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

August 2010

### Table of Contents

Executive Summary

.............................................................................................................. ............................ 7

Introduction

................................................................................................................... ............................. 7
Status of CCS Technol ogies

.................................................................................................................... 8
Status of CCS in the United States

............................................................................................. ........... 9 Proposed Plan to Overcome Barriers

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

....................................................................................... 11 Providing Legal & Regulator y Clarity and Support

.................................................................. 12
Public Outreach

................................................................................................................ ............... 13
Conclusion

..................................................................................................................... ............................ 14

I. Background

..................................................................................................................... .................... 15

II. Role of CCS in Administration C limate 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 CO 2 Capture

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

................................................................................................................. 27
III.A.2 Status of Capture Technology

................................................................................. 28
III.A.3 Planned Demonstrations of CO 2 Capture Technologies

.................................. 32
III.A.4 CO 2 Capture Cost

..................................................................................................... 33
III.A.5 Technical Challenges to CO 2 Capture for Coal-Based Power Generation

.. 34

III.B CO 2 Transport

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

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

....................................................................... 36
III.B.3 CO 2 Design Construction, Op erations and Safety

............................................. 36
III.B.4 CO 2 Transport Cost

.................................................................................................. 37
III.B.5 Anticipated Future CO 2 Pipeline Development

................................................... 37
III.C CO 2 Storage

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

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

.................................................................................................. 38
III.C.3 Demonstrations of CO 2 Storage Technologies

................................................... 43
III.C.4 CO 2 Storage Cost

....................................................................................................... 44
III.C.5 Technical and Other Considerations for CO 2 Storage

...................................... 45

III.D Conclusions

.................................................................................................................... .......... 50
III.D.1 CO 2 Capture

................................................................................................................ 50
III.D.2 CO 2 Transport

............................................................................................................ 50
III.D.3 CO 2 Storage

................................................................................................................. 51

IV. Current Barriers and Concerns for CCS Deployment and Commercialization

................ 53
IV.A Market Failures

................................................................................................................ ........ 54

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

...................................................................................................................... 5 4
IV.A.2 Failure to Account for Social Cost of Greenhouse Gas Emissions

................. 54
IV.A.3 Knowledge Spillovers from Resea rch and Development of CCS Technology

................................................................................................................... 55

IV.B Regulatory Framework Governing the Ca pture, Transportation, and Storage
of CO 2 ............................................................................................................................... ........ 56
IV.B.1 Current Framework

................................................................................................... 57
IV.B.2 Legal and Regulatory Challenges

............................................................................. 66
IV.C Long-Term Liability Regar ding Storage of CO 2 ............................................................... 68
IV.C.1 Overview

...................................................................................................................... 6 8
IV.C.2 Policy Considerations for a Long -Term Liability Arrangement

........................ 73

IV.D Public Information, Education, and Outreach

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

...................................................................................................................... 7 6
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 Te chnology 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 fo r Targeted CCS Projects

...................................................... 84
V.C Technology-Push Drivers for CCS

..................................................................................... 87
V.C.1 Demonstration of Curre nt 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” A llowance Allocation

................................................ 98

VI. Options for Enhancing the Legal /Regulatory Framework

..................................................... 101

VII. Approaches for Legal or Regulatory Structure s to Deal with Potential Liabilities

......... 109
VII.A Existing Legal and Regul atory 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 3IX.A Conclusions

.................................................................................................................... ....... 123

IX.B Recommendations

............................................................................................................... 1 24
IX.B.1 Early Projects

............................................................................................................ 124
IX.B.2 Wider Deployment

................................................................................................. 126

X. List of Acronyms

............................................................................................................... ............. 129

XI. References

..................................................................................................................... .................. 131
Appendix A. CO 2 Capture – State of Technology Develo pment: Supplementary Material...

... A-1
Appendix B. CO 2 Pipeline Transport – State of Tec hnology Development: Supplementary

Material...................................................................................................

...... B-1

Appendix D. CO 2 Reuse...................................................................................D-1
Appendix E. Research, Develo pment, & Demonstration..............................................E-1
Appendix F. Applicability of Selected Environme ntal Laws to the Storage Phase of Carbon Appendix C. CO 2 Storage – State of Techno logy Development: Supplementary Material...

.... C-1

Capture and Storage........................................................................................F-1
Appendix G. Applicability of the National Env ironmental Policy Act, the Endangered Species Act, and the National Historic Preservation A ct to Carbon Capture and Storage Activities

... G-1

Appendix J. Government Indemnification................................................................J-1
Appendix K. Liability Associated wi th DOE CCS RD&D Programs.................................K-1

Appendix M. Siting Considerations for CO 2 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 Pr ivate Insurance Program.................................

.......... I-1

Appendix L. Property Rights............................................................................

.... L-1

Report of the Interagency Task Fo rce on Carbon Capture and Storage 4This 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 righ ts or remedies that benefit the public or any regulated entity. Th e 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 thro ugh 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 (CO 2 ) emissions from new and existing coal- and gas-fired power plants, industrial processes, and other stationary sources of CO 2 . In its application to electricity generation, CCS could play an important role in achieving national and global greenhouse gas (GHG) reduction goals. However, widespre ad cost-effective deployment of CCS will occur only if the technology is commercially available an d 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 Captur e and Storage composed of 14 Executive Departments and Federal Agencies. The Task Forc e, 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-e ffective deployment of CCS within ten years, with a goal of bringing five to ten commerc ial demonstration proj ects online by 2016. Composed of more than 100 Federal employees, the Task Force examined challenges facing early CCS projects as well as factors that coul d inhibit widespread commercial deployment of CCS. In developing the findings and recommendatio ns outlined in this report, the Task Force relied on published literature and individu al input from more than 100 experts and stakeholders, as well as public comments submi tted to the Task Force. The Task Force also held a large public meeting and severa l targeted stakeholder briefings.

While CCS can be applied to a vari ety of stationary sources of CO 2 , its application to coal-fired power plant emissions offers the greatest potent ial 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 Am erican 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 (CO 2 ) emissions from the consumption of energy. EPA and Energy Informati on Administration (EIA) assessments of recent climate and energy legislat ive proposals show that, if ava ilable 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 resour ce, help improve national security, help to maximize production from existing oil fields thro ugh enhanced oil recovery (EOR), and assist in the creation of new technologies for export.

While there are no insurmountable technologica l, legal, institutional, regulatory or other barriers that prevent CCS from playing a role in reducing GHG emissions, early CCS projects

Executive Summary 7face 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 th at CCS technologies will not be widely deployed
in the next two decades absent financial incent ives that supplement proj ected carbon prices. In addition to the challenges asso ciated with cost, these projects will need to meet regulatory requirements that are currently under developm ent. Long-standing regulatory programs are being adapted to meet the circumstances of CCS, but limited experience and institutional capacity at the Federal and State 1 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 technol ogies such as CCS, be cause it will create a stable, long-term framework for private investme nts. A concerted effort to properly address financial, economic, technological, legal, institutio nal, and social barriers will enable CCS to be a viable climate change mitigation option that can over time play an impo rtant role in reducing the overall cost of meeting domestic and global emissions reduction targets. Federal and State agencies can use existing authorities and progr ams 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 in cludes capture and compression of CO 2 from power plants or industrial sources; transport of the captured CO 2 (usually in pipelines); and storage of that
CO 2 in geologic formations, such as deep sa line formations, oil and gas reservoirs, and unmineable coal seams. Technologies exis t for all three components of CCS.

 Capture of CO 2 from industrial gas streams has o ccurred since the 1930s using a variety of approaches to separate CO 2 from other gases. These processes have been used in the natural gas industry and to prod uce food and chemical-grade CO 2 . Existing capture technologies are energy-intensive, and conseque ntly their application to coal-fired power plants and other industrial sources is expensive.

 The history of transporting CO 2 via pipelines in the United States spans nearly 40 years. Approximately 50 million tonnes of CO 2 are transported each year in the United States through 3,600 miles of existing CO 2 pipelines.

1 References to “States” also include Tribal governments.

Report of the Interagency Task Fo rce on Carbon Capture and Storage 8 Globally, there are four commercial CC S facilities sequestering captured CO 2 into deep geologic formations and applying a suite of te chnologies to monitor and verify that the
CO 2 remains sequestered. 2,3 These four sites represent 25 years of cumulative experience on safely and effe ctively storing anthropogenic CO 2 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” thes e existing processes and integrating them with coal-based power generation poses technical, economic, and regulatory challenges. In the electricity sector, estimates of the incremental co sts of new coal-fired plants with CCS relative to new conventional coal-fired plants typic ally range from $60 to $95 per tonne of CO 2 avoided (DOE, 2010a). Approximately 70–90 percent of th at cost is associated with capture and compression. Some of this cost co uld be offset by the use of CO 2 for EOR for which there is an existing market, but EOR options may no t 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 CO 2 capture component technologies and advanced power generation technologies to significantly re duce 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 deve lopment of regulations that address the safety, efficacy, and environmenta l soundness of injecting and storing carbon dioxide underground; and the assessment of th e country's geologic capacity to store carbon

dioxide. All of this work builds on the firm scie ntific basis that now exists for the viability of CCS technology.

2 Since the 1970s, engineered injection of CO 2 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 CO 2 .

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

Executive Summary 9Long-term integrated testing and validation pr ograms 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 Act 4 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 projec ts supported by DOE are intended to begin operation by 2016 in the United States. Thes e demonstrations will integrate current CCS technologies with commercial-scal e 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 CO 2 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 de monstration projects may not proceed for economic or other reasons. Looking toward lo ng-term deployment, additional actions may be required to help overcome the uncertainty of ev olving climate change policy and the high cost of applying currently availabl e CCS technology, consistent wit h addressing market failures.



### Barriers to CCS Deployment

The lack of comprehensive climate change legi slation is the key barri er 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 R D&D efforts to push CCS technology development, and market-pull mechanis ms such as tax credits and loan guarantees. However, many of these projects are being plan ned by the private sector in anticipation of requirements to reduce GHG emissions, and the foremost economic challenge to these projects is ongoing policy uncertainty regardi ng the value of GHG emissions reductions.

Even with financial support, ch allenges such as legal and regulatory uncertainty can hinder the development of CCS projects. Regulatory uncertain ty 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 regu latory 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 regu lating 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 Fo rce on Carbon Capture and Storage 10The Task Force identified a range of views conc erning potential long-ter m liabilities (i.e., those arising after closure of a CO 2 storage site) and the extent of any potential impacts on widespread deployment. Many States planning C CS projects are taking steps to address longterm liabilities associated with geologic storage of CO 2 . 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 commercia l-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 wi th widespread deployment.

Aggregation of pore space and associated proper ty 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 st orage on private lands. Based on experience thus far, the Task Force believe s 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 co mmercial-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, ed ucation, and outreach efforts throughout the lifecycle of CCS projects will he lp 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 proje cts, including five to ten commercial-scale demonstrations by 2016, DOE and EPA should cr eate 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 commi ttee would conduct a peri odic review of CCS demonstration projects to track their progress an d, broadly, identify any additional research, risk management, or regulatory needs. The te chnical committee could also, as requested by DOE or EPA, provide input on a range of CCS technical, economic , or policy issues.

Executive Summary 11DOE should continually review the adequacy of capture technologies an d classes of storage
reservoirs to enable safe and cost-effective wi despread CCS deployment within ten years. This ongoing assessment, coupled with input from the technical committ ee 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 Federa l financial support for CCS projects. Increased coordination will enha nce the government's ability to tailor Federal funding and assistance to each project’s market co ntext, improve the clarity of eligibility criteria for projects to receive Federal support, allo cate 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 co untries will improve the viability of CCS and potentially speed up global commercialization. Energy and economic modeling suggests that CCS in coal-dependent emerging economies pl ays a key role under so me future policy and economic scenarios in achieving global clim ate change mitigation goal s. The United States should continue its cooperation with large c oal-dependent emerging economies with rapidly expanding power sectors, to facilitate a constructi ve dialogue and help to avert the locking in of inefficient, high-GHG emission power generation assets for decades. Failu re 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, EP A should finalize rulemakings for geologic sequestration wells under the Safe Drinking Water Act (SDWA) and GHG reporting for CO 2 storage facilities under the Clean Air Act (CAA), and propose a Resource Conservation and Recovery Act (RCRA) applicability rule for CO 2 that is captured from an emission source for purposes of sequestration. EPA guidance to suppor t 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) sh ould immediately formalize coordination and prepare a strategy to develop regulatory framew orks 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 (M PRSA) as well as am endment of the Outer Continental Shelf Lands Act (O CSLA) will ensure a comprehensiv e statutory framework for the storage of CO 2 on the outer continental shelf.

Report of the Interagency Task Fo rce on Carbon Capture and Storage 12Federal and State agencies must wo rk together to enhance regula tory and technical capacity for safe and effective CCS deployment . Specifically, EPA, in coordina tion 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 tech nically sound permits. These programs should leverage existing efforts such as the DOE Regional Carbon Seque stration 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 mo nitoring, oversight, and accountability for CCS

activities will be essential to ensure the integrity of CCS oper ations, enable a sustainable CCS industry, and provide a strong foundation for pub lic confidence. DOE and EPA, in consultation with other agencies, should track regulatory implementation for early commercial CCS demonstration projects and consider whether a dditional statutory revisions are needed. This
will enable the Administration to more effectively cons ult 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 a ppropriate 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 stewar dship frameworks should continue. By late 2011, EPA, DOE, Department of Ju stice (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 th e seven options identified by the Task Force, the following four approaches, or combinations th ereof, should be considered: (1) reliance on the existing framework for long-term liability an d stewardship; (2) adoption of substantive or procedural limitations on claims; (3) creation of an industry-financed tr ust 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 CO 2 storage.

Public Outreach

To enhance and coordinate public outreach fo r CCS, DOE and EPA should leverage existing efforts to coordinate among Federal agencies, St ates, industry, and NGOs to gather information and evaluate potential key concer ns around CCS in different area s of the United States. Using this information, DOE and EPA should develop a comprehensive outreach strategy among the

Executive Summary 13Federal 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 CC S projects, to addre ss 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 energyresources. 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 governm ent could take under existing authority and

resources to address these barriers. For wides pread 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-effectiv e CCS could reduce the costs of achieving our Nation’s climate change goals.

CCS can also play a major role in reducing GH G 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 clim ate change technologies and markets. However, widespread cost-effective deployme nt of CCS will occur only if the technology is commercially available at economically compet itive prices and supportive nati onal policy frameworks are in place.

Report of the Interagency Task Fo rce 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 th e following Federal Agencies and Executive Departments participated in the Task Force: De partment of State, Depart ment of the Treasury, Department of Justice, Department of the Interio r, Department of Agriculture, Department of Commerce, Department of Labor, Department of Transportation, Department of Energy, Office of Management and Budget, Enviro nmental Protection Agency, Federal Energy Regulatory Commission, Office of Scienc e 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 carb on capture and storage technologies in line with the Administration’s goals for climate prot ection. The Task Force, co-chaired by the Department of Energy and the Environmental Pr otection Agency, was charged with proposing a plan to overcome the barriers to the widesprea d, cost-effective deploy ment of CCS within 10 years, with a goal of bringing five to ten co mmercial demonstration projects online by 2016.

In his memorandum, the President requested th at within 180 days the Task Force explore incentives for commercial CCS adoption and ad dress 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, comprisi ng over 100 Federal employees from multiple Federal agencies. The Task Force examined chal lenges facing early CCS projects as well as factors that could inhibit widespread commercial de ployment of CCS. In developing the findings and recommendations outlined in this report, th e Task Force relied on published literature and individual input from over 100 experts and stak eholders 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 fa shion 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 includ ed 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 wa tched online. The meeting included several

I. Background 15panels of experts on various components of CCS systems and opportunity for public input and questions. The video, expert pres entations, 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 he ld a series of targeted meetings with representative groups of stakeholders, including environmental organizat ions, labor organizations, State governments (including representatives from 14 governors' offi ces), 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 thei r ideas and concerns were heard and addressed.

The Task Force recognizes the contributions of States in evaluating an d beginning to address barriers to CCS deployment. States are support ing RD&D activities, developing regulatory frameworks, and providing incentives for CC S deployment. For example, several State universities are studying and assessing the pote ntial for CCS. Some States have created task forces or directed State agencie s or energy commissions to asse ss potential storage sites (both onshore and offshore) and develop reports wit h recommendations to accelerate CCS and
address barriers to CCS. 5 In some cases, grant programs an d 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 CO 2 injection, 7 designed regulations for injection wells, 8,9 established rules for permitting storage sites and CO 2 pipelines, 10 provided eminent domain powers for CCS development, 11 and developed laws related to liability 12 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 17 65, 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 Co de 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; Mo ntana 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 Fo rce on Carbon Capture and Storage 16Several States are providing ince ntives for CCS deployment such as portfolio standards that include generation of electricity from power plants with CCS 14 , alternative fuel standards, 15
emission standards, 16 prioritization of CCS during power plant permitting processes, 17 tax incentives (including tax exemption, reduced sale s tax, taxation at lowe red market value, tax credits), 18 and provision of full or partial cost reco very through authorized rate changes for power plants with CCS. 19

In addition to specific individual actions, seve ral 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 co ntinues 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 CC S: American Power Act (APA) of 2010 -- KerryLieberman 25 ; S. 1462, American Clean Energy Leadersh ip 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 17development and demonstration of CCS techno logies, create incentives for commercial deployment of CCS, and address legal and regu latory issues (CRS, 2010). For example, the ACELA authorizes funding for up to 10 CCS demo nstration projects through a competitive selection process 26 and the ACES Act and the APA would es tablish a CCS fund to finance either
the first five 27 or the first 10 GW 28 of commercial-scale demonstr ation 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 develo pment and deployment. For example, Senators Rockefeller and Voinovich introduced legislat ion in March 2010 to promote research and create incentives to develop and deploy fu ll 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 prov ide grants to large-scale projects advancing the commercial availability of CCS technology. Sena tor Boxer introduced an amendment in 2008 to the Lieberman-Warner Climate Security Act esta blishing 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 belo w Federal land. Senators Casey and Enzi introduced a bill for creating a framework for a ddressing legal and financial responsibilities for commercial carbon storage operations.

Other legislators have voiced support for CC S 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 CO 2 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 CO 2 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.

29 The 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.

30 See, 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 Fo rce on Carbon Capture and Storage 18

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

As one of relatively few low-carbon electricit y 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 availa bility 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 perc ent 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 to tal electricity generation) (EPA, 2010).

The Administration is committed to a range of po licies that address the market failures that would otherwise impede the deployment of low-ca rbon 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 fi rms tend to under inve st 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&D 32 . 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 invest ments 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 rang e from analysis of the sequestration 33 potential of geologic formations to public-private cost -shared demonstrations of advanced CCS technologies.

Globally, CCS can play a major role in reduci ng GHG emissions, with 20–40 percent of global
CO 2 emissions in 2050 projected to be suitab le 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 tec hnology 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, wides pread 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 addr ess these challenges.

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

33 “CO 2 sequestration”, “geologic sequestration”, and “CO 2 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 cons istent with the Administra tion’s climate change goals. 34,35 In the base case, allowance prices in 2020 are $24 and $31 per tonne CO 2 equivalent 36 (CO 2 e) 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 a llowed in the program, carbon prices are higher, at $52 per tonne CO 2 e for both the EPA and EIA analyses. Finally, if international offsets are unavailable, nuclear an d dedicated biomass electricity generation are unavailable beyond business-as-usual le vels, and CCS deployments are limited 37 , allowance prices rise to $59 - $89 per tonne CO 2 e in 2020 (EPA 2010; EIA 2010) . These results reinforce the concept that availability of mitigation opti ons (whether offsets or more cost-effective technologies) lowers the price of allowances, an d 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 carb on prices that achieve the President’s emission reduction goals, the cost to the Unit ed States economy of achiev ing 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 recog nized and respected in the climate policy discussion.

36 CO 2 equivalent is a measure used to compare the emi ssions from various greenhouse gases based upon their global warming potential (GWP). CO 2 equivalent for a gas is derived by multiplying the tonnes of the gas by the associated GWP. Tonne CO 2 e = (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 Fo rce on Carbon Capture and Storage 20$0 $50 $100 $150 $200 $250Allowance Price ($/tCO2e) 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 Mo deling 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 dr aft (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 broad er 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 di stort 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 ea rly deployment incentives would be reduced to the extent that early deployment lowers technical and co mmercial risk and enables CCS technology improvements that lower the cost of later widescale deployment.

38 Recent legislative proposals for GHG cap-and-trade syst ems have reserved a share of emission allowances for free allocation to CCS applications. Bonus allowanc es are discussed in detail in Section V.D.3.

II. Role of CCS in Administration Climate Policy & Global Initiatives 21Figure II-2 CCS Deployment (GW) EPA Modeling of Proposed PolicyGW 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 mo deled by EPA and EIA. Consistent with the previous discussion, the bonus allowance provisions would drive de ployment through 2030 in the cases where CCS technology is not delayed. The availability of in ternational offsets does not significantly change the impact of bonus allowa nces on CCS deployment. Ho wever, by 2050, CCS deploys economically and in greater quantities in the “n o international offset” scenarios due to higher allowance prices (i.e., more reductions must oc cur domestically and these have higher costs associated with them than opportunities availa ble 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 Fo rce on Carbon Capture and Storage 22Figure II-3 CCS (GW) EPA and EI A Modeling of Proposed Policy 39

350

0 50 100 150 200 250 300GW EPA - Base Case (sc enario 2)

EIA - Base Case

EPA - No Internati onal Offsets (scenario 5)

EIA - No International Offsets

EPA - Delayed CCS + No Internati onal 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. CO 2 captured assumed to be 90 percent. A typical 550MW net ou tput coal-fired power plant capturing 90 percent of the CO 2 would capture about 5 million tonnes of CO 2 per year.

These modeling exercises show th at CCS may play an important role in helping the United
States meet carbon reduction ta rgets. The key to broad, cost-e ffective, 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 an d 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 co st of meeting the Administrati on’s climate goals. Thus, the
Administration is committed to addre ssing these barriers to deployment.



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

Key insights into the value of international deploy ment 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 greate r amounts of GHG abatement to occur in covered sectors, including the power sector. CCS deployment is actually lo wer 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 re lative 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 summa rize 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 glob al participation case in which a 550 ppm CO 2 concentration target is not exceeded. 40 It shows the amount of CO 2 averaged across all the models that is projected to be captured and st ored by four major participants (the United States, European Union, China, and India). The me ssage 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 an y non-economic barriers not captured in the models. In addition to domestic efforts, the Ad ministration is committed to continuing its engagement with other nations as described in Sections V and VI.

Figure II-4 Projected CO 2 Sequestration for Four Majo r Participants in a Global Regime

0.0 0.5 1.0 1.5 2.0 2.5 3.0

United States European Union China IndiaGtCO2/ 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 availa bility of such reservoirs. However, emerging economies generally lack the resources and expe rtise to acquire the information needed for detailed assessments with a high degree of confi dence. In some countries, the information currently available is not suffici ently detailed to determine whethe r 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 Fo rce on Carbon Capture and Storage 24necessary to develop commercia l-scale CCS projects. The United States, along with several other developed countries, is prov iding 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 2 nd edition of the Carbon Sequestration Atlas of the United St ates and Canada (Atlas II) is a good example of the type of data needed to assess the technical potentia l 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 State s and portions of Canada. It also presents updated information on the location of stationary CO 2 emission sources and the locations and sequestration potential of various geologic seques tration sites, and provides information about the commercialization opportunities for CCS te chnologies. 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, Chin a, Japan, and European countries are currently publishing data on their geologic storage potentia l. However, there is no single reference at
sufficient detail for the rest of the world. Glob al capacity estimates use simplistic methods and assumptions and therefore have considerable un certainty (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 method ologies 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 thei r 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 ma de 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 count ries. Several of us commit to
accelerate the CCS demonstratio n 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 CO 2 emissions.

41 Page 7, paragraph 24 of G8 text at http://www.whiteh ouse.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 CO 2 from power plants or industrial sources, transport of the captured CO 2 (usually in pipelines), and storage of that CO 2 in suitable geologic reservoirs. Technologies exist fo r 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 technol ogy for CCS in power production range between $60 and $114 per tonne of CO 2 avoided 42 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 develo pment for capture, transport, and storage of
CO 2 . The small-scale CCS efforts that have been conducted to date are presented along with upcoming larger-scale demonstration projects.



### III.A CO 2 

### Capture

III.A.1 Introduction

This section of the report presents a brief history of CO 2 capture technology, the current state of technology development, and planned larg e-scale demonstration projects. Additional supporting material can be found in Appendix A.

Although CO 2 capture is new to coal-based power generation, removal of CO 2 from industrial gas streams is not a new process. Gas absorption processes using chemical solvents to separate
CO 2 from other gases have been in use since the 1930s in the natural gas industry and to produce food and chemical grade CO 2 from gas streams containing 3 to 25 percent CO 2 (see Appendix A, Figure A-1). In the 1950s and 1960s, gas adsorption processes were developed to separate CO 2 from gas streams associated with hydrogen (H 2 ) production (refineries), nitrogen (N 2 ) 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 CO 2 removal technologies (Chapel et al., 1999). Prior to 1999, 25 facilities were
built with CO 2 capture capacities rang ing 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 CO 2 per year. The captured CO 2 from these facilities was used for enhanced oil recovery (EOR), urea production, and in the fo od 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 pe r 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 27these facilities reflect the fact that they were built to serve a specific commercial market for
CO 2 . Other amine-based processes (e.g., ABB/Lummu s) were implemented at similar capture rates during this period. By comparison, a si ngle 550 megawatt (MW) ne t output coal-fired power plant capturing 90 percent of the emitted CO 2 will need to separate approximately 5
million tonnes of CO 2 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 CO 2 capture technologies identified 17 operating facilities using either chemical or physical captur e solvents (see Appendix A, Table A-2) (Dooley et al., 2009). These included four natural gas pr ocessing operations and a syngas production facility in which more than 1 million tonnes of CO 2 are being captured per year. The largest (a natural gas processing operation in Wyoming) ca ptures 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 proc essing is to separation of power plant flue gases, given the significant differences in th e 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 CO 2 capture.



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

III.A.2.1 Industrial Sectors

One-quarter of U.S. CO 2 emissions come from the industrial sector, with the highest emissions coming from petroleum refining, chemical prod uction, cement production, pulp and paper, and iron and steel production. Few studies or demons tration projects have enabled the evaluation of the applicability of CO 2 capture technologies to these indu strial sources. Some industrial facilities (e.g., lime production, petroleum refi neries, natural gas processing, and ammonia plants) produce relatively concentrated CO 2 streams. As previously mentioned, scrubbers have
been used at some of these industrial faciliti es, though at very sma ll scale, to capture CO 2 for specific use, such as EOR. The CO 2 from many of these facilitie s could likely be captured at lower cost, as the CO 2 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 emi ssions from these industrial sources. As a consequence, few of the available technologi es are being employed on a wide scale.

III.A.2.2Coal-Fired Power Generation

In general, CO 2 capture technologies applicable to coal-fired power generation can be categorized into three approac hes (IPCC, 2005; DOE, 2007):

Report of the Interagency Task Fo rce on Carbon Capture and Storage 28 Pre-combustion systems are designed to separate CO 2 and H 2 in the high-pressure syngas produced at Integrated Gasification Combined Cycle (IGCC) power plants.

 Post-combustion systems are designed to separate CO 2 from the flue gas produced by
fossil-fuel combustion in air.

 Oxy-combustion uses high-purity oxygen (O 2 ), rather than air, to combust coal and therefore produces a highly concentrated CO 2 stream.

Each of these approaches results in increased capital and operating costs and decreased electricity output (or energy penalty 43 ), thereby significantly increa sing the cost of electricity (COE) (Rubin, 2008; DOE, 2010a). The en ergy penalty occurs because the CO 2 capture process uses some of the energy produced fr om the plant. The capture approaches and their impacts on COE and electricity production are summarized below.

Pre-Combustion CO 2 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 O 2 . 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 fo r a pulverized coal (PC) power plant. Using the SelexolTM process to capture CO 2 at an IGCC power plant increases the COE by approximately 40 percent relative to th e same plant without a capture system. 44 By comparison, adding an amin e scrubber to capture CO 2 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 CO 2 in pre-combustion IGCC applications is approximately 20 percent (Rubin, 2008; Hamilton, 2009; DOE, 2010a).

Post-Combustion CO 2 Capture

Post-combustion CO 2 capture refers to removal of CO 2 from combustion flue gases prior to discharge to the atmosphere (see A ppendix A, Figure A-4). Separating CO 2 from this flue gas is challenging for the following reasons:

 A high volume of gas must be treated because the CO 2 is dilute (13 to 15 percent by volume in coal-fired system s, 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 repr esents 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 curre nt (i.e., real) dollars using 2009 as the base year.

III. State of CCS Technology 29 the flue gas is at low pressure (near atmos phere); trace impurities (particulate matter [PM], sulfur oxides [SO

x ], nitrogen oxides [NO

x ], etc.) can degrade the CO 2 capture materials; and

 compressing captured CO 2 from near atmospheric pressure to pipeline pressure (about 2,000 pounds per square inch absolute) requir es a large auxiliary power load (Rubin, 2008; Hamilton, 2009; Herzog, 2009; Herzog et al., 2009).

Post-combustion CO 2 capture offers the greatest near-term potential for reducing power
sector CO 2 emissions because it can be used to retr ofit existing PC power plants. Although post-combustion capture technol ogies would typically be applie d to conventional coal-fired power plants, they could also be applied to th e flue gas from IGCC power plants, natural gas combined cycle (NGCC) power plants, and indust rial facilities that combust fossil fuels. Currently, there are several commercially ava ilable solvent-based capture processes. In addition, a wide variety of processes employing solvents, solid sorbents, and membranes are at varying stages of development (EPR I, 2008; Ciferno et al., 2009).

Installing current amine post-combustion CO 2 capture technology on new conventional subcritical, supercritical, and ultra-supercritica l coal-fired power plants would increase the COE by about 80 percent. Further, the large quantit y of energy required to regenerate the amine solvent and compress the CO 2 to pipeline conditions would resu lt in about a 30 percent energy penalty (DOE, 2010a).

Oxy-Combustion

Oxy-combustion systems for CO 2 capture rely on combusting coal or other fuels with relatively pure O 2 diluted with recycled CO 2 or CO 2 /steam mixtures. Under these conditions, the primary products of co mbustion are water and CO 2 , with the CO 2 purified by condensing the water (see Appendix A, Figure A-6) (Bohm, 2006; Hamilton, 2009; Herzog, 2009).

There are multiple technical and economic adva ntages of coal oxy-combustion that provide a high potential for a significant reduction in CO 2 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 cry ogenic air separation units (ASU) and CO 2 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 NO

x , SO

x , and mercury (Hg) is enhanced during the oxy-combustion process. Finally, significant co st reductions and effici ency improvements can be realized by incorporating advanced ultra- supercritical boiler materials and advanced CO 2 purification/compression.

However, first-mover oxy-combustion power pl ants 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 Fo rce on Carbon Capture and Storage 30infiltration (mainly N 2 ), and excess O 2 contaminating in the CO 2 sequestration stream. Construction of a new supercritical oxy-com bustion coal-fired power plant equipped with a commercially available cryogenic ASU would incr ease 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 CO 2 capture (DOE, 2010a ; DOE, 2010b).

III.A.2.3 CO 2 Capture Experience Associat ed with Power Production

Commercially available CO 2 capture technologies are currently being used in various industrial applications. However, one of the key ba rriers to their more widespread commercial deployment as a climate change mi tigation strategy is the lack of experience with these systems at the appropriate scale in power plant sett ings (Kuuskraa, 2007). The following is a brief summary of currently operating CO 2 capture systems in coal-based power plant applications.

AES’s coal-fired Warrior Run (Cumberland, Ma ryland) and Shady Poin t (Panama, Oklahoma) power plants are equipped with amine scrubbe rs developed by ABB/Lummus. They were designed to process a relatively small percent age of each plant’s flue gas. At Warrior Run, approximately 110,000 tonnes of CO 2 per year are captured, whereas at Shady Point 66,000
tonnes of CO 2 per year are captured. The CO 2 from both plants is s ubsequently used in the food processing industry (Dooley et al., 2009).

At the Searles Valley Minerals soda ash plan t in Trona, California, approximately 270,000
tonnes of CO 2 per year are captured from the flue gas of a coal power plant via amine scrubbing and used for the carbonation of brin e 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 proc ess to capture 100,000 tonnes of CO 2 per year on the Mountaineer Plant in New Haven, West Virgin ia, and store it in deep geologic formations

beneath the Mountaineer site.

A pre-combustion Rectisol® system is used for CO 2 capture at the Dakota Gasification Company’s synthetic natural gas (SNG) producti on plant located in North Dakota, which is designed to remove approximately 1.6 million tonnes of CO 2 per year from the synthesis gas.
The CO 2 is purified, transported via a 200-mile pipelin e, and injected into the Weyburn oilfield in Saskatchewan, Canada. However, this experien ce 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 captur e 70,000 tonnes of CO 2 per year (Vattenfall, Undated).

III. State of CCS Technology 31

### III.A.3 Planned Demonstrations of CO 2 

### Capture Technologies

While the efforts described above are worthwhile and important in advancing CO 2 capture technologies, they still are not at a large en ough scale to overcome technical uncertainty associated with scale-up needed for widespr ead cost-effective deployment. One means of addressing these uncertainties is through de monstration programs such as those currently being conducted by DOE.

DOE’s Clean Coal Power Initiative (CCPI) is focused on accelerati ng availability of technologies for use by the private sector in new and existi ng coal-based power plants. CCPI is pursuing three pre-combustion and three post-combustion CO 2 capture demonstration projects using currently available technologies (see Appendix A, Table A-8).

The pre-combustion projects involve CO 2 capture from IGCC power plants. The specific projects include the following:

 Summit Texas Clean Energy: a 400 MW facilit y in west Texas burning Powder River Basin coal where 2.7 million tonnes per year of CO 2 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 CO 2 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 CO 2 will be captured using a Rectisol® process and used in an EOR application.

The post-combustion projects will capture CO 2 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 CO 2 from a 120 MW equivalent slipstream at a North Dakota plan t for use in an EOR application and/or saline
storage.

 NRG Energy: amine-based capture of 400,000 tonnes per year of CO 2 from a 60 MW equivalent slipstream at a Texas pl ant for use in an EOR application.

 American Electric Power: ammonia-based ca pture of 1.5 million tonnes per year of CO 2 from a 235 MW equivalent slipstream at a West Virginia plant for saline storage.

Similar to the CCPI projects, the FutureGen pr oject will demonstrate carbon capture from a 200 MW advanced oxy-combustion unit in Meredosia, Illinois, integrated with CO 2 storage in

Report of the Interagency Task Fo rce on Carbon Capture and Storage 32Mattoon, Illinois. FutureGen aims to captur e and store at least one million tonnes of CO 2 per

year.

In addition to the CCPI program, CO 2 capture demonstration projects are being conducted under the DOE Industrial Carbon Capture and St orage (ICCS) program (see Appendix A, Table A-9) (DOE, 2010c). These projects are pursuing capture technologi es 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 201 0 three projects were
selected to move forward to full demons trations. These include the following:

 Leucadia Energy: a methanol plant in Loui siana where 4 million tonnes per year of CO 2 will be captured and used in an EOR application.

 Archer Daniels Midland: an ethanol plant in Illinois where 900, 000 tonnes per year of
CO 2 will be captured and stored in a saline formation directly below the plant site.

 Air Products: a hydrogen-production facilit y in Texas where 900,000 tonnes per year of
CO 2 will be captured and used in an EOR application.

The large-scale CO 2 capture demonstrations that are curre ntly 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.Thou gh 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 CO 2 

### Capture Cost

DOE analyses indicate that for a new 550 MWe ne t output power plant, addition of currently available pre-combustion CO 2 capture and compression technologyincreases the capital cost of an IGCC power plant by approximately $400 mi llion (~25 percent) compared with the noncapture counterpart. For a similarly sized new s upercritical PC plant, post-combustion and oxycombustion capture would increa se capital costs by approximat ely $900 million (80 percent) and $700 million (65 percent) respectively. For post-combustion CO 2 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 CO 2 avoided, values range fr om $60/tonne for IGCC to $114/tonne for NGCC. 45 Figure III-1 shows the range of thes e costs for various types of power

45 The dollar per tonne of CO 2 avoided is the incremental cost of CO 2 emissions avoided by applying CCS and is compared to a similar non-captured facility. It is calcul ated by dividing the difference in COE, $/MWh, by the difference in CO 2 emissions with and without CO 2 capture, tonnes/MWh. The dollar per tonne CO 2 captured is

III. State of CCS Technology 33plants (DOE, 2010a). In terms of cost per tonne of CO 2 captured, values ra nge from $49/tonne for IGCC to $95/tonne for NGCC. Impr ovements to currently available CO 2 capture and compression processes are important in reducing the costs incurred for CO 2 capture.

Figure III-1 CCS Costs for Different Ty pes 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, $/tonne CO2LCOE,$/MWhAvoidedCost,$/tonneCO2

LCOE

‐‐ Levelized Cost of Electricity is a cost of generating elecricity for a particular system. It is an economic assessment of the cost of the

energy

‐ generating system including all the costs over its lifetime: initial investment, operations and maintenance, cost of fuel, cost of capital

. See Appendix A.4 for a complete description of f inancial assumptions and costing methodology



### III.A.5 Technical Challenges to CO 2 

### Capture for Coal-Based Power Generation

As discussed above, CO 2 removal technologies are not re ady for widespread implementation on coal-based power plants, primarily because th ey have not been demonstrated at the scale necessary to establish confidence for power plant application (Kuus kraa, 2007). Since the CO 2 capture capacities used in current industrial processes are generally much smaller than the capacity required for the purpose s of GHG emissions mitigation at a typical power plant, there is considerable uncertainty associated with proce ss scale-up. For example, maintaining adequate

the incremental cost per tonne of CO 2 captured and is calculated by dividing the difference in COE, $/MWh, by the total CO 2 emissions captured, tonnes/MWh.

Report of the Interagency Task Fo rce on Carbon Capture and Storage 34gas and/or liquid flow distributio n in the larger absorption and regeneration reactors required for power plant applications could prove difficult.

Other technical challenges associat ed with the application of these CO 2 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 (NO

x , SO

x , PM) on CO 2 capture system, increased water consumption and cost effective O 2 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 tec hnical challenges of appl ying these technologies.

III.A.5.1 CO 2 Capture Impacts on Water Use

CO 2 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 incl uding water withdrawal (water removed from a surface or groundwater source) and consumptio n (water not returned to the source) (DOE, 2010a; DOE, 2010b). The evaluations indicated that th ere 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 CO 2 Capture Impacts on Existing Plant Retrofits

The EIA estimates that U.S. el ectricity demand will grow at th e 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 de mand growth would be s ubstantially less than in the business as usual case. This relatively low gr owth 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. Implem entation of CCS to retrofit plants will be challenging because the size and space requirements for CO 2 capture process equipment are significantly greater than for conventional air pollution controls. Providing adequate space for CCS retrofits could prove difficult for certain pl ants. In addition, construc tion 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 CO 2 capture technology. Retr ofits could also face challenges associated with proximity to a geologic sequestration site and/or a CO 2 pipeline.

III. State of CCS Technology 35

### III.B CO 2 

### Transport

III.B.1 Introduction

The transportation of CO 2 is a vital component of the CCS process. Even though CO 2 transportation will likely be less costly than CO 2 capture, developing a transportation infrastructure to accommodate future CCS pr ojects may encounter challenges regarding technology, cost, regulation, policy, rights-of-wa y, and public acceptance. However, given that
CO 2 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 support ing material appears in Appendix B.

Pipelines are expected by many to be the most economical and e fficient method of transporting
CO 2 for future commercial CCS facilities (IPCC, 2005; Parfomak and Folger, 2007). Although capital costs are higher for pipelines, once constr ucted, they reduce the uncertainty associated with logistics, fuel costs, and reliance on other i nfrastructure that could increase the cost of
CO 2 transportation.

CO 2 pipelines require the same atte ntion to design, monitoring for leaks, and protection against overpressure as natural gas pipelines. The op erational experience and similarity between construction and operation of CO 2 and natural gas pipelines prov ides experience that can be
used to estimate future CO 2 transportation costs (Cosham and Eiber, 2008).



### III.B.2 Existing CO 2 

### Pipeline Infrastructure

The history of transporting CO 2 via pipelines in the United St ates spans over 35 years. The oldest long distance CO 2 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, Pe nnsylvania, the birthplace of the modern oil industry. Approximately 50 million tonnes per year of CO 2 are transported through approximately 3,600 miles of CO 2 -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 Unit ed States today (PHMSA, 2010).



### III.B.3 CO 2 

### Design Construction, Operations and Safety

The design, construction, operatio n, and safety requirements for CO 2 pipelines have been developed over the past 30 years and are not co nsidered barriers to the deployment of CCS technologies for the five to ten commercial pr ojects planned by 2016 or commercial efforts
after 2020. The standards for CO 2 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 Fo rce on Carbon Capture and Storage 36(PHMSA) and various State agencies. Additional i nformation on design, construction, operation, and safety requirements are discussed in Appendix B.



### III.B.4 CO 2 

### Transport Cost

Cost estimates for constructing new CO 2 pipelines and for transporting CO 2 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 CO 2 , and population and infrastructure development density. In certain circumstances, it may be more economical to transport CO 2 a longer distance to a lower co st high-quality storage formation than it is to transport it over a short distance to a more expe nsive storage operation in a lower quality storage field. Local costs for labo r and materials will also affect overall CO 2 transportation costs. Recent studies have shown that CO 2 pipeline transport costs for a 100­ kilometer (62 mile) pipeline transporting 5 m illion tonnes per year ra nge from approximately $1 per tonne to $3 per tonne, depending on the factors discussed above (McCollum and Ogden, 2006; McCoy and Rubin, 2008).

Transporting CO 2 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 CO 2 

### Pipeline Development

If CCS becomes commercially deployed, pipelines are expected to become the principal form of transport to bring CO 2 from point sources to geologic stor age sinks such as saline formations, coal seams, and oil and gas fields (Dooley et al., 2008). A review of the 500 largest CO 2 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 CO 2 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 CO 2 represent between 4 and 10 times the amount of
CO 2 transported in the United Stat es 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 th e amount of infrastructure necessary to support future CC S deployment (Dooley et a l., 2008; The INGAA Foundation,

III. State of CCS Technology 372009). 46 The estimated length of pipelines needed for commercial deploy ment 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 m iles of pipelines in the United States (EIA, 2008). While expected construction rates seem reasonable, CO 2 pipeline development will compete for resources, training needs, and additional draws on quantities of available

commodities such as steel.



### III.C CO 2 

### Storage

CO 2 storage refers to the process of injecting CO 2 into subsurface formations for long-term sequestration. CO 2 storage projects are multi-phase operat ions that include: (1) a pre-injection phase of site characterization that involves geol ogic evaluation of site suitability, modeling to predict the extent of the CO 2 plume and pressure front, and identification and plugging of artificial penetrations that could serve as cond uits for fluid movement; (2) an operational phase during which CO 2 is injected and the injection well is tested, ground water geochemistry is monitored, and the CO 2 plume is tracked; and (3) a post-inje ction phase of site monitoring to verify that the project poses no risk to under ground sources of drinking water (USDWs) and

site closure.

This section of the report presents a brief overview of CO 2 storage in geologic reservoirs. CO 2 reuse is not addressed in this section, but is considered a potential alternative approach to mitigating CO 2 emissions and is discussed in Appendix D.



### III.C.1 Introduction

Although engineered storage of CO 2 in geologic reservoirs is a relatively new concept, largescale natural CO 2 formations are known in numerous reservoirs worldwide, and many natural gas formations contain CO 2 . These natural examples demonstrate that large volumes of CO 2 can be retained in the subsurfa ce stably over geologic time. Na tural reservoirs can store as much as 5,600 million tonnes (100 trillion cubic feet) of CO 2 and can be as pure as 98 percent. They also provide natural laboratories to test the long-term interaction of CO 2 with subsurface fluids, reservoir mineralogy, and seals.



### III.C.2 Status of Technology

III.C.2.1 CO 2 Enhanced Oil Recovery

Since the 1970s, engineered injection of CO 2 into geologic reservoirs has occurred in the
context of EOR. CO 2 -EOR and enhanced gas recovery tech nologies are used in oil and gas

46 CCS deployment rates in the INGAA st udy are based on a summary of projec tions 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 Fo rce on Carbon Capture and Storage 38reservoirs to improve producti on efficiency. Injection of CO 2 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 ca se of oil, by also increasing mobility. Although
some features of CO 2 storage may differ from EOR operations, these operations have developed many aspects of reservoir manageme nt and operation needed for the large-scale injection of CO 2 . Use of such large volumes of CO 2 in EOR has shown that CO 2 can be injected at an industrial scale safely for long periods of time. Currently, approximately 50 million tonnes
of CO 2 per year are injected, pr oduced with the oil, captur ed, and re-injected. These operations are large in scale, with some injecting millions of tonnes of CO 2 per year, and some having already accumulated tens of millions of tonnes (Sweatman et al., 2009). As of year-end 2010, there were 114 CO 2 -EOR projects within th e 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 be low, depleted or active oil and gas reservoirs because the reservoirs have already been char acterized for hydrocarbon recovery, may have suitable infrastructure (e.g., wells and pipelines ) in place, and may prov ide revenues associated with recovery of additional crude oil. In addi tion, oil and gas fields now considered to be depleted may resume operation if there is an in crease in availability and decrease in cost of anthropogenic CO 2 . However, the extent that CO 2 -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 CO 2 used per barrel of oil produced, whereas CCS strategies will likely seek to maximize CO 2 stored. These changes in use of the reservoir would result in pressure increases. EPA is deve loping tailored regulatory requirements and management strategies to safeguard public health an d the environment in light of this effect (see section IV.B for details).

III.C.2.2 CO 2 Storage Potential

CO 2 storage potential is estimated to be larg e. Estimates based on DOE and International Energy Agency (IEA) studies indicate that areas of the United States wi th appropriate geology could theoretically provide storage potential for more than 3,000 billion tonnes of CO 2 —large enough to store the amount of CO 2 emissions currently emitted from the entire coal fired electricity sector in the Unit ed States for over 1,000 years. 47

As an outgrowth of efforts in the Regional Carbon Sequestrati on Partnership (RCSP) program, DOE produced the 2008 Carbon Sequestration At las of the United States and Canada, which

47 The coal fired electricity sector emitted 1,945.9 million tonnes of CO 2 in 2008. (EIA, 2009)

III. State of CCS Technology 39evaluated geologic storage potent ial with respect to three categories of storage reservoirs. The Atlas reports that storage resource and capacity 48 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 vari able, 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, in cluding geologic factors (e .g., heterogeneity in reservoir porosity/permeability, caprock integrity, etc.) and hydrologic factors (e.g., movement
of CO 2 , 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 assessmen t methodologies” for estimates of storage resource (IPCC, 2005). Researc h by DOE and USGS is addre ssing some of the factors contributing to uncertainties in estimates, for example:

 Improvements to the efficiency factors (the portion of pore space that the CO 2 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 an d 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 CO 2 .

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 Fo rce on Carbon Capture and Storage 40III.C.2.3 CO 2 Storage Security

The technical community believes that many aspects of the science related to geologic storage security are relatively well understood. For exam ple, IPCC concluded that “it is considered likely 50 that 99 percent or more of the injected CO 2 will be retained fo r 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 CO 2 and to quantify rates for long-t erm 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 th e best available science and tec hnology is central to ensuring storage integrity at each site . Experience at commercial-scale sites includes the following:

 Up to 14 years of continuo us monitoring at large-scal e CCS projects demonstrates geologic storage security (e.g., Sleipner , Snøhvit, Weyburn, In Salah); and

 Monitoring at large EOR sites provides additi onal data that suggests nearly 40 years of storage security (e.g., sites in th e Permian basin of West Texas).

Additional commercial-scale experience is need ed to confirm these estimates for a range of geological conditions.

EPA has also developed a Vulnerability Evaluati on 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 id entifying key factors to minimize risk.

50 The IPCC definition of “likely” is a probability between 66 and 90 percent.

III. State of CCS Technology 41Figure III-2 Vulnerability Evaluation Fram ework for Geologic Sequestration of CO 2

Source: EPA (2009a)

Broad consensus exists 51 regarding potential failure mode s and impacts associated with CO 2 storage. Key potential impacts could result from slow sustained releases as well as from rapid releases. For example, if improperly managed, CO 2 storage may endanger USDWs. While CO 2 itself is not a drinking water contaminant, CO 2 in the presence of water forms a weak acid, known as carbonic acid, that, in some instan ces, could cause leaching and mobilization of naturally-occurring metals or other contaminan ts from geologic formations into ground water (e.g., arsenic, lead, and organic compounds). A dditionally, pressures induced by injection may force native brines (naturally occurring salty water) into USDW s, causing degradation of water quality and affecting drinking water treatment processes.

CO 2 is not explosive or combus tible. Rapid release of CO 2 could, however, damage an injection well during operation and provide a conduit fo r contamination of USDWs. If supercritical CO 2 is injected into shallow formations where pres sures are not high enough to maintain its supercritical state and the CO 2 reverts to a gas, it could cause expansion of gaseous CO 2 , a drop in temperature (the Joule-Thomson effect ), and then freezing and thermal shock in the vicinity of the well. This the rmal shock could compromise the integrity of the injection well, increasing potential for fluid move ment 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 Fo rce on Carbon Capture and Storage 42In addition to risks to USDWs, injection activiti es could pose risks to the atmosphere, surface water, human health, ecosystems, an d the physical environment. While CO 2 is not toxic, direct exposure to elevated levels of CO 2 can cause both chronic (e.g., in creased 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
CO 2 to USDWs would also mi nimize the risk of CO 2 migration to the surface.

It is expected that, should these impacts aris e, they can be detect ed through appropriate monitoring, allowing consequences to be miti gated through readily available technology.

The risk of a rapid release of large and sustained amounts of CO 2 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 Co ntrol (UIC) Class VI requirements for wellbores (see Section IV.B.1.2 for detail) sp ecify cementing along the entirety of the wellbore, greatly reducing the chance of leaving an open space section for CO 2 flow along the wells.

 Natural mechanisms associated wi th the small pores in which CO 2 is stored further act
to restrict rates and volumes of CO 2 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 CO 2 

### Storage Technologies

III.C.3.1 Regional CO 2 Sequestration Part nership Projects

In 2003, DOE initiated the Regional Carbon Se questration Partnership (RCSP) program to provide guidance and experience related to de veloping the technology, infrastructure, and regulations needed to implement storage of CO 2 in the various regions and geologic formations found across the United States. The RCSP pr ogram has three phases: identification and characterization of potential sequestration opportuni ties (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, on e of which has already begun injection operations. The more than 20 sm all-scale field tests that were conducted as

III. State of CCS Technology 43part of Phase II have already yielded valuable information on how to safely and efficiently store
and monitor CO 2 in common formations fo und in the United States. 52

Additional studies are planned or underway. Ba sed on data tracked by EPA and DOE, as of April 2010, a total of 56 active storage or integr ated 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 perc ent are in the process of obtaining permits, 4 percent are drilling wells, and 26 percent are injecti ng. (See Appendix C.1. 3 for more detail.)

III.C.3.2International Geologic Storage Projects

Engineered storage of CO 2 is occurring at several large-scal e operations: Sleipner in the North Sea, Snøhvit in the Barents Sea, In Salah in Alge ria, and Weyburn in Canada. Although limited in number, these projects demonstrate CO 2 storage at commercial scale over a variety of geologic conditions and monitoring approaches that will be applicable to many potential CO 2 storage sites worldwide. (See Appendix C for details).



### III.C.4 CO 2 

### Storage Cost

Costs associated with CO 2 storage have been estimated to be approximately $0.4–20/tonne. 53 For example, the IPCC summarized several st udies from 2002–2005 reporting estimates in the range $0.4–12.2/tonne CO 2 stored plus $0.16–0.30/tonne CO 2 stored (undiscounted) for monitoring (IPCC, 2005). Estimates vary depe nding 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, whic h, 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. Re cent estimates of storage costs derived from current commercial-scale projects are $11–17 pe r tonne (Sleipner); $20 per tonne (Weyburn) and $6 per tonne (In Salah).

Additional revenues from oil produ ction may offset some costs for CO 2 storage in the context of an EOR operation. CO 2 -EOR provides two potential economic incentives for encouraging the deployment of CCS, 1) CO 2 sales revenues at the individual project level, and 2) an increase in the total amount of domestic crude oil produ ction. At the present time, an important limiting
factor in new CO 2 -EOR projects is a shortage of CO 2 .

52 Additional information about the part nership projects is available at http://www.netl.doe.gov/technologies/carbo n_seq/partnerships/partnerships.html

.

53 Cost estimates are limited to capital and operational cos ts, and do not include potential costs associated with long-term liability.

Report of the Interagency Task Fo rce on Carbon Capture and Storage 44The willingness of oil producers to pay for CO 2 supplies has the potential to defray a portion of the cost of building carbon capture and transporta tion facilities, particul arly 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 CO 2 for EOR. Along with Federal funding, the CO 2 sales are an important part of the project funding.

The second potential benefit of EOR for deployme nt 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 CO 2 -EOR in 2035 is proje cted to be 1.3 million barrels per day. EIA found in its analysis of th e American Power Act of 2010 that the additional CCS deployment spurred by the le gislation would result in 0.8 to 1.0 million barrels per day of additional crude oil production (EIA, 2010). Th e resulting reduction in U.S. net import expenditures from the incremental domestic cr ude 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.5 Technical and Other Considerations for CO 2 

### Storage

III.C.5.1 Geologic Siting and Area of Review Monitoring

Site characterization is a fundamental compon ent of selecting safe locations for geologic storage. The proposed new Class VI regula tion under the SDWA UIC program requires owners or operators of CO 2 storage wells to perform detaile d assessments of the geologic, hydrogeologic, geochemical, and geomecha nical properties of the proposed CO 2 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 endangerme nt in the onshore environment and the subseabed within State territorial waters. Data colle cted during site characterization also inform the development of construction and operating plans, provide inputs for area-of-review (AoR) delineation models (see below), and establis h 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
CO 2 stream; it is based on availa ble data collected during the si te characterization process.

III. State of CCS Technology 45Operators must also periodically reevaluate the AoR over the life of the project to incorporate
CO 2 monitoring and operational data into models in order to ensure that the CO 2 plume is moving within the subsurface as predicted.

III.C.5.2 Monitoring, Veri fication, and Accounting

Monitoring, verification, and accounting (MVA ) are important components of managing a geologic storage project and ensuring that the CO 2 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 thei r projects that includes injectate monitoring; corrosion monitoring of the we ll’s tubular, mechanical, and cement components; pressure falloff testing; mechanical integrity testing of the well; ground water quality monitoring; and CO 2 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 quant ifiable protocols for each stage of a CCS project. Variation in local surface and subsur face characteristics necessitate that these monitoring strategies are site-specific, but ge neral approaches (including the establishment of standards) are needed, particularly in the contex t of wide-scale deployment of CCS. In addition, the development of risk-based monitoring pr otocols 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 CO 2 sequestration facilities (EPA, 2009b), IPCC Guidelines for National Greenho use Gas Inventories (IPCC, 2006), API/IPIECA Guidelines for CCS (IPIECA, 2007), Department of Energy MVA Best Practices Manual (NETL, 2009a), and the International Ene rgy Agency GHG R&D Programme monitoring tool Web site (IEA, 2009b). In addition, Dooley et al. have summ arized 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 CO 2 in the subsurface, detection of fr actures and other potential leakage paths, intermittent leak age, 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 moni toring and site care to verify that the CO 2 plume is moving as predicted. This monitoring continues until it can be demonstrated that

Report of the Interagency Task Fo rce on Carbon Capture and Storage 46movement of the CO 2 plume and pressure front have stabili zed 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 CO 2 mobility over time (e.g., IPCC, 2005). In addition, site characterization, site operat ions, 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 CO 2 Storage Operation.

Risk is expected to increase during the injection phase of a st orage 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 characteristic s, 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 considerat ions 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 test s 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 47DOE’s National Risk Assessment Partnership (NRAP) initiative is building the scientific basis for quantifying risk profiles. NRAP comprises a br oad interdisciplinary team of scientists and engineers drawn from across the DOE complex de veloping and confirming (through targeted laboratory and field observations/experiments) a suite of science-based t ools for calculating the residual risk associated with sp ecific geologic storage sites.

III.C.5.5Potential Impact of Impurities in the CO 2 Stream

Purity of the injected CO 2 stream is a consideration for st orage because co-captured impurities could affect the storage proce sses 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 po tential 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 demonstr ation 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 ofthe basin-scale factors associated with widescale deployment.

III.C.5.7 Property Rights

Deployment of CO 2 sequestration would necessitate addr essing 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-wa y (e.g., for pipelines); placement and access to monitoring wells and devices at various locati ons; subsurface movement of injectate; and elevated regional pressure fronts due to inje ction. New Federal requirements proposed under the UIC Program for CO 2 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 woul d be guaranteed for areas requiring future corrective action. Access may also be needed for other aspects of the CO 2 storage operation, such as groundwater monitoring outside of the injection zone. Stakeholders noted aggregation of subsurface pore space within target injection fo rmations as particularly critical to the success
of CO 2 storage projects in th e near- and long-term.

Report of the Interagency Task Fo rce on Carbon Capture and Storage 48Pore Space Ownership

CO 2 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 us e of pore space in which they are storing CO 2 .
Pore space ownership issues will vary from State to State. In States wh ere 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 owne rship, a lease, or acce ss to, the pore space. Where subsurface minerals exist, many surfac e 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 reason able 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 CO 2 storage and mineral production.

Aggregation of Pore Space
Pore space could be acquired through an agreemen t with a single owner who owns all surface and subsurface rights. However, issues may arise where pore space needs for CO 2 storage
extend over an area where numerous owners ho ld rights. Currently in most States, owneroperators would need to engage in private comm ercial transactions with property owners to acquire ownership or lease the pore space. Whil e 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 mo re 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 CO 2 storage. These options are diverse; some would rely on private transactions, some on action by State government, and some on Federal intervention. These options ar e discussed in Appendix L. Which option or options are appropriate will depend on, among ot her 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
CO 2 storage property-rights issues such as owne rship, access to pore space, interaction
between mineral estate interests and CO 2 injection operations. 55

55 Selected State legislation relating to CO 2 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 CO 2 

### Capture

 Carbon dioxide gas separation technologies have been developed and employed in the industrial sector (e.g. petroleum refining, na tural gas purification) for more than 70

years.

 Current technologies coul d be used to capture CO 2 from new and existing fossil energy power plants; however, they are not ready for widespread implementation primarily because they have not been de monstrated at the scale necessary to establish confidence for power plant application. Since the CO 2 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 techno logies on new and existing fossil energy power plants in terms of cost per tonne of CO 2 avoided, range from $60/tonne for IGCC, $95/tonne for PC to $114/tonne for NGCC. 56

 Existing CO 2 separation technologies deployed on new and existing fossil energy power plants will result in a significant en ergy penalty, up to 30 percent.

 Ten large-scale power plant and industrial pl ant demonstrations projects are currently being pursued by DOE and will provide information and experience regarding operations at scale.



### III.D.2 CO 2 

### Transport

 Technologies for the transport of supercritical CO 2 through pipelines exist today.

 Approximately 3,600 miles of CO 2 -dedicated pipelines exis t 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 in dustry to expand the existing network of CO 2 pipelines.

 No technology barriers have been identifi ed that would hinder the development of these additional pipelines in the United States.

56 The dollar per tonne of CO 2 avoided is the incremental cost of CO 2 emissions avoided by applying CCS and is compared to a similar non-captured facility. It is calcul ated by dividing the difference in COE, $/MWh, by the difference in CO 2 emissions with and without CO 2 capture, tonnes/MWh. The dollar per tonne CO 2 captured is the incremental cost per tonne of CO 2 captured and is calculated by dividing the difference in COE, $/MWh, by the total CO 2 emissions captured, tonnes/MWh.

Report of the Interagency Task Fo rce 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 CO 2 

### Storage

 Large-scale CO 2 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, CO 2 storage should continue to be fielddemonstrated for a variety of geologic rese rvoir classes, with large-scale projects targeted at high-priority rese rvoir classes and smaller-scal e projects covering a wider range of classes that are important regionally.

 Storage security is believed to increase ov er time. Field-validated methodologies will help to quantify potential for risks tied to long-term liability.

 Scale-up from a limited number of demonstr ation projects to widescale commercial deployment may necessitate the considerat ion of basin-scale factors (e.g., brine displacement, overlap of pressure fronts, spat ial 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 an d the environment, and provides public
confidence that CO 2 can be stored safely and securely.

 Clarity with respect to the long-term liability for CO 2 sequestration , in particular regarding obligations for stewardship after cl osure and obligations to compensate parties for various types and forms of lega lly compensable losses or damages.

 Integration of public information, ed ucation, and outreach throughout the lifecycle of CCS projects in order to identify key issues , foster public understa nding, and build trust between communities and project developers.

In addition, some stakeholders have voiced co ncerns about training/workforce capacity and physical/infrastructure capacity. The widesprea d cost-effective deployme nt 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 challe nges will face the public sector in meeting the need for permitti ng and regulating CCS activities.

The Task Force recognizes that aggregation of po re space can be a barrier to deployment of
CO 2 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 CO 2 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 conc erns for CCS deployment for the four major issues identified above. Options for addr essing 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 (ins tances 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 po tential for introducing inefficiencies, such as distortions to capital and labor markets that resu lt from policies that ar e poorly targeted in scope or size, and from distortionary taxes used to raise revenue to pay for the intervention. The opportunity cost of lost sp ending on other government prio rities 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-effectiv e 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 mar ket failures described below impede early CCS deployment that could provide learning and lo wer future costs. Therefore, a complementary portfolio of measures to target these market failures will introduce in centives 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 external ity 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 lo w-carbon technologies on a level playing field with conventional carbon-emitting technologies , yield near-term opportunities for emerging technologies, and create greater market cert ainty for long-term investments in new or improved low-carbon energy technology development.

Internalizing the cost of GHG emissions is a th reshold barrier for further CCS technological development. Without an economic consequenc e 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 de velopment, as described below, which requires a separate policy remedy.

Report of the Interagency Task Fo rce on Carbon Capture and Storage 54

### IV.A.3 Knowledge Spillo vers from Research and Development of CCS Technology

Even with clear market signals that internaliz e 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 “knowledg e 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 a ppropriable, private benefits, even though such investment may provide additional social benefi ts. Put simply, individual firms will not typically take on investments for the good of the broader industry or societ y 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 wo uld 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 valu able but difficult to appropriate economic returns.

Investments that create knowledge further do wn 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 CO 2 ) creates knowledge (often referred to as learning -by-doing), and some portion of the gains from that knowledge cannot be captured by the firm maki ng the investments.

As a technology moves through the life cycl e from basic research to more targeted development and ultimately deployment, the shar e 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 benefi t created by innovations in the technology can be captured by those making th e investments through patents or other means. The smaller spillovers that occur as technologi es 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 incent ives so as not to create distor tions that outweigh the gains to society of promoting a particular technology.

Figure IV-1 shows a stylistic representation of th e relationship between spillovers as a share of the total benefit to society of new knowle dge and the phase of knowledge/technology development. Section V of this report desc ribes how policy makers ca n address the market failure of knowledge spillovers, including the ad vantages and disadvantages of applying a variety of incentive structures for the public sh are of investment in CCS technology.

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 55Figure IV-1 Private versus Spillove r Benefits of Knowledge Creation



### IV.B Regulatory Framework Governing the Capture, Transportation, and Storage of CO 2

Regulatory uncertainty is widely identified as a key barrier to CCS deployment in the United States. Existing environmental statutes and pr ograms such as the SDWA UIC Program apply to geologic sequestration of CO 2 . However, because CCS has not been widely deployed, there is uncertainty about how environmen tal statutes will apply, whet her 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, transpor tation, and sequestration phases of CCS. 58,59 This

58 The full array of Federal, State, and local laws, as applic able, will govern any particular CCS project. Appendix F and Appendix G analyze in greater detail how selected en vironmental, natural resource, and other laws may apply to CCS. Acquisition of property rights needed to inject an d store CCS and short- and long-term liability potentially

Report of the Interagency Task Fo rce on Carbon Capture and Storage 56section also identifies some ne ar- 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 releva nt 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 info rmation 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 St ate environmental planni ng review obligations. Of these, the Federal statute likely to be app licable 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 requ ires all Federal executive branch agencies to undertake specified assessments before they ma ke final decisions about Federal actions that
could have environmental effects. The environmen tal review process under NEPA also provides multiple opportunities for the public, States, Tr ibes, and local governments, among others, to participate in the Federal agency decision-making process, which will be cr itical 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 subjec t to Federal control or responsibility. Use of Federal or Tribal lands for the purposes of CO 2 pipeline siting or sequestration will require NEPA analysis. Non-Federal projects, which ar e 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 verycomplex 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 projec t in some instances. For example, where Federal or private actions in CCS deployment might affect endangered or threatened sp ecies 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 57intensive analysis to determine when a private project has become federalized. Because Federal agencies will likely be significantly involved, at leas t in the short-term, in the planning, financing, and permitting of CO 2 sequestration projects on private and Federal lands (on and offshore), NEPA could apply to those activities. Some perm itting activities may be exempt from NEPA, however, where a statute or regulation provid es for a similar environmental review process and public participation. For example, the issuance of a SDWA UIC permit for CO 2 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 Environment al 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 ma y 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 En vironmental 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 CO 2 sequestration. Site-specific analysis under NEPA would still be required for specific pipeline or sequestratio n 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 analys is. Once site-specific projects are identified, NEPA analysis for such projects will require addi tional 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 ma ny of the issues discussed in this report. On the other hand, attempting to co nduct such an analysis late in the planning process would undercut the utility of the NE PA 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 ha s 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 Fo rce on Carbon Capture and Storage 58Resource 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 require ments for generators and transporters, along with permitting and other requirements for hazard ous waste “treatment, storage, or disposal”
facilities. 63

Under EPA’s regulations, a solid waste is a haza rdous waste if, among other things, it exhibits the characteristic of toxicity. 64,65,66,67 CO 2 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 CO 2 stream is a hazardous waste based on toxicity will depend on whether it cont ains specific chemical constituents at levels above the toxicity characteristic concentrations in Table 1 of 40 C.F.R. § 261.24(b). A captured
CO 2 stream that meets the definition of a ha zardous waste will have to comply with all applicable RCRA requirements.

Various groups and studies have characterized po tential RCRA applicability as a possible barrier to CCS deployment due to its complex regulatory regime. 68 Characterization of a CO 2 stream as “hazardous waste” would make the RCRA wa ste management scheme applicable to the generation, transportation, treatment, se questration, and/or disposal of the CO 2 stream. This determination would mean that underground injection and sequestration of such a CO 2 stream would need to meet the requirements for Cla ss 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.

66 Hazardous secondary material which is used or re-use d 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 CO 2 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 le gitimately recycled. In addition the hazardous secondary material cannot be accumulated specul atively, meaning, generall y, 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 ener gy recovery nor re-used in a manner that constitutes disposal (i.e., being put on the land or used to make a pr oduct 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 CO 2 .

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 59Program, §§ 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 (CO 2 ) Geologic Sequestration Wells, 73 Fed. Reg. 43492, 43503 (July 25, 2008).

EPA is evaluating how and whether RCRA haza rdous waste requirements may apply to certain
CO 2 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 CO 2 streams in order to facilitate implementation of geologic se questration 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 no t managed pursuant to sp ecified 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 CO 2
One Clean Air Act (CAA) requirement that specifically applies to CO 2 capture is Subpart PP of the GHG Reporting Program. Facilities that capture CO 2 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 CO 2 supplied to the economy and a pplies to all facilities with CO 2 production wells, facilities with production process units that capture and supply CO 2 for commercial applications or that ca pture and maintain custody of a CO 2 stream to sequester or otherwise inject it underground, and to importers and exporters of bulk CO 2 .
Other relevant Clean Air Act provisio ns may apply to the capture of CO 2 . 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 en ergy is needed to capture and compress CO 2 . This energy could be derived from dive rting 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 requi red 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 Cla ss 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 CO 2 ’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 Fo rce on Carbon Capture and Storage 60Transportation of CO 2
Captured CO 2 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 CO 2 . 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 CO 2 pipelines in the United States ha ve generally been the province of State and local government. 72 State law also governs the rates, terms, and conditions of service provided by CO 2 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 CO 2 pipelines pursuant to the Hazardous Liquid Pipeline Act of 1979, as amended, 49 U.S.C. § 60101 et seq ., and the Hazardous Materials Transpor tation Act, 40 U.S.C. 5101 et seq . Design, construction, operational, and emergency response requirements for CO 2 pipelines are contained in 49
C.F.R. Parts 190–199 and 40 C.F.R. Parts 171–180.

Storage of CO 2
Due to their importance and public interest, th is section highlights the applicability of the SDWA UIC, CAA, and Comprehensive Environm ental Response, Compensation, and Liability Act (CERCLA, commonly known as Superfund) programs to CO 2 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 mu st 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), EP CRA and the CAA, where applicable by their terms.

72 In 1979, the Federal Energy Regulatory Commission (FERC) ruled that because CO 2 pipelines do not transport natural gas (described as a gaseous mixture having hydr ocarbons 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 Tr ansportation 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 Orde r--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 CO 2 pipelines.
Most current and projected future CO 2 pipelines transport CO 2 as a supercritical liquid, so they are subject to regulation as hazardous liquids.
However, future projects may increasingly require transport of CO 2 in a gaseous state. While PHMSA does not currently have statutory authority to regulate the safety of the transport of CO 2 in a gaseous state, if those authorities were to arise, any regulatory activity associat ed with exercising those authorities would be subject to public notice and comment.

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 61SDWA UIC Program

SDWA’s UIC Program regulates the underground in jection of fluids into the subsurface to prevent endangerment of undergro und sources of drinking water. 73 Supercritical CO 2 falls under the definition of “fluid” (40 C.F.R. § 144.3); thus underground CO 2 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 CO 2 for purposes of geologic sequestration. 74 The proposal builds on experience from the exis ting regulatory program, which provides the technical framework, expertise, and experience for permitting CO 2 sequestration. The rule proposes a new Class VI UIC well type for injection of CO 2 . The proposal applies to owners or operators of geologic sequestration we lls that will be used to inject CO 2 into the subsurface for long-term sequestration. The proposed Cla ss VI UIC well require ments address site characterization, area of review, well constr uction, 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 CO 2 , including its large volumes, buoyancy, viscosity, and corrosivity. The SDWA does not provide EPA with the authority to sh ift 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 move ment 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 fi nal and into effect, CCS will continue to be permitted under the existing SDWA UIC Program, in cluding existing State primacy authorities. Current options for permitting UIC wells that inject CO 2 include Class I industrial, Class II EOR, or Class V experimental wells, de pending on individual conditions.

SDWA provides States an option to assume prim ary enforcement responsibility, or primacy, to oversee injection wells in thei r State. States issue UIC permits for injection wells onshore and could implement those requirements for wells in side State territorial waters. EPA encourages States to assume primacy for Class VI wells beca use 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 anc illary activities (e.g., pipeline operations, pore space ownership, land use rights, and surfac e access) for which Stat es 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 Fo rce on Carbon Capture and Storage 62role 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 fo r review and approval. During this time, States with existing UIC primacy for all other well clas ses under §1422 of SDWA that receive Class VI permit applications may consider using existing auth orities (e.g., Class I, Cl ass II, or Class V), as appropriate, to issue permits for CO 2 injection for sequestration wh ile 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 th e 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 require ments have become applicable in the Federal Register. States may not issue Class VI permits until their Class VI UI C 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 di rect 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
CO 2 sequestration facilities. 75 CO 2 sequestration facilities woul d be required to develop and implement an EPA-approved, site-specific monitoring , reporting, and verification plan. This rule would not establish performance standards for CO 2 sequestration facilities but would require annual reporting of the amount of CO 2 sequestered. Under the proposal, reports would be submitted annually, with the first reports due to EPA in 2012 for CO 2 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 CO 2 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 63may 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 CO 2 injectate, it appears that under likely capture scenarios, the CO 2 could contain “hazardous substances” (e.g., arsenic and selenium). CO 2 sequestration projects would likely fall within the definition of a “facility” (as a site where a hazardous substance is deposi ted or stored), and owners and operators of
CO 2 sequestration projects are among the persons covered by CERCLA that could qualify as responsible persons if a plaintiff were to in cur cleanup costs. Consequently, CERCLA liability could apply, unless an owner or op erator could establish a defense. 76 If CO 2 enters groundwater, it might also cause hazardous substa nces, such as some meta ls, 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 CO 2 streams fall within the scope of a permit under the SDWA UI C 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 CO 2 injectate. Because CERCLA plays an important role in ensuring that there are financial resources and an accountable part y (or parties) able to respond to any release occurring during CCS activities, any analysis of statutory change s would need to address the potential need for alternative methods of provid ing 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 righ ts 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 discusse d below, may allow the siting of pipelines for transportation of CO 2 and the sequestration of CO 2 on BLM and Forest
Service lands.

Title V of the Federal Land Policy and Ma nagement 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 Fo rce on Carbon Capture and Storage 64private entities for pipelines and other systems fo r the transportation or distribution of liquids and gases (excluding those governed by the Mine ral 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 environmenta l values and Federal property and economic
interests. See also 43 C.F.R. Part 2800. FLPMA also authorizes Fe deral agencies to hold a rightof-way for transportation or distribution of liquids and gases governed by the MLA. FLPMA does not require such rights-o f-way to be constructed, oper ated, or maintained as common carriers (i.e., transporting CO 2 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
CO 2 from a natural gas stream across BLM lands or Federal lands administered by two or more Federal agencies. Such pipelines must be constructed, operat ed, and maintained as common carriers with certain limited exceptions, and Fe deral agencies are not included among qualified applicants. Due to the vast tr acts of Federal lands in the western United States, many CO 2 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 au thorizes the sequestration of CO 2 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 transportati on 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 forb idden by law and not authorized by other laws or regulations. See also 43 C.F. R. § 2920.1-1. The MLA provides au thority to lease lands for the extraction of minerals; however, it does not au thorize disposal of wastes, except those arising from lease operations. There is no MLA provis ion analogous to § 302(b) of FLPMA that might provide authority for CO 2 sequestration.

Section 202 of FLPMA, 43 U.S.C. § 1712, requi res that BLM prepare resource management plans to provide for the use of the public lands an d 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 Fo rest 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 CO 2 was a natural gas stream, section 501(a)(2) was found to be inapplicable to the transportation of CO 2 . 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 CO 2 may be important in identifying whether Title V provides authority for CO 2 storage.

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 65NEPA, 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 CO 2 pipelines across Federal lands, including the potential use of energy corridors.



### IV.B.2 Legal and Re gulatory 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 CO 2 sequestration, uncertainty around technology development, va riety of industry and regulatory actors, and potential scale of injection operations all pres ent uncertainties and potential areas that could stress the application of existing regulations an d resources. These considerations may warrant

additional actions that the Fede ral government could take to stre ngthen 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 framewor k for governing CCS and found that there are differences in scope, implementation approac hes, 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. Facto rs that may affect the regulatory requirements and implementing agencies include type of proje ct (e.g., experimental vs. commercial), source of funding (e.g., government vs. private), land owners hip (e.g., public vs. private), location of injection wells (e.g., onshore, offshore but gene rally within 3 miles, offshore and generally beyond 3 miles), type of sequestration reservoi r and/or project purpose (e.g., saline vs. oil field), purity of CO 2 stream, and source of CO 2 (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 th e 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 validatin g the results of complex computational models. As can be expected in a nascent industry, regula tory agencies will be ch allenged 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 Fo rce on Carbon Capture and Storage 66Permitting and regulatory authorities may face ch allenges in terms of training and workforce capacity. CO 2 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 fi rst responders. For sequestration, stakeholders have expressed concern that States may not have sufficient technical resources in very specialized areas related to CO 2 sequestration that will be critical in the review of permit applications, such as new site chara cterization technologies, specialized CO 2 -compatible well construction techniques, computational modeling, geochemistry, injection formation dynamics, and financial responsibility. State s may not have sufficient staff to review a large number of Class VI permit applications, write permits, an d review and enforce those permits.

Several challenges need to be addressed for on shore Federal lands to be fully used in an
efficient and effective manner for CO 2 sequestration. First, the BLM and the U.S. Forest Service (USFS) currently lack clear authority for long-term CO 2 sequestration. Second, the authority that may be applicable does not address issues of long-term liability, stewardship, ownership of pore space, and the appropriate re nt for the use of Federal pore space. As discussed in Section IV.C, CO 2 sequestration presents unique challeng es related to long-term liability and stewardship, since it is contemplated that the CO 2 will remain stored indefinitely, perhaps for hundreds or even thousands of years. BLM and USF S current authorities do not deal with these unique issues. Third, sequestration on split esta te 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. Thes e 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 oppo rtunities for public comment.

In addition, BLM does not currently have a stat utory or regulatory mechanism that directly addresses the assurances sought by current applic ants 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 CO 2 sequestration may potentially conflict with other subsurface uses, including existing and future mines, oil and gas fields, coal resources, geothermal fi elds, and drinking water sources. CO 2 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 CO 2



### IV.C.1 Overview

Many stakeholders have expressed the view th at 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 CO 2 . 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 interventi ons are appropriate, if any. It then analyzes the present legal regime relati ng 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 co mpensate parties for various types and forms of legally compensable losses or damages. Although financial responsibility is required until closure
of the CO 2 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 CO 2 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 CO 2 do not fall within the scope of this discussion. The discussion below al so does not address liability or stewardship of
CO 2 sequestration sites before the end of th e post-closure phase. Ensuring adequate stewardship and financial responsibility during that period is, ho wever, an important consideration in ensuring that long -term liabilities do not arise later.

IV.C.1.1 Existing Laws and Regulat ions Related to Long-Term Liability

Existing legal authorities include a range of a pproaches to liabilities related to long-term CO 2 sequestration. As noted below, although there is no comprehensive, integrated Federal framework specifically directed to defining or allocating long-term liab ility, 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 issu ed a proposed rule through its SDWA UIC Program to require owners or operators of underground geologic sequestration facilities to demons trate financial responsibility thro ugh post-injection site care. See 40 C.F.R. Part 146. The proposed rule provid es for owners or operators of sequestration
sites to demonstrate and maintain financial re sponsibility to ensure that resources will be

available to address adverse situations relate d to underground sources of drinking water throughout the lifetime of a project, even if th e operator experiences financial difficulty. The

Report of the Interagency Task Fo rce on Carbon Capture and Storage 68UIC regulations specify that owners or operator s 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 responsibilit y cost estimates at leas t annually to account for any amendments to the required project plans for th e 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 si te care and site closur e plan for at least 50 years following the cessation of injection, or unt il (either more or less than 50 years) the owner or operator can demonstrate to the Director 79 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 owne rs or operators. In addition, an owner or operator may be liable under §1431 of the SDWA af ter 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, pote ntially apply as we ll to the risks created by the longterm sequestration of CO 2 .
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 ti me after the last CO 2 has been injected and the site has been closed; until the time of transfer, the operator remains liable for damages related to CO 2 migration or leaks. Two States (I llinois and Texas) have accepted liability for certain CCS pilot projects within th eir borders. Two other States (Washington and Wyoming) have disclaimed State liability from long-term CO 2 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, th e Director is the EPA Regional Admini strator; for UIC programs in Primacy States, the Director is the person responsible for permitting, implementa tion, and compliance of the State, Territorial, or Tribal UIC program.

IV. Current Barriers and Concerns for CCS Deployment and Commercialization 69specified by law. Additionally, two States (Kan sas 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 numb er of stakeholders, particularly from private industry, have said that they consider long-te rm 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 technica l community believes that many aspects of the science related to geologic storage secu rity are relatively well understood, 80 the time frame over which the long-term risks might exist is lo ng, 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 ri sk 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 liabili ties are novel enough that businesses may encounter difficulties in re flecting 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 fi nancial officer will be required by the Sarbanes-Oxley legislation to sign a certification that based, on the offi cer’s knowledge, corporat e 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 ho rizon of underground sequestration may present a challenge to both the private and public se ctor. Some entities in the private sector are concerned over insurance requirements be cause the long-term horizon of geologic sequestration and its novelty appear to be limit ing the availability of coverage. Insurers state that they currently will not writ e policies to cover post-closure risks associated with CCS. Although they will underwrite conventional operat ional 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 CO 2 lost from a storage reservoir even in the shorter-term period, in light of the uncertainty as to the future per tonne price of CO 2 under future legislation. Thus, if a market for CO 2 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, whethe r other financial assurance mechanisms will be needed.

Report of the Interagency Task Fo rce on Carbon Capture and Storage 70are not able to estimate the costs of such po licies, their typical business does not encompass claims that may not arise for centuries, and th ey are not institutionally suited to underwrite risks arising in such a long time frame. Furt hermore, without insurance or a comparable risk management mechanism, private lending facilities may not be willing to exte nd credit to finance the construction of facilities conducting CO 2 sequestration. 83

A third set of issues identified by commentator s 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 CO 2 and contributes it to a particular reservoir could be held liable for the entire cost of any lia bility 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 CO 2 stream is acquired from third partie s, because of the larger number of parties that could potentially be involved in such transactions.

Other stakeholders and experts have questione d the substantiality of these concerns. They have said that a description of lo ng-term liabilities associated with CO 2 sequestration is ordinarily sufficient for recognition purposes in audited financial statements where an entity cannot establish a quantified estimate of such liab ilities, 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 thei r activities (Center for Biological Diversity et al., 2010). 86 Moreover, in other circumstances, simila r long-term risks do not appear to deter businesses from participating in commercial activities. For exampl e, businesses handle hazardous materials notwithstanding the potentia lly indefinite nature of CERCLA liability.
Material sent to a landfill can likewise generate indefinite liabilities under CERCLA. (One possible distinction, however, is that insu rance may be available in those settings.)

IV.C.1.3 Risks, Harms and Potential Liabilities Associated With CCS

The long-term sequestration of CO 2 gives rise to an assortment of potential risks, harms, and legal liabilities. Potential categorie s of risks include scientifically identifiable risks, e.g., the migration of CO 2 in ways that are scientifically understood; anomalous or unpredicted

83 Communication from GE Financial Services.

84 Communications from Coal Utilization Research Co uncil, North American Ca rbon Capture and Storage Association, and AEP Representatives.

85 See, e.g., S. 1013, the statement of Chiara Trabucchi on the De partment 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 Standard s 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 71behaviors, e.g., unpredicted geophysical or chemic al 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 CO 2 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 oper ations 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 associ ated with underground geologic sequestration of
CO 2 are expected to be highest during the operat ional phase of the project when insurance is available, and then decrease ov er 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
CO 2 . Exposure to CO 2 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. CO 2 migration underground can cause toxic substances (such as lead or arsenic) in surround ing rocks to dissolve into groundwater, through
acidification or other mechanisms. Groundwater co uld also be contaminated by brine displaced by CO 2 injection. CO 2 migration may also harm mineral deposits. 88 Finally, harm to the climate (or loss of benefits of sequestration) is associated with the release of CO 2 . 89

Potential legal liabilities associated with th e above harms include both performance and compensatory liabilities, as noted above. Perfo rmance liabilities include stewardship obligations of private entities, States, or the Federal gov ernment under environmental regimes (e.g., the proposed SDWA UIC Program described below), wh ich may range from monitoring to cleanup or other obligations. Compensatory liabilities incl ude tort liabilities under Federal or State law pursuant to various personal injury or property damage theories, including trespass, nuisance, negligence, and abnormally dangerous activities/str ict liability; liabilities arising from government action constituting a taking of private prop erty; 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 with in the scope of the present section.

89 There are also additional potential harms that are largel y associated with the injection phase, rather than with long-term stewardship. These include su rface 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 Fo rce on Carbon Capture and Storage 72sequestration transaction; and liabilities of site operators, on indemnification or other theories. Finally, if future legislation imposes a price on CO 2 emissions, a release of CO 2 could give rise to a claim for the replacement costs of lost CO 2 . 90

It bears noting that EOR activi ties in oil- or gas-producing areas for a number of years have included underground injection of CO 2 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 CO 2 in a manner very similar to EOR activities, should be chilled by long-term liability concerns. There are, however, a number of potential distinctio ns. First, the process of producing oil reduces underground pressure levels, so that addition of CO 2 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 CO 2 is removed from an EOR site for use in other fields. Although some CO 2 typically remains in the reservoir, this also means that EOR operations may be comparatively lower risk. Finally, CO 2 has been used for EOR purposes for decades, which has he lped 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 approp riate option or combinations of options. These policy considerations includ e encouraging CCS deployment, minimizing moral hazard, 92 minimizing negative impacts on existing in surance markets and sources of financing,

90 A future CCS regime is likely to incorporate financial incentives to sequester CO 2 , whether in the form of a capand-trade system or in some other program. Thus, if CO 2 escapes sequestration, there is likely to be a cost of replacing the sequestration capacity in question, whethe r a per-tonne cost based on the then-current price of CO 2 credits, or a cost of repaying the incentive amou nts 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 en tire field is managed to optimize reso urce 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 ow n 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 73providing 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 wh o are harmed can be compensated, and equitably distributing the costs of liability (e.g., determini ng whether liability costs should fall on those entities that generate CO 2 ; on sequestration facility owners/ope rators; on utility ratepayers, in
the case of CO 2 generated as a byproduct of electric ity generation; or on the taxpayers generally). 93

Whatever approach is adopted should take in to account the continue d need for long-term stewardship, defined as oversight of an undergr ound 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 responsi ble 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 ve rsus later projects. So me 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 fo r regulating CCS activities, the most critical features relating to long-term liability will be th ose that serve to preven t such liability from occurring. Appropriate site selection is espe cially important in minimizing risks of CO 2 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 siti ng and operational standards as well as the environmental performance of the CO 2 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 sh ould 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 s ite closure requirements. 73 Fed. Reg. 43492, 43540-1. Specifically, owners or operators would be required to pr epare, 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 Fo rce on Carbon Capture and Storage 74Any policy that allows a party to submit a demo nstration 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-takin g by insureds (Zimmerman, 1990). Any of these
measures should therefore be linked to moni toring, enforcement, and other accountability mechanisms to deter such conduct. Financial responsibility 97 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 liabi lities and future costs (including such costs as the cost of long-term monitoring and any necess ary remedial action). Financial responsibility mechanisms could be held by an individual owner/operator or pooled across multiple owners/operators. If held by individual owners/o perators, 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 co uld appropriately be based on a site-specific risk assessment (and thus would potentially vary between sequestration fa cilities, rather than being uniform across such facilities) (Dooley et al., 2010b). These risk assessments, and the associated fees, could be reevaluated periodical ly 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 ch anging 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 sa fe and environmentally sound manner. Nongovernmental organization (NGO) commentators ha ve 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 sign al to the public that the technology is too dangerous to use or as a “bailout” of privat e industry with an a ttendant socialization of

injection has ceased, owners and operators must mo nitor the site to show the position of the CO 2 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 proj ect 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 activitie s in the area; and records that reflect the nature, composition, and volume of the CO 2 stream.

97 Financial responsibility requirements are designed to ensure that owners and op erators maintain adequate financial resources to fulfill their current and fu ture environmental obligations. See (EPA, 2008).

98 See generally S. 1013, the Department of Energy Carbon Ca pture 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 75significant potential environmental impacts an d/or widespread environmental contamination. Liability caps and indemnities may be seen as in direct 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 industri es. Also, except where a regulatory program is specifically designed to foster private insuranc e, 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 recogniz ed as critical components in the development of new energy infrastructure, an d are widely viewed as vital for cost-effective CCS deployment (IPCC, 2005; CRS, 2008; IEA, 2009c). La ck of public acceptance can serve as a barrier if project developers fail to recognize th e 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 exte nt unknown. Most studies, in fact, have shown that the public is largel y 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 po tential for concern by local communities that they will be subjected to high risks while others derive the benefit. Ea rly experience has shown that local opposition can cause or contribute to project delays and cancellations. Geologic sequestration projects planned in Spremburg, Ge rmany and Greenville, Ohio were cancelled, in part, due to concerns from residents about escaping CO 2 endangering public health, reduced property values, and induced seismicity (Associ ated Press, 2009; Sl avin 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 po sitive experiences with public outreach and engagement. The Regional Carbon Sequestration Partnerships (RCSP) have managed the implementation of 21 sm all scale and several large scale CO 2 sequestration projects that have either been co mpleted or are currently injecting CO 2 in deep saline, coal seams, or oil and gas fields. The participants fr om these projects have worked to consolidate their experiences and lessons learned on comm unity engagement and acceptance into a best practices guide for public outreach and education (DOE, 2009).

Report of the Interagency Task Fo rce on Carbon Capture and Storage 76In order for CCS to be successfully deployed at scale it will be crit ical to address public perceptions of CCS technologies, their risks, an d their role in reducing GHG emissions. The primary avenues for such work are through outrea ch and education efforts, and through direct engagement with project communities. When done su ccessfully, 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 gr oups could include residents; local, regional, and national business owners and organizations; labor and related organizations; environmental organizations; environmental justice organizatio ns; employers; employees; academia; emergency responders; media; policy leaders; and other institutions.



### IV.D.2 Elements of a Su ccessful Outreach Strategy

Under the RCSP, DOE has been engaging with lo cal communities to educate and inform them about planned pilot and demonstratio n projects in their areas. DOE’s Best Practices for Public Outreach and Education fo r Carbon Storage Projects presents lessons learne d through the planning and implementation of CCS projects, as well as best practices for community engagement. The

World Resources Institute also has issued reco mmendation for regulators, project developers, and local decision-makers for engaging with co mmunities. Many of th ese recommendations

center on common themes:

 Integrate public engagement and outreach effo rts 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 info rmation about CCS projects;

 Engage the community during the planning st age and maintain engagement throughout the project lifetime;

 Communicate the potential bene fits 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 oppo rtunities 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 woul d results in reduced air emissi ons of criteria pollutants. In retrofits of existing plants, since the ability to capture CO 2 from a power plant will require the plant to install
NO

xand SO

x 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 awaren ess and understanding of CCS and associated
risks. Early engagement and communication will be essential, as misinformation and misperceptions can quickly spread; once initial op inions are formed, they can be slow to change (Ashworth et al., 2010). Studies have shown th at public perceptions about CCS become more positive with more information, and NGOs are tr usted most as conveyers of this information. The public is less likely to trust information comi ng from a single source, particularly coming solely from industry or government (Shackle y 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 partic ular project will affect them: risks to health, drinking water, property values, as well as benefi ts 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 proj ects are constructed. Such communities can get involved through various means, including si te 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 di sproportionately 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 Fo rce on Carbon Capture and Storage 78consequences. Minority, low-in come, Tribal, and other popul ations historically underrepresented in environmental decision-making pres ent 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 prof iciency 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 in ternalizing 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 Fede ral incentives for CCS. A key objective of this section is to outline a framework for assessing wh at, if any, additional drivers and incentives may be warranted beyond those proposed or already in place.

Several factors serve to widen the gap betw een the social and private returns to CCS technology development relative to those experi enced by other low-carbon technologies at a comparable stage of development. The de ployment of CCS, unlike other low-carbon technologies, is entirely de pendent on adoption of measures to limit greenhouse gas emissions, adding to uncertainty fo r private investors. As outlined in this report, the widespread deployment of CCS also hinges on other unres olved 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 in ternational 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 th e nature and extent of such incentives is between ensuring the availability of a cost-effective tec hnology (as a hedge against risk to the economy pose d by climate change) and over-investing in a technology, leading to inefficient allocation of scarce public resource s 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 cons ideration should be given to any economic costs associated with such policie s. This section summarizes existing incentives for the development of CCS and provides prin ciples for evaluating the extent to which additional drivers or incentives may be consider ed. The ultimate objective of public investment in CCS technology is to suppo rt the achievement of GHG emission reduction goals at the lowest cost possible, and these options ar e 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 fo llowing 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 incent ives and drivers for CCS technology.

V. Framework for Addressing Market Failures 81

### V.A.1 Key Principles for Assess ing CCS Drivers and Incentives

Any assessment of policy driver s and incentives should be grounded in the context of the related policy goal. Table V-1 show s several key principles to wh ich incentives for CCS should adhere. In this report’s context, the purpose of drivers and incentives is to overcome those market failures that impede wides cale, cost-effective availability of CCS consistent with market signals, including a price on GHGs. This goal is no t easily translated into a measure of capacity deployed or GHG abated, and for good reason, as the market will be th e 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-effe ctive 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 th e specific market failure targeted;

2 Adjust to changing circumstan ces 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 thei r 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 wid espread cost-effective commercial availability. For example, an incent ive 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 fa ilures impeding cost-effective C CS commercial availability is not only difficult to judge, but will also change over time as the te chnology 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 wo uld 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-s cale over time, so that public investment channeled through the

Report of the Interagency Task Fo rce on Carbon Capture and Storage 82incentive structure keeps pace with changes in the magnitude of the market failure it is designed
to address. Since economic incentives can cr eate their own constituencies, making their reduction or removal politically difficult, polic y 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 practica l, incentives should allow the market to decide which particul ar technologies will be develope d. Private investors with their own money at risk will have the right incentives an d 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 coordi nate 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 incentiv es 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 ta xpayer and consumer cost. In pursuing this goal of cost-effectiveness, consideration should be given to relevant institutional details of the targeted markets, such as diffe rences between publicly owned and investor-owned utilities, or
differences between cost-of-se rvice 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 invest ment 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 a ssess 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 br oad 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 83distinguish between efficiency gains driven by shared technology learning and those driven by other factors. In this context, Federal policy shou ld conservatively balance potential subsidies against their costs. These costs include potent ial economic distortions from taxation and spending, the risk of having subsidies effectivel y 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 failu res should leverage considerable non-Federal public and private resources. As the market be gins to mature, growing experience with CCS plants operating under varied conditions an d configurations will shrink information gaps, thereby weakening the case for continued Fe deral 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, th ere should be continual reevaluation of the merits of continuing subsidie s as more is learned about the magnitude of any market failures that those incentives are expe cted to address. Nevertheless, it should be recognized that subsidies, once en acted, 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 ex tent that the cap reflects society’s judgment of acceptable emission levels. A policy requiring CO 2 abatement is a necessary precondition to the economic relevance of CCS proj ects at any scale beyond what the market currently supports
for EOR and beneficial reuse of CO 2 . 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 CO 2 emissions avoided (i.e., incentive design for public inve stment should complement, not duplicate, the market’s willingness to pay for mitigation).

A variety of policies can capture shared tec hnological learning in the demonstration and deployment phases of CCS development. Any portfo lio of incentives would need to be carefully

coordinated to address both the constru ction and operation of plants using CCS. 101 For example, production-based incentives would impr ove the project’s frequency of operation (and

100 For example, while Denbury Resources’s willingness to pay up to $7 per tonne of CO 2 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 Fo rce on Carbon Capture and Storage 84thus would increase the learning-by-doing th at may yield knowledg e spillovers), while investment subsidies may be more appropriate when the government has a comparative advantage in raising capital for riskier tec hnology applications (such as demonstration projects). 102

To address knowledge spillovers from demonstr ation and initial deployment, policy makers will need to determine how such potential spillovers im pair the market’s willingn ess to invest in the face of early CCS project risk and cost. Th e following sections detail these factors.

Large-scale demonstrations of CO 2 capture technologies are ve ry important for encouraging the successful commercial deployment of CCS (Kuuskraa, 2007; MIT, 2007; National Research Council, 2007; GAO, 2008). While industrial CO 2 separation processes have been commercially available for some time, they have not been deployed at th e scale required for large power plant applications. The CO 2 capture capacities for current indu strial processes are typically an order of magnitude smaller than the capaci ty required for a typical power plant.

A concern regarding CO 2 capture technologies is whether they will safely and reliably work when applied to coal-based power generati on. Based on previous experience of CO 2 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, uncertain ty 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
CO 2 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 ca tegories include “threshold” risk challenges,
which are addressed in other sections of this re port. 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 CO 2 capture technologies includes unforeseen problems in plant operation that coul d require design and/or operational reform. In addition, the gas streams being treated with current industrial CO 2 capture processes have different compositions and characteristics than flue gas generated by commercial-scale coalbased power plants that could adversely affe ct 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 ri sk-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 85demonstrations on actual flue gas will generate operational data to info rm 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 CO 2 capture technologies to coal-based power generation. Acquiring adequate financing for early adoption of CO 2 capture systems could be difficu lt until there is a positive track record of cost and performance. The risk of cost uncertainty is co mpounded by uncertain benefits from investing in utility-scale CCS technology in the absence of a price on CO 2 emissions.

Uncertainty over technology cost and perf ormance has a greater impact on investment decisions in the power sector, as projects requi re large upfront capital for long-term use. To justify a high-risk investment, private sector fi nancing 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 inve stments, locking in potentially suboptimal established technologies for decades.

To ensure viability for those commercial-scale demonstrations and earl y deployments of CCS power projects that are supported by public fun ds - on the basis of an ticipated 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 curr ently available CCS technologies are relatively expensive and energy-intensive, due to the ener gy required to capture, compress, transport,
and store CO 2 into geologic formations (Herzog et al., 2009).

Because CCS projects require relatively high capi tal 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 betw een these projects’ COE values and expected market electricity prices can be achieved bo th 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 fund ing of targeted CCS applications. The first pathway, referred to as “technology push,” includ es 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 financ ial and economic incentives structured to encourage private investment in advancemen t 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 Fo rce on Carbon Capture and Storage 86

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

CCS technologies currently exist but are not likel y to be widely deployed at coal-fired power plants and other large industrial point source s without additional kn owledge generated by research, development, and demo nstration activities. The current focus of RD&D activities is
thus two-fold:

 Demonstrate the operation of current CCS te chnologies integrated at an appropriate scale to prove safe and reliable capture and storage.

 Develop improved CO 2 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 in dustry and others to manage and perform RD&D activities on low-carbon fossil energy technologi es. The thrust of these activities, implemented by DOE’s National Energy Technology Laboratory (NETL), is the efficient and cost-effective
reduction and removal of CO 2 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 condu ct 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 de ployment of CCS technologies by addressing the knowledge spillover market failure that impe des 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 activities 103 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 CO 2 capture, transportation, and perma nent sequestration at commercialscale, coal-fired power generating facilities ha s not yet been demonstrated. From a technical perspective, the ability to capture CO 2 , compress it for pipeline deli very, 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 implementati on 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 87goal of five to ten commercial scale demonstr ations online by 2016, bu t will require carefully structured financial plans to manage the la rge costs associated with these projects.

Up to 10 integrated CCS demonstration plan ts in the power and industrial sectors are expected to begin operation in the United State s under DOE’s CCPI, FutureGen (funded by the ARRA and prior year funds), and ICCS solicitat ion (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 op erated. New power plant applications will focus on bringing together IGCC tec hnology with pre-combustion CO 2 capture, transport, and geologic sequestration. Power plant retrofit and industrial applications will demonstrate integrated post-combustion capture. Ta ble V-2 summarizes the planned DOE CCS demonstration projects. These projects, in tand em 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 pr ojects may identify any remaining gaps in the demonstration of capture technologies and clas ses of storage reservoirs. Early low-carbon energy projects, including these 10 CCS demonstr ation projects, may face economic challenges, such as the absence of a carbon price. To the extent appropriate, addi tional actions may be required to support these proje cts, 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 Fo rce on Carbon Capture and Storage 881,500,000 Saline 2015 American Electric New Haven, Chilled
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 char ge to the sale of fossil-based electricity. The fees would be weighted base d on carbon content of the fuel: coal-based generation would be assessed a charge higher th an oil-based, which is in turn higher than natural-gas-based generation. Existing legislat ive proposals would make between $1 billion and $2 billion available annually to support CC S 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 (“1 st generation”) CCS technology is described in Section III. As part of its R&D programs, DOE is pursuing advanced (“2 nd generation”) technologies that could si gnificantly reduce the cost and energy penalties associated with 1 st generation CCS technologies. For a full description of 2 nd generation technologies, see Appendix E. Curre nt DOE efforts include advanced computational modeling, simulation, and analysis to accelerate the development of 2 nd generation CCS technologies. This includes the development of science-based models of fossil fuel conversion processes; advanced high-temperature materi als; 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 mi tigation 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,
2 nd generation CO 2 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 89modern supercritical PC plant without CCS. For current 1 st generation CCS plants, DOE

estimates this increase to be 60–80 percent. For CCS retrof its, DOE estimates that the

increase in cost could be reduced by two-thirds with 2 nd generation technology (NETL, 2009b). For example:

 Advanced gasification-based technology coul d achieve high capacity factors and include membrane technology for O 2 supply and H 2 /CO 2 separation, warm gas cleanup, and either high-efficiency H 2 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 indu strial facilities could use advanced 2 nd generation
CO 2 capture technologies including solvents , solid sorbents, and membranes for postcombustion capture.

 Oxy-combustion power plants could use membranes for O 2 supply and other innovations to improve plant efficiency. Bett er understanding of flame characteristics, burner and coal-feed design, and analyses of the interactions between products of

combustion and boiler materials could im prove the development of low-cost and efficient oxy-combustion power plant systems.

CO 2 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 CO 2 sequestration tests are being cond ucted across the country under the Regional Carbon Sequestration Partnership Program that complement RD&D aimed at improving the ability to predi ct and track the flow of CO 2 injected into geologic formations, including an improved understanding of geol ogic trapping mechanisms that can reduce CO 2 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 2 nd generation CCS technologies, and DO E is currently working to utilize Recovery Act funding for this purpose. This accelerated program will focus on developing more efficient, lower capital co st 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, effici ent, cost-effective CCS sy stems depends strongly
on RD&D efforts to advance C CS technologies. U.S. governm ent collaboration with other countries on fossil energy technologies is mo tivated by the premise that joint technology RD&D can help to improve energy security, address climate chan ge challenges, and position
U.S. businesses as global technology leaders. Mutually beneficial RD&D with foreign partners

Report of the Interagency Task Fo rce on Carbon Capture and Storage 90and promotion of U.S. clean energy technologies in foreign markets are central to the U.S. government’s desire to address the environmenta l 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 lo wer 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 th e 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 ot her developed countries may help to prove the viability of CCS as a long -term climate change mitigation option by speeding global acceptance and commercialization an d 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 conti nue its leadership role engaging large, coaldependent emerging economies with rapidly ex panding power sectors to avoid locking in inefficient, high GHG emission power generation assets for decades. Failu re to do so may make subsequent CCS deployment more difficult an d 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 CO 2 emissions from coal use. Despite effo rts being undertaken in various fora, data on the potential geologic CO 2 sequestration capacity for th ese countries are not available on a consistent basis. However, an assessment of available data indicates that sufficient sequestration capacity is likely available where n eeded relative to these countries’ current coalbased emissions. Most of these countries lik ely have hundreds to thousands of years of potential sequestration capacity, based on curre nt 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 (Glo bal 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 iden tified and classified according to their development status and progress towa rd key decision points for project design, definition, cost estimation, exec ution planning, and risk analysis. Each of these projects was

V. Framework for Addressing Market Failures 91assessed against criteria developed by the IEA to ascertain whether they would meet the commitment made by G8 leader s in 2008 at their Ho kkaido Toyako Summit to launch 20 largescale CCS demonstration projects by 2010, with a view to beginni ng broad deployment of CCS by 2020. Thirty-one of the 80 large-scale integrat ed 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 depl oyment 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 fo r advancing CCS technology and gaining public
acceptance.

In addition to enhancing RD&D, international co llaboration 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 allo w 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 complia nce with domestic legislation.

The United States is involved in many bilate ral and multilateral cooperative agreements and
initiatives in which CCS is either the focus ora key element of the cooperation. These costshared activities span cooperation with both de veloped and developing countries focusing on a wide range of objectives (RD&D, ca pacity building, regulatory de velopment, finance, market assessments, engineering analyses, and info rmation exchange) that help advance CCS technology development and acceptance in th e United States. The Carbon Sequestration Leadership Forum (CSLF) is an example of multilateral cooperation focused on the development of improved cost-effective techno logies for the separation and capture of CO 2 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 Partnershi p for Clean Development and Climate, the Asia Pacific Econ omic 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 acti vities 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 throug h bilateral and multilateral cooperation on CCS technology RD&D, policy development, and public engagement is critical to ensure maximum effectiveness, both from the stan dpoint of making wise investment s of taxpayer dollars and to rapidly advance the most promising technologi es through the development cycle into early

Report of the Interagency Task Fo rce on Carbon Capture and Storage 92deployment 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 Departme nt as appropriate. Periodic reviews of ongoing and planned activities are conducted, usually with in put from the private sector. Bilateral engagement on CCS is coordinated within DOE through st rategic energy policy dialogues, with participation by the State De partment, to ensure consistency with the Administration’s broader international priorities and climate and energy goals. Coordination of efforts being undertaken through mu ltilateral 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 objecti ves for participation. The State Department has a leading role in coordination of multilatera l 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 othe r countries, along with lessons learned on their operational issues (especially from projects wi th similar geologic formations), will help the United States in proving the long-term safe and effective geologic sequestration of CO 2 . The United States is currently participating in 10 larg e-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 invo lved in field experiments for site characterization and well monitoring, performing reservoir simulation mode ling, and developing and testing an array of monitoring, verification and accounting techniqu es and technologies—all of which will yield information that will help to overcome technolo gical barriers to CCS depl oyment domestically.



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

V.D.1 Loan Guarantees

Government loan guarantees can help prom ising, early-stage commercial technologies penetrate markets in which providers of capita l are either unable or unwilling to provide financing without public assistance. Such reluctan ce may reflect substantial capital requirements, the complexity and unproven nature of the tech nologies, regulatory uncertainty concerning
CO 2 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, cand idate projects are required to ha ve 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 cand idate project is generally more attractive the greater the proportion of equity at sta ke. 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 subs tantial equity capital at

V. Framework for Addressing Market Failures 93risk 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-t erm success so that the debt will be repaid in the manner in which the underlying loan anticipa tes. DOE’s Loan Guarantee Program (LGP) for fossil fuel energy projects currently is evaluati ng CCS projects that gasify coal or petroleum coke and produce a range of products from powe r and natural gas to transportation fuel and chemical manufacturing feedstock such as ammonia and methanol.

The USDA’s Rural Utilities Service (RUS) makes di rect loans and loan guarantees to electric utilities, and is already supporting at least one CCS project. All plant im provement 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 potentia lly be provided based on the review of these requirements.

A CCS project can support a loan (and a loan guaran tee) 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 candidat e projects for loan guarantees is relatively limited by the inability of CCS projec ts to rely on cash flow from CO 2 abatement prior to enactment of a policy to create a carbon mar ket. 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 ot her things, sound supply agreements, product sales agreements, reliable operations, and a high le vel 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 CO 2 produced.

Prospective financial success, sponsor expert ise, 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 progr am. Loan guarantees should be structured to complement, not displace, the private sector’s effo rts to finance large capital projects in power generation, oil and gas, petrochemicals, infrastructure, and public works.

The process of issuing loan guarantees is cont ingent 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. Sect ion 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 Fo rce on Carbon Capture and Storage 94The 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 taxabl e years. The R&E tax credit also provides a credit for 20 percent of basic research paymen ts above a base amount, and for all eligible payments to an energy research consortium fo r energy research. The R&E credit expires for amounts paid or incurred after December 31, 2009. However, the Ad ministration’s FY 2011 Budget has proposed to make this tax credit permanent.

Taxpayers currently may elect to deduct the am ount 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 taxabl e year. Taxpayers may alternatively elect to claim a reduced R&E tax cr edit 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 sc ientific research expenditures. The government is not attempting to “pick winners”—the firm decides what R&E invest ments to undertake. Research expenditures on clean energy technol ogies and CCS are potentially eligible for the present credits provided they me et certain eligibility criteria. 104

An investment tax credit under section 48A is available for powe r generation projects that use IGCC or other advanced coal-based electricity gene ration technologies. As originally enacted in 2005, the credit amount is 20 percent for in vestments in qualifying IGCC projects and 15 percent for investments in qualifying projects th at use other advanced coal-based electricity generation technologies. The Secretary of the Tr easury 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 pr ovision, 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 includ e equipment that separates and sequesters 65 percent of the project’s total CO 2 emissions.

104 Qualified research is research that is undertaken for th e 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 ac tivities 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 95Under section 48B, as originally enacted in 2005, a ta x credit of 20 percent was available for investments in certain qualifying gasification proj ects. The Secretary may no t 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 Secr etary is authorized to allocate an additional $250 million of credits to qualified projects that separate and sequester at least 75 percent of
total CO 2 emissions. 105

Under section 169, a taxpayer may el ect 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 primaril y 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 pe r tonne is available for qualified CO 2 that is captured at a qualified facility, used as a tertiary injectant in a qualified enhanc ed oil or natural gas recovery project and disposed of in secure geological se questration. In addition, a credit of $20 per tonne is available for qualified CO 2 captured by a taxpayer at a qua lified 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 Treasu ry Secretary certifies, in consultation with the
Administrator of the Environmental Protection Agency, that 75 million tonnes of qualified CO 2 have been captured and sequestered. As a po int of reference, a 1,000 MW CCS power plant that captures 90 percent of its CO 2 emissions and has a utilizat ion 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. Furthe r, non-taxable entities, such as governmental bodies and cooperative electric companies, cannot take direct advantage of investment or sequestration tax credits, althou gh they could benefit from tax credit bonds.

Firms without enough tax liability to take advantage of the credit s 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 credit s 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 CO 2 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 canno t 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 Fo rce on Carbon Capture and Storage 96credits, but credits that are carried forward have a lower present value th an 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-rel ated tax credits was significantly curtailed by limitations in the regular tax on the use of ge neral business credits. For example, for most years, between half and two-thirds of the rene wable electricity produc tion 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 ener gy-related capital invest ment 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 inco me to take advantage of energy-related tax credits. In this context, the latter firms are refe rred to as “tax equity investors.” However, the
costs associated with the financia l arrangements necessary for the partnership also reduce the
value of the tax credits. As was s een 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 pr oposed tax subsidy would yield additional investment in qualifying facilities, or instead simp ly 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 resp onse 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 th e amount of research that would have been taken anyway, so some R&E credits likely are cl aimed 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 (s uch as a price on carb on) in the future, tax
credits would divert revenue but fail to deliver additional benefits.

Finally, it is important to remember that in orde r to be deficit-neutral, tax credits must be paid for with higher distortionary taxe s 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 97the public budget is typically grea ter 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-trad e systems have reserved a share of emission allowances for free allocation to CCS applicat ions. For example, the American Power Act of 2010 discussion draft (APA) reserves about 6.3 pe rcent of total allowances from vintage years 2017–2034 for a “bonus allowance” program for CCS inst allations. Qualifying industrial facilities and electricity generators, including retrofits, rece ive the incentive for the first 10 years of their CCS operation. However, industrial facilities are limited to receive collect ively no more than 15 percent of the total incentive awarded. Electricit y 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 al lowance incentive in three project tranches. Projects in the first tranche of 10 gigawatts (GW) of CCS receive between $50 and $96 per
tonne of CO 2 sequestered (plus $10 per tonne if online by 2017), with the precise value determined by a project’s rate of CO 2 capture and sequestration (between 50 and 90 percent). Projects in the second tranche of 10 GW re ceive between $50 and $85 per tonne based on a similar scale of percentage of emissions seque stered. Developers of projects in the third tranche of up to 50 additional GW of CCS woul d participate in reverse auctions to establish the disbursement price per tonne of CO 2 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 bo nus 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 CO 2 sequestered, but the payment is denominated in allowances. A CCS project being awarded $90 per tonne of sequestered CO 2 would receive nine allowances (for each tonne sequestered) if the carbon price is $10, or only six allowa nces if the carb on price is $15. 109 The monetary value of the total

incentive disbursement is the same between thos e scenarios, but more allowances are required for the award when the carbon pr ice is lower. The total value av ailable 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 CO 2 (the same measure for each greenhouse gas allowance).

Report of the Interagency Task Fo rce on Carbon Capture and Storage 98The differences in the incentive structure betwee n each project tranche are significant. In the first two tranches, the incentive va lue is fixed on a per-tonne of CO 2 sequestered basis. Such a sequestration incentive should target the econom ic 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 CO 2 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 incent ive 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 impa irs 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 unc laimed. 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 C CS projects as “sequestration sellers.” If the reserve auction process is structured to scre en 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 CO 2 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 econ omic gap for qualifying CCS. In addition, the competition between projects should yield the most sequestra tion possible for the value of the total bonus

allocation awarded in the second tranche. Li ke other auction procedures, a reverse auction approach for CCS bonus allowanc es would need to establish safeguards against failure of participants to deliver on their bids and agai nst potential collusion between participants. 111

110 In expert Congressional testimony, one CCS vendor observed that “c limate 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, obta in 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 requ irements 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 99The magnitude of bonus allowances does not ap pear 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 su bstantial amount of geologic sequestration of
CO 2 . However, policy-makers cannot know with cert ainty in advance of a cap-and-trade system if such a level of sequestration would be th e 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 kn owledge 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, whic h muffles the carbon price signal to consumers and reduces the incentive for efficiency in el ectricity consumption (among the lowest-cost potential CO 2 emissions mitigation options). 112

112 McKinsey & Company (2007).

Report of the Interagency Task Fo rce on Carbon Capture and Storage 100

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

A key consideration for both near- and long-te rm 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 ge ologic sequestration of CO 2 as discussed in Section IV.B.1 and Appendix F of the report and co ncluded that the current statut ory framework can be used to regulate CCS projects.

Some regulatory actions will be ne cessary in the near term, to he lp 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 fa cilities under the CAA, also expected in late 2010, will ensure that CO 2 emissions to the atmosphere fr om capture and sequestration are monitored and reported in both the onshore an d offshore environments. Clarification of the regulatory status of CO 2 and/or CO 2 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 wit hin 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 natu ral resources, while providing a simple, straightforward regulatory system to oversee C CS and speed deployment of these technologies (RFF, 2007; CCS Regulatory Project, 2008; Ha rvard 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 asse ssed the existing regulatory framework with respect to its ability to meet key regulatory goals outlined below.

To facilitate widespread, cost-effe ctive deployment of CCS within 10 years, a future regulatory framework could be designed to balance multiple goals: reducing CO 2 emissions; increasing energy security; and protecting human health, the environment, and our resources. With this in mind, the Task Force has identified two paths fo r moving forward for long-term deployment of
CCS:

Option 1: Build Upon Existing Au thorities 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 stre amlined, where appropriate, exemptions could

VI. Options for Enhancing the Legal/Regulatory Framework 101be considered for early projects to accelerate deployment and lear ning by doing, and regulatory certainty could be enhanced.

Option 2: Create a New S tatutory 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 ad dress 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 es tablish clear requirements for how geologic sequestration sites could receive a fungible em issions “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 on shore 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, particul arly 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 cl arify regulatory authorities and processes.

Creation of a “comprehensive” regulatory fram ework 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 CO 2 . The goals are discussed in more detail below:

A comprehensive framework would:

 Be tailored to ensure the integrity of the emissions reductions associated with CO 2 sequestration;

 Address the full range of po tential impacts to human he alth and the environment, including environmental justice;

 Include clear standards, regulatory approache s, and legal or financial mechanisms that might be needed throughout the life of the CO 2 sequestration project, from site selection and operation to long-term stewardship;

 Promote national consistency, yet address exis ting differences in authorities between the onshore (Private vs. Federal) and offshore ( State vs. Federal), and clearly articulate the role of States;

 Include strong compliance assura nce and enforcement mechanisms;

 Create flexibility to account for site variability and be adaptive to accommodate learning;

Report of the Interagency Task Fo rce on Carbon Capture and Storage 102 Build knowledge and public confidence by ma king information available and creating opportunities for public engagement; and

 Be designed to meet internatio nal obligations as appropriate.

Goal 1: Tailor for CO 2 sequestration as a climate change mitigation approach . Given that the purpose of CCS is to address climate change, it will be para mount to ensure that projects reduce CO 2 emissions, and that regulations an d programs are designed to consider linking CCS with a future climat e regime (RFF, 2007; CCS Regula tory Project, 2009b). EPA has proposed new Federal requirements under th e SDWA for the underground injection of CO 2 for the purpose of geologic sequestration, whic h 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, su ch 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 ha s proposed methodologies and approaches for monitoring and verification of CO 2 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 CO 2 injected and geologically stored in the
United States would allow EPA and others to tr ack 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 potent ial 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 addr ess other human health and ecosystem impacts. Proposed UIC Class VI requirements for geol ogic sequestration wells seek to permanently
contain CO 2 by addressing leakage pathways and requi ring comprehensive monitoring plans to
track movement of CO 2 plumes. These requirements may indirectly protect against some impacts other than those associated with USD Ws. However, as discussed in Section III.C improperly operated CO 2 injection activities could conceivably result in release of CO 2 to the atmosphere from underground locations far af ield 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 he alth 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 th ese authorities differ in scope and coverage, significant efforts by implementing agencies woul d be needed in order to address all possible impacts from CCS, appropriately balance envi ronmental and safety objectives, reduce redundancy, and streamline regulatory re quirements across those regulatory programs.

VI. Options for Enhancing the Legal/Regulatory Framework 103Environmental justice issues concerning the st orage 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 permi t 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 heal th 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 sta ndards, regulatory approach es, and legal or financial mechanisms that might be needed throughout the life of the CO 2 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 verifica tion; financial assuranc e; long-term stewardship; and enforcement). For example, the current SDWA UIC framework includes requirements for site characterization, well construction, operatio n, closure, and post-closure monitoring, but does not address long-term stewardship of sequ estration sites, or address liability after the post-injection site care period. Currently, liabili ty 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 deta il in Section IV.C of the report.

Goal 4: Promote national consistency, yet addresses existing differences in
authorities between the onshore and offshor e, 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 progr ams have been approved by EPA. Technical capacity to operate the program will vary from State to Stat e, along with how regulatory requirements are implemented. To facilitate deployment of well-managed CCS projects throughout the United States, minimum Federal st andards will be important. It is important to note that EPA will not approve primacy applicatio ns from States that are unable to achieve minimum Federal standards as required under th e SDWA § 1422. National consistency is also important to ensure that CO 2 emissions reductions associated with geologic sequestration of
CO 2 can be included in future climate programs.

While the Federal Government does have authori ty for regulating CCS offshore, further clarity in statutory authority would ensure that it ca n provide the kind of comprehensive management

113 References to “States” in this section also include Tribal governments.

Report of the Interagency Task Fo rce on Carbon Capture and Storage 104described 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 kn own as the London Protocol), addresses offshore carbon sequestration in the sub-seab ed. Two guidance documents were developed by
the Parties to the London Convention and Prot ocol, the international body established to address prevention of marine pollution by du mping of wastes and other matter (i.e., ocean dumping of materials). The two documents toge ther are intended to provide guidance in evaluating applications for sequestration of CO 2 into sub-seabed geological formations (and not in the water column), and the other restriction s applicable under the London Protocol. The Specific Guidelines include sections addressi ng, among other things, the conduct of a waste prevention audit, consideration of waste manage ment options, consideration of the chemical and physical properties of the CO 2 stream, site selection and ch aracterization, assessment of potential effects, monitoring and risk man agement, the issuance of permits, and the development of permit conditions.

The United States has signed and has been workin g 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 consen t 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 re vised 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 sequestra tion 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 issu es and applies the necessary environmental protections for offshore sequestration in a ma nner similar to the regulation of onshore sequestration.

Goal 5: Include strong complia nce and enforcement mechanisms. A successful legal and regulatory framework will include complianc e 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 th eir environmental impacts are covered.

The Federal government currently has authori ty under SDWA to colle ct information, conduct inspections, monitor compliance, and take civil or criminal action related to the protection of

VI. Options for Enhancing the Legal/Regulatory Framework 105underground 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 pe rmit requirement, SDWA allows Federal information gathering and inspection under th e SDWA UIC Program, by regulation, and only for regulatory development or determination of individual well owner or operator compliance with UIC program requirements. Adequate complia nce and enforcement of all aspects of CCS may require the utilization of other environmenta l 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 CO 2 .
The injection and sequestration of CO 2 will require access and authority to monitor the migration of CO 2 over long distances in large geologi c formations beyond the property of the
UIC well owner or area of review of the UI C 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 purpose s. SDWA could be clarified to provide for extended access to property for monitoring and enforcement purposes and authority to request CCS-related information that ma y not required by UIC regulations.

CO 2 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 de ter such behavior and ensure that a national CCS program meets its critical environmental goals. Methods to provide the capability to verify quantities of CO 2 captured, transferred and stored, and to document
transfers of CO 2 through this system should be design ed. Participation in such a monitoring, reporting and verification system should be mand atory for all recipients of CCS-related Federal funding, and the regime should be robust enough to detect and quantify CO 2 loss at every phase of capture, transport and storage. The accu racy of the data in this system should be verified through signed reports, certified by a re sponsible corporate official, to ensure there is a remedy in the event of an inco rrect or fraudulent report. A market-wide CCS system is likely to require a robust accounting system of th is type to ensure system integrity.

114 Section 300j-4(a)-(b), 42 U.S.C. § 14 45(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 complianc e assurance and enforcement authorities in primacy States. Primacy States must also demo nstrate 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 Fo rce on Carbon Capture and Storage 106While other Federal statutes such as the C AA, RCRA, and CERCLA may provide stronger compliance and enforcement mechanisms where they are applicable, again, significant efforts by implementing agencies would be needed in orde r to address all possibl e impacts from CCS, appropriately balance environmen tal and safety objectives, reduce redundancy, and streamline regulatory requirements across those regulatory programs.

Finally, SDWA authorities could be expanded to a llow EPA to serve as trus tee or beneficiary of any financial instrument used to establish financial assurance under the UIC Program.

Goal 6: Create flexibility to account fo r 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 a ccount by EPA in the proposed Class VI rulemaking, which is largely performance- based, allows for site variability, provides for regularly updated plans, and includes requirement s 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 CO 2 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 depl oyment. 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. Th e SDWA UIC Program takes and requires primacy States to have actions by rulemaking (which ha s formal public participatio n 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 ha ve the ability to comment on CO 2 sequestration projects via the NEPA and other regulatory programs as applic able. EPA’s CAA GHG reporting proposal for
CO 2 sequestration would also provide public information on the amount of CO 2 injected and
stored in the United States.

Goal 8: Be designed to meet inte rnational obligations as appropriate. To ensure that
the United States meets its international obli gations and adheres to international law, the regulatory framework could consider agreements an d 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 107United States is required to submit an annual Inventory of Greenhouse Gas Emissions and Sinks
under the United Nations Framework Conven tion on Climate Change, which includes reporting of CCS. The United States is also pa rty 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 (Proto col) 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 a cts that would defeat th e 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 substanc es that may be considered for dumping under
certain conditions. The effect of the amendment was to provide for sub-seabed sequestration
of CO 2 under the LP subject to controls, including the issuance of a permit. Transboundary issues, such as tracking/regulating CO 2 plume movement across national boundaries, could also
be considered.

Report of the Interagency Task Fo rce 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-ter m liabilities associated
with CO 2 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 cove rage; (4) establishment of a liability fund; (5) government ownership or direct government liabili ty; (6) governmental indemnification: and (7) transfer of long-term risk to the Federal gov ernment 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 no t to recommend a specific approach for dealing with potential liabilities, but rather to evalua te 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 alread y exist Federal and State laws governing CCS activities. In particular, several States have adopte d 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 ba sis of this existing body of law.

A key question is whether, assuming liability concerns will in fact im pair adoption of CCS technology, there are ways to a ddress those concerns under this existing legal framework, or whether Congressional action would be require d to address those co ncerns. 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 po ssibly 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 CO 2 at the time of injection and sequestr ation facilities are Federally-owned, with the goal of preventing private parties from incurring risks of long-term liabilities. It appears,

119 The discussion that follow s 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 109however, that private entities that contribute CO 2 to such a reservoir still would have potential liabilities, as would any private contractors involv ed 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 suffic e to address all liabili ty concerns those entities might have.

Appendix KAppendix provides a discussion of liability arrangements under existing DOE CCS programs. Under the FutureGen program, Illinois la w provides for the State to accept liability. DOE has declined to accept liability under two other progr ams, the CCPI and the RCSP. Instead, liability under these two programs is pr esumably 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 legislat ion, that could suffice to provide the basis for early movers, including the five to ten commercial-scale proje cts planned by 2016. The Task
Force would need to confirm that the State le gislation in question adequately addresses potential sources of liability, including, for ex ample, CERCLA. Nonetheless, under an approach that relies on the States to address long-term lia bility, the Task Force would emphasize that the Federal government will need to ma intain 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 ther e 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 numb er of participating Stat es 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 CO 2 sequestration. Some States will be reluctant to adopt legislation on long-term liability, or may face fiscal constraints th at prevent them from enacting effective legislative programs. If many States are in this category, CCS deployment may be geographically limited as a result. Moreover, circum stances that could give rise to the existence of long-term liabilities include inadequate oversigh t 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 te n 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 Fo rce on Carbon Capture and Storage 110Advantages : This approach avoids the need to seek new legal authority or Congressional action. Because the timing and scope of Congressional acti on cannot be predicted, this is a significant advantage. States could implement framewor ks specific to their region and unique circumstances, which could encourage developmen t 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 regula tion could impede CCS projects that cross State lines. Potential parties could be di scouraged from investing in projects if they perceive a barrier related to balance-sheet recognit ion of the cost of potential liabilities or the insurability of risks. Limitations in State resour ces and regulatory capacity may limit their ability to approve and oversee CCS activities, whic h may in turn constrain adoption of CCS.



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

Another approach to addressing long-term liabilit y concerns would be to adopt substantive or procedural limitations on claims. These might in clude, 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 addr ess 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 no t be appropriately limited in this way.

Advantages : Establishing uniform Federal standards ma y help to ease uncertainties from the business community and insurers over the extent of potential liabilities and address uncertain
or inconsistent State standards. Federal liabilit y 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 St ate law. By contrast, more modest limitations on remedies may not suffice to reassure stakeholde rs 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 stat utes 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 contain s 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 proh ibiting imposition of joint and severa l liability. 6 C.F.R. 25.7 (2010). And CERCLA contains a provision establishing a uniform Federa l period for accrual of statutes of limitations for State tort claims relating to hazardou s waste sites. 42 U.S.C. § 9658.

VII. Approaches for Legal or Regulatory Structures to Deal with Potential Liabilities 111associated 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 facili tates private insurance coverage of long-term liabilities. (The Task Force does not analyze the approach of esta blishing a pooled liability fund in this section; that option is instead disc ussed in the section that follows. The present discussion focuses only on approaches that re ly on existing insurance companies and their capital.) The Task Force notes that the availa bility 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 insuranc e coverage would be to require owners or operators to purchase such insurance, thereby crea ting 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 th e owners/operators of nuclear reactors obtain private insurance at prescribed levels. Additi onal information regarding the Price-Anderson private insurance approach is presented in Appendix I.

The Task Force anticipates that private insura nce will be available and utilized up to the postclosure phase. Our understanding is that insu rers 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 th e present to cover long-term (pos t-closure) CCS-related risks. Insurers state that they have diffi culty valuing those risks because of their novelty that they are not institutionally suited to issuing policies wh ere 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 coul d 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 specifie d dollar limit; liability might be capped at the insurance company limit or additional risks could be addressed through some other mechanism); and (3) allowing shorte r-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 fa cilities under the Price-Anderson Act. The operation of those arrangements is se t forth in detail in Appendix I.

121 Insurers state that they may not currently be willin g to issue policies covering the replacement cost of CO 2 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 Fo rce on Carbon Capture and Storage 112The Task Force recommends soliciting further in put from the insurance industry to explore whether there are circumstances under which priv ate insurers would issue insurance policies to cover long-term risks of CO 2 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 rele vant time scale (which may, again, be measured in centuries).

There are considerable uncertainties as to how in surers 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 advant ages 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 Proje ct, 2009a; Jacobs et al., 2010). Su ch a fund would be a substitute for private insurance, in which the governmen t takes on the function of pooling risks and evaluating claims. Examples of existi ng, 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 nuclea r reactor industry is required (after a facility’s mandatory commercial in surance policy is exhausted) to contribute to
insurance to cover the costs of a cleanup in the event of an incide nt, 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 ei ther 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 th e form of a fee on each tonne of CO 2 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 pa rties 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 supporte d 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 Opportun ity 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). An y CCS liability fund should be desi gned to avoid these difficulties.

VII. Approaches for Legal or Regulatory Structures to Deal with Potential Liabilities 113fee imposed more broadly on energy production or large emitters. The amount of the fee would be based on a risk analys is (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 ha zard. 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 operator s from defaulting on future payment of fees; also, future legislation creating a market for CO 2 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 mo ral hazard; a risk-based payment into a fund mitigates that moral hazard to some extent. (By contrast, paymen ts assessed after an incident occurs may not have a similar in centive 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 activi ties. The costs would be paid by the relevant industry in advance; this is bene ficial because the responsible enti ty might no longer exist by the time a long-term liability arose. Fund monies mi ght also be helpful for certain other purposes, especially those that would help prevent liabilit y 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 oper ation could be completely responsible for its own post-closure liabilities, which can en courage 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 indeterminat e period (possibly cent uries). Also, a highly conservative approach to designing a liability fun d could mean maintaining very large sums of money over this time period, which coul d have significant opportunity costs.



### VII.E Government Ownershi p or Direct Liability

The fifth option involves the Federal government taking on ownership or direct liability for the risks of long-term CO 2 sequestration from the beginning of sequestration operations (that is, upon injection of CO 2 ). Government liability arguably co uld arise as a result of government planning, design, and construction of CCS facili ties or government ownership of sequestration

Report of the Interagency Task Fo rce on Carbon Capture and Storage 114locations, equipment, or the CO 2 itself, or government operat ion of the CCS facility and equipment.

The precise analysis of governmenta l liability varies by legal context. As to tort claims, there are legal limits on Federal government liability und er 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 statut e, regulation, or policy that pr escribed a specific course of action and (2) was “susceptible to policy anal ysis” involving “social, economic, or political” policy considerations); Laird v. Nelms , 406 U.S. 797 (1972) (the FT CA does not permit suits based on theories of strict liability).

To the extent that the Federal government op erates through contracto rs, those contractors

would still have tort lia bility, but that liability would be li mited 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 cl aims foreclose congressional action providing for compensation of affected parties or pe nalties or assessments under applicable environmental laws, such as CERCLA. 128

The legal analysis could be different under existi ng 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 CO 2 ; ownership of pipelines or other equipment; an d even governmental oversight, financing, and encouragement of CCS activities could be claime d 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 equipm ent 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 Governme nt 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 radiatio n of “downwinders” in the wake of above-ground nuclear testing during the height of the Cold War, Congress acted with ei ther private legislation or administrative programs funded by the Fede ral taxpayers to compensate those injured.

VII. Approaches for Legal or Regulatory Structures to Deal with Potential Liabilities 115government contractors that are involved in geol ogic sequestration operations in any of a range of ways would not necessarily be immune from such liability.

Advantages : Structuring a program so that the governme nt is directly liable for CCS activities, and no private party has remaining liability, coul d reduce the complexity of assigning long-term liability.

Disadvantages : Although this approach would add the gov ernment as a liable party, it would not necessarily eliminate CERCLA liability or commo n-law tort liability for private parties. For example, completely eliminating a party’s stat us as a CERCLA potent ially responsible party
could be difficult without statut ory or regulatory changes; al though 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 endorsin g 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 lia ble party, it might find it difficult to condition its own financial support on compliance with a partic ular regulatory regime. Second, there will be significantly less incentive for private parties an d States to take precautions to prevent harm.



### VII.F Governmental Indemnification

Governmental indemnification is another approac h to handling the liabi lity 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, an d then only when private insurance is unavailable (e.g., agreements indemnifying Department of Energ y contractors for liability arising out of nuclear incidents; and agreements indemnifying certain Department of Defense contractors). See Pub. L. No. 85-804 (cod ified 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 indemnificat ion 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 be cause it potentially severs day- to-day control of an activity from the associated costs and risks, an d thereby blurs or reduces accountability.

Report of the Interagency Task Fo rce on Carbon Capture and Storage 116

### VII.G Transfer of Liability to th e Federal Government after Site
Closure and Governmental Certification

Another approach to dealing with liabilities from long-term CO 2 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 Cont ractor Defense standards. The approach could apply to both compensatory as well as perfo rmance liabilities. A number of commentators have endorsed this approach, which is a variatio n 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 CO 2 is safely sequestered and will continue to remain so. Upon such certificatio n, 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 Excep tion, discussed above. As long as the United States did not violate any self-imposed specific ob ligations and its decisions were susceptible to policy analysis, there could be no tort liability against the Unit ed States. Under this approach, the former private owners/operators of the sites would no longer be potentially liable following certification, unless an injure d party or government agency coul d affirmatively show that the former owner/operator failed to meet certain standards associated with the certification process. For example, if the former owner/op erator failed to follow pertinent Federally mandated specifications or withheld adverse info rmation 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 pr ivate entities will still exist in the extremely long time periods associated with CO 2 sequestration, putting the government in charge provides the greatest assurance that an enti ty will be available to perform stewardship responsibilities. Moreover, the requirement th at CCS operators meet certain standards in order to qualify for a transfer of liability (and that the transfer is legally in effective if it later is determined that those standards were not met) would provide an additional mechanism for oversight of participants in CCS activiti es, 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 au thorizing a transfer of liability expressly

129 Industry stakeholders indica ted 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 117encompasses environmental laws such as CERC LA, 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 no t exempt the owners/operators fr om any potential liabilities under Federal law. Such liability is, in theory, potentially large and op en-ended, and it is very unusual
for the United States to assume such liabilit y 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 cl osure of hazardous waste sites), and the private sector is generally thought to be able to perform these functions.

Report of the Interagency Task Fo rce 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. Severa l 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 th e elements and potential extent of concerns around CCS. A coordinated effort among Federal agencies, industry, and NGOs could be undertaken to gat her information and evaluate potential key
concerns around CCS in different areas of th e United States. To inform a larger engagement strategy, it would be helpful to first understand ho w the public may perc eive 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 succ essful 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 cr itical to both near-term and long-term CCS deployment. A comprehensiv e outreach strategy could be developed between the Federal government, industry, and NG Os. 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 comp anies, and NGOs. Roles of agencies and other key players could be defined and coordinated th rough 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 ab out CCS. Studies have shown that perceptions about CCS generally become more positive with additional informa tion. Therefore, it will likely be more efficient to proactively initiate effo rts to educate the public about CCS prior to the active, widespread development of CCS proj ects. As demonstrated in Barendrecht, Netherlands, once projects have been initiate d and potentially negative information about CCS

VIII. Options for Federal Government Action on Public Outreach and Education 119has been communicated to the public from other so urces, 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 cr itical, so community engagement activities warrant a specialized stra tegy. 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 li kely 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 engage ment, 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 learne d from RCSP injection projects; it can also provide standardized education materials.

DOE, through its Public Outreach and Educat ion 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 comm unity 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. Theref ore, proactive and interactive communication between the host and the community will be cr itical 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 rele vant 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 CO 2 , includes public engagement requirements of the public notice of pending sequestration site permitting actions. The permitting authority would be require d 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 Fo rce on Carbon Capture and Storage 120Option 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 materi als concerning CCS, including best practice manuals, scientific studies and journal articles, an d basic educational materials. As part of the broader engagement strategy, the Federal gover nment 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 we bsites from different organization, centralizing some of the higher-quality material could fa cilitate 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 organizat ions that are providing similar material.

Separately, and in order to address community co ncerns around planned geologic sequestration sites, Federal agencies could work together to develop a web-accessible “toolkit” for project developers and regulators. This interagency t oolkit could be develope d 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 br oad spectrum of educational materials, from various regulatory agencies to educate potentia l neighbors of sequestration sites about CCS technologies, site characterization processes, ri sk assessment and mitigation, and the process of sequestration.

Option 5: Provide support for th ird-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 en gage stakeholders from different organizations on developing the consensus-based messages th at 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 inform ation can make a significant difference how the public reacts.

The Federal government could help facilitate this through various initia tives. For example, a Federal department or agency coul d assist an interstate compa ct or a Federal advisory group
that could advocate for State interests in CC S-related activities. Or the Federal government
could work with NGOs involved in the deve lopment 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 121technologies 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 characte rization of potential sequestration sites on Federal lands. Proactive efforts to fully characte rize these sites, assess the risks, and perform programmatic reviews of the projects’ impacts an d infrastructure requirements in the region could provide the information necessary to co mmunicate with stakeholders the impacts and benefits of conducting CCS at these sites.

Report of the Interagency Task Fo rce on Carbon Capture and Storage 122

## IX. Conclusions and Recommendations

IX.A Conclusions

 There are no insurmountable technological, le gal, institutional, or other barriers that prevent CCS from playing a role in reducing GHG emissions.

 Widescale cost-effective deployment of CCS wi ll occur only when driven by a policy designed to reduce GHG emissions. Ulti mately, comprehensive energy and climate legislation will provide the largest incentive fo r CCS deployment as an option for climate change mitigation, because it will create a st able, long-term, market-based framework to channel private investment in to 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 C CS technologies applied to coal-fired power plants and industrial facilities. Early CCS proj ects face challenges related to climate policy uncertainty in addition to th e challenges associated with cost, performance, legal and regulatory uncertainty, and early project te chnology risks. Prior to enactment of a comprehensive climate policy, early climate ch ange mitigation projects such as these will rely on other incentives.

 RD&D can enable deployment of CCS by he lping to reduce project uncertainty and improve technology cost and performa nce. 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 CO 2 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 enhanc e the government’s ability to assist these projects by providing more efficient in centives 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 action s to enhance regulatory authority, address long-term liability, and strengthen stew ardship frameworks could enable wider deployment. Some of these actions would re quire additional legislative authority.

 Open-ended Federal indemnification should no t be used to address long-term liabilities
associated with CO 2 storage.

 International collaboration complements dome stic efforts on CCS and facilitates its global deployment.

IX. Conclusions and Recommendations 123 Public awareness and support ar e 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 Tech nical Committee to Facilitate Early Projects.

To ensure the success of early projects, includ ing five to ten commercial CCS demonstrations by 2016, DOE and EPA should create a Federal age ncy roundtable to act as a single point of contact for project develo pers seeking assistance to overcome financial, technical, regulatory, and social barriers facing planned or existing projects. As needed, this roundtable should provide technical support to permittin g 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, ec onomic, and policy issues.

Increase Coordination in Applying Drivers and Incentiv es to Enhance the Government's Ability to Assist Early Projects.

To ensure the success of five to ten commerc ial demonstration projects by 2016, DOE, in coordination with EPA, Treasury, and USDA, sh ould track the use an d efficacy of Federal financial support for CCS projects. Increased coordination will:

 enhance the government's abili ty 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 eligibili ty criteria for proje cts to receive Federal support; and

 enable the Administration to allocate resour ces efficiently and more effectively consult with Congress and the States on the efficacy of existing incentives.

DOE should determine if early projects will suff iciently demonstrate an adequate breadth of capture technologies and classes of storage rese rvoirs to enable widespread cost-effective CCS deployment. This assessment will allow the Admini stration to target any remaining technology gaps in a manner consistent with addressing market failures.

Report of the Interagency Task Fo rce on Carbon Capture and Storage 124Ensure that Relevant Agencies Wo rk 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 seque stration wells under SDWA and GHG reporting for CO 2 storage facilities under CAA;

o propose RCRA applicability rule for CO 2 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 enhanc e regulatory and technical capacity for safe and effective CCS deployment. Specifically,

 EPA, in coordination with DOE and DOI, sh ould develop capacity-building programs for UIC regulators. Educating permit writers and ot her 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 NE PA analyses related to CCS as early as possible to help ensure timely completion of environmental reviews. Where appropriate to Federal agency decision-making, agenc ies should consider development of Programmatic Environmental Impact Statement s 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 regu latory development, permitting, and project development.

 EPA and DOE should study methods to monitor and account for CO 2 as it moves from capture, through a pipeline or other transpor tation system, to a storage facility. Because system design is likely to be time-consumi ng, Federal agencies should begin to put in place the basic architecture of such a system.

IX. Conclusions and Recommendations 125Enhance and Coordinate Public Outrea ch 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 conc erns 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 ar e candidates for CCS projects.

 Immediately establish a clearinghouse fo r public access to un biased, high-quality
information on CCS.

 Develop outreach tools for project develo pers and regulators with input from DOE (best practices from RCSPs), EPA (permitti ng/regulatory processes), DOT (pipeline transport), and DOI (Federal lands).



### IX.B.2 Wider Deployment

Address Key Market Drivers.

Congress should enact comprehensive energy an d 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 potent ial climate change mitigation option.

Enhance Regulatory and Long-term Liability and Stewardship Framework.

Congress should consider whether changes to st atutory authorities to facilitate regulatory development and implementation are nece ssary. 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 Sanctuarie s Act (MPRSA) as well as amendment of the
Outer Continental Shelf Lands Act (OCSLA) will ensure a comp rehensive statutory framework for the storage of CO 2 on the outer continental shelf.

DOE and EPA, in consultation with other agencies, should track regulatory implementation and consider whether additional statutory revisi ons are needed. These actions will enable the Administration to more effectively consult wit h Congress and the States on the efficacy of the existing framework.

By late 2011, EPA, in coordination with DOE, DO J, and Treasury, should further evaluate and provide further recommendations to address long -term liability and stewardship in the context

Report of the Interagency Task Fo rce on Carbon Capture and Storage 126of 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 fo r long-term liability and stewardship.

 Adoption of substantive or procedural limitations on claims.

 Creation of a fund to support long-term stewardship activi ties 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, an d other interested agencies and stakeholders should continue, and where appropriate enhance, engagement in international collaborative efforts on CCS. These activities assist in glob al penetration of CCS technologies, leverage U.S. funding, and increase access to international expertise an d experiences. In addition, international cooperation on CCS could potentially open mar kets 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
CO 2 Carbon dioxide
CO 2 e 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

H 2 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 129LC 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

N 2 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
NO

x Nitrogen oxides

NRAP National Risk Assessment Partnership
O 2 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
SO

x 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 Fo rce on Carbon Capture and Storage 130

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XI. References 137

# Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage

## Appendix A. CO 2 

## 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 CO 2 capture technology, the current state of technology development, and planned large-scale demonstratio n projects. It is an expanded version of the CO 2 capture section in the ma in body of the report.



### A.1 CO 2 

### Capture History

Although CO 2 capture is new to coal-based power generation, removal of CO 2 from industrial gas streams is not a new process. The history of removal of CO 2 from industrial gas streams is depicted in Figure A-1.

Figure A-1. Previous Experience with Removal of CO 2 from Gas Streams

1930 1980 1970 1960 1950 1940 2000 1990 Natural Gas Purification Food & Chemical Grade CO 2 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 CO 2 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 CO 2 from other gases have been in use since the 1930s in the natural gas industry and to produce food and chemical grade CO 2 . Chemical solvents are used to separate CO 2 from gas streams containing three to 25 percent CO 2 . In the 1940s, physica l solvents were deve loped to absorb CO 2 from gas streams with higher CO 2 concentration (25 to 70 perc ent) and higher pressure (approximately 1,500 Psia), such as those encoun tered in high-pressure natural gas processing. In the 1950s and 1960s, gas adsorption pr ocesses were developed to remove CO 2 from gas streams. In the 1970s and 1980s, gas separation membranes were developed (Kohl and Nielsen, 1997).

The licensing history of the Econamine FG proce ss (one of a handful of commercially available amine-based chemical solvent CO 2 separation processes) prov ides a good example of past applications of CO 2 removal technologies (Chapel et al., 1999). Prior to 1999, 25 capture

Appendix A. CO 2 Capture – State of Technology Development: Supplementary Material A -1facilities were built that captured CO 2 quantities ranging from 635 to 365,000 tonnes/year using the Econamine FG process (Table A-1).

Table A-1. CO 2 Capture Plants Built Prior to 1999 Using the Econamine Process

Capture Rate
CO 2 Use Owner Location Fuel (tonnes per 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, Au stralia 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 Do mingo, 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 captur ed more than 20,000 tonnes of CO 2 /year. Nine of these large facilities captured CO 2 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 CO 2 from these facilities was us ed for enhanced oil recovery (EOR), urea production, and in the food and beverage indust ry. The capture rates for these facilities reflect the fact that they were built to serve a sp ecific commercial market for CO 2 . 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 -2during this time period. By comparison, a sing le 550-MW net output coal-fired power plant capturing 90 percent of the emitted CO 2 will need to separate a pproximately five million tonnes per year of CO 2 . This large difference in capacity re presents a significant barrier to widespread commercial deployment of CO 2 removal technologies for coal-fired power plants (DOE, 2010a).

A 2009 review of commercially available CO 2 capture technologies identi fied 17 facilities (using both chemical and physical capture solvents) in current operation (Table A-2) (Dooley et al., 2009). These facilities incl ude four natural gas processing operations and a syngas production facility in which approximat ely 1 million tonnes of CO 2 are captured per year. The largest (the Shute Creek natural gas processing plant in Wy oming) 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 proce ssing is transferrable to separation of power plant flue gases is unclear, given the significan t differences in the chemical make-up of the two gas streams. In addition, integration of these te chnologies with the powe r cycle at generating plants presents significant cost and operating issu es that must be addressed in order to facilitate widespread, cost-effective deployment of CO 2 capture. CO 2 Capture in Coal-Fired Power Generation

In general, CO 2 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 CO 2 and hydrogen (H 2 ) in the high-pressure syngas produced at IGCC power plants. Post-c ombustion systems are designed to separate CO 2 from the flue gas—primarily nitrogen (N 2 )—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 (O 2 ) rather than air to combust coal and therefore produces a highly concentrated CO 2 stream.

Application of any of these approac hes results in an increase in th e 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 ener gy produced by the plant (in the form of both steam and electricity) in order to operate the CO 2 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. CO 2 Capture – State of Technology Development: Supplementary Material A -3Table A-2. Summary of CO 2 Capture Facilities Operating in 2009

CO 2 Source/Project Name Location Capture Rate (tonnes per year) Capture Technology CO 2 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

CO 2 Capture from Coal Gasification

Great Plains Synfuels Plant Beulah, ND 1,800,000 Rectisol EOR

CO 2 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

CO 2 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 Ga s Chemicals China 50,000 Amine Urea Production

CO 2 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 CO 2 

### 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 O 2 , as shown in Figure A-2.

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A -4Figure A-2. Pre-Combustion CO 2 Capture for an IGCC Power Plant

By carefully controlling the amount of O 2 , only a portion of the fuel burns to provide the heat necessary to decompose the fuel and produce syngas, a mixture of H 2 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 (W GS) reactor, which converts CO into CO 2 while producing additional H 2 . A physical solvent removal system, such as SelexolTM, can then be used to separate the CO 2 from the H 2 . Because CO 2 is present at much higher concentrations in syngas (after WGS) than in flue gas, and because the syngas is at higher pressure, CO 2 capture is less expensive for pre-combus tion capture than for post-combustion capture. After CO 2 removal, the H 2 can be used as a fuel in a combustion turbine combined cycle to generate electricity (Rubin, 2008; Hami lton, 2009; DOE, 2010a). The advantages of this type of system compared with post-combustion capture (described below) are the higher CO 2 concentration (partial pressure) and the lower volu me of syngas to be handled, which result in smaller equipment sizes an d lower capital costs.

The current state-of-the-art CO 2 capture technologies that could be applied to IGCC systems include the glycol-based, two-stage SelexolTM pr ocess, the methanol-based Rectisol® process, the pyrolidone-based Purisol process, and the polypropylene carbonate-based Fluor solvent (IEA, 2008). All employ physical solven ts that preferentially absorb CO 2 from the syngas mixture. However, these systems have not ye t been built for full-scale IGCC power plants.

Using the two-stage SelexolTM process as an exam ple (Figure A-3), in th e first stage, untreated syngas enters the first of two absorbers where H 2 S is preferentially removed using CO 2 -rich solvent from the CO 2 absorber. The gas exiting the H 2 S absorber passes through the second absorber, where CO 2 is removed using both semi-lean an d lean solvent streams. The treated syngas exits the absorber and is sent to the combustion turbine. The CO 2 -rich solvent exits the CO 2 absorber, and a portion is sent to the H 2 S absorber, while the remainder is sent to a series of flash drums for regeneration. The CO 2 product stream is obtained from the flash

Appendix A. CO 2 Capture – State of Technology Development: Supplementary Material A -5drums, and the semi-lean solvent is returned to the CO 2 absorber. The H 2 S/CO 2 -rich solvent exiting the H 2 S absorber is sent to the acid gas strippe r, 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, an d the lean solvent exiting the stripper is returned to the CO 2 absorber (UOP, 2009).

Figure A-3. Schematic Diagram of the Pre-Combustion Selexol TM CO 2 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 en ergy penalty for chemic al solvents used for post-combustion CO 2 capture). Furthermore, although the co st of electricity (COE) for a base IGCC power plant is higher than that for a coal -fired plant, the high thermodynamic driving force for CO 2 capture and reduced CO 2 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 powe r plant equipped with an amine scrubber for CO 2 control (as described below) (DOE, 2010a).



### A.1.2 Post-Combustion CO 2 

### Capture

Post-combustion CO 2 capture refers to removal of CO 2 from combustion flue gas prior to discharge to the atmosphere, as shown in Figu re 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 -6to produce electricity (Bohm, 2006). Flue gas from the boiler cons ists mostly of N 2 and CO 2 . Separating CO 2 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

• CO 2 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 CO 2 capture materials (e.g., solvent);

o particulate matter [PM]

o sulfur oxides [SO

x ]

o nitrogen oxides [NO

x ], etc.
Figure A-4. Post-Combustion CO 2 Capture for a Pulverized Coal Power Plant

PC Boiler Flue Gas Volume % CO 2 12-14% N 2 ~65% H 2 O ~18% O 2 ~2% 15 Psi/150 o F

Sulfur Removal Particulate Removal

Ash

S TEAM C YCLE CO 2 Capture Process Air

Power CO 2 Compression

Flue Gas

CO 2 To Storage Low Pressure Steam Optional Bypass

Coal

Post-combustion CO 2 capture offers the greatest near-term potential for reducing power sector CO 2 emissions because it can be retrofitted to existing plants and can be tuned for various levels of CO 2 capture (optional bypass shown in Figure A-4), which may accelerate market acceptance. Although post-combustion capture technologies woul d typically be applied to conventional coal-fired power plants, they ca n also be applied to the combustion flue gas from IGCC power plants, natural gas combined cycle (NGCC) power plants, and industrial

Appendix A. CO 2 Capture – State of Technology Development: Supplementary Material A -7facilities 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 He avy 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 ha ve not yet been demonstrated at the scale necessary to help achieve GHG reduction targets. Amines chemically react with CO 2 via reversible reactions to form water-soluble compounds. Despite the low CO 2 partial pressure in combustion flue gas, amines are capable of achieving high levels of CO 2 capture due to fast kinetics and strong chemical reactions. However, the absorption capacity for commercially available amines is chemically limited, requiring two molecu les of amine for each molecule of CO 2 . 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 soluti on helps control the solvent temperature during absorption, which is an exothermic reaction, th e water also requires significant amounts of sensible heating and stripping energy upon CO 2 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 CO 2 in the form of low pressure steam (approximat ely 45 psia) is required to regenerate the solvent to produce a concentrated CO 2 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 -8Figure A-5. Schematic Diagram of Amine-based CO 2 Capture Process

After conventional air pollutant cleanup (SO

x , NO

x , PM), the combustion flue gas enters an absorber reactor and flows counter-currently to a CO 2 -lean solvent where CO 2 is absorbed into, and chemically reacts with the amin e solution. The treated flue gas (mostly N 2 ) is discharged to the atmosphere, and the CO 2 -rich amine solution is pumped to a solvent regeneration column where the CO 2 -rich solution is heated in order to reverse the chemical reactions between the CO 2 and amine solvent. Steam extr acted from the turbine cycle, provides the heat for regeneration of the amin e solvent in the solvent regeneration column. Consequently, CO 2 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 CO 2 -lean solution is cooled and returned to the absorber for reuse (Herzog, 2009).

Installing the current state-of-the -art amine post-combustion CO 2 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 CO 2 to pipeline conditions wo uld result in about a 30 percent energy penalty (DOE, 2010a).

Appendix A. CO 2 Capture – State of Technology Development: Supplementary Material A -9

### A.1.3 Oxy-Combustion

Oxy-combustion systems for CO 2 capture rely on combusting c oal with relatively pure oxygen diluted with recycled CO 2 or CO 2 /steam mixtures, as shown in Figure A-6 (Herzog, 2009). The primary products of combustion are water and CO 2 , with the CO 2 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 CO 2 Capture

Oxy-combustion overcomes the technical challenge of low CO 2 partial pressure normally encountered in conventional coal combustion flue gas by producing a highly concentrated CO 2 stream (~60 percent), which is separated from water vapor by condensing the water through cooling and compression. An additional purific ation stage for the highly concentrated CO 2 flue gas may be necessary to produce a CO 2 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 CO 2 concentration and reduced flue gas volume (Herzog, 2009).

However, the appeal of oxy-combustion is temper ed 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 N 2 , and excess O 2 contained in the concentrated CO 2 stream. Flue gas recycle (~70 to 80 percent) is also necessary to approximate the combustion characteristics of air, since currently available boiler mate rials cannot withstand the high temperatures resulting from coal combustion in pure O 2 . 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 ab out 60 percent and have a 25 percent energy penalty compared with a new supercritical ai r-fired, coal-based power plant without CO 2 capture (DOE, 2010a; DOE, 2010b).

A.1.3.1 Chemical Looping Combustion

Chemical looping combustion (CLC) is an adva nced coal oxy-combustion technology that involves the use of a metal oxid e or other compound as an O 2 carrier to transfer O 2 from the combustion air to the fuel, avoiding direct co ntact between fuel and combustion air (Figure

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A -10A-7). Subsequently, the prod ucts from combustion (CO 2 and H 2 O) will be kept separate from the rest of the flue gases. Chemical looping splits combustion into separate oxidation and reduction reactions. In one potential configurati on, chemical looping is carried out in two fluidized beds. The metal oxide (e.g., iron, ni ckel, copper, or manganese) releases the O 2 in a reducing atmosphere and the O 2 reacts with the fuel. The metal is then recycled back to the oxidation chamber where the metal oxide is rege nerated by contact with air. The advantage of using the CLC process is that no separate ASU is required and CO 2 separation takes place during combustion (NETL, 2009a).

Figure A-7. Chemical Looping Combustion

Air A ir (Oxidizing)

Reactor M x O y N 2 , O 2

M x O y-1

Fuel CO 2 , H 2 O

Fuel (Reducing)

Reactor

C n H m N 2 , O 2 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 O 2 for gasification and to capture CO 2 . A loop, similar to that of CLC, is used to gasify the coal and produce syngas (H 2 and CO). A second solid loop is used in a WGS reactor. In this re actor, steam reacts with CO and converts it to
H 2 and CO 2 . The circulating solid absorbs the CO 2 , thereby providing a greater driving force for the WGS reaction. The CO 2 is then released in a calcinatio n step that produces nearly pure CO 2 for further compression and storage.



### A.2 Technical Challenges to CO 2 

### Capture for Coal-Based Power Generation

As discussed above, in their current state of development, CO 2 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 CO 2 capture would significantly decrease power generating capacity, and

Appendix A. CO 2 Capture – State of Technology Development: Supplementary Material A -113) if successfully scaled up, th ey would not be cost effective at their current level of process development (Kuuskraa, 2007).

Other technical challenges associat ed with the application of these CO 2 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 (NO

x , SO

x , PM) on CO 2 capture system, increased water consumption and cost effective O 2 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 CO 2 Capture

Parameter Technical Challenge

Scale

‐ Up While industrial

‐ scale CO 2 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 CO 2 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 CO 2 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 CO 2 capture technologies (~1,550 to 3,000 British thermal units [Btu] per pound of CO 2 removed)
would significantly reduce the total power plant output.

Energy Integration The energy required to regenerate the solvent in commercially available CO 2 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 CO 2 capture technology.

Flue Gas
Contaminants Constituents in the flue gas, particularly sulfur, can contaminate CO 2 capture technologies, leading to increased operational expenses.

Water Use

CO 2 Compression A significant amount of water use is required for CO 2 capture and compression cooling.

To enable storage, significant power is required to compress the captured CO 2 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 CO 2 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 CO 2 

### Capture Impacts on Water Use

CO 2 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, supercritica l PC, oxy-combustion, and IGCC configurations, both with and without capture, were evaluate d 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 s ubsequent study has eval uated five different scenarios for future freshwater withdrawal and consumption requirements for the U.S. thermoelectric generation sector using the An nual Energy Outlook (AEO) 2009 projections for capacity additions and retirement s (EIA, 2009). Results from this st udy 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 sa me time period (DOE, 2009; DOE/NETL, 2009)

Figure A-8. Relative Water Use for New PC and IGCC Plants With and Without CO 2 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 CaptureWater(gal/MWhr) Withdrawal

Consumption

Source: (DOE/NETL, 2009)



### A.2.2 CO 2 

### Capture Impacts on Cost and Performance

As indicated above, technologies exis t that will allow fo r the capture of CO 2 generated during the production of electricity. However, ther e 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 MW e net output power plant, addition of CO 2 capture

Appendix A. CO 2 Capture – State of Technology Development: Supplementary Material A -13technology increases the capital cost of a new IGCC facility by $400 million and results in an energy penalty of 20 percent. For post-combusti on and oxy-combustion capture, the increases in capital costs are $900 millio n and $700 million respectively, an d 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 CO 2 capture. The costs associated with CO 2 capture in terms of increases in the LCOE or cost per tonne of CO 2 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 th e existing fleet of power plants. In terms of costs per tonne of CO 2 avoided, values range fr om $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 fo und 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, $/tonne CO2LCOE,$/MWhAvoidedCost,$/tonneCO2

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A -14All 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 chem ical 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 ex penditure 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. CO 2 Capture – State of Technology Development: Supplementary Material A -15 economic development (costs for incentiv izing local collaboration and support);

 construction and/or improvement of roa ds and/or railroad spurs outside of site boundary;

 legal fees;

 permitting costs;

 owner’s engineering (staff paid by owner to gi ve 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 “man agement reserve”, these are funds to cover costs relating to delayed startup, fluctu ations in equipment costs, unplanned labor
incentives in excess of those for a 5 day, 10 hours per day work schedule.

Cost items excluded from “Oth er 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 re lated maintenance expenses (O&M) pertain to those charges associated with operating and main taining 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 indust ry. 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 leve lization period is the sum of the operational levelization period (30 years for all plants) an d the capital expenditure levelization period (assumed to be 3 years for NGCC plants and 5 ye ars 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 -16and PC cases. The LCOE is expressed in mill s/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:

(CCF P )(TOC) + (LF)[(OC F1 ) + (OC F2 ) + ...] + (CF)(LF)[(OC V1 ) + (OC V2 ) + ...] LCOE P = (CF)(MWh)

where:

LCOE P = levelized cost of electr icity over P years, $/MWh

P = levelization period (e .g., 10, 20 or 30 years)

CCF P = 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)

OC Fn = category n fixed operating cost for the in itial year of operation (but expressed in “first-year-of-construction” year dollars)

CF = plant capacity factor

OC Vn = 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 do llars, 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 leve lization 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 an d IOU low risk. All IGCC cases as well as PC and NGCC cases with CO 2 capture are considered high ri sk. The non-capture PC and NGCC cases are considered low risk. The result ing CCF and LFs are shown in Table A-5.

Appendix A. CO 2 Capture – State of Technology Development: Supplementary Material A -17Table 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 va lues 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 esca lation of capital costs during construction. This rate is equivalent to the nominal average annual escalation ra te for process plant construc tion 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 La bor's Producer Price Index for Finished Goods, the socalled "headline" index of the various Producer Price Indices. (The Produce r Price Index for the Electric Power

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage A -18Parameter Value
rate)
Escalation rates must be the same for LCOE approximation to be valid

Table A-7. Financial Structure for In vestor 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 CO 2 

### Capture Technologies

DOE/NETL is currently engaged in tw o major CCS demonstration programs.

The Clean Coal Power Initiative (CCPI) is an innovative technology demonstration program that fosters more efficient clean coal technologi es 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 privat e-sector decisions on de ployment can be made.

CCPI is currently pursuing three pre-combustion and three post-combustion CO 2 capture demonstration projects (Table A-8). Th e pre-combustion projects involve CO 2 capture from IGCC power plants. The generating capacities at the demonstratio n facilities range from 257 to 582 MW. The capture efficiencies range from 67 percent to 90 percent, and total CO 2 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 CO 2 from pulverized coal (PC) plant slipstre ams representing the equivalent of 60 to 235 MW of power production. Each will capture 90 percent of CO 2 emissions with total capture of 0.4 to 1.5 million tonnes per year.

Generation Industry may be more applicable, but that da ta does not provide a long-term historical perspective since it only dates back to December 2003.)

Appendix A. CO 2 Capture – State of Technology Development: Supplementary Material A -19Similar to the CCPI projects, the FutureGen pr oject will demonstrate carbon capture from a 200 MW advanced oxy-combustion unit in Meredosia, Illinois, integrated with CO 2 storage in Mattoon, Illinois. FutureGen aims to captur e and store at least one million tonnes of CO 2 per year.
Table A-8 Capture Projects Being Conduc ted 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 CO 2 capture demonstration projects are being cond ucted 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 Ene rgy Lake Charles project, the Archer Daniels Midland project, and the Air Products project.

Table A-9. Projects Selected Under th e 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. CO 2 

## Pipeline Transport – State of Technology Development: Supplementary Material

B.1 Existing Pipeline Networks in the United States

There are several CO 2 pipeline systems in the United States that were built largely to transport CO 2 from natural sources to co nsuming oil fields for EOR. CO 2 sources for these systems include natural deposits, natural gas processing plants, and other high-purity industrial vents. The longest existing pipeline system , the Cortez Pipe line, delivers CO 2 over a distance of 500 miles in the Permian basin of Texas, Colorado , and New Mexico (Parfomak and Folger, 2007). Other systems transport CO 2 along the Gulf Coast (Missi ssippi and Louisiana), through Colorado and Wyoming, from North Dakota into Canada, and in Northern Michigan. In addition, there are many smaller CO 2 pipelines connecting source s with specific customers. Figure B-1 and Table B-1 summarize the CO 2 pipelines in the United States.

Figure B-1. Existing and Planned CO 2 Pipelines in the United States with Sources

Source: NETL using data from Energy Velocity Database (2010).

Appendix B. CO 2 Pipeline Transport – State of Technology Development: Supplementary Material B-1Table B-1. CO 2 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 CO 2 223.5 0.0 223.5 4

Wiser 26.7 0.0 26.7 0

Source: NETL Generated from Ene rgy Velocity Database, April 2010.



### B.2 Pipeline Design

The primary design considerations for CO 2 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 us ing Supervisory Control and Data Acquisition (SCADA) systems. CO 2 poses a number of specific threats th at can be mitigated in the pipeline design stage. One major threat to the integrity of CO 2 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:

 CO 2 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 requi rements of the DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) liste d in its Hazardous Liquid Pipeline Safety Regulations (49 C.F.R. Part 195) th at address many of these design considerations. Most of the regulations are identical for transportation of hazardous liquids and CO 2 , with a few notable differences. For example, components for CO 2 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 prop agation must be mitigated against when designing a CO 2 pipeline. Lastly, valve materials must be compatible with CO 2 . The presence of impurities lowers the saturation pressure of the gases whic h affect the susceptibilit y 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 CO 2 pipeline systems.



### B.3 Pipeline Construction

Construction requirements and standards are virtually identical for CO 2 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 componen ts during transportation or during the actual construction activity. These construction requi rements and standards are in place to protect pipelines from damage and to maximize the integr ity 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, modifica tion to construction practices, or physical repairs to the pipeline, pipeline coating, or a uxiliary pipeline features. PHMSA inspections help to ensure that these issues are corrected pr ior to the pipeline being buried and operated. Hydrostatic pressure tests and inline inspection (I LI) 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 CO 2 pipelines. Maintaining the supercritical phase, as well as controlling impurities and moisture content, are paramount for the safe operation of these systems. CO 2 pipelines generally operat e above 2,000 pounds-force per square inch gauge (psig) in order to main tain 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. CO 2 Pipeline Transport – State of Technology Development: Supplementary Material B-3and localized reduction in pressu re. 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 o ff 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 tighte r 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 on ly after tailoring them to CO 2 pipelines. Gaseous CO 2 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-w ay surveys per year. In addition, liquid CO 2 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 Areas 4 (HCA) have a baseline pipeline integrity assessment, and be periodically reassessed. The us e of ILI technology, or “smart pigging,” is a major component of these assessments. CO 2 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 CO 2 pipelines, the blow-down rate must be strictly controlled, and in many cases the contents will be captured. Also, pipeline in tegrity operations may create hazards. As inspection tools are removed from a CO 2 pipeline, they may entrain liquid CO 2 into components which could break apart forcibly as the CO 2 decompresses.

The CO 2 pipeline safety record, with respect to both the frequency and consequence of failure, is comparable to traditional gas transmissi on and hazardous liquids pipelines. Given their relatively low mileage, the frequency of failures, and the mainly rural systems, CO 2 pipelines have been less prone to excavation damage, wh ich is the primary cause of failures for other Department of Transportation (DOT) regulated pipelines. The risk profile for CO 2 pipelines is somewhat different than for traditional gas tran smission and hazardous liquids pipelines. Special

4 HCA are defined as current class 3 and 4 locations; facili ties with persons who are mo bility-impaired, confined, or hard to evacuate, and places where people gather fo r recreational and other purposes. For facilities with mobility-impaired, confined, or hard-to-evacuate pers ons 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-4care must be given to a variety of design, oper ational, and human safety considerations in order to better compensate for CO 2 system-specific issues. DOT a ssumed the safety oversight of liquid CO 2 pipelines in 1988 and codified design , operational, and emergency response requirements in 49 C.F.R. Parts 194 and 195. Th at action, and the strengthening of related integrity management requirements in 2001, is focused on safe and secure liquid CO 2 pipeline operation.

Emergency responders are trained to respond safe ly to pipeline incident s. Specific training (Hazardous Waste Operations and Emergency Respo nse) is required for both pipeline operator personnel and emergency responders. In additi on, 49 C.F.R. Part 194 requires operators to have spill response plans and to hold spill drills in coordinati on 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 Sta te Fire Marshals resulted in the creation of training materials covering the ri sks associated with transportation of all pipeline commodities, which are available at http://pipeline.mindgrabmedia.com/main.aspx

.

Appendix B. CO 2 Pipeline Transport – State of Technology Development: Supplementary Material B-5

## Appendix C. CO 2 

## Storage – State of Technology Development: Supplementary Material

C.1 CO 2 

### Storage History

CO 2 fields are often found in regions that also host hydrocarbon resources. For example, Bravo Dome (New Mexico), McElmo Dome (Color ado), Escalate Reservo ir (Utah), Farnham Reservoir (Utah), Woodside Reser voir (Utah), and La Barge Dome (Wyoming) are some of the natural CO 2 reservoirs in the Colorado Plateau. Like many natural CO 2 accumulations, most of these deposits were discovered du ring hydrocarbon exploration. CO 2 from these reservoirs can be as pure as 98 percent. Contaminants often include natural gas and other hydrocarbon compounds.



### C.1.1 CO 2 

### Storage Experience Associated with CO 2 

### Enhanced Oil Recovery

CO 2 -enhanced oil recovery (EOR) and enhanced gas recovery (EGR) technologies are used in oil and gas reservoirs to improve pr oduction efficiency. Injection of CO 2 is one of several enhanced recovery (ER) techni ques that have successfully be en used to boost production efficiency of oil and gas by re-pressurizing the reserv oir, and in the case of oil, by also increasing mobility.

CO 2 currently injected for CO 2 -EOR in the United States comes from both natural and anthropogenic sources, which provide 79 pe rcent and 21 percent, respectively, of CO 2 supply (NETL, 2008). Historically, CO 2 purchases comprise about 33 to 68 percent of the cost of a CO 2 -ER project (EPRI, 1999). For this reason, CO 2 injection volumes are carefully managed at ER sites. CO 2 recovered from production wells during ER is recycled (i.e., separated and reinjected) and, at the conclusion of an ER project, as much CO 2 as possible is recovered and transported to other ER facilities to be used again. However, a certain incidental amount of CO 2 remains underground.

As of 2008, there were 105 CO 2 -EOR projects within the United States (Oil and Gas Journal, 2008). The majority (58) of these projects are lo cated in Texas, and the remaining projects are located in Mississippi, Wyoming, Michigan, Oklahoma, New Mexico, Utah, Louisiana, Kansas, and Colorado. CO 2 -EOR projects recovered 323,000 barrels of oil per day in 2008, 6.5 percent of total domestic oil prod uction. A total of 6,121 CO 2 injection wells among the 114 projects were used to inject approximately 50 million tonnes of CO 2 . Compared with CO 2 -EOR, CO 2 ­ 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 Ge ologic Storage Projects

Following are brief descriptions of several large- scale operations of engineered storage of CO 2: The Sleipner project , started in 1996, is the longest-running commercial-scale CO 2 storage project in the world. The Norwegia n project injects 98 percent pure CO 2 separated from produced natural gas in order to avoi d paying a carbon tax to vent the CO 2 imposed by the Norwegian government. The project injects one million tonnes of CO 2 annually through one horizontal well into the 250m thick Utsira Sand, a high permeability, high porosity sandstone

Appendix C. CO 2 Storage – State of Technology De velopment: Supplementary Material C-1unit roughly 1,100m below the sea surface. The re servoir is sealed with shales, and mudstones and shale baffles (discontinuous shale lenses) are present in the reservoir to further deter upward movement of CO 2 . Based on its somewhat unique litho logic 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 CO 2 from a nearby synfuels plant into two adjacent carbonate layers. Successful CO 2 -EOR operations at the site have de monstrated the applicability of EOR/GS technology to thin, less-than-ideal formations at moderate depth.

The Snøhvit project in the Barents Sea starte d operation in 2010. Natural gas produced from the Snøhvit Field contains ~5 vol% CO 2 . The CO 2 is removed from the natural gas at the receiving station located at Melkopya, near Hammerfest. Th e 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 CO 2 each year.

In Salah is a commercial-scale CO 2 storage project located in th e Sahara Desert in Southern Algeria. It uses three horizontal wells to annually inject roughl y 1.2 million tonnes of supercritical 98 percent pure CO 2 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 re servoir relied on measurement-while-drilling techniques, which were able to ta rget higher-quality regions of th e formation in real-time as the wells were drilled. This project demonstrated that reservoirs previously thought of as marginal or unusable could successfully stor e commercial-scale quantities of CO 2 . Other non-commercial scale test projects are un derway across the globe. Projects such as Ketzin (Germany), Lacq (Franc e), Otway (Australia), Gorgon (Australia), KB12 (Netherlands), and Nagaoka (Japan) either have already been co mpleted, are underway, or are anticipated to commence injection in the next five years. In to tal, these and other projects have committed to store an additional eight million tonnes of CO 2 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 locate d 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 implem ents 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 la rge: they plan to in ject over one million
tonnes of CO 2 total.

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage C-2 The RCSP Phase II storage projects that ar e complete as of 2 009 have collectively injected a total of 1,450,290 tonnes of CO 2 . 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 comple te. 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/sa line (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 associat ed with the varied geology across the U.S.



### C.2 CO 2 

### Storage Capacity

A range of geologic formations is being assessed as potential target formations for injecting and storing CO 2 . Target formations with the greatest geol ogic 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 reso urce and capacity, as noted in the body of the report, many of the fi rst geologic storage proje cts will likely be in oil and gas reservoirs because these sites have been previously ch aracterized 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 th ese formations may be overlain by laterally extensive, impermeable formations that may restrict upward movement of injected CO 2 . Depleted oil and gas reservoirs: Because many of thes e reservoirs have trapped liquid and gaseous hydrocarbon resources for millions of years, it is believed that they can also be used to store CO 2 . Hydrocarbons are commonly trapped structurally, by faulted, folded, or fractured formations, or stratigraphically, in porous formations bounded by impermeable rock formations. These same trapping me chanisms can effectively store CO 2 for geologic storage in depleted oil and gas reservoirs.

Unmineable coal seams: Currently, ECBM operations exploit th e preferential chemical affinity of coal for CO 2 relative to the methane that is naturally found on the surfaces of coal. When CO 2 is injected, it is adsorbed to the coal surface and releases meth ane, 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 CO 2 molecules are adsorbed. This process effectively “locks” the CO 2 to the coal, where it remains stored.

Appendix C. CO 2 Storage – State of Technology De velopment: Supplementary Material C-3Capacity estimates are regionally variable, but de tails are being refined in ongoing efforts (e.g., in both DOE and USGS). In 2008, US GS initiated development of a methodology for estimating the capacity to store CO 2 in geologic formations of the United States. While previous capacity estimates published by DOE/National Energy Tec hnology Laboratory have been broad in scope (i.e., geologic basin-wide), the US GS is focusing on smaller-scal e, refined estimates. In 2010, USGS published a proposed, geology-based prob abilistic 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), hydrol ogic (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, verifi cation, and accounting (MVA) are important components of managing a geologic stor age project and ensuring that the CO 2 plume and associated pressure front are moving through th e subsurface as predicted. Baseline monitoring data are necessary to differentiate natural phe nomena from signals associated with storage. Data collected during site characterization (such as baseline geoche mistry, 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 ow ner or operator and permitting authority to evaluate monitoring data and identify any change s in subsurface geochemistry that may indicate fluid movement. Operational-phase monitoring ca n demonstrate that a geologic storage project is performing as predicted, or provide warn ing that unexpected flui d movement has occurred and USDWs may be endangered or other adverse impacts associated with leakage of stored CO 2 may occur. For example, monitoring data can demonstrate that the injectate is confined in the injection zone, identify po tential corrosion of well mate rials and signal needed well construction/mechanical integrity fixes, or identi fy 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 enda ngerment or contamination or other adverse impacts associated with a geol ogic storage site until the CO 2 plume and pressure front stabilize.

Appropriate monitoring of a geologic storage si te can also provide data to maintain the efficiency of the storage operation, minimize co sts, improve site modeling, and target needed future corrective action. Robust MVA is also needed to ensure the integrity of CO 2 storage as a mitigation strategy under a carbon-constrained regulatory regime.

Several large projects involve extensive monitoring:

 At the Sleipner project, gravity and seis mic surveys have been used to track the migration of the CO 2 plume. Both methods have been able to successfully image the

5 This report, A Probabilistic Assessment Methodology for the Ev aluation 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-4plume and verify that the CO 2 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 ta ken place, even though more than 1,072 wells dating back to the 1960s were present with in Weyburn field. This is an important finding because abandoned wells are thought to be an important potential leakage path for CO 2 .

 At In Salah, in additional to standard seismi c and geochemical techniques, the project also used satellite monitoring to measure up lift of the earth surface to monitor CO 2 migration within the reservoir. This tec hnology was able to successfully image unexpected developments within the plume due to a previously uncharacterized fracture pattern in the subsurface. Disc overy 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 techniqu es are capable of successfully identifying leaks.

 The DOE Regional Carbon Sequestration Part nerships (RCSP) projects also involve testing of monitoring technologies. The re sults 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 munici pal wastewater via Class I municipal disposal wells in Florida offers an insight into the impo rtance of monitoring at geologic storage sites. Ground water monitoring data detected upwar d fluid movement of some of the injected wastewater, which had a lower density (lower TD S) 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 ad aptive approach to address problems identified.

Continued development is needed for MVA tools to improve aspects related to quantification and resolution of CO 2 in the subsurface, detection of fr actures and other potential leakage paths, intermittent leakage, etc. (e.g., IPCC, 2005).



### C.3.2 Potential Impact of Impurities in the CO 2 

### Stream

Impurities in CO 2 streams are manageable but could affect technical and non-technical considerations. Proper characterization of CO 2 injection streams will be required for determining well classification (e.g., proposed UI C Class VI well) and the applicability of other regulatory programs. Different CO 2 streams will have different compositions. For example, certain industrial processes (e.g., ammonia prod uction and biofuel production) produce streams that are nearly pure CO 2 . Natural gas combustion also produces a relatively pure waste stream. However, CO 2 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. CO 2 Storage – State of Technology De velopment: Supplementary Material C-5Potential co-captured impurities that could affe ct subsurface processes include hydrogen sulfide (H 2 S), and oxides of sulfur and nitrogen (SO

x and NO

x ). In a post-combustion scenario (i.e., capture from a conventional coal-fired power plant), impurities may include sulfur dioxide (SO 2 ), NO

x , and oxygen (O 2 ). Emissions from an IGCC plant would contain H 2 S instead of SO 2 and ammonia (NH 3 ) instead of NO

x . Also, the more volatile he avy metals (e.g., mercury, selenium, arsenic, and cadmium) and some organic impurities may be pres ent 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 sc rubbing steps (e.g., desul furization), as well as the CO 2 capture technology.

SO 2 raises concerns because it may become oxid ized 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 mi nerals, 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 SO 2 . However, current understanding is limited by la ck 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 plan ts that are capturing and injecting CO 2 into the subsurface, there are no field data with which to refine estimates from modeling. At this point, it is difficult to predict with certai nty the effects of injection of trace SO 2 . More research is needed, especially to assess the potential long-term effects on seal integrity.

H 2 S is not expected to severely affect pH. Neit her Xu et al. (2004) no r Knauss et al. (2005) predicted a significant pH change when H 2 S co-injection was simulated. Although low pH does not appear to be a concern with H 2 S injection, hydrogen sulfide is known to promote corrosion in steel. However, experience fr om analog operations (e.g., acid -gas disposal in Canada) is encouraging and suggests that the impact of impu rities on (at least) some reservoirs is manageable.

Potential heavy metal concen trations in a captured CO 2 stream have been calculated by Apps (2006) and are expected to be ve ry low. Non-volatile metals tend to remain associated with fly ash in coal combustion, and are not anticipated in CO 2 streams. Volatile and semi-volatile elements (mercury, arsenic, cadmium, and seleni um) have a greater potential for remaining with the flue gas and being captured. Post-com bustion treatment for particulates and SO 2 can remove a portion of the metals, but pr ediction of metals in a captured CO 2 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 issu e of trace metals as potential constituents in CO 2 injectate insignificant. Only trace concentr ations of organic compounds are expected (Sass et al., 2005).

All of these impurities would be injected along with the CO 2 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 wa ste wells. The corrosion-resistant construction standards, periodic corrosion monitoring and me chanical 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-6Experience from analog operations (e.g., acid- gas disposal in Canada) is encouraging and suggests that the impact of impurities on (at le ast) some reservoirs is manageable, but more research is needed to assess the potential long-te rm effects on seal integrity. Acid-gas injection is found to be a good analogue for CO 2 storage, as it results in the long-term storage of significant amounts of CO 2 . Because the equipment and geologic formations involved in acid-gas injection are similar to those required for CO 2 injection, much of the knowledge gained from acid-gas injection is directly applicable to CO 2 storage.



### C.4 Additional Needs for Widescale Deployment

Workforce capacity may be a barrier for wid espread deployment, including both projectrelated workforce needs (e.g., reservoir engi neers, etc.) and permitting-related workforce needs at both the State and Federal levels.

Technical Capacity

Current technical capacity of State and Federa l 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 pe rmit applications for completeness and technical accuracy. The UIC Program’s training material s address evaluating geologic data (e.g., on USDWs and formation testing); well constructi on and pre-operational testing data; permit conditions for construction, operation, ma intenance and monitoring; well plugging and abandonment requirements; addressing well fa ilures; financial responsibility; and public participation in the UIC permitting process.

The new requirements for Class VI geologi c 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 fo rthcoming 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 th e construction of a Class VI well.

o New site characterization consider ations for the unique nature of CO 2 geologic
storage.

o Evaluating the proposed well design an d construction, including the use of materials that are compatible with CO 2.

o Evaluating the proposed Area of Rev iew (AoR) for a Class VI well and the proposed multi-phase computational model.

o Evaluating Class VI testing and monito ring plans, including the monitoring necessary to track the CO 2 and pressure front in the subsurface and the ground water monitoring plan.

o Evaluating a Financial Responsibility demonstration.

Appendix C. CO 2 Storage – State of Technology De velopment: Supplementary Material C-7 Granting Approval for CO 2 Operations.

o Evaluating the Final AoR base d on logging and testing.

o Evaluating the testing to establish operat ing parameters and well shut-off triggers.

 Evaluating post-injection monitoring da ta 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 comp liance and enforcement activities. In addition to the workforce capacity development needs disc ussed in the body of the report, permitters will need guidance, training, and contractor assi stance to analyze fi nancial responsibility submissions in CCS permit applications. Current ly, 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 subm itted with insurance as part of the financial responsibility package, a permitter may not have the tools to dete rmine if the right coverage limit was selected or if the risk analysis perf ormed 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, acce ss to expert consultants who can troubleshoot will be critical for adequate review of CCS fina ncial responsibility submissions. Additionally, State UIC primacy agencies’ efforts could be ai ded by a national data system that would promote regulatory certainty, efficiency, and ac countability, while allowing transparency of all geologic sequestration related informatio n to improve public acceptance of CCS.

Pore Space

Definition of the ownership of injected CO 2 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 th em, ensuring that the community receives adequate information about the proposed in jection 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 provid e insight into how the local community and surrounding communities perceive potential en vironmental, 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-8It is important to ensure that mechanisms are in place for the public to access and synthesize storage project data (generally and on an in dividual site basis), including the following:

 stakeholders interested in launc hing and regulating projects,

 public education to address/forestall misinter pretations about this new technology, and

 engender commercial, regulatory, and public confidence.

Several efforts are already underway to deve loping a portfolio of outreach tools and approaches, including the following:

 Regional Carbon Sequestration Partnershi ps (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 la rge-scale injections). RCSP experience suggests outreach to various stakeholders is cr itical from beginning of project throughout
execution. Outreach needs ma y vary both between stakehol der groups and regionally.

 Best practice manual for outreach (based on RCSP experience) is anticipated to be released in 2010; Keystone Center has deve loped elementary and high-school curricula
for CCS.

EPA plans to work with permitting authorities an d 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 de veloping outreach tools on geologic storage such as fact sheets, visual aids, and the use of social media, and will hold public meetings.

Appendix C. CO 2 Storage – State of Technology De velopment: Supplementary Material C-9

## Appendix D. CO 2 

## Reuse

CO 2 reuse or utilization is the conversion of captured CO 2 to a useable product. 7 Similar to geologic storage of CO 2 , such utilization allows for a net reduction of CO 2 emissions into the atmosphere by using CO 2 either directly or as a feedstock (IPCC, 2005). Such net reduction is possible only if two conditions ar e met: (1) use of the captured CO 2 must not simply replace a source of CO 2 that would then be vented to the atmosphere, and (2) compounds produced from the captured CO 2 must have a long lifetime (IPCC, 200 5). For industrial processes, it is important to properly determine the system boundary in order to get an accurate determination of the net lifecycle CO 2 emissions based on material and energy balances (see IPCC, 2005 section 7.3.1 for more details).

CO 2 is a valuable industrial gas, and currently th ere are at least 22 commercial end-use sectors that use gaseous, liquid, or solid CO 2 (EPA, 2009), including food and beverage manufacturing and various chemical, pharmaceutica l, and other processes that use CO 2 as an end product. This number excludes intermediate CO 2 processors and enhanced oil and gas recovery. However, it remains to be determined whethe r there is a net redu ction of lifecycle CO 2 emissions from industrial processes using CO 2 . Furthermore, the amount of CO 2 reuse in industrial processes is very small compared with the magnitude of CO 2 emissions from industrial sources. Industrial sources in the Un ited States alone emit approximately 1.4 billion tonnes of CO 2 annually (EIA, 2010a).

Several options that are under investigation for CO 2 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 Unit ed States are based mostly on CO 2 obtained from natural sources. Replacing the use of natural CO 2 with captured CO 2 would result in a net reduction of emissions to the atmosphere, assuming that a part of the injected CO 2 remains stored underground. Through 2008, approximately 560 million tonnes (NETL, 2010) of CO 2 have been injected in the United Sta tes for EOR. Currently, the United States uses approximately 50 million tonnes of CO 2 per year for EOR (Dooley, 2008). Using EOR, 30– 60 percent of the reservoir’s original oil ca n 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, CO 2 is injected into an operational oil fi eld, 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. CO 2 injection can also be us ed to sweep oil toward production wells. In both cases, revenue accrued through the sale of the additional oil produced can help to offset CO 2 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. CO 2 Reuse D-1Figure D-1. Growth of U.S. Oil Production from CO 2 -based EOR

Source: (NETL, 2010)

Fuel Production: Most carbon-based fuels are made up of carbon, hydrogen, and oxygen. CO 2 can be hydrogenated to create low-carb on-chain fuel such as methanol. These hydrogenation reactions are exothermic in natu re, although they require catalysts such as copper, zinc, or alumina. Procuring hydrogen requi res 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 lif e-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 CO 2 generated from producing one unit of energy in a coal-fired power plant, if the hydrogen came from electr olysis of water (Herzog et al., 1993).

Chemical Synthesis: Ceramics, fertilizers, rubber, and many other small-scale industries require CO 2 at some stage of their manufacturing process. However, the amount of CO 2 that could be potentially used in these plants is rather small compared with emissions of CO 2 . The largest use of CO 2 in this area is in fertilizer plants, where CO 2 is captured from the exhaust gases of NH 3 reformer units and used to manufacture urea. Such chemical synthesis is already under application, and CO 2 emission from power plants can be routed to such units— although it is not clear if there will be net negat ive emissions from such applications. Laying of new pipeline for CO 2 would also be quite expensive and increase lifecycle CO 2 emissions.

Polymer Synthesis: 8 CO 2 can be viewed as a C 1 building block of a long carbon chain polymer. However, using CO 2 requires the development of efficient catalysts and additional energy for reducing CO 2 . Finding an efficient reducing catalyst or net low-energy-intensive process to reduce the CO 2 has been the challenge so far. However, CO 2 can be used in place of phosgene in polyurethane and polycarbonate manufacturing, as phosgen e is toxic. Overall potential for CO 2 use in polymer synthesis is not signific ant 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-2CO 2 , it can potentially use about 100 million tonnes of CO 2 , around 5 percent of annual CO 2 emission from the power sector (Herzog et al., 1997).

Bio-fuel production using Algae: Plants convert CO 2 and water into starch using sunlight during the photosynthesis process. Although mo re advanced plants are not very effective in conversion of large quantities of CO 2 , micro-algae can use high concentrations of CO 2 to create starch. The biomass prod uct can be used to recycle CO 2 into valuable industrial fuel such as methane, methanol, hydrogen and bio-diesel. However, the CO 2 removed by conversion to bio-fuel will be a dded back in the environment on ce it is burned. Also, it will require additional energy to convert the CO 2 to bio-fuel such as in ha rvesting, fertilizers, etc. Overall, the conversion efficiency is limited by photosynthetic efficien cy. At present, microalgae convert solar energy with one percent effici ency, implying that a solar collection area as large as 20 square miles is needed to convert CO 2 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 CO 2 to create insoluble carbonates. Rocks with high metal oxide concentrations ca n be used to store significant amounts of CO 2 in the form of carbonates. The technology for mine ral carbonation is not yet mature enough to allow for a proper assessment of costs and perf ormance, 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 CO 2 

### Utilization in Climate Change Mitigation

Several factors determine the viability of CO 2 reuse, and there are currently significant technical barriers to commercial-scale reuse. First, rates of conversion must be comparable to rates of CO 2 capture. Second, energy requirements for co nversion must be low. Third, potential volumes of reactants and/or products may limit th e scale of reuse relative to total emissions. Finally, reuse options need to co nsider the long-term fate of CO 2 and its lifecycle emissions.

In summary, there are limited commercial uses for captured CO 2 , such as in food and beverage manufacturing, pulp and paper manufacturing, the r ubber and plastic industry, fire suppression, and refrigeration and cooling. No market is expected to develop for reuse of CO 2 on a scale that would significantly affect a strategy to roll out CCS on a na tional basis by 2016.

Appendix D. CO 2 Reuse D-3

## Appendix E. Research, Development, & Demonstration

E.1 Research and Development

Capture

Two Research, Development and Demonstratio n (RD&D) technology pathways are being pursued globally for combining coal-fueled powe r generation with CCS. The first is based on pulverized coal (PC) power plant technology, whic h 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 tec hnology, but it is believed by many to be the pathway leading to the most co st-effective CCS options.

The highest priority RD&D is on capture technology using innovative solvents, solid sorbents, and membranes to extract CO 2 from flue gas. RD&D is focused on areas such as reducing regeneration energy and material cost, and incr easing reaction speed (s olvents and sorbents), durability, and tolerance to pollutants, and CO 2 selectivity (membranes). Advanced capture technology could reduce the increased cost of el ectricity 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 CO 2 reductions would be possible if ad vanced boiler materials are developed leading to a new generation of more efficient ul tra supercritical PC power plants that have a significantly smaller carbon footprint per power output.

Although several IGCC demonstration plants (as described in Append ix A) are operating worldwide, the strategy for IGCC RD&D is to co ntinue to improve the cost and performance of key plant components, including those that wi ll lead to higher availability. Current RD&D is focused primarily on advanced combus tion turbines, warm gas clean-up and H 2 / CO 2 separation membranes, coal feed pumps, and ion transpor t membranes for low-cost oxygen production.

The ongoing DOE CO 2 capture technology R&D program for post-combustion and oxycombustion capture is working to develop advanced 2 nd generation technologies capable of 90 percent CO 2 capture with a target of less than a 30 percent increase in the COE over a comparable plant without CCS. For pre-combustion capture (IGC C applications), the DOE goal is to provide electricity with less than a 10 perc ent 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 CO 2 capture technology R&D timeline to accomplish those goals includes the fo llowing major milestones (DOE, 2010):

 By 2016, complete small-scale fiel d testing of 2nd generation CO 2 capture technologies and components that demonstrate significant reduction in CO 2 capture cost and energy penalties compared with current technologies. The field test ing will be between 0.5 to 5 MWe scale from pilot plant fac ilities and/or slipstream treatment at operating coal-based power plants.

Appendix E. Research, Development, & Demonstration E-1 By 2020, complete large-scale fi eld testing at 25 MWe of 2 nd generation CO 2 capture technologies and integrated oxy-combusti on systems that demonstrate significant
reduction in CO 2 capture cost and energy penalties compared with current technologies.

As shown in Figure E-1 below, accomplishing these goals will re quire significant efficiency improvements for IGCC and conventional PC power plants. The IGCC with 2 nd generation CCS efficiency improvement includes advances in air separation (membranes), hot/warm gas cleanup, combustion turbines and CO 2 capture and compression technologies. With successful development of these technologies, the IGCC with 2 nd generation CCS efficiency increases from 33 percent to 40 percent. Likewise, impr ovements in advanced air separation, ultrasupercritical boiler materials, CO 2 capture and compression technologies will improve the PC with 2 nd 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 e fficiency improvements, the COE for IGCC with 2 nd generation CCS would decrease by 32 pe rcent (from 150 mills/kWh to 102 mills/kWh). Likewise, improvements in PC plan t capital costs (such as smaller CO 2 capture andPower Plant Efficiency [% HHV]

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage E-2compression 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 2 nd generation technologies sho wing 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 de cade. The relative roles of the government and the private sector in these more advanced stage s of CCS development and scale-up should be carefully evaluated.

Storage

DOE’s CO 2 storage activities involve three key elem ents for technology development: Core RD&D, Infrastructure, and Global Collaboration s. The Core RD&D element includes geologic storage, MVA, and simulation and risk assessmen t. 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 re search is identified through lessons learned from the Infrastructure and Gl obal 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 CO 2 trapping and storage capacity, determine reservoir theoretical capability to store CO 2 (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 CO 2 to be accredited as net emissions reductions.

 Assess the improvements to existing simulati on 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 CO 2 utilization, using fundamenta l 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 th e United States and Canada, and ongoing data collection is used to confirm geologi c 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 governmen t/industry cooperative effort tasked with developing guidelines for the mo st 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 en compassing 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 pa rtnerships completed the initial characterization of their regions’ potential to store CO 2 in different geologic formations.

 Validation Phase (2005–2010): The partnerships are concluding validation of the most promising regional storage opportunities throug h 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 prov ide the technical foundation for Development Phase activities.

 Development Phase (2008–2017): The partnershi ps are beginning to implement largescale field testing involving at least 1 million tonnes of CO 2 per project to confirm that CO 2 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 CO 2 storage capacity. This informatio n is integrated into the Carbon Sequestration Atlas and the National Carb on 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 ne xt-generation engineers and scient ists; and Site Characterization

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage E-4characterizes additional promising formations fo r geologic storage through investigations at 10 site locations. Work conducted through the RCSP Initiative and other Infr astructure activities benefits the DOE CCS Program by developi ng human capital, enco uraging stakeholder networking, providing data for policy developm ent, and developing visualization knowledge centers, best practices manuals, an d public outreach and education.

The majority of CO 2 operations today are occurring in tandem with business-as-usual EOR, with little effort spent on accounting for the CO 2 . To enable widespread, safe, and effective CCS within the next 10 years, commercial demo nstration projects should include storage in different geologic reservoir classes. DOE is currently conducting its CCPI and ICCS demonstration projects to determi ne effects of variation in CO 2 supply on storage operations. In addition, the RCSP program plans to cond uct nine large-scale injection and storage demonstration projects in a variety of ge ologic reservoirs. Knowledge generated from monitoring the fate and tr ansport of the injected CO 2 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 be tween the Federal government and industry to speed investment in low-emission coal techno logy by demonstrating and accelerating the commercial deployment of advanced coal-based power generation technologies. Recent project selections have focused on provin g the feasibility of integrating CO 2 management and power production, and facilitating the movement into th e 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 ne w 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 CO 2 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 necessar ily rely on consumers to pay the incremental cost of the technology (whereas public utilit y 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 fo r 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 depl oyment. However, certain key areas may not be adequately covered. For exam ple, a relatively small number of the abovementioned projects plan to inject captured CO 2 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 th e applicability of the Safe Drinking Water Act; the Resource Conservation and Recovery Act; the Comprehensive En vironmental 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: Injectio n and Geologic Sequestration of Carbon Dioxide , 75 Fed. Reg. 18576, 18578 (April 12, 2010), EPA note d 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 (existin g and new), natural gas processing facilities, petroleum refineries, iron & steel foundries, et hylene plants, hydrogen production facilities, ammonia refineries, ethanol production facilitie s, ethylene oxide plants, and cement kilns.” Id.



### F.2 Safe Drinking Water Act (SDWA)

CO 2 underground storage sites are regulate d through the SDWA Underground Injection Control (UIC) Program.

Underground injection wells are regulated und er 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 subs urface 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, liq uid, 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 fi ve 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); solu tion mining wells (Class III); shallow hazardous waste wells (Class IV, which are essentially banned); and all ot her wells (Class V). 11

Under § 1421(b), SDWA mandates that EPA deve lop 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 Po llution 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-1order to implement the SDWA UIC Program, States, Tribes, and territories must apply to EPA for primacy approval. Under § 1422, States have 270 days to subm it 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 Fede ral minimum requirements provided for in the Federal regulations. 13 Within 90 days of a State’s app lication, and after there has been “reasonable opportunity for presen tation 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 CO 2 , which is a supercritical fluid, meets the definition of “fluid” in SDWA. 15 CO 2 exists as a supercritical fluid at high pressure s and temperatures, and in this state exhibits properties of both a liquid and a gas. SDWA’s UIC regulations apply to all CO 2 sequestration well sites across the United States, including well s that are located inside a State’s territorial waters. CO 2 sequestration well sites are regulate d under the UIC program regardless of capture technology. Current options fo r permitting UIC wells that inject CO 2 include Class I industrial, Class II, or Class V experimental wells. 16

In 2008, EPA proposed Federal requirements for underground injection of CO 2 for purposes of geologic sequestration. 17 The proposal applies to owners or operators of wells that will be used to inject CO 2 into the subsurface for the purpose of long-term storage. It proposes a new class of well (Class VI) and tailors mi nimum technical criteria for geol ogic 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 in jection of large volumes of CO 2 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 in to effect, CCS will contin ue 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 CO 2 that may present an imminent and substantial endangerment to human health and the environment. RCRA hazardous waste requirements may apply to certain injectate CO 2 . The Solid Waste Disposal Act, as amended (commonly referre d to as RCRA), generally regulates “solid wastes,” with Subtitle C of the Act addressing management of solid wastes that are also “hazardous wastes.” RC RA 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-2States in lieu of a Federal program, with Federa l oversight. RCRA Subtitle C establishes a comprehensive “cradle to grave” regulatory sc heme, including requireme nts for generators and transporters, along with permitting and other requirements for hazardous waste “treatment, storage, or disposal” facilities. Violations of RC RA Subtitle C requirement s are subject to civil and criminal enforcement, and RCRA provides authority for the United States to take civil action to prevent imminent and substantial en dangerment due to the handling, transporting, disposing, or other actions relate d to a solid or hazardous waste. 18

RCRA defines “solid waste” as “any garbage, refus e, 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 ma terial 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 CO 2 is captured as a gas, (2) the point at which CO 2 is compressed to form a supercritical fluid (exhibitin g the properties of both a liquid and gas), and (3) the point at which CO 2 is injected as a supercritical fluid. At any of these points, CO 2 bound for permanent sequestration is li kely 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 ava ilable to address acti vities concerning CO 2 bound for sequestration that may present an imminent and substantial endangerment to human health and the environment.

CO 2 bound for permanent sequestration , if it were to qualify as a ha zardous waste, is also likely a solid waste for purposes of the RCRA hazardous wa ste regulations. It is “liquid [or] contained gaseous material resulting from industrial [or] co mmercial . . . 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 uphe ld 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-use d 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 CO 2 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 gene rally 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 re gulations state that this hazardous material may not be burned for energy recovery nor re-used in a manner that co nstitutes 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 CO 2 (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-3Under 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 (ignitab ility, corrosivity, rea ctivity, or toxicity), 26 or is a listed waste 27 (these include various used chemical products, byproducts from specific industries, or unused commercial products).

CO 2 is not a listed RCRA hazardous waste. From current technical knowledge, it is unlikely to exhibit the characteristics of ig nitability, reactivity, or corrosi vity at the point of capture or compression or injection for permanent storage. CO 2 captured from sectors amenable to CCS could contain toxic chemical cons tituents such as arsenic, merc ury, and selenium (IPCC, 2005; Apps, 2006). Whether a particular CO 2 stream is a hazardous wa ste based on toxicity will depend on whether it contains on e or more specific chemical constituents at levels above the toxicity characteristic concentrations in Ta ble 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 CO 2 is hazardous under RCRA.” (EPA could make a categorical determination through the rulemaking process.) EPA noted th at “[t]he composition of the captured CO 2 stream will depend on the source, the flue gas scrubbing technology for removing pollutants, additives, and the CO 2 capture technology. In mo st cases, the captured CO 2 will contain some impurities, however, concen trations 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 concentrat ions in Table 1 of 40 C.F.R 261.24(b), such waste stream likely would no t be subject to Subtitle C requirements as a RCRA hazardous waste.

In response to that proposal, EPA received co mments asking for clarification of how RCRA hazardous waste requirements apply to CO 2 streams. EPA is planning a proposed rule under RCRA to explore a number of options. Among th e options under consideration by EPA is the development of a “conditional exemption” from RCRA requirements for hazardous CO 2 streams in order to facilitate implementation of CCS while protecting human health and the

Rule for Mandatory Reporting of Greenhouse Gases: Inje ction and Geologic Sequestration of Carbon Dioxide (75 Fed. Reg.18576). However, while there might be limited commercial uses for captured CO 2 , such as in food and beverage manufacturing, pulp and paper manufacturing, the rubber and plastic indu stry, fire suppression, and refrigeration and cooling, no market is expe cted to develop for re-use of stored CO 2 in the regulatory time frame and the amounts at which CO 2 storage should occur on national scale-up of the CCS program.

23 For purposes of this report, it is assumed that the CO 2 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 CO 2 may be combined for transport to a storage site or sites. Depending on the nature of the CO 2 streams being mixed, the resultant mixture may contain different co-constit uents 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-4environment. EPA has created “conditional exempt ions” in the past defini ng 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 CO 2 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 contaminan ts 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, pumpi ng, pouring, emitting, emptying, discharging, injecting, escaping, leaching, dumping, or dispos ing into the environment . . . .” Under § 101(8), 42 U.S.C. § 9601(8), “environment” is broadly de fined and includes surface water, ground water, land surface or subsurface strata, and am bient 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 specif ied provisions of the Clean Air Act, the Clean Water Act, the Toxic Substances Control Act, and the Resour ce Conservation and Recovery Act. EPA may also designate a dditional substances as hazard ous substances under CERCLA. EPA maintains and updates a list of hazardou s substances in 40 C.F.R. Part 302. Under § 101(33), 42 U.S.C. § 9601(33), “po llutant” 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 estab lish liability under CERCLA § 107(a) 42 U.S.C. § 9607(a): (1) there must be a release or threaten ed 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 (10 th Cir. 2005). Liability under CERCLA is stri ct 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 al so responsible for the release, unless the responsible party can show that the harm is di visible. As is common under CERCLA, there is no statutory or regulatory exclusion for CCS activi ties, and it is this po tential liability that has raised concern about the viability of CCS projects.

Based on information we have to date on the po tential chemical composition of the injectate, it appears that under likely capture scenarios the in jectate will contain hazardous substances (e.g., arsenic and selenium). CO 2 storage projects almost certainl y fall within the definition of a facility. 31 Current owners and operators of CO 2 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 “an y 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-5the time of disposal, persons who arranged for the disposal of injectate at a storage project, and persons who transported captured CO 2 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. Conseque ntly, CERCLA liability could apply, unless such persons could establish a defense. Moreover, if CO 2 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) co uld be considered a fac ility owner under CERCLA § 107(a)(1), 42 U.S.C. § 9607(a), wh o might become liable for any response costs caused by that release.

One potential defense for CCS project owners an d 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 CERC LA § 107(j), 42 U.S.C. § 9607(j). Courts, however, have applied the exception narrowly. Li ability 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 CO 2 is reasonably expected to occupy through migration would provide for the broadest applic ation 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 de fined in CERCLA § 101(14) , 42 U.S.C. § 9601(14), CO 2 injectate would still be considered a hazard ous 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 requi red if a policy decision were made that a CERCLA exemption for CO 2 injectate would be appropriate.

CO 2 injectate could also be subject to release reporting requirements under CERCLA § 103(a), 42 U.S.C. § 9603(a), which serves to alert Fede ral 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 author ities 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 s ubsurface injection site, EPCRA would impose emergency planning requirements. Release re porting requirements might apply to certain releases outside the facility or outs ide the scope of a Federal permit.

In general, EPCRA establishes release report ing requirements and emergency planning requirements for hazardous substances (HS) listed in 40 C.F.R. § 302.4 and extremely hazardous substances (EHS) liste d in 40 C.F.R. Part 355 App. A, B. Based on information we have to date on the chemical composition of th e injectate, it appears th at under likely capture scenarios the injectate will cont ain both HS and EHS. How th ese 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 fa cility to include only the structures on land surface, or whether the facility also in cludes the subsurface injection site.

EPCRA § 304, 42 U.S.C. § 11004, requires the owne r or operator of a facility to notify State and local authorities of unpermitted releases in to the environment of a reportable quantity (RQ) of an HS or EHS. Release s that occur solely within the facility boundaries or that are Federally permitted are exempt fr om having to report. If the age ncy chooses to interpret the EPCRA facility as including the subsurface inje ction site, release reporting under EPCRA § 304 would not be required if the re lease does not cross the facili ty boundaries. Release reporting would be required if the release crossed the fa cility boundaries, the release was not Federally permitted, and the amount of HS or EHS in the CO 2 injectate exceeded the RQ.

EPCRA § 302, 42 U.S.C. § 11002, requires the owne r 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 requirement s would apply under ECPRA § 302 if the amount of EHS in the CO 2 injectate exceeded the TPQ.

There is no exclusion for CCS projects fr om 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 appl y to some geologic sequestration facilities. 34 EPA has proposed a rule to require monitoring and reporting of CO 2 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-7NSR applies to the emissions of any criteria po llutant 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 at tainment of the NAAQS and of all other regulated pollutants (except those designated as “hazar dous air pollutants” under § 112 of the CAA). Although CO 2 is not currently a regulated air pollutant under the CAA, this will change once the standards in EPA’s Light-Dut y Vehicle Rule take effect in 2011. 35 At this time, the change in the regulatory status of CO 2 is not anticipated to have a di rect substantial impact on the PSD requirements applicable to geol ogic 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 ai r emissions from the equipment at the facility. A geologic sequestration facility wi th sufficient potential air emissions to trigger NSR or PSD would be required to obtain a pe rmit 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 ar t 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 CO 2 , if any, would be appropriate as part of a PSD review; ho wever, it is worth noting that a well-designed geologic sequestration facility is unlikely to have significant potential emissions of CO 2 . As a result, the CO 2 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 implemen ted 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 th e requirements of PSD. EPA is the permitting authority for these sources.

EPA has also proposed to amend the Greenhous e 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 operat ors of facilities that conduct injection and geologic sequestration of CO 2 . 37 Facilities that conduct geologic sequestration would be required to develop and implement an EPA-approv ed site-specific monitoring, reporting, and verification plan; and to annually report the amount of CO 2 sequestered, by subtracting total CO 2 emissions (such as the amount if any leaked to the surface or vented from surface equipment) from the CO 2 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 pote ntial applicability of the National Environmental Policy Act (NEPA), 42 U.S.C. §§ 4321-4370h, the End angered Species Act (ESA), 16 U.S.C. §§ 1531-1544, and the National Historic Preservati on 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 en vironmental consideratio ns 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 pr ocess that ultimately leads to greater public awareness and better agency decisions that reflect an understanding of environmental consequences. The NEPA process provides mult iple and meaningful opportunities for public engagement. For example, during the process by wh ich the scope of the issues and alternatives to be examined in an Environmental Assessmen t or Environmental Impa ct Statement (EIS) is determined, there can be many public meetin gs with local communities and stakeholders. Moreover, the public has an opportunity to comment on environmental documents.



### G.1.2 Environmental Review is Requir ed when there is a “Major Federal Action”

NEPA requires agencies to prepare an EIS for “e very recommendation or report on proposals for legislation and other major Federal actions si gnificantly affecting the quality of the human environment.” 40 Although NEPA itself does not defi ne “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-1responsibility.” 41 In contrast, where an agency lacks disc retion to affect the environmental outcome of its actions, there is no “m ajor 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, regu lated, 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-Federa l project to become a major Federal action, the Federal agency must ha ve some measure of control over the environmentally pertinent aspects of a non-Fe deral project, some “ability to influence or control the outcome [of the project] in material respects.” 46

G.1.2.1 Federal CCS Activities That Requi re Preparation of a NEPA Document

Use of Federal lands for the purposes of CO 2 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 CO 2 storage. More specifically, CO 2 storage on Federal land will require amendment to the appropriate land use planning documents (i.e., National Forest Plans (Forest Pl ans) 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 pipelin e or storage siting, but these site-specific NEPA documents may be somewhat streamlined by bein g able to “tier” off of the PEIS. The sitespecific NEPA documents will eval uate local conditions that migh t 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 regulati ons 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-2Conducting a programmatic NEPA analysis is lik ely to be time-consuming, and that analysis should be commenced very early in the pla nning process for CCS. In fact, the law directs agencies to integrate the NEPA process into earl y 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 substa ntial interagency coordination and analysis. Some examples of timelines for PEIS preparatio n, from scoping to publication of the Record of Decision, are as follows: 1.5 years for the Ge othermal Resources Leas ing 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, NE PA analysis for such a project will require additional time, on the scale of two or more ye ars, depending on the co mplexity of the project and the significance of the impacts. Preparation of a PEIS can have substa ntial 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 an d 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-t erm systematic planning, establish mitigation strategies, and generally set the stage for potential site-specific actions that may have si gnificant 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 regi on-wide planning can work to streamline site-specific
review:
[The PEIS ]. . . establish[es] policies and BM Ps [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 energydevelopment projects on BLM-administered public lands. Site-specific concerns and speciesspecific concerns, and the development of additi onal mitigation measures, would be addressed in project-level reviews, including NEPA analyses, as required. To the extent appropriate, future project-specific analyses will tie r 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-3If 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 planni ng 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 cate gorical 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 ca tegorical exclusion by an agency (performed in conjunction with the CEQ) would include developi ng 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 Fe deral 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 provid ing 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 CO 2 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 th at 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 en ergy development, including adoption of the programmatic policies and BMPs and id entification of exclusion areas.
(Bureau of Land Management, 2006).

55 40 C.F.R. § 1508.4.

56 Id.

57 CEQ’s draft memorandum provides guid ance on applying existing or establishing new categorical exclusions. See (Council on Environment al 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 CO 2 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-4become Federalized can turn on very specific ci rcumstances. Therefore, each situation must be evaluated independently. Agencies should carefu lly consider their involvement in non-Federal projects to determine whether their NE PA 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 fo rmidable 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 CO 2 in the air or ocean, impacts to underground water supplies from migration of CO 2 , induced seismicity from the storage of CO 2 , and impacts to the climate if accidental release occurs. In addition, there will also be challenges in determining the cumulative impacts of CCS pr ojects, what direct and indirect effects are reasonably foreseeable, and the scope of the analysis area. These ch allenges occur in the context of NEPA’s express require ment 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 technologi cal 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 an d 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 specif y 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 ov erall 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 inco mplete 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 reasonab ly foreseeable impacts on the human environment; and (4) the agency’s eval uation of such impacts based upon theoretical approaches or research metho ds 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 incomp lete knowledge of system dynamics, or when evaluating the probability of credible ca tastrophic outcomes. Prior NEPA documents inadequately confronting issues of uncertainty pr ovided 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-5understand how uncertainty should be honestly assessed not simply for a legally sufficient NEPA document, but also for a NEPA document that will be accept able 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 a ssessment 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 de pend may be conserved, [and] to provide a program for the conservation of such enda ngered species and threatened species....” 63

As relevant to CCS, Section 7 of the ESA outlines the proc edures for Federal interagency cooperation to conserve Federally listed species and designated critical habitats. Section 7(a)(1) directs the Secretary (Secretary of the Inter ior/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 fo r 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 likel y 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 th ere is a “May Affect” Determination

ESA consultation will be determined by the presen ce 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 consulta tion (“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-6Service or NMFS depending on the species involv ed. The action agency may prepare a biological assessment (BA) to evaluate the pote ntial 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 alternat ive 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 propos ed action—whether standing alone or as modified by a reasonable and prudent alternative— is not likely to jeopar dize 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 spec ies and specify those re asonable and prudent measures that the USFWS or NMFS considers “n ecessary 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 Requi re Preparation of an ESA Document

Where there is an effect on ESA listed species, use of Federal lands for the purposes of CO 2 pipeline siting or storage requires ESA consulta tion, which can be under taken in conjunction with NEPA obligations. The use of programmati c 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 pl an, for example, establishing a national plan for the development of CCS infr astructure, would involve an “action” that is extremely broad. Moreover, concrete and on-the-ground effects woul d not be readily apparent or even existent until particular projects or actions are propos ed pursuant to the programmatic decision. Thus, the effects of the action—which may cover the en tire 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, sh oot, 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-7at a level that is more than theoretical and sp eculative. 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 discre tion, 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 Fede ral 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 degr ee of the Federal agency’s control over the environmentally pertinent aspects of th e 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 liste d species. While the ES A Section 7(a)(2) does not require Federal agencies to pr otect listed species or critical habitat from harms caused by third-party actors, seemingly private activi ties may not be exempt from the ESA.

That said, private activities that could trigge r 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 assi stance 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 subs equent land use decisions and therefore upon the land itself,” and thus is the cause of incident al 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 Ci r. 2001) (rejecting the notion th at an ITS must accompany every BiOp and holding instead that “an Incidental Take Statement must be predic ated on a finding of incidental take”).

76 An agency is required to consult only on actions wher e it has discretion to implement measures that inure to the benefit of protected species. The purposes underlyin g 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 ES A “covers only discretionary agency actions and does not attach to actions . . . that an agency is required by stat ute 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-8facilities; 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 CO 2 transport or storage on private land if a permit is required by stat ute or regulation for such activities).

Finally, the ESA also imposes certain requireme nts 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 proj ect were to be found not to impose Section 7(a)(2) Federal consultation requ irements, a private deve loper would likely still consider a project’s potential effects on an y 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 cann ot 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 i nforming decision makers and the public may be challenging; however, the ESA imposes substant ive 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 consideratio ns regarding the uncertainty in science and risk assessment should apply to ESA co nsultation (where necessary) as well. The use and limits of available science should be expl ained and disclosed. Assumption s should be supported, and the agency should discuss whether other models or other assumptions lead to different conclusions. Ultimately, as with the NEPA docu ment, 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 indi rectly, between the proposed agency action and the effect on a listed species must be established. See National W ildlife 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 require ments. For example, the National Historic Preservation Act, similar to NEPA, requires Fede ral 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 numbe r of State counterparts impose substantive requirements. For example, the California Env ironmental Policy Act requires that public agencies not approve projects if there are “feasibl e” alternatives; i.e., if the alternatives are “capable of being accomplished in a successful ma nner in a reasonable period of time, taking into account economic, environmenta l, social, and technological factors.” 85 Moreover, different types of State action trigger the State NEPA pr ocess, and the particular State agencies covered by the legislation vary. 86 Because currently CO 2 pipeline and siting decisions are authorized and permitted by States, environmental review th rough various State NEPAs more frequently occurs than Federal NEPA review. If CCS become s a project national in scope (i.e., through inter-state pipelines), a uniform environmenta l 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 CO 2 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 misapplie s monitoring technology and fails to detect migration of CO 2 , or an operator misuses injecti on equipment, which fails, and CO 2 is released from the storage site.

4. Regulatory mistake or oversight. For example, a State or Federal agency reviewing a permit application fails to dete ct a geological feature, or fa ils to identify migration of CO 2 in monitoring data.

5. Falsification and illegal conduct . For examples, a site operator falsifies geological data in order to obtain a permit; a site oper ator falsifies monitoring data in order to avoid the costs of remediation; or a site operator stores more CO 2 than allowed under a permit to obtain the associated income stream.

6. Policy changes . For example, a subsequent Admini stration 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 neverthe less erroneously holds the site operator liable, for example on an ultr ahazardous activity theory.
Scope of this list . Note that the foregoing list of sour ces of long-term storage risk and/or liability only addresses risks and/or liabilities a ssociated with storage activities. Capture and transportation risks are not included. Certain “gar den variety” sources of risks associated with industrial activities that will occu r at a storage site—such as inju ries 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 privat e insurance program that may be adapted (with appropriate revisions) for insuring the risks of long-term storage of CO 2 from CCS activities. It should be noted, however, that the main incent ive for private insurers to offer the insurance mandated by the PAA may be the fact that the P AA caps the liability of nuclear plant operators at an amount equal to the limits of liab ility 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 in surance protection consists of two tiers:

1. The primary level provides $375 million in liab ility insurance. This first-level coverage consists of the liability insurance provided by insurance pools. The pools are groups of insurance companies pledging assets that en able them to provide substantially higher coverage than an individual company could offe r. If this amount is no t sufficient to cover claims arising from a nuclear incident, secondary financial protection applies.

2. For the second level, in the event of a nucle ar incident, each nuclear plant must pay a retrospective premium equal to its propor tionate 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 nucle ar reactors in the United States are participating in the secondary financial protection program.

If claims exceed the maximum Pric e-Anderson value (i.e., insurance coverage is exhausted), the private insurers have no further liability. In th at event, the President is required to submit proposals to Congress. These proposals must de tail 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 th e Tucker Act (in which the government waives its sove reign immunity), 28 USC § 1491, for failure by the Federal government to carry out its duty to compensate claimants.

The NRC codifies the conditions for indemnit y 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 requireme nts than larger reactors, while the financial protection required for nonprofit educational re actors 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 State s 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 circumstan ces surrounding CCS warrant this extraordinary step.

Second, sound public policy and legislative preceden t 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 insuranc e is unavailable. Authori ty 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 defens e, and private insurance cannot be obtained to protect against the potential liability (e.g., agreements indemnif ying Department of Energy contractors for liability arising out of nuclear incidents, agreemen ts 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, gene rally, the discussion in Hercules Inc. v. United States , 516 U.S. 417, 426-29 & n.11 (1996).

Underlying these legislative exceptions and thei r implementing regulations has been the premise that not only is the activity esse ntial to national security, but also that private markets cannot provide adequate insurance coverage in the ev ent of a disaster. Executive Order 11610, which supplements Executive Order 1078 9 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 prote ction 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 I ndemnification 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 1078 9, the Federal Acquisition Regulations (FAR) provide detailed requirements that must be met when a government contra ctor seeks indemnific ation 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 -1One approach to government indemnification is co ntained 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 DO E. 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 transpor ting 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 auto matically extended to any subcontractors engaged by the contractor, by means of a provisio n in the indemnity requiring the contractor to provide an equivalent indemnity in any contra ct 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 wh o are covered by State or Federal workers’ compensation acts are not covered. There is also no right of re covery where a nuclear incident results from “acts of war,” and there is typic ally no carve-out under the indemnity for the contractor's negligence, willful or reckless mi sconduct. 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 Di strict Court for the Southern District of Ohio.

In re Fernald Litigation was brought in 1985 by property owne rs 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 lia bility, private nuisance, willful and wanton misconduct, violation of the parent corporation’s contractual guaranty and violation of the PAA. Plainti ffs claimed damages for emotiona l 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 th at was paid by DOE. The DOE indemnity was

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage J -2cited 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 Op en-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 be en that waivers of the strictures of the AntiDeficiency Act should only be co nsidered (and not necessarily a pproved) in situations in which essential activity will simply not be conducte d 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 inde mnification to contain a sunset date or provide that the authority to develop indemnit y agreements should expire on a date certain absent reauthorization, as in the PAA contex t. This would allow Co ngress to evaluate the continuing need for indemnity agreements based on the current state of the commercial CO 2 capture and storage market and availability of pr ivate insurance. Additionally, to protect the public, individual indemnification agreemen ts 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, proper ty, or natural resources. Such an indemnity would not be limited to hazards unique to the CO 2 capture and sequestration program; it could apply to injuries such as caused by traffic accidents in the course of the operations. Thus, any indemnificatio n 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 unde r 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, clai m, demand or action, liability , judgment, cost or other fee arising out of any claim for personal injury or property damage . . . that results fr om, 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 in stallation (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 ta ken lightly or routinely. The legislative proposals offered last year in Congress did not pr ovide 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 prom oting clean coal technologies and CCS. The major efforts include the Regional Carbon Sequest ration Partnerships (RCSP), the Clean Coal Power Initiative (CCPI), and FutureGen. Liability issues associated with the current DOE clean coal programs are generally handled pursuan t 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 th rough 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 liabili ties associated with CO 2 from project operations. For example, DOE application materials for the RCSPs contain lang uage 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, a ctions, or claims of any character for death, bodily injury, or loss of or damage to property or to the environment, resulting from the proje ct, 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 loca ted 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 liab ilities 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 proc ure 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 arisin g 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, oper ation, 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 op erator 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 pr e-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 Stat e 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, issu es may arise where pore space needs for CO 2 storage extend over an area where numerous owners hold rights.

Several options could address aggregation of pore space for CO 2 storage projects. All options except the first would require a statutor y 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 Environment al Response, Compensation, and Liability Act and/or tort law implications where ow nership vests in a government entity.

Option 2: Exercise or Delegate Federal and/or State Eminent Domain Authority. Federal or State governments could use (or dele gate) their authority of eminent domain to condemn pore space for use for a CO 2 storage project. Eminent domain is used to acquire property rights for underground natural gas st orage 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 CE RCLA 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 CO 2 geologic storage. Unitization is commonly used fo r 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). Unitizat ion of pore space coul d 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 cred it market (Sorensen et al., 2009).

Option 4: Provide Pore Sp ace Underlying Onshore or Offshore Federal Lands for CO 2 Storage. The Federal government could make pore space underlying Federal lands available for CO 2 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 CO 2 migrates beyond the Federal property boundary, or if

90 15 U.S.C. § 717f.

Appendix L. Property Rights L-1ownership 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 producti on, cultural resource protection, and community growth and development. There may also be addi tional 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 Federa l lands may be a viable option for some nearterm CO 2 storage projects.

Options 5: Assert that No State and/or Pr ivate Property Interest Exists in Deep Pore Space. 91 The United States could assert that no pr ivate property interest exists in deep pore space and that pore space property righ ts are owned by the Federal government. One could make an argument that sovereignty over navigable waterways provides precedent for Federally owned property interests. However, ex cept in those instance s 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 spac e 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 sp ace is designated for storage of CO 2 could also discourage the consideration of alternativ e uses of the subsurface. In ad dition, 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 repres entative 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 CO 2 storage would increase demand for pore space markedly, and could lead to an increa se 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 increa se availability of privately owned pore space, while also strengthening purchasers’ negotiati ng 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 CO 2 storage operators or other agents in proc edures akin to those used under the NGA. 92 At the outset, pore space owners might challenge co ndemnation by alleging that acquisition for CO 2 storage by private operators is not a “public ” use; however, such challenges would almost surely fail under precedent established by th e 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-2If 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 va lue is defined for Federal takings as the amount in cash, or on te rms reasonably equivalent to cash, for which in all probability a property would have sold afte r a reasonable exposure time in an open competitive market, from a willing and reason ably knowledgeable seller to a willing and reasonably knowledgeable buyer, with neither acting under any compulsion to buy or sell, giving due consideration to all availabl e 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 po re space, there are few transacti ons 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. Ch oice of State law valuation standards may open the door to higher values than would application of Federal standa rds, as well as inconsistent valuations across multiple States. 98

Where evidence of comparable sales or leases of pore space is unavailabl e, 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 CO 2 storage is sought in private subsurface areas where there are already commercial uses of pore space, su ch 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 CO 2 storage but there are not other commercial uses for the pore space, the costs associated with acquiri ng that property may be difficult to quantify until enough comparable transaction s 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 CO 2 . While most legal authority genera lly 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 applicatio n 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 Acquis itions, 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 ge nerous 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-3any 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 CO 2 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 sy stem that it is the rightful owner of pore space, the United States could avoid claims against it by competin g owners based on the Fifth Amendment. That section of the United States Constitution provid es that private property shall not be taken by the United States for public use without the paymen t of just compensation. It is well established that the permanent occupation of private proper ty by the United States es tablishes a successful “physical takings” claim, which althou gh not precluding continuation of CO 2 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 extra ct 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 CO 2 storage area. Such restrictions could give rise to “regulatory takings” claims by the holder of the deeper mineral intere sts. Like physical takings, regulatory takings entitle a successful claimant to just compensa tion based on the market value of the property interest; the determination of liability is far mo re complex, however, requiring a balancing of the property owner’s investment-backed expectati ons, the character of the government action, and the economic impact.

100 In the case of Federal lands, interp retation 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 CO 2 

## Pipelines

M.1 Siting of Pipelines across Private Lands

Given the potential for expansion of interstate and intrastate CO 2 pipelines and storage facilities, revisiting the siting authority of CO 2 pipelines across private lands may be warranted. Three potential models are discussed below.

Model 1: No Federal Auth ority – Retain Status Quo. This approach would retain existing State or local siting of CO 2 infrastructure. Various Stat es have sited approximately 3,600 miles of CO 2 pipeline in the United States (Dooley , 2008). There have been no instances of complaints that States have either inappropriately denied requests for CO 2 pipelines or unduly delayed projects. However, the existing system of CO 2 pipelines is relatively limited. The largest existing CO 2 pipeline system is located in and around the Permian Basin of Texas, Colorado, Oklahoma, and New Mexico. The on-s hore oil pipeline network, which has also been developed without Federal si ting 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 CO 2 infrastructure may prove to be effective to the extent that a substantia l, long-line, interstate pipeline network is not required.

However, if an extensive network of long-line in terstate pipelines is needed for transporting CO 2 , 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 siti ng interstate facilities. Construction in populated and environmentally sensitive areas poses significan t 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 em inent domain to CO 2 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 outs ide 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 o il pipelines and electric transmi ssion lines may be instructive. The Interstate Commerce Act gives the Federal Energy Regulatory Commission (FERC) authority to regulate the transportation rate s and practices of oil pipelines, but does not authorize FERC to site oil pipelines. 101 That authority rests with th e applicable State and local governments. An extensive network of oil pipelines has been constructed under this regulatory scheme. The majority of crude trunk lines transp ort oil from Canadian sources or sources in the Gulf Coast to Midwes t markets, particularly around Chic ago. Major oil pipeline projects are currently under construction to serve the Chica go 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 CO 2 Pipelines M-1However, the GAO issued a report finding that the U. S. petroleum product distribution system is constrained in key areas and will likel y become more so without timely investments (GAO, 2007). The report cites statements by De partment of Transportation officials that restrictions in the nation’s petroleum pipeline i nfrastructure 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 an d 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 permitti ng 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 pipe lines 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 popul ated 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 b een 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 CO 2 pipelines, would be less intrusiv e on State rights. A Federal agen cy would have the authority to site an interstate CO 2 pipeline only where a State does no t or cannot site th e pipeline. This approach would be effective in promot ing the development of interstate CO 2 infrastructure only to the extent that most pr ojects are actually sited at the State level, and that requests for Federal siting authority are the exception. Ho wever, if this is not the case, requiring CO 2 projects to be reviewed sequentially at both th e State and Federal level will significantly increase the processing time and associated costs for proj ects. To the extent the project is authorized under Federal authority, eminent domain rights co uld 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 In vestment 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 us ed and funded primarily by retail nativ e 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 infrastructu re is not only dependent on an effective siting approach, but on a clear and unambiguous revenu e 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-2lines has not yet been exercised, although there is an application to site an interstate electric transmission facility currently pending at FERC, an d 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 auth ority for the siting of interstate CO 2 pipelines in a single Federal agency. 106 That Federal agency would cond uct 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 Sta te-by-State permitting process. In addition, a Federal agency would be in a better position than individual States to ta ke into consideration the broad national interests that mi ght underlie a proposal to build CO 2 infrastructure. 107

Legislation implementing Federal siting authorit y 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-o f-way from landowners by private contract.

Providing a permit holder the ability to acquire ri ghts-of-way by exercise of the right of eminent domain ensures that project sponsors can secu re necessary property rights. Absent agreement between a permit holder and any landowner, th e 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 po tentially can reduce both delay and costs. In contrast, without the right to condemn necessary property, the pi peline may be unable to obtain rights-of-way over a preferred pipeline route; alternative rout es may ultimately prove to be economically, technically, or environmentally infeasible.



### M.2 Siting CO 2 

### Pipelines across Tribal Lands

The Energy Policy Act of 2005 Se ction 1813 Study on ROWs on Indian land reaffirmed the current policy that Tribal consent is needed befo re any right-of-way (ROW) is given on Tribal land. Any ROW across trust land would also requi re Secretarial approval subject to a NEPA analysis, as well as a determination that it is in “the best interests of the Tribe.” A CO 2 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 deve lopment that occurs on tribal la nd (as defined in Section 2601).

106 For this purpose, interstate CO 2 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 CO 2 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 CO 2 Pipelines M-3Thus, to bypass the requirement of Secret arial approval for a ROW, a ROW for a CO 2 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 pr oduction facility on that Tribal land.



### M.3 Siting CO 2 

### Pipelines across Federal Lands

Federal agencies have the authority to grant ROWs over Federal land. Currently, ROWs for the purpose of CO 2 pipelines are most commonly authorized by the Bureau of Land Management (BLM) pursuant to the Mineral Leas ing Act (MLA) of 1920, although some have been authorized pursuant to Title V of the Fe deral Land Policy and Management Act (FLPMA). Pipeline ROWs granted pursuant to MLA are re quired to be constructed, operated and maintained as common carriers, with certain limited exceptions. Federal departments or agencies cannot obtain a ROW grant for CO 2 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 Na tional 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 au thority 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 CO 2 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 la nds 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 Fe deral 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. Futu re use of the corridors should reduce the proliferation of ROWs across the landscape an d minimize the environmental footprint from development. Section 368 corridors are sited to avoid, to the maximum extent possible, significant known resource and environmental conf licts. The Act does not specifically identify CO 2 pipelines, but it also does not specif ically exclude them. It seems that a CO 2 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 CO 2 

### Pipelines

Bureau of Ocean Energy Management, Regulatio n, and Enforcement (BOEM) and other agencies may become involved in addressi ng issues associated with offsho re 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-4Department 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 permi ts for pipeline crossings of navigable waterways, shorelines, and navigatio n fairways. The U.S. Coast Guard regulates marine navigation generally, and may declare ex posed pipeline segments or other subsurface obstructions as hazards to navigation.



### M.5 CO 2 

### Pipeline Common Carriag e Considerations for CCS Operations

The model for CCS will likely be driven by the source of CO 2 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 indu stry, where wells can be shut and brought back on line as demand fluctuates. The ability to ma intain availability of the pipeline and storage system will require redundancy and spare capaci ty in both the transportation and storage systems to accommodate swings in the CO 2 supply. If a pipeline operator fails to satisfy CO 2 off-take agreements, the emissions sour ce could be forced to vent CO 2 emissions, scale back operations, or shut down. It is expected that sh utting down a power plan ts 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 CO 2 pipelines be designated as co mmon carriers. Common carriage law requires operators to offer excess capacity for a f ee to any entity wishing to transport their gas through the pipeline.

Regulators may consider the impacts that commo n carrier laws will have on the future CCS industry. Power plants and other sources of CO 2 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 th e 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 co nsider allowing sources to reserve capacity on dedicated pipelines once a source is in operatio n, or consider the entire CCS system (capture, transport, and storage) as an integrated syst em which would not be subject to the typical common carriage requirements.



### M.6 Approaches to Rate and Tariff Regulation of CO 2 

### Pipelines and Storage

There appears to be a particular need for flexib ility in any law providing for the regulation of services provided by CO 2 pipelines and storage, because of the current uncertainty as to who will own and operate such facilities, the exte nt to which an integrated interstate CO 2 pipeline grid will be necessary, and what business model th e 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 CO 2 Pipelines M-5and therefore the laws could be structured in light of the industry’s existing business practices. In considering legislation concerning Federal regulation of CO 2 pipelines and storage facilities, the need for regulatory flexibility should be bala nced with a need to provide potential industry participants with some degree of certainty co ncerning the applicable regulatory regime.

The approaches presented below illustrate the ra nge of possible ways to regulate the rates, terms, and conditions of service of CO 2 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 CO 2 pipelines or storage facilities. Instead, CO 2 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 CO 2 is relatively rare. In that event, State and local regulation would be adequate, and jurisdictional issues with interstate commerce, which might ot herwise act as a barrier to effective State and local regulation, would likely be minimal. This is the regulatory approach currently used for CO 2 pipelines transporting CO 2 to be employed in EOR operations.

Approach 2: Federal Open Acc ess and Transparency Requirements

An “open access/transparency” model of regulation would require interstate CO 2 pipelines and storage facilities to provide open and non-discrimi natory access both to ow ners of the facilities and to non-owners. 109 This model would also emphasiz e public disclosure of commercial transactions and terms and conditions of servic e 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 particul ar 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 requir ements. Most regulatory actions would be in reaction to the complaints of aggrieved parties against a CO 2 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 vertic ally integrated projects for CO 2 storage, and therefore may be interested in a commercial agreement with some one else’s project. A Federal oversight role would also act as a check that might prevent di scrimination, 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 CO 2 pipelines, leaving regulation of storage to the individual States.

Appendices to the Report of the Interagency Task Force on Carbon Capture and Storage M-6A traditional utility model of re gulation 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 requir es 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 te rms 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 wo uld be especially useful if development on a State-by-State level led to balkanization, inefficien cy (due to lack of econom ies 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 CO 2 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 CO 2 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 woul d be included in the cost of service. 111 In cases where facilities were also made available to othe r entities for a fee, the revenues collected from third parties would be “credited” to jurisdictiona l revenues. Where such facilities are part of an unbundled merchant generating facili ty, presumably the costs of CO 2 pipelines and storage would be at risk the same as any other gene ration 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 wo uld 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 regu latory approach. Currently, under the Natural

110 Congress could choose to establish such Federal regulation for CO 2 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 regula tors. State commissions would be responsible for siting and rate recovery at the retail level.

Appendix M. Siting Considerations for CO 2 Pipelines M-7Gas Policy Act of 1978 (NGP A), FERC may set rates in one of two ways. 112 First, FERC will allow a local distribution company or an intrasta te pipeline to use a St ate-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 ti me and fewer resources than the methods used to set cost-based rates for interstate pi pelines and wholesale electric utilities.

If CO 2 storage is developed on an intrastate level, and is not pr eempted by Federal regulation, it might be possible to use NGPA-like practice s to use State-approved rates to allow an intrastate storage service provider to provide interstate services.

112 15 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 CO 2 Emissions, Potential Storage and Storage Resource Duration for Top 10 Emitting Countries from Coal Utilization

Source for CO 2 emissions from coal: (EIA, 2010b).

Appendix N. International Collaboration Background N-1Table N-1. Storage Estimates for Top 10 Countries for CO2Emissions from Coal CombustionAppendices to the Report of the Interagency Task Force on Carbon Capture and StorageN-2Table N-2. U.S. Participation in La rge-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 CO 2 ‐ 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 CO 2 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 CO 2 . 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

CO 2 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.

CO 2 SINK 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 CO 2 trapping, plume tracking, and leakage by tagging CO 2 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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