This comment letter response contains two parts:   

(1) The original submittal from the commenter.

(2) A data base printout of EPA’s response to each point raised by the commenter.

Notes about the response letters:

• The response letters were generated by a data base used to track the content of all public

comment submittals and ensure that the Agency responds to each. Each comment letter

was assigned a Letter ID that corresponds to the last four digits of the docket number of the

original comment (as posted on www.regulations.gov).

• Each response letter includes: comment text; an EPA‐assigned comment code; and an

individual response. These are described and explained below.  

• The data base contains Comment text from the letters submitted by commenters.  

Many hard copy letters were scanned into electronic format for inclusion in the data

base. As a result, there may be some typographical errors attributable to optical

character recognition issues.  However, all original submittals were reviewed in the

process of drafting responses to ensure that the comment content was understood and

appropriately addressed.

• The content of each comment letter was divided into topic areas and assigned a unique

Comment ID.  Additionally, one or more Comment Codes (i.e., unique topic area ID) was

assigned to each discrete point raised by a commenter. This information was added to

the data base. To inform final rulemaking decisions, all comments and information

received on a given topic were reviewed by technical experts in each rule area (e.g., on

construction requirements).  

• Following decisions on the final rule requirements, Individual responses were drafted

by topic area to ensure completeness and consistency of the responses with the final

rule and other responses to similar comments.  Each discrete point made by a

commenter was given a unique response.

• Upon completion of comment responses, all information was entered into the data base.

Each letter response is a compilation of each comment and its individual response,

compiled in the order of the original comment letter.  As a result of this process, there is

repetition in the response text.  The Agency believes this approach ensures completeness

and attention to each comment letter that was submitted.   

• All comments in a topic area were reviewed, evaluated, and responded to concurrently.  

Responses on each topic area are compiled and are also available in the rulemaking docket.
December 22, 2008 

Via Electronic Mail and Hand Delivery 

Docket ID No.: EPA-HQ-OW-2008-0390 

Water Docket 

Environmental Protection Agency 

Docket Center (EPPNDC) 

EPA West Room 3334 

1301 Constitution Avenue, N.W. 

Washington, DC 20460 

Re: Comments on the United States Environmental Protection Agency' s Proposed Rule: 

Federal Requirements Under the Underground Injection Control (UIC) Program for Carbon 

Dioxide (COz) Geologic Sequestration (GS) Wells 

Dear Sir or Madam: 

The Carbon Capture and Storage Alliance ("CCS Alliance" or "Alliance") is pleased lo 

submit its comments on the United States Environmental Protection Agency's ("EPA or 

"Agency") Proposed Rule: Federal Requirements Under the Underground Injection Control 

(UIC) Program for Carbon Dioxide (COz) Geologic Sequestration (GS) Wells, which was 

released on July 25,2008 for review and comment by the public.1 

The CCS Alliance is a coalition of entities, spanning a number of economic sectors, that 

share a common interest in removing impediments to investment in and development of carbon 

capture and storage ("CCS"), as well as mitigating the potential risks associated with the 

deployment of this technology.' Its purpose is to promote development of policy by the states 

' Federal Requirements Under the Underground Injection Control (UIC, Program for Carbon Dioxide 

(C02) Geological Sequestration (GS) Wells. 73 Fed. Reg. 43503 (proposed July 25, 2008) ("Proposed Rule"). 

! MidAmerican Energy Holdings Company, National Mining Association, National Rural Electric 

Cooperative Association, NRG Energy, Inc., PacifiCorp and Zurich North America. 
and the federal government to appropriately address risks and potential liabilities, thereby 

enabling the further development and increased deployment of CCS. The CCS Alliance believes 

these technologies can be developed while protecting underground sources of drinking water, 

significantly reducing global and U.S. greenhouse gas ("GHG") emissions, and enhancing U.S. 

energy security. 

A plethora of regulations affect the delivery of power using coal. We suggest that the 

Agency consider other regulations addressing the environment, human health and safety, and 

electricity cost and reliability, when drafting and implementing these regulations. The Alliance 

urges the Agency to consider the support of integrated energy, climate, and environmental policy 

as time progresses. 

A central mission of the Alliance is to help ensure that the burden of regulations related 

to CCS, such as those proposed by EPA, and legislative proposals promote the mobilization of 

capital for use in CCS projects that have well managed risk profiles and help ensure that existing 

barriers to CCS created by laws and regulations are minimized, consistent with environmental, 

health, and safety objectives. 

If promulgated as currently proposed, the Proposed Rule will have a significant and direct 

impact on the interests of the members of the CCS Alliance and their customers. The CCS 

Alliance believes the Proposed Rule is helpful in many ways, but also that it can be improved in 

a manner that will both promote good risk management and reduce barriers to CCS deployment. 

I. INTRODUCTION 

If atmospheric emissions of CO:! are to be controlled, CCS is the only tool now on the 

horizon that may be capable of addressing in a major way and within a mid-term timeframe, the 

very large quantities of C02 emissions from fossil-fuel using facilities in the United States. 
However, CCS still requires the definition of a stable and rational legal and regulatory regime 

before it can be widely deployed. EPA has clear regulatory authority over the injection of wastes 

and other substances into below-surface wells through the UIC program. The UIC program was 

created by Congress under the Safe Drinking Water Act ("SDWA") over 30 years ago, without 

consideration of potential interaction with policies to address climate change, for the protection 

of underground sources of drinking water ("USDW). The Agency now proposes to use this 

framework to regulate below-ground CO2 injection activities, an application not contemplated at 

the time SDWA was drafted. Rules for geologic sequestration ("GS") of COz are timely and 

would be needed even if CCS is not deployed as quickly as many predict. While many projects 

are under development, many observers are operating under the assumption that it will be a 

decade or more before there can be wide deployment of CCS.~ The future of CCS is and will be 

at a critical juncture for some years. The CCS Alliance seeks, through its comments, to help 

ensure that these regulatory activities promote well designed and implemented CCS projects with 

sound risk management practices, and do not preclude the responsible, cost effective 

commercial-scale sequestration of C02. 

11. IMPORTANCE OF PROMOTING CCS TECHNOLOGIES 

EPA agrees, given the United States' abundant coal resources and its reliance on coal for 

power generation, that "CCS could be a key mitigation technology for achieving domestic 

emissions reductions." As the following diagram demonstrates, coal is indispensable to meeting 

the country's electricity demands, regardless of region: 

3 See, e.g., "EPRI Summer Seminar and Energy Technology Assessment Center (ETAC) Studies," 

presentation of Hank Courtright, Senior Vice President, Electric Power Research Institute. October 22. 2008. 
oiffen'ng Electricity Mix by Region (EEI), 2008~ 

As the only significant technology to reduce atmospheric CO2 emissions from coal, CCS 

is indispensable to reducing GHG emissions while meeting energy demand and achieving energy 

security. It is true, as EPA notes, that underground storage of C02 is "only one of a portfolio of 

options," including efficiency improvements, and the use of alternative and renewable energy 

sources. However, these other tools are not a substitute for baseload power generation, which 

comes primarily from fossil fuels. All GHG emission reduction options will need to be pursued 

Edison Electric Institute, DiJfermr Regions of the Countty Rely on Ugerent Fuel Mircs (April 2008), 

http://www.eei.com 
to meet proposed emission reduction targets. The CCS Alliance urges that EPA, and those 

concerned with the Proposed Rule, consider the importance of CCS in the context of climate risk 

mi tigation. 

The U.S. population is expected to grow by 60 million by 2030. During that time, 

electricity demand is projected to increase by approximately 30 percent.5 Without rapid 

deployment of technologies that have begun to show promise, such as CCS, it will not be 

possible to meet the GHG emission reduction goals being discussed by IPCC and others now for 

attainment by mid-century. While the thrust of this rulemaking is to protect and preserve 

USDWs, such environmental objectives should neither be viewed in isolation nor divorced from 

other environmental and policy considerations - including energy security, economic stability 

and trade considerations. A rational, comprehensive approach to the management of C02 

emissions from GHG-emitting facilities must be undertaken if we are to simultaneously preserve 

economic stability, ensure returns on invested capital, enhance U.S. energy security, and mitigate 

the predicted effects of climate change. 

111. SUMMARY OF SUGGESTED PRINCIPLES FOR A CCS POLICY STRUCTURE 

The CCS Alliance supports a CCS policy structure with the following elements. While 

we recognize that some of these elements are beyond the purview of a UIC rule, we provide 

them for consideration. 

5 Energy Information Administration, Annual Energy Outlook 2008 (June 2008), 

http://www.eia.doe.gov/oiaf/aeo/electricity,html; U.S. Census Bureau, Projections of the Population by Age and .5~t 

for the United States: 2010 to 2050 (Aug. 2008), 

http://www.census.gov/population/www/p~/np2008-12.xls. 
Promote CCS Development 

A CCS policy regime should be designed to encourage CCS, in addition to serving other 

public goals -- such as promotion of energy security, economic stability. and protection of 

USDWs, human health and the environment. 

Sound Risk Management 

Federal and state policy should encourage owners, operators, technology companies, 

engineering firms, utility regulators, and others involved in the CCS chain to take appropriate 

action to ensure safe and reliable operation of GS sites and systems, minimize risks, and allow 

CCS to earn broad public acceptance. 

Single, Clear Liabiliv Structure 

To the extent possible, policymakers should put in place a single, clear liability regime 

for CCS activities. In the context of this rule, EPA has considered the possibility of cleanup 

liability both under the Comprehensive Environmental Response, Compensation, and Liability 

Act ("CERCLA" or "Superfund") and the Resource Conservation and Recovery Act ("RCRA), 

in addition to the UIC program. There is also the possibility of liability under state statutes and 

common law. Parties who may be injured in the future must be able to resort to a fair liability 

scheme, but potential applicability of multiple schemes is likely to discourage CCS development. 

Single, Clear Regulatory Structure 

There should be a single, clear regulatory structure applicable to CCS rather than 

multiple, ill-suited regulatory and liability statutes and regulations that likely will discourage 

CCS To that end, the CCS Alliance believes that a beneficial approach would be to enact a1 the 

federal level a new regulatory structure specific to CCS. 
Site-Specific Approach 

Policy regarding GS siting should reflect that conditions affecting risk differ by site and 

should be tailored to risks presented by specific sites. For example, C02 has been injected 

underground for several decades for EOR. This technique is well developed and there is now a 

history through which its risks can be assessed. This differs from injection for long-term storage 

in deep saline formations or unmineable coal seams, with which there is limited experience, 

particularly on the massive scale -- a million or more tons per year per site -- envisioned for the 

future. Policy must encourage development of new data, technology, and practices while 

recognizing that existing technology is readily applicable. It also should reflect that some longterm injection practices such as natural gas storage and EOR already are known to pose little 

risk. Sites also will differ based on reservoir and confinement geological details, proximity to 

USDWs and other resources, and other factors. In addition, it is not necessarily the case that 

injection always should have to occur beneath the lower most water source with a confining 

system in place as suggested by EPA. This should be determined on a case-by-case basis. 

Liability and Size Cave Responsibility Cannot be Unlimited 

Site responsibility and liability of owners and operators should be designed to account 

not only for protection of the public, but recognizing that private parties cannot assume openended or unlimited risks. This includes site owners and operators, others involved in the CCS 

chain, and offerors of risk management products. There is not now, nor is there likely to be, a 

private market through which risks can be managed far beyond a reasonable post-operation site 

care period. In recognition of the market's limits, the duration and amount of site responsibility 

must be limited. 
As a point of clarification, we use the following terms to denote different periods in the 

CCS chain: 

Operation is intended to mean the period during which C02 is injected at 

the injection site. 

Pust-upemtion site care period or closure period is intended to mean the 

period of years after operation during which the owner or operator is 

required to meet State or EPA site care responsibilities. 

Post-closure period is intended to mean the period after State or EPA site 

care responsibilities end. 

Allow u Broad Array of Financial Assurance Mechanisms 

Government policy should allow a broad array of mechanisms, including trust funds, 

especially since the market is likely to be limited for risk management mechanisms for CCS. We 

provide suggested principles for financial assurance below. 

Government Backstop Role 

The government will need to step in beyond an owner and operator liability limit, as has 

been the case in many other areas in which the government has sought to encourage private 

action to achieve a public good. The private sector's capacity to manage risks is substantial, but 

not unlimited in either aggregate capital capacity or tenor and term. Government will need to 

accept responsibility beyond what the private market can manage. Because the goal in most 

cases will be long-term storage of C02, long beyond the typical lifespan of private entities, 

government should assume liability after injection operations cease and a reasonable closure 

period has elapsed. 
State and Federal Regulatory Responsibility 

State oil and gas commissions are repositories of expertise in regulating oil and gas 

industry underground injections, which have been safely undertaken for many decades. These 

commissions also have regulated COz injections for enhanced oil and gas recovery, a practice 

that has been in use for 40 years. However, not all states have oil and gas regulatory experience. 

In states that do not have experience regulating oil and gas injections, EPA and the state should 

ensure the application of reasonable regulation that protects public health and the environment 

without discouraging CCS development and deployment. 

IV. THE PROPOSED RULE: ASPECTS THE CCS ALLIANCE SUPPORTS 

From the point of view of the CCS Alliance, the Proposed Rule has a number of positive 

aspects. 

A. RECOGNITION OF THE IMPORTANCE OF SPURRING THE DEVELOPMENT OF CCS 

TECHNOLOGY 

The Proposed Rule recognizes the value of promoting CCS technology. With further 

modification and a broader scope, these regulations could encourage substantially the safe 

deployment of CCS technologies, support the construction of new fossil fuel-fired generation, 

promote capital formation, and broaden the availability of risk management mechanisms for 

CCS projects. The costs and benefits associated with protecting USDWs must be the focus of 

the Proposed Rule, but account has to be taken of the reality that such protection is inextricably 

linked to the mitigation of climate change risk. 

B. SDWA AUTHORITY IS LIMITED 

The CCS Alliance agrees with EPA7s view of its authority under the SDWA as limited to 

preventing endangerment of USDWs by the underground injection of COz. The Agency 

properly notes that regulating surface water and atmospheric releases is outside the scope of this 
proposal and SDWA authority. Though EPA regulates both pollutants and commodities under 

the UIC provisions, it is clear that the proposal does not address the status of COz whether as a 

pollutant or commodity. 

C. VIEW OF GS RISKS AND HAZARDS 

The CCS Alliance concurs with the Agency's identification of the risks and hazards, to 

the extent these are understood and can be reasonably predicted, that likely are posed by 

underground injection. The U.S. oil and gas industry, as EPA has pointed out. has had decades 

of experience drilling through highly pressurized formations and injecting significant amounts of 

COz for purposes of enhanced recovery. The Agency rightly notes that C02 has been 

successfully injected on much larger scale at several sites outside the United States. However, 

broad scale, large CCS injections pose new considerations, and CCS requires site-specific 

review. 

D. WELL CLASS APPROACH 

The creation of a new class of wells (Class VI) to cover underground injection of C02 

outside the context of EOR (existing Class I1 or Class V wells already permitted are properly left 

outside the scope of the Class VI proposal) is a reasonable approach due to the unique features of 

CCS, including the low viscosity of supercritical C02, its high buoyancy, and injection volumes 

that could dwarf those of other well classes. There is important recognition that such an 

approach should not impede the development of CCS technology but should "support the 

development of a key climate change" risk "mitigation technology"."he CCS Alliance agrees 

that where there is an EOR component in a project, that project should continue to be permitted 

and regulated under the Class I1 program. It is also positive that EPA is proposing that Directors 

6 Proposed Rule, 73 Fed. Reg. at p. 43,495. 
have authority to grandfather certain requirements for Class V experimental project wells and 

other wells (Class 11) when they are converted to full scale Class VI wells. The Alliance 

suggests that EPA should consider whether grandfathering the existing siting, AoR, operations, 

and monitoring plans for Class I1 and Class V wells when they are converted to full scale Class 

VI wells would protect USDWs while avoiding additional regulatory burden. 

E. REASONABLE LIMITS ON POST-CLOSURE CARE AND ASSURANCES AGAINST 

LEAKAGE 

The notion of owners and operators being responsible in perpetuity should continue to be 

avoided. Washington State has instituted the requirement that there be a "high degree of 

confidence that substantially 99 percent of the GHGs will remain contained for at least one 

thousand years."7 Such a standard would be inappropriate for C02 injection wells, and is not 

related to effects on human health or the environment from a potential leak. The CCS Alliance is 

encouraged by EPA's apparent focus on a workable approach to such matters as casing and 

cement quality, and on instituting a monitoring, mitigation and validation program that provides 

assurance of safe, long-term storage, in conjunction w~th setting a defined financial responsibility 

period that enables financing and risk management of CCS. Ultimately, needs associated with 

risk management of emissions to the atmosphere must be balanced against needs to manage risk 

to the water supply, as well as other public policy issues mentioned above. This points to why 

the Alliance suggests an iutegrated policy management approach to CCS technology. 

V. THE PROPOSED RULE: ASPECTS OF CONCERN TO THE CCS ALLIANCE 

A. FIFTY YEAR TIME FRAME FOR POST-CLOSURE SITE CARE RESPONSIBILITY 

The Proposed Rule states that the timeframe over which C02 will be trapped depends on 

the properties of the receiving formation and the injected C02 stream. Currently available 

WASH. ADMIN. CODE 173-407-1 10 (2008) (se~ definition of "Permanent Sequestration") 
information does not provide a complete understanding of the time required to stabilize 

geologically sequestered C02 under various conditions: however, some experience does exist 

and has led some to develop extrapolative estimates for related geologies. Some believe that 

significant number of cases, a 10 to 30 year timeframe will be sufficient to determine that the 

remaining pressure in plugged wells will not lift fluid to overlying strata. Any uncertainty in 

characterizing post-injection site care timeframes for GS, while challenging, could be dealt with 

through a maximum time period, performance standards, and Director discretion. 

The CCS Alliance recommends establishing a maximum 30-year post-operation site care 

and financial responsibility period. The Director would have discretion to shorten -- but not to 

lengthen -- this period if the owner or operator meets certain enumerated performance standards 

based on available data on pressure. fluid movement, mineralization andlor dissolution reactions 

to show whether movement of the plume and pressure front have ceased. Once the thirty-year 

period is reached -- or shorter if the performance standards are met -- a government backstop 

would be triggered, thereby ensuring that a risk management mechanism is in place beyond the 

responsibility of the owner or operator. Investment requires assumptions about the amount of 

capital required and for how long it is required. If either the maximum amount of capital or the 

term cannot be established, investment is deterred. Further, because most capital available will 

not commit for terms longer than thirty years, and the duration for which it is available is 

generally inversely proportional to risk. Thus, long term capital for even low frequency but high 

severity risks is difficult to obtain. To assure public funds can be leveraged with private 

investment to assure widespread deployment of this climate risk mitigating technology, a balance 

of risk and reward is required in the policy development that underpins this UIC regulation. 
B. POTEKTIAL APPLICABILITY OF RCRA AND CERCLA 

As discussed in greater detail below, the potential applicability of RCRA and CERCLA is 

a key concern. These statutes simply arc not designed with the thought in mind of encouraging 

the safe and widespread deployment of a new technology. The CCS Alliance believes that many 

parties involved in the CCS chain of events should bear responsibility for safe operation. Rather 

than apply environmental statutes with contentious and litigious histories, Congress should enact 

a new regulatory and liability framework for CCS in place of the multiple regimes that now may 

apply. This is not meant to detract from the progress EPA is making in this rulemaking. It 

merely recognizes the limitations and overlapping structures EPA itself has noted. CCS should 

be subject to a single, clear regulatory structure, and a single, clear liability structure. In the 

meantime, EPA should use what interpretive authority it has to limit the applicability of multiplc 

statutes and provisions, the applicability of which would discourage CCS. 

C. GUIDANCE FOR EPA REGIONAL ADMINISTRATORS AND STATE OFFICIALS 

Broad responsibility and decision making authority is centered in the EPA Regional 

Administrators (for UIC programs administered by EPA) and in non-EPA officials (responsible 

for permitting, implementation and compliance of state, territorial or tribal UIC programs). 

However, no guidance is provided as to how these individuals are to exercise such wide 

discretion. They will havc the authority to determine whether large pilot projects should be 

considered Class V (experimental) or Class VI wells, but on what basis such a decision is to be 

made is not clear. In accordance with OMB's Final Bulletin for Agency Good Guidance 

~ractices,~ EPA should consider developing additional guidelines that limit the ability of mid8 Final Bulletinfor Agency Good Gltidunce Prucfices, 72 Fed. Reg. 3432 (Jan. 25, 2007). 
level officials to implement and alter the program without review by the EPA Administrator or 

other organs of the U.S. Government. 

D. INSUFFICIENT RECOGNITION OF LIKELIHOOD OF TECHNICAL ADVANCES 

C02 injection has been successfully utilized in the EOR process for decades. As such, 

even though CCS technology has not been widely deployed, the technology and industry 

knowledge are nevertheless presently sufficient to commence CCS activities. However, 

significant advances in technology and understanding are likely to be made in the future. The 

Proposed Rule fails to fully recognize or otherwise take into account that technology and the 

state of knowledge almost certainly will improve and continue to evolve. EPA, therefore, should 

better reflect that as technology and understanding improves, the risks associated with CCS will 

be reduced and the ability to mitigate remaining risks will be improved. 

E. SECONDARY CONTAINMENT SHOULD NOT BE REQUIRED 

Secondary containment (i.e., a second formation of "caprock" above the initial formation) 

should not be required because it could limit the eligibility of potential storage sites, raise costs 

due to extra transportation, and add to the considerable regulatory burden of regulating site 

characterization. The standards of the Safe Drinking Water Act require that any injection that 

does occur will not result in endangerment of USDWs. This should be sufficient, without 

imposing in addition an arbitrary additional standard. 

F. GEOLOGIC SEQUESTRATION OF CO;! NEED NOT BE, IN EVERY INSTAKCE, 

BENEATH THE LOWERMOST FORMATION CONTAINING A USDW 

Geologic sequestration of C02 need not be, in every instance, beneath the lowermost 

formation containing a USDW, as is the case with Class I wells. Such a requirement likely 

would preclude injection into certain targeted geologic formations, which may include storage 

sites currently under consideration for GS. The Director should be given discretion, but to act in 
accordance with guidelines, to allow injection above or between USDWs in specific geological 

settings where the depth of the USDW would preclude GS and where there are thousands (or 

only hundreds) of feet of rock strata between the injection zone and the underlying or overlying 

USDW. This could in many instances open up more areas for CO;! slorage without endangering 

USDWs. 

G. VAGUE LANGUAGE AND DEFINITIONAL PROBLEMS 

There are many words and phrases in the draft regulations that are not well defined, and 

the meaning of which ought to be expanded upon. For instance, what might constitute 

"significant leakage" in the context of mechanical integrity testing should be identified. 

H. NON-COMPLIANCE 

If a site is not in compliance, there should be no requirement that injection cease 

immediately, unless an imminent threat of harm to human health or the environment is posed. 

VI. SPECIAL FOCUS: FINANCIAL ASSURANCE AND LONG TERM SITE 

RESPONSIBILITY 

Financial assurance and long-term site responsibility are an area of special focus for the 

CCS Alliance. As noted above. we believe the proposed 50-year time frame for site care 

responsibility after a GS facility has ceased operation is too long, and there should be a known 

end point fur site care responsibility up front. In addition to these concerns, we offer the 

following comments on financial assurance. 

A. THE PURPOSE OF FINANCIAL ASSURANCE 

EPA's Geologic Sequestration Stewardship paper, released in conjunction with the 

Proposed Rule in July, states that the purpose of financial assurance is "to minimize the number 
of facilities that are orphaned and abandoned; thereby, reducing the potential that these costs will 

be borne by the public."9 

This goal must be considered in the context of the facts surrounding CCS. It is an 

activity the government wants to encourage, the risks attendant to which may be significant if 

they occur but likely are of low probability, and for which the private risk management market 

will not cover the full amount or duration of the risks. To fail to implement CCS at this juncture, 

is not an option if we are to serve other public priorities, such as addressing climate change and 

energy security, which depends in part on utilizing domestic resources like coal. For CCS to 

occur on a broad-scale basis, "costs," in the form of long-term risk, will have to be borne by the 

public. A question is how to define and shape the public role. 

Insuring or otherwise rnannging risk at a complex industrial facility requires specialty risk 

products, not ordinary property and casualty coverage.10 In the broader environmental risk 

insurance market, only four or five insurers offer products. In the energy market, the number is 

roughly the same. Private risk managers must have experts in place with appropriate perspective 

to analyze the risks and calculate probabilities of the activity. Few risk management entities 

likely will develop this capability for CCS. Each may be willing to take a portion of the risk 

with respect to an individual project. However, consider that today there are 1,493 coal-fired 

5, U.S. ENVIRONMENTAL PROTECTION AGEKCY, Approaches to Geologic Sequestration Site Stewardship 

Afler Site Closure, n.2 (July 2008). 

10 Chiara Trabucchi and Lindene Patton, Storing Carbon: Options,for Liability Risk hfmagement, 

Financicrl Re.rpon.sibili~, BNA Daily Environment Report at p. 9 (Sept. 3, 2008). "Because CCS is what the 

financial services sector would call a specialty risk. only a small part of the sector would be equipped and qualified 

to analyze the risks and place capital thereon." 
electric generating units in the United states. ' This suggests a large potential need for risk 

management mechanisms. 

Forecasting for CCS can be difficult because there is no established track record in some 

formations where GS is envisioned to occur, such as deep saline aquifers, or on the scale 

envisioned for facilities generating electricity. Each risk management company will have 

differing conditions under which it will or will not accept risk. These might be based on factors 

such as geography, due diligence in siting, formation pressure and chemistry, type of geologic 

formation, proximity to population, and the applicable legal and liability regimes. These factors 

are not yet actual factors, as CCS as envisioned by policymakers has yet to emerge, but are based 

on the considerations in other fields. 

Companies may further specialize in the layer of risk they are willing to accept. For 

example, one risk management company may be comfortable writing coverage for the initial 

tranche of risk - perhaps the first $30 mdlion in potential damages, above the first $10 million, 

which it may require that the policyholder bear. Another may be willing trl write coverage for 

the next $30 million, liability for which would only arise if damages were beyond the $40 

million borne by the policy holder and the first insurer. Others may not be willing to provide 

coverage until after the first $100 million or more in risk is covered. A small pool of reinsurers 

may be willing to help further spread some of these risks. 

In considering financial assurance requirements, EPA and stakeholders should distinguish 

financial assurance from liability. Regardless of the length of time EPA establishes in the final 

rule for a GS facility owner or operator to maintain financial instruments to pay to clean up 

potential USDW contamination, liability for such cleanup may last longer, depending on which 

I I Energy Information Admmstration. Electric Power Annual, Existing Capaci~ by Energy Source, Table 

2-2 (Oct. 22, 2007). 
statutory provisions are applicable, as well as state law. While EPA is limited in its ability to 

address potential liability, it should seek to do so, as findings of the Risk Study conducted by the 

CCS Alliance (discussed below) show that potential long-term liability is a significant barrier to 

CCS development. 

Risk managers - insurers, sureties, banks, and others - will determine whether to provide 

financial assurance based on a calculation of the severity of risks and probability that they will 

occur over a given time period and the terms and conditions of the obligation. 

The severity and probability of risk is defined not just by physical dimensions, such as 

fractures and leaks, but by the regulatory and liability structure that is in place. A party may be 

in violation of a rule or may trigger large potential liability, notwithstanding that the risk to 

USDWs or human health or the environment may be minimal. 

One may look at the risks of a CCS project in two ways: by the activity being performed 

in the CCS chain (i.e.. generation, compression, transportation, injection, long-term storage), or 

by the phase of the project (i.e., operation, closure, post-closure). The CCS activity being 

performed, as well as other site-specific conditions, will affect the availability of risk 

management products: 

In the context of CCS, different risks are likely to present 

themselves at different stages during the facility's life-cycle. 

resulting in a range of consequences the financial materiality of 

which will depend on the site-specific characteristics and location 

of each CCS project. For these reasons, different phases of the 

CCS process wilI warrant different financial (risk) management 

mechanisms." 

'' Chiara Trabucchi and Lindene Patton, Storing Carbon: Options for Liability Risk kfanugement, 

Financial Responsibility, BNA Daily Environment Report at p. -3 (Sept. 3,2008). 
Some risks will be more easily addressed by the market than others. Risks in the 

generation and carbon capture phase are manageable under standard mechanisms such as bonds 

and insurance, or are retained by the operator. The same is true for risks during the 

transportation phase.I3 However, the long-term storage phase presents a set of risks the duration 

of which is beyond the scope of the market. The market will not take on liabilities beyond a 

defined amount for a defined period. Granger Morgan of Carnegie Mellon University's CCS 

Regulatory Project said, "[tlhey don't know how to write a policy that goes on f~rever."'~ It is 

not a matter of knowing how - it is a matter of not being willing to provide risk management for 

such duration. 

Underwriters look to ;I variety of factors in determining whether to offer a risk 

management product, what its features and conditions will be, and how to price it: 

An underwriter will look to the fundamentals of the technology 

itself when undertaking risk analysis. Technical specialists are 

assigned (such as engineers, geologists, chemists or the like) to 

develop an understanding of the technology's functionality and its 

potential failure points. The underwriter will ask for testing and 

performance data, including the conditions of performance - 

especially scale. In the area of technology, scalability presents 

substantial risk for many reasons, including - but not limited to - 

basic theory extensions, specific chemical or physical behavioral 

changes associated with volume or environmental factors (such as 

temperature or humidity) and supply-chain risks, to name a few.I5 

Many of these issues are key considerations in evaluating CCS risks. As noted above, few risk 

management companies may undertake to develop this information. 

14 Evan Lehmann, Wanted: 1,000 Year Insurance Policy, Climatewire, Aug. 19, 2008, 

http:llwww.eenews.net/climatewire/2008/O8ll9ll/. 

15 Lindene Patton, Beyond Rising Sea Levels, T H E EUROPEAN BUSINESS REVIEW (Mar.1Apr. 2008). 
C. WHAT MARKET PARTICIPANTS SAY ABOUT RISK 

The framework for approaching the commercial risk in the development and deployment 

of coal-based projects with CCS is demonstrated by the following chart: 

FarDlmlQmtp 

Approach to Commercial Risk Framework 

Energy Risk Analysis 

Develo~rnent Develo~ment 

Evaluation, 

Application 

of Risk 

Mitigation 

Mechanisms 

Coal prolecis wlth CCS cannot , Technical and operating risks 

complete financing without a 

comprehensive cornrnerc~al risk 

analysis by creditors, tmically in a 

prolect finance framework. 

Deployment = project finance possible 

Source. 

Scuily 

Capital 

Repayment 

and profit 

Design & Engineering & Operations & 

Development Construction Maintenance 

The CCS Alliance has evaluated technical, market, and policy risks associated with CCS 

deployment. On behalf ol' the CCS Alliance, Andrew Paterson of Econergy International 

interviewed dozens of market participants earlier this year, including project developers, utilities, 

technology vendors, risk managers, and financial providers to assess which risks were considered 

most likely to occur, and which, if they occurred, would be considered to have the greatest 

impact to the project. 

The results can be viewed graphically in a Cartesian coordinate analysis, as follows: 
Which Risks Matter? Which Will the Market Handle? 

Probability vs. lmpact 

Lower Likelihood 

Higher lmpact 

Accidents 

(Plant fires, or spikes in feedstock 

costs or a gas price slump with 

loss of competitiveness) 

Low Likelihood 

Low lmpact 

High Likelihood 

High lmpact 

Risks likely need to 

be shared between 

public and private 

(e.g., high capital costs with CCS, or 

lack of clarity about carbon regs) 

Higher Likelihood 

Lower lmpact 

Marketing and 

Operations 

(Workforce issues, coal transport, 

transmission congestion, etc.) 

Externalities 

(e.g., pollution) 

Or lax enforcement, lack of standards 

The CCS Alliance analysis confirms that market participants concur with the view of the 

Intergovernmental Panel on Climate Change ("IPCC") that physical risks such as an operating 

accident or geologic sequestration site failure are low probability, high impact ri~ks.'~ However. 

they view as higher probability the risk of policy failure. 

In the CCS Alliance Risk Study, the highest rated risks for companies and investors 

considering investment in projects with CCS were focused on: 

Higher capital costs for capture, compression, transport, injection and storage. 

l6 IPCC, Special Reporf on Carbon Dioxide Capture and Storage (2005). IPCC report states that there is 

only a one percent chance that C02 would escape into the atmosphere in 100 years. 
Uncertainty about the extent and timing of legislation and regulations for carbon emission 

constraints - in other words, a regulatory basis for pursuing CCS at all. 

Unclear rules at the federal and state level for CCS injection (which the UIC Proposed 

Rule is seeking to address), creating some uncertainty about specific liabilities. 

Lack of clarity about long-term ultimate liability for C02 leakage after injection and 

storage for some commercially relevant time period (e.g., 10 to 30 years). The Proposed 

Rule also seeks to address this issue. 

Electricity (or fuel) prices - in the regional market or set by state utility commissions - 

which are too low to cover costs for CCS. 

Some mechanisms, as either subsidies or for risk transfer, exist to address these issues, 

but as depicted in the table below, they are concentrated in the area of either reducing capital 

costs and other CCS related expenses, or in dealing with electricity rates and adjusting revenues 

in some manner. Subsidies to cover higher costs include: federal grants for new facilities, tax 

credits, and state grants. Other mechanisms, such as a federal loan guarantee (Section 1703 of 

EPAct 2005) or rate-basing a plant with CCS, remove substantial risk for capital recovery by 

providing alternative recovery or prevention of default. 
Uncertainty on -pr- Lack of clarity on (or rates set) 

High Capital Carbon Emission Unclear rules on lona-term CCS too low for 

Federal Federal grants (DOE) 

Federal Investment tax credits (capital subsidy) 

Federal Unit tax credits (operating subsidy) 

State State grants (e.g., for engineering) 

6) Risk Assumption/ Transfer 

Federal Federal Loan Guarantee 

State Rate-basing or Dispatch Preference 

Industry Stockpiles; Backup supplies or systems 

State Additional collateral or Revolving funds 

Federal Carbon allowurn (traded with cap) 

6) Risk Assumphan / Transfer 

Federal Clear regulations on carbon emissions 

State Clear ~les on CCS and LT Liabilay 

Because substantial exposure to some critical risks remains, additional mechanisms and 

regulatory clarification are needed to garner the scale of investment and capital recovery needed 

for commercial entities to deploy major facilities with CCS. As summarized in the table above, 

clarifying injection and transport rules clearly help, and can be coordinated with private 

insurance, trust funds or bonding, and state revolving funds. Additionally, some clarity on 

carbon emission rewlations would eventually enhance the value of assets with CCS, and help 

attract capital for construction in the first place. Without capital investment, no CCS will be 

implemented because it is an inherently capital-intensive activity primarily involving facilities 

costing more than $1 billion. 

But, there is no private instrument that can bear "indefinite, long-term liability" for 

leakage from CCS sites because commercial enterprise carries a finite horizon for investment. 

The EPA UIC program does wield a regulatory incentive, though, in negotiating or retaining 

some flexibility on the point (e.g., 10 years versus 50 years) at which liability for long-term 

leakage is assumed by the federal holder after injection. 
Results of the CCS Alliance Risk Study are summarized in the following chart. Note that 

in addition to the concern noted earlier about state CCS regulations and liability policies, one of 

the issues scoring the highest risk factor is that EPA regulations on underground injection of COs 

and liability fail to offer clarity for financing. Lack of clarity could prove to be a "showstopper." 

EPA should do its utmost to use its statutory authority to reduce this risk through this 

rulemaking. 

I Far Deplovment of Coal-based Proiects with CCS 

Risk Study: Technical, Policy, Market Risks 

30 Respondents 25 pim scale Rdad 

High 

High 

From interviews of key 

actors (owners, builders, 

financial entities, 

agencies, states) critical 

risks in three major areas 

are evaluated in a project 

finance credit analysis 

framework. Risks are 

rated (1 lo 5) for 

"likelihoad" and "impact" 

if a risk event occurs. 

The product (25 point 

scale) provides a 

"severity" of risk for 

specific events affecting 

deployment with CCS. 

This information is buttressed by the recently published findings of the Government 

Accountability Office ("GAO") which, in part, concludes that regulatory and legal uncertainties, 
including questions about liability concerning C02 leakage and ownership, are primary barriers 

to CCS deployment.17 

D. PRINCIPLES FOR A RISK MANAGEMENT REGIME FOR CCS 

Recognizing that it must act within the confines of its authority under the SDWA, and 

with the goal in mind of protecting USDWs, EPA should consider the following principles in 

constructing a financial assurance program. 

One means of encouraging adequate financial assurance is for regulators to (1) require 

site operators to provide accurate, comprehensive and current information on costs for closure, 

post-closure and corrective action activities; and (2) ensure that stakeholders have the means to 

verify those estimates. Moreover, the Alliance seeks to remind EPA that no type of financial 

assurance instrument can meet regulatory demands for an unrealistically long coverage time 

period that extends beyond the willingness of capital markets to accept covered risks for such 

periods. With these concepts in mind, regulations can be developed to ensure that funds will be 

readily available, and in the amount necessary, to cover costs associated with environmental 

obligations in thc event that owner/operators of underground injection sites are unable to meet 

their financial responsibilities. 

1. Clear, Reasonable, and Limited Regulatory and Liability Structure 

EPA should use its discretion, to the extent practicable, to establish a single, clear, and 

reasonable regulatory structure. CCS developers will be willing to abide by reasonable rules that 

protect human health and the environment, but society should not bear enhanced costs resulting 

from requirements that do not contribute to health and environmental protection. Nor do 

developers and risk managers want to face liability via multiple State and federal statutory and 

" GOVERNMENT ACCOUNTABILITY OFFICE. GAO-OX- 1080, CLIMATE CHAKGE: FEDERAL. ACTIONS WILL 

GREATLY AFFECT THE VIABILITY OFCARBON CAPTURE AND STORAGE AS A KEY MIT~GATION OPTION (2008). 
common law pathways, with the possibility of unnecessarily expensive and contentious 

remedies. EPA should use its discretion, to the extent practicable, to provide a single, clear, 

reasonable liability reglme. As these goals likely will require some legislative action, EPA also 

should educate Congress on the need for regulatory and liability regimes with these 

characteristics. 

2. Allow a Broad Array of Financial Assurance Instruments 

Since private market financial assurance may be scarce for some CCS phases, EPA 

should be flexible in the type of financial assurance instruments it authorizes and needs to 

encourage the development of financial assurance offerings for CCS. 

The Proposed Rule discusses four financial assurance/risk management instruments and 

requests comment on others. 

Generally, the CCS Alliance believes policy should foster a broad array of means 

whereby a regulated entity can satisfy financial assurance. Both regulators and site 

owner/operators will benefit from broad availability of an innovation in offering different types 

of financial assurance instruments. Increased competition may reduce the cost of obtaining these 

assurances as much as market conditions will permit. Each instrument has specific 

characteristics and may play a different role in addressing CCS risks. It should be noted that in 

difficult economic environments (e.g., contractions of available capital in the market), the capital 

markets may make less money available for new types of projects, especially if the risk profile is 

unclear, which could mean that arranging financial assurance for CCS may be difficult in the 

near term. 

One issue that applies to a variety of financial assurance instruments is the 

creditworthiness of the issuer. While EPA should seek satisfaction that the issuer is on sound 
financial footing, it should avoid unduly restrictive standards, or standards beyond the control of 

the issuer. For example, Bureau of Land Management regulations require that insurance 

providers offering financial assurance "must have an A.M. Best rating of 'superior' or an 

equivalent rating from a nationally recognized insurance rating ~ervice."'~ Such standards may 

dramatically contract the pool of available issuers, especially during difficult economic times. 

Creditworthiness standards should consider both ability to pay and the availability of costeffective financial assurance. 

a. Trust Funds 

The Alliance supports the concept of trust funds as reserves to address CCS liabilities for 

long-term stewardship. Properly structured, trust funds can be valuable tools in this area. 

A valuable feature of a trust fund is that a large reserve may be accumulated gradually. 

Costs can be spread over time. EPA has focused on the obverse of this issue - that in early years, 

a trust fund may not be sufficiently capitalized to address all the risks that may arise. EPA has 

proposed that trust funds have a three-year pay-in period. EPA should not impose such 

limitations, for two reasons. First, while it is possible that an incident may occur that would 

result in a demand on the fund in early years, many consider that risks are likely to be lower in 

the early phases of injection. Second, and more importantly, given that the private risk 

management market appears unlikely to be able to address all risks, EPA should encourage 

development of mechanisms that can address any portion of the risk. A three-year pay-in period 

arbitrarily restricts a potentially valuable tool with a heavy early payment burden. EPA should 

allow flexibility in trust fund arrangements, and can link the credit it gives to financial assurance 

through trust funds to the amount available in the fund. 

'$43 CFR 3809.555(f). 
Long-term, EPA and other policy makers should consider the possibility that too large an 

amount might be accumulated in trust funds, relative to the risks they are designed to cover. A 

recently released assessment of a $1 per ton tipping fee for CO;? sequestration, at levels required 

under WRE450 and WRE550 climate policies, would accumulate up to $1.5 trillion by the time 

the first 100 CCS facilities reach the end of their useful lives.l9 Such misplaced wealth storage is 

not economically sound. Furthermore, in light of the history of trust funds managed by the 

federal government, it would provide an unfortunate temptation for policy makers with other 

fiscal priorities. 

Observers have suggested fees to capitalize CCS trust funds with a number of different 

structures. The type of mechanism or amount of the fee should not be of concern to the EPA, but 

should be addressed by the policy makers establishing the trust. It may be that multiple trust 

funds could be applicable for portions of the risk associated with a CCS facility or facilities. 

Both private and government-run trust funds may arise. EPA should ensure sound 

management of trust funds, but does not need to limit parentage. Again, innovation should be 

and will need to be encouraged. The trusts could be privately administered in compliance with 

state insurance regulations; in this way, the state has final governance authority by charter status, 

while private industry can bring fiduciary and engineering analysis resources to bear which 

would be expensive for the states to match. 

Trust funds also could be structured to provide incentive for risk-mitigating behavior. As 

an example, their terms might be structured to limit eligibility to projects whose siting or 

operations meet superior standards. 

'"James J. Dooley. Chiara Trabucchi, and Lindene Patton, Tipping Fees Can't Save us fmm the Tipping 

Point: The Need to Create Rational Approaches to Risk Munagement that Motivure Geologic C02 Sforuge Best 

Pmctices. ScienceDirect, GHGT-9, November, 2008. 
Again, EPA should encourage development of trust funds, rather than artificially limit 

them. 

b. Insurance 

lnsurance should be authorized as a risk management tool for CCS. Insurance for CCS 

liability is a "specialty" product. Specialty underwriters generally are well-trained to focus on 

the environmental risks involved with each facility, and insurance provides full coverage for the 

financial assurance risk from pollcy inception forward. 

EPA appears to be approaching insurance guardedly, noting that the "insurance 

mechanism was and still is. rarely used for the purpose of demonstrating financial assurance for 

injection wells." EPA should provide guidance for the use of insurance. 

EPA should be careful to avoid several problems that have made insurance less available 

and more expensive in the past. For example, regulators typically require an insurance policy to 

be written to require payment to an entity designated by the regulator, rather than to the insured. 

The requirement to pay the regulator or a designated agency creates potential for "double 

payment" - both to the regulator, and as a result of state law, to the insured. EPA should address 

this problem by making possible clear designation of sole beneficiary status, and allowing parties 

to contract for express waivers by policyholders of their payment rights, where the regulator 

requires a different beneficiary. Another problem is that regulators often prohibit cancellation of 

a policy if an operating permit is revoked or if the operator seeks bankruptcy protection, even if 

continued premium payments do not occur. Such a prohibition drives up the cost of insurance, 

"front-loads'' insurance costs as insurers require up-front payments, and reduces insurers' 

willingness to offer policies. 
Since, as noted above, some risks associated with CCS will be beyond the market's 

willingness to bear, EPA should allow insurance to be arranged on terms that will encourage its 

availability. It should encourage the private risk management market to address as much risk as 

possible. 

c. Surety Bonds 

Bonds are a traditional financial assurance mechanism and have been widely used. They 

ensure the performance of the bond holder on behalf of a third party, such as the state or the 

federal government. 

Unfortunately, the surety market has contracted in other environmental areas."' Some of 

the conditions that led to the contraction elsewhere are relevant to CCS. For example, some 

agencies have focused on very long-term risks that might arise after site care responsibility has 

ended." The result can be bond amount increases by two orders of magnitude." Further 

exacerbating the problem, at least one court has found that EPA7s financial assurance 

requirements for bonds does not limit payment to the amount of the bond, should the bond issuer 

choose to perform the cleanup rather than pay the bond.23 Thus. for example, a bond issuer 

could pay $100 million for cleanup, even if the bond amount was $10 million. 

Surety industry representatives indicate that they are hesitant to underwrite any obligation 

that may extend even beyond five years. Presently, for example, surety bonds for mining-related 

obligations are virtually unavailable at any price. A 2002 National Mining Association report on 

") "Mining and the Vanishing Surety Bond Market," Lisa A. Kirschner and Edward B. Grandy, American 

Bar Association, Natural Resources & Environment, Winter 2003, Vol. 17, Number 3. 

" See, p.g., Mont. Code Ann. 382-4-338. 

'' Jim Carlton, "Mining Firms in U.S. Face Crisis Over Cleanups," Asian Wall Street Journal. July 34. 

2002. 

People ex uel. Ryan v. Enrtl. Waste Res. Inc., 782 N.E. 2d 29 1, 296 (Ill. App. 2003). 
surety bonds for mining operations noted "Five of the top 10 sureties in the 1990s have either 

merged or left the business. Others have announced their intent to withdraw, and several 

longstanding market participants have effectively withdrawn by curtailing their exposures so 

substantially.24 

As with other financial assurance mechanisms, EPA should take steps to encourage the 

availability of surety bonding. Such steps should include clarifying in EPA's financial assurance 

regulations for surety bonds the bonding period, and clarifying that sureties may offer pay or 

perform instruments that will remain subject to the bonding limit, even if the surety chooses the 

performance option. 

d. Corporate Financial Strength and Corporate Guarantees 

EPA proposes to authorize the use of corporate demonstration of financial strength and 

corporate guarantees as acceptable forms of financial assurance. In keeping with our 

recommendation that a broad array of financial assurance mechanisms be authorized, we support 

this proposal. 

e. Letters of Credit 

Letters of credit ("LoCs")are a standard form of financial assurance and should be 

authorized. 

A great advantage of LoCs in commercial practice is that as long as a LoC is valid, 

presentation of the proper documentation by the LoC beneficiary entitles it to payment. Their 

ease of use is a great benefit. 

24 Interim Report, National Mining Association Surety Bond Working Group, 2002, p. 4. 
However, LoCs can be expensive. Issuing banks may require a site owner or operator to 

provide secured collateral or deposits before agreeing to issue a LOC,?~ apossibility made all the 

more likely by the extended time window of liability in the environmental context (and in fact 

referred to by EPA in promulgating some of its FA regulations).26 Such a commitment of capital 

may be difficult in the context of an innovative project, such as a facility deploying CCS. EPA 

should take care not to assume heavy reliance on LoCs to meet financial assurance requirements, 

again pointing to the need to provide for a broad set of financial assurance instruments. 

Also, EPA should consider in its guidance for LoCs addressing the potential for 

differences in the coverage period detailed in the letter of credit and the letter's expiration date. 

LoCs ordinarily are issued for a short period, perhaps a year, with an annual renewal date. If the 

renewal merely extends the expiration date of the letter, giving additional time to present 

requests on the letter, without altering the period during which incidents covered by the letter 

would have to occur, gaps in coverage may arise. This issue could be addressed in guidance. 

3. A Government Backstop Is Necessary 

As the Proposed Rule states, EPA does not have the authority under the SDWA to 

establish a government backstop mechanism. Nevertheless, it is clear that such a mechanism is 

needed. A government backstop should be in place to the extent the private market is not. 

The CCS Alliance believes that the government will need to step in beyond an owner and 

operator liability limit, as has been the case in many other areas in which the government has 

sought to encourage private action to achieve a public good. The private sector's capacity to 

25 James William Boyd, "Financial Responsibility for Environmental Obligations: Are Bonding and 

Assurance Rules Fulfilling Their Promise?,' Resources for the Future Working Paper No. 01-42. August 2001, at 

24. 

26 See 53 Fed. Reg. 43,322, at 43$353, Oct. 26, 1988. 
manage risks may be substantial, but will have limits. Government will need to accept 

responsibility beyond what the prlvate market can manage, which is likely at a minimum to 

include the time after which operations cease and the project no longer produces revenues that 

would enable a private entity to cover liabilities. Because the goal in most cases is likely to be 

long-term storage of COz, long beyond the typical lifespan of private entities, government should 

be prepared to assume liability after injection operations cease and a 30-year or shorter (as 

described above) closure period has elapsed. 

4. Encourage Risk Management Through the Private Sector 

Notwithstanding that CCS will require some level of government risk management, 

particularly for long-term liability. EPA's financial assurance regime should encourage the role 

of private market risk management to be as large as possible. 

5. Encourage Economically Efficient Risk Management 

Financial assurance mechanisms should be cost effective. Factors in cost will include the 

risk estimate, the type of instrument, and the duration of the instrument. Each cost in the CCS 

chain will have an effect on whether CCS is deployed. The EPA should carefully consider the 

potential cost of financial assurance mechanisms when designing a Class VI financial assurance 

regime. 

VII. SPECIAL FOCUS: APPLICABILITY OF CERCLA 

The Proposed Rule raises the question whether the injected C02 stream2' will be 

considered a "hazardous substance" under CERCLA. 

The Proposed Rule states: 

27 The rule uses the terms "carbon dioxide stream" and "injectate" interchangeably. EPA's proposed 

definition of these terms includes C02 "plus incidental associated substances derived from the source materials and 

the capture process, and any substances added to the stream to enable or improve the injection process. This subpart 

does not apply to any carbon dioxide stream that meets the definition of a hazardous waste under 40 CFR Part 26 1 ." 
While C02 itself is not listed as a hazardous substance under CERCLA, the C02 

stream may contain other substances such as mercury that are hazardous 

substances or the constituents of the COz stream could react with groundwater to 

produce listed hazardous substances such as sulfuric acid. Thus, whether or not 

there is a "hazardous substance" that may result in CERCLA liability from a 

sequestration facility depends entirely on the make-up of the specific CO- 7 stream 

and of the environmental media (e.g., soil, groundwater) in which it is stored. 

A mechanism must be in place to address liability for releases from GS sites. However, 

Superfund has had a number of problems that EPA should carefully consider in the context of a 

regulatory regime the Agency hopes will encourage deployment of CCS. Cleanups sometimes 

have been delayed by decades, lawsuits can stretch for years and involve numerous parties, and 

cleanups have been far too costly. EPA should use its interpretive authority to limit the 

applicability of Superfund and respond to releases under other authorities. Ultimately, Congress 

should adopt a new response and liability system recognizing the policy goals, scale, and other 

special features of CCS that is unburdened by the problems of Superfund. 

A. RELEVANT PROBLEMS WITH SUPERFUND 

Superfund imposes a strict, joint, and several liability scheme upon facility owners and 

operators, parties who arrange for treatment, storage, transportation, or disposal of hazardous 

substances; and transporters of hazardous substances. This strict, joint, and several liability 

scheme, in conjunction with other features of Superfund, particularly what many consider to be 

inordinately high cleanup costs, frequently results in expensive and lengthy lawsuits and delayed 

cleanups. Superfund also has been criticized for remedies that are l'ar more aggressive than the 

risks warrant. 

B. 

EPA's authority to order cleanups under CERCLA is triggered whenever any "hazardous 

substance" is released or there is a substantial threat of such a release into the environment. The 
Agency is considering whether the injectate, substances mobilized as a result of injection, or 

substances formed by geochemical reactions between the injectate and underground materials 

will trigger the "hazardous substance" definition. 

While EPA correctly notes that C02 is not now a hazardous substance, that may not 

continue to be the case given Mussach~nsetts v. EPA.~"~ which the Supreme Court ruled that 

COz is a pollutant and directed the EPA to determine whether or how it should be regulated. 

Such a decision could affect whether COz is determined to be a hazardous substance under 

CERCLA. 

CERCLA defines a hazardous substance to include "any hazardous air pollutant listed 

under section 112 of the Clean Air Act . . . ."" C02 is not on this list at present. However, 

Section 1 12 authorizes EPA to add a compound to the list if the Agency finds that emissions of 

the compound "may reasonably be anticipated to cause adverse effects to human health or 

adverse environmental effe~ts."'~ Ifin response to Massachusetts v. EPA, EPA were to decide to 

regulate C02 under Section 1 12, releases of C02, even without the presence of or interaction 

with hazardous substances, would be subject to Superfund liability. 

EPA also notes that the presence of other materials or the injectate's reaction with other 

substances underground may result in it becoming a hazardous substance. These post-injection 

geochemical reactions are of significant concern because C02 injectate considered nonhazardous upon injection could, over time, react with underground materials, potentially creating 

a hazardous substance and triggering unintended and unanticipated Superfund applicability. 

'8 Massacl~usetts v. EPA, 549 U.S. 497 (2007). 

2"2 U.S.C. $ 9601. 

'O 42 U.S.C. $741 1. 
Triggering application of the "hazardous substance" definition under Superfund to CO2, either 

pre- or post-injection, will create concerns about liability that will not encourage CCS 

development and, as our research cited above suggests. likely will be an impediment to the 

investment and risk management needed for CCS projects. 

C. FEDERALLY PERMITTED RELEASE EXEMPTION 

Superfund liability does not apply to a "federally permitted release," pursuant to Section 

107(i).~' The Proposed Rule notes that parties may be able to avoid Superfund liability through 

this exception. However, this exception likely would not apply in cases where injectate 

accidentally has been released from a storage site. Both EPA" and the court^'^ have interpreted 

the federally permitted rdease exemption to apply to releases that are in compliance with a 

permit, but not to accidental releases. It potentially may not apply where injectate remains safely 

within a containment zone, but beyond the area for which a permit was granted. The EPA 

should consider the potential for triggering Superfund liability in determining how it writes 

permits, particularly in cases where the COz remains safely stored. 

" 42 U.S.C. # 9607. 

32 ~6 In most circumstances, releases resulting from accidents and maifunctions do not qualify for the 

federally permitted release exemption as defined in CERCLA section 10 1 (10)(H). Releases due to accidents and 

malfunctions, because they are by definition not anticipated, are difficult to subject to controls which limit or 

eliminate emissions. Congress did not intend to exempt unanticipated releases such as accidents and malfunctions 

from CERCLA section 103. An accidental release not in compliance with a permit would be subject to response 

costs and damages claims under Superfund in addition ot the provisions of the SDWA and state and common law.'' 

Guidance on the CERCLA Section I01 (lO)(H) Federally Permitted Release Definition for Certain Air Emissions, 67 

Fed. Reg. 18899, 18903 (Apr. 17,2002). 

33 See Ur~ired Stat~s v. Iron Mountain Mines. IIX, 812 F. Supp. 1528. 1540-41 (E.D. Cal. 1992) 

("Congress considered the interplay between FWPCA and CERCLA when it enacted the latter statute, but declined 

to exempt municipal sewer authorities from its broad reach . . FWPCA exemption extends to industrial discharges 

into POTWs, indicating that Congress specifically intended for CERCLA liability to reach releases from sewers or 

POTWs.") Reading Co, v. City ofPhiladelphia, 823 F. Supp. 1218, 1230-3 1 (E.D. Penn. 1993) (Toxic Substances 

Control Act (TSCA) compliance is insufficient to invoke the RCRA exemption under CERCLA); Westfarm 

Associates Ltci. Partrtership v. International Fubricare Inst., 1993 U.S. Dist. LEXIS 19952 (D.Md. 1993). See alro 

Idaho v. Bunker Hill Co., 635 F. Supp. 665, 673 (D. Idaho 1986); Reporting Exemptions for Federally Permitted 

Releases of Hazardous Substances, 53 Fed. Reg. 27,268-81 (proposed July 19, 1988) (to be codified at 40 C.F.R. $3 

117.12, 302.3,302.6, 355). 
If Superfund does not apply because of the exemption, remedies may be obtained under 

other law. CERCLA's federally permitted release exemption states that "recovery . . , for 

response costs . . . resulting from a federally permitted release shall be pursuant to existing law in 

lieu of [CERCLA] ."34 

D. POTENTIAL EFFECT OF SUPERFUND ON CCS DEPLOYMENT 

The CCS Alliance conducted a Risk Study earlier this year, surveying more than 30 

executives in companies involved with or considering CCS deployment.35 Thc purpose of the 

Risk Study was to identify policy, technical, and market risks that could pose barriers to 

proceeding with CCS projects. Respondents were asked to rate the likelihood of a policy, 

technical, or market factor occurring, as well as the severity of the impact to a CCS project if it 

did occur. The product of the likelihood and the severity of impact to the project for each 

surveyed issue generated a risk ranking. 

Three of the top eight concerns identified by respondents related to liability for CCS, 

including lack of clarity in the applicability of federal and state liability regimes. As the 

following chart demonstrates, particularly results for responses to questions 17,31, and 34. 

executives are very much concerned with the risks associated with the lack of clarity in state and 

federal rcgulations and liability regimes, as well as with liability over the long-term. 

" 42 U.S.C. rj 9607Cj) (2006). 

15 Risk Study for Commercicrl Deployment of CCS: Fcrctors Affecting Financingji~r Early Plants, CCS 

Alliance (July 2008). 
Moreover, a recent GAO report emphasizes the concern about liability: 

EPA's 2007 UIC workshop, attended by more than 200 stakeholders, revealed 

liability associated with unintended migration of injected COz to be a critical 

concern. Similarly, 19 of the 20 stakeholders we interviewed told us that liability 

related to C02 storage was a large or very large barrier to deployment of CCS at 

commercial scale, with some noting that liability concerns have already 

negat~vely impacted companies' ability to initiate CCS projects. For example. 

two stakeholders reported that these concerns have already made it difficult to 

obtain insurance for CCS proj ject~.~~ 

Although we currently are aware of no report specifically stating that liability under 

Superfund is the principal liability concern among CCS proponents, it clearly is a significant 

-- 

39.~. GAO, GAO-08- 1080. FEDERAL ACTIONS WlLL GREA I I Y A tWC' I THE VIABILITY OF CARBON 

CAPTURE AND STORAGE AS A KEY MITIGATION OPTION 25 (2008). 
issue that has been raised repeatedly, including through EPA advisory processes and the 

imposition of which would negatively affect future investment in CCS technologies.?" 

VIIL SPECIAI, FOCUS: APPLICABILITY OF RCRA 

The Proposed Rule raises the question whether injected C02 streams will be considered 

"hazardous waste" under RCRA. Rather than apply on top of the SDWA another environmental 

statute that was not designed with the thought of encouraging development and deployment of 

technology to address climate change, which is likely to discourage CCS deployment, CCS 

should be subject to a single. clear regulatory structure shaped by consideration of climate 

change objectives. Designating the C02 stream as a hazardous waste also will result in it being 

considered a "hazardous substance" under CERCLA, the problems with which are discussed 

above. 

The Proposed Rule states: 

Because the types of impurities and their concentrations in the C02 stream are 

likely to vary by facility, coal composition, plant operating conditions, and 

pollution removal technologies, EPA cannot make a categorical determination as 

to whether injected COz is hazardous under RCRA. Owners and operators will 

need to characterize their C02 stream as part of their permit application to 

determine if the injectate is considered hazardous as defined in 40 CFR Part 261. 

If the injectate is considered hazardous under RCRA, then the more stringent UIC 

Class I requirements for injection of hazardous waste apply.38 

Where EPA faces an interpretive question about the applicability of RCRA, it should avoid 

applying the statute. As noted above, the CCS Alliance believes that in place of existing, illsuited regulatory regimes, a new single, clear regulatory structure should apply to protect the 

environment. 

" EPA's Advanced Coal Technology Work Group Final Report recommends that EPA's UIC rulemaking 

proposal should "include a thorough discussion of. . liability implications under other statutes (CERCLA, RCRA, 

etc.) and potential linkages and impacts (or lack thereof) for CCS projects." U.S. ENVIRONMEKTAL PROTECTION 

AGENCY, FINAL REPORT: ADVANCED COAL TECHNOLOGY WORK GROUP REPORT 5 (Jan. 29,2008). 

38 Proposed Rule, 73 Fed Reg. 43503. 
A. BURDENS AND BARRIERS OF RCRA 

The UIC regulatory structure proposed by EPA to minimize releases not only protects 

groundwater, but by extension protects human health and the environment. RCRA's 

requirements are extensive, cxpcnsive, and ill-suited to activities to sequester large volumes of 

low-toxicity materials, especially when such activities will be regulated under the UIC program. 

EPA itself has acknowledged the burden of RCRA and the fact that many of its 

requirements are poorly suited to at least some of the activities to which they apply. EPA 

initiated a rulemaking in 2002 to reduce the burdens associated with the RCRA hazardous waste 

program.39 The Agency noted, "[tlhe existing hazardous waste regulations require the submittal 

of 334 notifications, reports, certifications, demonstrations, and plans from generators and 

TSDFs to demonstrate compliance with the RCRA regulations."40 Reporting requirements are 

just one example of RCRA's burdens. 

Given that CCS is a technology that the Agency and a broad array of others want to 

encourage, with this rule more than most others, EPA must consider very carefully whether the 

emission streams involved truly warrant hazardous waste regulation. Imposing extensive. 

burdensome RCRA regulations likely to have little benefit for human health and the environment 

may result in larger atmospheric releases of COZ if this "key" technology is not as widely 

deployed. 

Class I wells under the UIC program are intended, in part, to regulate hazardous waste 

disposal wells for the injection of hazardous waste, as defined by RCRA. If EPA were to 

39 Resource Conservation and Recovery Act Burden Reduction Initiative. 67 Fed. Reg. 25 18 (proposed Jan. 

17, 2002); see also RCRA Burden Initiative; Final Rule, 7 1 Fed. Reg. 16,862 (Apr. 4,2006). 

RCRA Burden Reduction Initiative: Notice of Data Availability, 68 Fed. Reg. 61,662, 61,644 (Oct. 29, 

2003). 
determine that CO;! is a hazardous waste under RCRA, C02 injection would be required to meet 

the more rigorous Class I well requirements, rather than the proposed Class V1 requirements. 

Indeed, the construction, permitting, operating, monitoring, and post-site closure requirements 

are much more burdensome for Class I hazardous wells than for the other types of injection 

wells. For instance, Class I wells have a requirement that there be no migration for 10,000 years. 

Such stl-ict requirements may be appropriate to protect USDWs and the environment from certain 

hazardous wastes, but such requirements were not established with COz injectate in mind. 

Furthermore, if a facility were required to obtain a Class I UIC hazardous waste injection 

permit, all other waste management units at the facility couId be subject to the full extent of 

RCRA's Subtitle C corrective action program, which is an extremely costly and administratively 

complex program. Determining that C02 constitutes A hazardous waste and subjecting COz 

injection and storage to the burdensome Class I well requirements would not promote 

underground injection and storage of C02. 

B. CONTINGENT MANAGEMENT 

Materials already subject to another regulatory regime that will ensure environmentally 

protective management of wastes can be excluded from RCRA regulation under "contingent 

management," a practice EPA has applied in other contexts. 

In this Proposed Rule, EPA is proposing a framework it believes is appropriate to ensure 

environmentally protective management of injected C02. The Agency makes clear that the 

extent of the UIC program limits the purpose of EPA's proposal to protection of USDWs; 

however, the Agency adds that it cons~del-s the risk of -'chronic and acute health effects from 
airborne exposure resulting from C02 injection activities (even in the case of leakage or 

accidental exposure) is rnir~ii~zal."~' 

EPA has applied the contingent management practice in case\ where potential 

mismanagement scenarios are addressed under other regulation. With respect to the Proposed 

Rule, EPA has proposed measures that would limit potential effects on human health and the 

environment by ensuring that the injectate should remain contained within the injection zone. 

The contingent management practice has been upheld, with the court holding that where other 

appropriate management programs are in place. hazardous waste classification and regulation are 

not required.42 

C. CONDITIONAL EXCLUSION 

If EPA considers that geologic sequestration of C02 constitutes waste disposal that 

cannot be subject to exclusion from RCRA regulation under a contingent management theory, it 

should establish a conditional exclusion from RCRA regulation for geologic sequestration of 

C02 injectate. 

IX. OTHER ISSUES: WELL PLUGGING, POST-IN JECTION SITE CARE, AND 

SITE CLOSURE REQUIREMENTS 

EPA's Proposed Rule would require owners and operators to develop a well plugging 

plan to be approved by the Director as part of each permit application. Such a plan would 

include: (I) a determination of bottom-hole reservoir pressure; (2) the identification of type and 

numbers of plugs to be used; (3) the placement of each plug; (4) testing methods to ensure 

mechanical integrity testing ("MIT"); (5) the method of plug placement; and (6) the type, grade 

4I Proposed Rule, 73 Fed. Reg. at pp. 43,497-98 (emphasis added). 

42 See. e.g., Military Toxics Puojecf v. EPA, 146 F. 36 948 (D.C. Cir. 1998). 
and quantity of material to be used in plugging. By not mandating specific typcs, materials, or 

testing methods, EPA is giving applicants broad flexibility to accommodate the varying types of 

GS projects contemplated by this rulemaking. The CCS Alliance agrees with this approach. 

Such flexibility also accounts for the fact that supercritical C02 has different properties than 

current injectants under the UIC program and, therefore. may require different plugging methods 

and materials. For instance, cement plugs can degrade over time from the build up of carbonic 

acid, which forms when C02 is injected in subsurface formations containing brine. However. 

well integrity should be considered the function of well materials collectively in maintaining a 

fluid barrier (as opposed to individual components susceptibility, particularly from laboratory 

tests). 

B. POST-INJECTION SITE CARE PLAN 

The Proposed Rule would require that owners or operators develop a post-injection site 

care and closure plan, submitted as part of the permit application and approved by the Director. 

The proposed regulation at 40 C.F.R. 9 146.93 would require the plan to describe: (1) the 

pressure differential between pre-injection and anticipated post-injection pressures in the 

injection zone; (2) predicted position of the plume and associated pressure front at the timc the 

site is closed; (3) post-injection monitoring location(s), methods, and proposed frequency of 

monitoring; and (4) a schedule for submitting post-injection site care and monitoring results to 

the Director. 

These requirements are reasonable given the long-term nature of GS projects. The CCS 

Alliance also supports the ability to amend the plan should the plan no longer reflect what is 

likely to occur upon closing the site. Likewise, the CCS Alliance agrees that, upon permanent 
cessation of injection, the owner or operator should be provided the opportunity to demonstrate 

that no amendment to the plan is necessary through monitoring and modeling results. 

C. POST-~JECTION SITE CARE PERIOD AND FINANCIAL RESPONSIBILITY 

The Agency has proposed a post-injection site care and financial responsibility period of 

50 years, which can be shortened or lengthened based on the discretion of the Director. The 

CCS Alliance agrees, in part, with this suggested use of a combination of a fixed timeframe and 

performance standard. However, as previously explained, the CCS Alliance recommends 

establishing a maximum 30-year post-closure per~od and providing the Director with discretion 

to shorten -- but not lengthen -- this period if the owner or operator meets certain enumerated 

performance standards based on avilable data on pressure, fluid movement. mineralization 

and/or dissolution reactions to show whether the plume and pressure front have stabilized. 

CCS is an activity the Agency hopes to encourage. A 50-year post-injection site care 

default is longer than any period of post-operation site care of which the Alliance is aware. The 

potential for threats to USDWs will have been considered prior to site operation. and will have 

been reconsidered throughout the life of the project, not only by the regulator, but by the owner 

or operator, entities providing financial support, and providers of risk management products and 

services. Continuance of injection will have depended upon an assessment of the potential for 

threats to USDWs at numerous points during the site's operation. 

EPA suggests that when owners or operators show that "models predicting C02 

movement are consistent with monitoring results and that there are no longer risks of 

endangerment to USDWs. they could request that the Director authorize site c~osure."~' The 

""reposed Rule. 73 Fed. Reg. at p. 43491 (emphasis added). 
CCS Alliance suggests that if EPA considers the relationship between modeling results and 

actual plume movement in determining the continuation of post-injection site responsibility, the 

standard need not be "consistency." Models may predict a range of outcomes. Notwithstanding 

falling outside the modeled range, actual plume movement may be safe. including when there are 

no USDWs in the area. The Alliance recommends that the rule authorize Directors to end the 

post-injection site responsibility period prior to the 30-year period, taking into account their 

ability reasonably to predict the likelihood of minimal or no risk to USDWs. 

EPA should consider whether financial assurance mechanisms are likely to be available 

for the entire post-operation site care period. While risks can be expected to decline over- time 

after injection ceases, it does not follow that private risk management entities will continue to 

cover the risks. If there are no financial assurance mechanisms available, owners and operators 

should not be at risk of non-compliance for failing to have them after operations (and revenue 

streams from the project) have ceased, especially if risks continue to be low. As such, the CCS 

Alliance recommends that once the 30-year period is reached -- or shorter if the performance 

standards are met -- a government backstop would be triggered, thereby ensuring that a risk 

management mechanism is in place beyond the responsibility of the owner or operator. 

D. SITE CLOSURE 

The CCS Alliance recommends including a provision releasing sites certified as closed 

from further monitoring and verification requirements, as well as releasing any outstanding 

financial assurance instruments. 
X. RECORD KEEPING AND REPORTING REQUIREMENTS 

A. GENERAL COMMENTS 

The application and reporting requirements for Class VI wells should be balanced, 

placing as little burden as possible on owners and operators, while also achieving EPA's goals. 

Sufficient reporting requirements ensure the collection of information necessary for the 

protection of human health and the environment, and provide companies and investors with 

information to better manage and mitigate risks. A robust but not overly burdensome reporting 

regime is necessary to the success of CCS. as well as to achieving EPA's goals of protecting 

USDWs. 

B. PERMIT APPLIC TIO ON REQUIREMENTS 

EPA proposes to require owners and operators to submit relevant site information to the 

permitting authority for consideration of permit applications, including: maps of the injection 

wells, the AoR as determined through computational modeling, all artificial penetrations within 

the AoR, maps of the general vertical and lateral limits of USDWs, maps of the geologic cross 

sections of the local area, the proposcd operating data and injection procedures, proposed 

formation testing program, and stimulation program, well schematics and construction 

procedures, and contingency plans for shut-ins or well failures. 

Some of the data that EPA proposes to require is irrelevant, excessive, or in some cases 

unavailable. Therefore, the CCS Alliance recommends that EPA ensure that any required data is 

necessary to the ultimate goals of the Proposed Rule. For example, artificial penetrations several 

formations above the injection zone may have little relevance to the GS operation. Similarly, the 

CCS Alliance recommends including a provision in the final rule providing the Director 
discretion to waive certain data requirements, where such requirements are unnecessary, or 

require that the data be updated as it is collected or becomes available. 

EPA is proposing that an applicant include "baseline geochemical data on subsurface 

formations, including all USDWs in the area of review."" The Proposed Rule is not clear as to 

how much baseline data EPA is expecting the permit applicant to generate and collect from 

additional drilling or testing of the injection zone and all other zones. Given the likely depth of 

many of the GS wells through many strata, this could involve a large number of different 

formations above the injection zone. EPA should limit the baseline geochemical data to 

information regarding the next porous formation above the injection zone. Similarly, EPA 

should clarify that the permit applicant may rely upon secondary sources (such as other drilling 

or geologic records) that relate to and support the data requirement. EPA also should clarify 

whether its expects applicants to test private wells, where permission is granted, within the AoR 

for purposes of establishing baseline data. 

EPA also has included a requirement that the permit applicant include a "proposed 

formation testing program to obtain an analysis of the chemical and physical characteristics" of 

the injection and confining zone." A permit applicant is already required to submit the 

underlying data as part of the permit application process, and it appears that this requirement is 

unnecessary and duplicative. Therefore, the Alliance requests furthcr clarification regarding the 

intent and scope of this formation testing program. 

EPA should monitor stimulation activities of third parties to ensure that such activities 

not interfere with or damage the containment integrity of other GS operations or natural gas 

'"0 C.F.R. rj 146.&2(g). 

'' 40 C.F.R. rj 146.82Q). 
storage reservoirs. The CCS Alliance, therefore, generally supports the requirement for the 

"proposed stimulation program" to ensure that stimulation activities will not interfere with 

containment. 36 

EPA has proposed requiring the applicant to submit "the status of corrective action on 

wells in the area of review."47 The CCS Alliance does not believe it is necessary to require the 

inclusion of all wells within the AoR regardless of whether or not they penetrate the injection 

zone. There could be many shallow wells within the AoR located hundreds or thousands of feet 

above the C02 injection zone. Therefore, EPA should limit this requirement to the injection 

zone, injection pool, and only those wells that either intersect or penetrate the proposed reservoir, 

the cap rock, and possibly the porous strata directly abovc the injection zone. 

On a related matter, EPA has stated that only information of public record pertaining to 

all types of wells (injection. producing, abandoned) be included on the AoR. Data availability 

and use raises a question regarding the possible existence of other data which might be private, 

proprietary, and/or not publicly available. Such non-publicly available data may or may not be 

relevant to the application process. The CCS Alliance requests EPA to clarify to what extent an 

applicant would be expected to develop or use information not contained in the public record. 

EPA also proposes that permit applications for GS sites include several plans not 

currently required under existing UIC regulations, including (1) a monitoring and testing plan; 

(2) an AoR and corrective action plan; (3) a well plugging plan: and (4) a post-injection site care 

and site closure plan. The CCS Alliance questions whether it is necessary for each plan to be 

submitted contemporaneously with the permit application. The up-front gathering and 

" 40 C.F.R. 9 146.82(k). 

" 40 C.F.R. $ 146.Wq). 
submission of such detailed information would be costly and time-consuming. We recommend 

requiring the submission of such plans only upon approval of an initial permit application, with 

further approvals contingent upon the successful completion, submission, and approval of the 

required plans. The initial permit application could provide general information regarding the 

specific plans to be submitted later. Such a process will provide sufficient information for EPA 

to make an initial permitting decision. 

As part of the permitting process, EPA should require that owners and operators establish 

a plan to ensure that resource development may occur in other geologic strata within or near the 

AoR. CCS will be a critical technology, but also critical to the nation are energy resources and 

mineral reserves. Companies may have made considerable investment in purchasing, identifying 

and characterizing these resources. This value should be protected as GS sites are selected and 

developed. EPA's proposed rule at present does not address this issue. 

C. Operational Recordkeeping and Reporting Requirements 

1. Reporting Requirements 

EPA proposes to require owners or operators of Class V1 wells to report semi-annually to 

the permitting authority on: the physical and chemical characteristics of injection fluids; injection 

pressure, flow rate, temperature, volume and annular pressure; annulus fluid volume added; and 

the results of MITs, plume tracking, and atmospheric/soil gas monitoring. Additionally, owners 

and operators will be required to submit the results of AoR modeling revisions: any updates to 

the information on the type, number, and location of all wells within the site AoR; and 

information on additional corrective action performed or planned based on AoR reevaluations. 

A semi-annual reporting obligation with respect to the above information is reasonable. 

The CCS Alliance requests, however, that EPA streamline the final reporting requirements to 
ensure simplicity and to avoid unnecessary confusion or duplication of reporting obligations. 

For instance, proposed section 146.91(b) requires a report within 30 days for certain tests or any 

well workover. These additional reports should be incorporated into the semi-annual report, as 

they are not so time-sensitive as to require a separate reporting obligation. 

EPA also seeks comment on whether owners or operators of GS sites should be required 

to provide an annual report on GS operation during the lifetime of the project, including the postinjection period. Such a report is not necessary in light of the other proposed semi-annual 

reporting obligations. 

2. Records Retention 

Under the proposal, owners and operators would be required to maintain recordkeeping 

and reporting information for the duration of the project, as well as for three years after site 

closure (following the post-injection site care period). Owners and operators also would be 

required to keep their most recent plugging and abandonment report for one year following site 

closure. Under proposed requirement 40 C.F.R. 5 146.93(g), EPA would require that the owner 

or operator deliver to the Director records collected during the post-injection site care period at 

the conclusion of the 3-year retention period. The CCS Alliance is concerned that some of this 

information may be of a confidential financial or business operations nature and should be 

protected from public disclosure. Thus, the CCS Alliance recommends the inclusion of ;i "nondisclosure requirement" to protect certain sensitive and confidential business information from 

public disclosure. The CCS Alliance also requests EPA to consult with the U.S. Department of 

Homeland Security to determine whether CCS sites would constitute "critical infrastructure," 

thereby necessitating additional protection of sensitive information. 
XI. ADDITIONAL REQUIREMENTS AND CONSIDERATIONS 

A. GEOLOGIC SITING 

1. Target Geological Formations 

EPA discusses the possible target geologic formations for GS of C02, stating at one point 

that deep saline formations are the leading candidates for GS. It is premature to prefer one type 

of formation over another. Deep saline aquifers have had very little detailed investigation at 

commercial scale to date. By contrast, there is a significant amount of information available 

about depleted oil and gas reservoirs. COz storage in unmineable coal seams is an area of very 

active research, particularly in certain regions. Industry reports have conservatively 

estimated more than 10 billion tons of potential storage in regional coal seams that, if utilized, 

could result in the incremental production of more than 17 Tcf of natural gas. 

EPA states that "[wlhile coal seams are well studied and understood, the process of COZ 

adsorption to coal has not been proven."4"he Alliance believes it is well understood. EPA also 

states that "many ECBM recovery operations will likely be shallow. Shallow storage will result 

-49 in the COz remaining in a gaseous state . . . Some parties believe this is incorrect, and that 

such a statement would be true for storage into shallow aquifer pore space, such as in shallow 

saline formations, but that it is not true for storage into shallow coal seams. In that case, the COz 

is adsorbed and remains in the dense phase. 

2. Geologic Siting Requirements 

EPA's Proposed Rule includes significant technical information requirements for the 

geological siting of Class VI wells, including: maps and cross-sections of nearby USDWs; 

48 Proposed Rule, 73 Fed. Reg, at p. 43503. 

Id. 
demonstrations of the porosity and permeability of the injection zone and subsurface formations; 

information on faults and fractures, including results of geomechanical studies; seismic history 

studies; determinations of maximum sustainable injection pressures; and geochemical data. 

The geological siting requirements for Class VI wells should be reasonably balanced to 

ensure that EPA's goals are mct. but not be so burdensome so as to deter the development of 

CCS projects. To this end, EPA should ensure that the information it seeks is essential to its 

evaluation efforts, and not unnecessarily overbroad. Proper geological siting requirements will 

help EPA, state actors, and owners and operators identify the risks involved so that proper 

additional evaluations may be made to protect human health and the snvironment and to evaluate 

financial and strategic risks associated with CCS projects. 

Moreover, the siting requirements authorize the Director to use his discretion to require 

owners and operators to identify and provide additional information with respect to additional 

zones near the GS. Such discretion should not be unlimited. We recommend that EPA establish 

clearer guidelines with respect to how such discretion may be exercised to prevent unnecessary 

requirements. 

The CCS Alliance also is concerned about numerous federal and state statutes that may 

be triggered through the siting of a CCS project. At the federal level, the siting of linear facilities 

most often raises issues under the Clean Water Act, the Rivers and Harbors Act of 1899, the 

National Environmental Policy Act, and the Endangered Species Act. Any number of other 

federal statutes may apply, depending upon the resources affected by or near the facility. 

Congress may need to consider how to balance the objectives of these acts with the policy 

inherent in promoting CCS. 
Siting requirements should reflect that conditions affecting risk differ by site. They need 

to be tailored to the actual risks presented by specific sites. EOR is a well developed technique 

and there is now a history through which its risks can be assessed. This differs from injection for 

long-term storage in deep saline formations or unmineable coal seams. with which there is little 

experience, particularly on the massive scale (e.g., a million or more tons per year per plant) 

envisioned for the future. For CCS to be a viable long-term strategy, policy must encourage 

development of data about these sites, new technology. and new practices. 

B. AREA OF REVIEW AND CORRECTIVE ACTION REQUIRF:MENTS 

1. Area of Review 

The CCS Alliance agrees that traditional AoR delineation methods such as a fixed radius 

or simple mathematical computations would not he sufficient to predict the extent of C02 plume 

movement. The CCS Alliance therefore supports the use of computational fluid flow modeling 

designed for the specific site conditions and injection regime to delineate the AoR for COz GS 

sites. Such modeling will provide the level of sophistication necessary to predict the complex 

multi-phase buoyant tlow of the COz, injectates, and mobilizing compounds. 

EPA also proposes requiring the reevaluation of the site AoR on a periodic basis, 

suggesting a 10-year minimum fixed frequency for AoR reevaluation. The CCS Alliance agrees 

that a 10-year minimum is reasonable for reevaluating the AoR delineation, given that long-term 

COz storage may produce an AoR differing from other types of UIC injection plumes and should 

therefore be reevaluated to assure prqject safety and stability. 

2. Phased Corrective Action 

The CCS Alliance phased correction action and believes such an approach is reasonable, 

given the potential size of the C02 plume for commercial-scale GS operations. Requiring up- 
front corrective action for the entire AoR prior to injection could result in substantial delays in 

permitting and project implementation. At a minimum, as part of the AoR process, wells that 

penetrate the confining or injection zone must be identified. Identifying problematic wells upfront may increase short-term costs, but should reduce risk and liability over the long-term. 

EPA should address gaining access to third party wells that may require corrective action. 

Most states require corrective action to be performed prior to injection and the "right of access" 

is taken into consideration during the adequacy determination of the corrective action plan. 

Some states, such as Texas, require corrective action prior to injection unless the ownerloperator, 

after best efforts, is unablc to get permission to access the property of a third party.50 SDWA 

does not provide EPA the authority to require third parties to provide access to an 

owner/operator for the purposes of conducting corrective action. EPA should clarify how 

ownerloperators and states will be expected to implement corrective action. 

Prior to denying a permit application, the regulations should provide the owner or 

operator the opportunity to demonstrate that a project can maintain its safety and security, 

despite an uncorrected well. Otherwise, a potential GS site could go unutilized, even if the 

uncorrected well creates no actual risk of harm to USDWs. Moreover, well remediation should 

be applicable only to those wells that are likely to be impacted (meaning exposed to corrosive 

fluid and/or pressure above likely capillary entry pressure) early to mid phases of operation (e.g., 

one to 20 years). 

C. INJECTION WELL OPEIWTIKG REQUIREMENTS 

Geologic sequestration of CO;! need not be, in every instance, beneath the lowermost 

USDWs, nor should EPA set a minimum injection depth requirement. Such requirements likely 
would preclude injection into certain targeted geologic formations, which may include storage 

sites currently under consideration for GS. These formations may include unmineable coal 

seams, zones in between or above USDWs, and others. 

Directors should have discretion to allow injection above or between USDWs in specific 

geological settings where going below the lowermost USDW would make GS impractical, as 

well as where there are appropriate strata between the injection zone and the underlying or 

overlying USDW. Such Director discretion, however, should be limited or based on measurable 

factors or criteria. The CCS Alliance also agrees that Directors should be able to exempt all 

USDWs below the injection zone, pursuant to "aquifer exemptions." 

With respect to specific well operating requirements, we reiterate the importance of 

maintaining reasonable standards that take into account that CCS injection will differ from other 

injection activities. For instance, Class I wells typically must maintain an annular-fluid pressure 

greater than the injection tubing pressure to prevent outward leakage from the injection tubing. 

Typically, these wells operate at pressures much lower than C02 injection wells. This same 

requirement imposed on C02 injection wells would require specialized high-pressure equipment 

to maintain the required pressure differential on the annular fluid. EPA also recommends as a 

possible safety device in COz injection wells the use of down-hole shut-off valves that would 

automatically shut-in the well. It is not clear that safety valves for a C02 injection wells are 

available in the sizes necessary for most on-shore injection wells because these devices are 

primarily used in larger, off-shore wells. The use of such valves, therefore, needs more 

consideration. 
D. INJECTION WELL CONSTRUCTION REQUIREMENTS 

Well construction procedures and requirements should remain reasonable and flexible 

given that long-term C02 storage remains a relatively new area with developing science and 

technologies. The experience of the operator, the volume of COz stored, and the pressure at 

which it needs to be injected, should be viewed as important variables when finalizing well 

construction requirements. EPA also should consider that a properly installed well provides a 

barrier to fluid movement, even if components are shown to degrade in aggressive laboratory 

experiments. It is also not known if new COz resistant cements will perform as well as 

conventional cements in terms of emplacement and bonding. 

Horizontal well construction has proven beneficial in other applications, such as EOR 

operations, and therefore should be an available option for Class VI wells. The CCS Alliance 

also supports EPA's proposal to provide Directors the authority to grandfather the construction 

requirements for Class V experimental project wells and other wells when they are converted to 

full scale Class VI wells. The Alliance suggests that EPA should consider whether 

grandfathering the existing siting, AoR, operations, and monitoring plans for Class I1 and Class 

V wells when they are converted to full scale Class VI wells would protect USDWs while 

avoiding additional regulatory burden. 

E. MECHANICAL INTEGRITY TESTING REQUIREMENTS 

EPA would require owners and operators of Class VI projects to monitor internal 

mechanical integrity of their injection wells by continuously monitoring injection pressure, flow 

rate, and in-jected volumes, as well as the annular pressure and fluid volume to assure that no 

anomalies occur that may indicate an internal leak. The practicability of such monitoring is yet 

unknown. The proposed MIT requirements, therefore, should be flexible. The same holds true 
for the frequency of internal and external MITs for injection wells, the types of MITs, and how 

to optimize MIT methods for geologic sequestration. As industry gains more knowledge and 

experience, more structured regulations for MIT types and frequency of MITs may be 

appropriate. 

We do not believe there is any compelling reason to require annual integrity testing or 

quarterly corrosion monitoring. A five-year testing routine has been sufficient for acid gas wells 

in Canada. Many known injection wells are reused producer wells that have been in corrosive 

environments for over 15 years and remain in good condition. Annual testing and quarterly 

corrosion testing could also result in significant costs from plant shutdowns and downtime. 

Many companies already conduct periodic plant-wide shutdowns to thoroughly inspect piping 

and equipment for corrosion and make any necessary equipment upgrades. These shutdowns, 

which ordinarily occur once every three to five years, are also used to inspect injection wells, 

including pulling tubing, running cement bond logs, and well casing integrity logs to determine 

the thickness and integrity of the steel in the boreholes. From these tests, companies are able to 

assess the cement and casing conditions, which provide the primary "isolation" mechanism from 

the reservoir fluids. Moreover, companies can and often do run noise logs that can assess for 

"channeling" behind the casing. 

Proposed section 146.89(d) would give the Director discretion to require any other test to 

evaluate mechanical integrity, if the alternative tests are approved and published in the Federal 

Register. We recommend that EPA revise the mechanical integrity testing requirements (1) to 

give the Director discretion to approve not only different testing requirements but the timing for 

testing requirements; and (2) to require such testing no more frequently than a reasonable multiyear period, or sooner if there is evidence that earlier testing is warranted. 
EPA has specifically requested comment on the use of tracers. Based on industry 

experience, tracers are not typically used for monitoring the movement of a C02 plume, unless 

potential leakage is occurring. They are then used to trace the leakage point. Tracers can be 

very expensive and the results can take a lot of time to develop, analyze, and understand. 

Radioactive tracers typically have long shelf lives and, if used by neighboring operators, could 

produce conflicting and indeterminate results. Duc to the potential for groundwater 

contamination, the use of radioactive materials should be used only sparingly and for targeted 

purposes. 

F. PLUME AND PRESSURE FRONT MONITO~~~ ~QTIEGE~T$ 

EPA proposes monitoring sequestration sites to track the location of the COz plume and 

associated pressure front over time. Plume monitoring is important to the long-term stability of 

CCS sites. However, we submit that such a requirement should be flexible to accommodate 

growing knowledge about injection and C02 plumes. Monitoring has limited usefulness in some 

settings (e.g., 4D seismic often does not have the resolution to detect C02 in some deep or 

complex settings or where hydrocarbon gases are present). Moreover, data gathering 

requirements related to plume tracking and testing should not unduly burden owners or 

operators, either in time or cost, and should be essential to evaluation of the plume's stability and 

safety. 

EPA proposes in section 146.90(d) "periodic monitoring of the ground water quality and 

geochemical changes above the confining zone(s)." It is unclear how many wells would be 

required, and whether EPA expects that all zones would be monitored. Given the potential size 

of the C02 plume and the number of confining zones, this could potentially require many 

monitoring wells, which could be extremely expensive and may not produce useful data. We 
strongly recommend that EPA limit monitoring to the zone immediately above the confining 

zone, and only to the extent that the COz plume is within close proximity. There may be regional 

conditions where ground water is separated by hundreds or thousands of feet of confining strata, 

and where such monitoring is completely unnecessary. Directors should have discretion to limit 

or tailor ground water monitoring, as appropriate, based on regional and site specific factors. 

Proposed section 146.90(h) gives Directors discretion to require surface air monitoring 

and/or soil gas monitoring to detect movement of C02 that could endanger a USDW. The 

Alliance recommends deleting this provision. It is not clear how ambient air or soil gas 

monitoring is related to or supports the protection of USDWs. Surface air monitoring can result 

in false positives, which could prompt unnecessary and costly response actions and nwdlessly 

alarm the public Any requirement for ambient air or soil gas monitoring would be a matter of 

state discretion pursuant to state law and not the federal UIC program, and would not be 

federally enf~rceable.~' 

G. DEFINITIONS 

EPA defines "area of review" as "the region surrounding the geologic sequestration 

project that may be impacted by the injection activity. The area of review is based on 

computational modeling that accounts for the physical and chemical properties of all phases of 

the injected carbon dioxide stream." The phrase "may be impacted" is too vague, The AoR 

delineation should be based on or limited by certain risk criteria; otherwise, an AoR could cover 

an inappropriately large area that could be expensive to review and characterize. 

The term "geological sequestration project" is defined as an injection well or wells used 

to emplace a C02 stream beneath the lowermost formation containing a USDW, including the 

Bath Petrdeum Stomgc, Inc. V. Sows, 309 F.Supp. 2d 357 (N.D.N.Y 2004) (state law requiring sonar 

survey for UIC injection not federally enforceable). 
subsurface three-dimensional extent of the C02 plume, associated pressure front, and displaced 

brine, as well as the surface area above that delineated region. We recommend removing the 

phrase "beneath the lowermost formation containing a USDW to reflect our comment 

suggesting that EPA permit CCS projects above USDWs where feasible. The AoR definition 

includes additional area that might be impacted and is not defined in terms of the extent of this 

area. 

EPA defines "mechanical integrity" as "the absence of significant leakage within the 

injection tubing, casing, or packer (known as internal mechanical integrity), or outside of the 

casing (known as external mechanical integrity)." The rerm "significant leakage" is not defined. 

An overly broad interpretation could result in a finding that mechanical integrity is not being 

maintained, notwithstanding the absence of any leakage that calls into question the safety of the 

project or threatens USDWs. EPA should characterize what constitutes "significant" or clarify 

under what conditions significant leakage might be construed. We suggest defining and 

construing the term within the statutorily defined concept of "endangerment"5' under SDWA, 

i.e., significant leakage would be defined as any leakage that could potentially endanger a 

USDW. The amount of leakage and what constitutes significant may vary depending upon the 

geologic formations and proximity to USDW~.~' 

'' Endangerment is defined as follows: 

Underground injection endangers drinking water sources if such injection may result 

in the presence in underground water which supplies or can reasonably be expected 

lo supply any public water system of any contaminant, and if the presence of such 

contaminant may result in such system's not complying with any national primary 

drinking water regulation or may otherwise adversely affect the health of persons. 

32 U.S.C. 5 300h(d). 

'' Miami-Dade Cmnty r. EPA, 529 F.3d 1049 (1 1Ih Cir. 2008) (upholding EPA's rule eliminating the nonendangerment finding requirement for Class I municipal injection wells). 
XII. RELATED ISSUES, NOT RAISED IN THE PROPOSED RULE, THAT REQUIRE 

RESOLUTION 

The SDWA does not provide EPA authority to de\.clop regulations for many important 

areas related to thc geulogical sequestration of COz. Thus the draft rule cannot address all of the 

potential impediments to CCS development. Even if EPA were to promulgate a final UIC rule 

that encourages development of these critical technologies, there are other key factors that would 

need to be properly addressed before major investment in these technologies can be expected. 

The following sets forth key issues that will not be resolved through this rulemaking but 

are linked inextricably to the successful development and implementation of CCS technology. 

A. EMINENT DOMAIN AUTHORITY TO FACILITATE PIPELIM CONSTRUCTION 

Energy facilities for the public convenience and necessity, such as electric transmission 

facilities and natural gas pipelines, are able to make use of state or federal eminent domain 

authority to ensure that private landowners cannot block a project necessary for the public good. 

Eminent domain authority should be available for COz pipeline5 for CCS when it is necessary to 

cross private property. A substantial COz pipeline network may be required for the transport of 

COz from sites where it is produced to an in.jection site. C02 pipelines for CCS clearly should be 

considered to be used for thc public convenience and necessity. 

DETERMINATION OF SUB-SURFACE PROPERTY RIGHTS 

The government must address the ability to gain sufficient property rights to deep saline 

formations to conduct geologic sequestration. State property ownership regimes vary, but 

surface owners typically are considered to own property below the surface to the center of the 

earth. Safe sequestration of C02 will not have any effect on the surface, but GS injections will 

result in underground plumes that may stretch across many square miles under the property of 

multiple surface property owners. Property ownership issues have been resolved successfully in 
the context of EOR, but it should not be assumed that the same will be true for GS. Eminent 

domain authority should be available to obtain rights to subsurface storage space for geologic 

sequestration because of its public benefit. 

C. RESOI,UTION OF SURFACE LIABILITY ISSUES 

Though this Proposed Rule is limited in its scope to underground injection of COz and 

the potential risks and resulting liabilities, issues regarding risks and liability at the surface must 

be addressed for CCS technology to fully develop. These include liability for major and sudden 

releases, seismic activity and ground heave, as well as liability under any GHG emission control 

regime when sequestered C02, for the storage of which credits or offsets have been granted, is 

subsequently released into the upper atmosphere. 

XIII. CONCLUSION 

In conclusion, the CCS Alliance appreciates the opportunity to provide these comments. 

We would be pleased to clarify or further discuss any of the points contained herein. 

Respectfully submitted, 

%red Eames 

for the CCS Alliance 

Frederick R. Eames 

Hunton & Williams LLP 

1900 K Street, N.W. 

Washington, D.C. 20006 

202/955- 1500 

73350.000003 EMF .US 26395536~7 
Letter ID: 0178 

Commenter: Frederick R. Eames 

Organization: CCS Alliance 

Letter ID: 0178 Comment ID: 23794 Letter Lines: 58 to 63 

Comment Code: 1270 1.1.2 Comments on other rules/issues 

Comment: A plethora of regulations affect the delivery of power using coal. We suggest 

that the Agency consider other regulations addressing the environment, human 

health and safety, and electricity cost and reliability, when drafting and 

implementing these regulations. The Alliance urges the Agency to consider the 

support of integrated energy, climate, and environmental policy as time 

progresses. 

Individual Response: EPA agrees that a strong regulatory framework will be important to 

ensuring that GS is deployed safely. The Class VI GS regulation will provide certainty, 

consistency, and transparency to owners or operators and the public about requirements that 

apply to GS injection across the U.S. The Class VI GS regulation builds upon the long-standing, 

protective framework of the UIC program, which has been regulating the injection of billions of 

gallons of liquids for decades. The Class VI GS regulation enhances this existing framework 

with requirements for Class VI wells that are tailored to the unique nature of large scale GS of 

CO2. These additional protective requirements include more extensive geologic testing, detailed 

computational modeling of the AoR and periodic re-evaluations, detailed requirements for 

monitoring and tracking the CO2 plume and pressure front, and extended post-injection 

monitoring and site care. 

In response to the suggestion that the Agency develop an integrated permitting process, EPA 

clarifies that the UIC program’s authority under SDWA is focused on ensuring consistency in 

permitting underground injection of CO2 at GS operations across the United States and provide 

requirements to prevent endangerment of USDWs in anticipation of the eventual use of GS to 

reduce CO2 emissions. 

Letter ID: 0178 Comment ID: 23795 Letter Lines: 72 to 76 

Comment Code: 1200 1.1 General comments about the rulemaking 

Comment: If promulgated as currently proposed, the Proposed Rule will have a significant 

and direct impact on the interests of the members of the CCS Alliance and their 

customers. The CCS Alliance believes the Proposed Rule is helpful in many ways, 

but also that it can be improved in a manner that will both promote good risk 

management and reduce barriers to CCS deployment. 

Individual Response: EPA acknowledges the comment. The purpose of the rule is to ensure 

consistency in permitting underground injection of CO2 at GS operations across the United 

1
States and provide requirements to prevent endangerment of USDWs in anticipation of the 

eventual use of GS to reduce CO2 emissions. Please see the remainder of EPA's responses to this 

comment for further details. For additional information on EPA's final regulatory approach, 

please see the final rule and preamble as well as the rulemaking docket. 

Letter ID: 0178 Comment ID: 23796 Letter Lines: 80 to 104 

Comment Code: 1330 1.1.3.1 Support use of GS in general 

Comment Code: 1400 1.2 Comments on EPA's Authority to Regulate Injection of CO2 

Comment: If atmospheric emissions of CO2 are to be controlled, CCS is the only tool now 

on the horizon that may be capable of addressing in a major way and within a 

mid-term timeframe, the very large quantities of CO2 emissions from fossil-fuel 

using facilities in the United States. However, CCS still requires the 

definition of a stable and rational legal and regulatory regime before it can be 

widely deployed. EPA has clear regulatory authority over the injection of wastes 

and other substances into below-surface wells through the UIC program. The UIC 

program was created by Congress under the Safe Drinking Water Act ("SDWA") over 

30 years ago, without consideration of potential interaction with policies to 

address climate change, for the protection of underground sources of drinking 

water ("USDW). The Agency now proposes to use this framework to regulate belowground CO2 injection activities, an application not contemplated at the time 

SDWA was drafted. Rules for geologic sequestration ("GS") of CO2 are timely and 

would be needed even if CCS is not deployed as quickly as many predict. While 

many projects are under development, many observers are operating under the 

assumption that it will be a decade or more before there can be wide deployment 

of CCS.[FN3] The future of CCS is and will be at a critical juncture for some years. 

The CCS Alliance seeks, through its comments, to help ensure that these 

regulatory activities promote well designed and implemented CCS projects with 

sound risk management practices, and do not preclude the responsible, cost 

effective commercial-scale sequestration of CO2. 

[FN3] See, e.g., "EPRI Summer Seminar and Energy Technology Assessment Center 

(ETAC) Studies," presentation of Hank Courtright, Senior Vice President, 

Electric Power Research Institute. October 22. 2008. 

Individual Response: EPA believes that the creation of a new injection well class (VI) under the 

existing UIC Program is necessary to enable the use of GS as a climate change mitigation 

technology in a manner that protects USDWs from endangerment. EPA believes that the UIC 

Program, under the authority of the SDWA, provides a strong framework for regulating injection 

of CO2 for GS and adds that the GS regulation tailors the UIC requirements to address the 

unique issues associated with large-scale GS including large injection volumes, the relative 

buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in 

captured CO2, and its mobility within subsurface geologic formations. 

EPA agrees that the implementation of the GS rule in a manner that ensures protection of 

2
USDWs from endangerment is important to establishing a foundation for further advances in the 

field of CO2 GS. EPA acknowledges the need for regulatory certainty: the final GS requirements 

provide a level of certainty by setting forth unique requirements for GS. These requirements 

include: the tailored AoR delineation process at §146.84, the types of monitoring appropriate to 

GS projects §146.90, and the post-injection site care process §146.93. 

Letter ID: 0178 Comment ID: 23797 Letter Lines: 121 to 150 

Comment Code: 1200 1.1 General comments about the rulemaking 

Comment: As the only significant technology to reduce atmospheric CO2 emissions from 

coal, CCS is indispensable to reducing GHG emissions while meeting energy demand 

and achieving energy security. It is true, as EPA notes, that underground 

storage of CO2 is "only one of a portfolio of options," including efficiency 

improvements, and the use of alternative and renewable energy sources. However, 

these other tools are not a substitute for baseload power generation, which 

comes primarily from fossil fuels. All GHG emission reduction options will need 

to be pursued to meet proposed emission reduction targets. The CCS Alliance 

urges that EPA, and those concerned with the Proposed Rule, consider the 

importance of CCS in the context of climate risk mitigation. 

The U.S. population is expected to grow by 60 million by 2030. During that time, 

electricity demand is projected to increase by approximately 30 percent.[FN5] 

Without rapid deployment of technologies that have begun to show promise, such 

as CCS, it will not be possible to meet the GHG emission reduction goals being 

discussed by IPCC and others now for attainment by mid-century. While the thrust 

of this rulemaking is to protect and preserve USDWs, such environmental 

objectives should neither be viewed in isolation nor divorced from other 

environmental and policy considerations - including energy security, economic 

stability and trade considerations. A rational, comprehensive approach to the 

management of CO2 emissions from GHG-emitting facilities must be undertaken if 

we are to simultaneously preserve economic stability, ensure returns on invested 

capital, enhance U.S. energy security, and mitigate the predicted effects of 

climate change. 

[FN5] Energy Information Administration, Annual Energy Outlook 2008 (June 2008), 

http://www.eia.doe.gov/oiaf/aeo/electricity,html; U.S. Census Bureau, 

Projections of the Population by Age and Sex for the United States: 2010 to 

2050 (Aug. 2008), 

http://www.census.gov/population/www/projections/files/nation/summary/np2008-12.xls. 

Individual Response: EPA clarifies that mitigating climate change is outside the scope of the 

GS rulemaking. Rather, the purpose of the GS regulation is to ensure consistency in permitting 

underground injection of CO2 at GS operations across the United States and provide 

requirements to prevent endangerment of USDWs in anticipation of the eventual use of GS to 

reduce CO2 emissions. 

3
Letter ID: 0178 Comment ID: 23798 Letter Lines: 159 to 171 

Comment Code: 1380 1.1.3.6 Deployment of GS 

Comment: Promote CCS Development 

A CCS policy regime should be designed to encourage CCS, in addition to serving 

other public goals -- such as promotion of energy security, economic stability. 

and protection of USDWs, human health and the environment. 

Sound Risk Management 

Federal and state policy should encourage owners, operators, technology 

companies, engineering firms, utility regulators, and others involved in the CCS 

chain to take appropriate action to ensure safe and reliable operation of GS 

sites and systems, minimize risks, and allow CCS to earn broad public 

acceptance. 

Individual Response: EPA clarifies that the Class VI GS regulations promulgated under Safe 

Drinking Water Act authority do not promote or encourage the use of GS but, ensure consistency 

in permitting underground injection of CO2 at GS operations across the United States and 

provide requirements to prevent endangerment of USDWs in anticipation of the eventual use of 

GS to reduce CO2 emissions. EPA believes that the Class VI GS regulations, which build upon 

the long-standing, protective, regulatory framework of the UIC program, will provide the 

regulatory certainty and clarity that owners or operators have requested. 

EPA acknowledges that there are unknowns associated with early GS project deployment and the 

long term storage of CO2 for GS. For these reasons, the Agency is using an adaptive approach to 

regulating GS injection. The Agency will, every six years, collect and review data on GS projects 

to determine whether the appropriate amount and types of information and appropriate 

documentation are being collected, and to determine if modifications to the requirements are 

appropriate or necessary. 

EPA agrees that input of and participation by a wide spectrum of stakeholders is a vital 

component of successful rulemaking. The Agency appreciates the degree of cooperation, 

participation, and active dialogue between the EPA and stakeholders and will continue to work 

with stakeholders and experts as it implements the Class VI GS rule. 

Letter ID: 0178 Comment ID: 23799 Letter Lines: 173 to 183 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment Code: 5400 2.9 Proposed Financial Responsibility and Long-Term Care 

Requirements 

4
Comment: Single, Clear Liability Structure 

To the extent possible, policymakers should put in place a single, clear 

liability regime for CCS activities. In the context of this rule, EPA has 

considered the possibility of cleanup liability both under the Comprehensive 

Environmental Response, Compensation, and Liability Act ("CERCLA" or 

"Superfund") and the Resource Conservation and Recovery Act ("RCRA), in addition 

to the UIC program. There is also the possibility of liability under state 

statutes and common law. Parties who may be injured in the future must be able 

to resort to a fair liability scheme, but potential applicability of multiple 

schemes is likely to discourage CCS development. 

Individual Response: EPA acknowledges the commenter's concerns regarding the applicability 

of multiple statutes to GS projects and the need for a single clear liability regime for owners or 

operators. As a federal agency, EPA is working to create a nationally consistent financial 

responsibility regime within its authority while providing permitting authorities an appropriate 

level of flexibility. EPA is finalizing financial responsibility requirements under authority of the 

SDWA. EPA believes that the general authorities provided under SDWA include the authority to 

set minimum federal requirements for financial responsibility to ensure that financial resources 

are available to protect USDWs throughout the life of the GS project. See the final rule and 

preamble for further discussion of EPA's final approach to financial responsibility. 

Furthermore, an owner or operator may always be subject to any action the Administrator deems 

necessary to protect the health of persons under §1431 of the SDWA after site closure if there is 

unanticipated migration towards or into a USDW that causes or threatens imminent and 

substantial endangerment to public health. The action may include issuing administrative orders 

or commencing a civil action for appropriate relief. If the owner or operator fails to comply with 

the order, they may be subject to a civil penalty for each day in which such violation occurs or 

failure to comply continues. 

The Agency acknowledges and clarifies that, after site closure, an owner or operator may, 

depending on the fact scenario and state law, remain liable under state tort law and other 

remedies, or under other Statutes including, but not limited to, Clean Air Act, 42 U.S.C. §§ 

7401-7671; CERCLA, 42 U.S.C. § 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. 

EPA appreciates the commenter’s suggestions for a single liability scheme for CCS; however, 

the GS rule is not promulgated under either RCRA or CERCLA, and making legislation changes 

or addressing liability under state statutes and common law is also outside the scope of the GS 

rulemaking. EPA also notes that the applicability of RCRA and CERCLA will not be determined 

under the SDWA or the terms of the GS rule, but rather according to those statutes themselves 

and any implementing regulations that may apply. 

EPA agrees that any requirements applicable to CO2 injectate should be clearly identified to the 

public and to the regulated community. EPA received many comments regarding the 

applicability of the RCRA regulations and statute to CO2 streams that are geologically 

sequestered under the final Class VI UIC well requirements. As a result, EPA has decided to 

5
initiate a separate proposed rulemaking specifically to examine the issue of RCRA applicability 

to CO2 streams being geologically sequestered, including the possible option of a conditional 

exemption from the RCRA requirements for CO2 GS in Class VI wells. EPA will consider these 

comments as part of its development of that proposal. The Agency will consider issues particular 

to RCRA in the context of that separate rulemaking, and recommends that the commenter read 

that proposed rule when it is published. The Agency notes that commenters who wish to submit 

comments on the RCRA proposal will need to do so during the comment period for that rule. 

Finally, EPA also notes that the final GS rule, which adds new regulations for Class VI wells 

under the Safe Drinking Water Act (SDWA), is not making any changes to the RCRA 

regulations. 

Letter ID: 0178 Comment ID: 23800 Letter Lines: 185 to 191 

Comment Code: 1300 1.1.2.3 Comments on other aspects of CCS (capture, transport) 

Comment Code: 1540 1.2.3.2 Climate change legislation 

Comment: Single, Clear Regulatory Structure 

There should be a single, clear regulatory structure applicable to CCS rather 

than multiple, ill-suited regulatory and liability statutes and regulations that 

likely will discourage CCS To that end, the CCS Alliance believes that a 

beneficial approach would be to enact at the federal level a new regulatory 

structure specific to CCS. 

Individual Response: EPA acknowledges that GS falls within the broader context of CCS and 

the need for regulatory clarity to ensure that USDWs are protected from endangerment. In 

developing the final GS rule, the Office of Water coordinated with other Agency program offices 

and across federal agencies (e.g., with the Department of Energy; United States Geological 

Survey; Bureau of Ocean Energy Management, Regulation, and Enforcement, formerly the 

Minerals Management Service; Bureau of Land Management). The Agency continues to evaluate 

areas of potential applicability of other Federal environmental statutes including, but not limited 

to: the Clean Air Act; the Resource Conservation and Recovery Act; the Comprehensive 

Environmental Response, Compensation, and Liability Act; and the Marine Protection, Research 

and Sanctuaries Act to various aspects of GS and CCS. The Agency will continue to coordinate 

on GS and CCS related issues to minimize redundancy and maximize efficiencies for owners or 

operators. For additional information, please see the discussion entitled "How Does This 

Rulemaking Relate to Other Federal Authorities and GS and CCS Activities?" in the preamble to 

the final GS rule. 

EPA is also aware that states are currently in various stages of developing statutory frameworks, 

regulations, technical guidance, and strategies for addressing CCS and GS. States can use 

multiple authorities beyond those afforded under the SDWA and UIC regulations, including laws 

and policies addressing surface access and land rights, unitization of fields, pore space 

ownership, mineral rights, worker safety and emergency preparedness, and maximization of state 

oil and gas resource exploitation. EPA plans to work closely with states and tribes as they 

develop Class VI primacy programs in this broader context. EPA adds that states may adopt 

6
more stringent standards for Class VI wells than the Federal requirements. 

In a separate rulemaking under authority of the Clean Air Act, EPA is amending the Greenhouse 

Gas (GHG) Reporting Program at 40 CFR Part 98 to add reporting requirements for facilities 

that conduct GS (subpart RR) and all other facilities that inject CO2 underground (subpart UU). 

For additional information, see the section of the final GS rule preamble entitled, "How Does 

Mandatory Reporting of Greenhouse Gases (GHGs) Relate to This Rulemaking?” and the GHG 

Reporting Program rulemaking and docket. 

Letter ID: 0178 Comment ID: 23801 Letter Lines: 193 to 207 

Comment Code: 1210 1.1.1 Comments about the proposed rule 

Comment: Site-Specific Approach 

Policy regarding GS siting should reflect that conditions affecting risk differ 

by site and should be tailored to risks presented by specific sites. For 

example, CO2 has been injected underground for several decades for EOR. This 

technique is well developed and there is now a history through which its risks 

can be assessed. This differs from injection for long-term storage in deep 

saline formations or unmineable coal seams, with which there is limited 

experience, particularly on the massive scale -- a million or more tons per year 

per site -- envisioned for the future. Policy must encourage development of new 

data, technology, and practices while recognizing that existing technology is 

readily applicable. It also should reflect that some long term injection 

practices such as natural gas storage and EOR already are known to pose little 

risk. Sites also will differ based on reservoir and confinement geological 

details, proximity to USDWs and other resources, and other factors. In addition, 

Individual Response: EPA agrees that permitting decisions for GS wells should be based on 

site-specific factors. The GS rule requires owners or operators to submit, and Directors to 

consider, extensive site-specific data, specified at §146.82, to demonstrate that a site is suitable 

for GS. Additionally, many of the permit requirements for GS wells are established through 

individualized site-specific plans for AoR and corrective action, testing and monitoring, and 

injection well plugging and post-injection site care and site closure. EPA adds that the final GS 

rule includes a balance of specific criteria to be met by the owner or operator and areas of 

Directorial discretion. The Agency believes this balance allows for GS projects to be designed 

and permitted to address the unique, site-specific aspects of each project, while providing 

consistency in permitting across the U.S. 

EPA adds that the GS rule does not categorically preclude injection of CO2 into any formation 

types. The purpose of the GS rule is to ensure protection of USDWs from endangerment, and the 

rule requires that owners or operators demonstrate that wells are sited in suitable systems with 

geologic formations to receive and confine injected CO2, required at §146.83 of the GS rule. 

7
Letter ID: 0178 Comment ID: 23802 Letter Lines: 207 to 210 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment: details, proximity to USDWs and other resources, and other factors. In addition, 

it is not necessarily the case that injection always should have to occur 

beneath the lower most water source with a confining system in place as 

suggested by EPA. This should be determined on a case-by-case basis. 

Individual Response: EPA acknowledges that there are limited circumstances where injection 

above the lowermost USDW can be performed in a manner that protects USDWs from 

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 

establishes a process by which owners or operators can seek a waiver of the Class VI injection 

depth requirements for injection into non-USDW formations above and/or between USDWs. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to 

UIC program Directors and owners or operators who undertake CO2 injection for GS. The 

Agency believes this approach: 1) responds to concerns about local and regional geologic storage 

capacity limitations imposed by the proposed injection depth requirements; 2) allows for a more 

site-specific assessment of injection depth for GS projects; 3) accommodates injection into 

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or 

between USDWs when appropriate and where it can be demonstrated that USDWs will be 

protected; and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, 

EPA’s approach to addressing injection depth variability through a waiver process responds to 

concerns about future drinking water resource availability and the need to ensure that high 

quality water remains available in sufficient quantities to supply drinking water needs. For 

additional information on the waiver approach, please see the final rule and preamble, as well as 

EPA's responses to comments on the Notice of Data Availability and Request for Comment. 

Letter ID: 0178 Comment ID: 23803 Letter Lines: 212 to 232 

Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: Liability and Site Care Responsibility Cannot be Unlimited 

Site responsibility and liability of owners and operators should be designed to 

account not only for protection of the public, but recognizing that private 

parties cannot assume open ended or unlimited risks. This includes site owners 

and operators, others involved in the CCS chain, and offerors of risk management 

products. There is not now, nor is there likely to be, a private market through 

which risks can be managed far beyond a reasonable post-operation site care 

period. In recognition of the market's limits, the duration and amount of site 

responsibility must be limited. 

As a point of clarification, we use the following terms to denote different 

8
periods in the CCS chain: 

Operation is intended to mean the period during which CO2 is injected at the 

injection site. 

- Post-operation site care period or closure period is intended to mean the 

period of years after operation during which the owner or operator is required 

to meet State or EPA site care responsibilities. 

- Post-closure period is intended to mean the period after State or EPA site 

care responsibilities end. 

Individual Response: Under the final GS rule, once an owner or operator has met all regulatory 

requirements under Part 146 for Class VI wells and the Director has approved site closure 

pursuant to requirements at §146.93, the owner or operator will generally no longer be subject to 

enforcement for regulatory noncompliance. Furthermore, their financial instrument as required 

under §146.85 will be released if it was not used. However, even if a site closure is approved 

under §146.93, an owner or operator may be held liable for regulatory noncompliance (including 

violation of 40 CFR 144.12) in certain circumstances. For example, an owner or operator may be 

held liable for regulatory noncompliance even after site closure was approved if the Director 

relied on erroneous information (e.g., erroneous modeling data) provided by the owner or 

operator when approving site closure. 

Separate from EPA’s authority to enforce regulatory compliance, an owner or operator may be 

subject to a §1431 response order even after proper site closure is approved under §146.93. 

Under §1431 the Administrator may require an owner or operator to take necessary response 

measures if he or she receives information that a contaminant is present or is likely to enter a 

public water system or an USDW, which may present an imminent and substantial endangerment 

to the health of persons, and the appropriate State and local authorities have not acted to protect 

the health of such persons. The action may include issuing administrative orders or commencing 

a civil action for appropriate relief against the owner or operator of a Class VI well. If the owner 

or operator fails to comply with the order, they may be subject to a civil penalty for each day in 

which such violation occurs or failure to comply continues. 

Furthermore, after site closure an owner or operator may remain liable under tort and other 

remedies, or under other federal statutes including, but not limited to, Clean Air Act, 42 U.S.C. 

§§ 7401-7671; CERCLA, 42 U.S.C. § 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. EPA 

does not have authority to transfer SDWA or other legal liability for Class VI wells to the State 

or federal government or a third-party fund. See the final rule preamble for further discussion of 

EPA's final approach. 

Letter ID: 0178 Comment ID: 23804 Letter Lines: 234 to 239 

Comment Code: 5434 2.9.1.2 Need for additional instruments (seeking comment) 

Comment: Allow a Broad Array of Financial Assurance Mechanisms 

Government policy should allow a broad array of mechanisms, including trust 

9
funds, especially since the market is likely to be limited for risk management 

mechanisms for CCS. We provide suggested principles for financial assurance 

below. 

Individual Response: Owners or operators may choose from a variety of financial instruments 

to meet their financial responsibility obligations under the rule, provided the Director determines 

that the operator's proposed financial responsibility demonstration is adequate to protect USDWs 

from endangerment, which means the ability of the owner or operator to pay for each activity for 

which financial responsibility must be demonstrated, including corrective action on wells in the 

AoR, injection well plugging, PISC and site closure, and emergency and remedial response 

throughout the life of the project. The final GS rule specifies at §146.85(a)(1) the permitted types 

of financial responsibility instruments. See the final rule and preamble for further discussion of 

EPA's final approach to financial responsibility. 

Letter ID: 0178 Comment ID: 23805 Letter Lines: 241 to 251 

Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: Government Backstop Role 

The government will need to step in beyond an owner and operator liability 

limit, as has been the case in many other areas in which the government has 

sought to encourage private action to achieve a public good. The private 

sector's capacity to manage risks is substantial, but not unlimited in either 

aggregate capital capacity or tenor and term. Government will need to accept 

responsibility beyond what the private market can manage. Because the goal in 

most cases will be long-term storage of CO2, long beyond the typical lifespan of 

private entities, government should assume liability after injection operations 

cease and a reasonable closure period has elapsed. 

Individual Response: As described above, once an owner or operator has met all regulatory 

requirements under Part 146 for Class VI wells and the Director has approved site closure 

pursuant to requirements at §146.93, the owner or operator will generally no longer be subject to 

enforcement for regulatory noncompliance. 

EPA does not have authority to transfer SDWA or other legal liability for Class VI wells to the 

State or federal government or a third-party fund. See the final rule preamble for further 

discussion of EPA's final approach. 

Letter ID: 0178 Comment ID: 23806 Letter Lines: 253 to 262 

Comment Code: 1530 1.2.3.1 State regulatory efforts on GS (seeking comment) 

Comment: State and Federal Regulatory Responsibility 

10
State oil and gas commissions are repositories of expertise in regulating oil 

and gas industry underground injections, which have been safely undertaken for 

many decades. These commissions also have regulated CO2 injections for enhanced 

oil and gas recovery, a practice that has been in use for 40 years. However, not 

all states have oil and gas regulatory experience. In states that do not have 

experience regulating oil and gas injections, EPA and the state should ensure 

the application of reasonable regulation that protects public health and the 

environment without discouraging CCS development and deployment. 

Individual Response: EPA clarifies that states will be granted primacy for Class VI wells on the 

basis of meeting minimum federal requirements for the protection of USDWs. EPA believes that 

the requirement that states' regulations meet the minimum federal requirements will promote 

national consistency. To further ensure the final rule is applied consistently, EPA is developing 

guidance documents for states that describe the process of applying for and receiving primary 

enforcement responsibility (primacy) for GS Class VI wells under Section 1422 of SDWA, as 

well as the technical and administrative issues on developing GS regulations that are the 

equivalent of minimum federal criteria and requirements. EPA adds that the guidance discusses 

additional considerations for states that do not have primacy for Class II wells. EPA is 

developing a series of guidance documents to support the GS rulemaking. These are available on 

EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA acknowledges that some states and tribes are developing statutory frameworks, regulations, 

technical guidance, and strategies for addressing broader issues related to CCS and GS, and 

encourages states to seek primacy for Class VI wells to further these efforts. 

Letter ID: 0178 Comment ID: 23807 Letter Lines: 270 to 279 

Comment Code: 1380 1.1.3.6 Deployment of GS 

Comment: A. RECOGNITION OF THE IMPORTANCE OF SPURRING THE 

DEVELOPMENT OF CCS TECHNOLOGY 

The Proposed Rule recognizes the value of promoting CCS technology. With further 

modification and a broader scope, these regulations could encourage 

substantially the safe deployment of CCS technologies, support the construction 

of new fossil fuel-fired generation, promote capital formation, and broaden the 

availability of risk management mechanisms for CCS projects. The costs and 

benefits associated with protecting USDWs must be the focus of the Proposed 

Rule, but account has to be taken of the reality that such protection is 

inextricably linked to the mitigation of climate change risk. 

Individual Response: EPA clarifies that the Class VI GS regulations promulgated under Safe 

Drinking Water Act authority do not promote or encourage the use of GS, but, ensure 

consistency in permitting underground injection of CO2 at GS operations across the United 

States and provide requirements to prevent endangerment of USDWs in anticipation of the 

eventual use of GS to reduce CO2 emissions. EPA believes that the Class VI GS regulations, 

11
which build upon the long-standing, protective, regulatory framework of the UIC program, will 

provide the regulatory certainty and clarity that owners or operators have requested. 

EPA acknowledges that there are unknowns associated with early GS project deployment and the 

long-term storage of CO2 for GS. For these reasons, the Agency is using an adaptive approach to 

regulating GS injection. The Agency will, every six years, collect and review data on GS projects 

to determine whether the appropriate amount and types of information and appropriate 

documentation are being collected, and to determine if modifications to the requirements are 

appropriate or necessary. 

Letter ID: 0178 Comment ID: 23808 Letter Lines: 281 to 288 

Comment Code: 1400 1.2 Comments on EPA's Authority to Regulate Injection of CO2 

Comment: B. SDWA AUTHORITY IS LIMITED 

The CCS Alliance agrees with EPA's view of its authority under the SDWA as 

limited to preventing endangerment of USDWs by the underground injection of CO2. 

The Agency properly notes that regulating surface water and atmospheric releases 

is outside the scope of this proposal and SDWA authority. Though EPA regulates 

both pollutants and commodities under the UIC provisions, it is clear that the 

proposal does not address the status of CO2 whether as a pollutant or commodity. 

Individual Response: EPA acknowledges the comment. 

Letter ID: 0178 Comment ID: 23809 Letter Lines: 290 to 300 

Comment Code: 1600 1.3 Risk Associated with CO2 GS 

Comment: C. VIEW OF GS RISKS AND HAZARDS 

The CCS Alliance concurs with the Agency's identification of the risks and 

hazards, to the extent these are understood and can be reasonably predicted, 

that likely are posed by underground injection. The U.S. oil and gas industry, 

as EPA has pointed out. has had decades of experience drilling through highly 

pressurized formations and injecting significant amounts of CO2 for purposes of 

enhanced recovery. The Agency rightly notes that CO2 has been successfully 

injected on much larger scale at several sites outside the United States. 

However, broad scale, large CCS injections pose new considerations, and CCS 

requires site-specific review. 

Individual Response: EPA recognizes that industry has decades of experience with well 

construction and operation. For example, the oil and gas industry has experience drilling and 

cementing wells in very deep formations, in a variety of environments (e.g., high-pressure and 

low-pressure formations), and for a variety of uses (e.g., injection, oil and gas production, 

12
monitoring). EPA believes that this experience has led to the development of well materials and 

construction and operating procedures that are applicable to Class VI wells. 

EPA has taken a regulatory approach that promotes USDW protection, incorporates flexibility or 

the discretion of the permitting authority when appropriate, seeks to limit burden on owners or 

operators and permitting agencies, and provides a foundation for national consistency in 

permitting of GS projects. For example, under the final rule, many of the permit requirements 

must be established through site-specific plans (e.g., AoR and corrective action plan, testing and 

monitoring plan, etc.) developed by the owner or operator and approved by the Director. 

Consequently EPA expects that owners or operators will consult with the Director as they 

develop, implement, and update these plans. Additionally, the Director has the discretion to 

approve alternatives to the requirements in some cases. For example, the Director may in certain 

situations modify the length of the post-injection site care period under §146.93, allow the use of 

alternate methods for mechanical integrity testing (if approved by EPA) under §146.89, and 

waive the requirement that wells be designed to inject below the lowermost USDW under 

§146.95. 

Letter ID: 0178 Comment ID: 23810 Letter Lines: 302 to 312 

Comment Code: 2020 1.5.1 Support Class VI designation 

Comment: D. WELL CLASS APPROACH 

The creation of a new class of wells (Class VI) to cover underground injection 

of CO2 outside the context of EOR (existing Class II or Class V wells already 

permitted are properly left outside the scope of the Class VI proposal) is a 

reasonable approach due to the unique features of CCS, including the low 

viscosity of supercritical CO2, its high buoyancy, and injection volumes that 

could dwarf those of other well classes. There is important recognition that 

such an approach should not impede the development of CCS technology but should 

"support the development of a key climate change" risk "mitigation 

technology".[FN6] The CCS Alliance agrees that where there is an EOR component 

Individual Response: EPA agrees that tailored requirements for Class VI wells are necessary to 

address the unique nature of injecting large volumes of CO2 and to ensure that USDWs are 

protected from endangerment. EPA also agrees that the nature and risks of CO2 injection for 

long term storage is different from Class II CO2 injection for ER, and that tailored requirements 

for GS wells are appropriate and necessary to protect USDWs from endangerment. For this 

reason, the Agency tailored UIC requirements for Class VI wells that address the general risks 

deep injection may pose to USDWs and specifically address the unique nature of CO2 GS (i.e., 

very large volumes, very long time-periods, and reservoir pressure conditions). 

EPA clarifies that the purpose of the GS rule is not to incentivize the use of GS. The purpose of 

the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that does not 

endanger USDWs. 

13
Letter ID: 0178 Comment ID: 23811 Letter Lines: 312 to 314 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: technology".[FN6] The CCS Alliance agrees that where there is an EOR component 

in a project, that project should continue to be permitted and regulated under 

the Class II program. It is also positive that EPA is proposing that Directors 

Individual Response: EPA agrees that injection of CO2 for the primary purpose of enhancing 

oil and gas recovery should remain under the Class II Program. EPA also recognizes that the oil 

and gas industry has decades of experience injecting CO2 for the purpose of ER, and that sites 

used for ER may be suitable for GS and may be among the first GS sites. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary 

purpose of long term storage obtain a Class VI permit with some special consideration for the 

fact that they are transitioning from a well not originally designed to meet Class VI requirements. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. For more information, please see the discussion on 

transition of Class II wells in the preamble to the final GS rule. 

Letter ID: 0178 Comment ID: 23812 Letter Lines: 314 to 322 

Comment Code: 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment) 

Comment: the Class II program. It is also positive that EPA is proposing that Directors 

have authority to grandfather certain requirements for Class V experimental 

project wells and other wells (Class II) when they are converted to full scale 

Class VI wells. The Alliance suggests that EPA should consider whether 

grandfathering the existing siting, AoR, operations, and monitoring plans for 

Class II and Class V wells when they are converted to full scale Class VI wells 

would protect USDWs while avoiding additional regulatory burden. 

[FN6] Proposed Rule, 73 Fed. Reg. at p. 43,495. 

Individual Response: EPA agrees that many Class II wells are designed and constructed to 

withstand exposure to CO2. The final GS rule provides for the construction of these wells to be 

grandfathered per §146.81(c), provided the owner or operator can demonstrate to the Director 

that the wells were engineered and constructed to meet the requirements at §146.86(a) and 

ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies 

that only the construction requirements are grandfathered and that all other Class VI 

14
requirements (reporting, monitoring, mechanical integrity testing, etc.) must be met following a 

determination under §146.81(c). 

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, and AoR requirements) 

should also be grandfathered. Following re-permitting of the project as GS, many of the unique 

factors of GS sites (e.g., increased reservoir pressures associated with large volumes of stored 

CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk profile, 

warranting the specific requirements in the final GS rule. Therefore, following re-permitting as 

Class VI wells, these projects would be subject to the operational, MIT, monitoring, reporting, 

plugging, and post-injection site care and site closure requirements in the final GS rule. See the 

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail 

on these requirements. 

Letter ID: 0178 Comment ID: 23813 Letter Lines: 324 to 344 

Comment Code: 5400 2.9 Proposed Financial Responsibility and Long-Term Care 

Requirements 

Comment: E. REASONABLE LIMITS ON POST-CLOSURE CARE AND ASSURANCES 

AGAINST 

LEAKAGE 

The notion of owners and operators being responsible in perpetuity should 

continue to be avoided. Washington State has instituted the requirement that 

there be a "high degree of confidence that substantially 99 percent of the GHGs 

will remain contained for at least one thousand years."[FN7] Such a standard would 

be inappropriate for CO2 injection wells, and is not related to effects on human 

health or the environment from a potential leak. The CCS Alliance is encouraged 

by EPA's apparent focus on a workable approach to such matters as casing and 

cement quality, and on instituting a monitoring, mitigation and validation 

program that provides assurance of safe, long-term storage, in conjunction with 

setting a defined financial responsibility period that enables financing and 

risk management of CCS. Ultimately, needs associated with risk management of 

emissions to the atmosphere must be balanced against needs to manage risk to the 

water supply, as well as other public policy issues mentioned above. This points 

to why the Alliance suggests an integrated policy management approach to CCS 

technology. 

[FN7] WASH. ADMIN. CODE 173-407-110 (2008) (see definition of "Permanent 

Sequestration") 

Individual Response: EPA notes that SDWA does not contain any provisions addressing 

liability. See the final rule and preamble for further discussion of EPA's final approach to 

financial responsibility for Class VI wells. Under SDWA authority, owners or operators of 

injection wells must ensure protection of USDWs from endangerment and are subject to liability 

for enforcement under the Act. 

15
The final rule requires that an owner or operator conduct monitoring as specified in the Directorapproved PISC and site closure plan following the cessation of injection until the owner or 

operator can demonstrate that the geologic sequestration project no longer poses an 

endangerment to USDWs. For additional information about the PISC and site closure 

requirements, see the preamble to the final GS rule. 

Once an owner or operator has met all regulatory requirements under Part 146 for Class VI wells 

and site closure has been approved pursuant to requirements at §146.93, the owner or operator 

will generally no longer be subject to enforcement for regulatory noncompliance. Furthermore, 

the financial instrument required under §146.85 will be released if it was not used. However, 

even if a site closure is approved under §146.93, an owner or operator may be held liable for 

regulatory noncompliance (including violation of 40 CFR 144.12) in certain circumstances. For 

example, he or she may be held liable for regulatory noncompliance even after site closure if the 

Director relied on erroneous information provided by the owner or operator when approving site 

closure. 

Additionally, an owner or operator may always be subject to any action the Administrator deems 

necessary to protect the health of persons under §1431 of the SDWA after site closure if there is 

unanticipated migration towards or into a USDW that causes or threatens imminent and 

substantial endangerment to public health. The action may include issuing administrative orders 

or commencing a civil action for appropriate relief. If the owner or operator fails to comply with 

the order, he or she may be subject to a civil penalty for each day in which such violation occurs 

or failure to comply continues. 

The Agency clarifies that Class VI well permits may be transferred to another owner or operator 

pursuant to §144.38, whereby all potential liabilities associated with meeting the requirements of 

that permit are transferred. Please see further clarification on the issue of long term liability in 

the preamble of the final rule. 

Furthermore, after site closure an owner or operator may remain liable under tort and other 

remedies, or under other federal statutes including, but not limited to, Clean Air Act, 42 U.S.C. 

§§ 7401-7671; CERCLA, 42 U.S.C. § 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. EPA 

does not have authority to transfer SDWA or other legal liability for Class VI wells to the State 

or federal government or a third-party fund. See the final rule preamble for further discussion of 

EPA's final approach. 

EPA clarifies that standards for containment of carbon dioxide before it is injected are outside 

the scope of this rulemaking. EPA acknowledges the commenter’s support of EPA’s efforts to 

ensure the proper construction and monitoring of GS wells. 

EPA acknowledges that the issue of GS falls within the broader context of CCS. EPA clarifies 

that the Class VI requirements are designed to ensure that, where deployed, GS is conducted in a 

manner that protects USDWs from endangerment. The requirements apply to owners or 

operators of injection wells used to inject CO2 for permanent storage. The Class VI GS 

rulemaking is promulgated under SDWA authority and does not relate to any endangerment and 

16
cause or contribute findings under the Clean Air Act. The Class VI GS requirements do not 

depend upon, and are unaffected by, Clean Air Act endangerment and cause or contribute 

findings. 

Letter ID: 0178 Comment ID: 23814 Letter Lines: 349 to 381 

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment Code: 5400 2.9 Proposed Financial Responsibility and Long-Term Care 

Requirements 

Comment: A. FIFTY YEAR TIME FRAME FOR POST-CLOSURE SITE CARE 

RESPONSIBILITY 

The Proposed Rule states that the timeframe over which CO2 will be trapped 

depends on the properties of the receiving formation and the injected CO2 

stream. Currently available information does not provide a complete 

understanding of the time required to stabilize geologically sequestered CO2 

under various conditions: however, some experience does exist and has led some 

to develop extrapolative estimates for related geologies. Some believe that in a 

significant number of cases, a 10 to 30 year timeframe will be sufficient to 

determine that the remaining pressure in plugged wells will not lift fluid to 

overlying strata. Any uncertainty in characterizing post-injection site care 

timeframes for GS, while challenging, could be dealt with through a maximum time 

period, performance standards, and Director discretion. 

The CCS Alliance recommends establishing a maximum 30-year post-operation site 

care and financial responsibility period. The Director would have discretion to 

shorten -- but not to lengthen -- this period if the owner or operator meets 

certain enumerated performance standards based on available data on pressure. 

fluid movement, mineralization and/or dissolution reactions to show whether 

movement of the plume and pressure front have ceased. Once the thirty-year 

period is reached -- or shorter if the performance standards are met -- a 

government backstop would be triggered, thereby ensuring that a risk management 

mechanism is in place beyond the responsibility of the owner or operator. 

Investment requires assumptions about the amount of capital required and for how 

long it is required. If either the maximum amount of capital or the term cannot 

be established, investment is deterred. Further, because most capital available 

will not commit for terms longer than thirty years, and the duration for which 

it is available is generally inversely proportional to risk. Thus, long term 

capital for even low frequency but high severity risks is difficult to obtain. 

To assure public funds can be leveraged with private investment to assure 

widespread deployment of this climate risk mitigating technology, a balance of 

risk and reward is required in the policy development that underpins this UIC 

regulation. 

Individual Response: EPA disagrees that a post-injection site care timeframe of 50 years is 

17
excessive for most Class VI wells. EPA proposed a default post-injection site care timeframe of 

50 years based on a review of research studies, industry reports, and existing environmental 

programs. This analysis was included in an EPA-prepared background document that is available 

in the federal docket, titled "Computational Modeling of Underground Injection of Carbon 

Dioxide for Determination of Area-of-Review and Potential Risk to Underground Sources of 

Drinking Water." EPA assessed various default timeframes based on additional review of 

research studies and evaluation of public comments. While numerous commenters suggested that 

EPA shorten the monitoring timeframe, none of the commenters provided sufficient data or other 

evidence to warrant a change in the proposed timeframe. While the 10- or 30-year timeframe 

suggested by some of these commenters may be within the timeframe suggested in some studies, 

EPA believes that the potential risks of endangering USDWs will likely not decline within these 

timeframes and available data, including data submitted by commenters, do not support a 

different default timeframe. However, EPA recognizes that alternative timeframes may be 

appropriate under limited, specific circumstances. 

For this reason, the Class VI rule offers owners or operators flexibility regarding the duration of 

the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC 

timeframe during the PISC period based on site-specific data, pursuant to requirements at 

§146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator to 

demonstrate, based on substantial data during the permitting process, that an alternative PISC 

timeframe may be appropriate if it ensures non-endangerment of USDWs pursuant to 

requirements at §146.93(c). 

EPA believes that a 50 year post-injection site care timeframe represents a reasonable and 

protective monitoring period and available data, including data submitted by commenters, do not 

support a different default timeframe. Furthermore, EPA believes that a 50-year default postinjection site care timeframe, as required at §146.93(b)(1), is not overly burdensome, does not 

exaggerate the risks associated with GS, is consistent with other environmental programs, and 

sufficiently protects USDWs from endangerment. 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA disagrees that the requirements on financial responsibility are overly stringent. The goal of 

financial responsibility is to ensure that financial resources are available to prevent the 

endangerment of USDWs from improper plugging, remediation, and management of wells in the 

event that the owner or operator experiences financial difficulties. EPA adds that the purpose of 

the GS rule is not to encourage the use of GS; rather, the purpose of the GS rule is to ensure that, 

where GS is deployed, it is conducted in a manner that protects USDWs from endangerment. 

Letter ID: 0178 Comment ID: 23815 Letter Lines: 383 to 397 

18
Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment Code: 5400 2.9 Proposed Financial Responsibility and Long-Term Care 

Requirements 

Comment: B. POTENTIAL APPLICABILITY OF RCRA AND CERCLA 

As discussed in greater detail below, the potential applicability of RCRA and 

CERCLA is a key concern. These statutes simply are not designed with the thought 

in mind of encouraging the safe and widespread deployment of a new technology. 

The CCS Alliance believes that many parties involved in the CCS chain of events 

should bear responsibility for safe operation. Rather than apply environmental 

statutes with contentious and litigious histories, Congress should enact a new 

regulatory and liability framework for CCS in place of the multiple regimes that 

now may apply. This is not meant to detract from the progress EPA is making in 

this rulemaking. It merely recognizes the limitations and overlapping structures 

EPA itself has noted. CCS should be subject to a single, clear regulatory 

structure, and a single, clear liability structure. In the meantime, EPA should 

use what interpretive authority it has to limit the applicability of multiple 

statutes and provisions, the applicability of which would discourage CCS. 

Individual Response: EPA acknowledges the commenter's concerns regarding the applicability 

of multiple statutes to GS projects and the need for a single clear liability regime for owners or 

operators. EPA is working to create a nationally consistent financial responsibility regime within 

its authority while providing permitting authorities an appropriate level of flexibility. EPA is 

finalizing financial responsibility requirements under authority of the SDWA, which includes the 

authority to set federal minimum requirements for financial responsibility to ensure that 

resources are available to protect USDWs throughout the life of the GS project. 

This authority does not extend to release owners or operators from long-term responsibility 

under other statutes, such as CERCLA, for potential impacts after the PISC period has ended, or 

for the potential economic costs associated with impacts unrelated to USDWs. Under current 

SDWA provisions, EPA does not have authority to transfer liability from one entity to another 

and it does not provide for the creation of a third party financial instrument where EPA is the 

trustee. 

Under SDWA authority, owners or operators of injection wells must ensure protection of 

USDWs from endangerment and are subject to liability for enforcement under the Act. The final 

rule requires that an owner or operator conduct monitoring as specified in the Director-approved 

PISC and site closure plan following the cessation of injection until he or she can demonstrate to 

the Director that the geologic sequestration project no longer poses an endangerment to USDWs. 

For additional information about the PISC and site closure requirements, see the preamble to the 

final GS rule. 

Once an owner or operator has met all regulatory requirements under Part 146 for Class VI wells 

and the Director has approved site closure pursuant to requirements at §146.93, the owner or 

19
operator will generally no longer be subject to enforcement for regulatory noncompliance. 

Furthermore, the financial instrument required under §146.85 will be released if it has not been 

used. However, even if a site closure is approved under §146.93, an owner or operator may be 

held liable for regulatory noncompliance (including violation of 40 CFR 144.12) in certain 

circumstances. For example, an owner or operator may be held liable even after site closure was 

approved if the Director relied on erroneous information provided by the owner or operator when 

approving site closure. 

Additionally, an owner or operator may always be subject to any action the Administrator deems 

necessary to protect the health of persons under §1431 of the SDWA after site closure if there is 

unanticipated migration towards or into a USDW that causes or threatens imminent and 

substantial endangerment to public health. If the owner or operator fails to comply with the 

order, he or she may be subject to a civil penalty for each day in which such violation occurs or 

failure to comply continues. 

The Agency clarifies that Class VI well permits may be transferred to another owner or operator 

pursuant to §144.38 whereby generally all other regulatory responsibilities are transferred to that 

new owner and operator, including all potential liabilities associated with meeting the 

requirements of that permit. 

Furthermore, after site closure an owner or operator may remain liable under tort and other 

remedies, or under other federal statutes including, but not limited to, Clean Air Act, 42 U.S.C. 

§§ 7401-7671; CERCLA, 42 U.S.C. § 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. EPA 

does not have authority to transfer SDWA or other legal liability for Class VI wells to the State 

or federal government or a third-party fund. See the final rule preamble for further discussion of 

EPA's final approach. 

Comments requesting congressional legislation on liability for GS are outside of the scope of this 

rulemaking. 

EPA agrees that identifying and addressing potential barriers to the deployment of CCS, while 

protecting human health and the environment, is important. As described above, making 

legislation changes is outside the scope of the GS rulemaking. Also as described above, EPA has 

decided to initiate a separate proposed rulemaking specifically to examine the issue of RCRA 

applicability to CO2 streams being geologically sequestered, including the possible option of a 

conditional exemption from the RCRA requirements for CO2 GS in Class VI wells. 

Furthermore, EPA is promulgating the GS rule under the authority of the SDWA. To the extent 

the commenter is seeking interpretations of CERCLA and its related provisions, such as the 

definition of a federally permitted release, such interpretations are beyond the scope of this 

rulemaking. 

Letter ID: 0178 Comment ID: 23816 Letter Lines: 399 to 414 

Comment Code: 1435 1.2.1.3 EPA should develop guidance 

20
Comment: C. GUIDANCE FOR EPA REGIONAL ADMINISTRATORS AND STATE 

OFFICIALS 

Broad responsibility and decision making authority is centered in the EPA 

Regional Administrators (for UIC programs administered by EPA) and in non-EPA 

officials (responsible for permitting, implementation and compliance of state, 

territorial or tribal UIC programs). However, no guidance is provided as to how 

these individuals are to exercise such wide discretion. They will have the 

authority to determine whether large pilot projects should be considered Class V 

(experimental) or Class VI wells, but on what basis such a decision is to be 

made is not clear. In accordance with OMB's Final Bulletin for Agency Good 

Guidance Practices,[FN8] EPA should consider developing additional guidelines 

that limit the ability of mid-level officials to implement and alter the program 

without review by the EPA Administrator or other organs of the U.S. Government. 

[FN8] Final Bulletin for Agency Good Guidance Practices, 72 Fed. Reg. 3432 

(Jan. 25, 2007). 

Individual Response: To promote consistency while providing the Director with an appropriate 

level of discretion, EPA is developing guidances for states and tribes that describe the process of 

applying for and receiving primacy for GS Class VI wells under Section 1422 of SDWA, as well 

as the technical and administrative issues associated with developing GS regulations that are the 

equivalent of minimum federal criteria and requirements. These are available on EPA’s website 

at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA intends to take OMB’s Good Guidance Manual into consideration as guidance is developed. 

OMB’s Good Guidance Manual establishes policies and procedures for the development, 

issuance, and use of significant guidance documents by Executive Branch departments and 

agencies. 

Letter ID: 0178 Comment ID: 23817 Letter Lines: 416 to 427 

Comment Code: 1600 1.3 Risk Associated with CO2 GS 

Comment: D. INSUFFICIENT RECOGNITION OF LIKELIHOOD OF TECHNICAL 

ADVANCES 

CO2 injection has been successfully utilized in the EOR process for decades. As 

such, even though CCS technology has not been widely deployed, the technology 

and industry knowledge are nevertheless presently sufficient to commence CCS 

activities. However, significant advances in technology and understanding are 

likely to be made in the future. The Proposed Rule fails to fully recognize or 

otherwise take into account that technology and the state of knowledge almost 

certainly will improve and continue to evolve. EPA, therefore, should better 

reflect that as technology and understanding improves, the risks associated with 

CCS will be reduced and the ability to mitigate remaining risks will be 

21
improved. 

Individual Response: EPA recognizes that technologies will evolve and improve over time, and 

for these reasons, the Agency is using an adaptive approach to regulate GS injection. The 

Agency plans, every six years, to collect and review data on GS projects to determine whether 

the appropriate amount and types of information and appropriate documentation are being 

collected, and to determine if modifications to the requirements are appropriate or necessary. 

Letter ID: 0178 Comment ID: 23818 Letter Lines: 429 to 437 

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones 

(seeking comment) 

Comment: E. SECONDARY CONTAINMENT SHOULD NOT BE REQUIRED 

Secondary containment (i.e., a second formation of "caprock" above the initial 

formation) should not be required because it could limit the eligibility of 

potential storage sites, raise costs due to extra transportation, and add to the 

considerable regulatory burden of regulating site characterization. The 

standards of the Safe Drinking Water Act require that any injection that does 

occur will not result in endangerment of USDWs. This should be sufficient, 

without imposing in addition an arbitrary additional standard. 

Individual Response: EPA clarifies that secondary confining zones are not required for all GS 

sites. Rather, secondary confining zones are required when the Director determines that these 

zones are needed to maximize the protection of USDWs from endangerment. EPA retains the 

requirement to identify additional containment/confining zones, if required by the Director, as 

proposed (e.g., §146.83(b)). EPA believes that, in some situations, the presence of additional 

confining and containment zones above the primary (i.e., lowermost) confining zone can 

improve USDW protection. These layers could further impede vertical fluid movement and 

allow for pressure dissipation, and also provide additional sites for monitoring, mitigation, and 

remediation. EPA disagrees that the requirement would reduce the number of sites available for 

GS. The intent of this requirement is to ensure that a proposed site provides adequate protection 

of USDWs from endangerment; if this protection cannot be demonstrated, the Director would not 

issue a permit for GS at the site. 

The Agency believes that providing the Director discretion will allow consideration of a range of 

sites for GS, based on site-specific conditions and ensure USDW protection. EPA believes that 

requiring appropriate site characterization by the owner or operator (under §146.82) and 

providing an appropriate degree of flexibility to the Director to evaluate site-specific geologic 

data will afford the greatest protection of USDWs from endangerment. 

Letter ID: 0178 Comment ID: 23819 Letter Lines: 439 to 451 

22
Comment Code: 4410 2.4.4.3.1 Comments in favor of allowing injection above/between 

USDWs in certain circumstances 

Comment: F. GEOLOGIC SEQUESTRATION OF CO2 NEED NOT BE, IN EVERY 

INSTAKCE, BENEATH THE 

LOWERMOST FORMATION CONTAINING A USDW 

Geologic sequestration of CO2 need not be, in every instance, beneath the 

lowermost formation containing a USDW, as is the case with Class I wells. Such a 

requirement likely would preclude injection into certain targeted geologic 

formations, which may include storage sites currently under consideration for 

GS. The Director should be given discretion, but to act in accordance with 

guidelines, to allow injection above or between USDWs in specific geological 

settings where the depth of the USDW would preclude GS and where there are 

thousands (or only hundreds) of feet of rock strata between the injection zone 

and the underlying or overlying USDW. This could in many instances open up more 

areas for CO2 storage without endangering USDWs. 

Individual Response: EPA acknowledges that there are limited circumstances where injection 

above the lowermost USDW can be performed in a manner that protects USDWs from 

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 

establishes a process by which owners or operators can seek a waiver of the Class VI injection 

depth requirements for injection into non-USDW formations above and/or between USDWs. 

Additionally, the final GS rule does not categorically preclude or prohibit injection into any type 

of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to 

UIC program Directors and owners or operators who undertake CO2 injection for GS. The 

Agency believes this approach: 1) responds to concerns about local and regional geologic storage 

capacity limitations imposed by the proposed injection depth requirements; 2) allows for a more 

site-specific assessment of injection depth for GS projects; 3) accommodates injection into 

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or 

between USDWs when appropriate and where it can be demonstrated that USDWs will be 

protected; and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, 

EPA’s approach to addressing injection depth variability through a waiver process responds to 

concerns about future drinking water resource availability and the need to ensure that high 

quality water remains available in sufficient quantities to supply drinking water needs. For 

additional information on the waiver approach, please see the final rule and preamble, as well as 

EPA's responses to comments on the Notice of Data Availability and Request for Comment. 

EPA clarifies that all decisions regarding injection depth waivers will be at the Director's 

discretion and based on site-specific information. EPA is developing guidance on the injection 

depth waiver process. The guidance describes the recommended approach an owner or operator 

may follow when submitting a waiver application, processing waiver applications by the UIC 

and PWSS Program Directors, and additional processes that may apply to projects that have been 

23
issued waivers. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0178 Comment ID: 23820 Letter Lines: 453 to 458 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 1230 1.1.1.2 General comments on the regulatory text 

Comment: G. VAGUE LANGUAGE AND DEFINITIONAL PROBLEMS 

There are many words and phrases in the draft regulations that are not well 

defined, and the meaning of which ought to be expanded upon. For instance, what 

might constitute "significant leakage" in the context of mechanical integrity 

testing should be identified. 

Individual Response: A properly designed and operated well should have no leakage in the 

casing, tubing, or packer and no fluid movement into a USDW through channels adjacent to the 

wellbore. While the intent of MITs is to detect these types of problems as early as possible, the 

goal of the well design and construction requirements at §146.86 is the complete absence of such 

problems. EPA clarifies that the purpose of the "significant leakage" language in this narrow 

context is simply to avoid triggering corrective actions for essentially de minimis situations. 

Determining whether a MIT result should trigger follow-up action is necessarily a case and sitespecific situation; as a result, EPA does not believe it is appropriate to define the term 

"significant leakage" in the context of MITs. In addition, EPA has not defined this term for 

purposes of other injection well classes and this has not been shown to hinder permitting 

authorities' and owners or operators' ability to assess whether injection wells have adequate 

mechanical integrity. EPA believes that this approach allows states flexibility, will not interfere 

with the implementation of existing UIC programs, and maintains protection of USDWs from 

endangerment. 

The final definition of mechanical integrity is unchanged. EPA clarifies that mechanical integrity 

is defined at §146.89(a) as the absence (1) of significant leak in the casing, tubing, or packer and 

(2) of significant fluid movement into a USDW through channels adjacent to the injection 

wellbore. 

Based on its evaluation of all public comments and input on the proposed rule and the NODA 

and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 0178 Comment ID: 23821 Letter Lines: 460 to 464 

Comment Code: 4000 2.4 Proposed Injection Well Operating Requirements (40 CFR 146.88) 

Comment: H. NON-COMPLIANCE 

24
If a site is not in compliance, there should be no requirement that injection 

cease immediately, unless an imminent threat of harm to human health or the 

environment is posed. 

Individual Response: EPA disagrees with the commenter, and believes that the requirement at 

§146.88(f) to cease injection immediately upon indication of a mechanical integrity loss is 

necessary and appropriate because loss of mechanical integrity can signal problems which could 

lead to a loss of integrity or well failure and potential leaks of CO2 that may cause endangerment 

to a USDW. While there may be circumstances in which a well appears to lack mechanical 

integrity but actually poses no risk, such a determination cannot be made without an 

investigation. It would be inadequate for purposes of protecting USDWs from endangerment to 

require that injection cease only when there was an imminent threat of harm to human health or 

environment. 

Letter ID: 0178 Comment ID: 23822 Letter Lines: 467 to 475 

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment: VI. SPECIAL FOCUS: FINANCIAL ASSURANCE AND LONG TERM SITE 

RESPONSIBILITY 

Financial assurance and long-term site responsibility are an area of special 

focus for the CCS Alliance. As noted above. we believe the proposed 50-year time 

frame for site care responsibility after a GS facility has ceased operation is 

too long, and there should be a known end point fur site care responsibility up 

front. In addition to these concerns, we offer the following comments on 

financial assurance. 

Individual Response: EPA disagrees that a post-injection site care timeframe of 50 years is 

excessive for most Class VI wells. EPA proposed a default post-injection site care timeframe of 

50 years based on a review of research studies, industry reports, and existing environmental 

programs. This analysis was included in an EPA-prepared background document that is available 

in the federal docket, titled ""Computational Modeling of Underground Injection of Carbon 

Dioxide for Determination of Area-of-Review and Potential Risk to Underground Sources of 

Drinking Water."" EPA assessed various default timeframes based on additional review of 

research studies and evaluation of public comments. While numerous commenters suggested that 

EPA shorten the monitoring timeframe, none of the commenters provided sufficient data or other 

evidence to warrant a change in the proposed timeframe. While the 10- or 30-year timeframe 

suggested by some of these commenters may be within the timeframe suggested in some studies, 

EPA believes that the potential risks of endangering USDWs will likely not decline within these 

timeframes and available data, including data submitted by commenters, do not support a 

different default timeframe. 

However, EPA recognizes that alternative timeframes may be appropriate under limited, specific 

circumstances. For this reason, the Class VI rule offers owners or operators flexibility regarding 

the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or 

25
lengthen the PISC timeframe during the PISC period based on site-specific data, pursuant to 

requirements at §146.93(b); or (2) affording the Director discretion to allow a Class VI well 

owner or operator to demonstrate, based on substantial data during the permitting process, that an 

alternative PISC timeframe may be appropriate if it ensures non-endangerment of USDWs 

pursuant to requirements at §146.93(c). 

EPA believes that a 50 year post-injection site care timeframe represents a reasonable and 

protective monitoring period and available data, including data submitted by commenters, do not 

support a different default timeframe. Furthermore, EPA believes that a 50-year default postinjection site care timeframe, as required at §146.93(b)(1), is not overly burdensome, does not 

exaggerate the risks associated with GS, is consistent with other environmental programs, and 

sufficiently protects USDWs from endangerment. 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters¿ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA recognizes that there are challenges associated with assuring funding for activities that will 

occur far in the future. However, the Agency believes that in order to protect USDWs from 

endangerment under the SDWA operators must demonstrate under §146.85 that financial 

resources are available to plug the injection well and provide post-injection site care at the point 

in time that the first CO2 is injected. 

EPA also recognizes the concerns associated with assuring financial responsibility for the long 

time frames over which post-injection site care will be conducted. EPA is developing guidance 

on financial responsibility to assist owners or operators in evaluating the requirements of 

§146.85 and to assist Directors in evaluating financial responsibility demonstrations. The 

guidance describes the types of financial mechanisms that operators may choose to use when 

evaluating the financial responsibility requirements for GS wells and it will also include a section 

on how to estimate costs to support accurate financial responsibility demonstrations. The 

guidance will be available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0178 Comment ID: 23823 Letter Lines: 477 to 548 

Comment Code: 5400 2.9 Proposed Financial Responsibility and Long-Term Care 

Requirements 

Comment: A. THE PURPOSE OF FINANCIAL ASSURANCE 

EPA's Geologic Sequestration Stewardship paper, released in conjunction with the 

Proposed Rule in July, states that the purpose of financial assurance is "to 

26
minimize the number of facilities that are orphaned and abandoned; thereby, 

reducing the potential that these costs will be borne by the public."[FN9] 

[FN9] U.S. ENVIRONMENTAL PROTECTION AGENCY, Approaches to Geologic 

Sequestration 

Site Stewardship After Site Closure, n.2 (July 2008). 

This goal must be considered in the context of the facts surrounding CCS. It is 

an activity the government wants to encourage, the risks attendant to which may 

be significant if they occur but likely are of low probability, and for which 

the private risk management market will not cover the full amount or duration of 

the risks. To fail to implement CCS at this juncture, is not an option if we are 

to serve other public priorities, such as addressing climate change and energy 

security, which depends in part on utilizing domestic resources like coal. For 

CCS to occur on a broad-scale basis, "costs," in the form of long-term risk, 

will have to be borne by the public. A question is how to define and shape the 

public role. 

Insuring or otherwise managing risk at a complex industrial facility requires 

specialty risk products, not ordinary property and casualty coverage.[FN10] In the 

broader environmental risk insurance market, only four or five insurers offer 

products. In the energy market, the number is roughly the same. Private risk 

managers must have experts in place with appropriate perspective to analyze the 

risks and calculate probabilities of the activity. Few risk management entities 

likely will develop this capability for CCS. Each may be willing to take a 

portion of the risk with respect to an individual project. However, consider 

that today there are 1,493 coal-fired electric generating units in the United 

states.[FN11] This suggests a large potential need for risk management mechanisms. 

[FN10] Chiara Trabucchi and Lindene Patton, Storing Carbon: Options for 

Liability Risk Management, Financial Responsibility, B N A Daily Environment 

Report at p.9 (Sept. 3, 2008). "Because CCS is what the financial services 

sector would call a specialty risk. only a small part of the sector would be 

equipped and qualified to analyze the risks and place capital thereon." 

[FN11] Energy Information Administration. Electric Power Annual, Existing Capacity 

by Energy Source, Table 2-2 (Oct. 22, 2007). 

Forecasting for CCS can be difficult because there is no established track 

record in some formations where GS is envisioned to occur, such as deep saline 

aquifers, or on the scale envisioned for facilities generating electricity. Each 

risk management company will have differing conditions under which it will or 

will not accept risk. These might be based on factors such as geography, due 

diligence in siting, formation pressure and chemistry, type of geologic 

formation, proximity to population, and the applicable legal and liability 

regimes. These factors are not yet actual factors, as CCS as envisioned by 

27
policymakers has yet to emerge, but are based on the considerations in other 

fields. 

Companies may further specialize in the layer of risk they are willing to 

accept. For example, one risk management company may be comfortable writing 

coverage for the initial tranche of risk - perhaps the first $30 million in 

potential damages, above the first $10 million, which it may require that the 

policyholder bear. Another may be willing to write coverage for the next $30 

million, liability for which would only arise if damages were beyond the $40 

million borne by the policy holder and the first insurer. Others may not be 

willing to provide coverage until after the first $100 million or more in risk 

is covered. A small pool of reinsurers may be willing to help further spread 

some of these risks. 

In considering financial assurance requirements, EPA and stakeholders should 

distinguish financial assurance from liability. Regardless of the length of time 

EPA establishes in the final rule for a GS facility owner or operator to 

maintain financial instruments to pay to clean up potential USDW contamination, 

liability for such cleanup may last longer, depending on which statutory 

provisions are applicable, as well as state law. While EPA is limited in its 

ability to address potential liability, it should seek to do so, as findings of 

the Risk Study conducted by the CCS Alliance (discussed below) show that 

potential long-term liability is a significant barrier to CCS development. 

Individual Response: As described above, the goal of financial responsibility is to ensure that 

financial resources are available to prevent the endangerment of USDWs from improper 

plugging, remediation, and management of wells in the event that the owner or operator 

experiences financial difficulties, not to encourage or discourage the use of GS. 

Regarding the availability of financial responsibility providers, EPA anticipates that the 

availability of a variety of financial responsibility providers and third-party GS financial 

instruments will grow in response to demand. In addition, EPA plans to allow owners or 

operators the flexibility to choose from a variety of financial instruments in order to meet the 

requirements at §146.85. 

EPA acknowledges that financial responsibility and long-term liability are separate issues. EPA 

clarifies that SDWA does not contain any provisions addressing liability. However, consistent 

with the policy of the UIC program, the financial responsibility provisions provided in the GS 

rule are intended to ensure the owner or operator will be liable for remediating or correcting any 

endangerment of USDWs via their demonstrated financial instrument up through site closure. 

See the final rule and preamble for further discussion of EPA's final approach to financial 

responsibility for Class VI wells. 

Letter ID: 0178 Comment ID: 23824 Letter Lines: 550 to 616 

Comment Code: 5400 2.9 Proposed Financial Responsibility and Long-Term Care 

28
Requirements 

Comment: B. CONSIDERATION IN VIEWING RISK 

Risk managers - insurers, sureties, banks, and others - will determine whether 

to provide financial assurance based on a calculation of the severity of risks 

and probability that they will occur over a given time period and the terms and 

conditions of the obligation. 

The severity and probability of risk is defined not just by physical dimensions, 

such as fractures and leaks, but by the regulatory and liability structure that 

is in place. A party may be in violation of a rule or may trigger large 

potential liability, notwithstanding that the risk to USDWs or human health or 

the environment may be minimal. 

One may look at the risks of a CCS project in two ways: by the activity being 

performed in the CCS chain (i.e.. generation, compression, transportation, 

injection, long-term storage), or by the phase of the project (i.e., operation, 

closure, post-closure). The CCS activity being performed, as well as other sitespecific conditions, will affect the availability of risk management products: 

In the context of CCS, different risks are likely to present themselves 

at different stages during the facility's life-cycle. resulting in a 

range of consequences the financial materiality of which will depend on 

the site-specific characteristics and location of each CCS project. For 

these reasons, different phases of the CCS process will warrant 

different financial (risk) management mechanisms." 

[FN12] Chiara Trabucchi and Lindene Patton, Storing Carbon: Options for 

Liability Risk Management, Financial Responsibility, B N A Daily Environment 

Report at p. 3 (Sept. 3,2008). 

Some risks will be more easily addressed by the market than others. Risks in the 

generation and carbon capture phase are manageable under standard mechanisms 

such as bonds and insurance, or are retained by the operator. The same is true 

for risks during the transportation phase.[FN13] However, the long-term storage 

phase presents a set of risks the duration of which is beyond the scope of the 

market. The market will not take on liabilities beyond a defined amount for a 

defined period. Granger Morgan of Carnegie Mellon University's CCS Regulatory 

Project said, "[t]hey don't know how to write a policy that goes on forever." 

[FN14] It is not a matter of knowing how - it is a matter of not being willing 

to provide risk management for such duration. 

[FN13] Id. at 9. 

[FN14] Evan Lehmann, Wanted: 1,000 Year Insurance Policy, ClimateWire, Aug. 19, 

29
2008, http://www.eenews.net/climatewire/2008/O8ll9ll/. 

Underwriters look to a variety of factors in determining whether to offer a 

risk management product, what its features and conditions will be, and how to 

price it: 

An underwriter will look to the fundamentals of the technology itself 

when undertaking risk analysis. Technical specialists are assigned (such 

as engineers, geologists, chemists or the like) to develop an 

understanding of the technology's functionality and its potential 

failure points. The underwriter will ask for testing and performance 

data, including the conditions of performance - especially scale. In the 

area of technology, scalability presents substantial risk for many 

reasons, including - but not limited to - basic theory extensions, 

specific chemical or physical behavioral changes associated with volume 

or environmental factors (such as temperature or humidity) and supplychain risks, to name a few.[FN15] 

Many of these issues are key considerations in evaluating CCS risks. As noted 

above, few risk management companies may undertake to develop this information. 

[FN15] Lindene Patton, Beyond Rising Sea Levels, THE EUROPEAN BUSINESS REVIEW 

(Mar./Apr. 2008). 

Individual Response: EPA is developing guidance on financial responsibility for Class VI 

wells. The guidance will include a discussion on how best to estimate costs to assist GS well 

owners or operators, third party insurers or providers of financial instruments, and permitting 

authorities in developing estimates of the costs associated with various GS activities. EPA will 

also discuss how best to evaluate the appropriateness of single and multiple bonding and phased 

release of bonds in the guidance. This guidance will be available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

The final rule provides owners or operators the option to use separate financial responsibility 

instruments for different GS activities and project phases. However, owners or operators must 

demonstrate adequate financial responsibility for all required activities with their permit 

application, per §146.82(a)(14). In addition, on an annual basis, the owner or operator must 

adjust the cost estimate for inflation, increase or decrease the value of the financial instrument to 

match the cost estimate, and provide any updated information related to their financial 

responsibility instrument(s), or at any other time deemed appropriate by the Director. These 

annual reviews provide mechanisms for revising cost estimates up or down to account for 

changes in the project, including the execution of environmental obligations as phases of a GS 

project are completed. 

EPA clarifies that SDWA does not contain any provisions addressing liability. However, 

consistent with the policy of the UIC program, the financial responsibility provisions provided in 

the GS rule are intended to ensure the owner or operator will be liable for remediating or 

30
correcting any endangerment of USDWs via their demonstrated financial instrument up through 

site closure. See the final rule and preamble for further discussion of EPA's final approach to 

financial responsibility for Class VI wells. 

See the final rule and preamble for further discussion of EPA's final approach to financial 

responsibility for Class VI wells. 

As described above, EPA anticipates that the availability of a variety of financial responsibility 

providers and third-party GS financial instruments will grow in response to demand. EPA adds 

that other aspects of CCS, e.g., capture and transport of CO2, are outside the scope of the GS 

rule. 

Letter ID: 0178 Comment ID: 23825 Letter Lines: 618 to 720 

Comment Code: 1600 1.3 Risk Associated with CO2 GS 

Comment Code: 5400 2.9 Proposed Financial Responsibility and Long-Term Care 

Requirements 

Comment: C. WHAT MARKET PARTICIPANTS SAY ABOUT RISK 

The framework for approaching the commercial risk in the development and 

deployment of coal-based projects with CCS is demonstrated by the following 

chart: 

For Development of Coal Based Charts with CCS Approach to Commercial Risk 

Framework [Please see Comment Pdf for Graphic, pg. 20] 

The CCS Alliance has evaluated technical, market, and policy risks associated 

with CCS deployment. On behalf of the CCS Alliance, Andrew Paterson of Econergy 

International interviewed dozens of market participants earlier this year, 

including project developers, utilities, technology vendors, risk managers, and 

financial providers to assess which risks were considered most likely to occur, 

and which, if they occurred, would be considered to have the greatest impact to 

the project. 

The results can be viewed graphically in a Cartesian coordinate analysis, as follows: 

Which Risks Matter? Which Will the Market Handle? Probability vs. Impact [Please 

see Comment Pdf for Graphic, pg. 21] 

The CCS Alliance analysis confirms that market participants concur with the view 

of the Intergovernmental Panel on Climate Change ("IPCC") that physical risks 

such as an operating accident or geologic sequestration site failure are low 

probability, high impact risks.[FN16] However, they view as higher probability the 

risk of policy failure. 

[FNl6] IPCC, Special Report on Carbon Dioxide Capture and Storage (2005). IPCC 

31
report states that there is only a one percent chance that CO2 would escape into 

the atmosphere in 100 years. 

In the CCS Alliance Risk Study, the highest rated risks for companies and 

investors considering investment in projects with CCS were focused on: 

- Higher capital costs for capture, compression, transport, injection and 

storage. 

- Uncertainty about the extent and timing of legislation and regulations for 

carbon emission constraints - in other words, a regulatory basis for pursuing 

CCS at all. 

- Unclear rules at the federal and state level for CCS injection (which the UIC 

Proposed Rule is seeking to address), creating some uncertainty about specific 

liabilities. 

- Lack of clarity about long-term ultimate liability for CO2 leakage after 

injection and storage for some commercially relevant time period (e.g., 10 to 30 

years). The Proposed Rule also seeks to address this issue. 

- Electricity (or fuel) prices - in the regional market or set by state utility 

commissions - which are too low to cover costs for CCS. 

Some mechanisms, as either subsidies or for risk transfer, exist to address 

these issues, but as depicted in the table below, they are concentrated in the 

area of either reducing capital costs and other CCS related expenses, or in 

dealing with electricity rates and adjusting revenues in some manner. Subsidies 

to cover higher costs include: federal grants for new facilities, tax credits, 

and state grants. Other mechanisms, such as a federal loan guarantee (Section 

1703 of EPAct 2005) or rate-basing a plant with CCS, remove substantial risk for 

capital recovery by providing alternative recovery or prevention of default. 

Mechanisms (vs. Capital Risks) -- [Please see Comment Pdf for Graphic, pg. 23] 

Because substantial exposure to some critical risks remains, additional 

mechanisms and regulatory clarification are needed to garner the scale of 

investment and capital recovery needed for commercial entities to deploy major 

facilities with CCS. As summarized in the table above, clarifying injection and 

transport rules clearly help, and can be coordinated with private insurance, 

trust funds or bonding, and state revolving funds. Additionally, some clarity on 

carbon emission regulations would eventually enhance the value of assets with 

CCS, and help attract capital for construction in the first place. Without 

capital investment, no CCS will be implemented because it is an inherently 

capital-intensive activity primarily involving facilities costing more than $1 

billion. 

32
But, there is no private instrument that can bear "indefinite, long-term 

liability" for leakage from CCS sites because commercial enterprise carries a 

finite horizon for investment. The EPA UIC program does wield a regulatory 

incentive, though, in negotiating or retaining some flexibility on the point 

(e.g., 10 years versus 50 years) at which liability for long-term leakage is 

assumed by the federal holder after injection. 

Results of the CCS Alliance Risk Study are summarized in the following chart. 

Note that in addition to the concern noted earlier about state CCS regulations 

and liability policies, one of the issues scoring the highest risk factor is 

that EPA regulations on underground injection of CO2 and liability fail to offer 

clarity for financing. Lack of clarity could prove to be a "showstopper." EPA 

should do its utmost to use its statutory authority to reduce this risk through 

this rulemaking. 

Far Deployment of Coal-based Projects with CCS Risk Study: Technical, Policy, 

Market Risks -- [Please see Comment Pdf for Graphic, pg. 24] 

This information is buttressed by the recently published findings of the 

Government Accountability Office ("GAO") which, in part, concludes that 

regulatory and legal uncertainties, including questions about liability 

concerning CO2 leakage and ownership, are primary barriers to CCS 

deployment.[FN17] 

[FN17] GOVERNMENT ACCOUNTABILITY OFFICE. GAO-OX-1080, CLIMATE 

CHANGE: FEDERAL. 

ACTIONS WILL GREATLY AFFECT THE VIABILITY OF CARBON CAPTURE AND 

STORAGE AS A KEY 

MITIGATION OPTION (2008). 

Individual Response: EPA acknowledges the comment on market risk. This comment is outside 

the scope of the UIC Program’s authority under the GS rulemaking. However, EPA clarifies that 

the final rule, at §146.85, provides more detailed requirements on financial responsibility for 

risks associated with injection. 

Letter ID: 0178 Comment ID: 23826 Letter Lines: 722 to 785 

Comment Code: 5400 2.9 Proposed Financial Responsibility and Long-Term Care 

Requirements 

Comment: D. PRINCIPLES FOR A RISK MANAGEMENT REGIME FOR CCS 

Recognizing that it must act within the confines of its authority under the 

SDWA, and with the goal in mind of protecting USDWs, EPA should consider the 

following principles in constructing a financial assurance program. 

33
One means of encouraging adequate financial assurance is for regulators to (1) 

require site operators to provide accurate, comprehensive and current 

information on costs for closure, post-closure and corrective action activities; 

and (2) ensure that stakeholders have the means to verify those estimates. 

Moreover, the Alliance seeks to remind EPA that no type of financial assurance 

instrument can meet regulatory demands for an unrealistically long coverage time 

period that extends beyond the willingness of capital markets to accept covered 

risks for such periods. With these concepts in mind, regulations can be 

developed to ensure that funds will be readily available, and in the amount 

necessary, to cover costs associated with environmental obligations in the event 

that owner/operators of underground injection sites are unable to meet their 

financial responsibilities. 

1. Clear, Reasonable, and Limited Regulatory and Liability Structure 

EPA should use its discretion, to the extent practicable, to establish a single, 

clear, and reasonable regulatory structure. CCS developers will be willing to 

abide by reasonable rules that protect human health and the environment, but 

society should not bear enhanced costs resulting from requirements that do not 

contribute to health and environmental protection. Nor do developers and risk 

managers want to face liability via multiple State and federal statutory and 

common law pathways, with the possibility of unnecessarily expensive and 

contentious remedies. EPA should use its discretion, to the extent practicable, 

to provide a single, clear, reasonable liability regime. As these goals likely 

will require some legislative action, EPA also should educate Congress on the 

need for regulatory and liability regimes with these characteristics. 

2. Allow a Broad Array of Financial Assurance Instruments 

Since private market financial assurance may be scarce for some CCS phases, EPA 

should be flexible in the type of financial assurance instruments it authorizes 

and needs to encourage the development of financial assurance offerings for CCS. 

The Proposed Rule discusses four financial assurance/risk management instruments 

and requests comment on others. 

Generally, the CCS Alliance believes policy should foster a broad array of means 

whereby a regulated entity can satisfy financial assurance. Both regulators and 

site owner/operators will benefit from broad availability of an innovation in 

offering different types of financial assurance instruments. Increased 

competition may reduce the cost of obtaining these assurances as much as market 

conditions will permit. Each instrument has specific characteristics and may 

play a different role in addressing CCS risks. It should be noted that in 

difficult economic environments (e.g., contractions of available capital in the 

market), the capital markets may make less money available for new types of 

projects, especially if the risk profile is unclear, which could mean that 

arranging financial assurance for CCS may be difficult in the near term. 

34
One issue that applies to a variety of financial assurance instruments is the 

creditworthiness of the issuer. While EPA should seek satisfaction that the 

issuer is on sound financial footing, it should avoid unduly restrictive 

standards, or standards beyond the control of the issuer. For example, Bureau of 

Land Management regulations require that insurance providers offering financial 

assurance "must have an A.M. Best rating of 'superior' or an equivalent rating 

from a nationally recognized insurance rating service."[FN18] Such standards may 

dramatically contract the pool of available issuers, especially during difficult 

economic times. Creditworthiness standards should consider both ability to pay 

and the availability of cost-effective financial assurance. 

[FN18] 43 CFR 3809.555(f). 

Individual Response: EPA believes that all of the requirements for owners or operators of Class 

VI wells, including the financial responsibility requirements, are for the purpose of protecting 

human health and the environment as it pertains to protection of USDWs. Furthermore, the final 

rule addresses comments concerns regarding the need to provide a financial assurance program 

while working within the confines of the SDWA. 

As described above, EPA is working to create a nationally consistent financial responsibility 

regime within its authority while providing permitting authorities an appropriate level of 

flexibility. However, under current SDWA provisions, EPA does not have authority to transfer 

liability from one entity to another. 

Under §146.85 provides the owner or operator the option to demonstrate financial responsibility 

by using a broad array of financial instruments. Furthermore, the owner or operator must 

maintain financial responsibility and resources until approved site closure while also providing 

detailed up to date written estimates of the cost of performing corrective action, plugging the 

injection wells, PISC and site closure, and emergency and remedial response. 

Furthermore, EPA’s financial responsibility guidance (see below) will provide recommendations 

for generating such cost estimates. EPA also agrees that stakeholders should be able to verify 

such estimates. As described above, EPA anticipates that the availability of a variety of financial 

responsibility providers and third-party GS financial instruments will grow in response to GS 

technology demand. 

Letter ID: 0178 Comment ID: 23827 Letter Lines: 787 to 843 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: a. Trust Funds 

The Alliance supports the concept of trust funds as reserves to address CCS 

liabilities for long-term stewardship. Properly structured, trust funds can be 

35
valuable tools in this area. 

A valuable feature of a trust fund is that a large reserve may be accumulated 

gradually. Costs can be spread over time. EPA has focused on the obverse of this 

issue - that in early years, a trust fund may not be sufficiently capitalized to 

address all the risks that may arise. EPA has proposed that trust funds have a 

three-year pay-in period. EPA should not impose such limitations, for two 

reasons. First, while it is possible that an incident may occur that would 

result in a demand on the fund in early years, many consider that risks are 

likely to be lower in the early phases of injection. Second, and more 

importantly, given that the private risk management market appears unlikely to 

be able to address all risks, EPA should encourage development of mechanisms 

that can address any portion of the risk. A three-year pay-in period arbitrarily 

restricts a potentially valuable tool with a heavy early payment burden. EPA 

should allow flexibility in trust fund arrangements, and can link the credit it 

gives to financial assurance through trust funds to the amount available in the 

fund. 

Long-term, EPA and other policy makers should consider the possibility that too 

large an amount might be accumulated in trust funds, relative to the risks they 

are designed to cover. A recently released assessment of a $1 per ton tipping 

fee for CO2 sequestration, at levels required under WRE450 and WRE550 climate 

policies, would accumulate up to $1.5 trillion by the time the first 100 CCS 

facilities reach the end of their useful lives.[FNl9] Such misplaced wealth 

storage is not economically sound. Furthermore, in light of the history of trust 

funds managed by the federal government, it would provide an unfortunate 

temptation for policy makers with other fiscal priorities. 

[FN19] James J. Dooley, Chiara Trabucchi, and Lindene Patton, Tipping Fees Can't 

Save us from the Tipping Point: The Need to Create Rational Approaches to Risk 

Management that Motivate Geologic CO2 Storage Best Pmctices . ScienceDirect, 

GHGT-9, November, 2008. 

Observers have suggested fees to capitalize CCS trust funds with a number of 

different structures. The type of mechanism or amount of the fee should not be 

of concern to the EPA, but should be addressed by the policy makers establishing 

the trust. It may be that multiple trust funds could be applicable for portions 

of the risk associated with a CCS facility or facilities. 

Both private and government-run trust funds may arise. EPA should ensure sound 

management of trust funds, but does not need to limit parentage. Again, 

innovation should be and will need to be encouraged. The trusts could be 

privately administered in compliance with state insurance regulations; in this 

way, the state has final governance authority by charter status, while private 

industry can bring fiduciary and engineering analysis resources to bear which 

would be expensive for the states to match. 

36
Trust funds also could be structured to provide incentive for risk-mitigating 

behavior. As an example, their terms might be structured to limit eligibility to 

projects whose siting or operations meet superior standards. 

Again, EPA should encourage development of trust funds, rather than artificially 

limit them. 

Individual Response: EPA acknowledges that there may be several possible approaches to 

setting pay-in periods for trust funds while still ensuring financial resources are available to 

protects USDWs from endangerment. The final rule requires that the Director approve the use 

and length of pay-in periods. 

Furthermore, EPA is developing guidance (available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) that describes the types of 

financial instruments that owners or operators can use to meet financial responsibility 

requirements for GS wells. Specifically, the guidance will discuss pay-in periods and provide 

guidance for Directors to use in determining an appropriate pay-in period. EPA adds that owners 

or operators may choose from a variety of financial instruments to meet their financial 

responsibility needs. 

Under SDWA, EPA has the general authority to set financial responsibility requirements for 

injection well owners or operators to ensure that adequate resources are available to protect 

USDWs throughout the life of the GS project. However, this authority does not extend to 

allowing the Agency to create a financial instrument with EPA as the trustee, due to the 

restrictions of the Miscellaneous Receipts Act (MRA). The MRA requires that EPA deposit the 

funds it receives for the use of the Government into the Treasury, therefore funds would not 

necessarily be available for GS financial responsibility. 

Additionally, EPA does not have authority under SDWA to establish a trust fund for purposes of 

financial responsibility for Class VI projects. The Agency clarifies that the trust funds that are 

addressed as financial responsibility instruments on the GS rule are set up by individual owners 

or operators and are different from a national-level trust described by the commenters that would 

cover large numbers of GS projects. 

Letter ID: 0178 Comment ID: 23828 Letter Lines: 845 to 876 

Comment Code: 5434 2.9.1.2 Need for additional instruments (seeking comment) 

Comment: b. Insurance 

Insurance should be authorized as a risk management tool for CCS. Insurance for 

CCS liability is a "specialty" product. Specialty underwriters generally are 

well-trained to focus on the environmental risks involved with each facility, 

and insurance provides full coverage for the financial assurance risk from 

policy inception forward. 

37
EPA appears to be approaching insurance guardedly, noting that the "insurance 

mechanism was and still is. rarely used for the purpose of demonstrating 

financial assurance for injection wells." EPA should provide guidance for the 

use of insurance. 

EPA should be careful to avoid several problems that have made insurance less 

available and more expensive in the past. For example, regulators typically 

require an insurance policy to be written to require payment to an entity 

designated by the regulator, rather than to the insured. The requirement to pay 

the regulator or a designated agency creates potential for "double payment" - 

both to the regulator, and as a result of state law, to the insured. EPA should 

address this problem by making possible clear designation of sole beneficiary 

status, and allowing parties to contract for express waivers by policyholders of 

their payment rights, where the regulator requires a different beneficiary. 

Another problem is that regulators often prohibit cancellation of a policy if an 

operating permit is revoked or if the operator seeks bankruptcy protection, even 

if continued premium payments do not occur. Such a prohibition drives up the 

cost of insurance, "front-loads" insurance costs as insurers require up-front 

payments, and reduces insurers' willingness to offer policies. 

Since, as noted above, some risks associated with CCS will be beyond the 

market's willingness to bear, EPA should allow insurance to be arranged on terms 

that will encourage its availability. It should encourage the private risk 

management market to address as much risk as possible. 

Individual Response: EPA will retain self insurance as an option for financial responsibility for 

Class VI wells. EPA believes that if properly used, the financial test can be an appropriate option 

for some owners or operators. EPA recognizes that it is important for self-insurers to be creditworthy, otherwise USDWs may not be adequately protected. Owner or operators who choose to 

self-insure and use the financial test must be able to demonstrate profitability, with a margin 

sufficient to cover contingencies and unknown obligations, and stability. If the owner or operator 

meets corporate financial test criteria, this is an indication that the owner or operator can 

guarantee its ability to satisfy financial obligations based solely on the strength of the company’s 

financial condition. If an operator or operator is not able to meet the corporate financial test 

criteria may arrange a corporate guarantee by demonstrating that its corporate parent meets the 

financial requirements on its behalf. 

EPA is developing guidance that describes the types of financial instruments, including 

insurance, which owners or operators can use to meet financial responsibility requirements for 

GS wells and will take the commenter's suggestion into consideration. The guidance will discuss 

the strengths and weaknesses of various instruments, and EPA anticipates that some of the 

strengths of insurance described by the commenter will be included in this discussion. In 

developing the guidance, EPA will also consider these commenters' concerns about creating 

certainty with regard to beneficiary designations as it develops the guidance. This guidance will 

be available on EPA's website at 

38
http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA anticipates that as GS is deployed, particularly if there are early successful uses of these 

instruments, owners or operators will demand and carriers will offer third-party GS financial 

instruments, including insurance, in greater numbers. 

EPA has expanded and clarified the financial responsibility requirements in the final rule to 

address commenters' requests for additional certainty. For example, regarding cancellation of 

policies, the final GS rule contains new language at §146.85(a)(4)(i)(C) that an owner or operator 

must provide that their financial mechanism may not cancel, terminate or fail to renew except for 

failure to pay such financial instrument. If there is a failure to pay the financial instrument, the 

financial institution may elect to cancel, terminate, or fail to renew the instrument by sending 

notice by certified mail to the owner or operator and the Director. The cancellation must not be 

final for 120 days after receipt of cancellation notice, the owner or operator must provide an 

alternate financial responsibility demonstration within 60 days of notice of cancellation, and if an 

alternate financial responsibility demonstration is not acceptable (or possible), any funds from 

the instrument being cancelled should be released within 60 days of notification by the Director. 

Letter ID: 0178 Comment ID: 23829 Letter Lines: 878 to 923 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: c. Surety Bonds 

Bonds are a traditional financial assurance mechanism and have been widely used. 

They ensure the performance of the bond holder on behalf of a third party, such 

as the state or the federal government. 

Unfortunately, the surety market has contracted in other environmental 

areas." Some of the conditions that led to the contraction elsewhere are 

relevant to CCS. For example, some agencies have focused on very long-term risks 

that might arise after site care responsibility has ended." The result can 

be bond amount increases by two orders of magnitude." Further exacerbating 

the problem, at least one court has found that EPA's financial assurance 

requirements for bonds does not limit payment to the amount of the bond, should 

the bond issuer choose to perform the cleanup rather than pay the bond.[FN23] 

Thus. for example, a bond issuer could pay $100 million for cleanup, even if the 

bond amount was $10 million. 

[FN20]"Mining and the Vanishing Surety Bond Market," Lisa A. Kirschner and 

Edward B. Grandy, American Bar Association, Natural Resources & Environment, 

Winter 2003, Vol. 17, Number 3. 

[FN21] See, e.g. , Mont. Code Ann. 382-4-338. 

39
[FN22] Jim Carlton, "Mining Firms in U.S. Face Crisis Over Cleanups," Asian Wall 

Street Journal. July 34. 2002. 

[FN23] People ex rel. Ryan v. Envtl. Waste Res. Inc., 782 N.E. 2d 291, 296 (Ill. 

App. 2003). 

Surety industry representatives indicate that they are hesitant to underwrite 

any obligation that may extend even beyond five years. Presently, for example, 

surety bonds for mining-related obligations are virtually unavailable at any 

price. A 2002 National Mining Association report on surety bonds for mining 

operations noted "Five of the top 10 sureties in the 1990s have either merged or 

left the business. Others have announced their intent to withdraw, and several 

longstanding market participants have effectively withdrawn by curtailing their 

exposures so substantially.[FN24] 

[FN24] Interim Report, National Mining Association Surety Bond Working Group, 

2002, p. 4. 

As with other financial assurance mechanisms, EPA should take steps to encourage 

the availability of surety bonding. Such steps should include clarifying in 

EPA's financial assurance regulations for surety bonds the bonding period, and 

clarifying that sureties may offer pay or perform instruments that will remain 

subject to the bonding limit, even if the surety chooses the performance option. 

Individual Response: EPA acknowledges that there are concerns regarding the feasibility of 

bonds. Therefore, EPA notes that the GS regulation provides flexibility for owners or operators 

to choose from a variety of financial instruments to meet their financial responsibility 

obligations. EPA anticipates that the availability of third-party GS financial instruments, 

including surety bonds, will grow in response to demand for such instruments by Class VI well 

owners or operators or based on successful uses of these instruments. 

EPA also acknowledges the commenters' concern regarding potential insolvency of surety 

companies, but notes that such unpredictable events are outside of the Agency's control or 

authority. However, EPA requires under §146.85 that a Director may only approve instruments 

determined to be sufficient to address endangerment of USDWs and has the discretion to 

disapprove of instruments that they determine are not sufficient. Furthermore, owners or 

operators or their guarantor must notify the Director no later than 10 days after filing for 

bankruptcy. 

Finally, regarding past cases where the courts have ordered bond issuers to pay the full cost of 

the cleanup rather than spend just the amount of the bond, EPA notes that this problem may be 

best remedied by requiring accurate cost estimates, which must be updated on an annual basis. 

The final rule requires annual updating of cost estimates for inflation and requires updates when 

the AoR and corrective action plan, well plugging plan, post-injection site care and site closure 

plan, and emergency and remedial response plan are amended, as specified in §146.85(c)(2). 

40
EPA adds that it is developing guidance that describes the types of financial instruments that 

owners or operators can use to meet financial responsibility requirements for Class VI wells. The 

guidance is available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0178 Comment ID: 23830 Letter Lines: 925 to 930 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: d. Corporate Financial Strength and Corporate Guarantees 

EPA proposes to authorize the use of corporate demonstration of financial 

strength and corporate guarantees as acceptable forms of financial assurance. In 

keeping with our recommendation that a broad array of financial assurance 

mechanisms be authorized, we support this proposal. 

Individual Response: EPA will retain self insurance as an option for financial responsibility for 

Class VI wells. EPA believes that if properly used, the financial test can be an appropriate option 

for some owners or operators. EPA recognizes that it is important for self-insurers to be creditworthy, otherwise USDWs may not be adequately protected. Owner or operators who choose to 

self-insure and use the financial test must be able to demonstrate profitability, with a margin 

sufficient to cover contingencies and unknown obligations, and stability. If the owner or operator 

meets corporate financial test criteria, this is an indication that the owner or operator can 

guarantee its ability to satisfy financial obligations based solely on the strength of the company’s 

financial condition. An operator or operator that is not able to meet the corporate financial test 

criteria may arrange a corporate guarantee by demonstrating that its corporate parent meets the 

financial requirements on its behalf. 

Furthermore, EPA is developing guidance to assist Directors in evaluating the appropriateness of 

corporate guarantees in specific circumstances. The guidance will be available on EPA's website 

at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0178 Comment ID: 23831 Letter Lines: 932 to 964 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: e. Letters of Credit 

Letters of credit ("LoCs")are a standard form of financial assurance and should 

be authorized. 

A great advantage of LoCs in commercial practice is that as long as a LoC is 

valid, presentation of the proper documentation by the LoC beneficiary entitles 

41
it to payment. Their ease of use is a great benefit. 

However, LoCs can be expensive. Issuing banks may require a site owner or 

operator to provide secured collateral or deposits before agreeing to issue a 

LoC,[FN25] a possibility made all the more likely by the extended time window of 

liability in the environmental context (and in fact referred to by EPA in 

promulgating some of its FA regulations).[FN26] Such a commitment of capital may 

be difficult in the context of an innovative project, such as a facility 

deploying CCS. EPA should take care not to assume heavy reliance on LoCs to meet 

financial assurance requirements, again pointing to the need to provide for a 

broad set of financial assurance instruments. 

[FN25] James William Boyd, "Financial Responsibility for Environmental 

Obligations: Are Bonding and Assurance Rules Fulfilling Their Promise?,' 

Resources for the Future Working Paper No. 01-42. August 2001, at 24. 

[FN26] See 53 Fed. Reg. 43,322, at 43,353, Oct. 26, 1988. 

Also, EPA should consider in its guidance for LoCs addressing the potential for 

differences in the coverage period detailed in the letter of credit and the 

letter's expiration date. LoCs ordinarily are issued for a short period, perhaps 

a year, with an annual renewal date. If the renewal merely extends the 

expiration date of the letter, giving additional time to present requests on the 

letter, without altering the period during which incidents covered by the letter 

would have to occur, gaps in coverage may arise. This issue could be addressed 

in guidance. 

Individual Response: EPA recognizes that, for some projects, the use of letters of credit may 

require owners or operators to provide high amounts of collateral. For this reason the final GS 

rule provides owners or operators the flexibility to choose from a variety of instruments to meet 

their financial responsibility requirements, thus allowing them to select instruments that are most 

appropriate to their needs while still ensuring protecting of USDWs. 

Furthermore, EPA is developing guidance that describes the types of financial instruments, 

including letters of credit, which owners or operators can use to meet financial responsibility 

requirements for Class VI wells. The guidance (available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) will include considerations 

for Directors regarding how best to evaluate the appropriateness of a specific financial 

responsibility instrument for a specific project. EPA will also consider the commenter's concerns 

regarding how to clarify confusion about the expiration dates and the coverage period for letters 

of credit as it develops the guidance. 

EPA also acknowledges the commenter's concern regarding potential insolvency of surety 

companies, but notes that such unpredictable events are outside of the Agency's control or 

authority. However, EPA requires under §146.85 that a Director may only approve instruments 

determined to be sufficient to address endangerment of USDWs and has the discretion to 

42
disapprove of instruments that they determine are not sufficient. Furthermore, owners or 

operators or their guarantor must notify the Director no later than 10 days after filing for 

bankruptcy. 

Letter ID: 0178 Comment ID: 23832 Letter Lines: 966 to 995 

Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: 3. A Government Backstop Is Necessary 

As the Proposed Rule states, EPA does not have the authority under the SDWA to 

establish a government backstop mechanism. Nevertheless, it is clear that such a 

mechanism is needed. A government backstop should be in place to the extent the 

private market is not. 

The CCS Alliance believes that the government will need to step in beyond an 

owner and operator liability limit, as has been the case in many other areas in 

which the government has sought to encourage private action to achieve a public 

good. The private sector's capacity to manage risks may be substantial, but will 

have limits. Government will need to accept responsibility beyond what the 

private market can manage, which is likely at a minimum to include the time 

after which operations cease and the project no longer produces revenues that 

would enable a private entity to cover liabilities. Because the goal in most 

cases is likely to be long-term storage of CO2, long beyond the typical lifespan 

of private entities, government should be prepared to assume liability after 

injection operations cease and a 30-year or shorter (as described above) closure 

period has elapsed. 

4. Encourage Risk Management Through the Private Sector 

Notwithstanding that CCS will require some level of government risk management, 

particularly for long-term liability. EPA's financial assurance regime should 

encourage the role of private market risk management to be as large as possible. 

5. Encourage Economically Efficient Risk Management 

Financial assurance mechanisms should be cost effective. Factors in cost will 

include the risk estimate, the type of instrument, and the duration of the 

instrument. Each cost in the CCS chain will have an effect on whether CCS is 

deployed. The EPA should carefully consider the potential cost of financial 

assurance mechanisms when designing a Class VI financial assurance regime. 

Individual Response: As described above, once an owner or operator has met all regulatory 

requirements under Part 146 for Class VI wells and the Director has approved site closure 

pursuant to requirements at §146.93, the owner or operator will generally no longer be subject to 

enforcement for regulatory noncompliance. 

EPA does not have authority to transfer SDWA or other legal liability for Class VI wells to the 

43
State or federal government or a third-party fund. See the final rule preamble for further 

discussion of EPA's final approach. 

Letter ID: 0178 Comment ID: 23833 Letter Lines: 998 to 1134 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: VII. SPECIAL FOCUS: APPLICABILITY OF CERCLA 

The Proposed Rule raises the question whether the injected CO2 stream[FN27]" 

will be considered a "hazardous substance" under CERCLA. 

[FN27] The rule uses the terms "carbon dioxide stream" and "injectate" 

interchangeably. EPA's proposed definition of these terms includes CO2 "plus 

incidental associated substances derived from the source materials and the 

capture process, and any substances added to the stream to enable or improve the 

injection process. This subpart does not apply to any carbon dioxide stream that 

meets the definition of a hazardous waste under 40 CFR Part 261." 

The Proposed Rule states: 

While CO2 itself is not listed as a hazardous substance under CERCLA, 

the CO2 stream may contain other substances such as mercury that are 

hazardous substances or the constituents of the CO2 stream could react 

with groundwater to produce listed hazardous substances such as sulfuric 

acid. Thus, whether or not there is a "hazardous substance" that may 

result in CERCLA liability from a sequestration facility depends 

entirely on the make-up of the specific CO2 and of the environmental 

media (e.g., soil, groundwater) in which it is stored. 

A mechanism must be in place to address liability for releases from GS sites. 

However, Superfund has had a number of problems that EPA should carefully 

consider in the context of a regulatory regime the Agency hopes will encourage 

deployment of CCS. Cleanups sometimes have been delayed by decades, lawsuits can 

stretch for years and involve numerous parties, and cleanups have been far too 

costly. EPA should use its interpretive authority to limit the applicability of 

Superfund and respond to releases under other authorities. Ultimately, Congress 

should adopt a new response and liability system recognizing the policy goals, 

scale, and other special features of CCS that is unburdened by the problems of 

Superfund. 

A. RELEVANT PROBLEMS WITH SUPERFUND 

Superfund imposes a strict, joint, and several liability scheme upon facility 

owners and operators, parties who arrange for treatment, storage, 

transportation, or disposal of hazardous substances; and transporters of 

44
hazardous substances. This strict, joint, and several liability scheme, in 

conjunction with other features of Superfund, particularly what many consider to 

be inordinately high cleanup costs, frequently results in expensive and lengthy 

lawsuits and delayed cleanups. Superfund also has been criticized for remedies 

that are far more aggressive than the risks warrant. 

B. SUPERFUND APPLICABILITY 

EPA's authority to order cleanups under CERCLA is triggered whenever any 

"hazardous substance" is released or there is a substantial threat of such a 

release into the environment. The Agency is considering whether the injectate, 

substances mobilized as a result of injection, or substances formed by 

geochemical reactions between the injectate and underground materials will 

trigger the "hazardous substance" definition. 

While EPA correctly notes that CO2 is not now a hazardous substance, that may 

not continue to be the case given Massachusetts v. EPA,[FN28] in which the 

Supreme Court ruled that CO2 is a pollutant and directed the EPA to determine 

whether or how it should be regulated. Such a decision could affect whether CO2 

is determined to be a hazardous substance under CERCLA. 

[FN28] Massachusetts v. EPA, 549 U.S. 497 (2007). 

CERCLA defines a hazardous substance to include "any hazardous air pollutant 

listed under section 112 of the Clean Air Act . . . ."[FN29] CO2 is not on this 

list at present. However, Section 112 authorizes EPA to add a compound to the 

list if the Agency finds that emissions of the compound "may reasonably be 

anticipated to cause adverse effects to human health or adverse environmental 

effects."[FN30] If in response to Massachusetts v. EPA, EPA were to decide to 

regulate CO2 under Section 112, releases of CO2, even without the presence of 

or interaction with hazardous substances, would be subject to Superfund 

liability. 

[FN29] 42 U.S. C. $9601. 

[FN30] 42 U.S. C. $7411. 

EPA also notes that the presence of other materials or the injectate's reaction 

with other substances underground may result in it becoming a hazardous 

substance. These post-injection geochemical reactions are of significant concern 

because CO2 injectate considered non-hazardous upon injection could, over time, 

react with underground materials, potentially creating a hazardous substance and 

triggering unintended and unanticipated Superfund applicability. 

Triggering application of the "hazardous substance" definition under Superfund 

to CO2, either pre- or post-injection, will create concerns about liability that 

45
will not encourage CCS development and, as our research cited above suggests. 

likely will be an impediment to the investment and risk management needed for 

CCS projects. 

C. FEDERALLY PERMITTED RELEASE EXEMPTION 

Superfund liability does not apply to a "federally permitted release," pursuant 

to Section 107(j).[FN31] The Proposed Rule notes that parties may be able to 

avoid Superfund liability through this exception. However, this exception likely 

would not apply in cases where injectate accidentally has been released from a 

storage site. Both EPA [FN32] and the courts [FN33] have interpreted the 

federally permitted release exemption to apply to releases that are in compliance 

with a permit, but not to accidental releases. It potentially may not apply 

where injectate remains safely within a containment zone, but beyond the area 

for which a permit was granted. The EPA should consider the potential for 

triggering Superfund liability in determining how it writes permits, 

particularly in cases where the CO2 remains safely stored. 

[FN31] 42 U.S.C. # 9607. 

[FN32] "In most circumstances, releases resulting from accidents and 

maifunctions do not qualify for the federally permitted release exemption as 

defined in CERCLA section 101(10)(H). Releases due to accidents and 

malfunctions, because they are by definition not anticipated, are difficult to 

subject to controls which limit or eliminate emissions. Congress did not intend 

to exempt unanticipated releases such as accidents and malfunctions from CERCLA 

section 103. An accidental release not in compliance with a permit would be 

subject to response costs and damages claims under Superfund in addition ot the 

provisions of the SDWA and state and common law." Guidance on the CERCLA Section 

101(10)(H) Federally Permitted Release Definition for Certain Air Emissions, 67 

Fed. Reg. 18899, 18903 (Apr. 17,2002). 

[FN33] See United States v. Iron Mountain Mines. Inc., 812 F. Supp. 1528. 

1540-41 (E.D. Cal. 1992) ("Congress considered the interplay between FWPCA and 

CERCLA when it enacted the latter statute, but declined to exempt municipal 

sewer authorities from its broad reach . . FWPCA exemption extends to industrial 

discharges into POTWs, indicating that Congress specifically intended for CERCLA 

liability to reach releases from sewers or POTWs.") Reading Co. v. City of 

Philadelphia, 823 F. Supp. 1218, 1230-31 (E.D. Penn. 1993) (Toxic Substances 

Control Act (TSCA) compliance is insufficient to invoke the RCRA exemption under 

CERCLA); Westfarm Associates Ltd. Partnership v. International Fabricare Inst., 

1993 U.S. Dist. LEXIS 19952 (D.Md. 1993). See also Idaho v. Bunker Hill Co., 635 

F. Supp. 665, 673 (D. Idaho 1986); Reporting Exemptions for Federally Permitted 

Releases of Hazardous Substances, 53 Fed. Reg. 27,268-81 (proposed July 19, 

1988) (to be codified at 40 C.F.R. $$ 117.12, 302.3, 302.6, 355). 

46
If Superfund does not apply because of the exemption, remedies may be obtained 

under other law. CERCLA's federally permitted release exemption states that 

"recovery . . . for response costs . . . resulting from a federally permitted 

release shall be pursuant to existing law in lieu of [CERCLA]."[FN34] 

[FN34] 42 U.S. C. $ 9607(j) (2006). 

Individual Response: CO2 itself is not listed as a hazardous substance under CERCLA 

however, the CO2 stream may contain a listed hazardous substance (such as mercury) or may 

mobilize substances in the subsurface that could react with ground water to produce listed 

hazardous substances (such as sulfuric acid). Whether such substances may result in CERCLA 

liability from a sequestration facility depends entirely on the composition of the specific CO2 

stream and the environmental media in which it is stored (e.g., soil or ground water). CERCLA 

exempts from liability, under CERCLA section 107, 42 U.S.C. 9607, certain “federally permitted 

releases” (FPR) as defined in CERCLA, 42 U.S.C. 9601(10). Class VI permits will need to be 

carefully structured to ensure that they prevent potential releases from the well which are outside 

the scope of the Class VI permit. Furthermore, EPA is promulgating the GS rule under the 

authority of the SDWA. To the extent the commenter is seeking interpretations of CERCLA and 

its related provisions, such as the definition of a federally permitted release, such interpretations 

are beyond the scope of this rulemaking. 

The UIC program Director has authority under SDWA §1423 to address potential compliance 

issues (e.g., potential releases that may endanger USDWs) resulting from injection violations in 

the unlikely event that a remedial response is necessary. Although EPA anticipates that the need 

for emergency or remedial actions at GS sites will be rare, the GS rule requires, at §146.94, that 

emergency and remedial response plans be developed and updated to address such events and 

that owners or operators demonstrate that financial resources are set aside to implement the plans 

if necessary, per §146.85. 

EPA clarifies that, while the Administrator reserves the right to promulgate regulations 

designating additional substances as hazardous under §102 of CERCLA, EPA intends to avoid 

any potential overlap of SDWA and CERCLA authority through its comprehensive Class VI 

requirements. 

CERCLA exempts from liability, under CERCLA section 107, 42 U.S.C. 9607, certain 

“federally permitted releases” (FPR) as defined in CERCLA, 42 U.S.C. 9601(10). Therefore, 

Class VI requirements and permits will need to be carefully structured to ensure that they do not 

“authorize” inappropriate releases, and would need to prevent potential releases from the well 

which are outside the scope of the Class VI permit. 

Letter ID: 0178 Comment ID: 23834 Letter Lines: 1136 to 1185 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment Code: 5400 2.9 Proposed Financial Responsibility and Long-Term Care 

Requirements 

47
Comment: D. POTENTIAL EFFECT OF SUPERFUND ON CCS DEPLOYMENT 

The CCS Alliance conducted a Risk Study earlier this year, surveying more than 

30 executives in companies involved with or considering CCS deployment.[FN35] 

the purpose of the Risk Study was to identify policy, technical, and market 

risks that could pose barriers to proceeding with CCS projects. Respondents were 

asked to rate the likelihood of a policy, technical, or market factor occurring, 

as well as the severity of the impact to a CCS project if it did occur. The 

product of the likelihood and the severity of impact to the project for each 

surveyed issue generated a risk ranking. 

[FN35] Risk Study for Commercial Deployment of CCS: Factors Affecting Financing 

for Early Plants, CCS Alliance (July 2008). 

Three of the top eight concerns identified by respondents related to liability 

for CCS, including lack of clarity in the applicability of federal and state 

liability regimes. As the following chart demonstrates, particularly results for 

responses to questions 17,31, and 34. executives are very much concerned with 

the risks associated with the lack of clarity in state and federal regulations 

and liability regimes, as well as with liability over the long-term. 

[Please see Comment Pdf for Chart, pg. 38] 

Moreover, a recent GAO report emphasizes the concern about liability: 

EPA's 2007 UIC workshop, attended by more than 200 stakeholders, 

revealed liability associated with unintended migration of injected CO2 

to be a critical concern. Similarly, 19 of the 20 stakeholders we 

interviewed told us that liability related to CO2 storage was a large or 

very large barrier to deployment of CCS at commercial scale, with some 

noting that liability concerns have already negatively impacted 

companies' ability to initiate CCS projects. For example. two 

stakeholders reported that these concerns have already made it difficult 

to obtain insurance for CCS projects. [FN36] 

[FN36] U.S. GAO, GAO-08-1080. FEDERAL ACTIONS WlLL GREATLY AFFECT THE 

VIABILITY 

OF CARBON CAPTURE AND STORAGE AS A KEY MITIGATION OPTION 25 (2008). 

Although we currently are aware of no report specifically stating that liability 

under Superfund is the principal liability concern among CCS proponents, it 

clearly is a significant issue that has been raised repeatedly, including 

through EPA advisory processes and the imposition of which would negatively 

affect future investment in CCS technologies.[FN37] 

[FN37] EPA's Advanced Coal Technology Work Group Final Report recommends that 

48
EPA's UIC rulemaking proposal should "include a thorough discussion of. . 

liability implications under other statutes (CERCLA, RCRA, etc.) and potential 

linkages and impacts (or lack thereof) for CCS projects." U.S. ENVIRONMEKTAL 

PROTECTION AGENCY, FINAL REPORT: ADVANCED COAL TECHNOLOGY WORK 

GROUP REPORT 5 

(Jan. 29,2008). 

Individual Response: As described above, EPA is working to create a nationally consistent 

financial responsibility regime within its authority while providing permitting authorities and 

owners or operators an appropriate level of flexibility. EPA believes that the general authorities 

provided under SDWA include the authority to set federal minimum requirements for financial 

responsibility to ensure that resources are available to protect USDWs throughout the life of the 

GS project. However, this authority does not extend to release owners or operators from longterm responsibility of other environmental statutes, such as CERCLA, for potential impacts to 

USDWs after the PISC period has ended, or for the potential economic costs associated with 

activities with impacts unrelated to USDWs (e.g., risks to air, or ecosystems). 

Additionally, an owner or operator may always be subject to any action the Administrator deems 

necessary to protect the health of persons under §1431 of the SDWA after site closure if there is 

unanticipated migration towards or into a USDW that causes or threatens imminent and 

substantial endangerment to public health. The action may include issuing administrative orders 

or commencing a civil action for appropriate relief. If the owner or operator fails to comply with 

the order, they may be subject to a civil penalty for each day in which such violation occurs or 

failure to comply continues. 

Furthermore, the Agency clarifies that, after site closure, an owner or operator may, depending 

on the fact scenario, remain liable under tort and other remedies, or under other Statutes 

including, but not limited to, Clean Air Act, 42 U.S.C. §§ 7401-7671; CERCLA, 42 U.S.C. § 

9601-9675; and RCRA, 42 U.S.C. § 6901-6992. 

See the final rule and preamble for further discussion of final approach to financial responsibility 

for GS projects. 

As described above, whether the presence of hazardous substances in CO2 streams may result in 

CERCLA liability from a sequestration facility depends entirely on the composition of the 

specific CO2 stream and the environmental media in which it is stored (e.g., soil or ground 

water). CERCLA exempts from liability, under CERCLA section 107, 42 U.S.C. 9607, certain 

“federally permitted releases” (FPR) as defined in CERCLA, 42 U.S.C. 9601(10). Class VI 

permits will need to be carefully structured to ensure that they prevent potential releases from the 

well which are outside the scope of the Class VI permit. 

Furthermore, EPA is promulgating the GS rule under the authority of the SDWA. To the extent 

the commenter is seeking interpretations of CERCLA and its related provisions, such as the 

definition of a federally permitted release, such interpretations are beyond the scope of this 

rulemaking. 

49
Letter ID: 0178 Comment ID: 23835 Letter Lines: 1188 to 1217 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment: VIII. SPECIAL FOCUS: APPLICABILITY OF RCRA 

The Proposed Rule raises the question whether injected CO2 streams will be 

considered "hazardous waste" under RCRA. Rather than apply on top of the SDWA 

another environmental statute that was not designed with the thought of 

encouraging development and deployment of technology to address climate change, 

which is likely to discourage CCS deployment, CCS should be subject to a single. 

clear regulatory structure shaped by consideration of climate change objectives. 

Designating the CO2 stream as a hazardous waste also will result in it being 

considered a "hazardous substance" under CERCLA, the problems with which are 

discussed above. 

The Proposed Rule states: 

Because the types of impurities and their concentrations in the CO2 

stream are likely to vary by facility, coal composition, plant operating 

conditions, and pollution removal technologies, EPA cannot make a 

categorical determination as to whether injected CO2 is hazardous under 

RCRA. Owners and operators will need to characterize their CO2 stream as 

part of their permit application to determine if the injectate is 

considered hazardous as defined in 40 CFR Part 261. If the injectate is 

considered hazardous under RCRA, then the more stringent UIC Class I 

requirements for injection of hazardous waste apply.[FN38] 

[FN38] Proposed Rule, 73 Fed Reg. 43503. 

Where EPA faces an interpretive question about the applicability of RCRA, it 

should avoid applying the statute. As noted above, the CCS Alliance believes 

that in place of existing, ill-suited regulatory regimes, a new single, clear 

regulatory structure should apply to protect the environment. 

Individual Response: EPA agrees that any requirements applicable to CO2 injectate should be 

clearly identified to the public and to the regulated community. As mentioned, making 

legislation changes is outside the scope of the GS rulemaking. 

As discussed above, EPA received many comments regarding the applicability of the RCRA 

regulations and statute to CO2 streams that are geologically sequestered under the final Class VI 

UIC well requirements. As a result, EPA has decided to initiate a separate proposed rulemaking 

specifically to examine the issue of RCRA applicability to CO2 streams being geologically 

sequestered, including the possible option of a conditional exemption from the RCRA 

requirements for CO2 GS in Class VI wells. EPA will consider these comments as part of its 

development of that proposal. The Agency will consider issues particular to RCRA in the context 

50
of that separate rulemaking, and recommends that the commenter read that proposed rule when it 

is published. The Agency notes that commenters who wish to submit comments on the RCRA 

proposal will need to do so during the comment period for that rule. 

Letter ID: 0178 Comment ID: 23836 Letter Lines: 1219 to 1268 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment: A. BURDENS AND BARRIERS OF RCRA 

The UIC regulatory structure proposed by EPA to minimize releases not only 

protects groundwater, but by extension protects human health and the 

environment. RCRA's requirements are extensive, expensive, and ill-suited to 

activities to sequester large volumes of low-toxicity materials, especially when 

such activities will be regulated under the UIC program. 

EPA itself has acknowledged the burden of RCRA and the fact that many of its 

requirements are poorly suited to at least some of the activities to which they 

apply. EPA initiated a rulemaking in 2002 to reduce the burdens associated with 

the RCRA hazardous waste program.[FN39] The Agency noted, "[t]he existing 

hazardous waste regulations require the submittal of 334 notifications, reports, 

certifications, demonstrations, and plans from generators and TSDFs to 

demonstrate compliance with the RCRA regulations."[FN40] Reporting requirements 

are just one example of RCRA's burdens. 

[FN39] Resource Conservation and Recovery Act Burden Reduction Initiative. 67 

Fed. Reg. 2518 (proposed Jan. 17, 2002); see also RCRA Burden Initiative; Final 

Rule, 71 Fed. Reg. 16,862 (Apr. 4,2006). 

[FN40] RCRA Burden Reduction Initiative: Notice of Data Availability, 68 Fed. 

Reg. 61,662, 61,644 (Oct. 29, 2003). 

Given that CCS is a technology that the Agency and a broad array of others want 

to encourage, with this rule more than most others, EPA must consider very 

carefully whether the emission streams involved truly warrant hazardous waste 

regulation. Imposing extensive. burdensome RCRA regulations likely to have 

little benefit for human health and the environment may result in larger 

atmospheric releases of CO2 if this "key" technology is not as widely deployed. 

Class I wells under the UIC program are intended, in part, to regulate hazardous 

waste disposal wells for the injection of hazardous waste, as defined by RCRA. 

If EPA were to determine that CO2 is a hazardous waste under RCRA, CO2 injection 

would be required to meet the more rigorous Class I well requirements, rather 

than the proposed Class VI requirements. Indeed, the construction, permitting, 

operating, monitoring, and post-site closure requirements are much more 

burdensome for Class I hazardous wells than for the other types of injection 

51
wells. For instance, Class I wells have a requirement that there be no migration 

for 10,000 years. Such strict requirements may be appropriate to protect USDWs 

and the environment from certain hazardous wastes, but such requirements were 

not established with CO2 injectate in mind. 

Furthermore, if a facility were required to obtain a Class I UIC hazardous waste 

injection permit, all other waste management units at the facility couId be 

subject to the full extent of RCRA's Subtitle C corrective action program, which 

is an extremely costly and administratively complex program. Determining that 

CO2 constitutes a hazardous waste and subjecting CO2 injection and storage to 

the burdensome Class I well requirements would not promote underground injection 

and storage of CO2. 

Individual Response: The Agency acknowledges the commenter’s concerns over potential 

barriers to CCS deployment, and will consider these comments as it examines the issue of RCRA 

applicability to CO2 streams being geologically sequestered in a separate Agency action related 

to RCRA, already described above. The Agency recommends that the commenter read that 

proposed rule when it is published. The Agency notes that commenters who wish to submit 

comments on the RCRA proposal will need to do so during the comment period for that rule. 

Letter ID: 0178 Comment ID: 23837 Letter Lines: 1270 to 1297 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment: B. CONTINGENT MANAGEMENT 

Materials already subject to another regulatory regime that will ensure 

environmentally protective management of wastes can be excluded from RCRA 

regulation under "contingent management," a practice EPA has applied in other 

contexts. 

In this Proposed Rule, EPA is proposing a framework it believes is appropriate 

to ensure environmentally protective management of injected CO2. The Agency 

makes clear that the extent of the UIC program limits the purpose of EPA's 

proposal to protection of USDWs; however, the Agency adds that it considers the 

risk of -'chronic and acute health effects from airborne exposure resulting from 

CO2 injection activities (even in the case of leakage or accidental exposure) is 

minimal."[FN41] 

[FN41] Proposed Rule, 73 Fed. Reg. at pp. 43,497-98 (emphasis added). 

EPA has applied the contingent management practice in cases where potential 

mismanagement scenarios are addressed under other regulation. With respect to 

the Proposed Rule, EPA has proposed measures that would limit potential effects 

on human health and the environment by ensuring that the injectate should remain 

contained within the injection zone. The contingent management practice has been 

52
upheld, with the court holding that where other appropriate management programs 

are in place. hazardous waste classification and regulation are not 

required.[FN42] 

[FN42] See. e.g., Military Toxics Project v. EPA, 146 F. 36 948 (D.C. Cir. 

1998). 

Individual Response: As described above, EPA has decided to initiate a separate proposed 

rulemaking specifically to examine the issue of RCRA applicability to CO2 streams being 

geologically sequestered, including the possible option of a conditional exemption from the 

RCRA requirements for CO2 GS in Class VI wells. The Agency recommends that the 

commenter read that proposed rule when it is published. The Agency notes that commenters who 

wish to submit comments on the RCRA proposal will need to do so during the comment period 

for that rule. 

Letter ID: 0178 Comment ID: 23838 Letter Lines: 1299 to 1304 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment: C. CONDITIONAL EXCLUSION 

If EPA considers that geologic sequestration of CO2 constitutes waste disposal 

that cannot be subject to exclusion from RCRA regulation under a contingent 

management theory, it should establish a conditional exclusion from RCRA 

regulation for geologic sequestration of CO2 injectate. 

Individual Response: EPA received many comments regarding the applicability of the RCRA 

regulations and statute to CO2 streams that are geologically sequestered under the final Class VI 

UIC well requirements. As a result, EPA has decided to initiate a separate proposed rulemaking 

specifically to examine the issue of RCRA applicability to CO2 streams being geologically 

sequestered, including the possible option of a conditional exemption from the RCRA 

requirements for CO2 GS in Class VI wells. EPA will consider these comments as part of its 

development of that proposal. The Agency will consider issues particular to RCRA in the context 

of that separate rulemaking, and recommends that the commenter read that proposed rule when it 

is published. The Agency notes that commenters who wish to submit comments on the RCRA 

proposal will need to do so during the comment period for that rule. Finally, EPA also notes that 

the final GS rule, which adds new regulations for Class VI wells under the Safe Drinking Water 

Act (SDWA), is not making any changes to the RCRA regulations. 

Letter ID: 0178 Comment ID: 23839 Letter Lines: 1310 to 1328 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

53
Comment: A. WELL PLUGGING PLAN 

EPA's Proposed Rule would require owners and operators to develop a well 

plugging plan to be approved by the Director as part of each permit application. 

Such a plan would include: (1) a determination of bottom-hole reservoir 

pressure; (2) the identification of type and numbers of plugs to be used; (3) 

the placement of each plug; (4) testing methods to ensure mechanical integrity 

testing ("MIT"); (5) the method of plug placement; and (6) the type, grade and 

quantity of material to be used in plugging. By not mandating specific types, 

materials, or testing methods, EPA is giving applicants broad flexibility to 

accommodate the varying types of GS projects contemplated by this rulemaking. 

The CCS Alliance agrees with this approach. Such flexibility also accounts for 

the fact that supercritical CO2 has different properties than current injectants 

under the UIC program and, therefore. may require different plugging methods and 

materials. For instance, cement plugs can degrade over time from the build up of 

carbonic acid, which forms when CO2 is injected in subsurface formations 

containing brine. However. well integrity should be considered the function of 

well materials collectively in maintaining a fluid barrier (as opposed to 

individual components susceptibility, particularly from laboratory tests). 

Individual Response: EPA agrees with commenters that a flexible approach is appropriate for 

GS wells. The GS rule does not prescribe the specific cements to be used to plug injection wells 

because industry standards, such as those developed by API or ASTM International, reflect the 

current state of the science and the expertise of industrial users on CO2-compatible materials, as 

specified in §146.92(b). Providing flexibility to choose materials for plugging, provided they are 

compatible with the injected fluid, is consistent with requirements for other injection well classes 

and will allow operators to utilize improved well technologies as they become available in the 

future without a need to amend the regulation. 

Letter ID: 0178 Comment ID: 23840 Letter Lines: 1330 to 1347 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93) 

Comment: B. POST-INJECTION SITE CARE PLAN 

The Proposed Rule would require that owners or operators develop a postinjection site care and closure plan, submitted as part of the permit 

application and approved by the Director. The proposed regulation at 40 C.F.R. $ 

146.93 would require the plan to describe: (1) the pressure differential between 

pre-injection and anticipated post-injection pressures in the injection zone; 

(2) predicted position of the plume and associated pressure front at the time 

the site is closed; (3) post-injection monitoring location(s), methods, and 

proposed frequency of monitoring; and (4) a schedule for submitting post54
injection site care and monitoring results to the Director. 

These requirements are reasonable given the long-term nature of GS projects. The 

CCS Alliance also supports the ability to amend the plan should the plan no 

longer reflect what is likely to occur upon closing the site. Likewise, the CCS 

Alliance agrees that, upon permanent cessation of injection, the owner or 

operator should be provided the opportunity to demonstrate that no amendment to 

the plan is necessary through monitoring and modeling results. 

Individual Response: EPA agrees that a post-injection site care monitoring plan is an important 

tool for GS, and retains this requirement in the final rule, at 146.93(a). Regarding updates to the 

plan, EPA is requiring that upon the cessation of injection, the owner or operator submit an 

amended post-injection site care and site closure plan or demonstrate to the Director that no 

changes to the original post-injection site care and site closure plan are necessary, as specified in 

§146.93(a)(3). EPA is not requiring formal periodic review and updates to the PISC and site 

closure plan throughout the injection phase. EPA does not expect that changes to this plan would 

be implemented until injection operations cease. 

Letter ID: 0178 Comment ID: 23841 Letter Lines: 1349 to 1384 

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment: C. POST-INJECTION SITE CARE PERIOD AND FINANCIAL 

RESPONSIBILITY 

The Agency has proposed a post-injection site care and financial responsibility 

period of 50 years, which can be shortened or lengthened based on the discretion 

of the Director. The CCS Alliance agrees, in part, with this suggested use of a 

combination of a fixed timeframe and performance standard. However, as 

previously explained, the CCS Alliance recommends establishing a maximum 30-year 

post-closure period and providing the Director with discretion to shorten -- but 

not lengthen -- this period if the owner or operator meets certain enumerated 

performance standards based on available data on pressure, fluid movement. 

mineralization and/or dissolution reactions to show whether the plume and 

pressure front have stabilized. 

CCS is an activity the Agency hopes to encourage. A 50-year post-injection site 

care default is longer than any period of post-operation site care of which the 

Alliance is aware. The potential for threats to USDWs will have been considered 

prior to site operation. and will have been reconsidered throughout the life of 

the project, not only by the regulator, but by the owner or operator, entities 

providing financial support, and providers of risk management products and 

services. Continuance of injection will have depended upon an assessment of the 

potential for threats to USDWs at numerous points during the site's operation. 

EPA suggests that when owners or operators show that "models predicting CO2 

55
movement are consistent with monitoring results and that there are no longer 

risks of endangerment to USDWs. they could request that the Director authorize 

site closure."[FN43] The CCS Alliance suggests that if EPA considers the 

relationship between modeling results and actual plume movement in determining 

the continuation of post- injection site responsibility, the standard need not 

be "consistency." Models may predict a range of outcomes. Notwithstanding 

falling outside the modeled range, actual plume movement may be safe. including 

when there are no USDWs in the area. The Alliance recommends that the rule 

authorize Directors to end the post-injection site responsibility period prior 

to the 30-year period, taking into account their ability reasonably to predict 

the likelihood of minimal or no risk to USDWs. 

[FN43] Proposed Rule. 73 Fed. Reg. at p. 43491 (emphasis added). 

Individual Response: EPA agrees that there will be circumstances where it can be demonstrated 

in less than 50 years that the plume and pressure front no longer pose a risk of endangerment to 

USDWs. For this reason, the Class VI rule offers owners or operators flexibility regarding the 

duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen 

the PISC timeframe during the PISC period based on site-specific data, pursuant to requirements 

at §146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator 

to demonstrate, based on substantial data during the permitting process, that an alternative PISC 

timeframe may be appropriate if it ensures non-endangerment of USDWs pursuant to 

requirements at §146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA agrees that proper site characterization is a critical component of ensuring that USDWs are 

protected. However, EPA disagrees that this is a substitute for post-injection site care. EPA 

believes that extensive post-injection monitoring is necessary to protect USDWs from 

endangerment. 

Letter ID: 0178 Comment ID: 23842 Letter Lines: 1386 to 1396 

Comment Code: 5400 2.9 Proposed Financial Responsibility and Long-Term Care 

Requirements 

Comment Code: 5460 2.9.2 Comments on transfer of liability for long-term care 

Comment: EPA should consider whether financial assurance mechanisms are likely to be 

available for the entire post-operation site care period. While risks can be 

expected to decline over time after injection ceases, it does not follow that 

56
private risk management entities will continue to cover the risks. If there are 

no financial assurance mechanisms available, owners and operators should not be 

at risk of non-compliance for failing to have them after operations (and revenue 

streams from the project) have ceased, especially if risks continue to be low. 

As such, the CCS Alliance recommends that once the 30-year period is reached -- 

or shorter if the performance standards are met -- a government backstop would 

be triggered, thereby ensuring that a risk management mechanism is in place 

beyond the responsibility of the owner or operator. 

Individual Response: EPA clarifies that owners or operators of GS wells must demonstrate and 

maintain financial responsibility for addressing corrective action on wells in the AoR, injection 

well plugging, PISC and site closure, and emergency and remedial response at GS sites, as 

required at §146.85(a). The final rule provides owners or operators to choose from a variety of 

financial instruments to meet the financial responsibility requirements. EPA anticipates that the 

availability of third-party GS financial instruments will grow in response to demand for such 

instruments by GS well owners or operators as deployment of GS technology increases in the 

future. 

Under SDWA authority, owners or operators of injection wells must ensure protection of 

USDWs from endangerment and are subject to liability for enforcement under the Act. The final 

rule requires that an owner or operator must conduct monitoring as specified in the Directorapproved PISC and site closure plan following the cessation of injection until the owner or 

operator can demonstrate to the Director that the geologic sequestration project no longer poses 

an endangerment to USDWs. For additional information about the PISC and site closure 

requirements, see the preamble to the final GS rule. 

Once an owner or operator has met all regulatory requirements under Part 146 for Class VI wells 

and the Director has approved site closure pursuant to requirements at §146.93, the owner or 

operator will generally no longer be subject to enforcement for regulatory noncompliance. 

Furthermore, their financial instrument as required under §146.85 will be released if it was not 

used. However, even if a site closure is approved under §146.93, an owner or operator may be 

held liable for regulatory noncompliance (including violation of 40 CFR 144.12) in certain 

circumstances. For example, an owner or operator may be held liable for regulatory 

noncompliance even after site closure was approved if the Director relied on erroneous 

information (e.g., erroneous modeling data) provided by the owner or operator when approving 

site closure. 

Additionally, an owner or operator may always be subject to any action the Administrator deems 

necessary to protect the health of persons under §1431 of the SDWA after site closure if there is 

unanticipated migration towards or into a USDW that causes or threatens imminent and 

substantial endangerment to public health. The action may include issuing administrative orders 

or commencing a civil action for appropriate relief. If the owner or operator fails to comply with 

the order, they may be subject to a civil penalty for each day in which such violation occurs or 

failure to comply continues. 

The Agency clarifies that Class VI well permits may be transferred to another owner or operator 

57
pursuant to §144.38 whereby generally all other regulatory responsibilities are transferred to that 

new owner and operator, which includes all potential liabilities associated with meeting the 

requirements of that permit. Please see further clarification on the issue of long term liability in 

the preamble of the final rule. 

Furthermore, after site closure an owner or operator may remain liable under tort and other 

remedies, or under other federal statutes including, but not limited to, Clean Air Act, 42 U.S.C. 

§§ 7401-7671; CERCLA, 42 U.S.C. § 9601-9675; and RCRA, 42 U.S.C. § 6901-6992. EPA 

does not have authority to transfer SDWA or other legal liability for Class VI wells to the State 

or federal government or a third-party fund. See the final rule preamble for further discussion of 

EPA's final approach. 

Letter ID: 0178 Comment ID: 23843 Letter Lines: 1398 to 1402 

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93) 

Comment: D. SITE CLOSURE 

The CCS Alliance recommends including a provision releasing sites certified as 

closed from further monitoring and verification requirements, as well as 

releasing any outstanding financial assurance instruments. 

Individual Response: EPA disagrees that the owner or operator should not be responsible for 

record retention such as site closure reports. EPA believes that the requirements that the owner or 

operator retain for ten years following site closure, records collected during the post-injection 

site care period at §146.93(f) and §146.93(h) are appropriate for the post-injection and site 

closure period to ensure that data are available to support non-endangerment demonstrations and 

to address any concerns that may arise following site closure. This data will also support EPA's 

review of project data as part of the adaptive rulemaking approach. 

Letter ID: 0178 Comment ID: 23844 Letter Lines: 1407 to 1416 

Comment Code: 4700 2.7 Proposed Recordkeeping and Reporting Requirements (40 CFR 

146.91) 

Comment: A. GENERAL COMMENTS 

The application and reporting requirements for Class VI wells should be 

balanced, placing as little burden as possible on owners and operators, while 

also achieving EPA's goals. Sufficient reporting requirements ensure the 

collection of information necessary for the protection of human health and the 

environment, and provide companies and investors with information to better 

manage and mitigate risks. A robust but not overly burdensome reporting regime 

is necessary to the success of CCS. as well as to achieving EPA's goals of 

58
protecting USDWs. 

Individual Response: EPA believes that all of the requirements for Class VI wells, including the 

reporting and recordkeeping requirements, are necessary to ensure that GS is conducted in a 

manner that protects USDWs from endangerment. The requirements for GS projects are tailored 

to address the unique issues associated with GS including large injection volumes, the relative 

buoyancy of CO2, its corrosivity in the presence of water, the potential presence of impurities in 

captured CO2, and its mobility within subsurface geologic formations. Because these 

requirements are necessary to protect USDWs from endangerment, they are in effect not overly 

burdensome to the owner or operator. 

The final GS rule affords flexibility to owners or operators. Many of the permit requirements will 

be established through site-specific plans developed by the owner or operator and approved by 

the Director. 

EPA is using an adaptive approach to regulating GS. The Agency plans to, every six years, 

collect and review data on GS projects to determine whether the appropriate amount and types of 

information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 

Letter ID: 0178 Comment ID: 23845 Letter Lines: 1418 to 1514 

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82) 

Comment: B. PERMIT APPLICATION REQUIREMENTS 

EPA proposes to require owners and operators to submit relevant site information 

to the permitting authority for consideration of permit applications, including: 

maps of the injection wells, the AoR as determined through computational 

modeling, all artificial penetrations within the AoR, maps of the general 

vertical and lateral limits of USDWs, maps of the geologic cross sections of the 

local area, the proposed operating data and injection procedures, proposed 

formation testing program, and stimulation program, well schematics and 

construction procedures, and contingency plans for shut-ins or well failures. 

Some of the data that EPA proposes to require is irrelevant, excessive, or in 

some cases unavailable. Therefore, the CCS Alliance recommends that EPA ensure 

that any required data is necessary to the ultimate goals of the Proposed Rule. 

For example, artificial penetrations several formations above the injection zone 

may have little relevance to the GS operation. Similarly, the CCS Alliance 

recommends including a provision in the final rule providing the Director 

discretion to waive certain data requirements, where such requirements are 

unnecessary, or require that the data be updated as it is collected or becomes 

available. 

EPA is proposing that an applicant include "baseline geochemical data on 

59
subsurface formations, including all USDWs in the area of review."" The 

Proposed Rule is not clear as to how much baseline data EPA is expecting the 

permit applicant to generate and collect from additional drilling or testing of 

the injection zone and all other zones. Given the likely depth of many of the GS 

wells through many strata, this could involve a large number of different 

formations above the injection zone. EPA should limit the baseline geochemical 

data to information regarding the next porous formation above the injection 

zone. Similarly, EPA should clarify that the permit applicant may rely upon 

secondary sources (such as other drilling or geologic records) that relate to 

and support the data requirement. EPA also should clarify whether its expects 

applicants to test private wells, where permission is granted, within the AoR 

for purposes of establishing baseline data. 

[FN44] 40 C.F.R. $ 146.82(g). 

EPA also has included a requirement that the permit applicant include a 

"proposed formation testing program to obtain an analysis of the chemical and 

physical characteristics" of the injection and confining zone." A permit 

applicant is already required to submit the underlying data as part of the 

permit application process, and it appears that this requirement is unnecessary 

and duplicative. Therefore, the Alliance requests further clarification 

regarding the intent and scope of this formation testing program. 

[FN45] 40 C.F.R. $ 146.82(j). 

EPA should monitor stimulation activities of third parties to ensure that such 

activities not interfere with or damage the containment integrity of other GS 

operations or natural gas storage reservoirs. The CCS Alliance, therefore, 

generally supports the requirement for the "proposed stimulation program" to 

ensure that stimulation activities will not interfere with containment. [FN46] 

[FN46] 40 C.F.R. 9 146.82(k). 

EPA has proposed requiring the applicant to submit "the status of corrective 

action on wells in the area of review."[FN47] The CCS Alliance does not believe 

it is necessary to require the inclusion of all wells within the AoR regardless 

of whether or not they penetrate the injection zone. There could be many shallow 

wells within the AoR located hundreds or thousands of feet above the CO2 

injection zone. Therefore, EPA should limit this requirement to the injection 

zone, injection pool, and only those wells that either intersect or penetrate 

the proposed reservoir, the cap rock, and possibly the porous strata directly 

above the injection zone. 

[FN47] 40 C.F.R. $ 146.82(q). 

On a related matter, EPA has stated that only information of public record 

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pertaining to all types of wells (injection. producing, abandoned) be included 

on the AoR. Data availability and use raises a question regarding the possible 

existence of other data which might be private, proprietary, and/or not publicly 

available. Such non-publicly available data may or may not be relevant to the 

application process. The CCS Alliance requests EPA to clarify to what extent an 

applicant would be expected to develop or use information not contained in the 

public record. 

EPA also proposes that permit applications for GS sites include several plans 

not currently required under existing UIC regulations, including (1) a 

monitoring and testing plan; (2) an AoR and corrective action plan; (3) a well 

plugging plan: and (4) a post-injection site care and site closure plan. The CCS 

Alliance questions whether it is necessary for each plan to be submitted 

contemporaneously with the permit application. The up-front gathering and 

submission of such detailed information would be costly and time-consuming. We 

recommend requiring the submission of such plans only upon approval of an 

initial permit application, with further approvals contingent upon the 

successful completion, submission, and approval of the required plans. The 

initial permit application could provide general information regarding the 

specific plans to be submitted later. Such a process will provide sufficient 

information for EPA to make an initial permitting decision. 

As part of the permitting process, EPA should require that owners and operators 

establish a plan to ensure that resource development may occur in other geologic 

strata within or near the AoR. CCS will be a critical technology, but also 

critical to the nation are energy resources and mineral reserves. Companies may 

have made considerable investment in purchasing, identifying and characterizing 

these resources. This value should be protected as GS sites are selected and 

developed. EPA's proposed rule at present does not address this issue. 

Individual Response: EPA believes that a detailed geological site characterization (required 

under 146.82) is essential to evaluating the presence and adequacy of the various geologic 

features necessary to receive and confine injected CO2 for GS. The requirements for geologic 

site characterization are based on a long standing UIC regulatory framework developed to 

address specific risks to USDWs posed by injection. The Class VI GS requirements are tailored 

so that they are appropriate for the unique nature of injecting large volumes of CO2 into a variety 

of geological formations for long-term storage. 

EPA recognizes that some of this information may not be available until after a well has been 

drilled. EPA revised §146.82 so that the final regulation specifies separate requirements for 

information to be submitted with the permit application and before well construction is approved 

(at §146.82(a)) and information to be submitted before operation of the well is authorized (at 

§146.82(c)). 

EPA disagrees that any of these protective requirements are unnecessary, and clarifies that 

waiving any of the requirements would not be acceptable. The GS regulation allows flexibility 

61
where appropriate. Certain requirements (e.g., the need to characterize additional confining 

layers) are at the Director's discretion (§146.83(b)), based on his or her understanding of a 

particular site. 

The Agency believes that the requirement at §146.82(a)(6) to submit baseline geochemical data 

on subsurface geologic formations, including all USDWs in the AoR is appropriate and 

protective of USDWs. EPA believes that this data will support monitoring plan development, 

inform injectate fate and transport model development (e.g., by providing appropriate input 

parameters), and provide information needed to respond to any unexpected and unpermitted 

leaks outside of the injection zone. The baseline geochemical information will allow the owner 

or operator and permitting authority to evaluate monitoring data and identify any changes in 

subsurface geochemistry that may indicate fluid movement. 

The rule requires geochemical analysis of, at a minimum, the injection zone, confining zone, and 

all USDWs (§146.82(a)(6)). These geochemical tests are necessary to ensure the adequacy of the 

confining system and to serve as a baseline for future monitoring. The Director has the discretion 

to require geochemical analysis of additional subsurface zones if in the Director's opinion they 

are necessary for the protection of USDWs from endangerment. 

EPA believes that a determination about whether or what information may be necessary (for a 

specific GS project) is outside of the public record will be site-specific and based on knowledge 

of the site, data availability, and data quality. For instance, in meeting the requirement to tabulate 

information on wells in the AoR, the Director has the discretion to require the owner or operator 

to supplement a data records search if there is reason to believe that the incompleteness of 

available information could compromise USDW protection from endangerment. 

In response to the comment that EPA should require that owners or operators establish a plan to 

ensure that resource development may occur in other geologic strata within or near the AoR, the 

Agency clarifies ensuring protection of resource rights including mineral, water, and energy 

resource development rights is outside the scope of this rulemaking. 

In conducting GS site characterization, the Agency anticipates that the owner or operator would 

consider the proximity of and implications that a GS project may have on other activities in the 

AoR. However, the purpose of the requirements is to ensure that Class VI GS well is 

constructed, operated, monitored, and closed in a manner that is protective of USDWs. 

Letter ID: 0178 Comment ID: 23846 Letter Lines: 1518 to 1537 

Comment Code: 4760 2.7.6 Proposed reporting frequency (seeking comment) 

Comment: 1. Reporting Requirements 

EPA proposes to require owners or operators of Class V1 wells to report semiannually to the permitting authority on: the physical and chemical 

characteristics of injection fluids; injection pressure, flow rate, temperature, 

volume and annular pressure; annulus fluid volume added; and the results of 

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MITs, plume tracking, and atmospheric/soil gas monitoring. Additionally, owners 

and operators will be required to submit the results of AoR modeling revisions: 

any updates to the information on the type, number, and location of all wells 

within the site AoR; and information on additional corrective action performed 

or planned based on AoR reevaluations. 

A semi-annual reporting obligation with respect to the above information is 

reasonable. The CCS Alliance requests, however, that EPA streamline the final 

reporting requirements to ensure simplicity and to avoid unnecessary confusion 

or duplication of reporting obligations. For instance, proposed section 

146.91(b) requires a report within 30 days for certain tests or any well 

workover. These additional reports should be incorporated into the semi-annual 

report, as they are not so time-sensitive as to require a separate reporting 

obligation. 

Individual Response: EPA is retaining the semi-annual reporting requirements as proposed at 

§146.91(a). These requirements ensure the Director has the information needed to take 

preventive action in a timely manner to protect USDWs from endangerment. EPA notes that 

operators who want to streamline their reporting schedules can negotiate with the permitting 

authority to establish a schedule that allows reporting on all wells in a GS project at the same 

time; however, data for each well must be reported separately and at least as frequently as 

required at §146.91. For additional information, please see the final rule and the preamble for a 

discussion of EPA's final approach to recordkeeping and reporting. 

Letter ID: 0178 Comment ID: 23847 Letter Lines: 1539 to 1542 

Comment Code: 4750 2.7.5 Comments on the merit of annual reports (seeking comment) 

Comment: EPA also seeks comment on whether owners or operators of GS sites should be 

required to provide an annual report on GS operation during the lifetime of the 

project, including the post-injection period. Such a report is not necessary in 

light of the other proposed semi-annual reporting obligations. 

Individual Response: The final GS regulation retains the reporting requirements as proposed, 

which does not include a requirement for an annual report. Instead, EPA believes that periodic 

reevaluation of the AoR, as required at §146.84(e), along with any revisions to the required plans 

that may be necessary based on the AoR reevaluation, will promote an ongoing relationship 

between the permitting authority and the owner or operator. The final GS rule, at §§146.84(c), 

146.90(j), and 146.94(d), requires owners or operators to review and update the AoR and 

corrective action plan, the testing and monitoring plan, and the emergency and remedial response 

plan throughout the life of the project. Owners or operators must review each plan and identify 

necessary amendments to the plan or demonstrate to the Director that no amendment is needed. 

These reviews must be performed within one year of an AoR reevaluation, following any 

significant changes to the facility (e.g., the addition of monitoring or injection wells), or when 

required by the Director. In no case can reviews occur less often than once every five years. For 

additional information, please see the final rule and the preamble for a discussion of EPA's final 

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approach to recordkeeping and reporting. 

While the Agency recognizes some concerns expressed by commenters about the burden 

associated with an annual report, the Agency's decision to retain the semi-annual reporting 

requirement at §146.91(a) is because the semi-annual report in conjunction with the continued 

dialogue associated with AoR reevaluations and periodic updates to the plans is a preferred 

approach to an annual report. 

Letter ID: 0178 Comment ID: 23848 Letter Lines: 1544 to 1561 

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment: 2. Records Retention 

Under the proposal, owners and operators would be required to maintain 

recordkeeping and reporting information for the duration of the project, as well 

as for three years after site closure (following the post-injection site care 

period). Owners and operators also would be required to keep their most recent 

plugging and abandonment report for one year following site closure. Under 

proposed requirement 40 C.F.R. $ 146.93(g), EPA would require that the owner or 

operator deliver to the Director records collected during the post-injection 

site care period at the conclusion of the 3-year retention period. The CCS 

Alliance is concerned that some of this information may be of a confidential 

financial or business operations nature and should be protected from public 

disclosure. Thus, the CCS Alliance recommends the inclusion of a "non-disclosure 

requirement" to protect certain sensitive and confidential business information 

from public disclosure. The CCS Alliance also requests EPA to consult with the 

U.S. Department of Homeland Security to determine whether CCS sites would 

constitute "critical infrastructure," thereby necessitating additional 

protection of sensitive information. 

Individual Response: The Agency clarifies that owners or operators may claim confidential 

business information under existing UIC regulations at 40 CFR 144.5. These requirements are 

applicable to all well classes. 

Letter ID: 0178 Comment ID: 23849 Letter Lines: 1566 to 1579 

Comment Code: 2100 1.6 Target Geologic Formations for GS 

Comment: A. GEOLOGIC SITING 

1. Target Geological Formations 

EPA discusses the possible target geologic formations for GS of CO2, stating at 

one point that deep saline formations are the leading candidates for GS. It is 

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premature to prefer one type of formation over another. Deep saline aquifers 

have had very little detailed investigation at commercial scale to date. By 

contrast, there is a significant amount of information available about depleted 

oil and gas reservoirs. CO2 storage in unmineable coal seams is an area of very 

active research, particularly in certain regions. Industry reports have 

conservatively estimated more than 10 billion tons of potential storage in 

regional coal seams that, if utilized, could result in the incremental 

production of more than 17 Tcf of natural gas. 

Individual Response: EPA believes that saline formations offer the greatest total capacity for 

GS and therefore will most likely be used for purposes of GS. EPA clarifies that the GS rule does 

not categorically preclude injection of CO2 into any non-USDW formation types. The purpose of 

the GS rule is to ensure protection of USDWs from endangerment, and the rule requires that 

owners or operators demonstrate that wells are sited in suitable systems with geologic formations 

to receive and confine injected CO2, required at §146.83 of the GS rule. If an owner or operator 

can demonstrate to the Director's satisfaction that GS in coal seams, basalts, salt domes, or shales 

can be accomplished in a manner that protects USDWs and meets all of the requirements of the 

GS rule, the project may be permitted as a Class VI well. 

Letter ID: 0178 Comment ID: 23850 Letter Lines: 1581 to 1592 

Comment Code: 2160 1.6.3 Unmineable coal seams 

Comment: EPA states that "[w]hile coal seams are well studied and understood, the process 

of CO2 adsorption to coal has not been proven."[FN48] The Alliance believes it 

is well understood. EPA also states that "many ECBM recovery operations will 

likely be shallow. Shallow storage will result in the CO2 remaining in a gaseous 

state..."[FN49] Some parties believe this is incorrect, and that such a 

statement would be true for storage into shallow aquifer pore space, such as in 

shallow saline formations, but that it is not true for storage into shallow coal 

seams. In that case, the CO2 is adsorbed and remains in the dense phase. 

[FN48] Proposed Rule, 73 Fed. Reg, at p. 43503. 

[FN49] Id. 

Individual Response: EPA acknowledges that site-suitability for GS is dependent on a number 

of factors and that many formation types may be suitable for GS. The final GS rule does not 

preclude injection into unmineable coal seams, or any other formation type, provided owners or 

operators can demonstrate that GS can be performed in a manner that protects USDWs from 

endangerment based on the requirements provided in the GS rulemaking. The Agency anticipates 

that in the near-term, most GS in unmineable coal seams will continue to be experimental. Such 

projects may be permitted as Class V experimental technology wells if they are of an 

experimental nature (i.e., to test GS technologies and collect data). EPA will continue to review 

data on early GS projects, including those in unmineable coal seams, to determine whether the 

appropriate amount and types of information and documentation are required and being 

65
collected. EPA plans, every six years, to collect and review data on GS projects to determine 

whether the appropriate amount and types of information and appropriate documentation are 

being collected, and to determine if modifications to the requirements are appropriate or 

necessary. 

EPA recognizes that GS in unmineable coal seams has been the subject of less research than 

saline formations or depleted oil and gas reservoirs. However, EPA has examined select field 

projects involving injection into unmineable coal seams, including the Pump Canyon Site, near 

Archuleta, New Mexico. In the Notice of Data Availability and Request for Comment, EPA 

described research at the Pump Canyon site where the Southwest Partnership is studying CO2 

injection into deep, unmineable coal seams and performing a "seal analysis" of the ability of the 

Kirtland Formation to act as a barrier to the movement of CO2 or other reservoir fluids. EPA 

continues to follow this project, recently completed projects, and ongoing GS projects injecting 

into unmineable coal seams. Other coal seam injection projects are underway through the RCSPs 

in the Illinois Basin, Black Warrior Basin, and Central Appalachian Basin. 

Letter ID: 0178 Comment ID: 23851 Letter Lines: 1594 to 1617 

Comment Code: 3110 2.1.1 Proposed siting requirements (i.e., injection/confining zones, 

trapping mechanism) 

Comment: 2. Geologic Siting Requirements 

EPA's Proposed Rule includes significant technical information requirements for 

the geological siting of Class VI wells, including: maps and cross-sections of 

nearby USDWs; demonstrations of the porosity and permeability of the injection 

zone and subsurface formations; information on faults and fractures, including 

results of geomechanical studies; seismic history studies; determinations of 

maximum sustainable injection pressures; and geochemical data. 

The geological siting requirements for Class VI wells should be reasonably 

balanced to ensure that EPA's goals are met. but not be so burdensome so as to 

deter the development of CCS projects. To this end, EPA should ensure that the 

information it seeks is essential to its evaluation efforts, and not 

unnecessarily overbroad. Proper geological siting requirements will help EPA, 

state actors, and owners and operators identify the risks involved so that 

proper additional evaluations may be made to protect human health and the 

snvironment and to evaluate financial and strategic risks associated with CCS 

projects. 

Moreover, the siting requirements authorize the Director to use his discretion 

to require owners and operators to identify and provide additional information 

with respect to additional zones near the GS. Such discretion should not be 

unlimited. We recommend that EPA establish clearer guidelines with respect to 

how such discretion may be exercised to prevent unnecessary requirements. 

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Individual Response: EPA believes that requiring appropriate, site-specific, site 

characterization by the owner or operator (under §146.82) and providing an appropriate degree 

of flexibility to the Director to evaluate site-specific geologic data will afford the greatest 

protection of USDWs from endangerment. EPA disagrees the requirements are too burdensome, 

and believes that it is important for the Director to have as much site-specific information as 

possible in order to make an informed decision to permit injection for GS at a specific site. EPA 

is developing guidance on site characterization for GS projects to assist owners or operators and 

Directors in evaluating permit requirements and applications under §146.82. The guidance 

provides recommendations regarding characterizing the regional geology and hydrogeology of a 

proposed GS site as well as performing the necessary geochemical, geomechanical, and 

geophysical analyses of the injection and confining zone. EPA expects that this guidance will 

assist permit writers in evaluating this information and exercising discretion. The guidance can 

be found on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0178 Comment ID: 23852 Letter Lines: 1619 to 1626 

Comment Code: 1520 1.2.3 Other authorities (e.g., CAA, MPRSA, London Convention) 

Comment: The CCS Alliance also is concerned about numerous federal and state statutes 

that may be triggered through the siting of a CCS project. At the federal level, 

the siting of linear facilities most often raises issues under the Clean Water 

Act, the Rivers and Harbors Act of 1899, the National Environmental Policy Act, 

and the Endangered Species Act. Any number of other federal statutes may apply, 

depending upon the resources affected by or near the facility. Congress may need 

to consider how to balance the objectives of these acts with the policy inherent 

in promoting CCS. 

Individual Response: EPA acknowledges that GS falls within the broader context of CCS and 

the need for regulatory clarity to ensure that USDWs are protected from endangerment. In 

developing the final GS rule, the Office of Water coordinated with other Agency program offices 

and across federal agencies (e.g., with the Department of Energy; United States Geological 

Survey; Bureau of Ocean Energy Management, Regulation, and Enforcement, formerly the 

Minerals Management Service; Bureau of Land Management). The Agency continues to evaluate 

areas of potential applicability of other Federal environmental statutes including, but not limited 

to: the Clean Air Act; the Resource Conservation and Recovery Act; the Comprehensive 

Environmental Response, Compensation, and Liability Act; and the Marine Protection, Research 

and Sanctuaries Act to various aspects of GS and CCS. The Agency will continue to coordinate 

on GS and CCS related issues to minimize redundancy and maximize efficiencies for owners or 

operators. For additional information, please see the discussion entitled "How Does This 

Rulemaking Relate to Other Federal Authorities and GS and CCS Activities?" in the preamble to 

the final GS rule. 

Regarding the need for a CCS agency to coordinate across agencies, EPA is coordinating with 

and will continue to facilitate communication among federal and state agencies during the 

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implementation phase of the GS regulation. 

EPA clarifies that the Agency is not obligated under the UIC program to comply with NEPA 

§§102(2)(c) and 102(2)(e) because the UIC permitting process is considered a “functional 

equivalent. 

Letter ID: 0178 Comment ID: 23853 Letter Lines: 1628 to 1636 

Comment Code: 1250 1.1.1.4 Flexibility is needed (performance-based standards) 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment: Siting requirements should reflect that conditions affecting risk differ by 

site. They need to be tailored to the actual risks presented by specific sites. 

EOR is a well developed technique and there is now a history through which its 

risks can be assessed. This differs from injection for long-term storage in deep 

saline formations or unmineable coal seams. with which there is little 

experience, particularly on the massive scale (e.g., a million or more tons per 

year per plant) envisioned for the future. For CCS to be a viable long-term 

strategy, policy must encourage development of data about these sites, new 

technology. and new practices. 

Individual Response: EPA agrees with the commenter that every site (and the risk posed) is 

unique. EPA agrees that site characterization should be site-specific, particularly in light of the 

variety of geologic settings in which GS may be employed. EPA believes that, while there is a 

large amount of required information, the owner or operator is given flexibility in determining 

what methods are used to demonstrate the suitability of a potential site. EPA envisions an 

ongoing dialogue between the Director and the owner or operator during the permitting process 

(as well as throughout the operation of the site). 

Letter ID: 0178 Comment ID: 23854 Letter Lines: 1640 to 1648 

Comment Code: 3310 2.2.1.1 Comments in favor of requiring computational models to 

delineate the AoR (seeking comment) 

Comment: 1. Area of Review 

The CCS Alliance agrees that traditional AoR delineation methods such as a fixed 

radius or simple mathematical computations would not he sufficient to predict 

the extent of CO2 plume movement. The CCS Alliance therefore supports the use of 

computational fluid flow modeling designed for the specific site conditions and 

injection regime to delineate the AoR for CO2 GS sites. Such modeling will 

provide the level of sophistication necessary to predict the complex multi-phase 

buoyant flow of the CO2, injectates, and mobilizing compounds. 

Individual Response: EPA acknowledges the commenter’s support and believes that predicting 

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the complex multiphase, buoyant flow of the CO2, co-injectates, and compounds that may be 

mobilized due to injection requires the sophistication of computational models, as required at 

146.84(c)(1). Models can predict CO2 fate and transport, as well as changes in formation 

pressure, in three dimensions, as a function of time in order to delineate the subsurface storage 

site and the AoR. Models can account for site-specific and predicted operating conditions as well 

as geologic heterogeneities and potential migration through faults, fractures, and artificial 

penetrations. 

Letter ID: 0178 Comment ID: 23855 Letter Lines: 1650 to 1655 

Comment Code: 3530 2.2.3.1 AoR reevaluation frequency (seeking comment) 

Comment: EPA also proposes requiring the reevaluation of the site AoR on a periodic 

basis, suggesting a 10-year minimum fixed frequency for AoR reevaluation. The 

CCS Alliance agrees that a 10-year minimum is reasonable for reevaluating the 

AoR delineation, given that long-term CO2 storage may produce an AoR differing 

from other types of UIC injection plumes and should therefore be reevaluated to 

assure project safety and stability. 

Individual Response: Based on evaluation of the public comments on this topic, EPA has 

changed the minimum frequency for the AoR reevaluation at §146.84(e) from 10 years to at least 

every 5 years. EPA believes that this revised frequency addresses concerns raised by commenters 

representing water associations, an energy company, associations, industries, states, and 

environmental groups about the inherent uncertainties in modeling CO2 movement, the emerging 

nature of GS technology, risk-based targeting of monitoring activities, and the unique nature of 

CO2 GS. 

The 5-year reevaluation frequency, particularly during early stages of GS deployment, will also 

support EPA's adaptive approach to the GS rulemaking. EPA is using an adaptive approach to 

regulating GS. The Agency plans, every six years, to collect and review data on GS projects to 

determine whether the appropriate amount and types of information and appropriate 

documentation are being collected, and to determine if modifications to the requirements are 

appropriate or necessary. 

Letter ID: 0178 Comment ID: 23856 Letter Lines: 1657 to 1666 

Comment Code: 3630 2.2.4.1 Comments in favor of allowing phased corrective action 

Comment: 2. Phased Corrective Action 

The CCS Alliance phased correction action and believes such an approach is 

reasonable, given the potential size of the CO2 plume for commercial-scale GS 

operations. Requiring up-front corrective action for the entire AoR prior to 

injection could result in substantial delays in permitting and project 

69
implementation. At a minimum, as part of the AoR process, wells that penetrate 

the confining or injection zone must be identified. Identifying problematic 

wells up-front may increase short-term costs, but should reduce risk and 

liability over the long-term. 

Individual Response: EPA agrees that phased corrective action may provide many benefits to a 

project including, but not limited to, spreading the burden of cost, avoiding delays in project 

start-up, allowing for use of future, improved corrective action techniques and addressing 

unanticipated changes in the movement of the CO2 plume or pressure front. EPA believes that 

the phased corrective action approach is appropriate for GS projects, and retained it at 

§146.84(b)(2)(iv) in the final GS regulation. 

Letter ID: 0178 Comment ID: 23857 Letter Lines: 1668 to 1688 

Comment Code: 3400 2.2.2 Corrective Action 

Comment: EPA should address gaining access to third party wells that may require 

corrective action. Most states require corrective action to be performed prior 

to injection and the "right of access" is taken into consideration during the 

adequacy determination of the corrective action plan. Some states, such as 

Texas, require corrective action prior to injection unless the owner/operator, 

after best efforts, is unable to get permission to access the property of a 

third party.[FN50] SDWA does not provide EPA the authority to require third 

parties to provide access to an owner/operator for the purposes of conducting 

corrective action. EPA should clarify how owner/operators and states will be 

expected to implement corrective action. 

[FN 50] 30 TEX. ADMIN Code $ 305.151 (2008) 

Prior to denying a permit application, the regulations should provide the owner 

or operator the opportunity to demonstrate that a project can maintain its 

safety and security, despite an uncorrected well. Otherwise, a potential GS site 

could go unutilized, even if the uncorrected well creates no actual risk of harm 

to USDWs. Moreover, well remediation should be applicable only to those wells 

that are likely to be impacted (meaning exposed to corrosive fluid and/or 

pressure above likely capillary entry pressure) early to mid phases of operation 

(e.g., one to 20 years). 

Individual Response: The purpose of the corrective action requirement at §146.84(d) is to 

ensure that all wells in the AoR that have the potential to cause the movement of CO2 or other 

fluids into or between USDWs receive appropriate corrective action. In general, to meet this 

requirement, the owner or operator most likely will need to obtain the right of access to wells 

that may require corrective action, and demonstrate they have done this in their proposed AoR 

and corrective action plan. In the AoR and corrective action plan, the owner or operator must 

describe how site access will be guaranteed for future corrective action, as specified in 

§146.84(b)(2)(iv). EPA adds that, in some circumstances, monitoring in the injection zone may 

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be an appropriate corrective action technique. These types of determinations would need to be 

made by the Director on a site-specific basis. 

Letter ID: 0178 Comment ID: 23858 Letter Lines: 1692 to 1697 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment Code: 4344 2.4.4.2.2 Comments opposed to setting a minimum injection depth 

Comment: Geologic sequestration of CO2 need not be, in every instance, beneath the 

lowermost USDWs, nor should EPA set a minimum injection depth requirement. Such 

requirements likely would preclude injection into certain targeted geologic 

formations, which may include storage sites currently under consideration for 

GS. These formations may include unmineable coal seams, zones in between or 

above USDWs, and others. 

Individual Response: EPA agrees that it is not appropriate to set a minimum injection depth for 

GS projects. EPA believes that a determination of site-suitability for GS (i.e., that subsurface 

formations will receive and confine injected CO2) should be made on a site-specific basis. The 

GS rule, at §146.82, requires the owner or operator to provide extensive site- and project-specific 

information to the Director to demonstrate that the site meets the minimum site criteria at 

§146.83, that the CO2 will be contained within the injection formation, and that USDWs will be 

protected from endangerment. 

EPA believes that proper siting, monitoring, and containment capacity are critical elements of 

Class VI injection for GS. However, the Agency also believes that injection into non-USDW 

formations above and between USDWs presents unique challenges related to movement of CO2 

in the subsurface, which requires a unique approach to ensure that USDWs are protected. 

Therefore, the Agency believes that additional requirements are appropriate and necessary for 

wells that would inject into non-USDWs above and between USDWs. 

EPA acknowledges that there are limited circumstances where injection above the lowermost 

USDW can be performed in a manner that protects USDWs, as long as appropriate protections 

are in place. The final GS rule at §146.95 establishes a process by which owners or operators can 

seek a waiver of the Class VI injection depth requirements for injection into non-USDW 

formations above and/or between USDWs. The waiver approach requires the submission of 

extensive, site-specific information (in conjunction with the permit application submission) to 

demonstrate that injection of CO2 into a non-USDW that is above or between USDWs can be 

done in a manner that is protective of USDWs. The requirements are designed to ensure that the 

owner or operator, the Director, and the Regional Administrator consider, on a site specific basis, 

the implications, benefits, and challenges associated with GS and ensuring water availability and 

USDW protection. For additional information on the waiver approach, please see the final rule 

and preamble, as well as EPA's responses to comments on the Notice of Data Availability and 

Request for Comment. 

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Letter ID: 0178 Comment ID: 23859 Letter Lines: 1699 to 1703 

Comment Code: 4410 2.4.4.3.1 Comments in favor of allowing injection above/between 

USDWs in certain circumstances 

Comment: Directors should have discretion to allow injection above or between USDWs in 

specific geological settings where going below the lowermost USDW would make GS 

impractical, as well as where there are appropriate strata between the injection 

zone and the underlying or overlying USDW. Such Director discretion, however, 

should be limited or based on measurable factors or criteria. The CCS Alliance 

Individual Response: As described above, EPA acknowledges that there are limited 

circumstances where injection above the lowermost USDW can be performed in a manner that 

protects USDWs from endangerment, as long as appropriate protections are in place. The final 

GS rule at §146.95 establishes a process by which owners or operators can seek a waiver of the 

Class VI injection depth requirements for injection into non-USDW formations above and/or 

between USDWs. Determinations about the appropriateness of a waiver would be made by the 

Director, based on evaluation of site-specific conditions. 

Letter ID: 0178 Comment ID: 23860 Letter Lines: 1703 to 1705 

Comment Code: 4460 2.4.4.4.1 Comments in favor of allowing aquifer exemptions in certain 

circumstances 

Comment: should be limited or based on measurable factors or criteria. The CCS Alliance 

also agrees that Directors should be able to exempt all USDWs below the 

injection zone, pursuant to "aquifer exemptions." 

Individual Response: EPA acknowledges that there are limited circumstances where aquifer 

exemptions for GS may be warranted. The final rule allows for the expansion of the areal extent 

of existing aquifer exemptions for Class II EOR/EGR wells transitioning to Class VI injection 

for GS pursuant to requirements at §§146.4 and 144.7(d). Class VI owners or operators granted 

expansions of existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of 

the tailored requirements for GS wells in the final GS rule. 

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; 

that is, aquifer exemptions will only be granted for projects that are transitioning from Class II 

EOR/EGR wells to Class VI. 

The Agency clarifies that the aquifer exemption requirements and the injection depth waiver 

requirements serve different purposes. Class VI owners or operators granted expansions of 

existing Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored 

requirements for GS wells in the final GS rule, including the requirements at §146.83 for site 

criteria. EPA believes that, in most cases, the injection depth waiver is a more appropriate option 

than aquifer exemptions for Class VI injection, and believes that aquifer exemption expansions 

for GS should be granted in limited circumstances. 

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EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will 

be at the Director's discretion and based on site-specific information. If an owner or operator 

applies for a Class VI permit to inject CO2 into a previously exempted aquifer (non-USDW) that 

is located above and/or between USDWs, the permit applicant must also apply for a waiver of 

the injection depth requirements pursuant to §146.95 to ensure that if a waiver is granted, 

USDWs above and below the injection zone are protected from endangerment. 

This approach is designed to ensure that the differences between traditional Class II EOR/EGR 

operations and Class VI operations are considered during the aquifer exemption application 

process and the Class VI permitting process. These differences include the anticipated large CO2 

injection volumes associated with GS, the buoyant and mobile nature of the injectate, and its 

corrosivity in the presence of water. The Agency believes that this process will encourage 

owners or operators and Directors to consider the use of alternative formations for GS, including 

non-USDW formations through the waiver process, prior to applying for or approving aquifer 

exemption expansions for Class II EOR/EGR wells transitioning to Class VI GS operations. 

For additional information on aquifer exemptions for Class VI wells, please see the final rule and 

preamble, as well as EPA's responses to comments on the Notice of Data Availability and 

Request for Comment. 

Letter ID: 0178 Comment ID: 23861 Letter Lines: 1707 to 1715 

Comment Code: 4100 2.4.1 Injection parameters 

Comment: With respect to specific well operating requirements, we reiterate the 

importance of maintaining reasonable standards that take into account that CCS 

injection will differ from other injection activities. For instance, Class I 

wells typically must maintain an annular-fluid pressure greater than the 

injection tubing pressure to prevent outward leakage from the injection tubing. 

Typically, these wells operate at pressures much lower than CO2 injection wells. 

This same requirement imposed on CO2 injection wells would require specialized 

high-pressure equipment to maintain the required pressure differential on the 

annular fluid. EPA also recommends as a possible safety device in CO2 injection 

Individual Response: EPA believes that maintaining an annulus pressure that is higher than the 

injection pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the 

annulus fluid will move into the tubing, rather than the injectate moving out of the tubing and 

potentially along the outside of the well. EPA believes this requirement is appropriate for Class 

VI wells given the potential high volumes and supercritical nature of the CO2 injectate, potential 

geomechanical stresses in the wellbore, and the potential for movement of the CO2 in the event 

of a mechanical integrity loss. 

Letter ID: 0178 Comment ID: 23862 Letter Lines: 1715 to 1720 

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Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment) 

Comment: annular fluid. EPA also recommends as a possible safety device in CO2 injection 

wells the use of down-hole shut-off valves that would automatically shut-in the 

well. It is not clear that safety valves for a CO2 injection wells are available 

in the sizes necessary for most on-shore injection wells because these devices 

are primarily used in larger, off-shore wells. The use of such valves, 

therefore, needs more consideration. 

Individual Response: After evaluating the risks and benefits of down-hole shut-off systems and 

considering additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from 

endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or operators of 

onshore Class VI wells install automatic surface shut-off devices. The rule affords Director's 

discretion to mandate automatic down-hole shut-off devices in onshore situations that may 

warrant their use. However, the Agency believes that offshore Class VI wells present unique 

construction and operational conditions, including isolation from shorelines and the need to 

construct wells through the water column and the subsurface, which may delay response time in 

the event of well difficulties. The rule requires, at §146.88(e)(3), that owners or operators of 

offshore wells within State territorial waters install automatic down-hole shut-off systems. EPA 

believes that these requirements at §146.88(e) ensure that proper precautions are taken to prevent 

subsurface fluid movement and ensure protection of USDWs. 

Letter ID: 0178 Comment ID: 23863 Letter Lines: 1722 to 1731 

Comment Code: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 

146.86) 

Comment: D. INJECTION WELL CONSTRUCTION REQUIREMENTS 

Well construction procedures and requirements should remain reasonable and 

flexible given that long-term CO2 storage remains a relatively new area with 

developing science and technologies. The experience of the operator, the volume 

of CO2 stored, and the pressure at which it needs to be injected, should be 

viewed as important variables when finalizing well construction requirements. 

EPA also should consider that a properly installed well provides a barrier to 

fluid movement, even if components are shown to degrade in aggressive laboratory 

experiments. It is also not known if new CO2 resistant cements will perform as 

Individual Response: EPA agrees that a flexible approach to the construction of Class VI wells 

is appropriate, and believes the rule provides an appropriate amount of flexibility. The 

construction requirements at §146.86 provide flexibility by listing the basic components a Class 

VI well must have to prevent endangerment of USDWs, and allow owners or operators to choose 

appropriate materials in meeting these requirements. 

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Letter ID: 0178 Comment ID: 23864 Letter Lines: 1731 to 1732 

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment) 

Comment: experiments. It is also not known if new CO2 resistant cements will perform as 

well as conventional cements in terms of emplacement and bonding. 

Individual Response: EPA notes that corrosion-resistant materials and cement do exist. Industry 

experience of many decades in corrosive down-hole situations such as acid gas injection and 

production of natural gas with carbon dioxide and hydrogen sulfide impurities shows that 

materials are available that can resist corrosive environments. Meyer (2007) lists several types of 

cements that have been used under such corrosive conditions. EPA acknowledges that studies 

have likely not been performed to prove a 50-year life span for corrosion-resistant materials. 

However, there are two studies of wells that were exposed to CO2 for approximately 30 years by 

Carey et al. (2007) and Crow et al. (2008). Although these studies are limited in the number of 

well material samples and the number of wells examined, the casing and cement sampled 

indicate fairly good condition (i.e., fairly significant corrosion resistance) of well materials 

installed three decades ago. The best available corrosion-resistant materials suited for each GS 

project will be determined by the Director. 

EPA acknowledges that there is limited data on this subject, and believes that providing multiple 

barriers of protection is the most appropriate approach to protecting USDWs from 

endangerment. EPA anticipates further findings on the use of acid-resistant cements, in particular 

the physical integrity of such modified cements in place. The Agency plans to, every six years, 

collect and review data on GS projects to determine whether the appropriate amount and types of 

information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 

Letter ID: 0178 Comment ID: 23865 Letter Lines: 1734 to 1736 

Comment Code: 3840 2.3.2 Horizontal well drilling techniques (seeking comment) 

Comment: Horizontal well construction has proven beneficial in other applications, such 

as EOR operations, and therefore should be an available option for Class VI 

wells. The CCS Alliance also supports EPA's proposal to provide Directors the 

Individual Response: In the final rule, EPA allows the use of horizontal wells at GS projects. In 

the proposed rule, EPA sought comment on the appropriateness of horizontal drilling techniques 

for Class VI wells, and commenters representing energy companies, electric utilities, the oil and 

gas industry, CCS associations, states, and the public, unanimously supported the concept and 

provided many reasons why horizontal wells could be beneficial at GS sites. Based on an 

evaluation of these comments and additional research by EPA, the Agency has concluded that 

horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to 

meet the requirements of the GS rule) can ensure the protection of USDWs from endangerment. 

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Letter ID: 0178 Comment ID: 23866 Letter Lines: 1736 to 1742 

Comment Code: 2060 1.5.3 Comments on grandfathering of existing wells (seeking comment) 

Comment: wells. The CCS Alliance also supports EPA's proposal to provide Directors the 

authority to grandfather the construction requirements for Class V experimental 

project wells and other wells when they are converted to full scale Class VI 

wells. The Alliance suggests that EPA should consider whether grandfathering the 

existing siting, AoR, operations, and monitoring plans for Class II and Class V 

wells when they are converted to full scale Class VI wells would protect USDWs 

while avoiding additional regulatory burden. 

Individual Response: EPA agrees that many Class II wells are designed and constructed to 

withstand exposure to CO2. The final GS rule provides for the construction of these wells to be 

grandfathered per §146.81(c), provided the owner or operator can demonstrate to the Director 

that the wells were engineered and constructed to meet the requirements at §146.86(a) and 

ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). EPA clarifies 

that only the construction requirements are grandfathered and that all other Class VI 

requirements (reporting, monitoring, mechanical integrity testing, etc.) must be met following a 

determination under §146.81(c). 

EPA disagrees that other requirements (e.g., MITs, siting, monitoring, and AoR requirements) 

should also be grandfathered. Following re-permitting of the project as GS, many of the unique 

factors of GS sites (e.g., increased reservoir pressures associated with large volumes of stored 

CO2 and the corrosivity of CO2 in the presence of water) will result in an increased risk profile, 

warranting the specific requirements in the final GS rule. Therefore, following re-permitting as 

Class VI wells, these projects would be subject to the operational, MIT, monitoring, reporting, 

plugging, and post-injection site care and site closure requirements in the final GS rule. See the 

discussion of EPA's final regulatory approach in the preamble to the GS rule for additional detail 

on these requirements. 

Letter ID: 0178 Comment ID: 23867 Letter Lines: 1744 to 1755 

Comment Code: 4500 2.5 Proposed Mechanical Integrity Testing (MIT) Requirements (40 CFR 

146.89) 

Comment: E. MECHANICAL INTEGRITY TESTING REQUIREMENTS 

EPA would require owners and operators of Class VI projects to monitor internal 

mechanical integrity of their injection wells by continuously monitoring 

injection pressure, flow rate, and injected volumes, as well as the annular 

pressure and fluid volume to assure that no anomalies occur that may indicate an 

internal leak. The practicability of such monitoring is yet unknown. The 

proposed MIT requirements, therefore, should be flexible. The same holds true 

for the frequency of internal and external MITs for injection wells, the types 

of MITs, and how to optimize MIT methods for geologic sequestration. As industry 

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gains more knowledge and experience, more structured regulations for MIT types 

and frequency of MITs may be appropriate. 

Individual Response: EPA believes that continuous pressure monitoring to demonstrate internal 

mechanical integrity of Class VI wells as required under §146.89(b), instead of periodic testing 

(which is required for most other types of deep injection wells) is important given the potential 

corrosive impact of CO2 and impurities on well materials, the potential geomechanical impacts 

to well integrity due to CO2 phase changes, and the temperature and pressure effects associated 

with injecting supercritical CO2. EPA also believes that the technology for continuous 

monitoring is practicable, available, and is currently in fairly wide use. The Texas Class I well 

regulations for industrial wells currently require continuous monitoring of annulus pressure and 

volume and the majority of injection wells in Ohio conduct continuous monitoring (GWPC, 

2006). At least one commenter indicated that the technology required for continuous monitoring 

is currently available and should not present an undue cost burden. Continuous annulus 

monitoring is also conducted at the commercial-scaled carbon capture and geologic sequestration 

operation at the In Salah, Algeria natural gas plant where more than 3 million tons of CO2 have 

been sequestered since 2004. 

EPA believes that the annual mechanical integrity testing is appropriate for GS wells. EPA 

retains the requirement that owners or operators of Class VI wells demonstrate injection well 

external mechanical integrity at least once annually. See §146.89(c). EPA believes this is 

justifiable for the protection of USDWs from endangerment given the unique nature of CO2 GS 

relative to other injection operations, including the potential corrosive impact of CO2 in the 

presence of water and impurities on well materials, the potential geomechanical impacts to well 

integrity due to CO2 phase changes, the temperature and pressure effects associated with 

injecting supercritical CO2, and the buoyant nature of the injected CO2. Because of the unknown 

long-term effects of CO2 GS, EPA chose a more conservative initial approach in the early stages 

of deployment for GS. 

The Agency plants to collect and review data every six years on GS projects to determine 

whether the appropriate amount and types of information and appropriate documentation are 

being collected, and to determine if modifications to the requirements are appropriate or 

necessary. 

Letter ID: 0178 Comment ID: 23868 Letter Lines: 1757 to 1771 

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment) 

Comment Code: 4630 2.6.3 Corrosion monitoring 

Comment: We do not believe there is any compelling reason to require annual integrity 

testing or quarterly corrosion monitoring. A five-year testing routine has been 

sufficient for acid gas wells in Canada. Many known injection wells are reused 

producer wells that have been in corrosive environments for over 15 years and 

remain in good condition. Annual testing and quarterly corrosion testing could 

also result in significant costs from plant shutdowns and downtime. Many 

77
companies already conduct periodic plant-wide shutdowns to thoroughly inspect 

piping and equipment for corrosion and make any necessary equipment upgrades. 

These shutdowns, which ordinarily occur once every three to five years, are also 

used to inspect injection wells, including pulling tubing, running cement bond 

logs, and well casing integrity logs to determine the thickness and integrity of 

the steel in the boreholes. From these tests, companies are able to assess the 

cement and casing conditions, which provide the primary "isolation" mechanism 

from the reservoir fluids. Moreover, companies can and often do run noise logs 

that can assess for "channeling" behind the casing. 

Individual Response: EPA disagrees that a five-year external MIT is appropriate. The final GS 

regulation retains the requirement that owners or operators of Class VI wells must demonstrate 

injection well external mechanical integrity at least once annually under §146.89(c). While EPA 

acknowledges the successful history of the Class II injection program, including injection of sour 

(acid) gas, the Agency believes that CO2 injection for GS is substantially different from Class II 

ER operations and believes annual MITs are justifiable for the protection of USDWs from 

endangerment given the unique nature of CO2 GS relative to other injection operations, 

including the potential corrosive impact of CO2 in the presence of water and impurities on well 

materials, the potential geomechanical impacts to well integrity due to CO2 phase changes, the 

temperature and pressure effects associated with injecting supercritical CO2, and the buoyant 

nature of the injected CO2. Because of the unknown long-term effects of CO2 GS, EPA chose a 

more conservative initial approach in the early stages of deployment for GS. 

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found 

that Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those 

that inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., 

in the presence of water or aqueous formation fluids), there is a potential risk factor for MIT 

failure and, for this reason, EPA believes that the tailored MIT requirements in the final GS rule 

are appropriate. Regarding concerns about disruptions of plant operations, EPA believes that, 

due to the expected size of GS fields, many GS operations will have more than one injection 

well, and that testing of each well can be timed to avoid complete interruption of the project. 

On the topic of corrosion monitoring, EPA disagrees with commenters' assertions that corrosion 

monitoring is unnecessary or excessive. CO2 in the presence of water (including water with 

NOx, SOx, and H2S impurities) can be corrosive to well materials and cements. Thus, although a 

CO2 stream may be dry, the potential for corrosion of well materials down-hole, where the 

injectate can potentially mix with water in the target formation, must be considered. 

EPA adds that it is using an adaptive approach to regulating GS. The Agency plans to collect and 

review data every six years on GS projects, including MIT data, to determine whether the 

appropriate amount and types of information and appropriate documentation are being collected, 

and to determine if modifications to the requirements are appropriate or necessary. 

Letter ID: 0178 Comment ID: 23869 Letter Lines: 1773 to 1780 

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Comment Code: 4540 2.5.2 Proposed external MIT requirements 

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment) 

Comment: Proposed section 146.89(d) would give the Director discretion to require any 

other test to evaluate mechanical integrity, if the alternative tests are 

approved and published in the Federal Register. We recommend that EPA revise the 

mechanical integrity testing requirements (1) to give the Director discretion to 

approve not only different testing requirements but the timing for testing 

requirements; and (2) to require such testing no more frequently than a 

reasonable multi-year period, or sooner if there is evidence that earlier 

testing is warranted. 

Individual Response: EPA believes that the MITs described in §146.89(c) of the rule (e.g., an 

approved tracer log or temperature or noise logs) are effective methods to demonstrate external 

MI, provide an important early warning of potential problems in the injection well system, and 

represent standard techniques that have been used successfully by the drilling industry and for 

the UIC Program for decades. The Agency notes that the regulations provide the Director the 

flexibility at §146.89(e) to approve the use of alternative MIT methods. 

The final GS regulation retains the requirement that owners or operators of Class VI wells must 

demonstrate injection well external mechanical integrity at least once annually. See §146.89(c). 

EPA believes this is justifiable for the protection of USDWs from endangerment given the 

unique nature of CO2 GS relative to other injection operations, including the potential corrosive 

impact of CO2 in the presence of water and impurities on well materials, the potential 

geomechanical impacts to well integrity due to CO2 phase changes, the temperature and pressure 

effects associated with injecting supercritical CO2, and the buoyant nature of the injected CO2. 

Because of the unknown long-term effects of CO2 GS, EPA chose a more conservative initial 

approach in the early stages of deployment for GS. 

A comprehensive review conducted by EPA of MIT results from 1993 to 1998 found that Class I 

wells injecting corrosive fluids fail MITs at rates two to three times higher than those that inject 

non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (i.e., in the 

presence of water or aqueous formation fluids), there is a potential risk factor for MIT failure 

and, for this reason, EPA believes that the tailored MIT requirements in the final GS rule are 

appropriate. 

EPA adds that it is using an adaptive approach to regulating GS. The Agency plans to collect and 

review data every six years on GS projects, including MIT data, to determine whether the 

appropriate amount and types of information and appropriate documentation are being collected, 

and to determine if modifications to the requirements are appropriate or necessary. For additional 

information, please see the discussion of MITs in the final rule preamble. 

Letter ID: 0178 Comment ID: 23870 Letter Lines: 1782 to 1790 

Comment Code: 4490 2.4.5 Use of tracers and potential impact on human health or ecosystems 

79
(seeking comment) 

Comment: EPA has specifically requested comment on the use of tracers. Based on industry 

experience, tracers are not typically used for monitoring the movement of a CO2 

plume, unless potential leakage is occurring. They are then used to trace the 

leakage point. Tracers can be very expensive and the results can take a lot of 

time to develop, analyze, and understand. Radioactive tracers typically have 

long shelf lives and, if used by neighboring operators, could produce 

conflicting and indeterminate results. Due to the potential for groundwater 

contamination, the use of radioactive materials should be used only sparingly 

and for targeted purposes. 

Individual Response: EPA agrees that tracer use is not appropriate in all Class VI well 

situations. Some tracers may have the potential to cause harm to people or the environment. For 

this reason, EPA does not require the use of tracers at all GS sites. Nevertheless, there are many 

different types of tracers and not all are problematic; research is being done to overcome 

problems with existing tracers. EPA believes that tracers have been used safely and successfully 

in other applications. Therefore the Director has discretion to require their use if he/she 

determines that the use of tracers could improve monitoring of the site and enhance USDW 

protection from endangerment. The rule will also allow their use if proposed by the owner or 

operator and approved by the Director. 

EPA has been following new and ongoing research on the safety and efficacy of tracers, and 

believes that, in some circumstances, tracers can be an effective part of monitoring GS projects. 

EPA will continue to track research related to tracer use and plans to, every six years, collect and 

review data on GS projects to determine whether the appropriate amount and types of 

information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 

Letter ID: 0178 Comment ID: 23871 Letter Lines: 1792 to 1803 

Comment Code: 4600 2.6 Proposed Plume and Pressure Front Monitoring Requirements (40 

CFR 146.90) 

Comment: F. PLUME AND PRESSURE FRONT MONITORING REQUIREMENT 

EPA proposes monitoring sequestration sites to track the location of the CO2 

plume and associated pressure front over time. Plume monitoring is important to 

the long-term stability of CCS sites. However, we submit that such a requirement 

should be flexible to accommodate growing knowledge about injection and CO2 

plumes. Monitoring has limited usefulness in some settings (e.g., 4D seismic 

often does not have the resolution to detect CO2 in some deep or complex 

settings or where hydrocarbon gases are present). Moreover, data gathering 

requirements related to plume tracking and testing should not unduly burden 

owners or operators, either in time or cost, and should be essential to 

evaluation of the plume's stability and safety. 

80
Individual Response: EPA agrees with commenters on the importance of monitoring at GS sites 

and emphasizes that monitoring of injection activities will be an important component of every 

GS project. Monitoring associated with injection wells and the movement of the CO2 plume is 

necessary to verify that the injectate is confined in the target formations and does not endanger 

USDWs. 

EPA agrees with commenters that flexibility is important in developing and implementing a 

monitoring plan that is appropriately tailored for a specific GS site. The purpose of the 

requirement at §146.90 to develop site-specific testing and monitoring plans is to ensure that the 

monitoring performed at a site is appropriate for site operational conditions and the geologic 

setting. EPA believes that this is the best approach for addressing potential risks at GS sites. 

These flexible provisions in the monitoring requirements for Class VI wells enable the owner or 

operator to tailor monitoring programs to the specific needs of each project in consultation with 

the Director. 

EPA agrees that seismic monitoring is not applicable to all sites. The final rule, at §146.90(g), 

requires owners or operators to perform monitoring to track the extent of the CO2 plume and 

pressure front. The owner or operator must use direct methods to monitor for pressure changes in 

the injection zone. Indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys 

and/or down-hole CO2 detection tools) are required unless the Director determines, based on 

site-specific geology that such methods are not appropriate. 

EPA is affording Director's discretion regarding the use of geophysical techniques at some sites 

because the Agency recognizes that geophysical methods are not appropriate in all geologic 

settings. For example, geophysical methods are difficult to execute in areas that are structurally 

and topographically complex or where lithologies have limited contrast in density, porosity, 

permeability, and other physical properties. EPA clarifies that this determination will be made by 

the Director based on the site-specific geologic information submitted by the owner or operator 

with their permit application. 

Letter ID: 0178 Comment ID: 23872 Letter Lines: 1805 to 1816 

Comment Code: 4660 2.6.6 Geochemical monitoring 

Comment: EPA proposes in section 146.90(d) "periodic monitoring of the ground water 

quality and geochemical changes above the confining zone(s)." It is unclear how 

many wells would be required, and whether EPA expects that all zones would be 

monitored. Given the potential size of the CO2 plume and the number of confining 

zones, this could potentially require many monitoring wells, which could be 

extremely expensive and may not produce useful data. We strongly recommend that 

EPA limit monitoring to the zone immediately above the confining zone, and only 

to the extent that the CO2 plume is within close proximity. There may be 

regional conditions where ground water is separated by hundreds or thousands of 

feet of confining strata, and where such monitoring is completely unnecessary. 

Directors should have discretion to limit or tailor ground water monitoring, as 

81
appropriate, based on regional and site specific factors. 

Individual Response: Regarding monitoring locations, section §146.90(d) requires periodic 

monitoring of the ground water quality and geochemical changes above the confining zone(s). 

EPA clarifies that this monitoring requirement does not include the confining layer itself. 

Monitoring above the confining layer will provide an indication of upward movement of CO2 

that might endanger a USDW. The exact number of formations to be tested will, however, be 

based on site-specific characteristics and vulnerabilities and described in the Director-approved 

testing and monitoring plan. 

EPA believes that monitoring above the confining layer is an important part of a rigorous 

monitoring program. The final rule, at §146.90(d) requires periodic monitoring of the ground 

water quality and geochemical changes above the confining zone(s). Monitoring in additional 

formations, e.g., the injection zone, may also be necessary, and if the Director believes such 

monitoring is warranted he/she has the authority to require that it be included in the testing and 

monitoring plan. 

EPA agrees that geochemical monitoring in the injection zone may not be warranted in all cases, 

and that it is important to install an appropriate number of monitoring wells based on sitespecific information and the planned monitoring regime. However, the Agency believes that the 

data gained from monitoring wells in carefully selected locations will be invaluable. 

EPA disagrees that such monitoring should be restricted to areas near the plume. Research, both 

EPA-funded and external, has shown that the zone of elevated pressure may be much larger than 

the plume (e.g., Birkholzer et al., 2008). This area of elevated pressure may cause migration of 

native brines from the target formation into overlying formations. Careful placement of 

monitoring wells within the delineated AoR (which includes areas beyond the extent of the CO2 

plume) would allow for detection of changes in water quality related to GS activities. EPA 

acknowledges that very thick confining zones would reduce the chance that CO2 or other fluids 

will move from the injection zone; however, to increase protectiveness, a multiple-barrier 

approach to protecting USDWs from endangerment that includes both proper site 

characterization and a detailed monitoring regime is warranted. 

Letter ID: 0178 Comment ID: 23873 Letter Lines: 1818 to 1829 

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking 

comment) 

Comment: Proposed section 146.90(h) gives Directors discretion to require surface air 

monitoring and/or soil gas monitoring to detect movement of CO2 that could 

endanger a USDW. The Alliance recommends deleting this provision. It is not 

clear how ambient air or soil gas monitoring is related to or supports the 

protection of USDWs. Surface air monitoring can result in false positives, which 

could prompt unnecessary and costly response actions and needlessly alarm the 

public Any requirement for ambient air or soil gas monitoring would be a matter 

of state discretion pursuant to state law and not the federal UIC program, and 

82
would not be federally enforceable. [FN51] 

[FN51] Bath Petroleum Storage , Inc. v. Sows, 309 F.Supp. 2d 357 (N.D.N.Y 2004) 

(state law requiring sonar survey for UIC injection not federally enforceable). 

Individual Response: EPA acknowledges that air and soil gas monitoring are subject to 

variability and may not be suitable in all settings as a method to ensure USDW protection. 

However, EPA does not believe that this should entirely preclude their use. EPA believes that 

surface air and soil gas monitoring in conjunction with deep subsurface monitoring as required at 

§146.90, can provide additional data to pinpoint the location and magnitude (or absence) of leaks 

that could endanger USDWs. 

The final rule at §146.90(h) retains the allowance for surface air and soil gas monitoring at the 

discretion of the Director as a means of identifying leaks that may pose a risk to USDWs and 

informing emergency notification of a Class VI owner or operator and UIC Director in the event 

of a USDW endangerment, pursuant to requirements at §146.91(c). EPA clarifies that the 

decision to use surface monitoring and the selection of monitoring methods will be site-specific 

(e.g., may be influenced by geology, injection depth, and operational conditions) and must be 

based on potential risks to USDWs within the AoR. 

EPA clarifies that use of surface air and soil gas monitoring as specified in the final GS rule at 

§146.90(h), as a means of identifying leaks that may pose a risk to USDWs and informing 

emergency notification of a Class VI owner or operator and UIC Director in the event of a 

USDW endangerment, pursuant to requirements at §146.91(c) is at the Director's discretion. 

Letter ID: 0178 Comment ID: 23874 Letter Lines: 1833 to 1839 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 3300 2.2.1 Delineating the AoR/Modeling CO2 movement 

Comment: EPA defines "area of review" as "the region surrounding the geologic 

sequestration project that may be impacted by the injection activity. The area 

of review is based on computational modeling that accounts for the physical and 

chemical properties of all phases of the injected carbon dioxide stream." The 

phrase "may be impacted" is too vague, The AoR delineation should be based on or 

limited by certain risk criteria; otherwise, an AoR could cover an 

inappropriately large area that could be expensive to review and characterize. 

Individual Response: EPA agrees with commenters that further clarity is needed with regard to 

the boundaries of the AoR. After considering the public comments on the proposed GS 

regulation, EPA has augmented the definition of AoR to better encompass the area that may be 

impacted by the injection activity (i.e., the "surrounding area" to which the commenter refers). 

The Agency has modified the AoR definition at 146.84(a) to read as follows: The region 

surrounding the geologic sequestration project where USDWs may be endangered by the 

injection activity. The area of review is delineated using computational modeling that accounts 

for the physical and chemical properties of all phases of the injected CO2 stream and is based on 

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available site characterization, monitoring, and operational data. 

EPA is developing guidance on AoR and corrective action at GS Class VI sites to assist owners 

or operators and Directors in evaluating requirements and proposed AoR and corrective action 

plans under 146.84. The guidance describes EPA's recommended approaches for the data to be 

considered in an initial AoR delineation, how to apply computational modeling to delineate the 

AoR, performing corrective action at GS sites, and, when appropriate, completing AoR 

reevaluations. The guidance will be available on EPA's web site, at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0178 Comment ID: 23875 Letter Lines: 1840 to 1848 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: The term "geological sequestration project" is defined as an injection well or 

wells used to emplace a CO2 stream beneath the lowermost formation containing a 

USDW, including the subsurface three-dimensional extent of the CO2 plume, 

associated pressure front, and displaced brine, as well as the surface area 

above that delineated region. We recommend removing the phrase "beneath the 

lowermost formation containing a USDW to reflect our comment suggesting that EPA 

permit CCS projects above USDWs where feasible. The AoR definition includes 

additional area that might be impacted and is not defined in terms of the extent 

of this area. 

Individual Response: EPA agrees that the geological sequestration project definition should 

account for the limited circumstances where injection above the lowermost USDW can be 

performed in a manner that protects USDWs. The Agency has modified the final definition of 

geologic sequestration project to read as follows: “Geologic sequestration project means an 

injection well or wells used to emplace a carbon dioxide stream beneath the lowermost formation 

containing a USDW; or, wells used for geologic sequestration of carbon dioxide that have been 

granted a waiver of the injection depth requirements pursuant to requirements at §146.95; or, 

wells used for geologic sequestration of carbon dioxide that have received an aquifer exemption 

expansion. It includes the subsurface three-dimensional extent of the carbon dioxide plume, 

associated pressure front, and displaced brine, as well as the surface area above that delineated 

region.” 

The final Class VI GS rule at §146.95 establishes a process by which owners or operators can 

seek a waiver of the Class VI injection depth requirements. The waiver approach requires the 

submission of extensive, site-specific information (in conjunction with the permit application 

submission) to demonstrate that injection of CO2 into a non-USDW that is above or between 

USDWs can be done in a manner that is protective of USDWs. The requirements are designed to 

ensure that the owner or operator, the Director, and the Regional Administrator consider, on a 

site specific basis, the implications, benefits, and challenges associated with GS and ensuring 

water availability and USDW protection. 

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Based on its evaluation of all public comments and input on the proposed rule and the NODA 

and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 0178 Comment ID: 23876 Letter Lines: 1850 to 1876 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment Code: 4500 2.5 Proposed Mechanical Integrity Testing (MIT) Requirements (40 CFR 

146.89) 

Comment: EPA defines "mechanical integrity" as "the absence of significant leakage within 

the injection tubing, casing, or packer (known as internal mechanical 

integrity), or outside of the casing (known as external mechanical integrity)." 

The term "significant leakage" is not defined. An overly broad interpretation 

could result in a finding that mechanical integrity is not being maintained, 

notwithstanding the absence of any leakage that calls into question the safety 

of the project or threatens USDWs. EPA should characterize what constitutes 

"significant" or clarify under what conditions significant leakage might be 

construed. We suggest defining and construing the term within the statutorily 

defined concept of "endangerment"[FN52] under SDWA, i.e., significant leakage 

would be defined as any leakage that could potentially endanger a USDW. The 

amount of leakage and what constitutes significant may vary depending upon the 

geologic formations and proximity to USDWs.[FN53] 

[FN52] Endangerment is defined as follows: 

Underground injection endangers drinking water sources if such injection 

may result in the presence in underground water which supplies or can 

reasonably be expected to supply any public water system of any 

contaminant, and if the presence of such contaminant may result in such 

system's not complying with any national primary drinking water 

regulation or may otherwise adversely affect the health of persons. 32 

U.S.C. $ 300h(d). 

[FN53] Miami-Dade County. EPA, 529 F.3d 1049 (11th Cir. 2008) (upholding 

EPA's rule eliminating the non-endangerment finding requirement for Class I 

municipal injection wells). 

Individual Response: A properly designed and operated well should have no leakage in the 

casing, tubing, or packer and no fluid movement into a USDW through channels adjacent to the 

wellbore. While the intent of MITs is to detect these types of problems as early as possible, the 

goal of the well design and construction requirements at §146.86 is the complete absence of such 

problems. EPA clarifies that the purpose of the "significant leakage" language in this narrow 

context is simply to avoid triggering corrective actions for essentially de minimis situations. 

Determining whether a MIT result should trigger follow-up action is necessarily a case and sitespecific situation; as a result, EPA does not believe it is appropriate to define the term 

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"significant leakage" in the context of MITs. In addition, EPA has not defined this term for 

purposes of other injection well classes and this has not been shown to hinder permitting 

authorities' and owners or operators' ability to assess whether injection wells have adequate 

mechanical integrity. EPA believes that this approach allows states flexibility, will not interfere 

with the implementation of existing UIC programs, and maintains protection of USDWs from 

endangerment. 

In keeping with its adaptive rulemaking approach, the Agency plans to collect and review data 

every six years on early GS projects, including MIT data, to determine whether the appropriate 

amount and types of information and appropriate documentation are being collected, and to 

determine if modifications to the requirements are appropriate or necessary. For additional 

information, please see the discussion of MITs in the final rule preamble. 

Letter ID: 0178 Comment ID: 23877 Letter Lines: 1879 to 1927 

Comment Code: 1300 1.1.2.3 Comments on other aspects of CCS (capture, transport) 

Comment Code: 1310 1.1.2.4 Comments on other "out of scope" issues, e.g., pore space 

ownership 

Comment Code: 1400 1.2 Comments on EPA's Authority to Regulate Injection of CO2 

Comment: XII. RELATED ISSUES, NOT RAISED IN THE PROPOSED RULE, THAT 

REQUIRE RESOLUTION 

The SDWA does not provide EPA authority to develop regulations for many 

important areas related to the geological sequestration of CO2. Thus the draft 

rule cannot address all of the potential impediments to CCS development. Even if 

EPA were to promulgate a final UIC rule that encourages development of these 

critical technologies, there are other key factors that would need to be 

properly addressed before major investment in these technologies can be 

expected. 

The following sets forth key issues that will not be resolved through this 

rulemaking but are linked inextricably to the successful development and 

implementation of CCS technology. 

A. EMINENT DOMAIN AUTHORITY TO FACILITATE PIPELINE CONSTRUCTION 

Energy facilities for the public convenience and necessity, such as electric 

transmission facilities and natural gas pipelines, are able to make use of state 

or federal eminent domain authority to ensure that private landowners cannot 

block a project necessary for the public good. Eminent domain authority should 

be available for CO2 pipelines for CCS when it is necessary to cross private 

property. A substantial CO2 pipeline network may be required for the transport 

of CO2 from sites where it is produced to an injection site. CO2 pipelines for 

CCS clearly should be considered to be used for the public convenience and 

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necessity. 

B. DETERMINATION OF SUB-SURFACE PROPERTY RIGHTS 

The government must address the ability to gain sufficient property rights to 

deep saline formations to conduct geologic sequestration. State property 

ownership regimes vary, but surface owners typically are considered to own 

property below the surface to the center of the earth. Safe sequestration of CO2 

will not have any effect on the surface, but GS injections will result in 

underground plumes that may stretch across many square miles under the property 

of multiple surface property owners. Property ownership issues have been 

resolved successfully in the context of EOR, but it should not be assumed that 

the same will be true for GS. Eminent domain authority should be available to 

obtain rights to subsurface storage space for geologic sequestration because of 

its public benefit. 

C. RESOLUTION OF SURFACE LIABILITY ISSUES 

Though this Proposed Rule is limited in its scope to underground injection of 

CO2 and the potential risks and resulting liabilities, issues regarding risks 

and liability at the surface must be addressed for CCS technology to fully 

develop. These include liability for major and sudden releases, seismic activity 

and ground heave, as well as liability under any GHG emission control regime 

when sequestered CO2, for the storage of which credits or offsets have been 

granted, is subsequently released into the upper atmosphere. 

Individual Response: EPA acknowledges that the issue of GS falls within the broader context of 

CCS. EPA received a number of comments indicating that the Agency should further explore 

environmental and regulatory issues beyond the scope of the GS rule as proposed. This comment 

is outside the scope of this rulemaking. 

EPA acknowledges that GS falls within the broader context of CCS and the need for regulatory 

clarity to ensure that USDWs are protected from endangerment. In developing the final GS rule, 

the Office of Water coordinated with other Agency program offices and across federal agencies 

(e.g., with the Department of Energy; United States Geological Survey; Bureau of Ocean Energy 

Management, Regulation, and Enforcement, formerly the Minerals Management Service; Bureau 

of Land Management). The Agency continues to evaluate areas of potential applicability of other 

Federal environmental statutes including, but not limited to: the Clean Air Act; the Resource 

Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, 

and Liability Act; and the Marine Protection, Research and Sanctuaries Act to various aspects of 

GS and CCS. The Agency will continue to coordinate on GS and CCS related issues to minimize 

redundancy and maximize efficiencies for owners or operators. For additional information, 

please see the discussion entitled "How Does This Rulemaking Relate to Other Federal 

Authorities and GS and CCS Activities?" in the preamble to the final GS rule. 

EPA recognizes that liability is an important issue to owners or operators but the Agency does 

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not have authority under the SDWA to transfer long term liability from owners or operators to 

the state or federal government. Therefore, liability remains with the owner or operator.