

Appendix I. Price-Anderson Act Private Insurance Program 

The Price-Anderson Act (PAA) includes a private insurance program that may be adapted (with 

appropriate revisions) for insuring the risks of long-term storage of CO2 from CCS activities. It 

should be noted, however, that the main incentive for private insurers to offer the insurance 

mandated by the PAA may be the fact that the PAA caps the liability of nuclear plant operators 

at an amount equal to the limits of liability under applicable insurance policies. 

Under the PAA, the nuclear energy industry provides more than $10 billion in insurance 

coverage in the event of a nuclear incident. No portion is borne by the taxpayers or the 

Federal government. However, public utilities that operate nuclear reactors will generally be 

permitted by their regulators to include the cost of these insurance premiums in the costs of 

service borne by ratepayers. The PAA private insurance protection consists of two tiers: 

1.	 The primary level provides $375 million in liability insurance. This first-level coverage 

consists of the liability insurance provided by insurance pools. The pools are groups of 

insurance companies pledging assets that enable them to provide substantially higher 

coverage than an individual company could offer. If this amount is not sufficient to cover 

claims arising from a nuclear incident, secondary financial protection applies. 

2.	 For the second level, in the event of a nuclear incident, each nuclear plant must pay a 

retrospective premium equal to its proportionate share of the excess loss, up to a 

maximum premium of $117.5 million. In any single year, however, the premium for the 

second tier is capped at a ceiling set by the NRC; currently, that annual cap is $17 

million per incident. All 104 operating nuclear reactors in the United States are 

participating in the secondary financial protection program. 

If claims exceed the maximum Price-Anderson value (i.e., insurance coverage is exhausted), the 

private insurers have no further liability. In that event, the President is required to submit 

proposals to Congress. These proposals must detail the costs of the incident, recommend how 

funds should be raised, and detail plans for full and prompt compensation to those affected. If 

Congress fails to provide for compensation, claims can be made under the Tucker Act (in which 

the government waives its sovereign immunity), 28 USC § 1491, for failure by the Federal 

government to carry out its duty to compensate claimants. 

The NRC codifies the conditions for indemnity agreements, liability limits, and fees for the 

different classes of licensees in 10 C.F.R. § 140. Power reactors rated below 100 MWe, for 

example, have lower primary insurance requirements than larger reactors, while the financial 

protection required for nonprofit educational reactors is a function of their maximum power 

and the neighboring population. 

Appendix I. Price-Anderson Private Insurance Program I-1 

 

Appendix J. Governmental Indemnification 

The option of governmental indemnification is characterized by several legal and policy 

infirmities. First, as a matter of law, the United States may not agree to open-ended 

indemnification arrangements absent specific Congressional authorization. See Anti-Deficiency 

Act, 31 U.S.C. 1341(a)(1)(B). Such authorizations have rarely been granted because open-ended 

indemnification agreements by the United States could be very costly. Only in the most 

exceptional and necessary circumstances has such authorization been given. Given this past 

experience, it is doubtful that the circumstances surrounding CCS warrant this extraordinary 

step. 

Second, sound public policy and legislative precedent counsel that authority to indemnify should 

be strictly limited to activities of absolutely vital national security interests (military or 

otherwise) and then only when private insurance is unavailable. Authority to enter into openended indemnification agreements with contractors and other third parties generally has been 

narrowly confined to those areas in which procuring the goods or services has been deemed 

essential to the national defense, and private insurance cannot be obtained to protect against 

the potential liability (e.g., agreements indemnifying Department of Energy contractors for 

liability arising out of nuclear incidents, agreements indemnifying certain Department of Defense 

contractors). See Pub. L. 85-804 (codified as 50 U.S.C. § 1431-1435);87 the Price-Anderson Act, 

42 U.S.C. § 2210; and, generally, the discussion in Hercules Inc. v. United States, 516 U.S. 417, 

426-29 & n.11 (1996). 

Underlying these legislative exceptions and their implementing regulations has been the premise 

that not only is the activity essential to national security, but also that private markets cannot 

provide adequate insurance coverage in the event of a disaster. Executive Order 11610, which 

supplements Executive Order 10789 and further implements Public Law 85-804, instructs that: 

[i]n deciding whether to approve the use of an indemnification provision and in 

determining the amount of financial protection to be provided and maintained by 

the indemnified contractor, the appropriate official shall take into account such 

factors as the availability, cost and terms of private insurance, self-insurance, 

other proof of financial responsibility and workmen's compensation insurance. 

Exec. Order No. 11,610. 

J.1 Price Anderson Act Indemnification Provisions 

The Price-Anderson Act has two components: an insurance component that is discussed in 

Appendix I and an indemnification component that is discussed here. 

87 Pursuant to Public Law 85-804 and Executive Order 10789, the Federal Acquisition Regulations (FAR) provide 

detailed requirements that must be met when a government contractor seeks indemnification agreements. See 

FAR Extraordinary Contractual Actions Subpart 50.1, 48 C.F.R. pt. 50.1including C.F.R. § 50.104-3 (Special 

procedures for unusually hazardous or nuclear risks). See also, FAR Contracts with Commercial Organizations 

Subpart 31.2, 48 C.F.R. pt. 31.2; 48 C.F.R. § 31.205-19(e)(5); and FAR Indemnification Under Public Law 85-80448 

C.F.R. § 52.250-1. 

Appendix J. Governmental Indemnification J-1 
One approach to government indemnification is contained in a portion of the PAA dealing with 

the potential liability of public sector employees and private sector contractors who have been 

engaged by the DOE to conduct decommissioning and clean-up operations on former defense, 

government-owned sites. The PAA requires the Secretary to enter into indemnification 

agreements with any person who may conduct “activities” under a contract with DOE that 

involves risk of “public liability.” Both of these terms are broadly defined. 

The PAA indemnity applies to all contracts entered into with DOE involving a radiological risk. 

It covers both lump sum and cost-reimbursement type contracts, and includes contracts and 

projects financed in whole or in part by DOE. The indemnity applies regardless of where the 

activities occur, and covers a broad spectrum of activities ranging from contractors engaged in 

clean-up activities on a designated site to transporting nuclear materials to or from a site. It is 

enforced by means of a standard form indemnity clause incorporated into any applicable DOE 

contract. 

The indemnity expressly covers all claims for “public liability” within the meaning of the PAA, 

together with the contractor's legal costs and other costs covered up to a specified maximum 

amount. Coverage under the indemnity is automatically extended to any subcontractors 

engaged by the contractor, by means of a provision in the indemnity requiring the contractor to 

provide an equivalent indemnity in any contract that the contractor enters into with a 

subcontractor. 

“Public liability” is broadly defined in the PAA but does include some exceptions. Claims of 

employees of the contractor who are employed at the site of, and in connection with, the 

activity where the nuclear incident occurs who are covered by State or Federal workers’ 

compensation acts are not covered. There is also no right of recovery where a nuclear incident 

results from “acts of war,” and there is typically no carve-out under the indemnity for the 

contractor's negligence, willful or reckless misconduct. Thus contractors can benefit from 

protection regardless of fault. 

J.2 Indemnification History 

A number of claims have been filed in Federal district courts seeking recovery under the PAA 

since its 1988 amendments. Settlements have been paid in two cases that arose out of activities 

at the DOE Feed Material Production Center (FMPC) in Fernald, Ohio, conducted from the 

1950s to the 1980s. The cases were brought in the United States District Court for the 

Southern District of Ohio. 

In re Fernald Litigation was brought in 1985 by property owners and residents living near the 

facility and local businesses and their employees (excluding employees of the DOE facility 

contractor). Plaintiffs alleged causes of action for negligence, strict liability, private nuisance, 

willful and wanton misconduct, violation of the parent corporation’s contractual guaranty and 

violation of the PAA. Plaintiffs claimed damages for emotional distress and diminution in 

property values. The parties participated in a summary jury trial in 1989 in which the jury 

returned a verdict for the plaintiffs for $136 million, including $1 million for diminution in 

property, $80 million for a medical monitoring fund, and $55 million in punitive damages. The 

parties reached a settlement for $78 million that was paid by DOE. The DOE indemnity was 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage J-2 
 

 

cited as the authority for payment of the settlement. See In re Fernald Litigation, No. C-1-85-149, 

1989 WL 267039 (S.D. Ohio Sept. 29, 1989). 

Day v. NLO, Inc. was filed in 1990 by workers and frequent visitors of the FMPC facility. Some of 

the plaintiffs’ claims were dismissed because workers’ compensation provided the exclusive 

remedy for these claims. The court concluded that its jurisdiction to hear this case stemmed 

from the PAA and that the Act was the source of all the plaintiff’s claims. DOE eventually paid 

$20 million to settle this lawsuit. See Day v. NLO, Inc., 811 F. Supp. 1271 (S.D. Ohio 1992). 

J.3 Underlying Policy on Open-Ended Indemnification 

An open-ended indemnification approach is very dangerous, since it does not deal in any way 

with the “moral hazard” issue, and simply shifts all risks to Federal taxpayers. 

The Executive Branch’s longstanding view has been that waivers of the strictures of the AntiDeficiency Act should only be considered (and not necessarily approved) in situations in which 

essential activity will simply not be conducted absent a governmental agreement to indemnify. 

Further, our view has been that if there are to be agreements to indemnify, they should be 

governed by the constraints placed on contractors in the national defense arena, as set forth 

above.88 In addition, it would make sense for any indemnification to contain a sunset date or 

provide that the authority to develop indemnity agreements should expire on a date certain 

absent reauthorization, as in the PAA context. This would allow Congress to evaluate the 

continuing need for indemnity agreements based on the current state of the commercial CO2 

capture and storage market and availability of private insurance. Additionally, to protect the 

public, individual indemnification agreements should be subject to DOJ review.89 

88 The sorts of indemnification proposals that have been made thus far have defined “liability” that would trigger 

indemnification as essentially any harm to persons, property, or natural resources. Such an indemnity would not be 

limited to hazards unique to the CO2 capture and sequestration program; it could apply to injuries such as caused by 

traffic accidents in the course of the operations. Thus, any indemnification program should be limited to hazards unique 

to the program. There is also the potential that indemnity arrangements could be read to provide indemnification from 

natural resource damage claims by Federal trustees under section 107 of the Comprehensive Environmental Response, 

Compensation, and Liability Act (Superfund), 42 U.S.C. § 9607. This would be inconsistent with section 107(e), which 

prohibits indemnity agreements for actions under section 107. 

89 Section 330 of the National Defense Authorization Act of 1993, 10 U.S.C. § 2687 note (known as Section 330), 

provides that "the Secretary of Defense shall hold harmless, defend, and indemnify in full [certain] persons and entities . . 

. from and against any suit, claim, demand or action, liability, judgment, cost or other fee arising out of any claim for 

personal injury or property damage . . . that results from, or is in any manner predicated upon, the release or 

threatened release of any hazardous substance, pollutant or contaminant, or petroleum or petroleum derivative as a 

result of Department of Defense activities at any military installation (or portion thereof) that is closed pursuant to a 

base closure law.@ Pub. L. 102-484, Div. A, Title III, § 330, 106 Stat. 2371 (1992) (codified at 10 U.S.C. § 2687). This 

provision does not require the putative indemnitee to go through processes like those under Public Law 85-804. While 

Section 330 is precedent for blanket statutory indemnification, such steps should not be taken lightly or routinely. The 

legislative proposals offered last year in Congress did not provide a blanket statutory indemnification, but, rather simply 

would authorize the Secretary of Energy to enter into indemnification agreements. 

Appendix J. Governmental Indemnification J-3 

Appendix K. Liability Associated with DOE CCS RD&D 

Programs 

DOE is engaged in several programs aimed at promoting clean coal technologies and CCS. The 

major efforts include the Regional Carbon Sequestration Partnerships (RCSP), the Clean Coal 

Power Initiative (CCPI), and FutureGen. Liability issues associated with the current DOE clean 

coal programs are generally handled pursuant to existing Federal and State laws. 

RCSP and CCPI Liability Issues. DOE thus far has not taken a property interest in any of the 

projects that it has funded through the RCSPs or CCPI programs, and it has offered funding 

under these two programs on the condition that it would be indemnified by funding recipients 

for any potential liabilities associated with CO2 from project operations. For example, DOE 

application materials for the RCSPs contain language disclaiming DOE responsibility for liability 

associated with project activities. Similarly, DOE issued CCPI model cooperative agreements 

that went out with the last round of Funding Opportunity Announcements (FOAs) in 2009 with 

the following notification: 

INDEMNITY The Recipient shall indemnify the Government and its officers, 

agents, or employees for any and all liability, including litigation expenses and 

attorneys' fees, arising from suits, actions, or claims of any character for 

death, bodily injury, or loss of or damage to property or to the 

environment, resulting from the project, except to the extent that such 

liability results from the direct fault or negligence of Government officers, 

agents or employees, or to the extent such liability may be covered by 

applicable allowable costs provisions. 

FutureGen Liability Issues. Liability issues associated with FutureGen are governed by a specific 

State law, the Clean Coal FutureGen for Illinois Act, 20 Ill. Comp. Stat. 1107/1 et seq. (2007) 

(CCFI). Provided that the FutureGen plant is located at one of two locations in Illinois (Tuscola 

or Mattoon, IL), CCFI provides for the transfer of title to and any liabilities associated with 

stored gas to the State. Title to and any liabilities associated with pre-injection stored gas 

remains with the operator of the FutureGen plant. CCFI also directs the State Department of 

Commerce and Economic Opportunity to procure insurance from a private insurance 

company, “if and to the extent such a policy is available,” that insures the operator of the 

FutureGen plant against any qualified loss from a “public liability” action. “Public Liability” is 

defined in CCFI as “any civil legal liability arising out of or resulting from the storage, escape, 

release, or migration of the post-injection stored gas that was injected during the operation of 

the FutureGen Project by the FutureGen Alliance,” but does not include any legal liability arising 

out of or resulting from the construction, operation, or other pre-injection activity of the 

operator. In addition to requiring insurance paid by State funds to protect the plant operator, 

CCFI contains a requirement that the State indemnify the plant operator against the risks of 

public liability actions except where the operator has engaged in intentional or willful 

misconduct; the operator has failed to comply with applicable Federal or State laws, rules, or 

regulations for CCS; the liability relates to pre-injection operations; or the loss has been 

covered by insurance. The obligations to obtain insurance and to indemnify the plant operator 

will be reduced under CCFI to the extent the State is indemnified by the Federal government. 

Appendix K. Liability Associated with DOE CCS RD&D Programs K-1 

 

Appendix L. Property Rights 

L.1 Aggregation of Pore Space 

Ideally, pore space could be acquired through an agreement with a single owner who owns all 

surface and subsurface rights. However, issues may arise where pore space needs for CO2 

storage extend over an area where numerous owners hold rights. 

Several options could address aggregation of pore space for CO2 storage projects. All options 

except the first would require a statutory change or regulatory authorization. 

Option 1: Rely on Private Commercial Transactions. As noted in Section III, one option 

would be for owner-operators to engage in private commercial transactions with property 

owners to acquire ownership of or lease the pore space. A variation on this approach would be 

for the Federal government to engage in private commercial transactions to acquire pore space, 

but there could be Comprehensive Environmental Response, Compensation, and Liability Act 

and/or tort law implications where ownership vests in a government entity. 

Option 2: Exercise or Delegate Federal and/or State Eminent Domain Authority. 

Federal or State governments could use (or delegate) their authority of eminent domain to 

condemn pore space for use for a CO2 storage project. Eminent domain is used to acquire 

property rights for underground natural gas storage in several States and under the Federal 

Natural Gas Act (NGA) (Anderson, 2009).90 The use of condemnation would assist projects in 

moving forward where hold-out property owners exist or where the sheer number of property 

owners makes private commercial transactions to acquire ownership or access difficult 

(Anderson, 2009). The exercise of eminent domain would require an award of just 

compensation. In addition, there could be CERCLA and/or tort law implications where 

ownership vests in a government entity. 

Option 3: Enable Unitization of Pore Space. Unitization of pore space would permit 

separate owners of pore space within a geological formation to act as a single unit for CO2 

geologic storage. Unitization is commonly used for secondary recovery of oil (Wilson and de 

Figueiredo, 2006), where oil and gas leases are combined in a single unit to increase the 

efficiency of production. Members of the unit are compensated, usually from production or 

rental revenues (Klass and Wilson, 2010). Unitization of pore space could build on established 

standards for oil field unitization. Unitization could be compelled when a minority group of 

owners objects to the use of their interests in the pore space. However, there would need to 

be a mechanism for compensating members of the unit, such as injection revenues and/or 

revenues from a future carbon credit market (Sorensen et al., 2009). 

Option 4: Provide Pore Space Underlying Onshore or Offshore Federal Lands for 

CO2 Storage. The Federal government could make pore space underlying Federal lands 

available for CO2 storage. Where the Federal government owns all land rights (“in fee simple”), 

conflicts regarding ownership of pore space are less likely to occur. However, property rights 

disputes could arise if injected CO2 migrates beyond the Federal property boundary, or if 

90 15 U.S.C. § 717f. 

Appendix L. Property Rights L-1 
 

 

ownership rights in the surface and minerals have been split between the Federal government 

and private entities. Conflicts with other surface and subsurface competing uses may occur such 

as mining, recreation, grazing, water production, cultural resource protection, and community 

growth and development. There may also be additional requirements associated with projects 

taking place on Federal lands, including under NEPA (see Section IV.B.1.1). Notwithstanding 

these concerns, use of onshore or offshore Federal lands may be a viable option for some nearterm CO2 storage projects. 

Options 5: Assert that No State and/or Private Property Interest Exists in Deep 

Pore Space.91 The United States could assert that no private property interest exists in deep 

pore space and that pore space property rights are owned by the Federal government. One 

could make an argument that sovereignty over navigable waterways provides precedent for 

Federally owned property interests. However, except in those instances where a property right 

has been recognized in the common law as belonging to the Federal government, the 

determination of property rights traditionally is reserved to the States, and the case could be 

made that the role of determining pore space ownership should remain with the States. In 

addition, the assertion of Federal government ownership would undermine State efforts to 

determine pore space property rights. Assigning pore space ownership to the government with 

the predetermined notion that the space is designated for storage of CO2 could also discourage 

the consideration of alternative uses of the subsurface. In addition, there could be CERCLA 

and/or tort law implications where ownership vests in a government entity. Finally, one might 

expect constitutional challenges associated with this option. 

L.2 Valuation 

At present, it is difficult to estimate a market price for pore space because demand is limited, 

resulting in few sales that might provide representative prices. The transactions that do occur 

depend on the ability of purchasers to persuade owners to sell or lease. A Federal carbon 

emissions reduction program that led to large-scale CO2 storage would increase demand for 

pore space markedly, and could lead to an increase in property values. Additional sellers might 

enter the market in response to such demand, but continued reliance on voluntary sales or 

leases could elevate prices. Congress might increase availability of privately owned pore space, 

while also strengthening purchasers’ negotiating posture, by authorizing acquisition via 

condemnation. As noted above, eminent domain authority could be exercised by a Federal 

agency tasked by Congress with acquiring rights in privately owned pore space, or delegated to 

CO2 storage operators or other agents in procedures akin to those used under the NGA.92 At 

the outset, pore space owners might challenge condemnation by alleging that acquisition for 

CO2 storage by private operators is not a “public” use; however, such challenges would almost 

surely fail under precedent established by the NGA and relevant Supreme Court decisions.93 

91 See, e.g., (RFF, 2007; CCS Regulatory Project, 2008). 

92 15 U.S.C. § 717f. 

93 Hawaii Housing Authority v. Midkiff, 467 U.S. 229 (1984); Kelo v. City of New London, 545 U.S. 469 (2005). 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage L-2 
 

 

 

If eminent domain authority is made available, the Fifth Amendment mandate for payment of 

just compensation will apply.94 Just compensation has historically been computed as the market 

value of a property interest on the date it is appropriated.95 In turn, market value is defined for 

Federal takings as the amount in cash, or on terms reasonably equivalent to cash, for which in 

all probability a property would have sold after a reasonable exposure time in an open 

competitive market, from a willing and reasonably knowledgeable seller to a willing and 

reasonably knowledgeable buyer, with neither acting under any compulsion to buy or sell, giving 

due consideration to all available economic uses of the property.96 

In other words, if there is a prevailing market price at the time of a taking, that price is likely to 

be deemed just compensation. However, assessing the market value of any property interest 

can be difficult where, as with pore space, there are few transactions to analyze. That issue has 

arisen in eminent domain actions brought under the NGA to acquire subsurface gas storage 

rights. In at least one NGA case,97 a Federal court applied State law governing just 

compensation rather than Federal standards. Choice of State law valuation standards may open 

the door to higher values than would application of Federal standards, as well as inconsistent 

valuations across multiple States.98 

Where evidence of comparable sales or leases of pore space is unavailable, parties will look to 

other factors to establish just compensation. For example, an owner might offer proof of loss in 

the overall value of its entire property interest caused by the taking of the pore space. 

Ultimately, to the extent that CO2 storage is sought in private subsurface areas where there 

are already commercial uses of pore space, such as for natural gas storage, the costs of 

obtaining rights to the subsurface may be more easily estimated. In other cases, where a 

geologic formation is appropriate for CO2 storage but there are not other commercial uses for 

the pore space, the costs associated with acquiring that property may be difficult to quantify 

until enough comparable transactions have taken place to establish a going price in the market. 

L.3 Takings Implications 

As discussed above, a determination must be made as to who owns the pore space that is being 

used for storage of CO2. While most legal authority generally suggests that ownership of the 

pore space belongs to the surface estate holder,99 the ultimate determination of ownership for 

any specific property must turn on the application of State property law to the specific terms of 

94 [N]or shall private property be taken for public use, without just compensation. U.S. Const. Amend. V. 

95 E.g., Kirby Forest Industries, Inc. v. United States, 467 U.S. 1 (1984). 

96 Uniform Appraisal Standards for Federal Land Acquisitions, Section B-2 (Appraisal Institute, 5th ed. 2001), 

available online at http://www.justice.gov/enrd/land-ack/Land_acquisition.html. This definition is based on a 

compendium of Supreme Court decisions cited therein. 

97 Columbia Gas Transmission Corp. v. Exclusive Natural Gas Storage Easement, 962 F.2d 1192 (6th Cir. 1992). 

98 State compensation standards sometimes permit more generous landowner recovery by requiring payment for 

elements of damage not compensable under Federal law. 

99 See, e.g., Emeny v. United States, 412 F.2d 1319 (Ct. Cl. 1969) (government’s ownership of gas rights under 

privately-owned surface did not entitle government to inject and store helium within pore space). 

Appendix L. Property Rights L-3 
 

 

any applicable title documents.100 As very few States have addressed pore space ownership 

either through statutory or case law, it may be advisable to institute legal proceedings to 

resolve disputes in advance of commencing CO2 storage. Where the United States asserts that 

it is the title holder to the pore space, such litigation may be brought in Federal district court 

pursuant to 28 U.S.C. § 2509a. 

By confirming through the judicial system that it is the rightful owner of pore space, the United 

States could avoid claims against it by competing owners based on the Fifth Amendment. That 

section of the United States Constitution provides that private property shall not be taken by 

the United States for public use without the payment of just compensation. It is well established 

that the permanent occupation of private property by the United States establishes a successful 

“physical takings” claim, which although not precluding continuation of CO2 storage activities, 

would require the United States to compensate the owner of the pore space for the market 

value of the occupied property interest. 

Fifth Amendment takings claims also could arise as a result of restrictions imposed by the 

Federal government on property interests adjacent to Federally held pore space. For example, 

where a private party holds the right to extract minerals from a stratum beneath the pore 

space, it may be necessary to preclude mining of those minerals so as to ensure the structural 

integrity of the CO2 storage area. Such restrictions could give rise to “regulatory takings” 

claims by the holder of the deeper mineral interests. Like physical takings, regulatory takings 

entitle a successful claimant to just compensation based on the market value of the property 

interest; the determination of liability is far more complex, however, requiring a balancing of 

the property owner’s investment-backed expectations, the character of the government action, 

and the economic impact. 

100 In the case of Federal lands, interpretation of a Federal patent is a matter of Federal law. See Bourgeois v. 

United States, 545 F.2d 727 (Ct. Claims 1976), and Borax Consolidated Ltd. v. Los Angeles, 296 U.S. 10, 22 (1922). 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage L-4 
 

Appendix M. Siting Considerations for CO2 Pipelines 

M.1 Siting of Pipelines across Private Lands 

Given the potential for expansion of interstate and intrastate CO2 pipelines and storage 

facilities, revisiting the siting authority of CO2 pipelines across private lands may be warranted. 

Three potential models are discussed below. 

Model 1: No Federal Authority – Retain Status Quo. This approach would retain 

existing State or local siting of CO2 infrastructure. Various States have sited approximately 

3,600 miles of CO2 pipeline in the United States (Dooley, 2008). There have been no instances 

of complaints that States have either inappropriately denied requests for CO2 pipelines or 

unduly delayed projects. However, the existing system of CO2 pipelines is relatively limited. The 

largest existing CO2 pipeline system is located in and around the Permian Basin of Texas, 

Colorado, Oklahoma, and New Mexico. The on-shore oil pipeline network, which has also 

been developed without Federal siting authority, is much more extensive, but still does not 

approach the level of development of the existing interstate natural gas pipeline network, which 

has been Federally sited since 1938. A State siting approach for CO2 infrastructure may prove 

to be effective to the extent that a substantial, long-line, interstate pipeline network is not 

required. 

However, if an extensive network of long-line interstate pipelines is needed for transporting 

CO2, the State siting approach could prove to be complex and expensive. The differing siting 

and permitting requirements among the various States could lead to coordination difficulties— 

and potential delays—when siting interstate facilities. Construction in populated and 

environmentally sensitive areas poses significant challenges. It may be difficult for project 

sponsors to obtain rights-of-way (ROWs), and it is unclear whether and to what extent the 

States will convey eminent domain to CO2 projects. The lack of State eminent domain rights 

can necessitate the costly rerouting of pipelines, potentially leading to the cancellation of a 

project for economic reasons. A given State or locality may not recognize the value or service 

provided by a proposed facility to customers outside of its own State, or deny a project due to 

concerns about the State’s customers bearing the costs which benefit multiple States. Problems 

such as these have impeded the development of electric transmission infrastructure. 

Experience with State siting for oil pipelines and electric transmission lines may be instructive. 

The Interstate Commerce Act gives the Federal Energy Regulatory Commission (FERC) 

authority to regulate the transportation rates and practices of oil pipelines, but does not 

authorize FERC to site oil pipelines.101 That authority rests with the applicable State and local 

governments. An extensive network of oil pipelines has been constructed under this regulatory 

scheme. The majority of crude trunk lines transport oil from Canadian sources or sources in 

the Gulf Coast to Midwest markets, particularly around Chicago. Major oil pipeline projects are 

currently under construction to serve the Chicago regional market from Canadian sources, and 

other parts of the Midwest and Rocky Mountain States. 

101 49 U.S.C. § 1 et seq. (2006). 

Appendix M. Siting Considerations for CO2 Pipelines M-1 
 

 

However, the GAO issued a report finding that the U. S. petroleum product distribution 

system is constrained in key areas and will likely become more so without timely investments 

(GAO, 2007). The report cites statements by Department of Transportation officials that 

restrictions in the nation’s petroleum pipeline infrastructure are becoming more apparent, and 

that the current regulatory mechanisms may not lead to appropriate reinvestment in the 

industry. The report noted that building interstate natural gas pipelines in the United States is 

easier than building oil pipelines, because FERC has been designated lead Federal agency for the 

construction of natural gas pipelines and Federal eminent domain is conveyed.102 The report 

recommends that various agencies explore whether a lead Federal agency could be assigned to 

coordinate infrastructure construction permitting for oil pipelines, and provide for eminent 

domain authority in order to streamline the process for siting oil and petroleum product 

pipelines. The recent problems in siting oil pipelines are no doubt reflective of the increasing 

difficulties in siting energy infrastructure in this country in general, due to heightened public 

opposition—particularly in more densely populated or environmentally sensitive areas. 

The siting of interstate electric transmission lines on a State-by-State basis has been less 

successful. It is well documented that the growth rate in transmission mileage is not keeping 

pace with the expected growth in consumer demand for electricity over the next two 

decades.103 The lack of Federal siting authority has been cited as one factor contributing to this 

underinvestment in electric transmission lines. This prompted Congress to provide for Federal 

backstop siting authority in the Energy Policy Act of 2005.104 

Model 2: Federal Backstop Siting (the Current Electric Transmission Approach). 

This approach, which would allow the States to retain primary siting authority over CO2 

pipelines, would be less intrusive on State rights. A Federal agency would have the authority to 

site an interstate CO2 pipeline only where a State does not or cannot site the pipeline. This 

approach would be effective in promoting the development of interstate CO2 infrastructure 

only to the extent that most projects are actually sited at the State level, and that requests for 

Federal siting authority are the exception. However, if this is not the case, requiring CO2 

projects to be reviewed sequentially at both the State and Federal level will significantly increase 

the processing time and associated costs for projects. To the extent the project is authorized 

under Federal authority, eminent domain rights could also be conveyed to the permit holder to 

facilitate the acquisition of rights-of-way.105 FERC’s backstop authority for electric transmission 

102 While some oil pipelines are authorized by some States to acquire necessary property by the exercise of the 

right of eminent domain, such authority does not exist in all States. 

103 See, e.g., Promoting Transmission Investment through Pricing Reform, Order No. 679, 71. Fed. Reg. 43294 (July 

31, 2006), FERC Stats. and Regs. ¶ 31,222, at 30,467 (2006). 

104 It is worth noting that while rates for transportation by oil pipelines are set at the Federal level (by FERC), most 

electric transmission facilities are used and funded primarily by retail native load, with the recovery of those costs 

within the control of the State regulator. Outside of a regional transmission organization market, only a small 

fraction of the cost of a transmission facility is usually recovered through Commission-approved wholesale rates. 

Ultimately, investment in electric transmission infrastructure is not only dependent on an effective siting approach, 

but on a clear and unambiguous revenue stream, sufficient to allow the investors to recover their investment. 

105 The Energy Policy Act of 2005 conveyed eminent domain rights to permit holders on property other than 

property owned by the United States or a State. Pub. L. No. 109-58, § 1221(e), 119 Stat. 594, 948 (2005). 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage M-2 
 

 

lines has not yet been exercised, although there is an application to site an interstate electric 

transmission facility currently pending at FERC, and there is uncertainty as to its effectiveness. 

Model 3: Exclusive Federal Siting with Eminent Domain (the Natural Gas Pipeline 

Approach) or Without Eminent Domain (the LNG Import Terminal Approach). 

This approach would vest exclusive authority for the siting of interstate CO2 pipelines in a 

single Federal agency.106 That Federal agency would conduct the necessary environmental 

review pursuant to NEPA, and coordinate the timing of issuance of other necessary Federal 

permits. Having one Federal agency responsible for the siting of an interstate project would be 

less burdensome and more efficient than the State-by-State permitting process. In addition, a 

Federal agency would be in a better position than individual States to take into consideration 

the broad national interests that might underlie a proposal to build CO2 infrastructure.107 

Legislation implementing Federal siting authority could include or exclude the grant of eminent 

domain rights to permit holders. Currently, NGA section 7(h) enables natural gas pipelines to 

exercise the right of eminent domain when they are unable to acquire necessary rights-of-way 

by agreement with the property owner. In contrast, NGA section 3 does not convey that right 

to those constructing LNG import terminals. Therefore, applicants proposing the construction 

of LNG import terminals must secure rights-of-way from landowners by private contract. 

Providing a permit holder the ability to acquire rights-of-way by exercise of the right of eminent 

domain ensures that project sponsors can secure necessary property rights. Absent agreement 

between a permit holder and any landowner, the project sponsor can acquire a right-of-way 

through an eminent domain proceeding and the court will establish the compensation due the 

owner of the land affected by the project. In certain circumstances, the ability of a project 

sponsor to pursue this remedy potentially can reduce both delay and costs. In contrast, without 

the right to condemn necessary property, the pipeline may be unable to obtain rights-of-way 

over a preferred pipeline route; alternative routes may ultimately prove to be economically, 

technically, or environmentally infeasible. 

M.2 Siting CO2 Pipelines across Tribal Lands 

The Energy Policy Act of 2005 Section 1813 Study on ROWs on Indian land reaffirmed the 

current policy that Tribal consent is needed before any right-of-way (ROW) is given on Tribal 

land. Any ROW across trust land would also require Secretarial approval subject to a NEPA 

analysis, as well as a determination that it is in “the best interests of the Tribe.” A CO2 pipeline 

for CCS would be subject to the same requirements as any ROW. 

In the Energy Policy Act of 2005, Title V, there are provisions that address Tribal Energy 

Resource Agreements (TERAs). Section 2604 et. seq. transfers authority from the Secretary to 

a Tribe for the approval of business leases and agreements, as well as ROWs. However, TERAs 

are tied to energy resource development that occurs on tribal land (as defined in Section 2601). 

106 For this purpose, interstate CO2 pipelines could be defined as those that cross State boundaries, and interstate 

storage facilities could be defined as those that straddle a State boundary or receive CO2 from out of State. 

107 A project sponsor would need to receive all other necessary Federal authorizations including those delegated to 

the States. 

Appendix M. Siting Considerations for CO2 Pipelines M-3 
 

 

Thus, to bypass the requirement of Secretarial approval for a ROW, a ROW for a CO2 pipeline 

across Tribal lands for disposal or sale/use under a TERA would have to be directly tied to an 

energy development project or energy production facility on that Tribal land. 

M.3 Siting CO2 Pipelines across Federal Lands 

Federal agencies have the authority to grant ROWs over Federal land. Currently, ROWs for 

the purpose of CO2 pipelines are most commonly authorized by the Bureau of Land 

Management (BLM) pursuant to the Mineral Leasing Act (MLA) of 1920, although some have 

been authorized pursuant to Title V of the Federal Land Policy and Management Act (FLPMA). 

Pipeline ROWs granted pursuant to MLA are required to be constructed, operated and 

maintained as common carriers, with certain limited exceptions. Federal departments or 

agencies cannot obtain a ROW grant for CO2 pipelines under the MLA, 30 U.S.C. 181. 

Section 501 of FLPMA authorizes the Secretary of the Interior with respect to public lands and 

the Secretary of Agriculture with respect to National Forest System lands to grant ROWs for 

pipelines and other systems for the transportation or distribution of liquids and gases (excluding 

the purposes in MLA). It also provides authority to issue ROWs for other necessary 

transportation or other systems/facilities that are in the public interest and which require 

ROWs. FLPMA does not require ROWs to be constructed, operated, and maintained as 

common carriers. Additionally, FLPMA would be appropriate for authorizing Federally 

owned/operated CO2 pipelines.108 

Energy Corridors/Federal Lands: In an effort to expedite the permitting of energy infrastructure 

crossing Federal land, section 368(a) of the Energy Policy Act of 2005 (EPAct) requires agencies 

to designate energy corridors across Federal lands in eleven Western States for “oil, gas, and 

hydrogen pipelines and electricity transmission and distribution facilities.” In November 2008, a 

final programmatic environmental impact statement was issued that evaluates issues associated 

with the designation of energy corridors on Federal lands in eleven Western States. Energy 

corridors on Federal lands provide pathways for future pipelines as well as long-distance 

electrical transmission lines that are expected to help relieve congestion, improve reliability, 

and enhance the national electric grid. Future use of the corridors should reduce the 

proliferation of ROWs across the landscape and minimize the environmental footprint from 

development. Section 368 corridors are sited to avoid, to the maximum extent possible, 

significant known resource and environmental conflicts. The Act does not specifically identify 

CO2 pipelines, but it also does not specifically exclude them. It seems that a CO2 pipeline could 

reasonably fit the definition of “gas pipelines” in EPAct. Section 368(b) requires agencies to 

designate energy corridors across Federal lands in the remaining 39 States; a programmatic 

environmental analysis is currently being prepared. 

M.4 Siting Offshore CO2 Pipelines 

Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEM) and other agencies 

may become involved in addressing issues associated with offshore pipelines. For example, the 

108 See 43 C.F.R § 2801.6. 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage M-4 
Department of Transportation Pipeline and Hazardous Material Safety Administration regulates 

pipeline safety under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline 

Safety Act of 1979 The U.S. Army Corps of Engineers issues permits for pipeline crossings of 

navigable waterways, shorelines, and navigation fairways. The U.S. Coast Guard regulates 

marine navigation generally, and may declare exposed pipeline segments or other subsurface 

obstructions as hazards to navigation. 

M.5 CO2 Pipeline Common Carriage Considerations for CCS 

Operations 

The model for CCS will likely be driven by the source of CO2 and the need to have 100 

percent off-take capacity by the pipeline operator and storage facilities. This model is very 

different from the supply-driven natural gas industry, where wells can be shut and brought back 

on line as demand fluctuates. The ability to maintain availability of the pipeline and storage 

system will require redundancy and spare capacity in both the transportation and storage 

systems to accommodate swings in the CO2 supply. If a pipeline operator fails to satisfy CO2 

off-take agreements, the emissions source could be forced to vent CO2 emissions, scale back 

operations, or shut down. It is expected that shutting down a power plants will not be feasible 

when demand for electricity requires the plant to be online even when venting could be very 

costly under carbon constraints. 

Current regulations for siting in some States, such as Texas and Montana, and across Federal 

lands require that CO2 pipelines be designated as common carriers. Common carriage law 

requires operators to offer excess capacity for a fee to any entity wishing to transport their gas 

through the pipeline. 

Regulators may consider the impacts that common carrier laws will have on the future CCS 

industry. Power plants and other sources of CO2 will likely need the flexibility to reserve 

capacity on the pipeline system. Power plants may need to cycle power production to meet 

demand, resulting in changes of emissions from the source, as well as bringing sources on and 

off line for maintenance. Under existing common carrier structures for natural gas transmission 

line, there exists the risk that another company could consume excess capacity during a period 

of reduced emissions from an emissions source, essentially stranding the source from access to 

a storage site. Regulators ought to carefully consider allowing sources to reserve capacity on 

dedicated pipelines once a source is in operation, or consider the entire CCS system (capture, 

transport, and storage) as an integrated system which would not be subject to the typical 

common carriage requirements. 

M.6 Approaches to Rate and Tariff Regulation of CO2 Pipelines and 

Storage 

There appears to be a particular need for flexibility in any law providing for the regulation of 

services provided by CO2 pipelines and storage, because of the current uncertainty as to who 

will own and operate such facilities, the extent to which an integrated interstate CO2 pipeline 

grid will be necessary, and what business model the providers of these services will use. In the 

past, when Congress adopted laws to regulate interstate businesses, such as railroads, 

wholesale electric power, and oil and natural gas pipelines, those businesses already existed, 

Appendix M. Siting Considerations for CO2 Pipelines M-5 
 

and therefore the laws could be structured in light of the industry’s existing business practices. 

In considering legislation concerning Federal regulation of CO2 pipelines and storage facilities, 

the need for regulatory flexibility should be balanced with a need to provide potential industry 

participants with some degree of certainty concerning the applicable regulatory regime. 

The approaches presented below illustrate the range of possible ways to regulate the rates, 

terms, and conditions of service of CO2 pipelines and storage facilities, and would be associated 

with slightly different standards and goals. Different regulatory approaches could be applied to 

storage versus transportation. 

Approach 1: A State-Based Approach 

Under this approach, Congress would not establish any Federal regime for regulating the rates, 

terms, and conditions of service of CO2 pipelines or storage facilities. Instead, CO2 pipelines’ 

and CCS storage facilities’ rates and services would be left to State and local regulation, if any, 

and/or commercial contracts. This approach could be particularly appropriate in an 

environment where most CCS activity was local, so that interstate transportation of the CO2 is 

relatively rare. In that event, State and local regulation would be adequate, and jurisdictional 

issues with interstate commerce, which might otherwise act as a barrier to effective State and 

local regulation, would likely be minimal. This is the regulatory approach currently used for 

CO2 pipelines transporting CO2 to be employed in EOR operations. 

 Approach 2: Federal Open Access and Transparency Requirements 

An “open access/transparency” model of regulation would require interstate CO2 pipelines and 

storage facilities to provide open and non-discriminatory access both to owners of the facilities 

and to non-owners.109 This model would also emphasize public disclosure of commercial 

transactions and terms and conditions of service as a means of controlling discrimination, but 

leave the negotiation of the specific rates, terms, and conditions of service to the mutual 

agreement of the commercial parties to a particular transaction, without any requirement that a 

regulatory agency review or approve the terms of those transactions. Regulators would simply 

establish rules and regulations for the posting or filing of transaction-specific information and/or 

contracts and ensure compliance with those requirements. Most regulatory actions would be in 

reaction to the complaints of aggrieved parties against a CO2 pipeline or CCS storage service 

provider. 

This may be especially beneficial where some smaller point-source generators have a limited 

ability to develop their own vertically integrated projects for CO2 storage, and therefore may 

be interested in a commercial agreement with someone else’s project. A Federal oversight role 

would also act as a check that might prevent discrimination, and pre-empt State policies that 

acted as commercial barriers to nationwide services. 

Approach 3: Traditional Public Utility Regulation 

109 Congress could choose to apply such regulations only to CO2 pipelines, leaving regulation of storage to the 

individual States. 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage M-6 
 

A traditional utility model of regulation would establish more detailed regulatory oversight of 

rates and terms and conditions of service along the lines of traditional public utility regulation 

(similar to that used for interstate natural gas pipelines).110 

The traditional regulatory approach relies on transparency through a tariff filing requirement, 

and provides extensive regulatory oversight over the rates, terms, and conditions of service; 

often regulators also control abandonment of services. The rates, services, terms and 

conditions of service, and contracts are made publicly available, usually through a tariff filing 

requirement. Frequently, this approach also requires prior notice of any changes in rates or 

services before any new or changed rates, terms or conditions of service, or services may be 

made effective. Another factor to consider is whether commercial terms are made available 

before- or after-the-fact. 

This approach would maximize Federal supervision of rates and services on a nationwide basis. 

It would also give the Federal regulator the maximum amount of control over the rates, terms, 

and conditions of service. These authorities would be especially useful if development on a 

State-by-State level led to balkanization, inefficiency (due to lack of economies of scale, or less 

efficient projects in one State relative to more economical project opportunities elsewhere), or 

obstructions rising within a State. 

Approach 4: Integrated System 

There may be other approaches to regulating CO2 pipelines and storage facilities. One 

possibility would be to regulate them as offshoots of the carbon-producing entity, as a de facto 

extension of a vertically integrated generation process. As such, the CO2 pipeline and storage 

facility would be considered to be part of the utility plant for the generation of electricity. 

Where generation facilities are regulated as part of an integrated system to provide bundled 

wholesale and retail sales, these costs would be included in the cost of service. 111 In cases 

where facilities were also made available to other entities for a fee, the revenues collected from 

third parties would be “credited” to jurisdictional revenues. Where such facilities are part of an 

unbundled merchant generating facility, presumably the costs of CO2 pipelines and storage 

would be at risk the same as any other generation investment. Furthermore, in regional 

transmission organizations with capacity markets, these costs may be subject to inclusion, e.g., 

included in the calculation of the cost of new entry, used in certain price setting and price 

mitigation provisions. Recovery of these costs would be subject generally to FERC’s existing 

sections 205 and 206 Federal Power Act authority. 

Approach 5: Hybrid System 

Finally, one possible evolutionary path for the development of CCS storage and pipeline 

transportation suggests a possible hybrid regulatory approach. Currently, under the Natural 

110 Congress could choose to establish such Federal regulation for CO2 pipelines, storage, or both. 

111 Under the current regulatory structure of the electric industry, this would leave investment decisions to the 

local utility and subject to the authority of State regulators. State commissions would be responsible for siting and 

rate recovery at the retail level. 

Appendix M. Siting Considerations for CO2 Pipelines M-7 
 

 

Gas Policy Act of 1978 (NGPA), FERC may set rates in one of two ways.112 First, FERC will 

allow a local distribution company or an intrastate pipeline to use a State-approved rate for 

interstate transportation or storage services, under appropriate circumstances. Second, where 

a comparable State-approved rate does not exist, FERC will set a “fair and equitable” rate based 

on traditional cost-of-service principles. FERC’s regulations establish a process for such rate 

approvals, which in most cases requires less time and fewer resources than the methods used 

to set cost-based rates for interstate pipelines and wholesale electric utilities. 

If CO2 storage is developed on an intrastate level, and is not preempted by Federal regulation, 

it might be possible to use NGPA-like practices to use State-approved rates to allow an 

intrastate storage service provider to provide interstate services. 

11215 U.S.C. § 3301 et seq. (2006). 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage M-8 
Appendix N. International Collaboration Background 

Figure N-1. Coal CO2 Emissions, Potential Storage and Storage Resource Duration 

for Top 10 Emitting Countries from Coal Utilization 

Source for CO2 emissions from coal: (EIA, 2010b). 

Appendix N. International Collaboration Background N-1 
Table N-1. Storage Estimates for Top 10 Countries for CO2 Emissions from Coal Combustion 

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage 
                 

      

  

           

       

     

       

   

  

  

         

           

               

   

   

            

             

         

         

   

   

   

              

           

         

   

   

              

     

             

     

                  

         

           

           

             

     

            

         

         

           

         

                  

             

   

         

            

   

         

         

           

   

Table N-2. U.S. Participation in Large-Scale International CCS Projects 

Project Location Formation Type U.S. Role in Project / Information Gained

Weyburn‐

Midale

North America,

Canada,

Saskatchewan

Oil Field

Carbonate

(EOR)

U.S. scientists test multiple monitoring and

simulation technologies at world’s largest CO2‐

EOR storage project.

Zama oil

field

North America,

Canada, Alberta

Oil Field

Carbonate

(EOR)

U.S. scientists conduct monitoring and

reservoir modeling studies to support CO2

storage with acid gas stream in carbonate oil

field.

Fort

Nelson

North America,

Canada, British

Columbia

Saline

Formation

U.S. scientists support monitoring and

reservoir modeling studies to verify concept of

utilizing the region’s carbonate saline

formations for large‐scale injection of

anthropogenic CO2.

Sleipner Europe, North

Sea, Norway

Marine

Sandstone

U.S. scientists use time‐lapse gravity survey

monitoring technology to augment seismic at

a subsea commercial‐scale injection site.

Snøhvit

CO2

Storage

Europe, North

Sea, Norway

Marine

Sandstone

U.S. scientists perform reservoir modeling of

geochemical, geomechanical, and seismic

conditions to predict storage effectiveness in a

subsea commercial operation.

CO2SINK Europe, Germany,

Ketzin

Saline

Sandstone

U.S. scientists test downhole monitoring

technology based on distributed thermal

perturbation sensors at pilot test site.

CarbFix Iceland Basalt U.S. scientists monitor CO2 trapping, plume

tracking, and leakage by tagging CO2 stream

with carbon isotope.

Otway

Basin

Australia, Victoria Gas Field

Sandstone

U.S. scientists design/fabricate/install

downhole monitoring technologies based on

seismic, pressure/ temperature sensors and U‐

tube reservoir fluid sampling and perform

reservoir simulations at mid‐scale injection.

In Salah

gas

Africa, Algeria Gas Field

Sandstone

U.S. scientists test monitoring technologies

based on seismic and satellite imagery, and

model geomechanical/geochemical reservoir

conditions at a commercial injection.

Ordos

Basin

Asia, China, Ordos

Basin

Oil and Gas

Field, Saline

U.S. scientists simulate hydrogeologic and

geochemical reservoir conditions and develop

geomodels to assess storage effectiveness at

future commercial‐scale operations.

Appendix N. International Collaboration Background N-3 

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